What goes wrong: Hydrogen & e-fuels — common failure modes and how to avoid them

The International Energy Agency's Global Hydrogen Review 2025 found that fewer than 10% of announced clean hydrogen projects globally had reached final investment decision, and roughly one in three projects that broke ground between 2020 and 2024 experienced significant delays, cost overruns, or outright cancellation. In the United States alone, the Department of Energy tracked $24 billion in announced hydrogen and e-fuel capacity that stalled or was abandoned before commissioning. For procurement teams evaluating hydrogen and synthetic fuel offtake agreements, understanding why projects fail is at least as important as understanding the technology itself. The failure modes are remarkably consistent across geographies and technology types, and most are preventable with disciplined planning and realistic assumptions.

Why It Matters

Hydrogen and e-fuels are positioned at the center of US decarbonization strategy. The Inflation Reduction Act's 45V clean hydrogen production tax credit, worth up to $3 per kilogram, has triggered a wave of project announcements. The seven Regional Clean Hydrogen Hubs (H2Hubs) selected by the DOE represent $7 billion in federal investment matched by $40 billion in private capital commitments. E-fuels, also known as synthetic fuels or power-to-liquids, are gaining traction for hard-to-abate sectors including aviation, maritime shipping, and long-haul trucking where direct electrification is impractical.

The stakes for procurement professionals are significant. Companies making hydrogen offtake commitments are locking in 10- to 20-year supply agreements worth hundreds of millions of dollars. A single project failure can leave a buyer without contracted supply, force emergency procurement at spot prices 3 to 5 times higher than contracted rates, and create gaps in Scope 1 and Scope 2 emissions reduction trajectories that undermine corporate climate commitments. Understanding the systematic patterns of failure allows procurement teams to structure contracts, evaluate counterparties, and manage risk portfolios more effectively.

The regulatory environment adds urgency. The US Treasury's final guidance on 45V production tax credit qualification, including the "three pillars" requirements for additionality, deliverability, and temporal matching of renewable electricity, has fundamentally changed project economics. Projects designed under earlier, more permissive assumptions are scrambling to restructure, and some cannot achieve economic viability under the finalized rules. Procurement teams that recognize which projects are at regulatory risk can avoid committing to supply that may never materialize.

Key Concepts

Hydrogen and e-fuel projects fail along predictable dimensions. Understanding these categories helps procurement teams ask the right questions during due diligence:

Electrolyzer performance risk refers to the gap between manufacturer specifications and real-world operating performance for proton exchange membrane (PEM) and alkaline electrolyzers. Stack degradation rates, capacity factors, and efficiency losses under variable renewable power input frequently underperform nameplate claims.

Renewable power procurement risk encompasses the challenge of securing sufficient, cost-effective, and temporally matched renewable electricity to produce genuinely clean hydrogen. The 45V tax credit's hourly matching requirement, effective from 2028, means green hydrogen projects need renewable power supply that aligns with electrolyzer operations on an hour-by-hour basis.

Offtake and demand risk involves the uncertainty of whether end-use demand will materialize at the volumes and price points assumed in project financial models. Many projects have secured letters of intent rather than binding offtake agreements, leaving revenue projections unanchored.

Infrastructure and permitting risk covers the physical systems needed to store, transport, and deliver hydrogen and e-fuels, including pipelines, compression and liquefaction facilities, fueling stations, and port infrastructure.

Failure Mode	Frequency	Typical Cost Impact	Detection Difficulty	Mitigation Complexity
Electrolyzer underperformance	High	15-30% increase in LCOH	Medium	Medium
Renewable power mismatch	Very High	20-50% increase in LCOH	Low	High
Offtake agreement collapse	High	Project cancellation	High	High
Permitting delays	Very High	12-36 month delays	Low	Medium
Water supply constraints	Medium	10-25% increase in LCOH	Medium	Medium-High
Storage and transport gaps	High	25-60% of delivered cost	Medium	Very High

What's Working

Phased Development with Binding Offtake

Air Products' NEOM green hydrogen project in Saudi Arabia, while not US-based, demonstrates a contracting model that US projects are beginning to replicate. The $8.4 billion project secured binding offtake agreements with Asian and European buyers for green ammonia before reaching final investment decision. The company committed its own balance sheet alongside project finance, aligning developer and buyer incentives. In the US, Air Products is applying similar discipline to its hydrogen projects in Texas and Arizona, requiring binding purchase commitments covering at least 60% of output before committing construction capital.

NextEra Energy's hydrogen pilot projects in Florida pair electrolyzers directly with dedicated solar generation assets on the same site, eliminating deliverability risk and simplifying 45V compliance. The integrated approach sacrifices some scale economy but dramatically reduces the regulatory and procurement complexity that has derailed larger projects. The company's 20 MW electrolyzer at its Canaveral facility achieved 92% uptime in its first full year, well above the 75 to 80% typical of early-stage projects.

Cooperative Hub Models

The Appalachian Regional Clean Hydrogen Hub (ARCH2) has structured its development around existing natural gas infrastructure and workforce capabilities, reducing greenfield construction risk. By retrofitting existing pipeline assets for hydrogen blending and co-locating production near established industrial demand centers in West Virginia, Ohio, and Pennsylvania, ARCH2 has shortened projected commissioning timelines by 18 to 24 months compared to fully greenfield hub designs. The hub's procurement approach aggregates demand from multiple industrial users including steelmakers, chemical producers, and glass manufacturers, reducing single-buyer concentration risk.

Standardized Equipment Procurement

Plug Power and Bloom Energy have introduced modular, factory-assembled electrolyzer systems that reduce on-site construction timelines from 18 to 24 months to 6 to 9 months for systems up to 10 MW. The modular approach shifts construction risk from the project site to the controlled factory environment, where quality control is more consistent and weather delays are eliminated. Procurement teams can specify performance guarantees against factory test results rather than relying on field commissioning targets that historically disappoint.

What's Not Working

Oversized Projects Without Demand Certainty

The pattern of announcing gigawatt-scale hydrogen production facilities before securing binding offtake has produced a wave of stalled projects. Plug Power's planned green hydrogen network experienced significant financial strain in 2024 when contracted demand failed to materialize at projected rates, contributing to liquidity concerns that required a capital restructuring. The company's experience illustrates a systemic issue: project developers frequently anchor financial models to expressions of interest rather than bankable contracts, inflating projected revenues by 30 to 60% above realistic demand scenarios.

The Hydrogen Energy California (HECA) project in Kern County spent over $400 million and 15 years in development before being restructured multiple times. Originally conceived as a coal-to-hydrogen project with carbon capture, it pivoted to renewable hydrogen but failed to secure offtake commitments at prices that could support its capital costs. The project became a cautionary example of technology pivots compounding rather than resolving underlying commercial viability challenges.

Underestimating Water Requirements

Electrolytic hydrogen production requires approximately 9 to 10 liters of purified water per kilogram of hydrogen produced. At scale, a 500 MW electrolyzer facility consumes roughly 1.3 million gallons of water per day. Multiple proposed US hydrogen projects in the arid Southwest, including sites in Arizona, Nevada, and West Texas, have encountered water permitting challenges that were not anticipated in initial project planning. The HyDeal Los Angeles initiative faced opposition from local water authorities who flagged competing demands from agricultural and residential users. Water acquisition costs in water-stressed regions can add $0.30 to $0.80 per kilogram to levelized hydrogen costs, eroding margins that were already thin in early project economics.

45V Tax Credit Compliance Gaps

The US Treasury's final rules on the 45V clean hydrogen production tax credit require three conditions for maximum credit eligibility: the renewable electricity must come from new generation assets (additionality), the assets must be on the same regional grid (deliverability), and the renewable generation must match hydrogen production on an hourly basis starting in 2028 (temporal matching). Projects designed under the assumption of annual matching, which is significantly less restrictive, face a fundamental restructuring challenge. The Hydrogen Council estimated that hourly matching requirements could increase the cost of compliant green hydrogen by $0.50 to $1.50 per kilogram compared to annual matching, potentially making the difference between a project that achieves a $1.50/kg production cost and one that cannot break below $3.00/kg.

E-Fuel Cost Overruns

E-fuel production via Fischer-Tropsch synthesis or methanol-to-gasoline pathways requires both clean hydrogen and captured CO2 as feedstocks. The compounding of electrolyzer costs, direct air capture costs, and synthesis plant capital expenditures creates cost structures that consistently exceed initial projections. HIF Global's Haru Oni pilot in Chile, the most advanced e-fuel facility globally, produced synthetic gasoline at approximately $50 per gallon during its pilot phase, roughly 15 times the cost of conventional gasoline. While commercial-scale facilities target $5 to $8 per gallon, no project has yet demonstrated these costs outside of financial models.

Key Players

Established Companies

Air Products: Industrial gas company with over $12 billion committed to clean hydrogen projects globally, operating the world's largest green hydrogen facility at NEOM and developing multiple US production sites.

NextEra Energy: Largest US renewable energy developer integrating hydrogen production with its existing solar and wind portfolio, operating pilot electrolyzers paired with dedicated renewable generation.

Linde: Global industrial gas company with over 200 hydrogen fueling stations and pipeline infrastructure supplying US refineries, operating one of the largest existing hydrogen distribution networks in the Gulf Coast region.

ExxonMobil: Major energy company investing in blue hydrogen with carbon capture at its Baytown, Texas complex, targeting 1 billion cubic feet per day of hydrogen production by 2028.

Startups and Innovators

Electric Hydrogen: California-based electrolyzer manufacturer developing 100 MW-class PEM systems optimized for variable renewable power input, backed by over $600 million in funding from Breakthrough Energy Ventures and Fifth Wall.

Infinium: Sacramento-based e-fuels company producing synthetic fuels from green hydrogen and captured CO2 for aviation and heavy transport, operating a commercial facility in Texas.

Koloma: Denver-based startup exploring geologic hydrogen, naturally occurring hydrogen trapped in subsurface formations, as a potentially lower-cost alternative to electrolytic production.

Investors and Funders

Breakthrough Energy Ventures: Bill Gates-founded climate investment fund with significant hydrogen portfolio positions across production, infrastructure, and end-use technologies.

ARPA-E (Advanced Research Projects Agency-Energy): DOE program funding early-stage hydrogen technologies including advanced electrolyzers, hydrogen storage materials, and novel production pathways.

Hy24: Paris-based clean hydrogen infrastructure fund managing over $2 billion in committed capital, co-led by Ardian and FiveT Hydrogen.

Action Checklist

• Require binding offtake agreements covering at least 50% of projected output before committing to long-term hydrogen supply contracts
• Verify 45V tax credit compliance under the final Treasury rules, specifically assessing additionality, deliverability, and hourly matching capabilities for each potential supplier
• Assess water supply security for any electrolyzer project in regions with water stress indices above 40%, requesting water rights documentation and alternative supply contingency plans
• Demand third-party verified electrolyzer performance data rather than manufacturer nameplate specifications, focusing on degradation rates, capacity factors, and efficiency under variable power input
• Structure contracts with milestone-based pricing that adjusts if delivered hydrogen costs exceed modeled assumptions by more than 15%
• Include supply security provisions that specify alternative sourcing obligations and liquidated damages if the primary project fails to deliver contracted volumes
• Evaluate counterparty financial health, prioritizing developers with investment-grade balance sheets or project finance structures with creditworthy equity sponsors
• Map the full delivered cost including transport, storage, and compression rather than evaluating only production-gate hydrogen pricing

FAQ

Q: What is the most common reason hydrogen projects fail in the US? A: The most common failure mode is the gap between announced offtake interest and binding commercial commitments. Developers frequently advance projects on the basis of letters of intent and memoranda of understanding that impose no purchase obligations on prospective buyers. When these non-binding expressions of interest fail to convert into firm contracts, projects cannot secure project finance and stall before construction. Procurement teams should distinguish clearly between binding offtake agreements with creditworthy counterparties and non-binding expressions of interest when evaluating supply security.

Q: How reliable are current cost projections for green hydrogen and e-fuels? A: Current cost projections carry significant uncertainty. The DOE's Hydrogen Shot target of $1 per kilogram by 2031 represents an aspirational benchmark rather than a consensus forecast. Realistic 2026 production costs for green hydrogen in favorable US locations range from $3 to $6 per kilogram, with delivered costs adding another $1 to $4 depending on transport distance and mode. E-fuel costs remain an order of magnitude above conventional fuel prices, with commercial-scale synthetic aviation fuel projected at $4 to $8 per gallon versus $2 to $3 for conventional jet fuel. Procurement teams should stress-test contracts against a range of cost scenarios rather than anchoring to optimistic base cases.

Q: Should procurement teams prefer blue hydrogen (natural gas with carbon capture) or green hydrogen (electrolysis with renewables)? A: The choice depends on timeline, volume requirements, and carbon accounting standards. Blue hydrogen from autothermal reforming with high-capture-rate carbon sequestration (90%+ CO2 capture) is available today at $1.50 to $2.50 per kilogram, roughly half the current cost of green hydrogen, and can deliver at industrial scale. However, upstream methane leakage in natural gas supply chains can significantly reduce lifecycle emissions benefits, and some corporate sustainability frameworks and voluntary standards do not count blue hydrogen toward net-zero commitments. Green hydrogen offers a cleaner lifecycle profile but carries higher cost and project execution risk. Many procurement teams are adopting blended strategies, contracting blue hydrogen for near-term needs while building green hydrogen supply for 2028 to 2030 delivery.

Q: What contract protections should buyers include in hydrogen offtake agreements? A: Key protections include volume flexibility clauses allowing buyers to reduce contracted volumes by 15 to 25% without penalty if their own demand projections change, price adjustment mechanisms tied to renewable electricity input costs and carbon credit values, force majeure provisions that specifically address electrolyzer failure and renewable power curtailment, step-in rights allowing the buyer to assume operational control if the developer enters financial distress, and alternative supply obligations requiring the seller to source hydrogen from third parties if production falls below minimum delivery thresholds. Buyers should also negotiate audit rights to verify 45V compliance and lifecycle emissions calculations independently.

Sources

• International Energy Agency. (2025). Global Hydrogen Review 2025. Paris: IEA.
• US Department of Energy. (2025). Regional Clean Hydrogen Hubs: Progress Report and Lessons Learned. Washington, DC: DOE Office of Clean Energy Demonstrations.
• US Treasury Department. (2024). Final Rules on Section 45V Clean Hydrogen Production Tax Credit. Washington, DC: Internal Revenue Service.
• Hydrogen Council. (2025). Hydrogen Insights 2025: Global Project Tracker and Cost Analysis. Brussels: Hydrogen Council and McKinsey & Company.
• Bloomberg New Energy Finance. (2025). Hydrogen Market Outlook: US Project Pipeline Analysis. New York: BloombergNEF.
• Air Products. (2025). NEOM Green Hydrogen Project: Development Update and Commercial Framework. Allentown, PA: Air Products and Chemicals Inc.
• National Renewable Energy Laboratory. (2025). Techno-Economic Analysis of Electrolytic Hydrogen Production: Performance Data from US Installations. Golden, CO: NREL.