There is increasing interest in many countries in reducing the greenhouse gas (GHG) emissions linked to their fossil fuel imports. For some of the largest oil and gas importers – the European Union, the United Kingdom, Japan, Korea and China – such emissions (15 million tonnes in 2024) far exceed those from domestic oil and gas operations and infrastructure (5 million tonnes in 2024).

Upstream methane emissions intensities associated with oil and gas imports differ across countries. According to International Energy Agency (IEA) estimates, average intensities are around 1% for the European Union and United Kingdom, 0.6% for Japan and Korea, and 1.3% for China.1 By reducing these intensities to 0.2% – a level that could be achieved worldwide using all currently available technologies – global methane emissions would fall by more than 12 million tonnes (Mt), or around 20% of total upstream oil and gas methane emissions.

The real-world impact of a methane import standard would depend heavily on its design, enforcement and compliance. If import penalties are low relative to abatement costs, exporters and importers may choose not to comply. Alternatively, exporters could adjust trade flows (physically or via tradeable certificates) so that fuel with low-emissions intensity is directed to countries with an import standard, while higher-emission fuels are either consumed domestically or exported to unregulated markets. In this case, emissions may fall somewhat where exports still require improvements to meet the standard, but the overall impact would be significantly weakened.

Conversely, an import standard could drive deeper methane cuts in exporting countries if companies extended abatement beyond the volumes destined for regulated markets. Such spillovers could arise if the countries or companies affected by the standard reduced the emissions intensity of a greater share of their oil and gas production. For example, if exporters to the European Union, United Kingdom, Japan, Korea and China achieved a 0.2% upstream intensity across all exports, regardless of the destination, global methane emissions would fall by 17 Mt.

A coordinated emissions import standard can strengthen energy security for importing countries. If countries that currently export fuel to the European Union, Japan, Korea or the United Kingdom were to cut flaring and methane emissions across all their exports, this could make more than 25 billion cubic metres (bcm) of additional gas available to importers. Reducing methane emissions and flaring can thus deliver a double dividend: improved energy security alongside progress toward climate goals.

Regulators considering methane-related import standards can pursue several strategies to avoid pitfalls and maximise impact. Effective design begins with clear timelines for compliance. Import requirements can be phased in gradually to give producers, exporters and importers time to adjust. Clear guidance is also needed on whether the standard applies to existing contracts or only to those signed after a specified date.

Designing an effective import standard also requires clear and consistent implementation rules. Regulators need to specify how importers need to measure and report the methane intensity of imported fuels. Once reliable data is available, regulators will need to determine whether imported fuels are to be subject to a maximum methane intensity threshold, and if so, how fuels exceeding that threshold will be handled. Several approaches exist for reporting upstream methane intensities and complying with a performance threshold, and countries need to decide which methods and certification schemes will be accepted as proof of compliance.

In a “book-and-claim” model, physical supply is decoupled from its emissions profile through tradeable certificates. These can operate at a national level, with importers sourcing certificates from any producer within a given country, or at the basin or regional level, with certificates tied to the basin or region of origin of the imported fuel.

Book-and-claim models tend to be relatively low-cost and simple for industry but could potentially weaken the impact of an import standard. This is because these systems would allow importers to purchase certificates from low-intensity producers that do not directly export physical supply to them. As a result, some high-intensity exporters may not be incentivised to implement abatement measures, resulting in a lower level of overall emission reductions. For example, if a producer with a high emissions intensity exports to an economy with an import standard, the importer could buy a certificate from a producer that already has a low emissions intensity, resulting in no overall emissions reduction (similar to the export sorting scenario described above).

In a “trace-and-claim” model, importers trace the imported fuel back to its production asset, rather than purchase certificates. This model is more likely to deliver real emission reductions but may prove relatively more costly and onerous to implement in some oil and gas supply chains, particularly more complex ones.

Countries or regions seeking to introduce an import standard may wish to adopt a phased approach, starting with a book-and-claim approach at the basin level. Under this arrangement, regulated importers would comply by purchasing tradeable certificates, but only those issued within the same basin or region as the physical origin of the imported fuel. To enforce this geographic constraint, information on origin could be attached to certificates at the point of issuance and embedded within digital trading platforms through which importers acquire them. As data reporting, verification and traceability improve over time, regulators could then transition to a trace-and-claim system, which is likely to deliver greater emission reductions in producing countries.

To unlock meaningful emission reductions, the enforcement mechanisms of import standards need to be sufficiently robust to encourage exporting countries or companies to adopt methane abatement measures. Importing countries can pair the introduction of such standards with technical assistance and financial support for exporting countries, helping to facilitate compliance with the new requirements. Regulators could further enhance effectiveness by coordinating with other jurisdictions that have already implemented similar standards, working together to harmonise import requirements and streamline compliance for both producers and buyers.

Several voluntary initiatives have emerged in recent years to improve transparency on methane emissions in the fossil fuel sector. These come in different forms, ranging from reporting frameworks – such as the Oil and Gas Methane Partnership (OGMP) 2.0, which underpins other transparency initiatives including the Coalition for LNG Emission Abatement towards Net-zero (CLEAN) –  to supply-chain protocols, including the Groupe International des Importateurs de Gaz Naturel Liquéfié (GIIGNL)’s MRV and GHG Neutral LNG Framework and Context Labs’ digital platform. Other initiatives focus on certification, including programmes run by MiQ, Equitable Origin and TrustWell.

Voluntary initiatives can allow high-performing operators to differentiate their products from higher-emissions alternatives. This can allow operators to attract new customers seeking fuels with lower emissions intensities – for example technology firms, data centres, or industrial companies that use natural gas as a feedstock and that have voluntary climate commitments in place. Over time, such differentiation could also support price premiums for lower-intensity fuels, strengthening incentives for producers to curb emissions.

Voluntary initiatives face several challenges, slowing the emergence of a differentiated market for low-intensity fuels. The current landscape is fragmented, with schemes differing in scope, methodology, definitions and grading. This can confuse buyers and weaken their ability to compare fuel sources by emissions performance. Among voluntary initiatives, only some certification schemes require third-party verification of emissions, potentially affecting the reliability of emissions reported under other initiatives. Most initiatives also focus on oil and gas supply chains, with comparatively little attention paid to coal.

Although certification typically involves independent third-party verification of emissions (enhancing buyers’ trust in reported emissions), it also faces its own unique challenges. Measurement-based quantification is not always required, raising the risk that methane emissions could be underestimated. Although volumes of certified natural gas reached 320 bcm in 2024 (roughly 7.5% of global output), certification remains concentrated in the North American upstream natural gas sector, with limited uptake outside this segment. Questions have also been raised about the integrity and transparency of some schemes, casting doubt on the reliability of emissions reported under them.

To address these challenges, countries can work together to harmonise voluntary initiatives and set common standards for measuring, reporting and verifying methane emissions across the oil and gas value chain, including common interoperability standards and consistent approaches for recording emissions performance on digital registries. Countries can build on initiatives that are already under way, such as OGMP 2.0 and CLEAN.

A globally accepted measurement, monitoring, reporting and verification (MMRV) framework could reduce the burden on companies of complying with multiple schemes and help market participants trade fuels on the basis of methane intensity. This could also spur the development of a globally differentiated market for near-zero methane intensity fuels, particularly if coupled with targeted incentive mechanisms. Such a market could, in turn, support price premiums for low-methane fuels, enabling operators to recoup investments in abatement technologies.