Regional spotlight: Hydrogen & e-fuels in US — what's different and why it matters

The United States allocated over $9.5 billion in federal hydrogen funding through the Infrastructure Investment and Jobs Act and the Inflation Reduction Act combined, making it the largest single-country commitment to hydrogen and e-fuels deployment in the world as of early 2026 (Department of Energy, 2025). Yet despite this extraordinary policy tailwind, only 1.1 million metric tonnes of clean hydrogen were produced domestically in 2025, less than 10% of the country's roughly 10 million metric tonnes of total annual hydrogen consumption. For procurement teams sourcing hydrogen or e-fuels for industrial, transport, or power applications, the US market presents a uniquely complex landscape where generous federal incentives, fragmented state-level regulation, and nascent infrastructure create both significant opportunity and execution risk that differs markedly from European and Asian hydrogen markets.

Why It Matters

The US hydrogen and e-fuels market operates under structural conditions that diverge from peer markets in Europe, Japan, and South Korea in ways that fundamentally alter procurement strategy, project economics, and supply chain design.

The most consequential differentiator is the Section 45V clean hydrogen production tax credit introduced by the Inflation Reduction Act. At its maximum tier, 45V provides $3.00 per kilogram of hydrogen produced with lifecycle greenhouse gas emissions below 0.45 kg CO2e per kg H2, delivered over 10 years. This credit alone can reduce the levelized cost of green hydrogen from approximately $5.00 to $6.50 per kilogram (unsubsidized electrolysis using renewable power) to $2.00 to $3.50 per kilogram, making US-produced green hydrogen cost-competitive with grey hydrogen at a scale no other national policy currently achieves (Hydrogen Council, 2025). By contrast, the EU's hydrogen strategy relies on contracts for difference and quota-based mandates that support demand creation but provide less direct production cost reduction.

The US also benefits from abundant, low-cost renewable energy resources. Wind capacity factors above 45% in the central corridor from Texas to the Dakotas and solar irradiance exceeding 5.5 kWh per square meter per day across the Sun Belt create electrolyzer utilization economics that are difficult to replicate in Northern Europe or East Asia. Combined with natural gas prices averaging $2.50 to $3.50 per MMBtu (compared to $8 to $12 in Europe and $10 to $14 in Asia), the US has a dual cost advantage in both green and blue hydrogen production pathways.

However, the US market lacks several structural elements that facilitate hydrogen deployment elsewhere. There is no national hydrogen mandate or binding consumption target equivalent to the EU's REPowerEU plan, which sets a target of 10 million tonnes of domestic production and 10 million tonnes of imports by 2030. The US has no national carbon price, no hydrogen blending mandate for gas networks, and no hydrogen-specific certification scheme with the legal standing of the EU's Delegated Acts on renewable fuels of non-biological origin. This policy gap means demand creation relies on voluntary corporate commitments, state-level clean fuel standards, and project-specific offtake agreements rather than regulatory pull.

Key Concepts

The Regional Hydrogen Hub Architecture

The Department of Energy's Regional Clean Hydrogen Hubs (H2Hubs) program, funded at $7 billion under the IIJA, selected seven hubs in October 2023 across diverse geographies and production pathways. As of early 2026, these hubs are in various stages of Phase 1 development, with community benefit plans finalized and initial engineering underway.

The hub structure is distinctive to the US approach. Rather than a national pipeline or infrastructure plan (as pursued by the European Hydrogen Backbone initiative), the US model clusters production, distribution, and end-use within regional ecosystems designed to achieve critical mass locally before interconnecting. The seven hubs span green electrolytic hydrogen (ACES Delta in Utah, Pacific Northwest Hydrogen Hub), blue hydrogen with CCS (Gulf Coast HyVelocity Hub, Heartland Hydrogen Hub), and nuclear-powered hydrogen (Midwest Alliance for Clean Hydrogen), creating a portfolio approach that hedges across technology and feedstock risks.

For procurement teams, the hub geography directly shapes supply availability and pricing. Organizations located within hub regions will have access to hydrogen at delivered costs 30 to 50% below out-of-region supply due to reduced transport distances and shared infrastructure costs. Organizations outside hub regions face a 3 to 5 year wait for pipeline extensions or must rely on trucked liquid hydrogen at delivered costs of $7 to $10 per kilogram (DOE Hydrogen Shot Analysis, 2025).

45V Implementation and Compliance Complexity

The Treasury Department's final rules for 45V, issued in late 2024 after extensive public comment, established three key requirements for claiming the maximum credit: temporal matching (hydrogen production must be matched with clean electricity generation on an hourly basis by 2028, with annual matching permitted through 2027), deliverability (the clean electricity source must be in the same region or connected by transmission to the electrolyzer), and additionality (the clean electricity must come from new generating capacity placed in service within 36 months of the electrolyzer).

These requirements have significant implications for project economics and procurement. The hourly matching requirement reduces effective electrolyzer utilization from theoretical 90%+ (under annual matching) to 40 to 60% for solar-powered systems and 55 to 70% for wind-powered systems, increasing the per-kilogram cost of production. The additionality requirement prevents producers from claiming credits using existing grid renewables, effectively requiring co-located or contracted new-build renewable capacity. Several industry groups have argued these provisions are overly restrictive and will slow deployment, while environmental organizations contend they are essential to ensuring genuine emissions reductions.

E-fuels and Sustainable Aviation Fuel

The US sustainable aviation fuel (SAF) market operates under a distinct incentive structure created by the SAF blenders tax credit (Section 40B), which provides $1.25 to $1.75 per gallon for SAF with lifecycle emissions reductions of 50% or more compared to conventional jet fuel. This credit, combined with California's Low Carbon Fuel Standard (LCFS) credits valued at $50 to $70 per tonne CO2e avoided, creates a revenue stack that can close the cost gap between e-SAF (produced via Fischer-Tropsch synthesis using green hydrogen and captured CO2) and petroleum-derived jet fuel.

US SAF production capacity reached approximately 1.2 billion gallons per year in 2025, dominated by hydroprocessed esters and fatty acids (HEFA) pathways using waste fats and oils. E-SAF (Power-to-Liquid) capacity remains minimal at fewer than 10 million gallons per year, but announced projects from Infinium, HIF Global, and Twelve would add over 500 million gallons of annual capacity by 2030 if fully built out. For airlines and corporate travel programs, procuring e-SAF through book-and-claim systems or direct offtake agreements requires navigating a fragmented certification landscape involving CORSIA eligibility, LCFS pathway certification, and federal tax credit documentation.

What's Working

The Gulf Coast is emerging as the epicenter of US blue hydrogen production, leveraging existing natural gas infrastructure, extensive geological storage capacity in depleted salt caverns and saline formations, and the deepest concentration of industrial hydrogen consumers in the country. The HyVelocity Hub, centered on Houston, has secured commitments from Air Liquide, Chevron, and ExxonMobil to develop over 2 million tonnes per year of blue hydrogen production capacity with CO2 stored in formations along the Texas and Louisiana coasts. Air Liquide's planned facility in Beaumont, Texas, would produce 600,000 tonnes per year of blue hydrogen with greater than 95% CO2 capture, making it one of the largest low-carbon hydrogen plants globally.

In the green hydrogen space, the ACES Delta hub in Utah represents the most advanced large-scale project. The hub combines 220 MW of dedicated electrolysis capacity (using Mitsubishi Power equipment) with hydrogen storage in the Magnum salt cavern formation, capable of storing 5,500 metric tonnes of hydrogen. The stored hydrogen will supply the Intermountain Power Agency's 840 MW combined-cycle power plant, which will initially operate on a 30% hydrogen blend transitioning to 100% hydrogen by 2045. For procurement teams in the western US, this project establishes a template for long-duration energy storage using hydrogen that could reshape power purchase agreement structures.

California's LCFS continues to drive hydrogen demand in the transport sector, providing credits worth $50 to $70 per tonne CO2e avoided on top of federal incentives. The state's network of 65 retail hydrogen stations (operated primarily by FirstElement Fuel and Shell) supports approximately 17,000 fuel cell electric vehicles. While the FCEV light-duty market has contracted relative to battery electric alternatives, California's requirement for zero-emission drayage trucks at ports (effective 2024) and the Advanced Clean Trucks regulation are shifting hydrogen demand toward medium and heavy-duty applications where fuel cells offer range, payload, and refueling time advantages over batteries.

Plug Power and Bloom Energy have demonstrated commercially viable fuel cell deployments in material handling (over 60,000 fuel cell forklifts deployed across Amazon, Walmart, and Home Depot distribution centers) and stationary power (over 1 GW of Bloom Energy Server installations at data centers and industrial facilities). These applications generate real recurring hydrogen demand outside the vehicle segment and provide procurement precedents for hydrogen-as-a-service contracts with performance guarantees.

What's Not Working

Permitting and interconnection delays are the single largest execution risk for US hydrogen projects. Electrolyzer facilities requiring dedicated renewable energy connections face interconnection queue wait times averaging 4 to 5 years across most grid regions, effectively making the 45V additionality requirement a bottleneck. The Lawrence Berkeley National Laboratory reported that over 2,600 GW of generation and storage projects were waiting in interconnection queues at the end of 2024, of which only 15 to 20% are expected to reach commercial operation (LBNL, 2025).

Water availability is an underappreciated constraint for green hydrogen at scale. Electrolysis consumes approximately 9 liters of purified water per kilogram of hydrogen produced. A 1 GW electrolyzer facility operating at 60% capacity factor would consume roughly 1.4 billion liters of water per year, a significant demand in the water-stressed Sun Belt regions where solar resources are strongest. Several proposed projects in Arizona, Nevada, and west Texas face water rights challenges that could delay or downscale deployment.

The hydrogen distribution gap remains acute. The US has approximately 1,600 miles of dedicated hydrogen pipeline, concentrated almost entirely along the Gulf Coast serving existing refinery demand. By comparison, the European Hydrogen Backbone envisions 28,000 km of pipeline by 2030, much of it repurposed from natural gas networks. Outside the Gulf Coast corridor, hydrogen delivery relies on tube trailers (gaseous, limited to 300 to 500 kg per truck) or liquid hydrogen tankers (cryogenic, higher capacity but energy-intensive liquefaction adds $1.50 to $2.50 per kilogram). This distribution cost penalty severely limits the addressable market for hydrogen produced at remote locations with the best renewable resources.

Policy uncertainty continues to weigh on investment decisions. The 45V tax credit, while transformative on paper, faces ongoing implementation questions around the hourly matching timeline and potential modifications under future administrations. Several developers have delayed final investment decisions pending regulatory clarity, creating a gap between announced project capacity and projects actually under construction. The Fuel Cell and Hydrogen Energy Association estimates that regulatory uncertainty has deferred over $15 billion in private investment as of early 2026.

Key Players

Established companies: Air Liquide (Gulf Coast blue hydrogen production and pipeline network), Linde (electrolysis projects and industrial gas distribution), Chevron (hydrogen hubs and SAF investments), ExxonMobil (blue hydrogen with CCS at Baytown, Texas), NextEra Energy (renewable-powered electrolysis development), Air Products (green hydrogen projects in Texas and Louisiana)

Startups and growth-stage: Plug Power (fuel cell systems and green hydrogen production via electrolysis), Bloom Energy (solid oxide fuel cells and electrolyzer technology), Electric Hydrogen (large-scale PEM electrolyzers optimized for industrial output), Infinium (e-fuels production using captured CO2 and green hydrogen), Twelve (CO2 transformation into e-SAF and chemicals), Monolith Materials (methane pyrolysis producing turquoise hydrogen and carbon black)

Investors and institutions: Department of Energy Loan Programs Office (conditional commitments exceeding $2 billion for hydrogen projects), Breakthrough Energy Ventures (portfolio investments across hydrogen value chain), Hy24 (Clean Hydrogen Infrastructure Fund with US allocations), S2G Ventures (clean energy and decarbonization investments), Generate Capital (infrastructure-as-a-service for distributed hydrogen)

Action Checklist

• Map your facility locations against the seven H2Hub regions to identify where subsidized hydrogen supply will be available earliest
• Model total cost of hydrogen including delivery by evaluating pipeline vs. trucked supply for your specific consumption volumes and locations
• Review 45V credit requirements with tax counsel to understand how credit eligibility impacts your suppliers' pricing and your own procurement terms
• Assess SAF procurement options through book-and-claim or direct offtake, factoring in the Section 40B blenders credit and applicable LCFS credits
• Evaluate blue vs. green hydrogen based on your organization's Scope 3 reporting requirements and carbon intensity thresholds
• Engage with state-level hydrogen roadmaps (California, Texas, New York, Ohio, Louisiana have published or are developing hydrogen strategies) to align procurement timing with infrastructure buildout
• Negotiate hydrogen supply agreements with performance guarantees on carbon intensity, availability, and pricing escalation to manage transition risk
• Monitor FERC and regional transmission organization proceedings on electrolyzer interconnection to anticipate supply timeline risks

FAQ

Q: How does the cost of green hydrogen in the US compare to Europe and Asia? A: With the 45V credit at its maximum $3.00/kg tier, US green hydrogen can reach levelized costs of $2.00 to $3.50 per kilogram, substantially below European green hydrogen at $4.50 to $7.00 per kilogram and Japanese imported hydrogen at $6.00 to $8.00 per kilogram (landed cost). The US advantage stems from three factors: lower renewable electricity costs ($20 to $30/MWh for best-in-class wind and solar vs. $35 to $55 in Europe), the production tax credit itself, and lower construction labor costs for electrolyzer installation relative to Western Europe and Japan. However, without the 45V credit, US green hydrogen costs are $5.00 to $6.50 per kilogram, roughly comparable to European levels. Procurement teams should assess supplier reliance on the credit and build contract provisions for scenarios where credit availability changes.

Q: Will the US hydrogen hub model actually deliver infrastructure at scale? A: The hub model addresses a genuine coordination failure by co-locating supply and demand, but execution risks are significant. Of the $7 billion allocated, less than $1 billion had been disbursed by early 2026 as hubs complete community benefit plans and environmental reviews. Historical precedent from DOE programs suggests 30 to 50% of initially selected projects may be restructured, downsized, or cancelled before reaching full operation. The most likely near-term successes are hubs with strong industrial anchor tenants (HyVelocity on the Gulf Coast, Midwest Alliance near existing refinery demand) rather than those dependent on creating new demand categories. Procurement teams should track individual hub milestone achievements rather than relying on aggregate DOE announcements.

Q: Should procurement teams prioritize blue or green hydrogen in the US market? A: In the near term (2026 to 2029), blue hydrogen will offer lower delivered costs ($1.50 to $2.50/kg at Gulf Coast facilities with CCS) and greater volume availability than green hydrogen. For organizations with flexible carbon intensity requirements, blue hydrogen provides a pragmatic bridge fuel. For organizations facing strict Scope 3 targets or customer-driven sustainability requirements, green hydrogen's lower lifecycle emissions (0.4 kg CO2e/kg H2 with 45V-qualifying production vs. 1.5 to 3.0 kg CO2e/kg H2 for blue hydrogen depending on methane leakage assumptions) justify the cost premium. Many sophisticated procurement strategies include a blend of both, with green hydrogen share increasing as electrolyzer capacity and renewable interconnections scale through the late 2020s.

Q: What is the outlook for e-fuels and SAF procurement in the US? A: E-SAF remains a premium product at $6 to $10 per gallon versus $2.50 to $3.50 for conventional jet fuel, but the combined value of the Section 40B credit ($1.25 to $1.75/gallon), LCFS credits ($0.50 to $1.00/gallon equivalent), and emerging voluntary SAF certificate markets ($15 to $30 per tonne CO2e) narrows the gap to 40 to 60%. Airlines with net-zero commitments (United, Delta, American, JetBlue) are signing multi-year SAF offtake agreements at volumes that exceed current e-SAF supply, creating a seller's market for certified product. Corporate travel programs can access SAF benefits through book-and-claim certificates without physical fuel delivery, typically priced at $20 to $50 per tonne CO2e avoided.

Sources

• Department of Energy. (2025). US National Clean Hydrogen Strategy and Roadmap: 2025 Update. Washington, DC: US Department of Energy, Office of Energy Efficiency and Renewable Energy.
• Hydrogen Council. (2025). Hydrogen Insights 2025: Global Cost Competitiveness and Deployment Tracker. Brussels: Hydrogen Council and McKinsey & Company.
• DOE Hydrogen Shot Analysis. (2025). Pathways to $1/kg Hydrogen: Progress Assessment and Remaining Gaps. Washington, DC: National Renewable Energy Laboratory for US DOE.
• Lawrence Berkeley National Laboratory. (2025). Queued Up: Characteristics of Power Plants Seeking Transmission Interconnection as of Year-End 2024. Berkeley, CA: LBNL.
• Fuel Cell and Hydrogen Energy Association. (2025). US Hydrogen Economy Status Report: Investment, Deployment, and Policy Outlook. Washington, DC: FCHEA.
• International Energy Agency. (2025). Global Hydrogen Review 2025: Regional Production Cost Comparisons. Paris: IEA.
• BloombergNEF. (2025). Hydrogen Market Outlook: US Production Economics and 45V Impact Analysis. New York: BNEF.