Urszula Szalkowska, managing director for European Markets at EcoEngineers, part of LRQA, examines how biomethane is now embedded in the EU's carbon compliance architecture and what this means in practice for operators under ETS1 and ETS2.
Biomethane has quietly crossed a threshold. It is no longer discussed primarily as a renewable gas alternative to natural gas; it has become a recognised instrument within the EU's carbon compliance architecture, and the implications for industrial operators, fuel suppliers and gas traders are beginning to materialise in ways that are both financial and operational.
The numbers provide a sense of the scale of what is changing. About 29% of the biomethane used in the European Union (EU) today falls within EU Emissions Trading System 1 (EU ETS 1) sectors, such as power generation and heavy industry, while an additional 43% is used in sectors covered by the newly operational EU Emissions Trading System 2 (ETS2), which includes buildings, road transport and smaller industries.
Together, close to three-quarters of EU biomethane consumption now intersects with the EU ETS in some form. The EU currently produces around 19 billion cubic metres of biomethane, representing roughly 6% of total EU gas consumption. With 90% of EU gas still imported, biomethane is increasingly being positioned by policymakers as both an energy security asset and a strategic substitute for fossil fuels.
This analysis draws on work developed alongside Julian Auderieth, president of the European Renewable Gas Registry (ERGaR), and covers the compliance mechanics, financial value and policy developments that operators in the sector should be tracking.
Under ETS1, the compliance benefit of biomethane flows from a straightforward principle. Operators report total calculated emissions, and where biomethane is used, they must determine the biomass fraction of their fuel mix and demonstrate that it meets the sustainability and GHG savings criteria set out in the Renewable Energy Directive (RED).
When those conditions are satisfied, biomethane can be assigned a zero-emission factor, meaning the emissions associated with its combustion do not require allowances. More eligible biomethane in the fuel mix means a lower fossil fraction, fewer reportable emissions, fewer allowances to surrender and a lower compliance cost. The zero rating is not automatic; it depends on RED compliance and requires the same certification and traceability evidence that underpins proofs of sustainability.
On the operational side, ETS1 also permits a simplified methodology for grid-delivered biogas. Rather than physically tracking individual molecules through the grid, operators can use purchase records of equivalent energy content alongside registry evidence. This is permitted only where the operator can demonstrate that no double counting occurs, that a shared grid connection exists between the producer and the operator, and that compliance with applicable sustainability criteria is achieved. For many ETS installations using grid-sourced biomethane, this flexibility represents a meaningful reduction in administrative burden.
ETS2 introduces a different point of obligation. Rather than sitting with the emitter, compliance costs fall upstream on the fuel supplier releasing fuel for consumption. The same zero-rating principle applies where RED sustainability conditions are met, reducing the total volume of allowances that must be surrendered. One distinction worth noting: ETS is not a life-cycle accounting system, and a negative carbon intensity score for a given biomethane pathway does not reduce ETS compliance emissions below zero. The full life-cycle benefit of high-performing pathways is captured under RED accounting rather than within the ETS framework itself.
The ETS2 timeline is now pressing. The monitoring phase began in 2025, and 2026 is the first full reporting year. By April 2027, regulated entities must submit emissions reports to relevant member state authorities, with the first surrender of allowances due in May 2029. Interest from industrial players and fuel suppliers in using biomethane to manage ETS exposure is rising, but operational readiness across the market remains uneven. Traders generally understand which certificates are needed, yet many face practical challenges with registry interoperability and cross-border transfers. Suppliers may be familiar with monitoring plans in their home markets while lacking the expertise to navigate certificate requirements in the member states where they supply. Some national authorities responsible for verifying ETS compliance are still building familiarity with how biomethane accounting functions in practice.
There is a degree of reassurance in the legal architecture, however. The Monitoring and Reporting Regulation (MRR) is a regulation rather than a directive, which means it is directly binding on all member states without requiring national transposition. Operators who follow what is written in the regulation can reasonably expect national authorities to accept it, and this matters for companies that want to move ahead of the market without waiting for full domestic clarity. Building the right dialogue with local authorities still requires effort, but the legal basis is solid.
The more forward-looking question concerns whether current frameworks are capturing biomethane's full climate contribution, and at present, they are not. The same biomethane pathway is treated differently depending on which framework applies. Under ETS, biomethane reduces fossil emissions and carbon compliance costs. Under RED, it is assessed on life-cycle performance against a fossil comparator, a more comprehensive methodology that can credit negative carbon intensity scores for high-performing pathways. Under the new Carbon Removal and Carbon Farming Framework (CRCF), where CO2 is captured from a biomethane production process and permanently stored, this constitutes a genuine carbon removal.
This fragmentation creates real costs for producers and investors. A producer investing in carbon capture at a biomethane plant currently faces genuine uncertainty about how that investment will be recognised across all three frameworks. Whether it reduces ETS obligations, generates carbon removal credits under the CRCF or improves a RED certification score depends on different rules, different methodologies and different institutional processes. This complexity raises the cost of investment decisions, particularly at the point where financing commitments need to be made.
The second half of 2026 is shaping up as a material window for change. The post-2030 ETS reform is under active discussion, with the European Commission having opened the conversation about integrating carbon removals into the ETS framework. The Renewable Energy Directive is also heading for revision. Both processes offer a genuine opportunity to reduce fragmentation, allow carbon removals to function as a compliance option within ETS where robust accounting can be assured, and align the treatment of biogenic CO2 across ETS, RED and CRCF using RED as a common regulatory backbone. Getting this right would give the industry clearer signals on value allocation earlier in the investment cycle and reduce the regulatory complexity that producers currently have to navigate across multiple, sometimes conflicting frameworks.
The commercial case for biomethane in industrial decarbonisation is already compelling without further reform. At a recent industry workshop in Ljubljana, an unsubsidised biomethane plant built by AstraZeneca at Gonerby Moor, Lincolnshire, supplying its Cambridge site among others, was presented as a case study. The pharmaceutical company had evaluated two decarbonisation options: green hydrogen at approximately €300 per megawatt-hour, or biomethane at approximately €90 per megawatt-hour, using the same existing infrastructure and equipment. The cost differential reflects a structural advantage that biomethane holds over most alternative pathways – it uses existing gas grid infrastructure, it is a molecule that industry already knows how to handle, and European storage and transport networks are already in place. The ETS is one mechanism that can close the remaining price gap with fossil gas for industrial consumers, and as ETS2 extends carbon pricing to buildings and transport, the same dynamic will apply across a much larger share of the economy.
For operators and suppliers now working through their ETS exposure, several practical issues deserve attention. Monitoring, reporting and verification systems need to correctly handle biomethane accounting – with clear segmentation between ETS1 and ETS2 consumption, robust prevention of double counting, and proper registry and mass-balance documentation. The compliance exposure from weak traceability is real and will grow as ETS2 obligations come fully into force. Separately, the sector continues to need harmonised tracking infrastructure. The EU's existing certificate instruments were not designed with gaseous energy carriers in mind. Guarantees of Origin were built for the electricity sector, and Proofs of Sustainability were originally developed for liquid biofuels. A fit-for-purpose tracking mechanism for biomethane that functions across borders and registries remains a prerequisite for a well-functioning market, and the ongoing delays to the Union Database (UDB) have created persistent uncertainty that the industry needs to continue pressing to resolve.
On the reform discussions now underway, active engagement from the biomethane industry matters. The current review processes for ETS and RED represent an opportunity to achieve more coherent recognition of biomethane's full carbon value across frameworks. The European Commission has been receptive to industry input through its call for evidence process, and producers, traders, suppliers and certifiers should be contributing concrete proposals while those discussions remain open.
Biomethane in the carbon market: what operators need to know about ETS1 and ETS2
