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There are no quick wins in the fight against climate change, but reducing methane emissions from the oil and gas industry is one of the fastest ways to slow the pace of global warming. Policymakers are focusing on curbing emissions of this super pollutant, and there is a growing sense of urgency to accelerate methane cuts from the oil and gas sector. Methane now features prominently in international climate negotiations, and the United States and the European Union are working on domestic rules and regulations as well as cooperative efforts to cut greenhouse gas (GHG) emissions from natural gas.
The U.S. Environmental Protection Agency (EPA) proposed ambitious new methane regulations in November 2021 and introduced a more expansive supplemental proposal in November 2022. The EPA aims to finalize these rules and issue related guidance this year, likely before the 2023 UN Climate Change Conference (COP28) begins on November 30. The European Union introduced a methane strategy in 2020 and a legislative proposal on methane emissions from the oil and gas sector in December 2021. As methane legislation progresses, there should be substantial alignment between U.S. and EU rules in certain areas—for example, in measurement, reporting, and verification (MRV) and flaring and venting standards. With the EU legislation still evolving, it is harder to predict how other rules will take shape.
This white paper analyzes how regulations are developing in the United States and the European Union, identifies areas of uncertainty, and describes how officials in Washington, D.C., and Brussels are collaborating to cut methane emissions from natural gas. It summarizes proposed EU requirements for gas importers related to methane intensity, analyzing potential challenges for gas suppliers in meeting new reporting requirements and potential import standards. Finally, the white paper analyzes the outlook for transatlantic cooperation on frameworks for differentiated, or less emissions-intensive, gas. These are important policy moves, and the white paper outlines the implications for the global gas industry.
Methane is often called a super pollutant. The global warming potential of methane in its first 20 years in the atmosphere is more than 80 times greater than that of carbon dioxide. Scientists estimate methane is responsible for at least 25 percent of global warming in the industrial era. Methane in the atmosphere also increases the concentration of ground-level ozone, harming air quality and contributing to respiratory illnesses. Yet for many years, methane received relatively little attention in international climate policy compared to carbon dioxide.
Methane reductions have garnered more attention in recent climate negotiations for several reasons. First, there is growing recognition that methane cuts are one of the best ways to slow the pace of global warming in the near term due to its relatively short life in the atmosphere. Sharp methane reductions in the next decade can help lengthen the pathway to cut carbon dioxide emissions and avoid a dangerous tipping point in global warming.
Sharp methane reductions in the next decade can help lengthen the pathway to cut carbon dioxide emissions and avoid a dangerous tipping point in global warming.
Second, growing evidence shows that methane emissions, including from the oil and gas sector, are worse than government estimates suggest. Methane emissions have typically been estimated via bottom-up inventories. The EPA’s Greenhouse Gas Inventory essentially counts total oil and gas equipment—such as wellheads, pneumatic devices, storage tanks, and gathering and transmission lines—as well as industry activities, and then applies a typical emissions factor for each piece of equipment or activity to estimate total emissions. This is a robust, comprehensive approach. Indeed, this type of GHG inventory underpins the UN Framework Convention on Climate Change (UNFCCC) national reporting requirements. However, there is a significant discrepancy between bottom-up inventory estimates and top-down estimates of atmospheric methane concentration, which rely on satellite surveillance and aircraft observations. Several studies show methane emissions are up to 60 percent higher than inventory approaches suggest. There are several reasons for this discrepancy. Contributing factors include super-emitters—infrequent events such as equipment failures or poor maintenance practices that produce a disproportionate share of total methane emissions—and leaks from storage tanks and equipment. Better, more comprehensive monitoring of methane emissions is revealing the scale of the problem.
A third reason for the new prominence of methane abatement is that some solutions can be implemented quickly and at relatively little cost. Methane emissions occur from natural sources such as wetlands, oceans, and permafrost melt, but anthropogenic methane emissions make up about 60 percent of the total. The three leading sources of human-caused methane emissions are agriculture, energy, and waste. The UN Environment Program estimates that globally, agriculture accounts for 40 percent of anthropogenic methane emissions; fossil fuel extraction, 35 percent; and waste, 20 percent. There is substantial variation by country (see Figure 1).
Methane abatement solutions are available for each of these industries. Changes to cattle feed and better manure management can cut methane emissions from livestock, and improved irrigation and draining practices can help cut emissions from rice cultivation. Food waste prevention, better separation of organic material from mixed waste, and improved efforts to monitor and quantify emissions and capture landfill gas can help cut emissions from the waste industry. Coal mine methane abatement solutions are also being implemented. But the most immediate, cost-effective solutions are found in the oil and gas sector.
Two key features of the oil and gas industry enable relatively rapid methane cuts. First, finding and fixing leaks, replacing leaky equipment, and eliminating nonemergency flaring and venting allows companies to capture and sell more gas. The International Energy Agency (IEA) estimates that based on average natural gas prices between 2017 and 2021, about half of global investments to cut emissions from oil and gas operations could be made at no net cost. At the elevated gas prices seen in 2022, some 80 percent of methane cuts could be implemented at no net cost. Of course, the actual abatement cost will vary by country depending on prevailing natural gas prices as well as labor and service sector costs. But some of the most powerful tools to cut methane emissions from oil and gas operations are relatively cheap. EQT, one of the largest shale gas producers in the United States, recently replaced or retrofitted all of the 9,000 natural gas-driven pneumatic devices in its operations for just $28 million. A second enabling factor for rapid cuts is that methane production is highly concentrated in the oil and gas sector compared to the waste and agricultural industries. The 100-plus companies that have joined the Oil and Gas Methane Partnership (OGMP 2.0) cover at least one-third of global oil and gas production via their operated and nonoperated assets. In contrast, methane abatement in the waste and agriculture sectors depends on a far wider set of actors.
In cutting methane emissions from oil and gas, most of the action will happen on the supply side. The EPA estimates the production, gathering, and boosting segment contributes more than half of methane emissions from U.S. natural gas systems. Forthcoming EPA regulations on the oil and gas industry, as well as the methane waste emissions charge (methane fee) in the Inflation Reduction Act (IRA), focus on the production and midstream sectors. Industry-wide efforts to cut methane emissions rightly concentrate on these segments.
Gas consumers also have a role to play in cutting methane emissions, both in their own operations and in their gas procurement. Utilities, national oil companies, and other gas companies operate assets such as regasification terminals, storage tanks, and transmission and distribution pipelines. While these facilities in Europe and Asia constitute a small share of global methane emissions, cutting methane can help such companies meet their Scope 1 and Scope 2 targets and their climate and methane commitments.
Gas consumers also have a role to play in cutting methane emissions, both in their own operations and in their gas procurement.
Gas-importing countries can also exercise leverage as consumers to help drive down global oil and gas emissions. Many gas-importing countries signed the Global Methane Pledge, a collective global agreement to cut methane emissions by 30 percent from 2020 levels by 2030. There is growing awareness and sensitivity to the methane emissions intensity associated with natural gas, but so far methane intensity has not yet become a big factor in pipeline gas and liquefied natural gas (LNG) purchases. However, the landscape is changing. The United States, the European Union, and other states are collaborating on efforts to reduce the GHG intensity of traded fossil fuels, and numerous multilateral initiatives are underway.
New methane regulations are in the works in both the United States and the European Union. New rules in the United States have the potential to significantly cut oil and gas methane emissions by covering more assets and adopting new approaches to detect and address super-emitters. New EPA regulations will also allow operators greater flexibility in applying a range of methane detection technology. EU methane legislation, which has been slower to materialize but is moving through the legislative process, would be a significant step forward in cutting emissions from the entire natural gas value chain, from upstream production through distribution. As a marginal area of oil and gas production, the most significant impact of EU methane legislation could be new rules and requirements for natural gas imports.
As a marginal area of oil and gas production, the most significant impact of EU methane legislation could be new rules and requirements for natural gas imports.
In November 2022 the EPA introduced its supplemental proposal for the regulation of methane and volatile organic compounds from new oil and gas facilities as well as methane from existing facilities. This was a second iteration of proposed regulations, following the EPA’s November 2021 proposed rule. The supplemental proposal is broader in scope, covering a wider range of upstream production sources including wells with lower production volumes. The supplemental proposal sets a zero-emissions standard for pneumatic pumps and controllers. It includes more stringent flaring rules. The latest EPA proposal would also require routine monitoring for fugitive emissions at all well sites, as opposed to the previous version of the rule, which would have exempted well sites with less than three tons per year of emissions, per an initial survey.
The EPA supplemental proposal introduces a few novel elements. The agency has proposed a Super-Emitter Response Program, which would allow approved third-party organizations to identify super-emitter events (above 100 kilograms per hour, per the EPA’s definition), notify asset owners and operators, and require an investigation and remediation effort. The EPA still needs to clarify important rules underpinning this program, such as how quickly third parties must notify asset owners and how much time operators will have to analyze such events and find solutions. The agency has sought comments on these issues, and oil and gas companies have concerns. A second new element of the EPA proposal is an effort to give operators more flexibility to apply various detection technologies. The agency aims to set a performance standard but allow a broader range of advanced methane detection technologies, including periodic screenings and continuous monitoring. The EPA would employ a matrix approach (outlined in tables 20 and 21 of the proposed rule), in which the detection threshold or sensitivity of various detection technologies would determine how often they must be applied. The goal is to set a tough performance standard but avoid being overly prescriptive since methane detection is a fast-evolving industry.
EPA efforts to finalize methane regulations in 2023 coincide with other important rules. As noted, the IRA passed in August 2022 includes a waste emissions charge, or fee on methane emissions above certain intensity thresholds for upstream production, nonproduction petroleum and natural gas systems, and gas transmission facilities. The IRA methane fee will apply to facilities that report more than 25,000 metric tons of carbon dioxide per year under current EPA GHG reporting rules. The methane fee first applies in 2025 for reported calendar emissions in 2024.
EPA regulations on the oil and gas industry are closely linked to the rollout of the IRA methane fee because of an important exemption. The IRA states that facilities subject to both EPA regulations and the methane fee will be exempt from the latter if EPA regulations are in effect in all states and “will result in equivalent or greater emissions reductions as would be achieved” by the EPA’s November 2021 proposed rule. This creates strong incentives for the oil and gas industry to support more rapid state-level action on compliance plans and discourages future administrations from rolling back the EPA regulations since doing so could trigger the IRA methane fee on more companies. (For details, see CSIS brief “What’s Next for Oil and Gas Methane Regulations”). The EPA aims to finalize its oil and gas methane regulations by August 2023. After EPA rules are finished, an important focus area will be state compliance plans and coordination with state regulators.
Meanwhile, EU methane legislation is proceeding, but some important elements need to be negotiated between the European Commission, the Council of the European Union (Council), and the European Parliament. On May 9, 2023, the parliament approved a version of methane legislation that covers natural gas imports as well as domestic production, illustrating a strong desire for Europe to drive down methane emissions associated with its imports. However, it remains uncertain whether these rules will remain in the final EU methane legislation.
The European Union introduced its methane strategy in October 2020, followed by a legislative proposal on methane emissions from the commission in December 2021. Since that time, methane legislation has been advancing slowly through EU legislative bodies, with other energy concerns taking precedence since March 2022 due to Russia’s war on Ukraine. In December 2022 the council issued its general approach to methane legislation, which watered down some key elements of leak detection and repair (LDAR) and flaring and venting rules. The council’s general approach exempted some offshore facilities from leak detection requirements. It also suggested a range of requirements for LDAR inspections for various components, in contrast with the commission’s proposed requirement that all components be inspected every three months. The parliament has approved more stringent rules, and negotiations with EU member states will likely take place in the summer. The European Union aims to vote on final legislation in the fall.
This paper focuses on U.S. methane regulations and EU methane legislation, but several other current and proposed policies also call for more detailed methane emissions accounting. The European Union’s “Fit for 55” climate plans include an extension of the EU Emissions Trading System (ETS) to cover the maritime shipping industry. The ETS for shipping emissions will cover carbon dioxide beginning in 2024, but will also cover methane and nitrous oxide beginning in 2026—and the MRV methodology for non-CO2 emissions accounting is not yet established. The European Union’s Corporate Sustainability Due Diligence Directive (CSDDD), with separate versions of legislation approved by the parliament and council and pending finalization this year, will also set out detailed environmental, social, and governance requirements for companies that vary depending on their staff size and annual revenue. CSDDD would require companies to develop climate plans to show that their business and strategy “are compatible with the transition to a sustainable economy and with the limiting of global warming to 1.5° C in line with the Paris Agreement.” Article 15 of the commission legislative proposal states that if climate change “is a principal impact of” the company’s operations, such plans should include emissions reduction objectives.
As regulations and methane legislation evolve in the United States and the European Union, the extent of regulatory alignment is uncertain. In theory, similar rules in the United States and the European Union could simplify reporting requirements and operational practices. But will the same methane detection technology satisfy requirements in both the United States and Europe? Can companies adopt standard operational practices for LDAR to meet requirements in both areas? Will operators in the United States and the European Union be able to implement similar MRV practices? These questions are difficult to answer definitively, as significant differences remain between the three legislative proposals from the commission, council, and parliament, including the requirements for LDAR and flaring and venting. But it is important to consider how the pieces fit together.
In terms of implementation—the day-to-day work of detecting methane leaks, mitigating problems, installing new equipment, and changing operational practices to eliminate nonemergency flaring and venting—companies will be subject to different rules. With regard to methane detection, new EPA regulations are designed to allow operators flexibility in implementing advanced methane detection technology. As noted, the EPA regulations would let companies apply different detection methods, and the frequency of required inspections would depend on the detection threshold of those technologies. Proposed EU rules are more prescriptive, and they also cover gas distribution. Operating environments also differ between the United States and the European Union: the latter has a much higher share of offshore versus onshore output, and different workforce and safety rules apply.
LDAR practices may be hard for companies in the United States and the European Union to standardize, even for the relatively few companies that have significant production volumes in both regions. In the European Union, the continuing policy debates surrounding LDAR and flaring and venting make alignment with U.S. rules difficult to assess. The commission’s initial proposal required operators to carry out LDAR surveys of all relevant components every three months using devices that detected leaks of 500 parts per million or more. During the comment period, industry respondents criticized this requirement as overly prescriptive and ineffective at reducing methane emissions. Some oil and gas companies highlighted the cost and practical challenges of surveying all distribution network components every three months for leaks. The council relaxed these requirements in its general agreement on legislation, varying the frequency and sensitivity of surveys by different components. The council raised detection limits and repair thresholds “to increase the efficiency of addressing significant volumes of leaks rather than [the] larger number of small leaks representing lower shares of emissions.” Environmental organizations objected to these changes. The more recent parliament approach includes stricter requirements than those of the council—including one option for quarterly inspections of aboveground components with a minimum detection limit of 50 parts per million, or 1 gram per hour (see Table 3). This standard could prove difficult, if not impossible, to meet, and it exceeds requirements in the United States.
In the European Union, the continuing policy debates surrounding LDAR and flaring and venting make alignment with U.S. rules difficult to assess.
Flaring and venting standards are an area of potential overlap in the emerging regulations, but key differences between the parliament and council proposals still must be reconciled. The parliament’s approach would require operators to conduct weekly inspections of all flare stacks or implement continuous monitoring devices. By comparison, the council’s approach would require only monthly inspections of flare stacks. Still, flaring requirements may evolve in a similar manner on both sides of the Atlantic. The proposals in both the European Union and the United States would impose flaring efficiency standards. The council proposal would impose a requirement of 98 percent efficiency, whereas the parliament’s proposal targets 99 percent flaring efficiency and the EPA supplemental proposal targets 95 percent efficiency (see Article 17 in the council’s general approach, and page 14 of the EPA’s supplemental proposal). U.S. regulations generally align with the council’s position on flaring.
Alignment between proposed regulations in the United States and the European Union could help create a new standard for MRV. These new rules and reporting frameworks could strengthen the OGMP 2.0, a reporting framework established by the UN Environment Program that is billed as the gold standard in methane detection and reporting. OGMP 2.0 has now grown to include more than 100 member companies, comprising around 35 percent of global oil and gas production and 25 percent of natural gas transmission and distribution pipelines. Reporting is assessed at five levels of stringency, and member companies commit to improving their measurement of methane emissions to enhance overall accuracy and transparency. Given that many companies in both the United States and the European Union have joined OGMP 2.0, new U.S. and EU reporting requirements could incentivize companies to adopt rigorous data collection and reporting for all applicable assets and sources.
At a high level, the emerging regulations in the United States and the European Union could push companies toward OGMP 2.0 standards. OGMP 2.0 has guided EU legislation, as the framework provides “a suitable basis for methane emissions standards, based on sound scientific norms.” Parliament’s proposal would require operators to report source-level measurements of emissions within 12 months for operated assets and within 24 months for nonoperated assets. The proposed regulation would also rely upon data collected and published by the International Methane Emissions Observatory (IMEO). The Parliament proposal suggests “the IMEO should play a role in identifying super-emitters by way of an early detection and warning system.”
Reporting and data standards in the United States could also support alignment between regulations and OGMP 2.0 standards. Upcoming modifications to the EPA’s Greenhouse Gas Reporting Program (GHGRP) Subpart W will help satisfy the requirement for more extensive data. To implement the methane fee included in the IRA, the EPA will revise requirements of GHGRP Subpart W to “ensure that reporting is based on empirical data and accurately reflects total methane emissions.” A key tenet of the forthcoming EPA regulations and the IRA methane fee has been that measurement-informed approaches are needed instead of the engineering-based inventory approach, which has significantly underestimated methane emissions from the oil and gas sector.
Prior to the IRA, the EPA had initiated a broader rulemaking process to update the GHGRP. In its 2022 supplementary proposal, the EPA outlines a number of required updates to Subpart W to improve data quality and require reporting for new emissions sources. New reporting sources would include atypical large emitting events, including storage and wellhead leaks and well blowouts. New EPA reporting requirements in Subpart W—the agency aims to issue a proposed rule by July 2023 and finalize it by April 2024—will be a critical step forward in establishing new MRV demands. observers have recommended a more stringent reporting framework that moves away from source-level estimates based on generic emissions factors in favor of site-level measurements, top-down estimates, and a reconciliation process. These updates could align U.S. reporting requirements with Level 4 or 5 reporting standards under OGMP 2.0. The key difference is that while OGMP 2.0 is a voluntary initiative, GHGRP standards will apply to all companies subject to Subpart W reporting requirements.
New EPA reporting requirements in Subpart W will be a critical step forward in establishing new MRV demands.
EU methane legislation is clearly important for local oil, gas, and coal companies, but for the global gas industry, the critical matter is how the European Union will impose import rules. Gas and LNG suppliers already face investor, shareholder, and societal pressure to cut methane emissions, but it is still uncertain how quickly a market for “cleaner,” or less emissions-intensive, gas will develop. An EU import standard would be the most powerful policy lever to date, and the ripple effects could spread throughout the global gas system, especially if Asian countries follow suit. Whether the European Union will pass such rules, how global gas players will meet the requirements, and how EU import standards might interact with U.S. regulations are all important policy discussions.
It is still uncertain how quickly a market for “cleaner” or less emissions-intensive gas will develop. An EU import standard would be the most powerful policy lever to date.
Climate hawks view EU methane legislation as a way to push the global oil and gas industry to reduce emissions. A key theory of change is that aside from compelling companies to cut emissions from EU-domiciled production, the European Union should exercise its power as a gas buyer. The European Union imports more than 90 percent of its gas and is a large importing region by volume, so its policy signals matter to the global gas market. Advocates of stringent import rules believe they would force the European Union’s gas suppliers to adjust and perhaps inspire other governments to follow suit. On May 9, 2023, the parliament approved legislation including new import standards, going farther than the Commission’s December 2021 legislative proposal and the council’s December 2022 general approach to methane legislation.
Any version of EU methane legislation will likely include reporting requirements for gas importers. The commission’s legislative proposal (Article 28) aimed to create a methane transparency database of EU gas supplies, including both companies and countries. Its stated goal was to “set incentives to reduce methane emissions in partner countries by creating transparency in the market.” These rules will force gas importers to collect certain information from their suppliers, as outlined in Articles 27–29 and Annex VIII in the legislative proposal. The goal is for the European Union to collect sufficient comparative data on the methane intensity of imported gas to differentiate between suppliers. The commission text would require pipeline gas and LNG suppliers to measure and report their methane emissions in a transparent manner, document their method of quantification, and specify whether they are meeting OGMP 2.0 standards.
It is reasonable to assume the European Union will seek to leverage these data to prioritize “cleaner,” or less emissions-intensive, suppliers. Policymakers could impose a fee on suppliers that fail to meet certain methane intensity standards or, perhaps eventually, restrict market access for those who fail to provide data or fall short of a methane import standard.
The legislative language the parliament approved in May includes a binding 2030 reduction target for oil and gas, coal, and biomethane (when injected into existing gas infrastructure). Methane reduction targets for all industries must be submitted by the end of 2025, and member states must submit national reduction targets. Crucially, parliament’s adopted text also covers gas imports. By 2026, gas importers would be required to submit proof they are meeting the requirements of the legislation.
The parliament also recommended the European Union introduce a methane intensity standard. Amendment 21, paragraph 1a suggests that six months after the entry into force of EU methane legislation, the commission should report on the “impact of introducing an ambitious upstream performance standard for methane emissions intensity for the oil and gas imported into or extracted within the Union.” Parliament suggests the commission consider the impact of a methane intensity standard below or equal to 0.2 percent. This 0.2 percent figure aligns with the upstream methane intensity threshold for U.S. petroleum and natural gas production facilities in the IRA methane fee. The IRA methane fee applies only to reported methane volumes that exceed 0.2 percent of natural gas sent to sale from such facilities. Parliament may be aiming for convergence between U.S. and EU standards. Regulatory incentives to keep upstream methane intensity below 0.2 percent could establish a de facto industry target to reduce compliance costs and ensure market access. There are many questions about how an EU import standard will work, including exactly which requirements will apply for MRV, LDAR, and flaring and venting, as well as how data from suppliers will be verified (see Figure 4).
Regulatory incentives to keep upstream methane intensity below 0.2 percent could establish a de facto industry target to reduce compliance costs and ensure market access.
It remains uncertain whether parliament’s preferred approach will survive the “trilogue” process and remain in the EU methane legislation. Now that parliament has passed its preferred version of legislation, negotiations between the commission, council, and parliament should begin this summer. The European Union’s goal is to finalize its methane legislation by the end of the year. Parliament has clearly signaled its intent to push for more ambitious legislation than the council’s general approach, which many environmental groups view as a step backward. But the trilogue involves negotiation with EU member states that may be wary of rules that could jeopardize their access to reliable gas supplies. Most observers expected the parliament to push harder on LDAR and flaring and venting rules, as well as a firm import standard. But the gap between council and parliament preferences on LDAR and import standards suggests that compromises will be necessary.
With methane regulations evolving on both sides of the Atlantic, a key question is how these rules will fit together, especially for U.S. LNG exporters. Although EU methane legislation has not yet been finalized, gas suppliers in the United States and elsewhere are closely watching proposed EU rules.
As noted, the goal in Brussels is for gas exporters to the European Union to meet the same MRV and operational requirements as EU companies, but there are questions about how this will work in practice. EU methane legislation requires companies to document their MRV, flaring and venting practices, and reporting standards and submit them to the commission on an annual basis. Parliament’s proposal also suggests in Article 202 a potential derogation for coal, gas, and oil importers if they can prove that they are subject to equivalent rules and regulations in their home jurisdiction (see Figure 4).
This text suggests that gas exporters from the United States may have incentives to prove EPA regulations and other rules, if completed, will create at least regulatory equivalence. On its face, this seems likely to disappoint some advocates of tough EU methane rules. Climate hawks may worry that this creates a loophole to allow continued market access for gas suppliers subject to weaker regulations—especially if they lobby their home governments for support. But, in fact, this amendment in the parliament text suggests an effort to align national rules and regulations and to compel companies to exceed national standards, if necessary, to meet EU requirements.
Parliament Proposal: Reporting Requirements and Derogations for Importers
The proposed EU import standard, especially if imposed in 2026, would create a significant challenge for global LNG companies. At present, almost no gas exporters are prepared to provide rigorous, measurement-informed, verifiable emissions accounting for gas exports, either for discrete pipeline volumes or LNG cargoes. There is growing interest among LNG exporters in providing verifiably “cleaner,” or less emissions-intensive, gas, in part to establish a competitive advantage as gas buyers start to scrutinize the emissions intensity of their supplies. But in the LNG industry, cargo-specific emissions accounting is still in its infancy.
At present, almost no gas exporters are prepared to provide rigorous, measurement-informed, verifiable emissions accounting for gas exports, either for discrete pipeline volumes or LNG cargoes.
The nature of the LNG industry also makes it hard to provide supply chain–specific emissions data. In the United States, LNG exporters are rarely involved in the production, gathering and boosting, or transportation segments. To provide detailed emissions accounting for their LNG cargoes, they need to gather such data from suppliers and partners throughout the value chain. Of course, a key goal for advocates of firm import standards is to force LNG suppliers to go upstream and gather these data. But this is no small task—especially for companies that buy large gas volumes from many suppliers, including private players and others that are less advanced in collecting emissions data. Gas trading also involves multiple parties. Aggregators and traders may source LNG from certain suppliers and sell from their portfolios to buyers in multiple regions. A certificate of origin of some sort may be required to trace the emissions associated with individual cargos, which presumably would change hands if those cargoes are diverted. Tracking and verifying these data would be a significant challenge.
To date, there is little evidence that gas buyers will pay a premium for less emissions-intensive gas, but it is conceivable that within a few years a differentiated market will develop. Creating this market depends on better data on emissions intensity, dissemination of that data in the marketplace, and stronger incentives for buyers, whether because of stakeholder or regulatory pressure. High natural gas prices and energy security concerns have taken precedence since mid-2021, limiting the demand pull for “cleaner” gas. But new regulations in the United States and methane legislation in the European Union could create a big push on the supply and demand sides, respectively.
Natural gas suppliers and midstream companies want better systems to measure and reduce their methane emissions and to establish themselves as top-tier performers. The result has been a growing number of industry-wide initiatives to track and report methane emissions, as well as programs that promise to certify and verify the emissions associated with a given company’s natural gas production.
Supplier incentives and public policy are driving innovation in emissions accounting. Examples of new protocols and standards include GTI Energy’s Veritas program, which offers technology-neutral protocols to help companies calculate and report methane emissions, as well as a draft certified gas addendum from the North American Energy Standards Board. These initiatives are related to national and international efforts to standardize MRV of methane emissions associated with natural gas, including OMGP 2.0 and the GHGRP. In some cases, standards are being developed in coordination. For example, Veritas is working to add a measurement-based source level inventory to its protocol to align with OGMP 2.0 level 4 reporting and allow for reconciliation with site-level data.
Supplier incentives and public policy are driving innovation in emissions accounting.
Gas companies and LNG suppliers, anticipating more scrutiny over emissions intensity, are also advancing voluntary industry initiatives. Companies are investing in certified gas schemes from providers including MiQ, Project Canary, and Equitable Origin. Cheniere Energy completed a life cycle assessment of GHG emissions specific to its supply chain and now offers cargo emissions tags, or emissions data associated with each cargo from its export facilities. The global LNG industry has also published frameworks for GHG-neutral LNG cargoes, including guidelines for reporting the GHG footprint of individual LNG cargoes as well as emissions reductions and offsets. Sales of GHG-neutral LNG cargoes have now taken place using frameworks published by the International Group of Liquefied Natural Gas Importers (GIIGNL), as well as a methodology developed by Pavilion Energy, Chevron, and Qatar Energy.
These disparate industry-led initiatives have both benefits and drawbacks. Advocates of certified or responsibly sourced gas argue that these market-based systems can cover broad geographies, including countries with lax regulations; improve industry learning; and encourage fixes and best practices across company operations. But environmental organizations criticize certified gas suppliers for everything from poor transparency over their methodologies to potential conflicts of interest in verifying emissions for paying clients to allowing companies to cherry-pick certain assets for certification. Critics argue that certified gas schemes are no substitute for firm regulations that would apply to all upstream and midstream operators.
Some policymakers are trying to bring order to a fragmented marketplace by creating a transparent, widely accepted standard for differentiated gas, and improving ways to track emissions associated with natural gas across the value chain. The U.S. Department of Energy (DOE) Office of Fossil Energy and Carbon Management convened several workshops on this subject. In October 2022 it held a workshop that covered methane measurement, methane detection technology, and market implications. The DOE also held discussions with oil and gas companies, environmental organizations, and analysts at the CERAWeek conference in March 2023. The goal was to harmonize various approaches to methane MRV to provide more certainty for gas purchasers, including LNG buyers, on emissions intensity.
Policymakers are trying to bring order to a fragmented marketplace by creating a transparent, widely accepted standard for differentiated gas, and improving ways to track emissions associated with natural gas across the value chain.
The aperture of this initiative has widened. The DOE and partners have now established a working group involving some 20 countries to examine ways to reduce GHG emissions from fossil fuels. This working group will build on the ambitions announced in a joint declaration between energy importers and exporters announced at COP27, as well as the U.S.-EU Energy Council. The latter group announced in April its intention to “develop an internationally aligned approach for transparent measurement, monitoring, reporting, and verification for methane and carbon dioxide emissions across the fossil energy value chain.” The United States and European Union also pledged to develop “a common tool for life cycle analysis of methane emissions for hydrocarbon suppliers and purchasers.” They also aim to improve the “accuracy, availability, and transparency of emissions data at cargo, portfolio, operator, jurisdiction, and basin level.”
These efforts to establish more transparent measurement, monitoring, reporting, and verification of emissions will have to tackle several issues. First is the question of scope. Certified gas providers generally cover the upstream and midstream segments, as opposed to liquefaction or shipping of LNG. More recently, some companies have offered to certify GHG emissions across the LNG value chain. To offer the greatest transparency on emissions associated with gas exports from the United States and other suppliers—with the goal of driving down those emissions— his framework must include comprehensive, measurement-informed data for the entire gas value chain. This could bolster the case for “cleaner” U.S. LNG exports by marshalling verifiable data to back those claims. Presumably, the elements of such a framework that cover only production, gathering and boosting, gas processing, and transmission would still be highly useful to domestic gas purchasers.
A second concern is data quality and availability for various segments of the gas and LNG value chain. Generally, there has been much stronger focus on GHG detection and quantification for the production segment and less attention paid to gas processing, transportation, compression facilities, storage, and liquefaction. In April 2023, the DOE issued a request for information on opportunities to reduce GHG emissions associated with LNG exports. The DOE specifically requested information on strategies and technologies that gas and LNG companies are deploying or could deploy to reduce emissions of CO2, methane, and other air pollutants associated with LNG exports. Quantifying emissions associated with shipping could prove challenging because direct measurements of LNG ships, to date, are limited and many detection technologies will not be applicable. The working group on emissions transparency and reductions will have to consider how to piece together imperfect data from across the value chain, and how policies should recognize the gaps and problems with data quality.
A third challenge that is directly related to EU methane legislation concerns third-party verification. If the goal is to ensure consistency and credibility, it will be important to create a governance framework that ensures data can be collected and vetted independently. EU methane legislation shares this goal. The commission’s legislative proposal calls for “independent accredited verifiers” of methane emissions data, separate from the competent authorities tasked with overseeing regulations in EU member states. But in the United States and the European Union, who should fulfill these roles? The European Union suggests IMEO can play an important advisory and support role, but the organization has other important responsibilities in collecting, reconciling, and integrating methane data. The DOE and other government agencies including the State Department may see merit in establishing a quasi-independent verification agency. Oil and gas companies, as well as certified gas players, however, may prefer the International Organization for Standardization (ISO) to establish standards for differentiated gas designations. It may take some time to resolve these questions.
While work on a differentiated gas framework continues, new reporting requirements for oil and gas operators in the United States may have a significant impact. As noted, the IRA tasked the EPA with updating its GHGRP Subpart W reporting requirements for oil and natural gas facilities within two years of enactment of the IRA (by August 2024), to ensure that reporting and calculation of methane charges are based on empirical data. Section 60113 of the IRA requires the EPA to “accurately reflect the total methane emissions and waste emissions from the applicable facilities” and notes that operators of facilities must “submit empirical emissions data.” The EPA sought comment on the type of revisions it ought to consider, and observers expect guidance on Subpart W updates by autumn.
While work on a differentiated gas framework continues, new reporting requirements for oil and gas operators in the United States may have a significant impact.
In adjusting its Subpart W reporting requirements, it is reasonable to assume the EPA will require operators of applicable facilities to provide extensive detail on their MRV standards and flaring and venting practices. In short, revisions to Subpart W could force upstream and midstream companies alike to provide the type of emissions data sought by the European Union. It is possible the new Subpart W requirements will have more of an impact than certified gas schemes or even OGMP 2.0 membership in moving the needle on methane disclosures—but aligning these standards as much as possible would maximize the impact for emissions reductions.
Methane abatement is now a key part of the international climate agenda. Rapid innovation in methane detection technologies including aerial and drone surveys and satellite surveillance is enabling progress, and investors are pushing companies to set clear targets for methane abatement. Eighteen months after the creation of the Global Methane Pledge and proposals for new methane regulations in the United States, the focus is shifting to concrete targets and action plans rather than vague commitments. The combination of EPA regulations, the IRA methane fee, and methane regulations in states including Colorado and New Mexico will create more stringent standards for measurement, quantification, reporting, and verification. Regulators are encouraging companies to move faster while allowing them to experiment with new detection technologies to find the best solutions at reasonable costs. Meanwhile, the next few years will bring a dramatic increase in available data on methane emissions, incentivizing companies to find and fix leaks.
The United States and the European Union are cooperating to drive down emissions from traded fossil fuels, and both sides see methane abatement in the oil and gas industry as the best opportunity for near-term cuts. High natural gas prices and substantial price volatility since mid-2021 have blunted some of these efforts, perhaps slowing the pace of new policies to cut methane emissions from traded gas. But this policy pressure will likely grow in the years to come. Most of the regulatory pressure will happen on the supply side, especially with forthcoming EPA regulations. But EU methane legislation should provide the strongest incentives to date for suppliers to provide empirical data and identify plans to cut methane emissions.
There is no guarantee that import standards will make it into final EU methane legislation. Wary policymakers may instead opt to collect data from gas suppliers to create a methane supply index, potentially enabling tougher actions down the line. But a methane import standard along the lines of the parliament proposal is possible this year. Parliament’s proposed 2026 timeline is aggressive, and some elements may be extremely hard to implement within two years. But the status quo—with continually rising atmospheric concentrations of methane—is unsustainable. Plenty of policymakers want to force companies to do hard things to help solve the methane challenge.
If the European Union passes tougher import rules, the U.S. LNG industry could be well-positioned. For years—and especially since Russia’s brutal invasion of Ukraine—U.S. companies and policymakers have argued the United States could boost energy security for allies in Europe and provide lower-emissions gas. This is a laudable goal, but the data to back up such claims have been patchy. EU rules, EPA methane regulations, and revised EPA reporting requirements under Subpart W will be challenging. But these rules will also force companies to gather data, enhance reporting, and implement corporate targets and operational practices to cut emissions. Eventually, these changes could create a competitive advantage for U.S. LNG exporters and make a stronger climate case for natural gas.
Ben Cahill is a senior fellow with the Energy Security and Climate Change Program at the Center for Strategic and International Studies (CSIS) in Washington, D.C. Allegra Dawes is an associate fellow with the Energy Security and Climate Change Program at CSIS.
The authors thank Jonathan Stern and Manfredi Caltagirone for their comments. Any remaining errors are solely those of the authors.
This report was made possible by support from Cheniere as part of a project on alignment between U.S. and EU regulations on methane emissions.
