Why green hydrogen projects struggle outside the laboratory
thyssenkrupp nucera’s standardized 20 MW alkaline water electrolysis module scalum® at the company’s module yard in Spain. Copyright: thyssenkrupp nucera
Green hydrogen’s journey from laboratory promise to industrial reality has produced several high-profile reversals.
Fortescue cancelled green-hydrogen projects in Australia and the United States. BP decided to withdraw as operator and shareholder from the planned Australian Renewable Energy Hub, although the development itself has not formally been abandoned. In Germany, ArcelorMittal dropped plans to convert two steelworks to lower-carbon production using renewable electricity and green hydrogen, despite being offered €1.3 billion in public support.
At thyssenkrupp nucera, however, the picture is more complicated than a straightforward retreat from hydrogen.
The German electrolyser manufacturer has abandoned plans to commercialise solid-oxide electrolysis cell, or SOEC, technology on the scale originally envisaged. The decision will result in a negative one-off impact on earnings before interest and tax of approximately €30 million, primarily through the impairment of its pilot plant and capitalised development costs.
Yet only days before announcing that decision, thyssenkrupp nucera signed a strategic collaboration agreement with Bharat Heavy Electricals Limited to manufacture alkaline water electrolysers for green-hydrogen projects in India. The company has also secured a contract to supply a 300-megawatt alkaline water electrolyser for Moeve’s project in southern Spain and is conducting a front-end engineering design study for a proposed 260-megawatt green-hydrogen and ammonia project in India.
The contrasting announcements reveal an industry entering a more selective phase. thyssenkrupp nucera is not turning away from green hydrogen. It is concentrating on alkaline water electrolysis, a commercially mature technology it already supplies at industrial scale, while discontinuing the planned scale-up of a younger technology whose prospective market was developing too slowly.
The reversal is nevertheless striking. thyssenkrupp nucera and research institute Fraunhofer IKTS opened their SOEC pilot production plant in Arnstadt only in May 2025. It was designed to produce stacks in small quantities, initially targeting annual capacity of 8 megawatts, while generating the manufacturing experience required for a future automated industrial facility.
SOEC technology itself has not failed. Solid-oxide electrolysers operate at high temperatures and use steam rather than liquid water. Some of the energy needed to split the steam can be supplied as heat, reducing electricity consumption, particularly when the system is integrated with an industrial process that already produces excess heat.
But potential efficiency under favourable conditions is only the beginning. Electrolysers must eventually become part of plants that operate for thousands of hours, respond to changing electricity supplies and produce hydrogen cheaply enough for customers to use. The decision by thyssenkrupp nucera illustrates how difficult that transition can be.
Why are green hydrogen projects struggling?
Green hydrogen projects face a combination of high electricity costs, intermittent renewable power, electrolyser degradation, expensive infrastructure and uncertain customer demand.
The underlying electrochemistry is well established. Electricity passes through water or steam inside an electrolyser, separating it into hydrogen and oxygen. When that electricity comes from qualifying renewable sources, the hydrogen can be classified as renewable or green.
A laboratory or pilot system can demonstrate efficiency, durability and hydrogen purity under controlled conditions. A commercial green-hydrogen project must reproduce those results while incorporating transformers, rectifiers, pumps, cooling systems, water purification, gas separation, drying, compression and safety equipment.
This surrounding machinery, known collectively as the balance of plant, can account for a significant proportion of an installation’s cost and complexity. Research by the US Department of Energy’s H2NEW consortium concludes that the electrolyser stack and balance-of-plant components both contribute substantially to total costs.
The distinction is easily obscured in corporate announcements. An electrolyser manufacturer may report impressive performance from a stack, while a project developer must make the entire production system work reliably.
Every conversion, pump and purification stage consumes energy. Once produced, the hydrogen may need to be compressed, stored, converted into ammonia or transported before it reaches a customer.
Stack efficiency is therefore not the same as plant efficiency, and doesn't automatically produce an economically viable green-hydrogen project either.
Green hydrogen needs cheap electricity for long periods
Electricity is generally the largest operating cost in green hydrogen production. This creates an apparently simple formula: place electrolysers near plentiful wind or solar generation and run them when electricity is cheap.
The difficulty is that an expensive industrial asset must operate for enough hours to recover its capital cost. The cheapest renewable electricity may only be available intermittently, leaving developers with an uncomfortable trade-off between low power prices and high electrolyser utilisation.
An electrolyser connected directly to a wind or solar development can secure renewable power but may remain underused when weather conditions change. Connecting it to the electricity grid can increase operating hours, but the power may be more expensive and may not always satisfy the emissions and sourcing rules attached to renewable hydrogen.
Battery storage can smooth short-term fluctuations, but introduces another substantial capital cost. Combining wind and solar can improve the production profile without eliminating variability.
The International Renewable Energy Agency estimates that renewable hydrogen remains two to three times more expensive than hydrogen produced from fossil fuels under typical conditions. Bringing that cost down depends not only on cheaper electrolysers, but also on sustained access to very inexpensive renewable electricity.
A viable project consequently needs more than an excellent wind or solar resource. It requires the right combination of electricity price, availability, grid access, carbon intensity and annual operating hours.
Intermittent renewable power can accelerate degradation
Variable electricity supplies create an engineering problem as well as a financial one. Electrolysers following wind and solar generation may repeatedly ramp up, reduce output, enter standby or shut down completely.
Modern alkaline, proton-exchange membrane and solid-oxide electrolysers can all respond to changing loads to some degree, but their operating characteristics differ.
Proton-exchange membrane electrolysers are particularly suited to rapid changes in output. Alkaline water electrolysis is more commercially mature and can also follow variable power within its operating limits. High-temperature SOEC systems offer potentially greater electrical efficiency but must manage demanding thermal conditions.
Repeated startup and shutdown cycles can accelerate electrolyser degradation. Components experience changing electrochemical, mechanical and thermal conditions, while electrodes, membranes, catalysts and other materials gradually lose performance. In an SOEC system operating at several hundred degrees Celsius, temperature management and thermal cycling are especially important.
H2NEW researchers have found that startup and shutdown cycles can degrade electrolyser performance over time. Their analysis also shows how electricity consumption per kilogram of hydrogen can rise as a system ages.
This deterioration affects more than an engineering specification. It helps determine when electrolyser stacks must be repaired or replaced, how much saleable hydrogen a plant can produce and whether projected savings survive years of operation.
Green hydrogen projects need committed customers
Even a technically successful green-hydrogen plant needs customers prepared to buy its output.
Hydrogen is already used extensively in oil refining, fertiliser production and chemical manufacturing, but most of that demand is supplied by hydrogen made from natural gas or coal. Switching to green hydrogen can require industrial customers to modify equipment, accept higher costs and enter long-term purchase agreements.
Those commitments, commonly called offtake agreements, are crucial to project financing. Banks and investors are reluctant to fund an expensive hydrogen plant without confidence that someone will purchase its output at a viable price.
Producers and potential customers can consequently become trapped in a waiting game. Developers hesitate to build without guaranteed demand, while industrial users hesitate to convert facilities until affordable and dependable supplies exist.
ArcelorMittal’s decision in Germany demonstrates the effect on the demand side. The company abandoned planned conversions at its Bremen and Eisenhüttenstadt steel plants after concluding that high energy costs prevented a competitive business case. The decision did not cancel an electrolyser factory, but it removed potentially significant future demand for green hydrogen.
Storage and transport add further costs
Hydrogen has a low volumetric energy density under normal conditions and requires specialised infrastructure.
It may need to be compressed, liquefied, converted into ammonia or carried through dedicated or converted pipelines. Each option adds cost, consumes energy and creates further engineering and safety requirements.
The most credible early projects are therefore often located close to existing industrial demand. Producing green hydrogen beside a refinery, chemical plant, fertiliser facility or steelworks can reduce the transport problem.
It does not, however, close the cost gap with fossil-based hydrogen. Nor does proximity guarantee that a customer will accept the higher price needed to make the project commercially viable.
Export projects face an additional challenge. Converting hydrogen into ammonia makes it easier to transport by ship, but the conversion and subsequent processing require more equipment and energy. The customer must ultimately pay for the entire chain, not simply the hydrogen leaving the electrolyser.
Electrolyser manufacturing faces a scale-up dilemma
Electrolyser manufacturers expect to reduce costs through mass production, automation and standardised designs. Yet factories cannot achieve economies of scale without substantial orders, and developers will not place those orders while projects remain financially uncertain.
The contrasting decisions by thyssenkrupp nucera illustrate how this pressure is reshaping the electrolyser market. Its agreement with BHEL is intended to strengthen local alkaline water electrolyser manufacturing for Indian green-hydrogen projects. Alkaline electrolysis has decades of industrial history, and thyssenkrupp nucera already offers it in standardised 20-megawatt modules.
SOEC technology was at a different point in its development. thyssenkrupp nucera and Fraunhofer IKTS had opened an 8-megawatt pilot production facility, but further industrialisation depended on demand growing sufficiently to justify automated series production. That market did not emerge quickly enough.
thyssenkrupp nucera is therefore not abandoning green hydrogen but narrowing its bets. It is backing a technology with an existing manufacturing base, current contracts and potential localisation partners while stepping away from the more speculative task of creating another supply chain ahead of dependable demand.
Where can green hydrogen still work?
Green hydrogen remains potentially valuable in sectors where direct electrification is extremely difficult. These include parts of fertiliser production, chemicals, shipping and steelmaking.
Its strongest early applications are likely to have several characteristics in common: access to inexpensive renewable electricity, high annual operating hours, nearby industrial demand, limited transport requirements and a customer prepared to sign a long-term purchase agreement.
Projects that depend simultaneously on unproven technology, newly built renewable generation, major transport infrastructure and a future export market carry far greater risk.
The setbacks across the industry do not demonstrate that green hydrogen cannot work. They show that technical feasibility is not enough.
Success will depend on complete plants surviving variable operation, maintaining performance, securing affordable renewable electricity and delivering hydrogen to customers willing to pay for it. Those are conditions no laboratory demonstration can settle—and they are where some of green hydrogen’s biggest promises are now encountering operational reality.
Liked this article? You can support our independent journalism via our page on Buy Me a Coffee. It helps keep MoveTheNeedle.news focused on depth, not clicks.