Before hydrogen became a headline decarbonization pathway, it was already one of the world’s largest industrial gases. Most of it was produced from natural gas or coal. The largest existing market was ammonia production, and most of that ammonia becomes fertilizer. Petroleum refining ranks second. Green hydrogen therefore targets a molecule that industrial buyers already know. The change is in how it is produced.
The consequence is visible in the geography of current projects. The earliest credible green hydrogen developments cluster around existing ammonia plants, refineries and chemical sites, where the hydrogen is consumed where it is produced. That pattern matters because it sidesteps the most expensive part of the value chain. It also explains why the near-term market looks quite different from the fuel-cell cars and power-to-gas pilots that attract public attention.
Why Green Hydrogen Re-entered the Conversation
Electrolysis has been used to produce hydrogen for decades, but historically at small scale and for specialist applications. The current wave of interest comes from a different source. Power systems are adding large volumes of variable renewable generation, and that creates a need for long-duration storage and for ways to channel surplus electricity into forms that can be used later. Green hydrogen offers one possible route, because an electrolyser can respond to periods of low electricity prices and produce a storable gas.
The second driver is harder to electrify directly. Industries such as steelmaking, chemicals and long-distance shipping require either intense heat or energy-dense fuels that batteries cannot easily provide. Hydrogen can serve as a reducing agent in steel production, as a feedstock for ammonia, and as a feedstock for synthetic fuels. The broad policy interest in green hydrogen therefore rests on two different arguments: one about electricity system balancing, and one about industrial decarbonization.
The two arguments create different expectations. System operators think in terms of charge-and-discharge hours, round-trip efficiency and grid services. Industrial buyers think in terms of delivered cost per tonne of ammonia or steel. Green hydrogen has to straddle both conversations, which is one reason the technology attracts more strategic attention than immediate project finance.
The Cost Structure That Separates Potential from Deployment
The core economic problem is straightforward. Green hydrogen is produced by using electricity to split water. The cost of that electricity is therefore the single largest variable in the production cost of the gas. In locations with cheap and abundant renewable power, the production economics improve substantially. In locations where renewable electricity remains scarce or expensive, green hydrogen production costs stay above those of hydrogen made from natural gas.
This also explains why regional strategies differ so widely. Countries with strong solar resources see green hydrogen as an export opportunity. Countries with limited land and high electricity demand see it as an import requirement. The same molecule can be a domestic industrial feedstock in one market and a tradable energy carrier in another, but the underlying cost logic is the same: the cost of electricity sets the floor.
The comparison with conventional hydrogen is not symmetrical. Natural gas prices fluctuate with global markets, while green hydrogen costs track renewable electricity generation costs. Where renewable costs have fallen, such as in certain utility-scale solar markets, the gap has narrowed. In those markets, the spread now depends on regional gas prices, carbon prices and electrolyser utilisation rates, rather than being impossibly wide everywhere.
The role of electricity input also creates a connection to the broader solar fleet. Building an electrolyser is, in effect, adding a large new source of electricity demand. The solar PV systems now feeding the grid can supply that demand, but their output varies by hour and season. An electrolyser that operates only when solar generation is abundant will have lower capacity utilisation, and lower utilisation raises the fixed-cost contribution per kilogram of hydrogen. Finding the right balance between cheap electricity and high operating hours is an optimisation problem, not a simple procurement decision.
Electrolysis: The Engineering Behind the Scale Gap
The main electrolyser technologies used today are alkaline and proton exchange membrane systems. Alkaline electrolysers are cheaper to build but less flexible in ramping. Proton exchange membrane electrolysers respond more quickly to variable electricity supply but require scarce materials such as iridium and platinum in catalytic layers. Solid oxide electrolysers operate at high temperature and promise higher electrical efficiency, but they are less commercially mature.
Beyond the choice of technology, the engineering challenge is one of scale. Most installed electrolyser capacity in the early 2020s was measured in tens of megawatts per project, while industrial hydrogen demand often requires hundreds of megawatts at a single site. The supply chain for electrodes, membranes, power electronics and balance-of-plant equipment will have to grow substantially before large orders become routine.
Electrolyser degradation adds another layer. Stacks do not last forever. Operating patterns, cycling frequency and water purity all affect stack lifetime. A green hydrogen plant designed around cheap solar will cycle more often than a plant designed for constant grid supply, and that cycling imposes wear. The cost of replacing stacks over the plant’s life must be included in the levelized cost of hydrogen. Early projects are still generating the operating data that will tell financiers how quickly stacks degrade under real-world duty cycles.
Water supply is a quieter constraint. Electrolysis requires purified water, typically in quantities of about nine litres per kilogram of hydrogen. In regions with strong solar resources but scarce fresh water, desalination becomes an additional process step. That increases energy consumption and adds a water treatment plant to the project. It does not usually make a project unworkable, but it adds complexity to locations where developers assumed land and sunlight were the only requirements.
Transport and Storage: The Quieter Barrier
Hydrogen has a high energy content per kilogram but a low energy content per cubic metre at ambient conditions. That physical mismatch shapes the entire discussion about moving hydrogen from production sites to consumers. A cubic metre of atmospheric hydrogen carries only a small fraction of the energy of a cubic metre of natural gas. To move meaningful quantities, hydrogen must be compressed, liquefied or converted into a chemical carrier such as ammonia.
Each of those options adds cost and energy losses. Compression is the simplest approach for pipelines and tube trailers, but high-pressure equipment introduces safety requirements and capital costs. Liquefaction requires cooling to extremely low temperatures and consumes a significant share of the energy contained in the hydrogen itself. Converting hydrogen to ammonia makes shipping easier, but reconverting ammonia back to hydrogen at the destination adds another industrial process.
This explains a recurring feature of early projects. Developers site electrolysers next to the end user whenever possible. A refinery or ammonia plant already has hydrogen piping, storage and handling equipment. Building a new electrolyser behind that fence line avoids the need to create long-distance transport infrastructure. The value of co-location is not simply convenience; it removes a cost layer that can exceed the cost of the electrolyser itself.
For long-distance trade, the obstacles are larger. The shipping industry has experience with liquefied natural gas, but liquid hydrogen behaves differently and requires new vessel designs. Ammonia carriers already exist, but using ammonia as a hydrogen carrier raises safety, toxicity and conversion-cost questions. Pilot projects are testing different approaches, but the industry has not yet settled on a dominant transport pathway.
Policy, Certification and the Additionality Debate
Policy support has become the most important near-term driver of green hydrogen demand. Subsidies, tax credits and public procurement programmes in Europe, the United States and parts of Asia have created the first genuine revenue floors for projects. The design of those programmes matters more than the headline funding amounts, because the rules determine what counts as green hydrogen.
The central disagreement concerns additionality. If an electrolyser uses electricity from the existing grid, it may simply increase demand for fossil generation elsewhere. Strict additionality rules therefore require that new renewable generation be built specifically to supply the electrolyser. Developers argue that strict rules raise costs and slow deployment. Environmental groups and some regulators argue that without additionality, the climate benefits can be overstated.
Certification systems sit on top of this debate. Renewable energy certificates can demonstrate that a given amount of renewable electricity was generated and matched to the electrolyser. But the role of renewable energy certificates depends on how granular the matching is. Annual matching allows a plant to use grid electricity at night and offset it with renewable certificates from another time. Hourly matching, now being introduced in some markets, is closer to a physical claim but much harder to achieve with current monitoring and certification infrastructure.
Because additionality and certification rules determine which projects can receive support and how their hydrogen is marketed, project developers have begun to treat those rules as part of the financing package rather than a bureaucratic afterthought. A subsidy that appears generous on paper can become unusable if the compliance requirements force a plant to operate far below its design utilisation.
Where Green Hydrogen Finds Its First Economic Case
The most credible early market is existing industrial hydrogen demand. Ammonia production, refining and methanol synthesis already consume large volumes of hydrogen. Replacing a portion of that hydrogen with green hydrogen does not require consumers to adopt a new fuel or install new equipment at their end of the supply chain. The main change occurs inside the facility fence line, where an electrolyser and a renewable power supply are added.
That colocation reduces project risk in ways that matter to lenders. The buyer is known, the offtake agreement is often internal to the same industrial group, and the transport infrastructure already exists. A green hydrogen project built next to an ammonia plant can begin production without waiting for new pipeline networks or for vehicle manufacturers to commit to fuel-cell fleets. Some industrial sites have also explored pairing electrolysers with floating solar installations where land is constrained, though this does not remove the need to manage variable input.
The second application with genuine long-term logic is long-duration storage. Power systems with high shares of wind and solar eventually need storage that can shift energy across days or seasons. Batteries are better suited to short-duration balancing and frequency response. Hydrogen stored in salt caverns or pressure vessels can, in principle, be converted back to electricity during extended periods of low renewable output. The economics of that round trip remain challenging because electrolysis and reconversion lose energy at each stage, but the service itself has few direct substitutes.
Heavy transport and power generation are often cited as early demand sources, but they face stronger competition. Battery electric vehicles already serve many short-haul transport segments. Trucks, ships and aircraft require more energy density than current batteries offer, but hydrogen or hydrogen-derived fuels must compete with other low-carbon fuels and with the cost of new refuelling infrastructure. In power generation, the efficiency penalty of converting electricity to hydrogen and back again makes direct use of electricity almost always more efficient where it is possible.
The Path to Scale
Scaling green hydrogen is not a matter of inventing a new technology. Commercial electrolysers already exist, and the basic chemistry is well understood. The harder challenge is assembling the surrounding system: cheap renewable electricity, large electrolyser plants, water supply, compression or conversion infrastructure, certification and a customer willing to pay the premium. A failure in any one of those elements can delay a project regardless of how mature the electrolyser technology is.
The industry is likely to develop unevenly. Regions with cheap renewable power, existing industrial hydrogen demand and clear subsidy rules can support clusters of projects. Regions lacking one or more of those conditions are likely to remain at the demonstration stage. The result will probably be a patchwork of hydrogen hubs around ports, refineries and fertiliser plants, rather than a uniform global market.
The remaining uncertainties are substantial. Electrolyser degradation under real-world cycling is still being measured. Certification rules are still tightening. Transport infrastructure for hydrogen and hydrogen carriers is mostly unbuilt. Gas prices, carbon prices and renewable electricity costs will continue to shift the competitive position of green hydrogen relative to conventional production and to direct electrification.
What green hydrogen offers is not a general-purpose replacement for electricity, oil or natural gas. It offers a focused tool for the parts of the industrial system where electrons are difficult to use directly. Whether the technology scales beyond those focused applications depends on whether the cost and transport barriers fall enough to make it a practical option rather than a strategic one. The current evidence points toward early growth in industrial hubs, followed by a more uncertain expansion into storage and long-distance trade if the first wave of projects performs as designed.
References
- International Energy Agency — Global Hydrogen Review data on hydrogen demand, production routes and electrolyser deployment trends.
- International Renewable Energy Agency — analysis of green hydrogen cost drivers and the role of renewable electricity input.
- BloombergNEF — market intelligence on green hydrogen project pipelines and levelized cost comparisons.
- DNV Energy Systems — Hydrogen forecast material covering electrolyser technology status, degradation and transport options.
