Report Highlights

Who Controls This Market — And Who Is Threatening That Control

Nel Hydrogen holds the largest installed alkaline electrolyser base globally and the longest operational track record for large-scale AEL deployments, with reference plants including the 20 MW Everfuel installation at Herøya Industrial Park (Norway) and multiple refinery hydrogen supply contracts. Nel's competitive position is increasingly challenged by Chinese AEL systems at 40%–50% lower capital cost, compelling Nel to emphasise stack lifetime guarantee programmes (10-year performance warranties), European manufacturing for local content requirements, and the technical advantage of its large-diameter electrode design for high-pressure operation. Nel's strategic response — partnering with Statkraft for green hydrogen production and licensing its technology to manufacturing partners — reflects the difficulty of competing on capital cost alone against Chinese scale.

ThyssenKrupp nucera's AWE (Alkaline Water Electrolysis) technology in 20 MW standardised modules is the most commercially scaled large-format AEL system in Western manufacturing, with a 1 GW/year production capacity target at its Dortmund facility. ThyssenKrupp nucera's competitive position in the GW-scale green hydrogen project segment relies on modular standardisation — identical 20 MW stacks enabling efficient manufacturing and streamlined project engineering — and its TKIS industrial project delivery capability for multi-hundred-MW projects requiring EPC-level execution that pure technology vendors cannot provide. NEOM Green Hydrogen Company's 2 GW electrolyser procurement (awarded to ACWA Power, with ThyssenKrupp nucera as technology supplier) is the commercial reference case for the large-project segment.

ITM Power and Plug Power represent the PEM electrolyser segment's Western champions, with ITM's 1 GW/year Sheffield Gigafactory serving primarily European industrial decarbonisation projects and Plug Power's 1 GW/year Rochester NY facility serving the US market with IRA Section 45V credit support. PEM's advantages over AEL — dynamic response to variable renewable power, compact footprint, higher purity output — make it preferred for applications requiring rapid ramp-up and co-location with intermittent solar and wind. The PEM cost disadvantage (30%–50% higher than AEL at comparable MW) is narrowing as iridium catalyst loading decreases and Nafion membrane manufacturing scales.

Industry Snapshot

Global electrolyser installations reached approximately 800 MW in 2024, up from approximately 50 MW in 2019 — rapid growth in absolute percentage terms but still a fraction of the 100 GW+ of projects in development pipelines. The gap between announcement and financial close is the defining commercial challenge: global announced electrolyser project capacity exceeds 150 GW for projects targeting before 2030 commissioning, but IEA estimates only 4–5% of this pipeline has reached final investment decision. The primary bottleneck is offtake — buyers willing to pay a green hydrogen premium at the scale required to underwrite project finance are scarce.

Cost reduction trajectory is tracking the optimistic end of projections. Alkaline electrolyser capital cost has declined from USD 1,200–1,500/kW in 2019 to USD 500–800/kW in 2024 for utility-scale Western systems and USD 250–400/kW for Chinese AEL systems. PEM electrolyser capital cost has declined from USD 1,800–2,200/kW to USD 800–1,200/kW over the same period. IEA's modelled target of USD 200–300/kW for AEL and USD 300–400/kW for PEM by 2030, required to achieve USD 2/kg green hydrogen at high-capacity-factor renewable sites, is within trajectory range in China but requires continued learning curve progress and manufacturing scale-up in Western markets supported by policy mandates.

The Forces Accelerating Demand Right Now

The IRA's clean hydrogen production tax credit (Section 45V) at USD 3/kg for hydrogen produced at below 0.45 kg CO₂e/kg H₂ — the full clean hydrogen threshold — is the most significant policy driver for US electrolyser deployment. At USD 3/kg subsidy on hydrogen currently costing USD 5–8/kg to produce via electrolysis in the US, the effective subsidy covers 40%–60% of production cost, making green hydrogen economically competitive with grey hydrogen (USD 1.5–3/kg) in states with low-carbon electricity. The IRS final rule's hourly matching and additionality requirements create operational constraints (electrolysers must primarily use new renewable capacity, not existing grid power) that add cost but are achievable in projects co-located with new wind or solar, where IRA solar and wind PTCs provide complementary support.

The European Hydrogen Bank's first auction (April 2024) awarded EUR 720 million in fixed premium grants to 7 green hydrogen projects, providing EUR 0.48–1.07/kg premium above market hydrogen price for 10-year contract periods. The auction mechanism creates a price discovery function — revealing the actual minimum subsidy required to achieve financial close for green hydrogen projects in European conditions (currently EUR 0.48–1.07/kg, implying production costs of EUR 4–6/kg). Subsequent auction rounds (EUR 3+ billion planned by 2030) will progressively reveal the cost reduction trajectory as production technology improves, providing a real-world cost deflation signal that academic learning curve models cannot match.

What Is Holding This Market Back

Proton exchange membrane electrolysers use iridium as a catalyst for the oxygen evolution reaction — currently at 0.3–0.5 mg/cm² per membrane. Global iridium production is approximately 7–8 tonnes per year, concentrated in South Africa's platinum group metal mining operations. At current iridium loading, scaling PEM to 100 GW/year of annual electrolyser production would require 7–14 tonnes of iridium per year — equal to current global annual production. Catalyst loading reduction roadmaps (to 0.05–0.1 mg/cm² by 2030) and iridium recycling programmes are essential to avoid a supply ceiling that would structurally cap PEM deployment scale. Alternative catalysts (ruthenium, which is less scarce but less stable) and iridium-free PEM designs are in research stage but not yet commercially validated for long-lifetime operation.

Large green hydrogen projects (100 MW+ electrolysis) require dedicated grid connections — either direct renewable co-location or grid connection for periods when renewable generation exceeds electrolyser capacity. Grid connection timelines in the UK (4–6 years), Germany (3–5 years), and US (4–7 years for large industrial customers) significantly exceed the 2–3 year engineering and procurement timeline for the electrolyser system itself, creating a situation where fully procured and manufactured electrolyser systems cannot begin operations due to grid access delays. This misalignment has caused developers to delay final investment decisions on projects where grid connections cannot be secured within the window required to claim IRA or EU subsidy commitments.

The Investment Case: Bull, Bear, and What Decides It

The bull case is IRA Section 45V's effective implementation at scale (10+ GW of US electrolyser project FIDs in 2025–2026 enabled by hourly matching clarity) combined with EU Hydrogen Bank Round 2–3 auctions supporting 5–10 GW of European projects reaching FID before 2027. Under this scenario, electrolyser manufacturing scale-up achieves USD 300–400/kW for AEL and USD 500–600/kW for PEM by 2028, driving down green hydrogen production cost to USD 2.5–3.5/kg in optimal locations and triggering industrial decarbonisation commitments in steel, ammonia, and refining sectors. The market reaches USD 45–55 billion by 2034. Bull case probability: 25%.

The bear case is the 2022–2024 manufacturing capacity expansion (Nel, ITM, ThyssenKrupp nucera all at 1 GW+/year nameplate capacity) outrunning project demand, with electrolyser capital costs collapsing to USD 200–250/kW as manufacturers compete for a pipeline of 3–5 GW/year in actual FIDs rather than the 10–15 GW/year required for viability. Under this scenario, most Western electrolyser manufacturers face financial distress by 2026–2027 (ITM Power is already loss-making), Chinese manufacturers capture the surviving project pipeline at lowest-cost pricing, and Western manufacturing capacity is rationalised. The market grows but Chinese manufacturers capture 70%+ of volume. Bear case probability: 40%.

The decisive indicator is the rate of project financial close in 2025 — specifically, how many of the 150+ GW of announced European and US green hydrogen projects reach FID before year-end 2025, triggering electrolyser procurement orders that fill manufacturer pipelines. The IRS's final 45V implementation guidance and the UK Hydrogen Production Business Model (HPBM) subsidy auction results in H1 2025 are the two policy events most immediately convertible to electrolyser order flow.

Where the Next USD Billion Is Being Built

The 3–5 year opportunity is modular small-scale electrolysers (1–5 MW) for industrial decarbonisation of captive hydrogen users — refineries, chemical plants, and food manufacturers that currently purchase grey hydrogen from on-site steam methane reformers or pipeline supply. The economics are increasingly attractive in regions with low renewable electricity costs: at USD 30/MWh electricity, a 5 MW PEM electrolyser produces hydrogen at approximately USD 3.5–4.5/kg — approaching parity with grey hydrogen including carbon cost exposure under EU ETS. Enapter's modular AEM electrolyser design, stackable from 1 kW to 10+ MW, targets this distributed industrial segment with a standardised plug-and-play architecture that reduces installation complexity and enables incremental capacity expansion.

The 5–10 year opportunity is solid oxide electrolysis (SOEL) for high-temperature industrial co-electrolysis applications. SOEL operates at 700–900°C, enabling 20%–30% higher electrical efficiency than AEL or PEM by using waste heat from industrial processes (steel plants, cement kilns, nuclear reactors) to provide the thermal energy component of water splitting. Sunfire's SOEL systems and Bloom Energy's high-temperature electrolysis are commercially available at small scale; multi-MW systems are in development for industrial co-electrolysis of steam and CO₂ to produce syngas for e-methanol and e-fuel applications. The integration of SOEL with industrial waste heat at steel and cement facilities — industries that require both green hydrogen for DRI reduction and green heat for decarbonisation — creates a uniquely high-value application where SOEL's efficiency advantage justifies the premium capital cost.

Market at a Glance

Regional Intelligence

The EU's Renewable Energy Directive III (RED III) delegated regulation on renewable fuels of non-biological origin (RFNBOs) establishes the eligibility criteria for green hydrogen in EU fuel mandates — requiring demonstration of additionality, temporal matching (monthly in 2025–2027, hourly from 2030), and geographic correlation with renewable generation. These criteria are stricter than US IRA's annual matching approach, raising effective green hydrogen production costs in Europe by EUR 0.3–0.8/kg relative to a less restrictive framework. The EU Hydrogen Bank auctions are the primary subsidy mechanism, complemented by national subsidy programmes in Germany (H2Global import tenders), France (Plan hydrogène), and the UK (Hydrogen Production Business Model).

The UK's Hydrogen Production Business Model (HPBM) is a revenue stabilisation mechanism modelled on the Contracts for Difference used in renewable energy — providing a production subsidy (the 'Hydrogen Production Strike Price') that closes the gap between green hydrogen production cost and the grey hydrogen market price, for 15-year contract periods. The UK's first HPBM allocation round (2023) awarded contracts to 11 projects totalling approximately 125 MW — a modest beginning relative to the UK's 5 GW by 2030 green hydrogen target, but establishing the commercial contract framework. The UK Net Zero Hydrogen Fund provides capital grants alongside HPBM revenue support, reducing the required strike price and therefore the subsidy budget required per project.

Leading Market Participants

• Nel Hydrogen
• ThyssenKrupp nucera
• ITM Power
• Plug Power
• Cummins
• Siemens Energy
• Bloom Energy
• Sunfire
• CSSC
• Enapter

Long-Term Market Perspective

By 2034, the global electrolyser market will have consolidated significantly from its current fragmented state, with three to five dominant AEL manufacturers (likely including one or two Chinese companies with global commercial presence), two to three PEM manufacturers at scale, and a niche SOEL market for high-temperature industrial applications. Total installed electrolysis capacity globally will reach 100–200 GW, producing 8–15 million tonnes of green hydrogen annually — a fraction of the 500 million tonnes of total hydrogen currently produced but sufficient to decarbonise significant portions of ammonia, methanol, and refinery hydrogen demand in regions with policy support.

The most consequential long-term structural question is whether green hydrogen becomes a global traded commodity or remains a regional, project-specific product. If green ammonia and e-methanol liquefaction and shipping infrastructure develops at the scale required for Japan, South Korea, and Europe's hydrogen import ambitions, hydrogen effectively becomes a global commodity with price discovery in spot and forward markets — analogous to LNG. If import infrastructure investment stalls, each national market develops independently, with production costs and prices reflecting domestic renewable electricity and policy support rather than global market arbitrage. The commodity versus local-supply question determines whether the best green hydrogen projects globally — NEOM in Saudi Arabia, Pilbara in Australia — can serve global markets or are constrained to domestic or bilateral offtake.