The Oil and Gas Methane Regulations You Need to Know in 2025: Expect Local to Global Impacts
Published: January 15, 2015
Revised: January 24, 2025
By: Elizabeth McGurk
In 2024, the landscape of methane regulation shifted dramatically, with a surge of new rules aimed at curbing emissions and driving accountability in the energy sector. For the first time, rules were finalized that impact operators not only at the state and federal level, but at a global level through methane-based import regulations.
As we move into 2025, the complexity of compliance is only increasing, presenting challenges and opportunities for industry stakeholders. Staying ahead of these changes requires a thorough understanding of the evolving regulatory environment, proactive planning, and strategic execution.
To help companies effectively navigate these changes, we’ve compiled a detailed summary of key methane regulations expected to impact the global oil and gas industry this year. Given the dynamic nature of methane regulations, we will continue to update this content periodically to reflect rule changes and our insights. Please refer to the date above for the latest revision.
Navigate directly to the region and rule below.
United States – Federal
U.S. EPA NSPS Subpart OOOO series rules effective
The U.S. EPA revised and released New Source Performance Standards (NSPS) Subparts OOOO, OOOOa, OOOOb, and OOOOc in 2023. These rules regulate emissions of volatile organic compounds and greenhouse gases from the oil and gas industry.
- NSPS Subpart OOOOb, which became effective in 2024, requires a much higher level of methane emissions control and monitoring for sites that are constructed, reconstructed, or modified after December 6, 2022.
- Emission Guideline OOOOc will trigger additional methane requirements for existing sites that are at least as stringent as NSPS Subpart OOOOb; the new requirements must be enforced by 2027.
What this means for you:
- Work practice and monitoring programs required by NSPS Subpart OOOOb must be in place, including, but not limited to, enhanced leak detection and repair (LDAR) programs, flare and combustion control device monitoring or exclusion testing, and more.
- The first NSPS Subpart OOOOb semiannual and annual reports are due this year and should be submitted online.
- The U.S. EPA is actively reviewing and approving certified third parties who can report super-emitter events under NSPS Subpart OOOOb. As of the date of this article, Carbon Mapper is approved.
- State regulatory agencies are working on developing their State Implementation Plans (SIPs) for Emission Guideline OOOOc.
U.S. EPA greenhouse gas reporting rule effective
The U.S. EPA revised several Greenhouse Gas Mandatory Reporting Rule (GHG MRR) subparts in 2024. Subpart W, which regulates reporting for the oil and gas industry, will be used to determine the methane waste emissions charge described below. The revisions to Subpart W are intended to increase the accuracy of the reported emissions inventory by requiring reporting of emission sources not previously included and allowing for the use of empirical site-specific data to develop measurement-informed emissions inventories. In many cases, Montrose has seen significant reductions in reported emissions when using measurement-based data compared to default emission factors.
What this means for you:
- Some of the site-specific measurement provisions of the revised Subpart W rule could optionally be implemented in calendar year (CY) 2024. The U.S. EPA is finalizing updated calculation tools and reporting forms that integrate the optional methods. The CY2024 report is due on March 31, 2025.
- The revised rule is fully effective and required for CY2025. Sites need to collect all data required for the CY2025 inventory now. Additionally, sites subject to the rule should have a revised GHG monitoring plan in place outlining their selected monitoring and calculation methodologies.
U.S. EPA Methane Waste Emission Charge effective
As dictated by the Inflation Reduction Act, the U.S. EPA finalized the first methane fee in the United States. The WEC applies to the oil and natural gas industry and is calculated based on emissions reported under Subpart W of the GHG MRR (see above). Companies are given a methane allowance based on throughput and industry segment. Emissions over the allowance are subject to a fee per metric ton of methane:
- $900 per metric ton for CY2024
- $1200 per metric ton for CY2025, and
- $1500 per metric ton for CY2026 and beyond.
The allowance and fee calculations can be netted across a company’s reporting facilities. The fee is due on August 31 annually.
What this means for you:
- Environmental data is financial data beginning for the CY2024 report. There is now a direct financial driver for increasing the accuracy of the reported emissions and decreasing emissions.
- The first fee is based on reported CY2024 emissions and is due on August 31, 2025.
U.S. DOT PHMSA Rule finalized January 17, 2025
The U.S. Department of Transportation proposed new pipeline safety leak detection and repair (LDAR) requirements through Pipeline and Hazardous Materials Safety Administration (PHMSA). The rule, as proposed, strengthens LDAR requirements for new and existing gas transmission pipelines, distribution pipelines, regulated (Types A, B, C and offshore) gas gathering pipelines, underground natural gas storage facilities, and liquefied natural gas facilities to curb methane emissions. The rule includes revised leak definitions, increases leak survey requirements, and implements mandatory repair timelines, among other changes. The rule was proposed in May 2023, and the rule was finalized on January 17, 2025. It has not yet been published in the Federal Register. It will be effective 180 days after publication, and the rule compliance date is January 1, 2028. Montrose is working on a full analysis of the final rule and will update this page with more detail soon.
What this means for you:
- The rule is newly published and established new LDAR requirements that both increase the frequency of scans and allow for advanced monitoring technologies.
- As it stands today, the rule will be effective 180 days after publication in the Federal Register, and the compliance date is January 1, 2028.
- Based on the date of rule finalization and the changes in the U.S. Administration, it is possible this rule may be impacted by the Congressional Review Act (CRA).
United States – State
Colorado GHG intensity verification requirements effective
Colorado enacted a landmark GHG emissions verification rule that requires upstream oil and gas operators to use direct measurement to inform their emissions inventory and calculate their GHG intensity. The verification rule is in effect beginning with the 2025 emissions inventory, which is due in 2026. Verification will also be required for the 2027 and 2030 inventories, due in 2028 and 2031, respectively. The rule is designed to ensure accuracy in emission calculations and reporting, and the state will incorporate its own aerial and ground monitoring into the calculations. Operators will have the option to use state default verification factors or operator-derived verification. Operator-derived verification requires independent verification by an accredited third-party auditor, currently aligning to MiQ or ISO 14064.
What this means for you:
- Robust data collection procedures for the 2025 emissions inventory should be in place to ensure an accurate calculated 2025 annual emissions inventory.
- If using operator-derived verification, monitoring data should be collected in 2025 and documented and analyzed throughout the year. In addition, operators should engage with an independent auditor.
California Senate Bill 1137 regulating oil and gas production in health protection zones effective
California passed Senate Bill 1137 (SB 1137) and subsequently Assembly Bill No. 218 (AB 218), which prohibits the construction of new oil and gas production facilities within a health protection zone (HPZ) or located within 3,200 feet from a sensitive receptor. It also establishes stringent engineering, operational, and monitoring requirements for existing oil and gas production operations within an HPZ or within 3,200 feet from a sensitive receptor. This rule is in effect, but specific requirements are phased, with the next requirement being a sensitive receptor inventory and map due by July 1, 2025. Health, safety, and environmental requirements, including but not limited to enhanced LDAR, are effective July 1, 2026. Operators are required to submit a leak detection and response plan by 2028, to be fully implemented by 2030.
What this means for you:
- Operators in an effective area must develop and submit their sensitive receptor inventory and map by July 1, 2025.
- Sites must fully comply with other operational and engineering requirements by July 1, 2026, and ensure a thorough understanding of those requirements this year.
- Continuous emissions monitoring programs take time to implement, and Montrose recommends starting to lay the groundwork for those programs.
Canada – Federal
Canadian proposed Amendments to the federal methane regulations for the oil and gas sector not yet finalized
Canada’s Environment and Climate Change Canada (ECCC) published a draft rule to reduce O&G methane emissions by 75% below 2012 levels by 2030. The draft rule was released in December 2023 and is expected to be finalized soon. The rule as proposed includes requirements for, but not limited to, LDAR programs (frequency, repair timelines, and verification by a third party) and emissions control equipment performance standards. It also prohibits venting and requires collection or control of gas released during fracking completions. The compliance deadlines, as proposed, are 2027 for new facilities and 2030 for existing facilities.
What this means for you:
- There are no new federal requirements at this time.
- Based on the anticipated compliance dates, Canadian operators may benefit from laying the groundwork for revised LDAR programs and exploring what changes are necessary from an operational and equipment/process design standpoint.
Canada – Provincial
Saskatchewan’s new methane regulations effective January 1, 2025
Saskatchewan’s Ministry of Energy and Resources finalized methane regulations targeting methane emissions from the upstream oil and gas industry in 2024. The regulation, which focuses primarily on LDAR programs and pneumatic venting, is effective this year. The rule requires semiannual LDAR surveys until 2027 when the frequency increases to three times annually. The rule also requires that new facilities do not vent gas from pneumatic devices and that existing facilities reduce venting emissions from pneumatic devices with phased reduction requirements until December 2028, when all pneumatic device venting must be eliminated.
What this means for you:
- LDAR programs with the increased survey frequency should be in place now, and operators must ensure that all required records are maintained.
- New facilities must be designed with no natural gas-actuated pneumatic devices venting to atmosphere.
- Existing facilities must phase out natural gas-actuated pneumatic devices, achieving a 25% reduction in venting emissions by December 31, 2025. 50%, 75%, and 100% reduction requirements apply in 2026, 2027, and 2028, respectively.
- The initial annual report is due April 1, 2025.
British Columbia’s new methane regulations effective January 1, 2025
The British Columbia Energy Regulator amended its Drilling and Production Regulation to reduce methane emissions from the upstream oil and gas industry. The regulation includes work practice requirements to reduce venting emissions, requires enhanced LDAR programs, and necessitates that operators eliminate venting emissions from natural gas-actuated pneumatic devices and compressors. The LDAR monitoring frequencies and venting standards are effective January 1, 2025. New facilities may not install natural gas-actuated pneumatic devices that vent to atmosphere, also beginning January 1, 2025. The other requirements become effective in a phased manner from January 1, 2026, through January 1, 2035.
What this means for you:
- LDAR programs with the increased survey frequency should be in place now, and operators must ensure that all required records are maintained.
- New facilities must be designed with no natural gas-actuated pneumatic devices venting to the atmosphere.
- Compressor seal venting requirements apply on January 1, 2025, and operators must ensure their compressors comply on an individual and fleet basis.
- Venting reports are due annually on March 31.
- Operators should ensure that they have a plan to meet the remaining work practice and operational requirements that become effective 2026 – 2035.
Global
European Union Methane Regulation adopted and will impact global energy producers
The European Union Methane Regulation (EUMR) is a monitoring, reporting, and verification (MRV) framework that applies to imported natural gas, oil, and coal. It requires that European energy importers disclose the upstream methane emissions associated with the product, as determined through a measurement-based program. It also imposes methane intensity limits on imported energy. Because the requirements apply to energy producers, regardless of country of origin, the regulation is expected to have global impacts on energy producers. Energy producers should expect to see methane MRV requirements in contracts this year. The compliance deadlines are phased with the first MRV reports due in August 2025 and emissions intensity limits in August 2030.
What this means for you:
- The EUMR is another example of environmental data becoming business and financial data, as compliance with this rule will impact energy producers’ ability to conduct business in the EU.
- The first MRV reports, which can use emissions factors, are due in August 2025. Measurement programs, including source- and site-level measurements, are due in due in February 2026 and February 2027, respectively.
- There are three paths of equivalency to comply with the EUMR, (1) national-level equivalency through federal requirements, (2) producer-level equivalency to be approved on a case-by-case basis, and (3) OGMP 2.0 gold standard + independent verification. There are currently no federal programs approved for national-level equivalency.
- Compliance with this new rule is expected to be especially complex for the liquified natural gas (LNG) value chain, particularly in pooled markets like the U.S., where multiple natural gas streams from multiple producers are combined prior to reaching a liquefaction facility.
- Although the rule is final, the EU Commission will release additional guidance on equivalency demonstrations, emissions intensity determinations, emissions intensity limits, and more. Here is one recently released Q&A document.
Japan and South Korea launch initiative to reduce emissions associated with imported LNG
Several Japanese and South Korean utilities and trading houses joined the Coalition for LNG Emission Abatement Toward Net Zero (CLEAN) Initiative designed to drive down methane emissions from the LNG supply chain. Like the EUMR, above, the CLEAN initiative framework applies first to the LNG buyer but is intended to influence the upstream value chain. Based on the 2024 Annual CLEAN report, member companies receive a questionnaire that collects data on value chain methane emissions and methane emissions reduction initiatives to compile methane emissions reduction best practices.
What this means for you:
- The CLEAN Initiative is another example of an effort to influence supply chain emissions through the energy importer.
- Companies whose products ultimately end up in LNG should expect receive requests for empirical data related to methane emissions and intensities associated with their products.
- The CLEAN Initiative is not yet codified in either Japan’s or South Korea’s environmental or import regulations.
What Next?
Feeling like you can’t keep up? Wondering how you will meet applicable work practice, monitoring, and reporting requirements? Curious if there are synergies to be had between the regulatory requirements and voluntary frameworks such as OGMP 2.0 or MiQ? Interested in working with your state regulatory agency in the development of SIPs? Rest assured that Montrose knows methane.
We take a comprehensive approach to measurement, management, and reduction of methane emissions from strategy and program development to boots-on-the-ground methane detection and measurement. We assist companies in addressing their toughest climate and broader sustainability challenges, including transitioning to a low-carbon economy while continuing to thrive in the oil and gas marketplace.
Elizabeth McGurk,
Methane Market Sector Leader
Elizabeth is a highly-experienced air quality program manager with expertise in the fields of greenhouse gas (GHG) quantification and mitigation, oil and gas sustainability framework implementation, regulatory analysis, and auditing. Her passion is in leveraging measurement-informed data to inform effective mitigation efforts, and she is proud to have supported OGMP 2.0 projects worldwide. Elizabeth has a strong background in delivering technical trainings and excels in distilling and presenting complex information, impacts, and solutions to various stakeholders. She leads diverse teams and has conducted complex environmental projects, both regulatorily and voluntarily driven, for clients in carbon-intensive industries. She specializes in assisting clients with Scope 1, Scope 2, and Scope 3 GHG emissions quantification and reporting as well as in developing practical, real-world carbon reduction strategies.
