What’s Next for Oil and Gas Methane Regulations

Emerging Rules in the United States and the European Union

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The Issue

Proposed methane regulations for the oil and gas industry are in the works in the United States and the European Union. These new rules—especially the U.S. regulations—could play a critical role in curbing emissions. This brief summarizes the next steps for methane rules on both sides of the Atlantic, including an overview of the emerging regulations in the United States and a synopsis of the EU methane legislation process. It identifies areas that require more analysis, such as how closely measurement, reporting, and verification (MRV), leak detection and repair (LDAR), and reporting requirements will align. The brief also summarizes the current EU approach to reducing methane emissions from its gas imports as well as its longer-term aspirations, outlining the implications for gas exporters to Europe.

Methane is a potent greenhouse gas, with more than 80 times the warming potential of carbon dioxide in its first 20 years in the atmosphere. Methane is likely responsible for at least 25 percent of global warming in the industrial era. Because it is a short-lived climate pollutant, reducing methane emissions quickly is one of the best ways to slow the pace of global warming—but annual increases in atmospheric concentrations of methane are still growing. Policymakers are keen to make progress and recognize that the oil and gas sector presents the best opportunities for cost-effective methane abatement. Proposed methane regulations for the oil and gas industry are in the works in the United States and the European Union, and these new rules—especially the U.S. regulations—could play a critical role in curbing emissions.

Regulations in Washington, D.C., and methane legislation in Brussels have not yet been finalized and there is still substantial uncertainty about how the EU legislation will take shape. Although proposed U.S. and EU rules share many common elements, their measurement, reporting, and verification (MRV) and leak detection and repair (LDAR) requirements vary. The two jurisdictions are also adopting different approaches to methane detection technology. Perhaps the most critical link between the U.S. and EU methane rules concerns natural gas imports to Europe. For now, the European Union seems unlikely to impose a strict methane performance standard or specific MRV requirements on suppliers. But Brussels does seem likely to require gas importers to provide information about suppliers’ MRV and methane mitigation practices.

This brief summarizes the next steps for methane rules on both sides of the Atlantic, including an overview of the emerging regulations in the United States and a synopsis of the EU methane legislation process. It identifies areas that require more analysis, such as how closely MRV, LDAR, and reporting requirements will align. Finally, the brief summarizes the current EU approach to reducing methane emissions from its gas imports, as well as its longer-term aspirations, outlining the implications for gas exporters to Europe.

U.S. Regulations on the Way

In November 2022, the United States Environmental Protection Agency (EPA) issued its supplemental proposal for the regulation of methane and volatile organic compounds (VOCs) from new facilities, as well as methane from existing facilities, in the oil and gas industry. The supplemental proposal updates and expands on the EPA’s November 2021 proposal for oil and gas methane regulations, which generated more than 470,000 public comments. It includes a number of changes from the previous version.

The supplemental proposal would require routine monitoring at all well sites for fugitive emissions—regardless of production size—and would oblige operators to repair any leaks found. Monitoring requirements would be in place for the entire life of the well site. By contrast, under the November 2021 rule, any well sites with less than three tons per year of methane emissions, per an initial survey, would be exempt from routine monitoring, while well sites with estimated emissions above three tons per year would have required quarterly optical gas imaging (OGI) or Method 21 monitoring. The supplemental proposal also covers other sources that were left out of the November 2021 proposal, including orphaned and unplugged wells. It sets a zero emissions standard for pneumatic pumps and controllers (natural gas–powered pneumatic devices are a large source of methane emissions), with some potential exceptions. The supplemental proposal also includes more stringent flaring rules.

The EPA has also proposed a significant new initiative called the Super Emitter Response Program (SERP). A key challenge in curbing methane emissions from oil and gas is the prevalence of “super emitters,” or large plumes that can result from venting or equipment failures. Continuous monitoring systems, satellite surveillance, and drone and airplane surveys will produce an ever-growing amount of data on methane emissions in the coming years. The SERP would allow approved third-party organizations to identify these events (which the EPA defines as those emitting 100 kilograms of methane or more per hour), notify owners and operators, and prompt an investigation and remediation effort. There are many open questions about how this program will work. The EPA will need to approve detection technologies, as well as entities, to take part in the SERP, which could be complicated and time consuming. The EPA will also need to set rules about how quickly notifiers must get in touch with operators and how much time the agency will allow for operators to analyze such events and mitigate problems. The agency sought public comments on these matters when it issued the supplemental proposal.

Another significant change concerns methane detection technology. Numerous public comments on the November 2021 rule called for more freedom to employ detection technologies aside from OGI. In the supplemental proposal, the EPA suggested the use of a broader range of advanced methane detection technology, allowing periodic screening or continuous monitoring. A proposed matrix approach would tie the frequency of required monitoring surveys to the detection threshold of those technologies (see Tables 1 and 2). In implementing this rule, a critical challenge for the EPA will be to allow operators to use technologies that meet specific performance criteria. The key is for such technologies to demonstrate equivalent detection capacity over a defined period of time.

Table 1. Alternative Approaches for Facilities  Subject to Quarterly Optical Gas Imaging (OGI)  Monitoring
Table 2. Alternative Approaches for Single and  Multi-wellhead Only Sites and Small Sites

Aside from the forthcoming EPA regulations, two other important U.S. rules on methane are expected this year: one on the Inflation Reduction Act (IRA) methane fee and one on the Waste Prevention Rule for federal lands from the Bureau of Land Management (BLM). The IRA includes a fee, or “waste emissions charge,” on methane emissions from oil and gas operations based on certain emissions intensity thresholds, building on earlier legislative proposals. The methane fee will start at $900 per metric ton in 2025 for emissions reported for calendar year 2024, rising to $1,200 per ton in 2026 and $1,500 per ton in 2027 and thereafter. Later this year, the EPA plans to finalize rules on the implementation of the IRA methane fee, as well as new guidance for Subpart W of the EPA’s Greenhouse Gas Reporting Program, which sets reporting requirements for oil and natural gas facilities. Finally, in November 2022, the BLM published a proposed waste prevention rule designed to prevent methane waste and loss of natural gas at oil and gas lease sites on public lands.

The Biden administration likely aims to finalize these rules before the 2023 UN Climate Change Conference (COP28) begins on November 30. Public comments on the EPA supplemental proposal closed on February 13, 2023, and the agency aims to finalize the rule by August. Public comments on the BLM’s waste prevention rule closed on January 30, 2023, and the BLM aims to finalize that rule by September. By October, the EPA aims to finalize rules regarding the IRA methane fee and Subpart W. Finalizing all of these regulations by the end of the year will require significant effort, especially at the EPA.

The timing has important implications. First, as with other climate policies, the Biden administration is in a race to finish rules and regulations by the end of this year to ensure their durability. Completing the regulations this year, as opposed to in 2024, would protect them from potentially being overturned by a joint resolution of disapproval under the Congressional Review Act.

Second, the timeline could affect the rollout of the IRA methane fee, which targets the same oil and gas sector facilities that will be covered by EPA methane regulations. The IRA adds Section 136 to the Clean Air Act, noting that facilities subject to both the methane fee and the EPA regulations will be exempt from the former if EPA regulations are in effect in all states and will “result in equivalent or greater emissions reductions as would be achieved” by the November 2021 proposed rule. These conditions appear strategic. The first condition provides an incentive for industry to push states to finalize their compliance plans quickly so they can avoid the methane fee. The second condition discourages a future administration from rolling back the stringency of the EPA regulations, because such a rollback will trigger the methane fee. 

Regarding the timeline for state compliance plans, there are several questions to consider. The EPA has proposed that states submit their own plans to create, implement, and enforce emissions performance standards within 18 months of promulgation of the final rule. The EPA also proposes that states impose a compliance timeline no later than 36 months after such plans are submitted. The EPA hopes that its own standards will establish a model rule and “will create a streamlined approach for states in developing plans and the EPA in evaluating state plans.” But even if the rule is finalized this year, the EPA projects that the process for submission and approval of state plans will extend into 2026—while the IRA methane fee first applies in 2025 with respect to 2024 emissions. Therefore, it seems likely that even facilities covered by the EPA regulation will be subject to the IRA methane fee provisions for at least one year. In addition, there are some oil and gas sector facilities subject to the IRA methane fee that are not covered by the EPA regulation at all, including offshore production facilities and liquefied natural gas (LNG) terminals. 

It is possible that some states will drag their feet on emissions performance standards. But presumably, oil and gas companies would prefer that states adopt new standards quickly so they can avoid the IRA methane charge. When the EPA rule is finalized, engagement with state regulators and development of state plans will be key focus areas.

The Journey Continues for EU Methane Legislation

Methane legislation is also advancing in Europe, but the path ahead is less certain. The European Union has been considering the impact of methane emissions in the oil and gas industry for several years. The European Commission introduced its methane strategy in October 2020 and a legislative proposal for methane regulations in December 2021. This proposal would require companies to submit source-level MRV data and would impose LDAR requirements, as well as a ban on routine flaring or venting. The European Council reached general agreement on a version of the methane legislation in December 2022, softening numerous requirements in the commission text. The focus has now shifted to the European Parliament, which is expected to push for more ambitious policies, and the next steps in the legislative process are complicated.

The European Council’s general approach to methane legislation in December 2022 watered down some of the key elements of the commission’s original proposal. MRV requirements and importer requirements remained largely untouched, but the council made substantial changes to LDAR requirements and flaring and venting rules. Instead of requiring LDAR inspections of all relevant components every three months, as in the commission’s legislative proposal, requirements in the council text vary for different types of equipment (see Table 3). For example, operators will be able to conduct inspections of flare stacks monthly instead of weekly. Oil and gas wells with 200–700 meters of water depth will be exempt from leak inspections “unless there is a documented risk of migration of methane leaks to the atmosphere,” while the rules will not apply to wells with more than 700 meters of water depth.

Table 3. EU Council Text: LDAR Requirements

Advocates of tougher rules on methane emissions are deeply disappointed with the council text. They argue that watering down the LDAR requirements will make it harder to spot leaks and fix them promptly and that exempting midstream and downstream equipment from regular inspections is a mistake. Environmental organizations believe Europe risks backtracking on methane emissions, even as the United States and other countries are strengthening their regulations. They blame oil and gas companies for influencing the outcome in the council. The European Council’s general agreement on methane legislation reflects a decisionmaking process that is opaque compared with that of the European Commission and the European Parliament. The council’s legislative priorities are subject to change depending on the control of the presidency, which rotates between countries every six months (Sweden holds the presidency January 1–June 30, 2023, to be followed by Spain). The parliamentary makeup in member states also influences council decisions, and environmental organizations suggest that during the French and Czech presidencies in 2022, industry voices were successful in scaling back ambitions.

On the other hand, oil and gas companies believe the commission proposal included onerous requirements that would have done little to cut methane emissions and would have carried unintended consequences. Upstream operators claim that weekly audio, visual, and olfactory inspections of flare stacks, for example, would require operational shutdowns of several days at offshore wells to ensure personnel safety, creating significant production losses. They argue that the commission proposal to include all permanently plugged wells is misguided, because the challenge with orphaned wells does not exist in Europe as it does in the United States due to clearer licenses and procedures for plugging and abandonment. Downstream companies claim that frequent inspections of pipelines and compressor stations would be redundant and costly. They argue that LDAR inspections of the entire transportation and distribution network in Europe, totaling some 200,000 kilometers of transmission pipelines and 2 million kilometers of distribution pipelines, would impose significant costs on companies and ignore existing practices to find and fix leaks.

The next stage of debates over these issues is taking place in the European Parliament, where amendments have already been tabled. Typically, the parliament is seen as more idealistic and more likely to push for ambitious climate policies, so the expectation is that it will want significant changes from the council version. But there is disagreement within the parliament over the methane legislation, making the outcome hard to predict. The Greens/European Free Alliance and Renew Europe, including the rapporteur of the critical Industry Research and Energy Committee, are pushing for more ambitious LDAR requirements and import rules. Other parties prefer an approach in line with the council text.

Some press articles suggest the goal is to hold a plenary vote in the parliament as soon as the end of March. Co-legislators in the commission, council, and parliament could then enter discussions known as a “trilogue” in the subsequent months. The EU goal is to finalize the methane legislation by the end of 2023. However, this timeline first depends on the outcome in the parliament. Ultimately, it seems more likely that the final methane legislation will more closely resemble the council version than the commission’s legislative proposal, but unexpected changes could occur as the process unfolds.

An overarching challenge is that with Russia’s invasion of Ukraine and the subsequent focus on energy security and high prices, regulations on methane emissions have simply slipped down the agenda. In the past year, the European Union has been forced to juggle many urgent energy priorities. At the moment, issues surrounding electricity market regulation are taking precedence.

Alignment on U.S. and EU Methane Rules

Policymakers in Washington and Brussels are coordinating on shared goals to scale up ambition on methane mitigation. Aligning U.S. and EU regulations as much as possible would simplify operator requirements, create more uniform reporting standards, ensure effectiveness, and promote rules that other regions can emulate. That said, there are many remaining questions about how well the rules will align.

Ideally, convergence between methane rules in the United States and the European Union would create powerful new standards for upstream and midstream operators. In theory, an offshore operator with assets in the North Sea and the U.S. Gulf of Mexico would apply similar LDAR practices, helping to standardize operations and minimize costs. Companies would adopt the same practices to limit routine flaring and venting. Operators would face similar MRV requirements. Advocates of tough regulations suggest the best case scenario would be establishing the Level 4 or 5 reporting guidelines of the Oil and Gas Methane Partnership (OGMP) 2.0 reporting framework—entailing, at minimum, direct measurement of source-level emissions—as the new “gold standard.”

In practice, it may not be so easy to adopt uniform methane rules. One obvious challenge is that most EU oil and gas production is offshore, while 85 percent of U.S. crude oil is produced onshore. Relatively few upstream operators have significant offshore assets in both countries. Additionally, U.S. regulations and reporting requirements apply to upstream and midstream asset owners and operators, while EU requirements apply across the oil and gas value chain, including gas distribution.

In terms of upstream operations, in some areas, the United States and the European Union seem to be aligning—for example, in flaring and venting rules. EPA regulations, as well as legislative language from both the European Commission and the European Council, would impose flaring efficiency requirements (a 95 percent reduction in methane and VOC emissions in the EPA supplemental proposal and 98 percent efficiency per Article 17 of the European Council text). The European Union is seeking to ban routine flaring, while the EPA so far has not matched rules in Colorado and New Mexico that ban routine flaring. The agency sought comment on steps it should consider taking “to disallow the indefinite continuation of routine flaring.”

In other areas, it is hard to predict how well U.S. and EU rules will align. Since the European methane legislation is still taking shape, most of the critical requirements for LDAR are yet to be determined, making it hard to compare with U.S. rules. The same is true for some elements of MRV.

Some areas of uncertainty include the following:

  • How the United States and the European Union may differ in accommodating fast-changing technology for methane monitoring
  • How LDAR requirements will vary between the proposed U.S. and EU rules, and whether it is feasible and cost-effective for companies to apply the same operational practices globally
  • How emissions reporting could become more standardized, and whether companies may need to maintain different “books” to meet requirements in different jurisdictions
  • How data from national inventories, scientific studies, satellites, and remote sensing can be collected, integrated, and vetted to help satisfy U.S. and EU regulatory requirements.

EU Gas Import Standard Likely off the Table for Now, but Still a Key Goal

Another critically important issue is how the European Union might impose new requirements on imported gas. Because the European Union relies on imports for more than 80 percent of its gas supply, advocates consider the issue of traded gas to be far more important than regulations on domestic production. Many policymakers believe that as a large gas importer, the European Union could send an important signal to suppliers and promote methane reductions throughout the global gas industry if it imposes a methane intensity standard for its imported gas. However, these ambitions are colliding with the reality of a tight global LNG market and elevated prices. In 2022, the European Union’s LNG imports rose by about 60 percent over the previous year and they are likely to remain high. Brussels and EU member states must balance methane reduction targets against energy security concerns.

Figure 1. European Union Gas Imports by Origin, 2022

The European Commission’s 2021 legislative proposal noted that a key objective was to “set incentives to reduce methane emissions in partner countries by creating transparency in the market.” Chapter 5 and Annex VIII of the legislative proposal outline these requirements in detail. Within nine months of the regulation’s entry into force and every year thereafter, EU gas importers would need to provide certain information to the competent authorities of the relevant member states. The commission envisions this information requirement as a way for Europe to drive down global methane emissions associated with European gas consumption. The assumption is that if the European Union sets these demands, gas exporters will have to comply to avoid jeopardizing their access to the European market.

The commission aims to start gathering data for a public “methane transparency database” of EU gas supplies, covering both supplier countries and companies. In its 2020 methane strategy, the European Union established a goal of creating an International Methane Emissions Observatory (launched at the G20 Summit in 2021), as well as a Methane Supply Index to better inform buyers on the emission intensity of various gas supply streams. The focus is on forcing suppliers to provide empirical data based on actual measurements, rather than estimates based on emissions factors.

Table 4. EU Legislative Proposal: Importer Requirements

The implicit assumption is that in several years, EU buyers will have several options. Buyers armed with comparative data on the methane intensity of gas from various countries—or, ideally, subnational data from key producing basins—could prioritize “cleaner” or less emissions-intensive gas. If, for example, empirical data suggests that Algerian gas is more emissions-intensive than LNG from Qatar or pipeline supplies from Azerbaijan, buyers could prioritize gas from the latter two countries. If the European Union deems this data to be sufficient and trustworthy, it may decide to impose a methane performance standard—perhaps a benchmark for upstream emissions intensity similar to the IRA methane fee threshold of 0.2 percent in the United States. The European Union could then impose a fee for suppliers that fall short of this standard, or perhaps even restrict their access to the EU market.

One key question is when the European Union will feel emboldened to make such moves. The European Commission’s December 2021 proposal did not include any mention of a performance standard or of restrictions on market access. High natural gas prices since mid-2021 and the intense focus on energy security since Russia’s war on Ukraine make some member states wary of measures that could raise gas prices or jeopardize supplies. Yet, from the start, climate hawks in the European Union have pushed for stronger import standards. They argue that without firm import standards and associated MRV and LDAR requirements to prove the veracity of supplier-provided data, the European Union will do little to encourage industry action.

The European Parliament may table some amendments to the legislative proposal to extend the obligations for gas importers. But the prevailing view is that such measures are unlikely to be imposed this year, even if the legislation is finalized. Rather, the European Union may be laying the groundwork for a review in several years, in which new supplier data could be leveraged to impose tougher import rules, perhaps starting in 2026 or 2027.

Regarding the calls for an import standard or methane intensity standard, there are many questions to consider. It is not clear when gas suppliers will be able to meet these requirements, especially for LNG supplies. It is extremely challenging to perform detailed, cargo-specific emissions accounting, which has been a major source of criticism for “carbon-neutral LNG.” The global LNG industry has now published a framework for cargo-specific emissions accounting, including methane emissions, which was recently adopted for the first time in a commercial transaction (although critical details were not made public). But it is no small task to aggregate supply chain–specific empirical data for the production, gathering, transportation, liquefaction, and shipping segments. This is especially challenging in the United States, where LNG exporters often do not produce the gas themselves but rather buy molecules from the grid and sell cargoes on a free-on-board basis. In comparison, an LNG supplier like Qatar may have an easier time meeting such requirements since its state gas company, Qatar Energy, is present throughout the gas value chain.

Several other challenges concern the role of various players and the role of third-party gas certification schemes. How can traders and aggregators meet requirements for records of emissions and LDAR methods if they are not involved in production? Is it feasible to create a “certificate of origin” verifying the emissions intensity of a certain volume of gas that can be transferred from one party to another if the gas changes hands, and how will the European Union verify this data? How will voluntary standards and certification schemes inform regulations, and in turn, how will regulations accelerate progress toward standards for “certified gas”? And finally, how will gas suppliers respond? A number of gas suppliers are likely to object to the European Union’s import requirements and could refuse to allow independent, third-party verification of their emissions—making implementation quite difficult. All of these questions merit more consideration.

Next Steps and Remaining Questions

A big push on methane regulations is underway on both sides of the Atlantic, though the path ahead in the European Union is somewhat uncertain. Tougher rules on oil and gas methane emissions are dovetailing with increased investor and shareholder pressure for companies to cut methane. The United States and the European Union have a shared interest in accelerating progress toward the Global Methane Pledge, as the 2030 target remains well out of sight. However, in many important areas—from MRV and LDAR requirements to accommodating new methane detection technology—the alignment of U.S. and EU rules and regulations is unclear.

Most of the action will happen on the supply side, but a critical link between the United States and Europe is the U.S. LNG industry. It is possible that in several years, firmer EU import rules, EPA regulations in the upstream and midstream segments, and a proliferation of new detection technology will enable significant, verifiable progress in driving down emissions from U.S. LNG. There is more work to be done in analyzing EU rules, reporting requirements in the United States and the European Union, and the roles and responsibilities of various players in the natural gas value chain.

Ben Cahill is a senior fellow with the Energy Security and Climate Change Program at the Center for Strategic and International Studies in Washington, D.C.

The author is grateful to Allegra Dawes and Nevi Cahya Winofa for research assistance, and to Kyle Danish, Carrie Jenks, and Jonathan Stern for their comments. Any remaining errors are solely those of the author.

This brief was made possible by support from Cheniere, as part of a project on alignment between U.S. and EU regulations on methane emissions.

Ben Cahill
Senior Fellow, Energy Security and Climate Change Program