Deep dive: Hydrogen & e‑fuels — what's working, what's not, and what's next

Global electrolyzer capacity reached 2.1 GW by the end of 2025, a threefold increase from 2023, yet that figure represents less than 1% of the installed capacity needed to meet net-zero hydrogen demand by 2050, according to the International Energy Agency's 2025 Global Hydrogen Review. Meanwhile, the first commercial-scale e-fuel plants are moving from pilot to production, with HIF Global's Haru Oni facility in Chile shipping its initial batches of synthetic gasoline and Atmosfair delivering e-kerosene to Lufthansa. The hydrogen and e-fuels sector is at a pivotal inflection point: proven at demonstration scale, backed by unprecedented policy support, but still facing cost curves, infrastructure gaps, and offtake uncertainties that will determine which projects survive the transition from subsidy-dependent pioneers to commercially viable operations.

Why It Matters

Hydrogen and e-fuels address emissions in sectors where direct electrification is technically or economically impractical. Heavy industry (steel, ammonia, refining), long-haul shipping, aviation, and seasonal energy storage collectively account for roughly 30% of global CO2 emissions. The IEA estimates that clean hydrogen must scale from approximately 1 million tonnes per year of low-carbon production in 2025 to 150 million tonnes per year by 2050 to align with net-zero pathways (IEA, 2025).

For procurement teams in emerging markets, the stakes are particularly high. Countries including India, Brazil, Chile, Morocco, and Namibia have positioned themselves as future green hydrogen exporters, leveraging abundant renewable energy resources to produce hydrogen at costs potentially 30 to 50% below European or East Asian production. India's National Green Hydrogen Mission targets 5 million tonnes per year of production capacity by 2030, backed by $2.3 billion in government incentives. Chile's national strategy aims to capture 4 to 6% of the global hydrogen export market by 2040. Procurement professionals operating in these markets face decisions today on electrolyzer sourcing, water supply agreements, and offtake structures that will lock in costs and risks for decades.

Key Concepts

Green hydrogen is produced through water electrolysis powered by renewable electricity. Alkaline electrolyzers (AEL) and proton exchange membrane (PEM) electrolyzers dominate the market, with solid oxide electrolyzer cells (SOEC) emerging as a high-efficiency alternative for applications with available waste heat.

E-fuels (electrofuels or synthetic fuels) combine green hydrogen with captured CO2 through Fischer-Tropsch synthesis or methanol-to-gasoline pathways to produce drop-in liquid fuels. E-kerosene (synthetic aviation fuel) and e-methanol (for shipping) are the two primary product categories attracting commercial investment.

Levelized cost of hydrogen (LCOH) measures the all-in production cost per kilogram, incorporating capital expenditure, electricity costs, water, operations, and financing. Green hydrogen LCOH in 2025 ranges from $3.50 to $7.00 per kg in most markets, compared to $1.00 to $1.80 per kg for grey hydrogen from unabated natural gas reforming.

Additionality refers to the requirement that renewable electricity used for hydrogen production comes from new generation capacity rather than diverting existing clean power from the grid. The EU Delegated Act on renewable hydrogen defines additionality, temporal correlation, and geographic correlation requirements that shape project economics across emerging markets seeking to export to European buyers.

Metric	2023 Baseline	2025 Actual	2030 Target
Global electrolyzer capacity (GW)	0.7	2.1	134
Green hydrogen LCOH ($/kg)	$5.00-$9.00	$3.50-$7.00	$1.50-$3.00
E-kerosene production (tonnes/yr)	<500	~5,000	500,000+
Announced hydrogen projects globally	680	1,400+	N/A
Final investment decisions taken (%)	~8%	~12%	N/A

What's Working

Electrolyzer Cost Reductions Are Accelerating

Electrolyzer manufacturing costs have declined faster than most analysts projected. PEM electrolyzer stack costs fell from approximately $1,400 per kW in 2022 to $700 to $900 per kW in 2025, driven by manufacturing scale-up and standardized designs. Plug Power's gigafactory in Rochester, New York, reached 2.5 GW per year of manufacturing capacity in 2025. In China, manufacturers including LONGi Hydrogen and Sungrow have pushed alkaline electrolyzer system costs below $300 per kW, though questions remain about durability and performance guarantees at those price points (BloombergNEF, 2025).

NEOM Green Hydrogen Company's 2.2 GW project in Saudi Arabia, a joint venture between ACWA Power, Air Products, and NEOM, secured $8.4 billion in financing and began commissioning its first electrolyzer modules in late 2025. The project targets production of 600 tonnes per day of green ammonia for export, with delivered costs competitive with conventional grey ammonia in Asian markets by 2027. This represents the first truly gigascale green hydrogen project to move beyond announcement into physical construction and equipment installation.

Policy Frameworks Are Driving Demand Signals

The US Inflation Reduction Act's Section 45V production tax credit provides up to $3.00 per kg for the cleanest hydrogen, fundamentally altering project economics. The EU's REPowerEU plan targets 10 million tonnes of domestic green hydrogen production and 10 million tonnes of imports by 2030, backed by the European Hydrogen Bank's competitive auction mechanism that awarded its first round of contracts in 2024 at a weighted average subsidy of EUR 0.48 per kg. India's SIGHT (Strategic Interventions for Green Hydrogen Transition) program offers production-linked incentives of $0.60 to $0.70 per kg for the first three years of operation (Ministry of New and Renewable Energy, 2025).

These demand signals have been particularly effective in emerging markets. Morocco's OCP Group, the world's largest phosphate producer, is developing a 1 GW electrolyzer project to produce green ammonia for fertilizer manufacturing, replacing imported natural gas. Namibia's Hyphen Hydrogen Energy project secured development rights for a $10 billion, 3 GW wind and solar complex to produce green hydrogen and ammonia for export to Europe.

E-Fuels Are Reaching Commercial Milestones

HIF Global's Haru Oni facility in Magallanes, Chile, produced its first commercial batches of synthetic gasoline in 2024 using wind-powered electrolysis and direct air-captured CO2. While initial volumes are small (approximately 130,000 liters per year), the project has validated the full production chain from renewable electricity through electrolysis, CO2 capture, methanol synthesis, and methanol-to-gasoline conversion. HIF Global has announced plans to scale to 550 million liters per year at its planned facility in Matagorda, Texas (HIF Global, 2025).

In the aviation sector, Atmosfair's e-kerosene produced at its Werlte, Germany, facility has been blended into Lufthansa's fuel supply, marking the first commercial delivery of synthetic aviation fuel to a major airline. The EU's ReFuelEU Aviation regulation mandates 1.2% sustainable aviation fuel (SAF) blending by 2030, with a dedicated e-kerosene sub-mandate of 0.7% by 2030 rising to 35% by 2050, creating a guaranteed and growing market for e-fuel producers.

What's Not Working

Project Attrition Rates Are Alarming

Despite over 1,400 announced hydrogen projects globally, only 12% have reached final investment decision (FID), and project cancellation rates have accelerated. The Hydrogen Council's 2025 project tracker found that 18% of projects announced before 2024 have been cancelled or indefinitely postponed, with a further 25% experiencing delays of 12 months or more. Common causes include: inability to secure long-term offtake agreements at prices that support project economics, permitting delays (particularly for water abstraction in water-stressed emerging markets), grid connection timelines exceeding 3 to 5 years, and financing challenges as lenders demand risk-sharing structures that developers struggle to provide (Hydrogen Council, 2025).

Fortescue Future Industries (now Fortescue Energy) scaled back its green hydrogen ambitions significantly in 2024 and 2025, reducing its workforce and narrowing its project pipeline from dozens of global sites to a handful of priority locations. The company's experience illustrates the gap between corporate hydrogen announcements and commercially viable projects.

The Cost Gap Remains Wide

Green hydrogen at $3.50 to $7.00 per kg cannot compete with grey hydrogen at $1.00 to $1.80 per kg without subsidies. Even with the full $3.00 per kg US 45V credit, green hydrogen achieves cost parity only in locations with exceptional renewable resources (capacity factors above 45%) and low-cost electrolyzer procurement. For e-fuels, the economics are even more challenging: e-kerosene production costs of $3.00 to $6.00 per liter compare unfavorably with conventional jet fuel at $0.60 to $0.90 per liter. The conversion efficiency penalty is fundamental: producing e-fuels requires roughly 5 to 6 times more renewable electricity per unit of delivered energy than direct electrification, meaning e-fuels will always carry a structural cost premium (IRENA, 2025).

Water Scarcity Creates Real Constraints

Electrolysis requires approximately 9 liters of purified water per kilogram of hydrogen produced, and total water consumption including cooling and losses reaches 15 to 25 liters per kg. In water-stressed emerging markets where green hydrogen projects are concentrated due to favorable solar and wind resources, water sourcing is becoming a genuine constraint. Namibia's Hyphen project has faced community opposition over water allocation in a country where 40% of the population lacks reliable access to clean water. Australia's Pilbara region, targeted for multiple large-scale hydrogen projects, relies on desalination that adds $0.30 to $0.50 per kg to hydrogen production costs.

Infrastructure Gaps Block Scale

Transporting hydrogen from production sites to demand centers remains unsolved at scale. Pipeline conversion from natural gas to hydrogen service requires metallurgical assessment, re-certification, and in many cases replacement of compressor stations. Dedicated hydrogen pipelines cost $1.5 to $3.0 million per km. Liquefaction of hydrogen for shipping consumes 30 to 35% of the hydrogen's energy content, and only three purpose-built liquid hydrogen carriers exist globally. Ammonia conversion offers a more practical transport vector but adds $0.50 to $1.00 per kg equivalent hydrogen cost for conversion and reconversion losses.

Key Players

Established Companies

• Air Products: largest committed hydrogen infrastructure investor with $15 billion in announced projects including NEOM
• Linde: leading industrial gas company operating 200+ hydrogen production facilities globally
• ACWA Power: Saudi developer leading NEOM Green Hydrogen and multiple emerging market projects
• Siemens Energy: PEM electrolyzer manufacturer scaling production at its Berlin gigafactory
• Thyssenkrupp Nucera: alkaline electrolyzer supplier with 10+ GW of contracted capacity

Startups and Growth Companies

• Electric Hydrogen: US-based PEM electrolyzer developer targeting $2/kg green hydrogen by 2027
• HIF Global: e-fuels pioneer developing commercial-scale synthetic fuel plants in Chile and Texas
• Hyphen Hydrogen Energy: Namibia-focused green hydrogen and ammonia developer backed by ENERTRAG
• Sunfire: German SOEC electrolyzer developer achieving >80% electrical efficiency
• Infinium: e-fuels company producing synthetic diesel and jet fuel from captured CO2

Investors and Funders

• Breakthrough Energy Ventures: invested in multiple electrolyzer and e-fuel startups
• AP Moller Capital: backing green hydrogen shipping fuel projects
• Abu Dhabi Investment Authority (ADIA): anchor investor in NEOM and Middle Eastern hydrogen projects
• US Department of Energy: funding seven Regional Clean Hydrogen Hubs with $7 billion
• European Hydrogen Bank: competitive auction mechanism deploying EUR 800 million in first rounds

Action Checklist

• Map electrolyzer procurement options across AEL, PEM, and SOEC technologies, evaluating total cost of ownership including degradation rates and maintenance schedules
• Secure renewable electricity supply agreements with capacity factors above 40% and pricing below $25/MWh to achieve competitive hydrogen production costs
• Negotiate offtake agreements with creditworthy buyers for minimum 10-year terms, specifying pricing escalation mechanisms tied to reference indices
• Conduct water availability assessments for project sites in emerging markets, including community water needs and seasonal variability analysis
• Evaluate additionality, temporal correlation, and geographic correlation requirements under EU Delegated Act for any hydrogen intended for European export markets
• Develop transport and logistics strategies comparing pipeline, ammonia conversion, and compressed gas trucking for specific demand center distances
• Assess eligibility for production incentives including US 45V, EU Hydrogen Bank auctions, and host country incentive programs
• Engage local communities and water authorities early to address social license concerns before permitting applications

FAQ

Q: What is the realistic timeline for green hydrogen to reach cost parity with grey hydrogen without subsidies? A: Most credible analyses project unsubsidized cost parity in the $1.50 to $2.50 per kg range by 2030 to 2035 for locations with excellent renewable resources (solar irradiance above 2,000 kWh/m2/yr or wind capacity factors above 45%). This requires electrolyzer capital costs falling below $300 per kW at the system level, renewable electricity costs below $20 per MWh, and electrolyzer utilization rates above 4,000 full-load hours per year. BloombergNEF's 2025 New Energy Outlook estimates that 28 countries could produce green hydrogen below $2.00 per kg by 2030 under optimistic assumptions.

Q: Which emerging markets offer the best conditions for green hydrogen production and export? A: Chile (Atacama Desert solar, Patagonia wind), Morocco (solar and proximity to Europe), Namibia (combined solar and wind), Oman (solar and existing port infrastructure), and western Australia (combined resources and Asian market proximity) consistently rank highest. Key differentiators beyond renewable resource quality include: water availability, port access for ammonia or liquid hydrogen export, political stability, and clarity of regulatory frameworks including export certification standards.

Q: How should procurement teams evaluate e-fuel purchase agreements given current pricing uncertainty? A: Structure agreements with volume flexibility (take-or-pay at 60 to 70% of contracted volume with options on the remainder), price indexation to a combination of renewable electricity costs and carbon credit prices, and quality specifications aligned with ASTM D7566 for aviation fuel or ISO 8217 for marine fuel. Build in technology review clauses at 3 to 5 year intervals to capture cost reductions. Consider portfolio approaches that blend e-fuel purchases with conventional SAF (HEFA, alcohol-to-jet) to manage cost exposure while meeting regulatory blending mandates.

Q: What are the most critical risk factors for hydrogen projects in emerging markets? A: The top risk factors are: currency and sovereign risk affecting long-term offtake pricing (mitigated through USD-denominated contracts and export credit agency guarantees), water rights and community opposition, grid connection delays, regulatory uncertainty around hydrogen certification and export standards, and construction cost overruns in locations with limited heavy industrial contractor capacity. Projects that advance to FID typically have addressed at least four of these five risks through binding agreements or insurance mechanisms.

Sources

• International Energy Agency. (2025). Global Hydrogen Review 2025. Paris: IEA.
• BloombergNEF. (2025). Hydrogen Levelized Cost Update: 1H 2025. London: BNEF.
• Hydrogen Council and McKinsey & Company. (2025). Hydrogen Insights 2025: Global Project Tracker and Investment Update. Brussels: Hydrogen Council.
• International Renewable Energy Agency. (2025). Green Hydrogen for Industry: Cost and Market Outlook. Abu Dhabi: IRENA.
• HIF Global. (2025). Haru Oni Demonstration Plant: Commercial Operations Update. Santiago: HIF Global.
• Ministry of New and Renewable Energy, Government of India. (2025). National Green Hydrogen Mission: Progress Report and Incentive Framework. New Delhi: MNRE.
• European Commission. (2024). European Hydrogen Bank: First Auction Results and Market Analysis. Brussels: EC Directorate-General for Energy.
• US Department of Energy. (2025). Regional Clean Hydrogen Hubs: Selection and Implementation Update. Washington, DC: DOE Office of Clean Energy Demonstrations.