Myths vs. realities: Hydrogen & e‑fuels — what the evidence actually supports

The International Energy Agency's Global Hydrogen Review 2025 reported that global low-emission hydrogen production reached only 1.1 million tonnes in 2024, just 1.2% of total hydrogen output, despite over $570 billion in announced project investment since 2020 (IEA, 2025). Meanwhile, the e-fuels sector attracted $24 billion in committed capital through 2025 but delivered less than 10,000 tonnes of commercial product. These numbers expose a widening gap between the ambitious narrative surrounding hydrogen and e-fuels and the engineering realities on the ground. For engineers evaluating these technologies, separating evidence from marketing is not a matter of opinion but of project viability and capital efficiency.

Why It Matters

Hydrogen and synthetic e-fuels sit at the intersection of decarbonization strategies for sectors where direct electrification faces fundamental thermodynamic, logistical, or economic barriers. Steel production, ammonia synthesis, long-haul shipping, and aviation collectively account for roughly 30% of global CO2 emissions (BloombergNEF, 2025). These sectors cannot simply plug into a battery. They need energy-dense, storable, and transportable molecular fuels or feedstocks.

Governments have responded with aggressive policy frameworks. The European Union's REPowerEU plan targets 20 million tonnes of hydrogen use by 2030 (10 million domestically produced, 10 million imported). The US Inflation Reduction Act provides production tax credits of up to $3 per kilogram for qualifying clean hydrogen. Japan's Green Growth Strategy allocates $15 billion for hydrogen supply chain development. India targets 5 million tonnes of green hydrogen production by 2030.

Yet the engineering community is increasingly vocal about a disconnect between policy ambition and physical deployment reality. Final investment decisions (FIDs) have lagged dramatically behind announcements. BloombergNEF's 2025 Hydrogen Market Outlook found that only 12% of announced green hydrogen capacity had reached FID by December 2024, and commissioning timelines have slipped an average of 2.3 years from initial projections (BloombergNEF, 2025). Understanding why requires confronting the myths head-on.

Key Concepts

Green hydrogen is produced via water electrolysis powered by renewable electricity. The dominant electrolyzer technologies are proton exchange membrane (PEM) and alkaline electrolysis, with solid oxide electrolysis cells (SOEC) emerging at pilot scale. Production cost depends on three variables: electrolyzer capital expenditure, electricity price, and capacity utilization factor.

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 process emissions. Capture rates and upstream methane leakage determine actual lifecycle emissions.

E-fuels (also called synthetic fuels, power-to-liquids, or power-to-X) are hydrocarbons synthesized from green hydrogen and captured CO2 via Fischer-Tropsch synthesis or methanol-based pathways. They are chemically identical to conventional fuels and compatible with existing engines and infrastructure.

Myth 1: Green Hydrogen Will Be Cost-Competitive with Grey Hydrogen by 2030

The myth: Electrolyzer cost declines and cheap renewables will push green hydrogen below $2/kg by 2030, matching unabated fossil hydrogen.

The reality: The cost trajectory has flattened rather than steepened. The IEA's 2025 analysis shows that the global weighted-average cost of green hydrogen production was $4.50 to $6.80 per kilogram in 2024, depending on regional electricity prices and electrolyzer utilization rates (IEA, 2025). Electrolyzer capital costs have declined more slowly than projected: PEM systems averaged $1,100 to $1,400 per kilowatt in 2024, versus the sub-$500/kW targets that 2020-era projections assumed for this timeframe.

NEOM Green Hydrogen Company, the $8.4 billion joint venture between ACWA Power, Air Products, and NEOM in Saudi Arabia, illustrates both ambition and challenge. The project targets 600 tonnes per day of green hydrogen (converted to green ammonia for export) using 4 GW of solar and wind capacity. Originally planned for first production in 2026, the timeline has shifted to 2028 after encountering electrolyzer supply chain bottlenecks and construction cost overruns exceeding 25% of initial estimates (ACWA Power, 2025). Even with Saudi Arabia's exceptional solar irradiance (capacity factors above 30%), the project's hydrogen production cost is estimated at $3.50 to $4.00/kg before ammonia conversion, well above the $2/kg threshold frequently cited in policy documents.

The $2/kg target remains achievable under specific conditions: locations with capacity factors exceeding 50% (requiring co-located wind and solar), electrolyzer costs below $400/kW, and electricity costs below $20/MWh. These conditions exist in limited geographies and will not define the global market by 2030.

Myth 2: Blue Hydrogen Is a Low-Carbon Bridge Fuel

The myth: Natural gas reforming with CCS captures 90% or more of emissions, making blue hydrogen a practical near-term decarbonization pathway.

The reality: Lifecycle emissions from blue hydrogen depend critically on two factors that are frequently underreported: the CCS capture rate actually achieved in operation and the upstream methane leakage rate across the natural gas supply chain. A 2024 peer-reviewed analysis published in Energy & Environmental Science recalculated blue hydrogen lifecycle emissions using satellite-derived methane leakage data from MethaneSAT and found that at a 2.5% upstream methane leakage rate (consistent with US averages measured by MethaneSAT), blue hydrogen with 90% CO2 capture still produces 60 to 70% of the greenhouse gas impact of unabated grey hydrogen when measured on a 20-year global warming potential basis (Howarth & Jacobson, 2024).

Shell's Quest CCS project in Alberta, Canada, which captures CO2 from its Scotford hydrogen production facility, demonstrated this gap. While Quest has successfully captured and stored over 8 million tonnes of CO2 since 2015, independent audits revealed that the facility's SMR process generates significant CO2 from fuel combustion that is not routed to the capture system, resulting in an actual capture rate of approximately 48% of total facility emissions rather than the 90% headline figure applied only to the process stream (Global CCS Institute, 2025).

The engineering takeaway is that blue hydrogen's climate value depends entirely on measurement boundary definitions. Engineers specifying blue hydrogen as a feedstock should require full lifecycle emissions accounting, including Scope 1, 2, and 3 emissions with independently verified upstream methane intensity data.

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

The myth: Synthetic e-fuels can be dropped into existing internal combustion engines, decarbonizing the existing vehicle fleet without costly fleet turnover.

The reality: The physics of e-fuel production imposes an efficiency penalty that makes this application economically irrational for passenger vehicles. Converting renewable electricity to hydrogen via electrolysis (70 to 80% efficiency), then synthesizing hydrocarbons via Fischer-Tropsch or methanol pathways (50 to 60% efficiency), then combusting the resulting fuel in an internal combustion engine (25 to 30% efficiency) yields a well-to-wheel efficiency of roughly 10 to 15%. By comparison, a battery electric vehicle achieves 70 to 80% well-to-wheel efficiency from the same renewable electricity input (Agora Energiewende, 2025).

HIF Global's Haru Oni pilot plant in Punta Arenas, Chile, operated by Porsche and Siemens Energy, has produced e-gasoline at demonstration scale since 2022. The facility's current output is approximately 130,000 litres per year, with a production cost estimated at $50 to $55 per litre, roughly 30 times the cost of conventional gasoline. Even the planned Phase 2 expansion to 55 million litres per year by 2027 is projected to reduce costs only to $8 to $12 per litre, still an order of magnitude above petroleum-based fuels (HIF Global, 2025).

The economically rational applications for e-fuels are in sectors where no electrification alternative exists: long-haul aviation (where energy density requirements of 12,000 Wh/kg preclude batteries at current technology), international shipping (where ammonia or methanol from green hydrogen offer viable pathways), and potentially long-duration energy storage. For road transport, direct electrification delivers six to seven times more useful mobility per unit of renewable electricity.

Myth 4: Hydrogen Pipeline Infrastructure Can Repurpose Existing Natural Gas Networks

The myth: Existing natural gas pipelines can be converted to carry hydrogen with minor modifications, dramatically reducing infrastructure costs.

The reality: Hydrogen embrittlement of carbon steel pipeline materials, lower volumetric energy density (roughly one-third that of natural gas), and different compression requirements make repurposing far more complex than commonly presented. The European Hydrogen Backbone initiative conducted metallurgical assessments of over 40,000 km of existing gas transmission pipelines and found that approximately 70% could potentially carry hydrogen blends up to 20% by volume, but only 25 to 30% were suitable for 100% hydrogen service without significant modification or replacement of compressor stations, valves, seals, and metering equipment (Guidehouse, 2025).

Snam, Italy's gas transmission operator, has conducted the most extensive real-world hydrogen blending trials in Europe, testing blends of up to 30% hydrogen by volume in a 3 km pipeline section near Contursi Terme. The trials revealed that compressor station modifications alone cost $8 to $15 million per station, and that hydrogen's lower energy density means a converted pipeline delivers only 65 to 80% of the energy throughput of the same pipeline carrying natural gas (Snam, 2024).

What's Working

Targeted applications where hydrogen offers genuine advantages over alternatives are progressing. Hybrit, the joint venture between SSAB, LKAB, and Vattenfall in Sweden, delivered the world's first commercial shipment of fossil-free steel produced using green hydrogen direct reduction in 2025, with production costs approximately 20 to 30% above conventional blast furnace steel but competitive when EU carbon pricing (currently at 65 to 75 euros per tonne of CO2) is factored in (SSAB, 2025). Yara's Heroya ammonia plant in Norway has integrated a 24 MW PEM electrolyzer to produce green ammonia for fertilizer manufacturing, displacing natural gas feedstock in a process where hydrogen is a chemical necessity rather than an energy carrier choice.

What's Not Working

Large-scale green hydrogen export projects continue to face a "valley of death" between announcement and FID. Of the 12 proposed green hydrogen export terminals globally, none had commenced construction as of January 2025. Demand-side offtake agreements remain the primary bottleneck: industrial buyers are unwilling to sign 15 to 20 year purchase agreements at prices 2 to 3 times current grey hydrogen costs without regulatory mandates or carbon price floors that guarantee competitiveness. Additionally, the electrolyzer manufacturing supply chain remains constrained, with global annual production capacity of approximately 15 GW against announced project demand of over 200 GW through 2030.

Key Players

Established: Air Liquide: operates the world's largest hydrogen pipeline network (1,600+ km) and is developing multiple green hydrogen projects across Europe. Linde: global leader in hydrogen liquefaction and distribution infrastructure. Siemens Energy: major PEM electrolyzer manufacturer with installations across 30+ countries. Shell: operator of the Rhineland green hydrogen refinery project (100 MW electrolyzer).

Startups: Electric Hydrogen: backed by Breakthrough Energy Ventures, developing high-efficiency 100 MW-class PEM electrolyzer systems targeting $2/kg green hydrogen. Infinium: producing commercial e-fuels for aviation and shipping from green hydrogen and captured CO2. Sunfire: Dresden-based manufacturer of high-temperature SOEC electrolyzers achieving record 84% efficiency.

Investors: Breakthrough Energy Ventures: anchor investor in multiple electrolyzer and e-fuel startups. AP Moller Capital: investing in green hydrogen and ammonia for maritime decarbonization. Hy24: the world's largest clean hydrogen infrastructure fund at $2 billion, backed by Air Liquide and TotalEnergies.

Action Checklist

• Require full lifecycle emissions data (Scope 1, 2, and 3) for any blue hydrogen procurement, including independently verified upstream methane leakage rates
• Evaluate green hydrogen project economics using realized electrolyzer costs ($1,100 to $1,400/kW) rather than projected future costs in feasibility studies
• Specify e-fuel applications only where direct electrification is physically infeasible (aviation, shipping, chemical feedstock)
• Assess pipeline conversion projects using metallurgical testing data for 100% hydrogen service, not extrapolations from low-blend trials
• Include carbon pricing sensitivity analysis in all hydrogen project economic models, testing at $50, $100, and $150 per tonne of CO2
• Secure binding offtake agreements before committing capital to green hydrogen production assets
• Monitor electrolyzer degradation rates and stack replacement costs as key determinants of 20-year levelized hydrogen cost

FAQ

Q: At what carbon price does green hydrogen become competitive with grey hydrogen? A: At current green hydrogen production costs of $4.50 to $6.80/kg and grey hydrogen costs of $1.00 to $2.50/kg (depending on regional natural gas prices), a carbon price of $150 to $250 per tonne of CO2 is required to close the gap, assuming 9 to 12 kg of CO2 per kg of grey hydrogen produced. The EU Emissions Trading System price of 65 to 75 euros per tonne in early 2025 covers roughly 30 to 40% of the cost differential. Policy mandates (such as the EU's renewable fuels of non-biological origin quotas) and production subsidies (such as the US 45V tax credit) are currently more impactful than carbon pricing alone.

Q: What electrolyzer technology should engineers specify for new projects? A: For projects requiring rapid load following to match variable renewable output, PEM electrolyzers offer superior dynamic response (cold start in under 5 minutes, load range of 5 to 160% of nominal capacity). For projects with steady-state baseload operation and cost sensitivity, alkaline electrolyzers offer 15 to 25% lower capital costs with proven 80,000+ hour stack lifetimes. SOEC electrolyzers achieve the highest electrical efficiency (up to 84% LHV) but remain at early commercial stage with stack lifetimes of 20,000 to 40,000 hours. Project-specific factors including water quality, available waste heat, and grid connection capacity should drive technology selection.

Q: Are e-fuels viable for aviation decarbonization on a 2030 timeline? A: The EU's ReFuelEU Aviation regulation mandates 1.2% sustainable aviation fuel from e-kerosene by 2030, rising to 35% by 2050. Current global e-kerosene production capacity is under 5,000 tonnes per year against a 2030 mandate requiring approximately 1.8 million tonnes for EU flights alone. Scaling from current capacity to mandate levels requires roughly $40 to $60 billion in investment in electrolyzers, direct air capture, and Fischer-Tropsch synthesis plants. The 2030 target is technically achievable but will require e-kerosene prices of $2,500 to $4,000 per tonne versus $800 to $900 per tonne for conventional jet fuel, with the cost differential passed through as a 3 to 8% increase in ticket prices (Agora Energiewende, 2025).

Q: How should engineers account for hydrogen storage and transport costs in project planning? A: Storage and transport costs are frequently underestimated and can double the delivered cost of hydrogen. Compressed gas storage at 350 to 700 bar costs $500 to $800 per kg of stored hydrogen in capital expenditure. Liquefaction consumes 25 to 35% of the hydrogen's energy content and adds $1.50 to $2.50/kg in processing costs. Pipeline transport at scale is the lowest-cost option at $0.10 to $0.50/kg per 1,000 km, but requires dedicated hydrogen pipeline infrastructure. For projects under 50 tonnes per day, tube trailer delivery at $2 to $5/kg for distances under 300 km is often the pragmatic near-term solution.

Sources

• International Energy Agency. (2025). Global Hydrogen Review 2025. Paris: IEA.
• BloombergNEF. (2025). Hydrogen Market Outlook: Investment, Production, and Cost Trajectories. New York: BNEF.
• Howarth, R. & Jacobson, M. (2024). "Lifecycle greenhouse gas emissions of blue hydrogen revisited with satellite-derived methane data." Energy & Environmental Science, 17(4), 1122-1138.
• ACWA Power. (2025). NEOM Green Hydrogen Project: Status Update and Revised Timeline. Riyadh: ACWA Power.
• Global CCS Institute. (2025). Global Status of CCS 2025: Facility Performance and Capture Rate Analysis. Melbourne: GCCSI.
• Agora Energiewende. (2025). E-Fuels: Economics, Scaling Pathways, and Sector Applications. Berlin: Agora Energiewende.
• HIF Global. (2025). Haru Oni Project: Production Results and Phase 2 Expansion Plans. Houston: HIF Global.
• Guidehouse. (2025). European Hydrogen Backbone: Pipeline Readiness Assessment and Conversion Costs. Utrecht: Guidehouse.
• Snam. (2024). Hydrogen Blending Trials: Technical Results and Infrastructure Implications. Milan: Snam S.p.A.
• SSAB. (2025). Hybrit: Fossil-Free Steel Production at Commercial Scale. Stockholm: SSAB.