All over the map: Basin-level methane metrics reveal uneven US gas performance ahead of EU regulations

In March, the EU began private talks with US LNG firms on the terms of the EU methane emissions regulation(opens in a new tab), or EMER, a framework to monitor and reduce methane emissions from fossil fuels placed on the EU market.

A key point of contention is how importers will report their gas suppliers' methane profiles, given that a single US LNG export cargo may contain gas commingled from many upstream producers, each with its own emissions footprint. As a practical alternative when producer-level data is unavailable, industry observers have suggested using aggregated data at the basin level. "[A]ggregating such [emissions] data and providing it at basin level for US suppliers could help provide the data transparency the EU is seeking," Ben Cahill, director for Energy Markets and Policy at the Center for Energy and Environmental Systems Analysis at The University of Texas at Austin, wrote in a March white paper.

Platts, part of S&P Global Commodity Insights, assesses the average methane intensity of natural gas from 19 US basins each month. Commodity Insights data quantifies the distance between the frequently cited 0.2% upstream methane intensity target and current US performance, although it also demonstrates the substantial variation between basins.

Related subscriber note: S&P Global Commodity Insights to update US Basin methane intensity methodology(opens in a new tab)

Some basins are better than others

Determining US readiness for the EMER is difficult because the EU will not outline its methane intensity methodology until 2027 or determine a methane intensity threshold until 2029. The EMER only indicates it will consider methane emissions "at the level of the producer," defined as an entity extracting, processing and transporting fossil fuels within a licensed area.

Upstream production is responsible for, on average, 58% of methane emissions from gas extraction through processing to transmission and storage, according to the US Environmental Protection Agency, although the share varies by basin. Tracking methane intensity beyond the extraction phase presents a challenge because gas may be processed in a different basin than it was extracted from, and interstate transmission pipelines may convey gas across multiple basins.

For this reason, methane reduction efforts often target upstream production. One early EMER working group cited the 0.2% upstream methane percentage target by the Oil and Gas Climate Initiative, an industry-led effort by 12 global oil and gas companies to curb methane emissions.

Methane percentage -- the volume of methane emitted as a share of total marketable methane -- is commonly used to quantify the methane intensity of a gas supply chain. No US basin in Commodity Insights' sample achieved this target in 2024 and performance varied substantially.

The best performing regions, the Appalachian Basin in Pennsylvania and Ohio, exhibited upstream methane intensities of 0.22% and 0.23%, respectively, very close to the OGCI target. In contrast, the worst-performing Anadarko Basin exhibited an upstream methane intensity of 2.95% -- almost 15 times the OGCI target.

Regional geology explains some of this variation. Dry gas-heavy basins like the Appalachian Marcellus Shale primarily yield natural gas, giving operators a financial incentive to prevent losses. On the other hand, operators in oil-dominant regions like the Powder River may lack the infrastructure to bring gas to market and instead flare it as waste. Some flare gas escapes uncombusted, driving up methane intensity.

State regulations also play an important role. Gas from the Texas portion of the Haynesville Basin exhibited an upstream methane intensity of 0.49%, well above the 0.31% intensity of the Louisiana/Arkansas section, corresponding to Texas's more permissive emissions controls. The three highest-intensity basins are in Oklahoma, Wyoming, and Texas -- all states without routine flaring bans.

Emissions are a moving target

Changes to infrastructure, technology, power and fuel sources, operational policies and regulations can alter methane intensity over time.

The average upstream methane intensity of US natural gas remained remarkably stable throughout 2024, finishing only 3% lower than it began. Individual basins, however, did not remain stable. Gas from the Anadarko was 44% less methane intensive in December 2024 than in January 2024. This progress was offset by the Eagle Ford, where methane performance fluctuated due to changing flaring activity and production volumes. It recorded an annual low in July but ended the year 30% worse than it started.

The dramatic emissions improvements of the Anadarko throughout 2024 indicate the potential for the emissions profile of US gas to improve significantly by the time the EU attaches financial penalties to its methane threshold in 2030. Still, the monthly fluctuations revealed by Platts data suggest not all basins, and certainly not all individual operators, will proceed in a linear manner toward ever greater methane efficiency.

Individual operator variation

Basin-level averages do not capture differences between individual producers in the same area. Operators may choose different approaches to venting, flaring or monitoring gas emissions for economic, safety or reputational reasons.

To account for this variation, the EU Commission issued further guidance in late 2024 confirming that purchasers will have to request methane emissions reports at the producer level from their suppliers. Various systems have been proposed to streamline this process, including the "trace and claim" method, which relies on a digital registry to follow specific gas volumes through the supply chain. No such system is widespread in the US market today.

Shifting energy priorities

The global energy landscape has evolved significantly since the EMER's initial conception in 2020. The outbreak of the Russia-Ukraine War renewed the EU's focus on energy security and affordability. American LNG quickly filled the gap left by Russian supply cuts, and in 2022, the EU committed to purchasing an additional 50 bcm of US LNG annually through 2030.

In December 2024, the US petitioned the EU Commission for "regulatory equivalence" to exempt US LNG from EMER compliance. The case for equivalence weakened, however, when the US Congress repealed the federal methane emissions tax(opens in a new tab) in February.

The talks surrounding the EMER present an opportunity to accommodate the new energy priorities on both sides. Importers unable to determine the methane intensity of their suppliers could use basin-level averages as the next-best alternative. Efficient US operators would still be incentivized to reduce and report their individual emissions performance to differentiate their supply from basin averages.

Basin-level methane intensity assessments may therefore serve as a pragmatic middle ground between the EU's climate ambitions and the US deregulation agenda while satisfying both sides' aim to bolster gas flows across the Atlantic.

With analysis from Richard Frey