Case study: Hydrogen & e-fuels — a startup-to-enterprise scale story

Global investment in clean hydrogen reached $42 billion in 2025, a 35% increase over 2024, yet fewer than 15% of hydrogen startups that secured Series A funding between 2019 and 2023 have successfully transitioned from demonstration projects to commercial-scale operations delivering more than 10 tonnes of hydrogen per day (BloombergNEF, 2025). This case study traces three startups across the hydrogen and e-fuels value chain in the Asia-Pacific region that navigated the treacherous path from pilot to enterprise scale, revealing the financing structures, offtake strategies, and operational pivots that determined which companies survived the "valley of death" and which did not.

Why It Matters

The hydrogen economy is projected to account for 12% of global final energy demand by 2050, requiring cumulative investment of $15 trillion across production, transport, and end-use infrastructure (Hydrogen Council, 2025). In the Asia-Pacific region, government commitments have accelerated sharply: Japan's revised Green Growth Strategy targets 12 million tonnes of hydrogen supply by 2040, South Korea's Hydrogen Economy Roadmap allocates $40 billion in public and private investment through 2030, and Australia's National Hydrogen Strategy has designated seven hydrogen hubs for priority development with $2 billion in federal funding.

For procurement professionals sourcing clean energy solutions in Asia-Pacific, the critical question is not whether hydrogen and e-fuels will play a role in decarbonization but which supply pathways will reach commercial reliability within procurement planning horizons. The difference between a hydrogen supplier that can deliver consistent purity at contracted volumes and one that misses delivery targets by 30 to 50% during commissioning delays directly affects industrial operations, compliance timelines under emerging regulatory frameworks such as Japan's GX (Green Transformation) League and Australia's Safeguard Mechanism, and the financial viability of long-term fuel switching contracts.

Key Concepts

Green hydrogen is hydrogen produced through electrolysis of water powered by renewable electricity, resulting in near-zero production emissions. The dominant electrolyzer technologies are proton exchange membrane (PEM) and alkaline electrolysis, with PEM offering faster response times and higher purity output but at 20 to 40% higher capital cost per megawatt of installed capacity compared to alkaline systems.

E-fuels (electrofuels) are synthetic liquid or gaseous fuels produced by combining green hydrogen with captured CO2 through processes such as Fischer-Tropsch synthesis or methanol synthesis. E-fuels are chemically identical to conventional fossil fuels and can use existing storage, transport, and combustion infrastructure without modification.

Levelized cost of hydrogen (LCOH) represents the total lifecycle cost of producing hydrogen per kilogram, incorporating capital expenditure, operating costs, electricity costs, water treatment, and equipment replacement over the project lifetime. Green hydrogen LCOH in Asia-Pacific ranged from $3.50 to $7.00 per kilogram in 2025, compared to $1.00 to $2.00 for grey hydrogen from steam methane reforming (IRENA, 2025).

Offtake agreements are binding contracts between hydrogen producers and industrial buyers that guarantee purchase volumes, pricing mechanisms, and delivery schedules over multi-year periods. These agreements are the foundation of project finance for hydrogen facilities, as lenders require revenue certainty before committing capital for construction.

What's Working

Fortescue Future Industries: Mining Company Pivot to Green Hydrogen Production

Fortescue Future Industries (FFI), the clean energy subsidiary of Australian mining conglomerate Fortescue, represents the most capital-intensive startup-to-enterprise trajectory in Asia-Pacific hydrogen. Founded in 2020 with an initial $1 billion commitment from Fortescue's balance sheet, FFI leveraged the parent company's project execution expertise, land holdings, and access to low-cost renewable resources in Western Australia to bypass the typical venture capital constraints that limit hydrogen startups.

FFI's Gibson Island project in Queensland, initially a 36 MW electrolyzer facility producing green hydrogen for ammonia manufacturing, served as the company's commercial proof of concept. The project reached mechanical completion in late 2024 and began commissioning in early 2025, targeting production of 4.5 tonnes of green hydrogen per day. FFI structured the Gibson Island offtake as a 15-year agreement with Incitec Pivot, the facility's existing ammonia producer, at a price indexed to the Henry Hub natural gas price plus a green premium that starts at $1.20 per kilogram and declines by 3% annually as electrolyzer costs decrease (Fortescue, 2025).

The scaling lesson from FFI is the advantage of corporate venture structures over traditional venture capital for capital-intensive hydrogen projects. By accessing the parent company's balance sheet and credit rating, FFI secured project finance at 200 to 300 basis points below what a standalone hydrogen startup could obtain. However, this model depends on a deep-pocketed industrial sponsor willing to absorb 3 to 5 years of pre-revenue investment, making it difficult to replicate for independent startups.

JERA and IHI: E-Fuel Demonstration to Commercial Ammonia Co-firing

JERA, Japan's largest power generation company (a joint venture between Tokyo Electric Power and Chubu Electric Power), partnered with IHI Corporation to scale ammonia co-firing in coal power plants as a decarbonization pathway. While JERA is not a startup in the conventional sense, its ammonia co-firing program followed a classic startup scaling arc: a 4 MW demonstration at Hekinan Unit 4 in 2021 that burned a 20% ammonia blend, followed by a 1 GW commercial-scale retrofit completed in 2025 targeting 50% ammonia co-firing by 2028.

The procurement implications of JERA's trajectory are significant. The company signed offtake agreements totaling 2 million tonnes of ammonia per year by 2030, split between Saudi Aramco (blue ammonia from carbon-captured natural gas), CF Industries in the United States, and Yara International in Norway. These agreements established the first large-scale pricing benchmarks for fuel-grade ammonia in Asia-Pacific, with delivered costs ranging from $450 to $600 per tonne CIF Japan, equivalent to approximately $3.50 to $4.60 per kilogram of hydrogen equivalent energy content (JERA, 2025).

JERA's approach demonstrated that scaling hydrogen-derived fuels requires simultaneously building both supply and demand infrastructure. The company invested $500 million in Hekinan plant modifications while concurrently developing ammonia receiving terminals at three Japanese ports, creating the logistical infrastructure that independent ammonia suppliers lacked the capital to build independently.

Lhyfe: Offshore Electrolysis Pioneer Entering the Australian Market

Lhyfe, founded in France in 2017, became the first company to produce green hydrogen from offshore wind power through its Sealhyfe pilot platform in the Atlantic Ocean in 2022. The company's expansion into the Asia-Pacific market, specifically its partnership with the Port of Gladstone in Queensland announced in 2024, illustrates how European hydrogen technology startups are scaling through geographic diversification.

Lhyfe's Gladstone project, a 100 MW electrolyzer facility co-located with a planned 400 MW solar farm, targets production of 45 tonnes of green hydrogen per day, with first production scheduled for 2027. The project was structured as a joint venture with local partner Stanwell Corporation, with Lhyfe contributing electrolyzer technology and operational expertise while Stanwell provided renewable electricity offtake, site access, and regulatory navigation capabilities. Total project capital expenditure is estimated at $350 million, funded through a combination of equity ($120 million), concessional debt from Australia's Clean Energy Finance Corporation ($130 million), and commercial project finance ($100 million) (Lhyfe, 2025).

The critical scaling insight from Lhyfe's Asia-Pacific entry is the importance of local partnerships for market access. Despite having proven technology and operational track records in Europe, Lhyfe required a local partner with grid connections, water rights, and established regulatory relationships to navigate Queensland's environmental approvals process, which took 14 months compared to 6 months for similar projects in France.

What's Not Working

Electrolyzer delivery timelines remain a bottleneck across the Asia-Pacific hydrogen sector. Lead times for PEM electrolyzers from major manufacturers such as Plug Power, ITM Power, and Siemens Energy stretched to 18 to 24 months in 2025, up from 10 to 12 months in 2022. Several hydrogen projects in Australia, including at least two of the government-designated hydrogen hubs, experienced 6 to 12 month schedule delays due to electrolyzer procurement issues, pushing first production dates into 2027 or later (Clean Energy Council, 2025).

Water availability is an underappreciated constraint for green hydrogen production in arid regions of Australia and parts of India. Producing 1 kilogram of hydrogen through electrolysis requires 9 to 10 liters of purified water. At enterprise scale, a 100 MW electrolyzer facility consumes approximately 400,000 liters of water per day. In Western Australia, where several major hydrogen projects are planned, water licensing approvals have emerged as a permitting bottleneck, with applications requiring 8 to 15 months for environmental impact assessment and competing with agricultural and municipal water users.

Offtake price uncertainty deters long-term commitments from industrial buyers. Green hydrogen prices in Asia-Pacific vary by 40 to 60% depending on renewable electricity costs, electrolyzer utilization rates, and transport distances. Procurement teams at steel mills, chemical plants, and refineries report difficulty building internal business cases for hydrogen switching when the delivered cost could range from $4 to $8 per kilogram over a 10-year contract period. This uncertainty has led many potential buyers to sign memoranda of understanding rather than binding offtake agreements, providing insufficient revenue certainty for project financing.

E-fuel cost competitiveness remains distant for most transport applications. Synthetic e-kerosene for aviation costs $3,000 to $5,000 per tonne compared to $600 to $800 per tonne for conventional jet fuel, a 4x to 6x premium that current carbon pricing and regulatory mandates do not fully bridge. The EU's ReFuelEU Aviation mandate requires 2% sustainable aviation fuel by 2025 (rising to 6% by 2030), but Asia-Pacific jurisdictions have not yet implemented comparable blending obligations, limiting demand signals for regional e-fuel producers.

Key Players

Established Companies

• Fortescue Future Industries: Australian clean energy company developing green hydrogen production across Western Australia and Queensland with multi-gigawatt electrolyzer deployment targets
• JERA: Japan's largest power generation company pioneering commercial-scale ammonia co-firing in coal plants as a hydrogen-derived fuel pathway
• Stanwell Corporation: Queensland government-owned energy company partnering with international hydrogen developers on production and export facilities
• IHI Corporation: Japanese heavy industry manufacturer developing ammonia combustion technology for power generation and industrial heat applications

Startups

• Lhyfe: French green hydrogen producer expanding into Asia-Pacific with offshore and onshore electrolyzer projects, targeting 3 GW of installed capacity by 2030
• Hysata: Australian electrolyzer technology startup whose capillary-fed cell design achieves 95% system efficiency, reducing electricity consumption per kilogram of hydrogen by 20% versus conventional PEM systems
• HydrogenPro: Norwegian electrolyzer manufacturer with a production facility in Tianjin, China, supplying high-pressure alkaline electrolyzers to Asia-Pacific projects
• Sunfire: German electrolyzer company specializing in solid oxide electrolysis for high-temperature industrial applications, with pilot deployments in Japan and South Korea

Investors and Funders

• Clean Energy Finance Corporation (CEFC): Australian government green bank providing concessional debt financing for hydrogen projects at below-market interest rates
• Japan Bank for International Cooperation (JBIC): providing export credit and project finance for Japanese hydrogen technology deployments across Southeast Asia
• Asian Development Bank (ADB): multilateral development bank offering technical assistance grants and risk mitigation instruments for hydrogen pilot projects in developing Asia-Pacific economies

Action Checklist

• Assess hydrogen demand potential across your operations by mapping current grey hydrogen consumption, natural gas usage in thermal processes, and diesel consumption in heavy transport to identify the highest-value fuel switching opportunities
• Request production performance data from hydrogen suppliers covering at least 6 months of continuous operation, including uptime percentage, purity consistency, and delivery reliability metrics
• Structure pilot hydrogen procurement contracts as 12 to 18 month trials with defined performance thresholds before committing to multi-year offtake agreements exceeding 3 years in duration
• Evaluate electrolyzer technology maturity by reviewing the supplier's installed base, mean time between failures for existing deployments, and availability of local maintenance and spare parts in your operating geography
• Incorporate water sourcing and treatment costs into total cost of hydrogen assessments, as water-related expenses can add $0.20 to $0.50 per kilogram of hydrogen in water-scarce regions
• Monitor regulatory developments including Japan's GX League carbon pricing, Australia's Safeguard Mechanism, and South Korea's hydrogen certification scheme to anticipate how compliance obligations will affect hydrogen procurement economics
• Build relationships with multiple hydrogen suppliers across different production pathways (green, blue, and pink) to diversify supply risk during the technology maturation period

FAQ

Q: What is the realistic delivered cost of green hydrogen in Asia-Pacific markets today? A: Delivered green hydrogen costs in Asia-Pacific ranged from $5.00 to $9.00 per kilogram in 2025, depending on production location, transport distance, and contract volume. Projects co-located with dedicated renewable generation in high-resource areas such as Western Australia or Queensland achieve production costs of $3.50 to $5.00 per kilogram, but compression, storage, and trucking add $1.50 to $4.00 per kilogram for delivery distances exceeding 200 kilometers. Pipeline delivery, where available, reduces transport costs to $0.30 to $0.80 per kilogram but requires infrastructure that does not yet exist at scale in most Asia-Pacific markets.

Q: How long does it take a hydrogen production facility to move from final investment decision to stable commercial operation? A: Based on project timelines in Australia, Japan, and South Korea, the period from final investment decision (FID) to first hydrogen production typically spans 24 to 36 months, including 12 to 18 months for construction and equipment installation, followed by 6 to 12 months of commissioning and ramp-up. Reaching stable commercial operation, defined as sustained production at more than 80% of nameplate capacity, typically requires an additional 6 to 12 months beyond first production. Total elapsed time from FID to stable commercial operation therefore ranges from 30 to 48 months, with electrolyzer procurement delays representing the most common source of schedule overruns.

Q: What contract structures protect procurement teams from hydrogen price volatility? A: The most effective structures observed in Asia-Pacific markets include price floors and ceilings indexed to a combination of renewable electricity costs and grey hydrogen benchmarks, with annual adjustment mechanisms. JERA's ammonia offtake agreements, for example, use a formula linked to the Japan customs-cleared LNG price plus a fixed green premium that declines over the contract term. Some contracts include take-or-pay provisions requiring the buyer to pay for 70 to 80% of contracted volumes regardless of actual consumption, which provides suppliers with revenue certainty while giving buyers flexibility to manage demand fluctuations.

Q: Should procurement teams prioritize green hydrogen or blue hydrogen for near-term decarbonization? A: The answer depends on the specific use case, geography, and timeline. Blue hydrogen (produced from natural gas with carbon capture) is currently 40 to 60% cheaper than green hydrogen in most Asia-Pacific markets and can be scaled faster using existing natural gas infrastructure. However, blue hydrogen faces residual emissions of 5 to 15% of upstream methane and CO2 that some regulatory frameworks may not credit as "clean." Procurement teams with compliance deadlines before 2030 may need to accept blue hydrogen as a transitional solution while building supply relationships with green hydrogen producers whose costs are projected to reach parity with blue hydrogen between 2028 and 2032.

Q: What role do e-fuels play in Asia-Pacific decarbonization strategies? A: E-fuels are most relevant for sectors where direct electrification is technically infeasible, primarily long-haul aviation, international shipping, and certain high-temperature industrial processes. In Asia-Pacific, Japan and South Korea have committed to e-fuel blending mandates for aviation by 2030, creating early demand signals. However, e-fuel production costs remain 4 to 6 times higher than fossil equivalents, limiting near-term procurement opportunities to compliance-driven purchases and voluntary sustainability commitments by airlines and shipping companies targeting net-zero operations.

Sources

• BloombergNEF. (2025). Hydrogen Market Outlook 2025: Investment, Production, and Cost Trends. London: Bloomberg Finance L.P.
• Hydrogen Council. (2025). Hydrogen Insights 2025: Global Deployment and Investment Update. Brussels: Hydrogen Council.
• International Renewable Energy Agency. (2025). Green Hydrogen Cost Reduction: Scaling Up Electrolysers to Meet the 1.5C Climate Goal. Abu Dhabi: IRENA.
• Fortescue. (2025). Annual Report 2025: Energy Transition and Green Hydrogen Development. Perth: Fortescue Ltd.
• JERA Co., Inc. (2025). Ammonia Co-Firing Progress Report: Hekinan Thermal Power Station. Tokyo: JERA Co., Inc.
• Lhyfe. (2025). Corporate Update: Asia-Pacific Expansion and Gladstone Project Development. Nantes: Lhyfe SAS.
• Clean Energy Council. (2025). Clean Energy Australia Report 2025: Hydrogen and Storage. Melbourne: Clean Energy Council.