Deep dive: Hydrogen & e‑fuels — fastest‑moving subsegments to watch

the fastest‑moving subsegments to watch. Focus on Europe's hydrogen and e‑fuels, including the leading sectors and metrics that matter.

Executive Summary

Europe has raced ahead on clean hydrogen and synthetic fuels, doubling its installed water‑electrolysis capacity to about 385 MW by September 2024 and commissioning the continent’s largest 24 MW system in Norway. Yet electrolysis still accounts for only a tiny share—roughly 0.4 %—of the region’s total hydrogen production, and most of the 7.9 Mt of hydrogen consumed in 2023 remained fossil based. Ambitious mandates such as the EU’s ReFuelEU aviation regulation have spurred a surge of project announcements, including 41 large‑scale e‑kerosene plants with a combined 2.8 Mt annual capacity. Meanwhile, industrial users—from fertiliser manufacturers to steelmakers—are commissioning the first commercial‑scale green‑hydrogen projects. This deep dive summarises the fastest‑moving subsegments in Europe’s hydrogen and e‑fuels landscape, identifies what is working and where bottlenecks persist, and provides a framework for sustainability leads to evaluate opportunities. Key takeaways include:

• Electrolyser momentum but miles to go: Installed electrolysis capacity more than doubled in two years, yet Europe is far from its 6 GW 2024 target and the 100 GW needed by 2030. Large projects like Yara’s 24 MW renewable‑hydrogen plant and H2 Green Steel’s 690 MW electrolyser show industrial appetite.
• E‑fuel pipelines are burgeoning: Europe hosts 41 announced e‑kerosene projects, capable of producing 2.8 Mt per year—nearly three times the amount required by the ReFuelEU mandate by 2032. The continent also brought the world’s largest power‑to‑X e‑methanol plant online in Denmark, using three 52 MW electrolysers to make 42 000 t per year of green methanol for shipping and chemicals.
• High costs and slow FIDs: Renewable hydrogen still costs around €6.6/kg on average, and synthetic kerosene costs ~€7 700 per tonne. None of the large e‑SAF projects have yet reached final investment decision (FID); each plant requires €1–2 billion in capital and investors face regulatory uncertainty.
• Energy and water efficiency matter: Producing 1 kg of hydrogen via electrolysis requires 9 L of water plus another 10–20 L for purification and cooling, amounting to 20–30 L/kg—comparable to or lower than fossil‑hydrogen pathways. Turning that hydrogen into more complex e‑fuels adds energy penalties: synthetic methane retains only ~52 % of the input energy, Fischer–Tropsch e‑kerosene ~42 %, and e‑OME3‑5 just 28 %.
• Industrial offtakers drive demand: Early markets are emerging in fertilisers, green steel, shipping and aviation. Norway’s 24 MW plant supplies renewable ammonia and cuts 41 000 t of CO₂ annually, while Sweden’s upcoming H2 Green Steel plant plans to use a 690 MW electrolyser to make 2.4 Mt of green steel per year. The Kassø e‑methanol facility will supply Maersk’s vessels, Lego’s plastics and Novo Nordisk’s medical products.

Why It Matters

Europe’s push to decarbonise hard‑to‑abate sectors hinges on replacing fossil hydrogen and hydrocarbons with molecules made from renewable electricity and captured carbon. Hydrogen is central to this strategy because it can store and transport energy, feed synthesis of new fuels and chemicals, and decarbonise processes such as steelmaking and fertiliser production. However, achieving Europe’s 2030 target of producing 10 Mt of renewable hydrogen will require a step‑change: present electrolysis capacity accounts for less than 0.4 % of total hydrogen production and is far off the 6 GW 2024 milestone. Demand remains dominated by fossil hydrogen—7.9 Mt in 2023—and clean‑hydrogen projects face financing and permitting hurdles. E‑fuels such as e‑kerosene, e‑methanol and e‑ammonia are needed to decarbonise aviation, shipping and heavy industry, yet they are energy‑intensive and costly. Understanding which subsegments are advancing fastest and why helps sustainability leads prioritise investments, secure supply, and influence policy.

Key Concepts and Market Fundamentals

Colours of hydrogen and synthetic fuels

Hydrogen can be produced in different ways. Green hydrogen uses renewable electricity to split water via electrolysis, emitting only oxygen; it consumes around 9 L of water per kilogram of hydrogen produced and an additional 10–20 L for purification and cooling. Blue hydrogen pairs natural‑gas reforming with carbon capture, while grey hydrogen lacks capture. Europe consumed 7.9 Mt of hydrogen in 2023; almost all of it was grey.

Synthetic or e‑fuels combine green hydrogen with captured carbon or nitrogen to produce liquid fuels such as e‑methane (synthetic natural gas), e‑methanol, Fischer–Tropsch e‑kerosene/diesel and e‑ammonia. The more complex the molecule, the more energy it requires: producing 1 MJ of Fischer–Tropsch e‑diesel from direct‑air‑capture CO₂ consumes about 2.4 times the energy needed for 1 MJ of hydrogen. Energy efficiency drops as molecules lengthen: green hydrogen retains about 75 % of its input energy, e‑methane 52 %, e‑kerosene 42 %, and e‑OME3‑5 just 28 %.

Europe’s hydrogen baseline

Clean‑hydrogen supply is expanding rapidly but remains small in absolute terms. Electrolytic production capacity more than doubled to 385 MW by September 2024, yet it provides just 0.4 % of Europe’s hydrogen. The largest commissioned electrolyser—a 24 MW plant at Herøya, Norway—cuts 41 000 t of CO₂ per year and produces low‑carbon ammonia. Under current trajectories, Europe is on track to produce around 2.5 Mt of clean hydrogen by 2030 (1.7 Mt electrolytic), far short of the 10 Mt target envisaged by the REPowerEU plan. Even in an accelerated scenario, output would rise to 4.4 Mt. Average renewable hydrogen costs hover around €6.6/kg, although costs are expected to fall by 2030 and narrow the gap with fossil hydrogen to less than €1/kg in markets with abundant renewables like Spain.

Key e‑fuel pathways

• E‑kerosene (synthetic aviation fuel) blends green hydrogen with captured CO₂ via Fischer–Tropsch or methanol‑to‑jet processes. The EU’s ReFuelEU Aviation mandate requires e‑kerosene to account for at least 1.2 % of jet fuel by 2030, rising to 35 % by 2050. As of May 2025, 41 large‑scale e‑SAF projects are under development in Europe, with a combined capacity of 2.8 Mt per year. None have reached FID and each plant needs €1–2 billion in investment. RFNBO‑grade e‑SAF is expensive: EASA estimates costs around €7 700 per tonne, and penalties for suppliers failing to meet mandates could reach €14 000 per tonne.
• E‑methanol couples green hydrogen with CO₂ in a simpler reaction than Fischer–Tropsch and is widely considered the next marine fuel and a chemical feedstock. European Energy’s Kassø Power‑to‑X plant in Denmark demonstrates commercial viability: three 52 MW electrolysers convert solar power and biogenic CO₂ into 42 000 t per year of e‑methanol. The plant produced its first five tonnes in 2025 and will supply Maersk’s container ships, Lego’s plastic production and Novo Nordisk’s pharmaceuticals.
• E‑ammonia synthesises hydrogen with nitrogen through the Haber–Bosch process. Yara’s renewable hydrogen plant at Herøya, Norway, uses a 24 MW PEM electrolyser to make 10 t of hydrogen per day, feeding 20 000 t of ammonia production annually. The facility reduces emissions by 41 000 t per year and shows how existing ammonia plants can be retrofitted.
• Green steel and other industrial applications integrate hydrogen directly rather than synthesising it into fuels. The H2 Green Steel project in Sweden includes a 690 MW electrolyser to produce renewable hydrogen for a direct‑reduction iron plant and electric‑arc furnaces, aiming to make 2.4 Mt of green steel annually from 2026. The European Commission has approved €265 million to support the project.

Fast‑Moving Subsegments to Watch

Electrolyser capacity and industrial projects

Europe’s industrial sector is deploying some of the world’s largest electrolysers. Yara’s Herøya plant demonstrates commercial green hydrogen for fertilisers: its 24 MW PEM electrolyser delivers 10 t of hydrogen per day at 30 bar and powers 20 000 t of renewable ammonia production annually. It cuts 41 000 t of CO₂ each year and is the largest operational system of its kind in Europe. On the steel front, H2 Green Steel’s Boden project will integrate a 690 MW electrolyser with a direct‑reduction iron plant, targeting 2.4 Mt of green steel per year by 2026. These projects illustrate how heavy industry is emerging as an anchor market for green hydrogen.

E‑methanol for shipping and chemicals

Synthetic methanol is gaining traction in maritime and chemical sectors because it is liquid at ambient conditions, easy to handle and versatile. The Kassø Power‑to‑X facility in Denmark is Europe’s largest power‑to‑x plant: three 52 MW electrolysers convert solar‑generated hydrogen and biogenic CO₂ into e‑methanol. When fully ramped up, the plant will produce 42 000 t per year. Shipping giant Maersk plans to use the fuel in its methanol‑powered container ships, while Lego and Novo Nordisk will incorporate it into plastics and pharmaceuticals. The success of Kassø underscores the growing demand for e‑methanol and its role as a bridge fuel for multiple sectors.

E‑kerosene for aviation

The ReFuelEU mandate has catalysed a rush of synthetic aviation fuel projects. Europe hosts 41 announced e‑kerosene plants with 2.8 Mt of potential output. However, high costs and regulatory uncertainty are slowing progress. E‑kerosene production is energy intensive: producing 1 kg of fuel requires about 0.8 kg of hydrogen and 3.1 kg of captured CO₂, and the conversion efficiency is only 20–30 %. EASA’s reference price of around €7 700 per tonne translates to e‑SAF being several times more expensive than fossil jet fuel. Financial penalties for non‑compliance could reach €14 000 per tonne. None of the European projects have reached FID yet; unlocking them will require long‑term offtake agreements and supportive funding mechanisms.

Green steel and ammonia: demand‑side pull

Industrial offtake is critical for scaling hydrogen. Yara’s fertiliser plant demonstrates how renewable hydrogen can decarbonise ammonia production, and H2 Green Steel shows the potential for hydrogen‑direct‑reduction steelmaking. Demand‑side initiatives also create markets for derivatives like e‑methanol: Maersk’s adoption of methanol‑powered ships and orders for dozens of methanol‑dual‑fuel container vessels will increase demand for e‑methanol. Steel, fertiliser and shipping thus form a virtuous triangle that can absorb large volumes of hydrogen and derivatives.

Hydrogen valleys and integrated hubs

Hydrogen valleys are regions where production, storage, distribution and consumption of hydrogen occur within a defined geographic area. Europe has invested heavily in such integrated hubs; they typically provide hydrogen to multiple sectors such as industry, mobility and power. Hubs reduce risk by aggregating offtake and enable shared infrastructure like pipelines, storage and carbon capture. They also help meet the EU’s requirement that renewable‑hydrogen producers source electricity locally and match production temporally to renewable generation. Sustainability leads should monitor emerging valleys—such as those in northern Spain, the Netherlands and Germany—because they will offer early opportunities for projects and procurement.

What’s Working

1. Policy‑driven momentum: Binding mandates like ReFuelEU and national hydrogen strategies create market certainty. Europe’s clean electricity mix gives domestic projects a cost advantage.
2. Industrial scale‑ups: Large electrolysers are moving from pilots to commercial operations. Yara’s Herøya plant and the Kassø e‑methanol facility demonstrate that industrial users can integrate green hydrogen and derivatives at scale.
3. Cross‑sector collaboration: Partnerships between energy companies, heavy industry and off‑takers are emerging. Shipping, chemicals and fertilisers are signing supply agreements that provide demand certainty for producers.
4. Cost decline trajectory: Renewable hydrogen costs are expected to fall significantly by 2030, narrowing the gap with fossil hydrogen to less than €1 per kilogram in high‑renewables regions. Electrolyser manufacturing innovations and economies of scale will drive further reductions.

What Isn’t Working

1. Slow final investment decisions: None of Europe’s large e‑SAF projects have reached FID, and most e‑methanol and e‑ammonia projects remain at early stages. Long permitting timelines and uncertain offtake agreements slow progress.
2. High capital and operating costs: Renewable hydrogen still averages €6.6/kg, and e‑SAF costs €7 700 per tonne. E‑fuel conversion efficiencies are low, meaning more renewable electricity is needed—hydrogen retains 75 % of its input energy while e‑kerosene retains only ~42 %.
3. Regulatory uncertainties: Complex rules around additionality, geographic and temporal correlation and carbon sources create investment risk. The upcoming 2027 ReFuelEU review may alter sub‑targets, while the EU Delegated Acts restrict the use of fossil‑derived CO₂ after 2041.
4. Resource constraints: Delivering 10 Mt of renewable hydrogen by 2030 would require roughly 100 GW of electrolysis capacity and massive amounts of renewable electricity and water. Electrolysis currently uses ~20–30 L of water per kilogram of hydrogen; projects must secure sustainable water sources and avoid local scarcity.

A Quick Framework for Sustainability Leads

When evaluating hydrogen and e‑fuel opportunities, sustainability leads should consider:

1. Resource availability: Assess access to renewable electricity, water and captured CO₂ or nitrogen. Sites with abundant low‑cost renewables and sustainable water sources will have cost advantages.
2. Technology readiness: Evaluate the maturity of electrolyser technology, synthesis processes and associated infrastructure. PEM electrolysers are proven at tens of megawatts, while solid‑oxide and co‑electrolysis remain emerging.
3. Market and offtake: Identify industrial users willing to sign long‑term contracts—steel mills, ammonia plants, shipping lines and airlines. Secure offtake agreements reduce risk and enable financing.
4. Policy and incentives: Monitor EU and national support schemes, including contracts for difference, tax credits and grants. Take note of regulatory requirements on additionality and carbon sourcing and ensure compliance.
5. Life‑cycle assessment (LCA) and carbon intensity: Ensure projects achieve at least 70 % emissions reduction relative to fossil fuels, as required by EU rules, and account for upstream emissions from electricity, water purification and feedstock capture.
6. Cost and financing: Model capital expenditures (electrolysers, synthesis plants, carbon capture) and operating costs (electricity, water, maintenance). Consider partnering with investors and tapping EU funds such as the Innovation Fund or the Recovery and Resilience Facility.
7. Integration and scaling: Favour projects within hydrogen valleys or industrial clusters that share infrastructure. Plan for scalability—small pilots should be designed to integrate into larger networks.

Fast‑Moving Segments to Watch

• Industrial electrolysers (>50 MW): Commercial deployments like Yara’s 24 MW plant and the planned 690 MW unit for H2 Green Steel signal a shift toward megawatt‑scale hydrogen production.
• E‑methanol for maritime transport: The Kassø plant demonstrates large‑scale e‑methanol production; global shipping companies are ordering methanol‑powered vessels, positioning e‑methanol as a leading marine fuel.
• E‑kerosene for aviation: With 41 European projects totalling 2.8 Mt/year of capacity, e‑kerosene is poised to become a regulated commodity. Watch for the first FIDs and cost breakthroughs.
• Green steel and fertilisers: Demand from steelmakers and fertiliser producers provides stable offtake for hydrogen. The H2 Green Steel and Yara projects exemplify this pull.
• Hydrogen valleys: Integrated hubs connecting renewable generation, electrolysers, storage and multiple end‑users are emerging across Europe. These valleys reduce risk and foster economies of scale.

Action Checklist

• Map your demand: Quantify potential hydrogen and e‑fuel consumption across operations (e.g., fuel switching, process heat, feedstocks) and identify segments where substitution is technically feasible.
• Secure renewable resources: Engage with developers to lock in renewable electricity supply and explore options for co‑locating electrolysers with wind or solar farms. Evaluate water sources and recycling technologies to ensure sustainable use.
• Partner early: Collaborate with industrial peers, shipping companies, airlines and fuel suppliers to aggregate demand and support early projects. Participate in hydrogen valleys or regional clusters to share infrastructure.
• Design for flexibility: Favour modular electrolyser systems that can scale with demand, and choose synthesis pathways (e‑methanol, e‑kerosene, e‑ammonia) aligned with your sector’s needs and the availability of carbon or nitrogen feedstocks.
• Prioritise LCA compliance: Conduct life‑cycle assessments to ensure projects meet EU carbon‑intensity thresholds. Factor in upstream emissions from electricity generation, water treatment and CO₂ capture.
• Plan financing strategies: Evaluate grants, tax credits and contracts for difference available through the Innovation Fund, European Hydrogen Bank and national programs. Prepare for high capex and long payback periods.
• Track regulation: Monitor updates to the ReFuelEU mandate, hydrogen additionality rules and carbon‑sourcing restrictions. Engage in public consultations to shape policies and reduce uncertainty.

Frequently Asked Questions

What is green hydrogen and how does it differ from grey or blue hydrogen? Green hydrogen is produced by electrolysing water with renewable electricity. Grey hydrogen is made via steam methane reforming without carbon capture, while blue hydrogen pairs reforming with carbon capture and storage. Green hydrogen has near‑zero direct emissions and uses roughly 20–30 L of water per kilogram produced.

How much water does green hydrogen consume? The electrolysis reaction itself uses 9 L of water per kilogram of hydrogen. Additional purification and cooling typically require another 10–20 L, bringing total consumption to 20–30 L/kg—similar to or lower than fossil‑hydrogen processes.

Why are e‑fuels so energy‑intensive? Combining hydrogen with carbon or nitrogen requires additional chemical reactions that consume energy. E‑methane retains about 52 % of the input energy, e‑kerosene only ~42 %, and more complex fuels like e‑OME3‑5 around 28 %, whereas hydrogen retains about 75 %.

What are the largest green‑hydrogen projects in Europe today? The largest operational system is Yara’s 24 MW PEM electrolyser in Herøya, Norway, which produces 10 t of hydrogen per day and supplies renewable ammonia. Upcoming projects include the H2 Green Steel plant in Sweden, integrating a 690 MW electrolyser, and multiple 100+ MW projects under construction.

How expensive are synthetic aviation fuels? EASA estimates that RFNBO e‑kerosene costs around €7 700 per tonne and that penalties for failing to supply mandated volumes could reach €14 000 per tonne. These high costs reflect both the low energy efficiency of e‑kerosene and the capital intensity of the required infrastructure.

Will renewable hydrogen become cost‑competitive with fossil hydrogen? Renewable hydrogen averaged €6.6/kg in 2023, but costs are projected to fall rapidly as electrolyser technology improves and renewable power prices decline. The cost gap with fossil hydrogen could narrow to less than €1/kg by 2030 in regions with plentiful renewable resources.

Sources

[1] Clean Hydrogen Monitor 2024 and Hydrogen Europe Quarterly #09: Europe doubled installed electrolysis capacity to about 385 MW by September 2024, but this accounts for only 0.4 % of hydrogen production; hydrogen demand was 7.9 Mt in 2023; the largest commissioned installation is a 24 MW system in Norway; the EU’s target of 6 GW by 2024 will not be met.

[2] Hydrogen Europe Quarterly #09: Renewable hydrogen costs around €6.6/kg and the cost gap with fossil hydrogen is expected to fall below €1/kg by 2030; Europe’s clean‑hydrogen pipeline amounts to 14.4 Mt, with current trajectories delivering 2.5 Mt of clean hydrogen (1.7 Mt electrolytic) by 2030 and an accelerated scenario delivering 4.4 Mt.

[3] Yara corporate release and fact sheet: Yara’s 24 MW PEM electrolyser at Herøya produces renewable hydrogen and ammonia, cutting 41 000 t of CO₂ annually; the plant delivers hydrogen at 99 % purity at 30 bar, produces 10 t H₂/day and 20 000 t of ammonia per year.

[4] Rinnovabili article: The Kassø Power‑to‑X facility in Denmark uses three 52 MW electrolysers powered by solar energy and biogenic CO₂ to produce e‑methanol; the plant targets 42 000 t/year and produced its first 5 t in 2025; Maersk, Lego and Novo Nordisk will use the fuel.

[5] Hydrogen Europe news: The EU approved €265 million for Sweden’s H2 Green Steel project; the plant will incorporate a 690 MW electrolyser, direct‑reduction iron facility and electric‑arc furnaces to produce 2.4 Mt of green steel per year starting in 2026.

[6] RMI article: Green hydrogen requires 9 L of water per kg for electrolysis and an additional 10–20 L for purification and cooling, resulting in 20–30 L/kg; this is comparable to or less than fossil‑hydrogen pathways.

[7] Concawe techno‑economic assessment: E‑fuel energy efficiency declines with complexity; hydrogen retains about 75 % of input energy, e‑methane 52 %, Fischer–Tropsch e‑kerosene/diesel 42 %, and e‑OME3‑5 28 %; producing 1 MJ of e‑diesel requires 2.4 times the energy needed for 1 MJ of hydrogen.

[8] Transport & Environment e‑SAF report: Europe has 41 large‑scale e‑SAF projects under development with a combined capacity of 2.8 Mt/year; none have reached final investment decision; projects need €1–2 billion each; FIDs must be secured within 12–18 months to meet 2030 targets. Europe’s clean electricity and unique mandate create a cost advantage, but financing and regulatory uncertainties hamper progress.

[9] Transport & Environment report on penalties: EASA estimates RFNBO e‑kerosene costs around €7 700 per tonne and that penalties for failing to supply mandated volumes could reach €14 000 per tonne.