Trend analysis: Hydrogen & e‑fuels — where the value pools are (and who captures them)

Global investment in clean hydrogen and e-fuels surpassed $45 billion in announced project capacity in 2025 alone, yet less than 4% of those projects reached final investment decision. The hydrogen economy is generating enormous capital commitments on paper while the actual value pools remain concentrated in a handful of segments where economics, policy, and demand intersect. Understanding where returns actually materialize separates strategic positioning from stranded capital.

Why It Matters

Hydrogen and e-fuels sit at the center of the hardest decarbonization challenges: heavy industry, long-haul shipping, aviation, and high-temperature heat. These sectors account for roughly 30% of global CO2 emissions and lack viable direct electrification pathways. The International Energy Agency projects that clean hydrogen production must reach 150 million tonnes annually by 2050 to meet net-zero targets, up from approximately 1 million tonnes of low-carbon hydrogen produced today. Governments have responded with over $280 billion in cumulative policy support across the US Inflation Reduction Act, the EU Hydrogen Strategy, Japan's Green Transformation program, and India's National Green Hydrogen Mission. For corporates, the question is not whether hydrogen will play a role in the energy transition but which segments of the value chain will generate sustainable returns versus absorb subsidies indefinitely. The gap between announced capacity and operational projects signals that capital allocation discipline will determine winners and losers over the next decade.

Key Concepts

Green hydrogen is produced through electrolysis powered by renewable electricity, splitting water into hydrogen and oxygen with zero direct emissions. Production costs have fallen from $6-8 per kilogram in 2020 to $3.50-5.50 per kilogram in 2025, with projections of $1.50-2.50 per kilogram by 2030 in regions with abundant low-cost renewables.

E-fuels (electrofuels or synthetic fuels) are produced by combining green hydrogen with captured CO2 to create liquid hydrocarbons such as e-methanol, e-kerosene, and e-diesel. These drop-in fuels can use existing infrastructure but carry a significant energy penalty: converting electricity to hydrogen to synthetic fuel typically loses 50-70% of the original energy input.

Electrolyzer technology encompasses the core hardware for hydrogen production. Three main types compete: alkaline electrolysis (mature, lower cost), proton exchange membrane or PEM (flexible, faster response), and solid oxide electrolysis cells or SOEC (highest efficiency, earliest commercial stage). Electrolyzer manufacturing capacity is scaling rapidly, with over 45 GW of annual production capacity announced globally.

KPI	Current Benchmark	Leading Practice	Laggard Threshold
Green hydrogen levelized cost ($/kg)	$3.50-5.50	<$2.50	>$7.00
Electrolyzer capacity factor	35-50%	>65%	<25%
E-fuel production cost ($/liter diesel equivalent)	$3.00-5.00	<$2.00	>$6.00
Project FID conversion rate	3-5% of announced	>15%	<2%
Offtake agreement coverage (% of planned output)	20-35%	>60%	<10%
Renewable electricity cost for electrolysis ($/MWh)	$25-45	<$20	>$60

What's Working

Industrial hydrogen hubs with captive demand. The most bankable hydrogen projects are those co-located with existing industrial consumers: refineries, ammonia plants, steel mills, and chemical complexes. NEOM's Helios Green Fuels project in Saudi Arabia secured a $8.4 billion investment to produce 600 tonnes of green hydrogen daily, converted to green ammonia for export. The project benefits from some of the world's lowest renewable energy costs (below $15/MWh), a committed offtake with Air Products, and proximity to export terminals. Similarly, the HyDeal Ambition consortium in Europe has aggregated demand from ArcelorMittal, Engie, and other industrial buyers to underpin a 67 GW pipeline of solar-powered electrolysis across Spain, France, and Germany. These hub models reduce offtake risk and enable shared infrastructure costs.

Policy-driven demand mandates in aviation and shipping. The EU's ReFuelEU Aviation regulation mandates that 1.2% of jet fuel must be synthetic (e-kerosene) by 2030, rising to 35% by 2050. FuelEU Maritime imposes greenhouse gas intensity reduction targets on shipping fuels starting in 2025. These mandates create guaranteed demand floors that de-risk production investments. Maersk has ordered 19 methanol-capable container vessels, creating a multi-billion-dollar demand signal for green methanol producers. The International Maritime Organization's revised greenhouse gas strategy targeting net-zero by 2050 further strengthens the regulatory tailwind for alternative maritime fuels.

Electrolyzer cost reduction through manufacturing scale. Chinese electrolyzer manufacturers, led by LONGi Hydrogen, Peric, and Sungrow, have driven alkaline electrolyzer costs below $300 per kilowatt, roughly one-third the cost of Western equivalents. This cost compression is enabling projects in the Middle East, North Africa, and Latin America that were previously uneconomic. ITM Power and Nel Hydrogen are scaling gigafactory production in the UK and Norway respectively, targeting PEM electrolyzer costs below $400 per kilowatt by 2027. The manufacturing scale-up mirrors the trajectory of solar panel cost reductions in the 2010s.

What's Not Working

Hydrogen transport and storage infrastructure gaps. Producing cheap hydrogen is only half the challenge. Moving it to end users remains prohibitively expensive for most applications. Compressed hydrogen trucking costs $2-4 per kilogram for distances over 300 kilometers, potentially doubling the delivered cost. Pipeline infrastructure requires massive upfront capital ($1-3 million per kilometer for new builds), and repurposing existing natural gas pipelines faces technical and regulatory hurdles. Liquefied hydrogen loses 25-35% of its energy content during the liquefaction process. These logistics constraints mean that hydrogen economics are fundamentally local, and projects without nearby demand face structural cost disadvantages.

E-fuel cost premiums remain extreme. Despite policy mandates, e-fuels cost 3-5 times more than fossil equivalents. E-kerosene production costs of $3-5 per liter compare unfavorably with conventional jet fuel at $0.60-0.90 per liter. The energy conversion losses inherent in the power-to-liquid pathway mean that e-fuels will likely remain a premium product for hard-to-abate applications rather than a mass-market substitute. Projects banking on rapid cost parity with fossil fuels are building on optimistic assumptions that may not materialize within their financing windows.

Overcrowded project pipelines with insufficient offtake. The Hydrogen Council reports over 1,400 large-scale hydrogen projects announced globally, but binding offtake agreements cover less than 20% of planned capacity. Many projects are competing for the same limited pools of policy incentives and early-adopter customers. In Europe, electrolyzer deployment reached only 300 MW cumulative by end of 2025 against a target of 6 GW by 2024 under the original REPowerEU plan. The gap between ambition and execution suggests that a significant shakeout of announced projects is inevitable, with capital concentrating in the most cost-advantaged locations.

Key Players

Established Leaders

• Air Liquide: Operates over 50 hydrogen production facilities worldwide. Committed 8 billion euros to low-carbon hydrogen investments through 2035, with projects spanning electrolysis, blue hydrogen with CCS, and hydrogen distribution.
• Linde: World's largest industrial gas company with extensive hydrogen infrastructure across refining and chemical sectors. Developing green hydrogen projects in Germany, Australia, and the United States.
• Air Products: Leading merchant hydrogen producer. Committed over $15 billion to clean hydrogen mega-projects including NEOM and a Louisiana blue hydrogen complex.
• Siemens Energy: Major electrolyzer manufacturer with PEM technology. Building a gigawatt-scale electrolyzer factory in Berlin targeting annual output of 1 GW.

Emerging Startups

• Electric Hydrogen: Backed by Breakthrough Energy Ventures, developing high-efficiency PEM electrolyzers optimized for continuous industrial operation at costs targeting sub-$2/kg hydrogen.
• Infinium: Produces e-fuels from green hydrogen and captured CO2 for aviation and heavy transport. Secured offtake agreements with Amazon and American Airlines.
• HIF Global: Developing the Haru Oni e-fuels plant in Chile using wind-powered electrolysis, with backing from Porsche and ExxonMobil for synthetic gasoline production.
• Fortescue Future Industries: Subsidiary of mining giant Fortescue, pursuing green hydrogen production at scale across Australia, Brazil, Kenya, and Norway with a target of 15 million tonnes annually by 2030.

Key Investors and Funders

• Breakthrough Energy Ventures: Bill Gates-backed fund investing across the hydrogen value chain, including electrolyzers, storage, and end-use applications.
• Hy24: World's largest clean hydrogen infrastructure fund at 2 billion euros, backed by Air Liquide, TotalEnergies, and VINCI and targeting projects from production through distribution.
• US Department of Energy: Allocated $7 billion for Regional Clean Hydrogen Hubs, selecting seven hubs across the United States to demonstrate integrated hydrogen ecosystems.

Where the Value Pools Are

Electrolyzer manufacturing and technology licensing. The global electrolyzer market is projected to reach $35 billion annually by 2030. Companies that achieve manufacturing scale, drive down unit costs, and secure long-term supply agreements with project developers will capture recurring hardware revenue. The technology licensing model, where manufacturers provide stack designs and process know-how to regional partners, offers high-margin revenue without capital-intensive factory buildouts.

Industrial decarbonization offtake aggregation. The highest-value commercial position in hydrogen is not production but demand aggregation. Companies that secure binding offtake contracts from steel, ammonia, and refining customers and then procure supply from the lowest-cost producers earn intermediation margins while bearing minimal production risk. This model mirrors the power purchase agreement market in renewables, where energy traders and aggregators captured significant value.

Hydrogen derivatives for export markets. Green ammonia and green methanol serve as hydrogen carriers that solve the transport problem by leveraging existing commodity shipping infrastructure. The green ammonia market alone is projected to reach $18 billion by 2030, driven by fertilizer decarbonization and maritime fuel demand. Producers in cost-advantaged regions (Australia, Chile, Middle East, North Africa) with port access are best positioned to serve import-dependent markets in Japan, South Korea, and Northern Europe.

Infrastructure and midstream services. As production scales, the constraint shifts to transport, storage, and distribution. Companies building hydrogen pipeline networks, storage caverns (salt caverns offer the lowest-cost bulk storage at $0.10-0.30 per kilogram), and refueling stations capture toll-road economics with long-duration revenue visibility. European gas transmission operators including Snam, Gasunie, and Fluxys are investing billions in hydrogen backbone pipeline networks.

Action Checklist

• Map your organization's hard-to-abate energy consumption to identify where hydrogen or e-fuels could displace fossil inputs
• Evaluate proximity to planned hydrogen hubs and pipeline infrastructure when assessing project viability
• Secure binding offtake agreements or join demand aggregation consortia before committing production capital
• Benchmark electrolyzer technology choices against your operating profile: alkaline for baseload, PEM for variable renewable integration, SOEC for waste heat recovery applications
• Track policy developments across the IRA Section 45V production tax credit, EU hydrogen bank auctions, and national hydrogen strategies in target markets
• Stress-test project economics against realistic capacity factors, delivered hydrogen costs (not production-gate costs), and offtake price escalation mechanisms
• Assess e-fuel investments against sector-specific mandate timelines rather than cost parity assumptions

FAQ

What is the realistic timeline for green hydrogen cost competitiveness? In regions with the best renewable resources (Middle East, Chile, Australia, parts of North Africa), green hydrogen costs are projected to fall below $2 per kilogram by 2028-2030. In Europe and most of North America, costs will likely remain in the $3-4 per kilogram range through 2030 without substantial subsidy support. The US 45V production tax credit of up to $3 per kilogram effectively closes this gap for qualifying projects, making subsidy architecture as important as underlying economics.

Which hydrogen color wins in the long run? Green hydrogen (electrolysis plus renewables) has the strongest long-term trajectory due to declining renewable electricity costs and zero upstream emissions. Blue hydrogen (natural gas reforming plus carbon capture) fills a transitional role where natural gas is cheap and CCS infrastructure exists, but faces methane leakage scrutiny and long-term carbon lock-in risk. The real competition is less about color and more about delivered cost and carbon intensity at the point of use.

Are e-fuels a viable mass-market energy source? No. E-fuels will remain a premium decarbonization pathway for applications where direct electrification and batteries are physically impractical: long-haul aviation, deep-sea shipping, and legacy vehicle fleets. The 50-70% energy conversion loss makes e-fuels inherently more expensive per unit of useful energy than direct electricity use. Policy mandates, not cost competitiveness, will drive e-fuel adoption in the foreseeable future.

How should investors evaluate hydrogen project risk? Focus on three factors: offtake security (what percentage of output has binding purchase agreements), renewable electricity cost and availability (the single largest input cost), and infrastructure proximity (distance to end users and export terminals). Projects with all three aligned represent the lowest risk. Projects relying on speculative future demand or distant infrastructure buildout carry significantly higher execution risk.

What role does China play in the hydrogen economy? China is simultaneously the world's largest hydrogen producer (approximately 33 million tonnes annually, mostly grey), the lowest-cost electrolyzer manufacturer, and the most aggressive deployer of fuel cell vehicles (over 18,000 on the road by 2025). Chinese electrolyzer exports are reshaping global project economics by compressing hardware costs, similar to the role Chinese solar panel manufacturing played in driving down solar electricity costs globally.

Sources

1. International Energy Agency. "Global Hydrogen Review 2025." IEA, 2025.
2. Hydrogen Council and McKinsey & Company. "Hydrogen Insights 2025: An Updated Perspective on Hydrogen Investment, Deployment, and Cost Competitiveness." 2025.
3. BloombergNEF. "Hydrogen Economy Outlook: Annual Update." BNEF, 2025.
4. European Commission. "ReFuelEU Aviation: Regulation on Sustainable Aviation Fuels." Official Journal of the European Union, 2023.
5. US Department of Energy. "Regional Clean Hydrogen Hubs: Selection and Progress Report." DOE, 2025.
6. Carbon Tracker Initiative. "The Hydrogen Ladder: Prioritising Hydrogen Applications for Decarbonisation." Carbon Tracker, 2024.
7. International Renewable Energy Agency. "Green Hydrogen Cost Reduction: Scaling Up Electrolysers." IRENA, 2024.