Interview: Practitioners on Hydrogen & e-fuels — what they wish they knew earlier

Global electrolyzer manufacturing capacity reached approximately 45 GW per year by end of 2025, yet only 4% of announced green hydrogen projects worldwide had reached final investment decision, according to the International Energy Agency's Global Hydrogen Review 2025. Europe alone has committed over €20 billion in public subsidies through mechanisms including the EU Hydrogen Bank and national hydrogen strategies, while actual green hydrogen production on the continent remains below 100,000 tonnes per year. For executives evaluating hydrogen and e-fuel investments, the chasm between policy ambition and operational delivery creates a landscape where expensive lessons are learned daily. Seven practitioners across electrolysis, hydrogen distribution, and e-fuel production shared the hard-won insights they wish someone had given them before committing capital and organizational resources.

Why It Matters

Hydrogen is positioned as a critical decarbonization vector for sectors where direct electrification is technically or economically impractical, including steelmaking, ammonia production, heavy-duty transport, and long-duration energy storage. The European Commission's REPowerEU plan targets 10 million tonnes of domestic green hydrogen production and 10 million tonnes of imports by 2030. Germany's national hydrogen strategy, updated in 2023, calls for 10 GW of domestic electrolyzer capacity by 2030. The United Kingdom's Hydrogen Production Business Model provides revenue support contracts of up to 15 years to bridge the cost gap between green hydrogen and fossil fuel alternatives.

The cost dynamics are shifting but remain challenging. Green hydrogen production costs in Europe ranged from €4.50 to €7.50 per kilogram in 2025, compared to grey hydrogen produced from natural gas at €1.50 to €2.50 per kilogram (Hydrogen Council, 2025). E-fuels produced via Fischer-Tropsch synthesis using green hydrogen and captured CO2 cost between €3.00 and €6.00 per liter, roughly 4 to 8 times the price of conventional diesel. Decisions made today on electrolyzer technology, offtake structures, and infrastructure routing will determine which organizations capture value as regulatory mandates tighten and carbon pricing rises through the EU Emissions Trading System and the Carbon Border Adjustment Mechanism.

Key Concepts

Navigating the hydrogen and e-fuels sector requires familiarity with several foundational elements.

Green Hydrogen: Hydrogen produced through water electrolysis powered by renewable electricity. The EU Delegated Acts under the Renewable Energy Directive (RED III) define strict additionality, temporal correlation, and geographic correlation requirements for electricity used in green hydrogen production, which practitioners report have significantly complicated project development timelines.

Electrolyzer Technologies: Three primary types dominate the market. Alkaline electrolyzers offer the lowest capital cost (€500 to €800 per kW) but slower ramp rates. Proton exchange membrane (PEM) electrolyzers provide faster dynamic response (€800 to €1,400 per kW) suited to coupling with variable renewables. Solid oxide electrolyzers (SOEC) achieve the highest efficiency (up to 85%) but remain at earlier commercial maturity with limited deployment at scale.

E-fuels (Electrofuels): Synthetic fuels produced by combining green hydrogen with captured CO2 through processes including Fischer-Tropsch synthesis, methanol synthesis, or methanation. E-fuels are "drop-in" compatible with existing engines and fuel infrastructure, making them attractive for sectors that cannot transition to direct hydrogen use.

Hydrogen Derivatives: Chemicals produced from hydrogen including green ammonia (for fertilizer production and maritime fuel), green methanol (for shipping and chemical feedstocks), and synthetic kerosene (for aviation). Each derivative pathway has distinct efficiency losses, infrastructure requirements, and end-market dynamics.

EU Hydrogen Bank: Mechanism launched in 2023 that uses competitive auctions to allocate fixed premium subsidies (in € per kg) to green hydrogen producers, bridging the cost gap with fossil alternatives. The first auction in 2024 awarded €720 million across 7 projects at an average premium of €0.48 per kg.

What's Working

Practitioners identified several approaches delivering measurable results across the hydrogen value chain.

Vertical integration between renewable power generation and electrolyzer operation is reducing green hydrogen production costs significantly. Iberdrola's Puertollano green hydrogen plant in Spain, one of Europe's largest operational facilities at 20 MW, co-locates a 100 MW solar photovoltaic installation with an alkaline electrolyzer. The company reports a levelized cost of hydrogen below €4.00 per kg by eliminating grid connection fees, transmission losses, and renewable energy certificate procurement costs. The integrated model also simplifies compliance with EU additionality requirements since the dedicated renewable capacity directly feeds production.

Long-term hydrogen purchase agreements (HPAs) with industrial off-takers are proving essential for securing project finance. Thyssenkrupp Steel signed a binding 10-year green hydrogen offtake agreement with Shell for supply to its Duisburg steelworks in Germany, providing the revenue certainty required for Shell to commit to its Holland Hydrogen I project, a 200 MW electrolyzer facility in Rotterdam. The agreement includes price indexation mechanisms tied to EU ETS carbon prices, ensuring that the green hydrogen premium narrows as carbon costs rise, reducing subsidy dependency over time.

Modular electrolyzer deployment strategies are enabling faster learning and risk reduction compared to single large-scale installations. ITM Power's approach of manufacturing standardized 5 MW PEM electrolyzer modules in its Sheffield gigafactory allows customers to deploy capacity incrementally, validate performance, and add modules as demand materializes. Linde has adopted this modular approach at its Leuna facility in Germany, starting with a 24 MW installation and adding capacity in 5 MW increments based on industrial customer demand.

Hub-and-cluster infrastructure models are reducing per-unit distribution costs. The Port of Rotterdam's hydrogen backbone project connects multiple industrial users through a shared pipeline network, distributing costs across Unilever, Shell, Air Liquide, and BP operations within the port complex. This shared infrastructure model reduces per-kilogram transport costs by an estimated 30 to 40% compared to dedicated point-to-point delivery arrangements (Port of Rotterdam Authority, 2025).

What's Not Working

Practitioners were equally direct about persistent challenges and outright failures.

EU regulatory complexity around green hydrogen certification has delayed projects by 12 to 24 months. The Delegated Acts defining "renewable hydrogen" require hourly temporal correlation between renewable electricity generation and electrolyzer operation starting in 2030, with monthly correlation accepted until then. Geographic correlation rules require renewable generation and electrolysis to be in the same bidding zone or connected by a dedicated line. Multiple practitioners described spending 6 to 12 months on regulatory interpretation and compliance structuring before beginning equipment procurement, with several projects redesigned after legal analysis revealed that initial configurations would not qualify for green certification.

Electrolyzer performance degradation in real-world operations has exceeded manufacturer specifications. Stack degradation rates of 1.5 to 3% per year have been documented at multiple European PEM installations, versus manufacturer warranties based on 0.5 to 1% annual degradation under laboratory conditions. The discrepancy is attributed to impure water supply, frequent cycling loads, and higher operating temperatures than test conditions. Several practitioners reported that stack replacement cycles of 5 to 7 years, rather than the projected 8 to 10 years, significantly impact levelized cost of hydrogen calculations (Fraunhofer ISE, 2025).

Green hydrogen transport and storage costs are frequently underestimated in project economics. Compressed hydrogen trucking at 350 to 500 bar costs €1.50 to €3.00 per kg for distances exceeding 100 km, often doubling the delivered cost of hydrogen relative to production cost. Pipeline repurposing from natural gas to hydrogen service requires extensive metallurgical assessment and typically 30 to 50% of new-build pipeline costs. One practitioner described a project where transport costs exceeded production costs for the first three years of operation because the off-taker facility was 180 km from the nearest electrolyzer.

E-fuel production efficiency losses remain a fundamental economic barrier. The round-trip efficiency from renewable electricity to e-fuel delivered to an engine is approximately 13 to 20%, meaning 5 to 8 kWh of renewable electricity are consumed for every 1 kWh of useful energy in the final e-fuel. This efficiency penalty makes e-fuels the most expensive decarbonization option on a per-unit-of-energy basis and restricts their economic viability to applications where no direct electrification alternative exists (Agora Energiewende, 2025).

Water availability at electrolyzer sites has emerged as a constraint that early project planners overlooked. Producing 1 kg of hydrogen via electrolysis requires approximately 9 to 10 liters of ultra-pure water, and treatment of raw water sources adds 15 to 25% to operating costs. Several projects in southern Spain and North Africa have encountered permitting delays because local water authorities raised concerns about industrial water consumption in drought-affected regions.

Key Players

Established Companies

• Siemens Energy: Major electrolyzer manufacturer producing both PEM and pressurized alkaline systems at its Berlin factory with capacity exceeding 1 GW per year
• Air Liquide: Industrial gas company operating over 40 hydrogen production facilities globally and developing large-scale green hydrogen projects in Normandy, France
• Shell: Developing the 200 MW Holland Hydrogen I project in Rotterdam and building hydrogen refueling infrastructure across Europe
• Thyssenkrupp nucera: Alkaline water electrolysis technology provider with over 600 projects delivered globally and a 1 GW per year manufacturing capacity target
• Linde: Operating green hydrogen production at Leuna, Germany and supplying hydrogen distribution infrastructure to industrial clusters

Startups and Innovators

• Sunfire: Dresden-based company developing solid oxide electrolyzers for high-efficiency hydrogen production, with a 500 MW factory under construction
• HIF Global: Developing the Haru Oni e-fuels pilot in Chile producing synthetic gasoline from green hydrogen and captured CO2, backed by Porsche
• Enapter: Italian-German startup mass-producing anion exchange membrane (AEM) electrolyzers targeting distributed hydrogen production at smaller scales
• Tree Energy Solutions (TES): Belgian company developing e-methane (synthetic natural gas) production facilities using green hydrogen and biogenic CO2

Investors and Funders

• European Clean Hydrogen Alliance: EU industry coalition coordinating investment across the hydrogen value chain with a pipeline exceeding €300 billion in announced projects
• Hy24: Joint venture between Ardian and FiveT Hydrogen managing the world's largest clean hydrogen infrastructure fund at €2 billion
• JERA: Japanese energy company investing in European green hydrogen and ammonia supply chains for import to Asian markets

Action Checklist

• Map internal hydrogen demand potential across operations, identifying processes where direct electrification is not technically feasible and hydrogen is the lowest-cost decarbonization pathway
• Evaluate electrolyzer technology options (alkaline, PEM, SOEC) against specific operational requirements including load flexibility, space constraints, and heat integration potential
• Engage legal counsel on EU Delegated Act compliance for green hydrogen certification before finalizing renewable energy sourcing arrangements
• Structure hydrogen purchase agreements with carbon price indexation clauses to reduce subsidy dependency as EU ETS prices rise
• Conduct water availability and permitting assessment at prospective electrolyzer sites, including drought risk projections and competing water demand analysis
• Adopt modular deployment strategies starting with 5 to 20 MW pilot installations to validate real-world performance before committing to 100 MW-plus projects
• Evaluate hub-and-cluster infrastructure models that share pipeline and storage costs across multiple off-takers rather than dedicated point-to-point delivery
• Build internal capability on hydrogen lifecycle carbon intensity calculation to verify supplier claims and ensure compliance with evolving regulatory definitions

FAQ

Q: How should executives evaluate whether green hydrogen or direct electrification is the right decarbonization pathway for a specific industrial process? A: Apply a decision hierarchy based on process temperature, energy density requirements, and infrastructure constraints. Direct electrification using heat pumps or electric furnaces is nearly always more cost-effective and energy-efficient for processes below 400 degrees Celsius. Hydrogen becomes competitive for high-temperature industrial heat above 1,000 degrees Celsius (steelmaking, glass, ceramics) and for chemical feedstock applications where hydrogen is a molecular input rather than just an energy carrier (ammonia, methanol, refining). For transport applications, battery electric solutions dominate for vehicles under 40 tonnes and routes under 500 km, while hydrogen fuel cells offer advantages for heavy-duty long-haul applications. The key mistake practitioners report is defaulting to hydrogen when electrification would deliver the same outcome at 30 to 50% lower total cost.

Q: What contract structures best protect buyers in long-term hydrogen purchase agreements? A: Effective HPAs include several protective mechanisms. Price indexation should link to both renewable electricity costs and EU ETS carbon prices, ensuring the green premium narrows over time. Volume flexibility provisions of plus or minus 15 to 20% accommodate demand uncertainty without triggering take-or-pay penalties. Quality specifications should define maximum carbon intensity per kilogram (typically below 3 kg CO2e per kg H2 for green certification) with independent verification rights. Include technology upgrade clauses allowing the supplier to replace or upgrade electrolyzer stacks without disrupting supply commitments. Force majeure provisions should specifically address regulatory reclassification risk, meaning scenarios where changes to EU Delegated Act definitions could affect the green hydrogen certification status of the supply.

Q: What is the realistic timeline for green hydrogen cost parity with grey hydrogen in Europe? A: Most practitioners estimate 2030 to 2034 for cost parity at production-gate level, contingent on three converging factors. Electrolyzer capital costs need to decline from current levels of €600 to €1,400 per kW to €200 to €400 per kW through manufacturing scale-up and learning rates. Renewable electricity costs need to remain below €30 per MWh for dedicated supply. EU ETS carbon prices need to sustain levels above €80 to €100 per tonne, effectively raising grey hydrogen costs to €2.50 to €3.50 per kg. If all three conditions converge, green hydrogen production costs could reach €2.00 to €3.00 per kg by 2032, overlapping with carbon-priced grey hydrogen (Hydrogen Council, 2025). However, delivered cost parity (including transport and storage) will lag production-gate parity by 2 to 4 years due to the infrastructure buildout timeline.

Q: How do e-fuels compare economically to other decarbonization options for hard-to-abate sectors? A: E-fuels occupy the highest-cost tier of decarbonization options due to the compounding efficiency losses in their production chain. For aviation, e-SAF currently costs €3.00 to €6.00 per liter versus €0.60 to €0.80 per liter for conventional jet fuel, though the ReFuelEU Aviation mandate creates guaranteed demand from 2030. For maritime shipping, green methanol at €800 to €1,200 per tonne competes with conventional heavy fuel oil at €350 to €450 per tonne. The economic case for e-fuels relies on three conditions: regulatory mandates that create obligated demand, carbon pricing that penalizes fossil alternatives, and continued decline in renewable electricity and electrolyzer costs. Practitioners advise against investing in e-fuel projects without at least one binding offtake agreement or regulatory mandate as a demand anchor.

Sources

• International Energy Agency. (2025). Global Hydrogen Review 2025. Paris: IEA.
• Hydrogen Council. (2025). Hydrogen Insights 2025: Global Hydrogen Market Update. Brussels: Hydrogen Council.
• Fraunhofer ISE. (2025). Electrolyzer Performance and Degradation: Field Data Analysis from European Installations. Freiburg: Fraunhofer Institute for Solar Energy Systems.
• Agora Energiewende. (2025). E-fuels: Opportunities, Costs, and Sustainability Constraints in the European Energy Transition. Berlin: Agora Energiewende.
• European Commission. (2023). Delegated Acts on Renewable Hydrogen Definition: Additionality, Temporal Correlation, and Geographic Correlation. Brussels: European Commission.
• Port of Rotterdam Authority. (2025). Hydrogen Hub Rotterdam: Infrastructure Development Progress Report. Rotterdam: Port of Rotterdam Authority.
• DNV. (2025). Energy Transition Outlook: Hydrogen and Derivatives Market Assessment. Hovik, Norway: DNV AS.