Explainer: Hydrogen & e‑fuels — what it is, why it matters, and how to evaluate options

Global investment in low-carbon hydrogen reached $42 billion in 2025, yet over 95% of the roughly 95 million tonnes of hydrogen produced annually still comes from unabated fossil fuels, according to the International Energy Agency. That contrast captures both the enormous promise and the persistent challenge of hydrogen and e-fuels: they can theoretically decarbonize sectors that batteries and direct electrification cannot reach, but the economics, infrastructure, and policy frameworks required to scale clean production remain in early stages. For sustainability professionals evaluating where hydrogen and e-fuels fit within decarbonization strategies, understanding the technology landscape, cost trajectories, and evaluation criteria has never been more critical.

Why It Matters

The urgency around hydrogen and e-fuels stems from a fundamental gap in the energy transition. Direct electrification can address roughly 60-65% of global final energy demand, covering passenger vehicles, building heating and cooling, and light industry. The remaining 35-40% includes heavy industry (steel, cement, ammonia production), long-haul shipping, aviation, and seasonal energy storage, all of which require energy carriers with high volumetric or gravimetric energy density that batteries cannot economically provide. Hydrogen and its derivatives (ammonia, methanol, synthetic kerosene) are among the few viable options for these hard-to-abate applications.

The policy landscape has accelerated dramatically. The US Inflation Reduction Act's 45V Production Tax Credit offers up to $3 per kilogram for clean hydrogen production meeting lifecycle emissions thresholds below 0.45 kg CO2e per kg H2. The European Union's REFuelEU Aviation regulation mandates 2% sustainable aviation fuel blending by 2025, rising to 70% by 2050, with a specific sub-mandate for synthetic e-kerosene beginning in 2030. Canada's Clean Hydrogen Investment Tax Credit provides refundable credits of 15-40% of eligible project costs. Japan, South Korea, and Australia have each published national hydrogen strategies with combined public funding commitments exceeding $30 billion through 2030.

The market signal is clear: hydrogen and e-fuels will be a multi-trillion-dollar industry within two decades. BloombergNEF projects that clean hydrogen could meet up to 14% of global final energy demand by 2050, requiring cumulative investment of $12-16 trillion. Organizations that understand the technology today will be positioned to capture value as markets mature.

Key Concepts

Green Hydrogen is produced through water electrolysis powered entirely by renewable electricity. An electrolyzer splits water (H2O) into hydrogen and oxygen, with zero direct carbon emissions. The dominant electrolyzer technologies are alkaline electrolysis (mature, lower cost at $500-800 per kW, but slower response), proton exchange membrane or PEM electrolysis (faster response, higher purity, but $800-1,400 per kW), and solid oxide electrolysis (highest efficiency at 80-90%, operating at 700-850°C, but earliest stage commercially). Green hydrogen production cost in 2025 ranges from $3.50 to $7.00 per kilogram depending on electricity price, electrolyzer utilization, and scale, compared to $1.00-1.80 per kg for grey hydrogen from unabated natural gas.

Blue Hydrogen is produced from natural gas via steam methane reforming (SMR) or autothermal reforming (ATR) with carbon capture and storage (CCS) applied to the concentrated CO2 stream. Blue hydrogen captures 85-95% of process emissions when properly implemented, though upstream methane leakage from natural gas supply chains can significantly erode lifecycle benefits. A 2022 study published in Applied Energy found that methane leakage rates above 3.5% can make blue hydrogen's lifecycle emissions comparable to or worse than direct natural gas combustion. Current blue hydrogen costs range from $1.50 to $3.00 per kg including CCS.

E-fuels (Electrofuels or Synthetic Fuels) are liquid or gaseous hydrocarbons synthesized by combining green hydrogen with captured CO2 through processes such as Fischer-Tropsch synthesis (producing synthetic diesel or kerosene) or methanol synthesis. E-fuels are "drop-in" compatible with existing engines, turbines, and fuel distribution infrastructure, which is their primary advantage over hydrogen itself. However, each conversion step introduces energy losses: electrolysis operates at 60-70% efficiency, CO2 capture at 85-95%, and fuel synthesis at 50-70%, resulting in overall well-to-tank efficiencies of 25-40%. This means e-fuels require 3-5 times more renewable electricity than direct electrification for the same end-use energy service.

Hydrogen Derivatives include ammonia (NH3) and methanol (CH3OH), which serve as both hydrogen carriers and direct fuels. Green ammonia, produced by combining green hydrogen with nitrogen from air via the Haber-Bosch process, has emerged as a leading candidate for maritime shipping fuel and long-distance hydrogen transport. Its volumetric energy density (12.7 MJ/L) is significantly higher than compressed hydrogen (4.5 MJ/L at 700 bar), making it more practical for shipping and storage. The International Maritime Organization's revised 2023 greenhouse gas strategy targets net-zero emissions by approximately 2050, driving substantial investment in ammonia-fueled vessel designs.

Hydrogen Color Spectrum describes production pathways: grey (unabated SMR), blue (SMR with CCS), green (renewable electrolysis), pink or red (nuclear-powered electrolysis), turquoise (methane pyrolysis producing solid carbon), and white (naturally occurring geological hydrogen). Each pathway carries distinct cost, emissions, and scalability profiles. Sustainability professionals should evaluate hydrogen by lifecycle emissions intensity (kg CO2e per kg H2) rather than relying solely on color labels, as performance within each color category varies widely.

Hydrogen and E-fuels KPIs: Benchmark Ranges by Application

Metric	Below Average	Average	Above Average	Top Quartile
Green H2 Production Cost ($/kg)	>$6.00	$4.50-6.00	$3.50-4.50	<$3.50
Electrolyzer Efficiency (LHV)	<55%	55-63%	63-70%	>70%
Blue H2 CO2 Capture Rate	<85%	85-90%	90-95%	>95%
E-fuel Well-to-Tank Efficiency	<25%	25-32%	32-40%	>40%
Electrolyzer Capacity Factor	<30%	30-50%	50-70%	>70%
Levelized Cost of E-kerosene ($/L)	>$4.00	$2.50-4.00	$1.50-2.50	<$1.50
Lifecycle Emissions (kg CO2e/kg H2, green)	>2.0	1.0-2.0	0.45-1.0	<0.45

What's Working

Large-Scale Green Hydrogen Projects Reaching Final Investment Decision

NEOM Green Hydrogen Company's $8.4 billion facility in Saudi Arabia, a joint venture between ACWA Power, Air Products, and NEOM, reached financial close in 2023 and is progressing toward first production in 2026. The project will deploy over 4 GW of solar and wind capacity to power electrolyzers producing up to 600 tonnes per day of green hydrogen, converted to green ammonia for export. This single project represents a step-change in scale, demonstrating that bankable economics for green hydrogen are achievable when paired with exceptional renewable resources (capacity factors exceeding 60% from combined solar and wind).

In Europe, the HyDeal Ambition consortium has signed agreements to deliver green hydrogen at $1.50 per kg by 2030 through co-locating 95 GW of solar with 67 GW of electrolysis across Spain and France, supplying industrial consumers including ArcelorMittal for green steel production.

E-fuels for Aviation Gaining Commercial Traction

HIF Global's Haru Oni pilot plant in Magallanes, Chile, backed by Porsche and Siemens Energy, demonstrated end-to-end e-gasoline production in 2023 using wind-powered electrolysis and direct air capture of CO2. The company's planned commercial-scale facility in Texas aims to produce 200 million gallons of e-fuels annually by 2027. Meanwhile, Infinium, supported by Amazon Climate Pledge Fund and NextEra Energy, is producing e-fuels from waste CO2 and green hydrogen at its facility in Corpus Christi, Texas, with offtake agreements from American Airlines.

Policy Driving Demand Certainty

The US Department of Energy's Regional Clean Hydrogen Hubs (H2Hubs) program allocated $7 billion to seven hub projects in 2023, catalyzing regional ecosystems connecting hydrogen producers, infrastructure developers, and end-users. The Appalachian, California, Gulf Coast, Heartland, Mid-Atlantic, Midwest, and Pacific Northwest hubs collectively plan to produce over 3 million tonnes of clean hydrogen annually, creating guaranteed demand signals that derisk private investment.

What's Not Working

Cost Gap Remains Substantial

Despite policy support, green hydrogen at $3.50-7.00 per kg remains 2-5 times more expensive than grey hydrogen. The US 45V Production Tax Credit narrows this gap significantly for qualifying projects, but the stringent "three pillars" requirements (additionality, temporal matching, and deliverability of renewable electricity) have slowed project development as the Treasury Department finalizes implementation guidance. Many projects that penciled out with assumed credits have been delayed pending regulatory clarity.

Infrastructure Bottleneck

The physical infrastructure to transport, store, and distribute hydrogen at scale does not yet exist in most regions. Converting existing natural gas pipelines to carry hydrogen requires metallurgical assessment for embrittlement, upgraded compression, and modified metering. The US currently has approximately 1,600 miles of dedicated hydrogen pipeline, compared to over 3 million miles of natural gas pipeline. Storage remains equally challenging: geological salt caverns represent the most cost-effective option ($0.50-1.50 per kg stored), but suitable formations are geographically limited to the US Gulf Coast, parts of Northern Europe, and select other regions.

Efficiency Penalty for E-fuels

E-fuels' overall energy efficiency of 25-40% means that for every 100 kWh of renewable electricity input, only 25-40 kWh of useful energy reaches the end user. By comparison, battery electric vehicles deliver 75-85 kWh to wheels from the same input. This physics-driven disadvantage means e-fuels will remain significantly more expensive than direct electrification wherever the latter is technically feasible. E-fuels should be reserved for applications where no electrification pathway exists, primarily long-haul aviation, transoceanic shipping, and certain high-temperature industrial processes.

Key Players

Established Leaders

Air Liquide operates the world's largest hydrogen pipeline network and is investing over $8 billion in clean hydrogen projects through 2035, including 3 GW of electrolysis capacity.

Linde plc supplies hydrogen to over 200 refueling stations globally and is developing large-scale green hydrogen projects in partnership with ITM Power and other electrolyzer manufacturers.

Shell is building Europe's largest renewable hydrogen plant (Holland Hydrogen I, 200 MW) near Rotterdam, targeting industrial customers in the refining and chemicals sectors.

Emerging Startups

Electric Hydrogen has raised over $600 million to manufacture high-capacity PEM electrolyzers designed for industrial scale, with a 100 MW electrolyzer architecture that reduces balance-of-plant costs by 40%.

Infinium produces ultra-low-carbon e-fuels from waste CO2 and green hydrogen, with commercial operations in Texas and offtake agreements with major airlines and logistics companies.

Monolith uses methane pyrolysis to produce turquoise hydrogen and solid carbon black, avoiding CO2 emissions entirely while creating a valuable industrial byproduct.

Key Investors and Funders

Breakthrough Energy Ventures has invested across the hydrogen value chain, including Electric Hydrogen, Koloma (geological hydrogen), and multiple electrolyzer companies.

Hy24 (joint venture of Ardian and FiveT Hydrogen) manages the world's largest clean hydrogen infrastructure fund at $2 billion, targeting production, storage, and distribution assets.

US Department of Energy has committed over $9.5 billion to clean hydrogen through the H2Hubs program, Electrolyzer Manufacturing Program, and demand-side initiatives.

Action Checklist

• Map your organization's energy consumption to identify processes where direct electrification is technically infeasible and hydrogen or e-fuels represent the most viable decarbonization pathway
• Evaluate hydrogen production options by lifecycle emissions intensity (kg CO2e/kg H2) rather than color labels, requesting third-party verified lifecycle assessments from potential suppliers
• Assess proximity to planned hydrogen infrastructure (H2Hubs, pipeline networks, import terminals) to understand future supply availability and transport costs
• Model total cost of ownership for hydrogen vs. alternative decarbonization pathways including capital equipment conversion, fuel costs, and available policy incentives
• Engage with policy teams to track evolving regulations including 45V PTC implementation, REFuelEU mandates, and state-level hydrogen incentive programs
• Develop pilot project scope for highest-priority application, targeting 12-24 month demonstration timeline with clear go/no-go decision criteria
• Establish internal expertise through cross-functional team spanning operations, procurement, finance, and sustainability to evaluate hydrogen opportunities
• Consider offtake agreement structures (fixed-price, index-linked, or tolling) that provide cost certainty while maintaining flexibility as market prices decline

FAQ

Q: When will green hydrogen reach cost parity with grey hydrogen without subsidies? A: Most projections place unsubsidized cost parity between 2030 and 2035, contingent on electrolyzer cost reductions (targeting $200-300 per kW from current $500-1,400 per kW), declining renewable electricity costs (below $20 per MWh), and increased electrolyzer utilization rates. The IEA's 2025 Global Hydrogen Review estimates green hydrogen could reach $1.30-2.50 per kg by 2030 in regions with best renewable resources. With current US 45V subsidies, cost parity is effectively achievable today for qualifying projects.

Q: Should my organization invest in blue or green hydrogen? A: The answer depends on timeline, geography, and application. Blue hydrogen offers lower near-term costs ($1.50-3.00/kg) and leverages existing natural gas infrastructure, making it suitable as a transitional solution for large-scale industrial applications in gas-rich regions. Green hydrogen provides superior lifecycle emissions performance and avoids upstream methane leakage concerns, making it preferable for organizations with strong decarbonization commitments and access to low-cost renewables. Many credible transition strategies employ blue hydrogen as a bridge while green hydrogen scales.

Q: Are e-fuels a realistic alternative to sustainable aviation fuel from biomass? A: E-fuels and biogenic SAF (HEFA, alcohol-to-jet, gasification-FT) serve complementary roles. Biogenic SAF is commercially available today at $1.50-3.00 per gallon premium over conventional jet fuel, but feedstock sustainability concerns and limited supply (projected at 5-10% of global jet fuel demand by 2030) constrain scalability. E-kerosene has virtually unlimited scalability given sufficient renewable electricity and captured CO2, but current costs ($4-8 per liter) are 5-8 times conventional jet fuel. The EU's REFuelEU mandates both pathways, reflecting the consensus that neither alone can meet aviation decarbonization goals.

Q: What infrastructure investments should we plan for if adopting hydrogen? A: Infrastructure requirements vary by application. On-site hydrogen use (industrial processes, backup power) requires electrolyzers or delivered hydrogen storage, compression, and fuel-cell or burner equipment. Fleet applications (trucks, forklifts, buses) require refueling stations with 350-700 bar compression. Budget $2-5 million per heavy-duty refueling station serving 20-50 vehicles. For thermal applications, burner and furnace modifications for hydrogen compatibility typically cost 10-30% more than natural gas equivalents. All applications require safety systems including hydrogen detection, ventilation, and fire suppression designed for hydrogen's unique combustion properties.

Q: How do I verify that hydrogen I purchase is genuinely "clean"? A: Request certification under recognized standards: CertifHy in Europe, the US DOE's Clean Hydrogen Production Standard, or the Green Hydrogen Organisation's GH2 Standard. These frameworks require third-party verification of production emissions, electricity sourcing (additionality, temporal and geographic correlation), and methane leakage measurement for blue hydrogen. Certificates of origin and guarantees of origin provide chain-of-custody documentation. Avoid suppliers who cannot provide independently audited lifecycle emissions data.

Sources

• International Energy Agency. (2025). Global Hydrogen Review 2025. Paris: IEA Publications.
• BloombergNEF. (2025). Hydrogen Economy Outlook: Cost and Deployment Projections to 2050. New York: Bloomberg LP.
• US Department of Energy. (2025). Regional Clean Hydrogen Hubs: Progress and Milestones Report. Washington, DC: DOE.
• European Commission. (2024). REFuelEU Aviation Regulation: Implementation Framework and Compliance Guidance. Brussels: EC.
• Bauer, C., et al. (2022). "On the Climate Impacts of Blue Hydrogen Production." Applied Energy, 312, 118745.
• Hydrogen Council and McKinsey & Company. (2025). Hydrogen Insights 2025: Global Overview and Investment Trends. Brussels: Hydrogen Council.
• National Renewable Energy Laboratory. (2025). H2@Scale: Techno-Economic Analysis of Hydrogen Production Pathways. Golden, CO: NREL.