This report, prepared at the request of the European Parliament’s Committee on Industry, Research and Energy (ITRE), aims to answer key questions, such as: Which production pathways are included and excluded by the methodology provided by the draft Delegated Act? Does the Delegated Act enable the hydrogen economy by providing incentives to produce or import sufficient volumes of hydrogen in/to the European Union? Is the Delegated Act sufficiently addressing fossil fuel emissions? What are the price and cost expectations of such hydrogen based on this methodology?
Please note: The analysis has been produced under a contract with the European Parliament and the opinions expressed are from Future Cleantech Architects only and do not represent the EP’s official position.
On 8 July 2025, the European Commission adopted a Delegated Act C(2025) 4674, supplementing Directive (EU) 2024/1788 on the internal markets for renewable gas, natural gas, and hydrogen, which is currently subject to scrutiny by the European Parliament and the Council. The Act defines the methodology to calculate greenhouse gas (GHG) emissions savings from Low-Carbon Fuels (LCFs), with particular relevance for low-carbon hydrogen. It aligns with the earlier adopted methodology for renewable fuels of non-biological origin (RFNBOs) and establishes a minimum reduction of 70% GHG emissions savings compared to the unabated fossil fuel comparator.
This Delegated Act (DA) comes in the context of the EU Hydrogen Strategy (2020) and REPowerEU (2022), which set ambitious deployment goals for renewable hydrogen. Following the adoption of the Hydrogen and Gas Market Directive, the role of low-carbon hydrogen and fuels was recognised as one of the levers to advance decarbonisation efforts in sectors where electrification would offer limited solutions. However, a critical missing piece was the EU-wide framework to assess their GHG emissions performance. Establishing clear standards, embedded in an enabling regulatory framework, is essential to foster an environment that provides investment certainty and safeguards environmental integrity for development and deployment of clean hydrogen solutions.
The Delegated Act aims to provide a harmonized and transparent regulatory framework for low-carbon hydrogen and fuels, ensure comparability with renewable hydrogen and fuels, and facilitate the scaling of low-carbon hydrogen and fuel supply in the EU. It has important implications for investment decisions and market signals, production costs, and the environmental integrity of Europe’s hydrogen economy.
The Delegated Act (DA) is a regulatory enabler, not a market driver. It does not create demand, set production targets, or provide financial incentives for hydrogen. Instead, it establishes a harmonized EU-wide accounting and certification methodology for low-carbon fuels, giving developers, investors,
importers, and Member States regulatory certainty about what qualifies as low-carbon hydrogen. This reduces investment risk, facilitates cross-border trade, and prevents fragmentation from diverging national standards. In short, the DA lays the groundwork for a functioning low-carbon hydrogen market but does not itself stimulate production or imports. Most current EU support is targeted at renewable hydrogen (RFNBOs), so the DA’s effect on low-carbon hydrogen will depend heavily on whether additional policy instruments are created at EU or national level.
The Delegated Act (DA) defines rules for both fossil-based hydrogen with CCS and electrolytic hydrogen, but its adequacy in addressing fossil emissions is decisive for credibility. Low-carbon hydrogen climate integrity will hinge on robust methane (CH<sub>4</sub>) emissions measurement and reporting data.
- Natural gas pathways:
- Upstream CH<sub>4</sub> emissions: The DA includes methane intensity in life cycle GHG accounting. The default leakage rate (0.88%, 0.190 g CH<sub>4</sub>/MJ NG) is reasonable but not conservative, meaning some higher-emission sources may still meet thresholds by reporting default values. Accurate and comprehensive reporting under the Methane Regulation is key.
- Upstream natural gas CO<sub>2</sub> emissions: The DA’s CO<sub>2</sub> default value of 4.9 g CO<sub>2</sub>/MJ NG is broadly consistent with the EU-mix value in the 2020 JEC Well-to-Wheels report and with the IEA’s estimate of the global average. Like the methane default, the CO<sub>2</sub> default can be characterised as justifiable but is not strongly conservative.
- LNG emissions: LNG is more emission-intensive than pipeline gas due to liquefaction and transport losses. Current defaults do not include LNG-specific values, creating uncertainty and underreporting risks without standardized measurement.
- Electrolytic pathways:
- Emissions depend on the electricity mix. Four calculation methods are allowed, with nuclear recognised as a low-carbon source. Countries with clean grids (e.g. Sweden, France) can already comply but fossil-heavy grids (e.g. Germany, Poland) require a part of the supply to come from renewable PPAs or direct connection to reduce the average of the input mix.
The DA is a step forward in assessing emissions across the whole hydrogen supply chain. However, relying on reasonable but non-conservative CH<sub>4</sub> and CO<sub>2</sub> defaults, and the omission of LNG-specific default values, risks underestimating methane emissions where actual data is lacking. Its effectiveness
will depend on strict enforcement and accurate reporting under the methane regulation. Electrolytic hydrogen already meets thresholds in low-carbon grid regions, while fossil-heavy grids need dedicated renewable PPAs or direct connections to renewable plants in accordance with the RFNBO DA.
Complying with LCF emissions savings raises costs compared to unabated “grey” hydrogen, since producers must add carbon abatement technologies (CCS or CCU) or restrict electrolytic production to low-emission hours if the grid intensity exceeds the minimum threshold.
- Blue hydrogen (natural gas with CCS):
- Estimated costs are in the range 3.5-6.5 €/kg, with the lower end reflecting current gas prices (40 €/MWh). At this level, the cost is 3.5 €/kg, roughly 60% more expensive than grey hydrogen (2.2 €/kg).
- Cost variations across Member States are minimal, as natural gas price is the main contributor to blue hydrogen cost. CO<sub>2</sub> transport and storage costs remain uncertain and depend on utilisation for cost reduction.
- Future gas price volatility will be the main factor influencing blue hydrogen costs.
- • Electrolytic low-carbon hydrogen:
- Current costs are 6-8 €/kg, depending on electrolyser and grid costs. Electricity makes up about half or more of total costs.
- Falling electrolyser prices allow greater flexibility to use cheap, low-emission electricity, which could allow costs to fall below 3 €/kg. However, the speed of progress is uncertain.
- In fossil-heavy grids, production hours are limited to meet LCF rules, which would raise costs due to lower utilisation rates, unless electricity supply is partially supplemented by renewable PPAs, bringing down the average emissions of the input mix. This increases average electricity costs but boosts RFNBO compliant output.
Blue hydrogen is likely the cheapest near-term option, though tied to volatile gas prices. Electrolytic hydrogen will become more competitive as electrolyzer costs fall, low-carbon electricity expands, but remains costlier today and highly dependent on power prices.