A growing number of oil and gas companies have set methane targets, joining initiatives such as the Oil and Gas Methane Partnership 2.0 (OGMP 2.0), the Oil and Gas Climate Initiative (OGCI), the Oil and Gas Decarbonization Charter (OGDC), and the Methane Guiding Principles.

OGMP 2.0 is the flagship oil and gas reporting and mitigation initiative of the United Nations Environment Programme (UNEP). Since 2023, around 20 new companies joined OGMP 2.0, bringing coverage to just over 40% of global oil and gas production.

OGCI’s Aiming for Zero Methane Emissions Initiative aims to eliminate all methane emissions from the oil and gas sector by 2030. OGCI also facilitates peer-to-peer learning through its role as the secretariat of the OGDC, which includes knowledge-sharing and collaboration programmes to disseminate solutions. With the recent inclusion of PetroChina, the OGDC’s membership now accounts for around 40% of global oil and gas production. Several companies in China, including PetroChina, Sinopec and CNOOC, as well as pipeline operators and utilities, have also recently established the China Oil and Gas Methane Alliance to promote best practices.

While this momentum is positive and some operators have taken demonstrable steps forward, globally the industry has yet to demonstrate consistent progress in methane reductions. Reducing methane is the single-most effective and cost-efficient way for the industry to minimise overall emissions. The gains are not solely environmental: fossil fuel operations with lower emissions intensity are likely to have an increasing commercial advantage over higher-emitting sources.  

Credibly reducing emissions from upstream assets should be a top priority. Upstream operations are not just the main source of emissions in the oil and gas industry – they hold the greatest potential for cost-effective abatement. We estimate that around 25 Mt of methane emissions from upstream operations (40% of all upstream oil and gas methane emissions worldwide) could have been avoided at no net cost in 2024. Well over 15 Mt of emissions could have been avoided through measures with internal rates of return exceeding 25% – well above the thresholds that oil and gas companies typically require for capital investment.

The global average methane intensity of upstream oil and gas has fallen by around 10% since 2019. Yet despite this progress, emissions intensities still vary more than 100-fold between the best and worst performers – and recent increases in production mean that emissions remain at record levels. The most cost-effective options available today for reducing emissions include: leak detection and repair (LDAR); replacing pumps and other methane-emitting equipment with electric devices; using vapour recovery units to capture vented gas; and employing associated gas utilisation technologies such as microturbines for power generation.

The IEA’s methane abatement model – which was recently released as an open-source tool – can be used by companies to explore abatement costs and technologies in detail and help them identify appropriate and cost-effective solutions for methane abatement.

Downstream operations – defined here to include refining and shipping as well as natural gas transmission, distribution and storage – resulted in nearly 13 Mt of methane emissions in 2024 (an upward revision from our 2023 estimate given new data from measurement studies and satellites). This represents around 15% of total methane emissions from oil and natural gas operations – with almost all of that coming from natural gas value chains. In the European Union, downstream operations are responsible for nearly 75% of methane emissions from domestic oil and gas supply chains. 

Several solutions exist for reducing emissions in the downstream segment, and many companies are working to improve methane monitoring and reduce emissions. In 2024, for example, Cheniere Energy completed measurement studies and set a target for annual methane emissions intensity of 0.03% per tonne of LNG produced. Terega, which manages more than 5 000 km of pipelines in France, reported a 36% reduction in methane emissions from 2017 levels. 

If all the abatement technologies available today were to be deployed at natural gas processing and transport facilities, the global average methane intensity of downstream natural gas operations would fall from more than 0.4% to below 0.2%.

The coal sector released around 40 Mt of methane emissions in 2024. While there are some instances where methane capture and use is economically viable for coal operators, most would not generate enough revenue from the sale or use of captured gas to pay for it themselves. Widespread deployment of abatement measures should remain a priority, however, especially for coking coal, which is generally harder to replace than steam coal, and which is often sourced from underground mines where abatement is more feasible.

Most of the coal industry has not committed to reducing its methane emissions. Some companies engage in initiatives like the United Nations Economic Commission for Europe Group of Experts on Coal Mine Methane and Just Transition, or the Global Methane Initiative, while others choose to address methane in their climate or sustainability strategies. For example, BHP has committed to “minimise fugitive methane emissions to the greatest extent technically and commercially viable, through enhanced application of existing or emerging technology.” Anglo American reports its investments in methane pre‑drainage infrastructure at underground steelmaking coal operations. Coal producers that can credibly demonstrate lower methane emissions could gain a commercial edge with customers: Many steel producers, for example, are looking for ways to reduce the lifecycle emissions intensity of their products.

Annual emissions from steam coal and lignite production have remained around 30 Mt for the past decade. They fall under the Stated Policies Scenario (STEPS) largely because of a reduction in demand. The STEPS also sees emissions from coking coal mines fall around 15% to 2035, slightly outpacing decreases in production, thanks to pledges by certain countries to tackle coal mine methane (e.g. China’s Methane Action Plan).

Use of biogas and biomethane – both of which are considered to be low-emissions gases – has notably increased in recent years. Biogas can be used for heat and electricity generation and biomethane (an upgraded form of biogas) can be a direct substitute for natural gas. Biogas feedstocks include crop residues, animal manure, solid waste from municipalities or landfills and sewage sludge. For some of these feedstocks – mostly notably waste and manure – biogas production using anaerobic digestors can prevent methane emissions that would have otherwise occurred during natural decomposition. Quantifying and recognising the value of these avoided emissions is crucial for assessing the environmental credentials of biogases. Without careful handling, methane leaks along biogas and biomethane supply chains can undermine – or eliminate entirely – the benefits of switching from natural gas to biogases.

Methane leaks can occur during transport, storage and processing of feedstock, during the biogas production and upgrading processes or from the handling and storage of the residual fluids and fibrous materials (often called “digestate”).  Emission factors for each of these stages vary widely: from around 2% to 10% for digestate composting or storage and from 0.2% to 3% for upgrading units that produce biomethane.

There are several measures available for minimising methane emissions in each of these stages. These include LDAR programmes, the use of thermal oxidisers to reduce methane emissions from low-concentration flows, the application of best available technologies (e.g. gastight digestate storage at biogas plants), and the optimisation of production processes. The IEA will release a report on the outlook for biogases in May 2025 that will provide further detail on strategies to minimise emissions from biogases.