Hydrogen as a Fuel: Over-Announced, Under-Built
They spoke of it as though it were gold, and drew up ledgers against a treasury none had yet opened. But it was never gold. It was flame carried in an open hand — real enough, and useful to the one who could hold it, but diminished at every step of the journey, and worth least of all to the man who had to carry it furthest.
The Correction, in Numbers
No corner of the energy transition has produced a wider gap between announcement and delivery than hydrogen. For four years it was described as the missing molecule — the answer to aviation, shipping, steel, heating, heavy trucking and seasonal storage simultaneously. The 2025–26 correction has been correspondingly brutal, and it is worth looking at plainly before assessing what survives.
Start with the headline ratio. Of roughly 520 GW of globally announced electrolysis capacity, only about 4 to 7% has reached a final investment decision. The rest is press releases, memoranda of understanding and feasibility studies. The International Energy Agency’s pipeline of announced low-emissions hydrogen has shrunk to around 27 million tonnes of potential 2030 production — and, more tellingly, the volume of projects either committed or with a realistic chance of operating by 2030 fell from roughly 10 million tonnes to just over 6 million in a single year. Since the prior review, only about 300,000 tonnes a year of genuinely new capacity has cleared FID.
The cancellations behind that shrinkage were not marginal projects. Over 33 GW has been cancelled or deferred across a handful of flagship schemes — including a 26 GW Australian renewable hydrogen hub, a 2.88 GW Queensland project, a 2.5 GW Norwegian scheme and a 1.4 GW US development. Close to sixty major clean hydrogen projects were cancelled during 2025 alone.
The most instructive failure was administrative rather than technical. In the European Hydrogen Bank’s second auction, despite a budget of some €1.2 billion, seven winning projects representing 1.88 GW of the 2.33 GW awarded subsequently withdrew. Developers had bid aggressively — as low as €0.20 to €0.48 per kilogram of subsidy — to win support, and then could not secure offtake agreements at the prices those bids implied. They had won the subsidy and lost the customer.
And Yet: There Is Real Steel in the Ground
A fair assessment has to resist the opposite error. The correction is not an extinction, and the sector that emerges from it is smaller but considerably more real than the one that entered.
Global installed electrolysis capacity doubled during 2025 to surpass 4 GW, with more than 2.5 GW under construction and due online through 2026. More than 500 hydrogen projects worldwide have now passed final investment decision, entered construction, or begun operating, backed by upward of $110 billion of committed capital. That is no longer a speculative pipeline; it is a real, if concentrated, industrial base — heavily weighted toward a handful of very large projects rather than spread evenly across markets.
The announced pipeline and the constructed base tell opposite stories, and most commentary picks one. The disciplined reading holds both: hydrogen’s addressable market was wildly overstated, and its real industrial base is nonetheless growing quickly from a small number. The investable question is therefore not “is hydrogen real?” but “which four to seven per cent?” — and the sorting criteria turn out to be remarkably consistent.
The Cost Gap Widened Instead of Closing
Every forecast made between 2020 and 2022 rested on a single assumption: that electrolyser costs would fall steadily with scale, in the manner of solar panels and lithium cells. That assumption failed. Electrolyser system costs rose by a median of around 57% since 2022, driven by input inflation, supply-chain constraints and the discovery that balance-of-plant costs at industrial scale were considerably higher than pilot economics implied.
The result is a cost gap against incumbents that is wider today than when the hype began.
The threshold usually cited for competitiveness is around $2 per kilogram. Reaching it requires two conditions to hold simultaneously: electricity below roughly €20/MWh, and electrolyser utilisation above about 5,500 hours a year. That combination exists in parts of the Iberian peninsula, Scandinavia and the Middle East and North Africa corridor. It does not exist across most of Europe, and it is precisely why the map of viable projects looks so different from the map of announced ones.
This is also why blue hydrogen keeps winning the decisions that actually get made. Its cost base is anchored to natural gas, a commodity with decades of liquid futures markets behind it, so a lender can hedge and underwrite it. Green hydrogen’s cost base is renewable electricity and electrolyser capex over a twenty-to-thirty-year life — a forecasting problem with no comparable instruments. When a US ammonia complex reached FID and began construction in 2026 with Japanese offtake attached, it was blue ammonia, and bankability was the reason.
The Financing Mechanics That Actually Killed the Projects
For a markets audience this is the section that matters, because the cancellations were not decided by engineers. They were decided in credit committees, and the mechanism is precise enough to generalise to every other first-of-a-kind technology in this section.
A 100 or 200 MW electrolyser is a genuine first-of-a-kind at the site level in most jurisdictions. That means no established lender track record, no proven engineering contractor willing to wrap completion risk at that scale, no operating history from which to model stack degradation, and an equipment supply chain untested at the required volumes. Lenders priced that accordingly: debt for green hydrogen projects has cost more than three times the equivalent for mature renewable energy.
Many schemes were viable at €60/MWh power and an 8% cost of capital. They were not viable at the cost of capital lenders actually offered.
That single substitution — replacing an assumed discount rate with a real one — moved a large share of the announced pipeline from marginal to impossible. And the response is telling: sponsors cancelled rather than restructured, because the restructured version would have been smaller, less leveraged and below their return threshold. It was not that a viable smaller project did not exist. It was that no one wanted to own it.
The primer’s point about duration sensitivity applies here with unusual force. Hydrogen projects are long-dated, capital-heavy and front-loaded — exactly the cash-flow profile most punished by a higher discount rate. Hydrogen did not fail a technology test. It failed a discount-rate test, and the same test is being applied to every first-of-a-kind clean-industrial proposal now seeking finance.
The Physics Nobody Put in the Model
Production cost is only half the story, and the neglected half is thermodynamic. Hydrogen is the lightest element in the universe, which makes it extraordinarily awkward to move and store — and every step taken to make it transportable consumes a large fraction of the energy it contains.
- Liquefaction consumes 30–40% of hydrogen’s own energy content — on the order of 10 to 13 kWh per kilogram, spent purely to make it cold enough to ship.
- Conversion to ammonia and back again collapses round-trip efficiency to roughly 11–19%, if the objective is to recover hydrogen at the far end.
- Together, these penalties add something like $2.70–3.20 per kilogram to delivered cost — frequently more than the entire target production price.
Hydrogen is not a fuel you ship. It is a feedstock you make next to where it is consumed.
The vision of a global hydrogen trade — produced cheaply in sunny places, liquefied, shipped, and burned in importing economies — runs directly into these penalties. Any business case that requires hydrogen to travel a long distance as hydrogen is fighting thermodynamics, and thermodynamics does not respond to subsidy. What survives is a much narrower proposition: co-located production and consumption, or export in a form whose end use is the molecule itself — ammonia shipped to be used as ammonia, not as a hydrogen carrier. That single distinction separates most of the viable projects from most of the cancelled ones.
Two further physical constraints sit underneath. PEM electrolysers depend on iridium, one of the scarcest elements in commercial use, creating a genuine ceiling on that technology’s deployment rate irrespective of capital availability. And stack degradation over an operating life remains imperfectly characterised, which is precisely the uncertainty that pushes up the cost of debt.
Where It Genuinely Works
The now-standard way to think about this — popularised as a “hydrogen ladder” by the analyst Michael Liebreich — is to rank applications not by how well hydrogen performs, but by how good the alternatives are. Where direct electrification works, it wins decisively on efficiency and cost. Hydrogen earns its place only where nothing else does the job.
| Application | Verdict | Why |
|---|---|---|
| Replacing existing grey hydrogen (refining, ammonia, methanol) | Strongest case | The demand already exists and is already met with hydrogen. Substitution requires no new market, no new infrastructure and no behaviour change — only a cost gap to close. This is where nearly all sensible capital is going. |
| Steel (direct reduced iron) | Strong, policy-dependent | One of the few routes to deep decarbonisation of primary steelmaking. Economics rest on carbon pricing and border adjustment rather than on standalone competitiveness. |
| Shipping fuel via ammonia | Plausible | Few alternatives for long-haul marine, and ammonia is used directly rather than reconverted — which avoids the round-trip penalty. |
| Aviation e-fuels | Expensive but few options | Synthetic fuels combining hydrogen with captured CO₂ are costly, but batteries cannot serve long-haul flight. Early plants are being built. |
| Cars, domestic heating, most short-haul transport | Loses decisively | Direct electrification is far more efficient and already deployed at scale. These uses drove much of the announced pipeline and almost none of the built one. |
The pattern is consistent: hydrogen works where it is a feedstock replacing an identical incumbent feedstock, and struggles wherever it is proposed as an energy carrier competing with electrons. Most of the cancelled capacity was aimed at the second category.
Reading It Through the Frameworks
How does it get paid? This is the sector’s defining weakness. The European auction failure showed developers who had secured a subsidy but no customer — and a subsidy without offtake is not a revenue model. The industrial buyers meant to anchor demand (ammonia producers, refiners, steelmakers) run thin margins and make fuel-switching decisions on total cost of ownership over ten to fifteen year cycles. They are not paying a premium for a molecule that performs identically.
Where is the moat? Not in electrolysers, which are commoditising even as they inflate. It is in geography — sites combining very cheap power with high utilisation are genuinely scarce — and in signed, long-dated offtake, which is the rarest asset in the sector. A twenty-year offtake agreement with a creditworthy industrial buyer is worth more than any technology position.
Hydrogen was sold as a universal solvent for hard-to-abate emissions and is settling into something far narrower and considerably more durable: an industrial feedstock, made close to where it is used, replacing the grey hydrogen the world already consumes. The 2025–26 correction removed the applications that never made sense — cars, home heating, long-distance molecular export — and left a smaller sector with real capital behind it.
Two tests sort it. First, is the hydrogen replacing an identical incumbent feedstock, or competing with electrons? Second, does the project have signed offtake, or only a subsidy? The projects that answered both correctly are being built. The 93-odd per cent that never reached a final investment decision mostly answered neither — and no amount of policy support closes a gap that thermodynamics opened.
In the end they used it as the old smiths always had — close to the furnace, in small measure, for the few tasks nothing else would serve. It was the merchants who had promised to carry it across the sea who were ruined, for they had reckoned the worth of the flame and forgotten the cost of the lantern.
Leave a Reply