Case study: Hydrogen & e-fuels — a sector comparison with benchmark KPIs

North America's clean hydrogen sector reached an inflection point in 2024, with announced project capacity exceeding 18 million metric tons per year—yet only 4% of that capacity has achieved final investment decision status. This gap between ambition and execution reveals the fundamental tensions shaping the hydrogen economy: levelized cost of hydrogen (LCOH) remains stubbornly above $4/kg for most green projects, offtake agreements struggle to bridge the price differential with incumbent grey hydrogen, and infrastructure bottlenecks threaten to strand otherwise viable assets. For investors and operators navigating this landscape, understanding the benchmark KPIs across sectors—from ammonia synthesis to sustainable aviation fuel—is essential to separating credible opportunities from stranded capital risk.

Why It Matters

Hydrogen and e-fuels represent one of the few viable pathways to decarbonize sectors responsible for approximately 30% of global emissions that cannot be easily electrified: heavy industry, long-haul shipping, aviation, and high-temperature manufacturing. In North America specifically, the policy landscape shifted dramatically between 2022 and 2025, with the Inflation Reduction Act's 45V production tax credit offering up to $3/kg for hydrogen produced with lifecycle emissions below 0.45 kg CO2e/kg H2.

The stakes are substantial. According to the U.S. Department of Energy's 2024 National Clean Hydrogen Strategy update, domestic clean hydrogen demand could reach 10 million metric tons annually by 2030 and 50 million metric tons by 2050. Canada's hydrogen strategy targets 30% of delivered energy from hydrogen by 2050. Mexico's emerging framework, while less developed, identifies hydrogen as central to its industrial decarbonization pathway.

Yet the 2024-2025 period exposed critical execution challenges. The Treasury Department's final 45V guidance, released in January 2025, imposed strict hourly matching requirements for green hydrogen production beginning in 2028, requiring electrolyzers to demonstrate temporal correlation with renewable generation. This ruling effectively increased projected LCOH by $0.40–$0.80/kg for projects that had modeled annual matching assumptions. Simultaneously, interconnection queue backlogs across major grid regions—ERCOT, PJM, and CAISO—extended average wait times beyond 5 years, stranding gigawatts of renewable capacity that would otherwise support hydrogen production.

The market response has been bifurcated. Projects with secured offtake contracts and grid connections continue advancing, while speculative developments face indefinite delays. Understanding which KPIs differentiate these outcomes is now the central analytical challenge for the sector.

Key Concepts

Hydrogen (H2): The lightest element, hydrogen serves as both an energy carrier and industrial feedstock. Production pathways are color-coded: grey hydrogen derives from unabated natural gas reforming (responsible for ~95% of current global production), blue hydrogen captures and stores reforming emissions, and green hydrogen uses electrolysis powered by renewable electricity. The carbon intensity varies dramatically: grey hydrogen produces 9–12 kg CO2e/kg H2, best-in-class blue achieves 1–3 kg CO2e/kg H2, and green hydrogen can approach 0.4 kg CO2e/kg H2 when sourcing verified renewable power.

Levelized Cost of Hydrogen (LCOH): The all-in cost per kilogram of hydrogen production, incorporating capital expenditure (electrolyzer or reformer), feedstock (electricity or natural gas), operating expenses, and financing costs over project lifetime. As of late 2024, North American LCOH benchmarks ranged from $1.00–$1.50/kg for grey hydrogen, $1.80–$2.80/kg for blue hydrogen with 90%+ capture rates, and $3.50–$6.00/kg for green hydrogen depending on renewable electricity pricing and capacity factors. The 45V tax credit at full value ($3/kg) theoretically brings green hydrogen to cost parity, but qualification requirements and verification costs reduce effective subsidy value.

Curtailment: The deliberate reduction of renewable electricity generation when supply exceeds grid demand or transmission capacity. For hydrogen producers, curtailed renewable energy represents a potential low-cost or negative-cost feedstock—several Texas projects specifically co-locate electrolyzers with wind farms to monetize otherwise curtailed generation. ERCOT curtailment exceeded 10 TWh in 2024, representing substantial untapped hydrogen production potential.

Life Cycle Assessment (LCA): A comprehensive methodology for quantifying environmental impacts across a product's entire value chain—from raw material extraction through end-use. For hydrogen, LCA boundaries are contentious: whether to include upstream methane leakage for blue hydrogen, transmission losses for green hydrogen electricity, and end-of-life electrolyzer disposal significantly affects reported carbon intensities. The 45V credit's GREET model implementation standardized these boundaries for U.S. projects, but international offtakers may require different certification frameworks.

Interconnection: The process of connecting new generation or load assets to the electrical grid. Hydrogen production at scale requires substantial grid capacity—a 100 MW electrolyzer operating at 70% capacity factor draws power equivalent to approximately 25,000 homes. The interconnection process involves feasibility studies, system impact studies, facility studies, and construction, with cumulative timelines now averaging 4–7 years across North American ISOs. This bottleneck represents the single largest constraint on green hydrogen deployment velocity.

What's Working and What Isn't

What's Working

Behind-the-meter configurations with dedicated renewables: Projects that co-locate electrolysis with dedicated renewable generation—avoiding grid interconnection entirely—have demonstrated the fastest development timelines. Air Liquide's 250 MW electrolyzer project in Texas, powered by a dedicated wind farm under a long-term PPA, reached mechanical completion in 2024 without entering the ERCOT interconnection queue. This configuration satisfies 45V additionality and deliverability requirements while eliminating multi-year grid connection delays.

Industrial cluster strategies leveraging existing hydrogen demand: The most commercially advanced projects target facilities already consuming grey hydrogen—oil refineries, ammonia plants, and methanol producers—where the value proposition involves emissions reduction rather than market creation. The Gulf Coast hydrogen hub, one of seven Regional Clean Hydrogen Hubs selected by DOE in October 2023, aggregates demand across 48 industrial facilities within a 150-mile radius, enabling shared pipeline infrastructure and reducing per-project logistics costs.

Blended offtake structures with price escalators: Successful offtake negotiations increasingly feature hybrid pricing mechanisms—combining fixed floors with index-linked escalators tied to carbon prices or natural gas spreads. These structures allow producers to secure bankable minimum revenue while preserving upside exposure to tightening emissions regulations. Multiple announced agreements include price reopener provisions if the 45V credit is extended or enhanced beyond 2032.

Blue hydrogen with enhanced methane monitoring: While green hydrogen attracts more attention, blue hydrogen projects incorporating continuous methane emissions monitoring have advanced more rapidly to construction. ExxonMobil's Baytown blue hydrogen project, targeting 1 billion cubic feet per day of hydrogen production with 98%+ carbon capture, leverages existing natural gas infrastructure and has secured long-term agreements with industrial customers seeking carbon intensity reductions without the supply chain complexity of electrolytic hydrogen.

What Isn't Working

Projects dependent on merchant hydrogen sales: Developments targeting commodity hydrogen markets without binding offtake contracts face severe financing constraints. Lenders require 60–80% of projected revenue secured through long-term agreements for non-recourse project financing; the residual exposure to spot hydrogen markets—which remain thin and localized—introduces unacceptable downside risk. Several announced projects in 2024 scaled back or postponed final investment decisions when offtake negotiations stalled.

Electrolyzers requiring grid connection without queue position: The interconnection backlog fundamentally constrains green hydrogen development velocity. Projects that announced in 2023 expecting 18–24 month grid connections now face 2028–2030 commercial operation dates—well after initial offtake contracts would expire. The Midcontinent ISO (MISO) queue alone contains over 300 GW of pending generation and storage requests, with withdrawal rates exceeding 70% for projects that cannot sustain extended development periods.

E-fuels without aviation mandates or premium pricing: Sustainable aviation fuel (SAF) and e-methanol projects face the challenge of producing fuels that cost 3–5x conventional alternatives in markets without binding consumption mandates. While the EU's ReFuelEU regulation requires 2% SAF blending by 2025 (scaling to 70% by 2050), North American aviation lacks comparable requirements. Projects targeting SAF production struggle to secure offtake at prices sufficient to support investment, despite technical viability.

Hydrogen storage infrastructure development: Unlike natural gas, which benefits from extensive underground storage in depleted reservoirs and salt caverns, hydrogen storage infrastructure remains nascent. The physical properties of hydrogen—low volumetric energy density and embrittlement risk for conventional steel—require specialized facilities. Only a handful of operational salt cavern hydrogen storage sites exist globally, and North American development lags European projects. Without storage buffers, hydrogen production and consumption must remain closely synchronized, limiting operational flexibility.

Key Players

Established Leaders

Air Products and Chemicals: The Pennsylvania-headquartered industrial gas producer operates the largest hydrogen pipeline network in the world (over 2,000 miles) and has committed $15 billion to clean hydrogen projects globally. Its NEOM green hydrogen project in Saudi Arabia (targeting 2025 production) and Louisiana blue hydrogen facility demonstrate cross-technology expertise.

Linde plc: With hydrogen production capacity exceeding 1 billion cubic feet per day, Linde provides engineering, procurement, and construction services alongside gas supply. The company's partnership with ITM Power on electrolyzer manufacturing and its operation of over 200 hydrogen fueling stations position it across the value chain.

Chevron Corporation: Chevron's $10 billion lower-carbon investment commitment through 2028 includes substantial hydrogen allocations. The company's Advanced Clean Energy Storage project in Delta, Utah—the world's largest green hydrogen storage facility using salt caverns—demonstrates integration of production and storage at industrial scale.

ExxonMobil: Despite historical skepticism toward hydrogen economics, ExxonMobil's Baytown low-carbon hydrogen project represents one of the largest blue hydrogen investments in North America. The integration with the company's carbon capture and storage expertise creates a differentiated pathway for industrial decarbonization.

Shell plc: Shell's hydrogen activities span production (including the Rhineland refinery electrolyzer in Germany), distribution (Shell Hydrogen branded refueling stations), and offtake (long-term supply agreements with trucking fleets). The company's 2024 strategic review reaffirmed hydrogen as core to its energy transition portfolio.

Emerging Startups

Electric Hydrogen: Founded in 2020, this California-based company develops high-efficiency proton exchange membrane (PEM) electrolyzers specifically designed for industrial-scale hydrogen production. Its 100 MW electrolyzer platform targets LCOH below $2/kg at favorable renewable electricity pricing.

Monolith Materials: Nebraska-based Monolith uses methane pyrolysis—splitting natural gas into hydrogen and solid carbon without CO2 emissions—to produce clean hydrogen and carbon black simultaneously. The company's Olive Creek facility represents the first commercial-scale methane pyrolysis plant in North America.

Infinium: This California startup produces e-fuels by combining captured CO2 with green hydrogen. Its Pathfinder project in Texas, targeting 2024 production, supplies ultra-low carbon intensity fuels to Amazon's logistics fleet under a multi-year offtake agreement.

Koloma: Focused on naturally occurring geological hydrogen ("gold hydrogen"), Koloma raised $245 million in 2024 to explore and extract subsurface hydrogen deposits. If commercially viable, geological hydrogen could provide zero-carbon supply at costs potentially below $1/kg.

Verdagy: This Newark, California company develops advanced alkaline electrolyzers with proprietary membrane technology, targeting capital costs 30% below conventional systems. Verdagy's partnership with TotalEnergies includes electrolyzer deployment at European refinery complexes.

Key Investors & Funders

U.S. Department of Energy (DOE): Through the Regional Clean Hydrogen Hubs program, DOE has allocated $7 billion across seven selected hubs, with projects spanning production, storage, and end-use infrastructure. The Loan Programs Office has additionally provided conditional commitments exceeding $2 billion for hydrogen-related projects.

Breakthrough Energy Ventures: Bill Gates' climate-focused fund has invested in multiple hydrogen and e-fuel companies, including Electric Hydrogen, Infinium, and Koloma. The fund's patient capital approach—accepting 10–15 year return horizons—aligns with hydrogen infrastructure development timelines.

Canada Infrastructure Bank (CIB): The CIB has committed CAD $1.5 billion to hydrogen projects, including investments in Hydrogen Optimized's electrolyzer manufacturing and ATCO's Fort Saskatchewan hydrogen blending project. Federal co-investment substantially de-risks private capital deployment.

Hy24: This Paris-based clean hydrogen investment platform, backed by Ardian and FiveT Hydrogen, manages €2 billion in assets and has expanded North American investments in 2024. The fund targets infrastructure-style returns with contracted cash flows.

Goldman Sachs Alternatives: Goldman's infrastructure and clean energy funds have deployed capital to hydrogen projects, including its role as financial advisor on multiple hydrogen hub formations. The firm's January 2025 report projected the clean hydrogen market reaching $250 billion by 2030.

Examples

1. Air Products Massena Green Hydrogen Project (New York): Leveraging low-cost hydroelectric power from the St. Lawrence-FDR Power Project, Air Products is developing a 35-ton-per-day green hydrogen facility targeting industrial customers in the northeastern United States and Canada. The project benefits from contracted renewable electricity at approximately $0.025/kWh, enabling projected LCOH of $2.80–$3.20/kg before tax credits. With 45V incentives, delivered hydrogen costs approach grey hydrogen parity. The project secured a 15-year offtake agreement with a regional ammonia producer, demonstrating that strategic site selection and patient capital can overcome broader market headwinds.

2. HyVelocity Hub (Gulf Coast): As one of DOE's seven selected Regional Clean Hydrogen Hubs, HyVelocity aggregates $7 billion in planned investment across the Houston-Louisiana industrial corridor. The hub's strategy centers on leveraging existing hydrogen infrastructure—approximately 900 miles of operational hydrogen pipelines—while progressively decarbonizing production. Initial phases target blue hydrogen production with 95%+ carbon capture at three large-scale facilities, with green hydrogen integration planned as electrolyzer costs decline. The consortium structure, including ExxonMobil, Chevron, Air Liquide, and 20+ additional partners, distributes infrastructure investment costs and coordinates demand aggregation across refineries, chemical plants, and steel production.

3. ACES Delta (Utah): The Advanced Clean Energy Storage project in Delta, Utah represents the largest green hydrogen storage facility in the world. The $1.5 billion project combines an 840 MW electrolyzer (procured from Mitsubishi Power) with salt cavern storage capable of holding 5,500 metric tons of hydrogen—equivalent to 150 GWh of energy. Initial hydrogen production powers the adjacent Intermountain Power Project's transition from coal to hydrogen-capable gas turbines. The project's structure—with guaranteed electricity offtake from the Los Angeles Department of Water and Power—illustrates how vertical integration across production, storage, and consumption can create bankable project economics despite broader market uncertainty.

Action Checklist

• Conduct detailed LCOH sensitivity analysis incorporating electrolyzer capital costs, capacity factors, and electricity pricing scenarios for target project sites
• Evaluate interconnection queue positions and realistic grid connection timelines; prioritize sites with existing transmission capacity or behind-the-meter configurations
• Map existing industrial hydrogen consumers within 100-mile radius to identify offtake candidates with immediate demand and grey hydrogen substitution potential
• Structure offtake negotiations with price floors, carbon-price escalators, and reopener provisions tied to policy developments
• Assess 45V eligibility pathways, including hourly matching requirements effective 2028 and GREET model compliance for lifecycle emissions calculations
• Develop detailed carbon intensity documentation systems meeting multiple certification frameworks (45V, CertifHy, ISCC) to maximize offtake flexibility
• Evaluate salt cavern or lined rock cavern storage options within target production regions; commission geological assessments for greenfield storage development
• Establish partnerships with electrolyzer manufacturers securing equipment delivery schedules and performance warranties aligned with project timelines
• Monitor state-level hydrogen incentive programs (California LCFS, Washington Clean Fuel Standard) that can stack with federal 45V credits
• Create contingency plans for policy uncertainty, including project structures viable without 45V credit continuation beyond 2032

FAQ

Q: What LCOH threshold makes green hydrogen projects commercially viable in North America? A: Commercial viability depends heavily on the incumbent fuel being displaced and available incentives. For grey hydrogen substitution in refineries and ammonia plants, parity requires LCOH at or below $1.50/kg—achievable only with full 45V credits ($3/kg) and production costs below $4.50/kg. For transportation applications competing with diesel at $3.50/gallon, hydrogen delivered to vehicle at $8–10/kg can be competitive on a per-mile basis given fuel cell efficiency advantages. For e-fuels targeting aviation, customers currently pay 3–5x conventional jet fuel pricing, implying tolerance for hydrogen feedstock costs of $5–6/kg. The $2.50/kg threshold frequently cited as "cost parity" reflects an idealized industrial offtake scenario with favorable electricity pricing and high electrolyzer utilization.

Q: How do the 2025 45V final rules affect project development timelines? A: The Treasury Department's January 2025 final guidance imposed hourly matching requirements beginning January 1, 2028, with a transition period allowing annual matching through 2027. Projects achieving commercial operation before 2028 face lower compliance burdens, creating urgency for developments nearing final investment decision. For projects targeting 2028+ operations, hourly matching requires either co-located dedicated renewables with matched generation profiles, battery storage to shift renewable generation to consumption periods, or access to 24/7 carbon-free power from nuclear or geothermal sources. Early analysis suggests hourly matching increases effective LCOH by $0.40–$0.80/kg compared to annual matching assumptions, though sophisticated project structures with storage and diversified renewable portfolios can minimize this premium.

Q: What role does blue hydrogen play in the near-term North American market? A: Blue hydrogen—produced from natural gas with carbon capture—offers a pragmatic pathway for industrial decarbonization while green hydrogen scales. With natural gas prices in the $2.50–$4.00/MMBtu range, blue hydrogen LCOH ranges from $1.80–$2.80/kg depending on capture rates and CO2 storage costs. The 45Q tax credit provides $85/ton for geological CO2 storage, improving blue hydrogen economics substantially. For carbon-intensive industries seeking near-term emissions reductions without the supply chain complexity of electrolytic hydrogen, blue hydrogen offers an available solution. Concerns regarding upstream methane leakage—which can eliminate lifecycle emissions benefits—are increasingly addressed through continuous emissions monitoring and third-party verification. Several 2024-2025 blue hydrogen projects incorporate methane intensity guarantees into natural gas supply contracts.

Q: What infrastructure investments are most critical for hydrogen market development? A: Three infrastructure categories determine market scalability: production, transmission/distribution, and storage. Production infrastructure—electrolyzers and reformers—has attracted substantial investment, but transmission and storage remain bottlenecks. Dedicated hydrogen pipelines cost $1–3 million per mile depending on diameter and terrain; repurposing natural gas pipelines offers lower costs but faces metallurgical limitations requiring case-by-case assessment. Salt cavern storage, the only proven large-scale hydrogen storage technology, requires specific geological conditions found in the Gulf Coast, Utah, and portions of the Southwest. Developing storage capacity equivalent to natural gas's current strategic reserves would require investment exceeding $50 billion. Without storage and transmission buildout coordinated with production expansion, hydrogen markets will remain fragmented and localized, limiting economies of scale.

Q: How should investors evaluate hydrogen project counterparty risk? A: Counterparty risk assessment for hydrogen projects requires examining both offtaker creditworthiness and technological readiness. For industrial offtake, buyers should demonstrate existing hydrogen consumption (eliminating demand risk) and investment-grade credit ratings or parent guarantees. For transportation and power sector offtake, agreements should include minimum take-or-pay volumes and termination provisions that protect producer economics. Technology risk centers on electrolyzer performance—degradation rates, availability, and efficiency—with warranties and performance guarantees from established manufacturers (Nel, ITM Power, Cummins) providing protection. Projects relying on emerging technologies (solid oxide electrolysis, methane pyrolysis) warrant higher risk premiums. Geographic concentration introduces additional risks: projects dependent on single renewable resources face production volatility, while those dependent on single offtakers face credit concentration. Diversified production portfolios and multiple offtake counterparties, though operationally complex, substantially reduce project risk profiles.

Sources

• U.S. Department of Energy, "National Clean Hydrogen Strategy and Roadmap: 2024 Update," September 2024
• Internal Revenue Service, "Section 45V Clean Hydrogen Production Tax Credit: Final Regulations," January 2025
• BloombergNEF, "Hydrogen Economy Outlook 2025: Market Size and Investment Flows," January 2025
• Lawrence Berkeley National Laboratory, "Queued Up: Characteristics of Power Plants Seeking Transmission Interconnection," December 2024
• International Energy Agency, "Global Hydrogen Review 2024," September 2024
• Hydrogen Council and McKinsey & Company, "Hydrogen Insights 2024: An Updated Perspective on Hydrogen Investment, Deployment, and Cost Competitiveness," November 2024
• S&P Global Commodity Insights, "North American Hydrogen Price Assessments Methodology," 2024