EU legislates to plug methane leaks

European Union policymakers have reached a deal to implement the EU Methane Regulation. Expected to enter into force in early 2024, this is the EU’s first legislation specifically targeting methane emissions from the energy sector.

Reducing CH4 leaks is to a large extent a question of ‘plumbing’ – finding and fixing leaks – which consistently ranks among the quickest and most cost-effective means of delivering big cuts in planet-warming emissions. The EU regulation is the most ambitious attempt yet to drive CH4 fugitive emissions out of fossil fuel supply chains, but falls short on several key criteria.

The new law will ban routine venting and flaring by Europe’s oil and gas industry from 2025, or 2027 depending on the type of infrastructure, and will restrict venting from thermal coal mines from 2027. It will also require improvements in monitoring, reporting, and verification (MRV) of methane emissions. From 2027, the same MRV obligations that apply to EU oil and gas producers will be applied to new coal, gas and oil import contracts to the EU.

Crucially, the EU Methane Regulation will impose methane emission intensity limits on imports of fossil fuels into the EU. The EU imports 90% of the gas and 97% of the oil it consumes, and methane emissions associated with imported LNG and crude are estimated to be 3-8 times higher than domestically produced fossil fuels.

By 2030 fossil fuel importers will have to meet a maximum methane intensity threshold or pay a penalty. The methane intensity methodology, the trigger threshold, and the financial penalty itself have yet to be decided. But if an ‘announcement effect’ results in exporters taking action to reduce the methane intensity of their oil and gas exports even before the fee comes into force, the market impact could be immediate.

Clean premium or dirty discount?

For low-methane North Sea oil and gas producers, the methane penalty raises the question of whether they can extract a premium from buyers for their ‘clean’ molecules. If they can, this is likely to be the only benefit because there is limited scope for the UK and Norway to increase supplies to the EU and drive out dirtier imports.

Since neither country is likely to face charges under the methane import standard, investors might argue that there is little incentive to invest in further methane abatement in the North Sea.

Oil and gas companies with assets in multiple jurisdictions could decide that it is more cost efficient to direct investment to methane abatement outside Europe, rather than pursuing incremental improvements in North Sea methane abatement.

The methane import standard is likely to be reflected in prices. European buyers might still buy volumes with a high methane emissions intensity but push for a discount. On the flipside, exporters of very low methane intensity gas and crude (such as the UK and Norway), may be able to extract a premium from European buyers motivated by the penalty.

Big impact, small cost

Either way, the price differential will not be huge. The potential impact of an EU methane import standard was examined in a recent report carried out by Rystad and commissioned by the Clean Air Task Force (CATF).

Their analysis indicates that the policy could lead to a 1.9 Mt (30%) reduction in annual upstream methane emissions associated with the export of oil and gas to the EU, compared against a ‘Business as Usual’ scenario.

In their scenario analysis, CATF/Rystad assume that a methane fee would be introduced in 2027 at €300 per tonne, and gradually rise to €1,500 per tonne by 2031. This is broadly in line with the methane fee included in the US Inflation Reduction Act (IRA), which starts in 2024 at $900 ($36 per tonne of CO2e), rising to $1,200 ($48 per tonne of CO2e) in 2025 and to $1,500 a tonne ($60 per tonne of CO2e) in 2026.

Countries with a methane emissions intensity above the assumed threshold of 1.61 Gg per Mtoe (equivalent to a 0.2% leak rate for natural gas) will face additional costs if they export to the EU. This includes the fee plus any costs incurred to reduce their exposure to the fee. Overall, CATF/Rystad estimate that the fee would result in an average increase in costs borne by gas exporters to the EU amounting to less than 1%. Due to crude’s higher methane intensity than natural gas, the average impact on exporter costs is estimated to be 7%.

The marginal emitter

The price impact depends on the degree to which the marginal supplier of gas or crude is affected by the penalty. The marginal supplier is the exporter that meets the last energy molecule demanded by the market. Most exporters have little or no impact on the price, and hence are known as price takers.

Although the US is the marginal supplier of gas to Europe it has relatively low methane intensity and it is expected to decline further as we move towards 2030. The price impact on gas is expected to be very small, with CATF/Rystad indicating the impact could be less than €0.1 per MMBtu. The impact could be even smaller if the EU decides to reduce the fees applicable to US exporters since they may have already been penalised under the US Methane Levy.

For crude the marginal supplier varies by crude type, i.e., light, medium or heavy. Although the US is the dominant marginal supplier of light crude to Europe, the supply of heavier grades is much more disaggregated. Overall, CATF/Rystad estimate that the impact on crude prices could be in the order of €0.90 per barrel.

Bifurcated market?

Eradicating methane is vital to keeping the bloc’s ‘Fit for 55’ climate targets on track because EU reliance on imported LNG is expected to rise sharply over the next few decades. Projections by consultancy Rystad see LNG as a share of EU natural gas imports rising from 38% in 2023 to 46% in 2030 and to over 50% by 2040.

Cleaner domestic EU production of natural gas, coupled with molecules piped from Norway and the UK, is not sufficient to offset the complete loss of Russian gas volumes – which are expected to be phased out completely by the end of 2024.

A methane import standard would have little impact on natural gas export volumes to Europe, according to CATF/Rystad. The relatively low methane emissions intensity of the major exporters provides little incentive to re-route LNG export cargoes from lower emission exporters.

The risk of crude exports being re-directed away from the EU to avoid the fee is much higher. The analysis highlights crude exports from Kazakhstan and Libya at particular risk of being redirected.

Buy now, vent later

The methane import standard will be mandatory for supply contracts agreed after the law enters the statute books, which could happen before the end of 2023. This means existing import contracts are exempt. Although that wouldn’t necessarily have been a problem in the past, European LNG buyers have recently signed a slew of long-term LNG contracts in a bid to increase energy security.

For example, Qatar recently signed agreements with Shell, Total Energies, and Eni to supply LNG to Europe for 27 years. Meanwhile, Chevron is negotiating contracts to ship LNG to Europe for up to 15 years.

It is conceivable that the EU Methane Regulation announcement could incentivise buyers and sellers to accelerate the contracting process to avoid paying any penalties. If so, the proportion of LNG imports covered by the methane import standard could be significantly less than indicated by CATF/Rystad estimates.

Of course, that doesn’t preclude those suppliers from taking action to abate their methane emissions separately, it’s just that volumes under long-term contracts agreed before the law enters into force won’t face a penalty.

Still a work in progress

Methane is a potent greenhouse gas with a global warming potential ~85 times greater than that of carbon dioxide over a 20-year period. it is released across the oil and gas supply chain, from exploration to processing and transportation. Around two-thirds comes from venting, one-quarter results from fugitive emissions (leaks), while the remainder arises from incomplete flaring during oil extraction.

The methane import standard is a positive step in tackling this massive and under-reported problem. But the absence of clarity on the methane threshold, the trigger threshold, and the methodology for calculating methane emissions gives oil and gas exporters little guidance as to how and where they should invest in methane abatement.

Exporters now have seven years in which they can continue to supply the European market with methane-intensive oil and gas. Introducing the measure much sooner than 2030 (perhaps in a phased transition as outlined by CATF/Rystad) would have resulted in significantly greater methane emission abatement, increasing the EU’s contribution towards meeting the Global Methane Pledge.

Arguably, it is in exporters’ long-term best interest to cut their methane emissions, even in the absence of regulation and penalties. The returns from methane abatement are likely to be greatest for natural gas, since the captured volumes reduces lost inventory.

The reputation of gas as a cleaner fossil fuel has been sullied by concerns over methane emissions. This means gas also offers many of the most cost-effective CH4 mitigation measures. Energy companies claim gas will be needed to fuel advanced economies for many decades to come. If they take meaningful action on methane, its role in the mix will be that much more secure.