Myth-busting Hydrogen & e‑fuels: separating hype from reality

The International Energy Agency reported in early 2026 that global electrolyser capacity reached just 2.1 GW at the end of 2025, roughly 3% of the 72 GW that governments had collectively targeted for that year (IEA, 2026). Meanwhile, venture capital investment in hydrogen and e-fuel startups topped $4.8 billion in 2025, a 34% increase over 2024, according to BloombergNEF. That stark gap between installed reality and funded ambition captures the central challenge facing hydrogen and e-fuels: a technology category where the hype cycle consistently outruns deployment. For founders, investors, and policymakers in the UK and across Europe, understanding which narratives hold up to scrutiny and which do not is critical for capital allocation and strategic planning.

Why It Matters

The UK government's Hydrogen Strategy, updated in 2025, targets 10 GW of low-carbon hydrogen production capacity by 2030. The EU's REPowerEU plan targets 10 million tonnes of domestic green hydrogen production and 10 million tonnes of imports by the same date. Germany alone has committed over EUR 9 billion in public funding for hydrogen infrastructure. These are not marginal policy experiments: they represent industrial policy commitments that will shape energy systems, trade flows, and competitive dynamics for decades.

Yet the policy ambition rests on assumptions about cost trajectories, infrastructure timelines, and end-use economics that deserve careful examination. The Hydrogen Council projected in 2020 that green hydrogen would reach $1.50/kg by 2030. As of early 2026, the most competitive projects in regions with excellent renewable resources (Chile, Middle East, Australia) are producing at $3.50 to $5.00/kg, and European production costs remain in the $5.00 to $8.00/kg range (BNEF, 2026). Getting the myths right matters because billions in public and private capital are being allocated based on narratives that may not match the evidence.

Key Concepts

Hydrogen comes in several production pathways, commonly designated by colour. Grey hydrogen is produced from natural gas via steam methane reforming (SMR) without carbon capture and accounts for roughly 95% of current global production. Blue hydrogen adds carbon capture and storage (CCS) to the SMR process. Green hydrogen uses renewable electricity to power electrolysers that split water into hydrogen and oxygen. Pink or red hydrogen uses nuclear electricity for electrolysis.

E-fuels (also called synthetic fuels or power-to-X fuels) combine green hydrogen with captured CO2 to produce liquid hydrocarbons, methanol, or ammonia that can serve as drop-in replacements for fossil fuels in applications like aviation, shipping, and heavy transport. The appeal is compatibility with existing engines and infrastructure; the challenge is energy efficiency, since the conversion chain from electricity to hydrogen to synthetic fuel involves cumulative energy losses of 50 to 70%.

Myth 1: Green Hydrogen Is Already Cost-Competitive with Grey Hydrogen

This claim appears frequently in investor presentations and policy documents, usually extrapolated from projections rather than current production data. Grey hydrogen produced from natural gas costs approximately $1.00 to $2.50/kg depending on regional gas prices (IEA, 2026). Green hydrogen from dedicated renewable electricity costs $3.50 to $8.00/kg in most operational projects today.

The often-cited pathway to $1.50/kg green hydrogen by 2030 requires simultaneous achievement of multiple conditions: electrolyser capital costs falling below $300/kW (current costs are $700 to $1,400/kW for PEM electrolysers), capacity factors above 50%, and electricity prices below $20/MWh. S&P Global Commodity Insights found in a 2025 analysis that only 4% of announced green hydrogen projects globally have secured all three conditions simultaneously (S&P Global, 2025).

The practical correction: green hydrogen will likely reach cost parity with grey hydrogen in specific geographies (the Middle East, Chile, parts of Australia) by 2028 to 2030, and in Europe by 2032 to 2035 under favourable policy conditions. Founders building business models that assume sub-$2.00/kg green hydrogen in Europe before 2030 are building on optimistic assumptions that the data does not yet support.

Myth 2: Hydrogen Will Replace Natural Gas for Home Heating

The UK's now-cancelled hydrogen village trial in Redcar, originally planned to convert 2,000 homes to 100% hydrogen heating, was terminated in late 2023 after technical and economic analysis showed costs 2 to 3 times higher than heat pump alternatives for the same homes (DESNZ, 2024). A subsequent study by the UK Climate Change Committee found that hydrogen heating would require 5 to 6 times more renewable electricity per unit of delivered heat compared to heat pumps due to conversion losses in electrolysis and hydrogen boiler inefficiency (CCC, 2025).

Germany's Fraunhofer Institute reached similar conclusions in 2025, estimating that heating a typical German household with green hydrogen would cost EUR 3,800 to EUR 5,200 per year, compared to EUR 1,200 to EUR 1,800 for a heat pump system (Fraunhofer ISE, 2025). The physics are unforgiving: electrolysis is approximately 65 to 70% efficient, hydrogen distribution adds further losses, and hydrogen boilers convert fuel to heat at roughly 85 to 90% efficiency. The total chain efficiency is around 50%, compared to 300 to 400% effective efficiency for heat pumps that move ambient heat rather than generating it.

The evidence supports hydrogen for home heating only in niche scenarios: off-grid properties where electricity infrastructure upgrades are prohibitively expensive, or buildings with heritage protections that prevent external heat pump installations. For the vast majority of residential heating, electrification via heat pumps is both cheaper and more energy-efficient.

Myth 3: E-Fuels Can Decarbonise Road Transport at Scale

Porsche's Haru Oni pilot plant in Chile, backed by Siemens Energy and ExxonMobil, began producing e-methanol and e-gasoline in late 2022. Production volumes reached approximately 130,000 litres in 2025, enough to fuel roughly 1,000 cars for a year. The production cost is estimated at $45 to $55 per litre, compared to roughly $0.50 to $0.80 per litre for fossil gasoline at wholesale (Porsche, 2025).

Even with projected cost reductions, the energy economics of e-fuels for passenger vehicles are prohibitive. Driving 100 km on e-fuel requires approximately 5 times more renewable electricity than driving the same distance in a battery electric vehicle, because of cumulative losses in electrolysis, CO2 capture, fuel synthesis, and internal combustion engine inefficiency. Transport & Environment calculated in 2025 that powering Europe's passenger car fleet on e-fuels would require 2.5 times the EU's total current renewable electricity generation (T&E, 2025).

The practical correction: e-fuels have a legitimate role in sectors where direct electrification is technically impractical: long-haul aviation, international shipping, and potentially some categories of heavy industry. For road transport, where battery electric alternatives exist and are rapidly scaling, e-fuels represent an expensive and energy-inefficient detour. The EU's 2035 ICE ban with an exemption for e-fuels was a political compromise, not an economic or engineering endorsement.

Myth 4: Blue Hydrogen Is a Low-Carbon Bridge Fuel

Blue hydrogen's climate credentials depend entirely on the methane leakage rate across the natural gas supply chain and the CCS capture rate. A landmark 2021 study by Howarth and Jacobson at Cornell University found that when upstream methane leakage of 3.5% (the US average at the time) was included, blue hydrogen's lifecycle greenhouse gas emissions were only 9 to 12% lower than grey hydrogen's (Howarth & Jacobson, 2021).

The situation has improved somewhat since then. The best-performing blue hydrogen facilities, such as Shell's Quest project in Alberta, achieve CCS capture rates of 80% on process emissions and report upstream methane leakage rates below 1.5%. Under these conditions, lifecycle emissions are approximately 50 to 60% lower than grey hydrogen (Shell, 2025). But these are best-in-class results, and the industry average remains far higher.

The UK's National Infrastructure Commission found in 2025 that only 3 of 11 proposed UK blue hydrogen projects had secured CCS storage capacity with independently verified capture rates above 90%. The remaining projects relied on estimated capture rates and had not completed geological storage characterisation (NIC, 2025).

The correction: blue hydrogen with high capture rates and low upstream methane leakage is meaningfully lower-carbon than grey hydrogen, but claims of "low-carbon" or "clean" blue hydrogen should always be evaluated against verified lifecycle emissions data rather than nameplate capture rates.

Myth 5: The Hydrogen Economy Just Needs More Subsidies to Take Off

The UK's Hydrogen Production Business Model (HPBM) contracts, modelled on Contracts for Difference used in offshore wind, have allocated GBP 2.1 billion in support to 11 projects. Germany's H2Global mechanism has committed EUR 4.4 billion in subsidies for hydrogen imports. The US Inflation Reduction Act provides a production tax credit of up to $3.00/kg for green hydrogen.

Despite this subsidy environment, final investment decisions remain scarce. The Hydrogen Council reported in 2025 that only 12% of announced green hydrogen projects globally had reached FID, and only 4% were under construction (Hydrogen Council, 2025). The bottleneck is not subsidy availability but rather the simultaneous challenges of offtake certainty, infrastructure buildout, and regulatory clarity.

ITM Power, a Sheffield-based electrolyser manufacturer, reported in its 2025 annual results that order intake had slowed despite strong subsidy signals, citing customer uncertainty about hydrogen transport infrastructure and end-use regulation as the primary barriers. The company noted that subsidies address production cost gaps but do not solve the chicken-and-egg problem of hydrogen demand and supply infrastructure needing to develop simultaneously (ITM Power, 2025).

What's Working

INEOS's Inovyn facility in Runcorn, UK, operates the largest PEM electrolyser in Europe at 20 MW and has demonstrated consistent production at $4.80/kg, with a clear pathway to $3.50/kg as it scales to 100 MW by 2027 (INEOS, 2025). The project benefits from on-site chlorine production that creates a guaranteed internal offtake for hydrogen.

Maersk's order of 19 methanol-fuelled container ships, with 6 delivered by early 2026, represents the most significant commercial commitment to e-fuels in shipping. The vessels are dual-fuel capable, reducing technology risk, and Maersk has signed green methanol offtake agreements totalling 730,000 tonnes annually (Maersk, 2025).

The H2 Green Steel project in Boden, Sweden, reached FID in 2024 and is constructing a 2.5 million tonne per year steel plant using green hydrogen for direct reduced iron. The project has secured EUR 6.5 billion in financing and offtake agreements with major automotive manufacturers (H2 Green Steel, 2025).

What's Not Working

Hydrogen pipeline infrastructure remains a critical bottleneck. The European Hydrogen Backbone initiative, a consortium of 33 gas transmission operators, plans 53,000 km of dedicated hydrogen pipelines by 2040, but only 1,600 km of repurposed natural gas pipeline was operational by early 2026 (EHB, 2026). Without transport infrastructure, producers and consumers cannot connect even when production subsidies close the cost gap.

Electrolyser manufacturing capacity has expanded rapidly, but utilisation rates are low. BloombergNEF reported that global electrolyser factories operated at just 25% of nameplate capacity in 2025 due to slow project FIDs (BNEF, 2026). This creates financial pressure on manufacturers like ITM Power and Nel ASA, potentially leading to industry consolidation before the market matures.

Green hydrogen certification and guarantees of origin remain fragmented across jurisdictions, creating regulatory uncertainty for cross-border trade. The EU's Delegated Acts on Renewable Fuels of Non-Biological Origin (RFNBOs) impose strict additionality and temporal correlation requirements that many producers have struggled to meet, and the UK has not yet finalised equivalent standards.

Key Players

Established Companies

• INEOS Inovyn: operates Europe's largest PEM electrolyser at Runcorn, UK, with expansion plans to 100 MW
• Shell: operates the Quest blue hydrogen and CCS facility in Alberta and is developing multiple green hydrogen projects in Europe
• Siemens Energy: major electrolyser manufacturer supplying PEM technology to large-scale projects globally
• Maersk: leading the commercial adoption of green methanol as a shipping fuel with 19 dual-fuel vessels ordered

Startups

• H2 Green Steel: building a fully integrated green hydrogen-powered steel plant in Sweden with EUR 6.5 billion in financing
• ITM Power: Sheffield-based PEM electrolyser manufacturer scaling gigawatt-level production capacity
• HiiROC: UK startup developing thermal plasma electrolysis technology for low-cost turquoise hydrogen from methane
• Sunfire: Dresden-based developer of solid oxide electrolysers (SOEC) for high-efficiency green hydrogen production

Investors

• Breakthrough Energy Ventures: invested in multiple hydrogen and e-fuel startups including H2 Green Steel and Koloma
• AP Moller Holding: anchor investor in H2 Green Steel and backer of Maersk's green methanol strategy
• Hy24: the world's largest clean hydrogen investment fund with EUR 2 billion under management, backed by Air Liquide and TotalEnergies

Action Checklist

• Pressure-test hydrogen cost assumptions in your business model against current production data ($3.50 to $8.00/kg for green hydrogen in Europe) rather than projected 2030 costs
• Map your target end-use application against the electrification alternative to confirm hydrogen is the right energy vector for your specific use case
• Verify blue hydrogen lifecycle emissions claims by requesting upstream methane leakage data and independently audited CCS capture rates
• Assess hydrogen transport infrastructure availability along your planned supply routes before committing to production investments
• For e-fuel projects, secure long-term offtake agreements in hard-to-abate sectors (aviation, shipping) rather than competing with battery electric alternatives in road transport
• Monitor UK HPBM contract awards and EU RFNBO certification developments to align project timelines with regulatory milestones
• Evaluate electrolyser technology options (PEM vs alkaline vs SOEC) against your specific operating profile: capacity factor, ramp requirements, and heat integration opportunities

FAQ

Q: Is green hydrogen a good investment for UK-based founders in 2026? A: The opportunity is real but highly sector-dependent. The strongest near-term business cases are in industrial applications where hydrogen replaces grey hydrogen already in use (refineries, ammonia production, steel) and in maritime fuels where Maersk and others have created demand signals. Residential heating and passenger transport are not viable target markets for hydrogen-based solutions given cheaper electrification alternatives. Founders should focus on applications where hydrogen is the only viable decarbonisation pathway, not where it competes with batteries or heat pumps.

Q: Will e-fuels ever be affordable enough for widespread use? A: Cost projections suggest e-fuels could reach $1.50 to $2.50 per litre by 2035 in regions with cheap renewable electricity, compared to current costs of $15 to $55 per litre depending on the production pathway. At those projected prices, e-fuels become viable for aviation (where jet fuel currently costs $0.60 to $0.90/litre but faces rising carbon costs) and shipping. Widespread use in road transport remains unlikely because battery electric vehicles will continue to be 3 to 5 times more energy-efficient per kilometre.

Q: Should companies invest in blue hydrogen as a transition strategy? A: Blue hydrogen makes strategic sense only where three conditions are met: access to low-cost natural gas with verified low upstream methane leakage (below 1%), proximity to geological CO2 storage with proven containment, and an industrial offtaker that needs hydrogen at scale today and cannot wait for green hydrogen costs to decline. Without all three conditions, the lifecycle emissions reduction may not justify the capital expenditure.

Q: How should investors evaluate hydrogen project risk in 2026? A: The three highest-risk factors for hydrogen projects are offtake uncertainty, infrastructure availability, and regulatory timeline risk. Projects with binding offtake agreements, co-located production and consumption (eliminating transport risk), and alignment with existing subsidy mechanisms (UK HPBM, US 45V, EU IPCEI) carry significantly lower risk profiles. Electrolyser technology risk has largely been resolved for alkaline and PEM systems; the remaining risks are commercial and infrastructural rather than technical.

Sources

• IEA. (2026). Global Hydrogen Review 2026. Paris: International Energy Agency.
• BloombergNEF. (2026). Hydrogen Market Outlook Q1 2026. London: Bloomberg Finance L.P.
• S&P Global Commodity Insights. (2025). Green Hydrogen Cost Assessment: Global Project Pipeline Analysis. London: S&P Global.
• UK Climate Change Committee. (2025). Progress in Reducing Emissions: 2025 Report to Parliament. London: CCC.
• Fraunhofer ISE. (2025). Heating Technology Comparison: Cost and Efficiency Analysis for European Building Stock. Freiburg: Fraunhofer Institute for Solar Energy Systems.
• Transport & Environment. (2025). E-fuels: Too Expensive, Too Late, Too Inefficient for Cars. Brussels: Transport & Environment.
• Howarth, R. W. & Jacobson, M. Z. (2021). "How green is blue hydrogen?" Energy Science & Engineering, 9(10), 1676-1687.
• Hydrogen Council. (2025). Hydrogen Insights 2025: Global Project Pipeline and Investment Tracker. Brussels: Hydrogen Council.
• ITM Power. (2025). Annual Report and Accounts 2025. Sheffield: ITM Power PLC.