Sustainability Atlas
Clean Energy·14 min read··...

Interview: the builder's playbook for Hydrogen & e-fuels — hard-earned lessons

A practitioner conversation: what surprised them, what failed, and what they'd do differently. Focus on LCOH drivers, offtake contracts, and infrastructure bottlenecks.

The hydrogen sector experienced a stark reality check in 2024-2025: potential 2030 production capacity dropped from 49 Mt/year to 37 Mt/year—a 25% contraction—as project cancellations swept across Europe, Australia, and North America. New offtake agreements fell from 2.4 Mt/year in 2023 to just 1.7 Mt/year in 2024, exposing the fragility of projects announced during the hype cycle of 2020-2023. Yet amid this correction, practitioners who secured binding agreements, co-located with industrial demand, and negotiated realistic pricing are advancing toward final investment decisions. We spoke with project developers, infrastructure specialists, and investors across Europe and the United States to extract the hard-earned lessons shaping the next wave of hydrogen and e-fuels deployment.

Why It Matters

Hydrogen and synthetic fuels represent the decarbonisation pathway for sectors that cannot electrify: steel production (7% of global emissions), ammonia synthesis (1.8% of global CO₂), maritime shipping, and long-haul aviation. The IEA estimates that achieving net-zero by 2050 requires 150 Mt/year of low-emissions hydrogen production—yet current output stands at less than 1 Mt/year, representing under 1% of global hydrogen supply.

For European investors, the stakes are particularly acute. The EU has committed to 10 million tonnes of domestic green hydrogen production plus 10 million tonnes of imports by 2030, backed by €992 million in EU Innovation Fund grants announced in May 2025 for 15 hydrogen projects across 5 countries. The H2med corridor—a €6 billion cross-border pipeline connecting Iberian solar resources to Central European industrial demand—received Project of Common Interest status in 2024, signalling regulatory commitment.

The e-fuels market reached $8.75 billion in 2024 and is projected to grow to $87.92 billion by 2032 at a 33.33% CAGR, driven by EU mandates requiring 2% sustainable aviation fuel by 2025 scaling to 70% by 2050. For hard-to-abate sectors, hydrogen derivatives are not optional—they are the only viable pathway to regulatory compliance.

The question facing practitioners is not whether hydrogen will scale, but which projects will survive the current correction and capture value as infrastructure matures.

Key Concepts

Levelized Cost of Hydrogen (LCOH)

LCOH represents the total cost of producing hydrogen per kilogram, encompassing capital expenditure, operating costs, feedstock, and financing. Green hydrogen from electrolysis currently ranges from $3.00-8.00/kg globally, with optimised solar-driven projects in Australia and the Middle East achieving $2.00-3.50/kg. The US Gulf Coast reported alkaline electrolysis at $2.30/kg in January 2025 following IRA 45V tax credit implementation.

Electricity costs dominate LCOH, representing 57-87% of total production costs across all electrolyser technologies. This explains why project success correlates strongly with access to low-cost, high-capacity-factor renewable electricity—and why projects without dedicated renewable supply face existential cost challenges.

Offtake Agreements

Offtake agreements are legally binding contracts between hydrogen producers and industrial buyers that guarantee purchase volumes and pricing over 15-20 year periods. Without secured offtake, projects cannot achieve financing close. As of September 2024, only 8.3 Mt/year of production capacity had any form of contracted demand—representing just 6% of total announced projects. More critically, only 13% of that contracted volume (1 Mt/year) consists of binding agreements rather than non-binding memoranda of understanding.

The offtake crisis reflects a structural chicken-or-egg problem: developers need buyers to secure financing, but buyers hesitate without infrastructure and transparent pricing. Successful projects are increasingly structured around industrial clusters where producer and offtaker share project equity and development risk.

Infrastructure Bottlenecks

Hydrogen infrastructure lags catastrophically behind production ambitions. Of the 37,000 km of pipelines announced through 2035, only 6% have reached final investment decision. Underground storage capacity stands at 11 TWh announced by 2035—representing just 5% of the 230 TWh required under IEA Net Zero Emissions scenarios. Germany began repurposing 400 km of natural gas pipeline for hydrogen transport in 2025, representing the world's first large-scale conversion—but deployment timelines remain measured in decades rather than years.

What's Working

Industrial Cluster Co-location

Projects that integrate hydrogen production with immediate industrial demand are advancing while standalone production facilities stall. Shell's Holland Hydrogen I in Rotterdam—Europe's largest operational electrolyser at 200 MW—achieved commissioning in 2025 by supplying 21,900 tonnes per year directly to Shell's refinery, eliminating transport infrastructure dependencies. The project secured €150 million in EU funding by demonstrating a captive offtake pathway.

Similarly, CF Industries' green ammonia facility in Louisiana targets 20,000 tonnes per year using ThyssenKrupp Nucera electrolysers. The project secures offtake by integrating with existing ammonia distribution networks rather than requiring new hydrogen-specific infrastructure. Practitioners emphasise that co-location reduces not just transport costs but permitting complexity and financing risk.

Binding Offtake with Price Certainty

Projects with binding agreements are weathering the correction. Lhyfe signed a five-year offtake agreement with H2 MOBILITY Deutschland in September 2024, guaranteeing renewable hydrogen supply to four fuel stations in Germany from its Schwäbisch Gmünd production site. The contract provides Lhyfe with revenue certainty enabling continued development while giving H2 MOBILITY supply security.

In January 2025, Provaris Energy, Norwegian Hydrogen, and Uniper Global Commodities executed a conditional term sheet for 42,500 tonnes per year of RFNBO-certified green hydrogen, with transport via Provaris' H2Neo compressed carriers. The structure—linking producer, logistics provider, and commodity trader—demonstrates how vertical integration de-risks project execution.

Ammonia and Methanol as Hydrogen Vectors

Rather than transporting pure hydrogen, successful projects are converting to ammonia or methanol for easier storage and shipping. Hapag-Lloyd and Goldwind signed a long-term offtake agreement in December 2024 for 250,000 tonnes per year of green methanol, enabling Hapag-Lloyd to fuel its dual-fuel container vessels without hydrogen infrastructure investments. The e-methanol pathway leverages existing chemical handling infrastructure at the 80+ ports worldwide already equipped for ammonia and methanol bunkering.

HIF Matagorda in Texas—a $6 billion facility with 1.8 GW electrolyser capacity—targets 1.4 million tonnes of e-methanol per year using 2 million tonnes of captured CO₂. Construction began in 2024 with operations planned for 2027. By producing e-methanol rather than hydrogen, the project accesses established commodity markets while avoiding nascent hydrogen infrastructure.

What's Not Working

Standalone Production Without Offtake

The 2024-2025 cancellation wave demonstrates that production capacity without guaranteed buyers is stranded investment. Shell cancelled its Norway west coast hydrogen plant in September 2024, citing "lack of demand." Days later, Equinor abandoned a similar project. Ørsted's FlagshipONE—a 50,000 tonnes per year e-methanol facility in Sweden—was cancelled despite being under construction after 2023 final investment decision.

ArcelorMittal shelved its €2.5 billion plan to convert two German steel plants to hydrogen-based production in June 2025, rejecting €1.3 billion in government subsidies because offtake economics remained unviable. The lesson: subsidy cannot substitute for market demand.

Geographic Mismatch Between Production and Demand

Projects planned in regions with excellent renewable resources but distant from industrial demand face infrastructure costs that destroy project economics. Australia exemplifies this challenge: Queensland's A$12.5 billion liquefied hydrogen export plant lost funding in 2025 when investors Kansai Electric and Iwatani withdrew. Trafigura abandoned its A$750 million Port Pirie facility in March 2025. Woodside shelved two Australian projects in September 2024.

The fundamental issue: hydrogen's low energy density makes long-distance transport economically punishing. Until pipeline and shipping infrastructure matures, production must locate near consumption—not near the cheapest electricity.

Regulatory Uncertainty on Credits and Additionality

US 45V tax credit rules—finalised in December 2024—imposed strict additionality requirements that disqualified hydroelectric power. Air Products cancelled its Massena, New York green hydrogen facility in February 2025 after learning its hydro-powered production would not qualify for the $3/kg tax credit. The regulatory surprise stranded completed development work.

European additionality and temporal correlation requirements similarly constrain project structures. Certification standards for RFNBO (Renewable Fuels of Non-Biological Origin) remain inconsistent across jurisdictions, creating compliance risk that freezes investment decisions.

Pipeline and Storage Infrastructure Lag

China operates 3.5 GW of electrolysis capacity—70% of global deployment—but has only 100 km of hydrogen pipelines operational. Transport and storage bottlenecks limit how much production can reach industrial consumers. In Europe, 94% of announced pipeline projects lack final investment decision. Underground storage projects—essential for managing renewable intermittency—cover just 5% of Net Zero requirements.

The infrastructure gap represents a decade-long buildout that cannot be accelerated through production subsidies alone. Projects that assumed infrastructure would follow production are discovering that pipeline permitting and construction timelines extend beyond typical project financing horizons.

Key Players

Established Leaders

  • HYBRIT (SSAB/LKAB/Vattenfall) — Swedish consortium producing hydrogen-reduced iron at industrial demonstration scale. Over 5,000 tonnes of fossil-free sponge iron delivered to Volvo, Epiroc, and GE Vernova. Commercial plant targeting 1.2 Mt/year by 2026.
  • Shell — Operating Holland Hydrogen I (200 MW) in Rotterdam. REFHYNE II (100 MW) in Germany reaching operations 2027. Leading electrolysis deployment in integrated refinery environments.
  • Air Liquide — Global hydrogen infrastructure operator with 50+ years of industrial gas experience. Developing large-scale electrolysis projects across Europe and North America with integrated distribution networks.
  • Linde — Major industrial gas supplier expanding green hydrogen production. Partnership with ITM Power on electrolyser deployment. Strong position in hydrogen logistics and storage.

Emerging Startups

  • H2 Green Steel — Building fossil-free steel plant in Sweden with €750 million EIB funding. Production targeting 2025-2026, scaling to 5 million tonnes annual capacity by 2030.
  • Lhyfe — European green hydrogen producer with operational sites in France and Germany. Pioneering offshore electrolysis and securing multi-year industrial offtake agreements.
  • P2X Solutions — Finnish Power-to-X developer with 20 MW electrolyser operational in 2024, targeting 1 GW green hydrogen by 2031. Received €50 million EU Innovation Fund grant in October 2024.
  • HIF Global — Developing e-fuels facilities globally. HIF Matagorda ($6 billion, 1.8 GW) represents largest e-methanol project under development.

Key Investors & Funders

  • EU Innovation Fund — €992 million allocated in May 2025 for 15 hydrogen projects across 5 countries, generating 2.2 Mt hydrogen over 10 years.
  • European Investment Bank — €750 million commitment to H2 Green Steel. Strategic financing for hydrogen infrastructure across EU member states.
  • US DOE Hydrogen Hubs Program — $8 billion allocated for seven regional hydrogen hubs including ARCHES (California, $12.6 billion total investment) signed July 2024.
  • Breakthrough Energy Ventures — Backing hydrogen and e-fuels technology providers including electrolyser manufacturers and carbon capture integration.

Action Checklist

  1. Secure binding offtake before production investment: Prioritise projects with signed purchase agreements from creditworthy industrial counterparties. Non-binding MoUs do not provide financing certainty—target 15-20 year contracts with take-or-pay structures.

  2. Co-locate with industrial demand: Site production within industrial clusters to eliminate transport infrastructure dependencies. Refineries, ammonia plants, steel facilities, and chemical complexes provide immediate hydrogen consumption without pipeline buildout.

  3. Model full-stack LCOH including delivery: Production costs represent only part of delivered hydrogen economics. Include compression, liquefaction, transport, and storage in financial models. Projects achieving $3/kg production may face $8-10/kg delivered costs without infrastructure.

  4. Verify regulatory eligibility before development spend: Confirm tax credit qualification (IRA 45V), RFNBO certification requirements, and additionality standards before committing capital. Regulatory interpretation has stranded multiple projects mid-development.

  5. Consider hydrogen derivatives for export: Ammonia and methanol leverage existing commodity infrastructure while avoiding nascent hydrogen transport challenges. Projects targeting export markets should evaluate conversion economics against pure hydrogen logistics.

  6. Partner with midstream infrastructure developers: Pipeline, storage, and port infrastructure represent the critical path constraint. Equity partnerships with infrastructure developers align incentives and reduce single-project financing burden.

  7. Structure for policy risk allocation: Include change-in-law provisions in offtake contracts specifying who bears regulatory risk. Back-to-back contract structures with power purchase agreements provide additional protection.

  8. Track electrolyser cost trajectories: Current electrolysis CAPEX exceeds $2,000/kW but could decline 60% over the next decade with manufacturing scale. Project economics should stress-test against falling replacement costs and potential technology obsolescence.

FAQ

Q: What LCOH must green hydrogen achieve to compete with grey hydrogen without subsidies? A: Grey hydrogen from unabated steam methane reforming costs $1.50-2.50/kg depending on natural gas prices. Green hydrogen must reach approximately $2.00/kg to achieve unsubsidised competitiveness. Currently, the most cost-effective green hydrogen projects in Australia and the Middle East achieve $2.00-3.50/kg—approaching parity but typically requiring policy support. The US DOE Hydrogen Shot targets $1.00/kg by 2031 through manufacturing scale and technology improvements. For European projects, the cost gap remains wider at $3.00-5.50/kg, making subsidies essential for near-term viability. The key variable is electricity cost: reducing renewable electricity prices to $20-30/MWh and improving electrolyser utilisation to 70%+ capacity factors are the primary pathways to cost parity.

Q: Why have so many hydrogen projects been cancelled despite billions in government subsidies? A: Subsidies reduce production costs but do not create demand. The cancellation wave of 2024-2025—including ArcelorMittal's rejection of €1.3 billion in German government support—reflects a fundamental market development failure: projects were sized for demand that does not yet exist. Traditional hydrogen consumers (refineries, ammonia plants) are not scaling adoption because low-emissions hydrogen remains more expensive than fossil alternatives even with subsidies. New demand applications (steel, shipping, aviation) require infrastructure that will take a decade to build. The correction is forcing projects to secure binding offtake before production investment—a sequencing that subsidies alone cannot substitute. Projects that survived are those with guaranteed industrial buyers, not those with the largest production ambitions.

Q: How should investors evaluate hydrogen project risk in the current market environment? A: Focus on three indicators: binding offtake coverage, infrastructure dependency, and regulatory qualification certainty. Projects with less than 50% of capacity under binding purchase agreements face material execution risk. Projects requiring significant new pipeline or storage infrastructure before revenue generation extend financing timelines beyond typical project debt structures. Projects assuming tax credit or subsidy eligibility without formal confirmation risk Air Products-style cancellations. The safest investments are industrial cluster projects with captive offtake, proven electrolyser technology, and grandfathered regulatory qualification. Export-oriented projects targeting markets without domestic hydrogen infrastructure carry the highest risk until international shipping and terminal infrastructure matures—likely post-2030 for meaningful scale.

Q: When will hydrogen infrastructure catch up to production capacity? A: Infrastructure buildout operates on 10-15 year cycles that cannot be accelerated through production subsidies. Only 6% of the 37,000 km of announced pipelines through 2035 have reached final investment decision. Underground storage projects cover 5% of Net Zero requirements. Germany's 400 km pipeline conversion in 2025 represents the first large-scale hydrogen-ready infrastructure in Europe. Realistic timelines suggest material cross-border hydrogen pipeline capacity by 2030-2032, with storage adequacy by 2035 at earliest. Projects planning production before infrastructure availability must either co-locate with industrial demand or produce hydrogen derivatives (ammonia, methanol) that leverage existing commodity logistics. The infrastructure constraint—not production technology—will pace hydrogen economy development through the 2030s.

Sources

The hydrogen and e-fuels sector has entered a necessary maturation phase. The practitioners advancing projects today are those who treated offtake as the first step rather than an afterthought, who co-located with industrial demand rather than chasing the cheapest electrons, and who modelled delivered costs rather than production economics alone. The $8 billion investment expected in 2025 will flow to projects meeting these criteria—not to capacity announcements without commercial foundations. For investors navigating this correction, the hard-earned lesson is clear: hydrogen project success is measured in binding contracts and infrastructure access, not megawatt announcements.

Topics

hydrogenfuelsVPPcurtailmentHVDCopexpermitting

Related Articles