On April 22, 2026, the U.S. Environmental Protection Agency (EPA) proposed updates to the National Emission Standards for Hazardous Air Pollutants (NESHAP) for the oil and gas sector through 40 CFR Part 63, Subparts HH (Oil and Natural Gas Production) and HHH (Natural Gas Transmission and Storage), as outlined in Part 1 of this series, “EPA Proposed Changes to NESHAP Subparts HH & HHH: Key Changes, Compliance, and Comment Deadlines.”
The proposal includes potential changes to how certain affected emission points are regulated under the Clean Air Act (CAA) and includes 36 targeted questions for stakeholder input, which EPA has organized into a structured framework to gather feedback and technical data on regulatory approaches, emissions controls, and implementation considerations.
The EPA has requested comments, due June 22, 2026, from operators on how an update to Subpart HH could affect regulatory applicability (which facilities and emission points are covered), how to conduct regulatory surveys, what the best control technologies to reduce emissions are, and the timelines associated.
This article, part 3 of our NESHAP Subpart HH and HHH series, focuses on EPA’s proposed updates to leak detection technologies, control requirements, and compliance timelines, including the expanded role of optical gas imaging (OGI), updates to maximum achievable control technology (MACT) standards, and new considerations for methanol emissions. These topics are tied to EPA’s request for input on how monitoring, control technologies, and implementation schedules should evolve to reflect current industry practices.
Optical Gas Imaging vs. Method 21 (Question 1)
The proposed rule asks whether optical gas imaging (OGI) should play a larger role in leak detection and repair (LDAR) at natural gas processing plants. For oil and gas EHS managers, LDAR supervisors, and regulatory compliance teams, this question is significant because it affects how facilities structure monitoring programs under NESHAP Subpart HH.
In EPA’s 2012 technology review for NESHAP Subpart HH, OGI was considered an emerging technology and standard operating procedures had not yet been established. At that time, EPA only allowed OGI under an alternative work practice (AWP) that required facilities to conduct an annual Method 21 survey.
The development of EPA’s Appendix K has since established a clear framework for OGI surveys, giving EPA a basis to reevaluate OGI as an alternative to Method 21 for natural gas processing plants. While Method 21 would remain an accepted LDAR method, adding OGI as an option could benefit operators that do not have an established Method 21 program and are evaluating more flexible oil and gas compliance strategies.
Appendix K has its own implementation challenges but making it available as a compliance option could allow operators to transition portions of existing Method 21 programs to Appendix K-based OGI programs. That flexibility may be especially valuable in states such as New Mexico, where monthly OGI monitoring requirements already influence oil and gas LDAR program design. Even if a facility is not currently subject to NSPS Subpart OOOOb, the option to use Appendix K could provide a more future-proof compliance option for natural gas processors navigating evolving air regulations, and hazardous air pollutant compliance obligations.
Maximum Achievable Control Technology (MACT) (Questions 10a, 10b, 11a)
EPA is reevaluating emissions from natural gas-driven process controllers at major natural gas transmission and storage facilities. In support of that review, the Agency cited responses to the 2023 Information Collection Request (ICR), which indicated that current major-source transmission and storage facilities have access to electrical power through the grid or on-site generation, and furthermore stating many of these facilities have had electric service since at least 1999. Based on that information and its MACT-floor analysis, EPA proposed separate standards for natural gas-driven pneumatic controllers and pumps. EPA is specifically requesting comments on whether its assumptions about the location, use, and types of process controllers at these facilities in 1999 are accurate.
For pneumatic process controllers, EPA proposed a zero-emission MACT floor for new units. Many facilities already use this technology, with controllers powered by electricity, compressed air, solar, or nitrogen-driven equipment. Because access to electricity is now widespread, EPA considers zero-emission controls to represent the MACT floor for new process controllers.
For existing natural gas-driven controllers, however, EPA recognized that converting an entire facility from low or intermittent-bleed pneumatics to zero-emission equipment may not be cost-effective. As a result, the proposal would require existing process controllers to use low-bleed natural gas-driven pneumatics with emissions of less than 6 standard cubic feet per hour (scfh).
EPA also proposed a MACT floor requiring zero-emission pumps. The Agency cited 2024 Phase II ICR data indicating that approximately 95% of pumps currently in service are already zero-emission, typically using electricity or compressed air rather than natural gas. EPA also acknowledged that before 1999, zero-emission pumps were less common. Even so, the proposal establishes zero-emission pumps as the MACT floor for both new and existing major-source natural gas transmission and storage facilities.
Operators should evaluate existing process controller and pump inventories to determine the potential new regulatory requirements and consider submitting comments to EPA regarding the implications.
Non-Combustion vs. Combustion Control for Methanol (Question 18a)
Although methanol is a hazardous air pollutant (HAP), it has not historically been regulated under this framework. EPA is now proposing to add methanol to the list of regulated HAPs under Subpart HH.
EPA states that existing controls reduce methanol emissions from certain equipment subject to Subpart HH. However, EPA indicates methanol-specific standards may be needed for small dehydrators, because the current BTEX-based approach might not adequately serve as a surrogate for methanol in all situations.
Traditionally, combustion has been used to reduce HAP emissions from larger dehydrators. In a study of 58 dehydrators that reported methanol emissions, 38 reported using a combustion device for emissions control. Properly operated combustion devices can achieve a 95% reduction in emissions. Based on that performance, EPA proposed a MACT floor for methanol control from small dehydrators of 95% control. EPA estimated the cost effectiveness of achieving 95% control at approximately $4,058 per ton of methanol reduced per year.
EPA also acknowledged that combustion is not the only potential control method and is seeking comment on which approaches are most effective. Once requirements are finalized, operators will need to identify units where methanol is used or emitted and begin the associated recordkeeping and reporting processes. Due to this, EPA is offering a 12-month period to achieve compliance. Operators should comment on the potential seasonality of methanol emissions, as seasonal HAP emissions can be challenging for operators to quantify and annualize relative to more consistent HAP emissions like BTEX.
Timeline of Compliance (Questions 18b, 18c)
In response to the newly proposed MACT floors, operators will require adequate time to comply. EPA appears to view a longer compliance period as potentially appropriate for process controllers, while taking a more expedited approach for pumps based on the assumption that most affected pumps are already zero-emission.
The proposed timeline for existing process controllers is no later than 36 months after the rule becomes effective. For existing pumps, EPA is proposing a 12-month compliance period.
While available data suggests that many operators already comply with both types of equipment, sufficient time must be allowed for others to replace and install new systems. EPA is specifically requesting comment on whether these timelines are reasonable.
For existing operations, operators will need to identify affected units and order, install, and begin recordkeeping and reporting procedures for replacement equipment. In some cases, achieving full compliance may require unit shutdowns.
Summary
EPA’s proposed updates to Subparts HH and HHH continue to focus on improving regulatory clarity while incorporating current technologies and practices for monitoring and emissions control. In this article, EPA is evaluating the use of optical gas imaging (OGI) as an alternative to Method 21 for LDAR programs, updating MACT requirements for process controllers and pumps, and establishing potential control standards and compliance timelines associated with methanol emissions. As discussed in Part 2 of this series, the proposed changes also evaluate source classification, permitting implications, and updates to emissions calculation methods.
Upstream and midstream operators are both affected by these proposed changes. Subpart HH has historically been complex, and EPA’s request for stakeholder input presents an opportunity to improve how these requirements are applied in practice. Providing targeted, technically grounded comments can help shape a final rule that reflects both regulatory intent and operational realities.
Delve Deeper with our in-Depth Guide to EPA’s Proposed Changes to Subparts HH and HHH
This article is part of Trihydro’s four-part series on EPA’s proposed updates to NESHAP Subparts HH and HHH:
- Start here: Overview of EPA’s Proposed Changes to Subparts HH & HHH (Part 1)
- Next: Source Classification, Permitting, and Emissions Calculations (Part 2)
- This article: LDAR technologies, MACT standards, and compliance timelines
- Final: Methanol, metal HAPs, and additional stakeholder considerations
Each article focuses on a key group of EPA’s requests for comment to help operators evaluate potential impacts and identify priorities ahead of the June 22, 2026 deadline.
