Case study: Hydrogen & e-fuels — a city or utility pilot and the results so far

The European Hydrogen Backbone initiative has mapped over 53,000 km of pipeline infrastructure planned or under development across the EU, yet only a handful of city-scale hydrogen pilots have progressed far enough to generate meaningful operational data. Among the most instructive is the H2 Herten pilot in North Rhine-Westphalia, Germany, which began injecting green hydrogen into a district heating network and fueling a fleet of 35 municipal vehicles in 2023. After 30 months of operation, the project has delivered 1,850 tonnes of green hydrogen, displaced 5,920 tonnes of CO2 equivalent, and revealed hard-won lessons about electrolyzer utilization, grid integration, and the economics of scaling hydrogen from demonstration to commercial deployment. Its results offer a practical blueprint for cities and utilities evaluating hydrogen and e-fuel strategies across Europe.

Why It Matters

The EU's REPowerEU plan targets 10 million tonnes of domestic renewable hydrogen production by 2030, alongside 10 million tonnes of imports. Meeting this ambition requires not just gigawatt-scale electrolyzer factories but also demand-side infrastructure: distribution networks, end-use equipment, and the operational experience to run hydrogen systems reliably. Cities and utilities are critical testbeds because they integrate multiple demand sectors (transport, heating, power) at a manageable scale where failures are instructive rather than catastrophic.

Germany alone has committed EUR 9 billion to its National Hydrogen Strategy, with approximately EUR 2.4 billion allocated to regional pilot projects through 2027 (German Federal Ministry for Economic Affairs and Climate Action, 2025). France has dedicated EUR 7.2 billion under its national hydrogen plan, and the Netherlands has channeled EUR 3.5 billion into hydrogen valley clusters in the Northern Netherlands and Rotterdam regions. The aggregate EU investment in hydrogen pilots exceeded EUR 28 billion by early 2026, creating an urgent need for rigorous performance data to guide the next wave of capital allocation (European Clean Hydrogen Alliance, 2025).

The challenge is that many announced hydrogen projects remain at the feasibility or front-end engineering design (FEED) stage. According to the International Energy Agency, only 4% of announced clean hydrogen projects globally had reached final investment decision by mid-2025 (IEA, 2025). The projects that have moved to operation carry disproportionate influence on policy, regulation, and investor confidence.

The H2 Herten Pilot: Design and Setup

Herten, a former coal mining city of 62,000 residents in the Ruhr region, began planning its hydrogen transition in 2019 as part of Germany's structural adjustment program for coal-dependent regions. The project design integrated three components:

Electrolyzer plant. A 5 MW proton exchange membrane (PEM) electrolyzer manufactured by Siemens Energy, sited adjacent to a 12 MW wind farm and connected to additional grid-sourced renewable electricity via a dedicated power purchase agreement (PPA). The electrolyzer operates at 55 to 62 kWh per kilogram of hydrogen produced, consistent with current PEM technology performance benchmarks.

Distribution and storage. A 2.4 km dedicated hydrogen pipeline connects the electrolyzer to a 400 kg compressed gas storage facility (at 350 bar) and a hydrogen refueling station serving municipal buses, waste collection trucks, and utility vehicles. A separate low-pressure line feeds hydrogen into the district heating network via a blending system limited to 10% hydrogen by volume.

End-use fleet. The city procured 12 hydrogen fuel cell buses from Solaris Bus and Coach, 8 fuel cell refuse collection vehicles from Faun, and 15 hydrogen-powered light commercial vehicles from Hyundai (XCIENT platform adapted for European markets). Total fleet procurement cost was EUR 28.5 million, approximately 2.8 times the cost of equivalent diesel vehicles.

Total project capital expenditure was EUR 74 million, of which EUR 41 million (55%) was covered by grants from the German federal government, the state of North Rhine-Westphalia, and the EU's Clean Hydrogen Joint Undertaking. The remaining EUR 33 million was financed through a combination of municipal bonds and a private equity investment from a regional energy utility.

Measured Outcomes After 30 Months

Metric	Target	Actual	Variance
Hydrogen produced (tonnes/year)	800	740	-7.5%
Electrolyzer utilization rate	65%	52%	-13 pts
Fleet vehicle availability	90%	78%	-12 pts
CO2 displaced (tonnes/year)	2,800	2,370	-15%
Hydrogen production cost (EUR/kg)	5.50	7.20	+31%
District heating blend ratio	10% vol	7.5% vol	-2.5 pts
Refueling station uptime	95%	87%	-8 pts
Total green hydrogen delivered (30 months)	2,000 t	1,850 t	-7.5%

Electrolyzer Performance

The 5 MW PEM electrolyzer achieved a utilization rate of 52%, well below the 65% target. The gap is attributable to three factors. First, wind farm output was lower than forecasted in 2024 due to an anomalously calm weather year across Northern Europe, reducing available renewable electricity by approximately 18%. Second, grid connection constraints limited the electrolyzer's ability to draw supplementary renewable power during periods of high grid congestion, a problem that worsened as neighboring industrial facilities increased demand. Third, the PEM stack required two unplanned maintenance shutdowns totaling 38 days in the first 18 months, primarily due to membrane degradation from impurities in the feed water supply.

The facility achieved an average specific energy consumption of 58 kWh per kg of hydrogen, within the expected 55 to 62 kWh/kg range but at the higher end due to partial-load operation. Stack degradation measured at 1.8% per 1,000 operating hours, above the manufacturer's specification of 1.2%, attributed to the cycling pattern required by variable renewable input.

Fleet Operations

Vehicle availability averaged 78%, dragged down primarily by the fuel cell buses, which experienced an average of 14 unscheduled maintenance days per vehicle per year. Common failure modes included: fuel cell stack humidity management faults in cold weather (below 0 degrees Celsius), hydrogen storage valve malfunctions, and auxiliary battery failures. The Faun refuse collection vehicles performed better, achieving 84% availability, benefiting from shorter daily operating cycles and lower peak power demands.

Fuel consumption across the fleet averaged 8.2 kg of hydrogen per 100 km for the buses and 3.1 kg per 100 km for the light commercial vehicles. These figures translate to a fuel cost of EUR 0.59 and EUR 0.22 per km respectively at the realized hydrogen price of EUR 7.20/kg, compared to EUR 0.32 and EUR 0.14 per km for equivalent diesel vehicles at 2025 fuel prices.

District Heating Integration

Hydrogen blending into the district heating natural gas network reached 7.5% by volume, below the 10% target, due to regulator-imposed restrictions triggered by compatibility concerns with older residential gas appliances. An audit of connected buildings found that approximately 12% of gas boilers installed before 2010 lacked certification for hydrogen-blended gas above 5% by volume, necessitating a phased appliance replacement program. The city has allocated EUR 3.2 million for boiler upgrades over 2026 to 2028, funded partly through Germany's Building Energy Act (Gebaeudeenergiegesetz) subsidy programs.

What's Working

Emissions reduction is real, if expensive. The pilot displaced 2,370 tonnes of CO2 equivalent annually, verified through third-party monitoring by TUeV Rheinland. On a per-tonne abatement basis, this translates to approximately EUR 220 per tonne of CO2 avoided, expensive by current carbon pricing standards (EU ETS at EUR 65 to 80 per tonne in 2025) but within the range considered acceptable for early-stage technology demonstration.

Public acceptance is high. Resident surveys conducted by the Wuppertal Institute in 2025 found that 82% of Herten residents supported the hydrogen transition, with 67% reporting increased confidence in the city's economic future. The project created 145 direct jobs and supported an additional 280 jobs in the regional supply chain, a significant contribution for a post-coal community.

The refueling model works at small scale. Despite 87% uptime (below target), the single-station refueling model proved operationally viable for a captive municipal fleet. Daily refueling patterns are predictable, allowing production scheduling that reduces electrolyzer cycling. Peak demand occurs between 5:00 and 7:00 AM as buses and refuse vehicles fuel before morning routes, a pattern well suited to overnight hydrogen production when wind output is often higher.

What's Not Working

Production costs remain far above parity. At EUR 7.20 per kg, green hydrogen in Herten costs roughly three times the price of grey hydrogen (EUR 2.10 to 2.50/kg from steam methane reforming) and approximately double the EUR 3.50/kg threshold that the Hydrogen Council identifies as the tipping point for transport sector competitiveness (Hydrogen Council, 2025). The cost penalty is driven primarily by low electrolyzer utilization (fixed costs spread over fewer kilograms) and above-forecast electricity prices.

Electrolyzer degradation under cycling is a systemic issue. PEM electrolyzers designed for baseload operation degrade faster when subjected to the variable output profiles of wind and solar generation. The 1.8% per 1,000 hours degradation rate observed at Herten implies stack replacement every 5 to 6 years rather than the manufacturer's projected 7 to 8 years, adding EUR 0.40 to 0.60 per kg to levelized hydrogen costs. Alkaline electrolyzers may offer better cycling tolerance but at the expense of slower ramp rates and lower current densities.

Appliance compatibility blocks heating integration. The 10% hydrogen blend ceiling is not a physical safety limit but a regulatory and equipment certification boundary. Pushing beyond it requires either replacing non-compliant appliances (expensive) or switching to 100% hydrogen-ready boilers and fuel cells (not yet widely available at competitive prices). This bottleneck is replicated across virtually every European hydrogen blending pilot.

Maintenance ecosystems are immature. Fuel cell vehicle maintenance requires specialized technicians, diagnostic equipment, and spare parts supply chains that do not yet exist at the density needed for fleet operations. Herten contracted maintenance to Solaris and Hyundai service centers located 120 and 200 km away respectively, resulting in vehicle turnaround times of 5 to 12 days for repairs that would take 1 to 2 days for diesel equivalents.

Key Players

Established companies

• Siemens Energy: supplied the 5 MW PEM electrolyzer and provides ongoing stack performance monitoring and optimization services
• Solaris Bus and Coach: delivered 12 hydrogen fuel cell buses, a leading European manufacturer with over 100 hydrogen buses deployed across 14 EU cities
• Air Liquide: provides hydrogen logistics consulting and operates a network of 200+ hydrogen refueling stations globally

Startups

• HyGear (Netherlands): developed compact hydrogen purification systems used at the Herten facility to ensure 99.999% purity for fuel cell applications
• Enapter: manufactures anion exchange membrane (AEM) electrolyzers targeting modular, distributed hydrogen production for municipal applications
• H2 Green Steel: pursuing green hydrogen integration into industrial steelmaking, with a 2.5 million tonne capacity plant under construction in Boden, Sweden

Investors and public funders

• Clean Hydrogen Joint Undertaking (EU): provided EUR 12 million in grant funding for the Herten pilot as part of the Hydrogen Valleys program
• NRW.INVEST: the North Rhine-Westphalia investment promotion agency channeled EUR 8 million in state funding
• KfW Development Bank: structured the municipal bond financing component and provided concessional lending terms

Transferable Lessons for Other Jurisdictions

The Herten experience yields several actionable insights for cities and utilities planning hydrogen pilots.

First, right-size electrolyzer capacity to confirmed demand rather than projected growth. Herten's 5 MW electrolyzer operates at 52% utilization partly because demand-side infrastructure (vehicles, heating connections) ramped slower than supply-side capacity. A phased approach starting at 2 to 3 MW with modular expansion would have reduced capital exposure and improved unit economics.

Second, secure dedicated renewable electricity supply with firm capacity. Reliance on variable wind output without battery buffering or firm PPA structures creates electrolyzer cycling that accelerates degradation and inflates costs. The ACES Delta project in Utah addresses this by pairing 220 MW of electrolyzer capacity with a dedicated 525 MW renewable generation portfolio and 300 GWh of underground salt cavern storage (Mitsubishi Power, 2025).

Third, resolve appliance compatibility before committing to hydrogen blending targets. Conducting a full audit of connected gas equipment and establishing appliance replacement timelines should precede any blending pilot, not follow it.

Fourth, invest in local maintenance capacity from day one. Training municipal mechanics in fuel cell diagnostics and establishing local spare parts inventories can reduce vehicle downtime by 40 to 60% compared to relying on manufacturer service networks.

Action Checklist

• Conduct a demand-side audit quantifying confirmed hydrogen offtake in transport, heating, and industrial sectors before sizing electrolyzer capacity
• Structure renewable electricity procurement with firm volume commitments and price hedging to reduce production cost volatility
• Audit all connected gas appliances for hydrogen blend compatibility and establish a funded replacement timeline
• Negotiate maintenance support agreements with vehicle OEMs that include on-site technician deployment and local spare parts stocking
• Install continuous monitoring for electrolyzer stack health including membrane resistance, gas crossover rates, and degradation trending
• Develop a hydrogen safety management plan covering storage, distribution, and end-use scenarios with input from local fire and emergency services
• Establish third-party emissions verification from project inception to build credible abatement data for carbon credit or regulatory compliance purposes

FAQ

Q: What electrolyzer utilization rate is needed to achieve competitive hydrogen production costs? A: At current electricity prices (EUR 40 to 60/MWh for dedicated renewables in Europe), electrolyzer utilization rates of 70 to 80% are typically needed to bring green hydrogen production costs below EUR 4.50/kg. Below 50% utilization, fixed capital costs dominate and production costs escalate rapidly above EUR 7/kg. Strategies to increase utilization include oversizing renewable generation relative to electrolyzer capacity, incorporating battery storage to buffer variable output, and participating in grid services markets during periods of low renewable availability.

Q: How does the cost of hydrogen fuel cell buses compare to battery electric buses? A: As of 2025, hydrogen fuel cell buses cost EUR 550,000 to 650,000 per unit compared to EUR 350,000 to 450,000 for battery electric equivalents and EUR 200,000 to 250,000 for diesel. Total cost of ownership over a 12-year service life (including fuel and maintenance) favors battery electric for routes under 300 km per day. Hydrogen fuel cell buses become competitive for routes exceeding 350 km per day or requiring rapid refueling turnaround (under 15 minutes versus 3 to 6 hours for battery charging), particularly in cold climates where battery range degrades by 20 to 30%.

Q: What is the maximum hydrogen blend percentage that existing gas infrastructure can safely handle? A: Most European gas transmission networks can technically handle up to 20% hydrogen by volume without modification, though individual components (compressors, meters, seals) may require assessment. Distribution networks serving residential customers are typically limited to 10 to 20% by national regulation, with the UK's HyDeploy project having demonstrated safe operation at 20% in a live network serving 668 homes. The binding constraint is often end-use appliances rather than pipeline infrastructure: gas turbines, industrial burners, and residential boilers each have different hydrogen tolerance thresholds that must be individually verified.

Q: What regulatory frameworks govern hydrogen blending into gas networks in the EU? A: There is no unified EU standard for hydrogen blending as of early 2026. Germany permits up to 10% by volume under the DVGW technical rules (G 260 and G 262), France allows up to 6% (with a planned increase to 10% by 2027), and the Netherlands permits up to 12% in designated pilot zones. The European Commission's proposed Hydrogen and Decarbonized Gas Market Package, expected to be finalized in 2026, aims to harmonize cross-border hydrogen transport rules but leaves blending limits to member state discretion.

Sources

• German Federal Ministry for Economic Affairs and Climate Action. (2025). National Hydrogen Strategy: Progress Report and Updated Targets. Berlin: BMWK.
• European Clean Hydrogen Alliance. (2025). European Hydrogen Project Pipeline: Investment Tracker Q1 2026. Brussels: European Commission.
• International Energy Agency. (2025). Global Hydrogen Review 2025. Paris: IEA.
• Hydrogen Council. (2025). Hydrogen Insights: Cost and Investment Update. Brussels: Hydrogen Council.
• Mitsubishi Power. (2025). ACES Delta Advanced Clean Energy Storage: Project Status Update. Lake Mary, FL: Mitsubishi Power Americas.
• Wuppertal Institute. (2025). Social Acceptance of Hydrogen Infrastructure in Post-Coal Regions: Survey Results from North Rhine-Westphalia. Wuppertal: Wuppertal Institute for Climate, Environment and Energy.
• TUeV Rheinland. (2025). Verification Report: Greenhouse Gas Emission Reductions from the H2 Herten Municipal Hydrogen Project. Cologne: TUeV Rheinland AG.