Myth-busting Hydrogen & e-fuels: 10 misconceptions holding teams back
Myths vs. realities, backed by recent evidence and practitioner experience. Focus on LCOH drivers, offtake contracts, and infrastructure bottlenecks.
At £6.69 per kilogram—the current UK levelized cost of hydrogen via alkaline electrolysis—green hydrogen remains nearly three times more expensive than its grey counterpart. Yet the UK government has committed £400 million in private capital to its first 11 hydrogen projects, targeting 10 GW of production capacity by 2030. For investors navigating this transition, distinguishing between persistent myths and emerging realities is essential. The gap between perceived barriers and actual market conditions determines which teams capture value and which remain paralyzed by outdated assumptions. This analysis examines ten common misconceptions that continue to hold back institutional capital, project developers, and industrial offtakers in the UK hydrogen and e-fuels sector.
The 10 Myths
1. Green hydrogen is too expensive to compete with fossil fuels
Reality: While current UK green hydrogen costs (£6-9/kg) exceed grey hydrogen (£1.50-2.50/kg), the trajectory matters more than the snapshot. The UK's Hydrogen Allocation Round 1 (HAR1) set strike prices averaging £241/MWh (~£9.50/kg), but industry analysis by RenewableUK and Hydrogen UK projects a 58% cost reduction to below £100/MWh by 2030 with policy implementation. Electricity represents approximately 70% of final green hydrogen cost—meaning falling renewable electricity prices directly translate to LCOH improvements. At wholesale electricity below £20-30/MWh (increasingly achievable during high-wind periods), green hydrogen approaches cost parity with grey alternatives.
2. The CfD mechanism for hydrogen is unproven and risky
Reality: The UK's Low Carbon Hydrogen Agreement (LCHA) structure adapts the proven Contract for Difference model that successfully reduced offshore wind costs by 70% over a decade. The mechanism provides 15-year revenue support covering the gap between production costs and market reference prices. By December 2024, the first three LCHAs were signed, with initial projects expected operational in 2025. HAR2 shortlisted 27 projects across England, Scotland, and Wales in April 2025 for up to 875 MW capacity. The regulatory architecture exists—what remains is execution risk, not design risk.
3. Hydrogen storage in the UK is impossible at scale
Reality: Geographic constraints exist but are not prohibitive. The UK possesses three discrete salt basins suitable for large-scale hydrogen storage, with theoretical upper-bound capacity of 64 million tonnes (2,150 TWh). Centrica's proposed Rough facility conversion—a £2 billion investment—could alone provide meaningful storage. Analysis suggests the UK requires approximately 8 TWh of hydrogen storage by 2035 and 7.7-9.7 TWh for power system integration by 2040. The bottleneck is business model finalization (the Hydrogen Storage Business Model allocation rounds were delayed to 2025), not geological feasibility.
4. Pipeline infrastructure will take decades to build
Reality: The 2030 pipeline requirement ranges from 100-1,000 km depending on hydrogen's role in power generation—a wide band reflecting policy uncertainty rather than technical barriers. The FutureGrid project is actively testing natural gas pipeline repurposing with HSE oversight, and many existing assets may be hydrogen-compatible with modifications. The government targets regional pipeline infrastructure operational by 2030, with the first Hydrogen Transport Business Model allocation round scheduled for 2025. The timeline is compressed but achievable.
5. There's no viable demand for hydrogen at meaningful scale
Reality: Industrial heat, ammonia production, steel manufacturing, and heavy transport represent proven demand segments. The UK steel sector alone—with decarbonization commitments from British Steel and Tata Steel—presents multi-gigawatt hydrogen demand. Maritime and aviation e-fuels add significant volume: the UK's Sustainable Aviation Fuel mandate (2% by 2025, 10% by 2030) creates guaranteed offtake. Willis Sustainable Fuels' 14 kt/year facility in Teesside and Alfanar Energy's 124 kt/year Lighthouse Green Fuels project demonstrate committed demand.
6. Electrolyser technology is immature and unreliable
Reality: Both PEM and alkaline electrolysis have achieved commercial maturity. ITM Power's Sheffield facility produces 1 GW/year of electrolyser capacity—the world's largest. Their NEPTUNE platform delivers 2 MW (NEPTUNE II) and 5 MW (NEPTUNE V) containerized units with proven reliability. Ceres Power's solid oxide electrolysis (SOEC) technology achieves <40 kWh/kg efficiency—25% more efficient than conventional electrolysis—and is now moving from demonstration to 100 MW+ commercial systems with partners including Shell and AtkinsRéalis.
7. E-fuels are a decade away from commercial viability
Reality: UK e-fuel projects are approaching commercial operation now. OXCCU's OX1 demonstration plant at Oxford Airport became operational in September 2024, producing synthetic aviation fuel via a novel single-step catalyst process. Zero Petroleum's Plant Zero.1—described as the world's first fully-featured synthetic fuel plant—opened in Oxford in 2024. Commercial-scale facilities including Willis Sustainable Fuels (2028), LanzaTech UK (2028), and OXCCU's OX2 at Hull (2026) are in construction or advanced development phases.
8. Hydrogen traceability and certification are unsolved problems
Reality: The UK Low Carbon Hydrogen Standard provides a certified framework for production emissions intensity. The CertifHy scheme offers EU-compatible green hydrogen certification. For e-fuels, the SAF Clearing House (safclearinghouse.uk) provides chain-of-custody tracking. Digital product passports and blockchain-based traceability systems are being piloted across multiple projects. The standards architecture is substantially complete; implementation and interoperability remain works in progress.
9. Critical minerals constraints make electrolyser scaling impossible
Reality: Platinum group metals (PGMs) for PEM electrolysis and nickel for alkaline systems face supply considerations, not absolute constraints. Technology roadmaps project 80% PGM reduction per unit capacity by 2030 through improved catalyst design. Alternative electrolyser chemistries—including SOEC and anion exchange membrane (AEM)—reduce or eliminate PGM requirements. Chinese electrolyser manufacturers offer equipment at approximately 75% lower cost than Western alternatives, reflecting both supply chain maturity and competitive dynamics.
10. First-mover disadvantage outweighs early-mover benefits
Reality: The CfD structure specifically rewards early movers through locked-in strike prices that may prove generous as production costs decline. HAR1 projects secured £241/MWh for 15 years—a rate that will likely exceed market prices substantially by the late 2020s. Infrastructure positioning, offtake relationship development, and operational learning curves compound over time. Late entrants will compete for constrained interconnection capacity and face established incumbents with cost advantages.
Why It Matters
The UK hydrogen sector represents a £48 billion investment opportunity through 2030, supporting an estimated 29,000 jobs (13,000 direct) according to Hydrogen UK's 2024 Economic Impact Assessment. For investors, the myths examined above translate directly into mispriced risk assessments. Teams that internalize outdated cost assumptions underweight LCOH improvement trajectories. Those paralyzed by infrastructure concerns miss first-mover CfD opportunities. The gap between perceived and actual risk creates alpha for investors who do the work to distinguish signal from noise.
The e-fuels segment amplifies these dynamics. With the UK SAF mandate creating guaranteed demand and revenue certainty mechanisms modeled on proven CfD structures, the sector transitions from speculative to bankable. The £63 million Advanced Fuels Fund allocation to 17 projects in July 2025 signals government commitment extending beyond rhetoric.
Key Concepts
| Concept | Definition | UK Benchmark (2024-2025) |
|---|---|---|
| LCOH | Levelized Cost of Hydrogen—fully-loaded production cost per kg | £6.69/kg (alkaline), £7+/kg (PEM) |
| Strike Price | CfD-equivalent contracted price in LCHA | £241/MWh (~£9.50/kg) HAR1 weighted avg |
| Electrolyser Efficiency | Energy consumption per kg H₂ produced | 52-56 kWh/kg typical |
| PtL | Power-to-Liquid—synthetic fuel production pathway | 0.2% UK mandate from 2028 |
| LCHA | Low Carbon Hydrogen Agreement—15-year revenue support contract | 3 signed December 2024 |
| HAR | Hydrogen Allocation Round—competitive process for LCHA awards | HAR1: 125 MW, HAR2: 875 MW target |
Sector-Specific KPI Table
| KPI | Definition | Target Range | Red Flag |
|---|---|---|---|
| LCOH | Production cost per kg | <£5/kg by 2030 | >£8/kg by 2028 |
| Electrolyser CAPEX | Installed cost per MW | <£400k/MW | >£800k/MW |
| Capacity Factor | Operational hours/total hours | >50% | <30% |
| Offtake Coverage | Contracted vs. production capacity | >70% | <40% |
| Grid Connection Timeline | Months from application to energization | <24 months | >48 months |
| Carbon Intensity | gCO₂e/MJ hydrogen | <20 (green), <40 (blue) | >80 |
What's Working
CfD Architecture Adaptation
The translation of proven renewable electricity CfD mechanisms to hydrogen production has created investable risk-return profiles. The 15-year LCHA duration provides bankability, while competitive allocation rounds drive cost reduction. HAR2's 27 shortlisted projects demonstrate market appetite.
Integrated Cluster Development
Projects combining production, storage, and industrial offtake within geographic clusters—particularly Teesside and Humberside—reduce transportation costs and counterparty risks. The HyNet cluster demonstrates this model, integrating hydrogen production with CCUS and industrial demand.
Strategic SAF Positioning
The UK's SAF mandate with revenue certainty mechanism creates a guaranteed demand wedge for e-fuels. First-mover projects (Zero Petroleum, OXCCU, Willis Sustainable Fuels) are positioning to capture mandate-driven volume with contracted pricing.
What's Not Working
Transport & Storage Business Model Delays
The Hydrogen Transport Business Model (HTBM) and Hydrogen Storage Business Model (HSBM) allocation rounds, originally planned for 2024, have slipped to 2025. This regulatory delay creates the "chicken and egg" problem: production projects await infrastructure, while infrastructure developers need demand certainty. Investment hesitation follows.
Grid Connection Bottlenecks
UK-wide grid interconnection queues affect hydrogen projects as severely as renewable generation. Wait times exceeding 36 months undermine project economics and CfD strike price assumptions based on earlier timelines.
Heating Role Uncertainty
Government consultation on hydrogen's role in residential heating remains unresolved. Policy clarity—expected in 2025—affects demand projections for pipeline infrastructure investment. Transmission-level blending decisions (under consultation in early 2025) compound this uncertainty.
Key Players
Established Leaders
| Company | Focus | Notable |
|---|---|---|
| ITM Power | PEM electrolyser manufacturing | 1 GW/year Sheffield factory; NEPTUNE platform |
| Ceres Power | Solid oxide electrolysis technology | 25% efficiency advantage; Shell partnership |
| bp | Integrated hydrogen production | H2Teesside blue hydrogen project |
| SSE | Hydrogen production and storage | Slough and Keadby projects |
| Centrica | Large-scale hydrogen storage | £2bn Rough facility conversion proposal |
Emerging Startups
| Company | Focus | Notable |
|---|---|---|
| Zero Petroleum | Synthetic aviation fuel | Plant Zero.1 operational; Airbus partnership |
| OXCCU | Single-step PtL catalyst | OX1 demo operational September 2024 |
| Hygen Energy | Hydrogen infrastructure | ITM Power preferred supplier |
| Bramble Energy | Printed fuel cells | Novel manufacturing approach |
| AFC Energy | Alkaline fuel cells | Industrial power applications |
Key Investors & Funders
| Organization | Focus | Notable |
|---|---|---|
| UK Infrastructure Bank | Project finance | Mandate includes hydrogen infrastructure |
| Net Zero Hydrogen Fund | Grant funding | £240m allocated across rounds |
| Breakthrough Energy Ventures | Climate tech VC | Multiple UK hydrogen investments |
| Legal & General | Infrastructure investment | Low-carbon energy portfolio |
| Octopus Energy Group | Renewable integration | Hydrogen-to-power interest |
Examples
ITM Power's Tees Green Hydrogen Project: ITM Power is delivering an 8 MW engineering integration package for Hynamics (EDF Renewables UK subsidiary) at Tees Valley, using four NEPTUNE II units. The project, supported by HAR1 and the Net Zero Hydrogen Fund, demonstrates the integration pathway from electrolyser manufacturing through to industrial hydrogen supply. Phase 1 engineering commenced in 2024, with the project targeting operations in 2025-2026.
OXCCU's Oxford Airport Demonstration: OXCCU's OX1 facility, operational since September 2024, produces synthetic aviation fuel at Oxford Airport using a novel single-step catalyst that converts biogenic CO₂ and green hydrogen directly to jet fuel. The process eliminates energy-intensive intermediate steps in conventional Power-to-Liquid pathways. A commercial-scale OX2 facility at Saltend (Hull) targeting 9+ million litres/year is planned for 2026, with partnership from px Group.
Centrica's Rough Storage Conversion: Centrica's proposal to convert the Rough gas storage facility in the North Sea for hydrogen storage represents a £2 billion investment opportunity. Analysis indicates that operational hydrogen storage of this scale could have saved £5 billion during the 2021-2022 energy crisis and could reduce customer energy costs by £1 billion annually by 2050. The project awaits finalization of the Hydrogen Storage Business Model.
Action Checklist
- Update LCOH assumptions in investment models using 2024-2025 data (current: £6-9/kg; 2030 projection: £3-5/kg)
- Track HAR2 allocation outcomes and HAR3 design consultations for capacity planning
- Assess grid connection timelines for target geographies before committing capital
- Evaluate offtake contract structures for 70%+ production coverage before final investment decision
- Map critical minerals exposure in electrolyser supply chain with technology-specific analysis
- Monitor HTBM and HSBM allocation round timelines for infrastructure investment opportunities
- Review SAF mandate compliance pathways for e-fuel investment thesis alignment
- Engage with cluster development initiatives (Teesside, Humberside, HyNet) for integrated project access
FAQ
Q: What is the realistic timeline for green hydrogen cost parity with grey hydrogen in the UK? A: Based on current trajectories, green hydrogen could approach £3-5/kg by 2030—still above grey hydrogen (£1.50-2.50/kg) but competitive when carbon pricing exceeds £100/tonne CO₂. True cost parity likely arrives 2032-2035, though specific industrial applications with high carbon pricing or supply chain requirements may see earlier crossover.
Q: How should investors evaluate hydrogen project offtake risk? A: Focus on three metrics: contracted offtake percentage (target >70% of production capacity), counterparty creditworthiness, and contract duration relative to LCHA terms. Projects with industrial anchor tenants (steel, chemicals, refining) present lower demand risk than those dependent on mobility or heating offtake, which face infrastructure and policy uncertainty.
Q: Are UK electrolyser manufacturers competitive with Chinese alternatives? A: Chinese manufacturers offer equipment at approximately 75% lower cost, creating competitive pressure. However, UK projects benefit from domestic supply chain preferences in government-supported schemes, and technology differentiation (particularly Ceres Power's SOEC efficiency advantage) creates value beyond pure cost. For HAR-supported projects, supply chain requirements and lifecycle emissions considerations favour UK/European equipment.
Q: What distinguishes viable e-fuel projects from speculative ventures? A: Three markers: secured green hydrogen supply at known cost, validated carbon capture or biogenic CO₂ source, and contracted offtake with mandate-compliant buyers. Projects meeting all three—such as OXCCU and Zero Petroleum—are commercially de-risked. Projects lacking any element remain pre-commercial.
Q: How material is the grid connection bottleneck for hydrogen project economics? A: Highly material. Connection delays exceeding 24 months erode CfD strike price margins as construction costs accumulate without revenue. Projects should stress-test economics against 36-48 month connection scenarios and prioritize sites with existing or accelerated grid access paths.
Sources
- UK Government Department for Energy Security and Net Zero, "Hydrogen Strategy Update to the Market: December 2024"
- European Hydrogen Observatory, "Levelised Cost of Hydrogen Calculator," June 2024
- RenewableUK and Hydrogen UK, "Key Measures to Drive Down Green Hydrogen Production Costs," 2024
- Hydrogen UK, "Economic Impact Assessment for the Hydrogen Sector to 2030," April 2024
- UK Government, "Hydrogen Transport and Storage Networks Pathway," 2024
- UK House of Commons Library, "Sustainable Aviation Fuel Bill 2024-25," CBP-10279
- ITM Power, Corporate Announcements and Product Documentation, 2024-2025
- Ceres Power, Corporate Announcements and Technology Publications, 2024-2025
- Oxford Institute for Energy Studies, "Can UK Green Hydrogen CfD Match the Cost-Saving Success of Renewable Electricity?," October 2024
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