Green Hydrogen
Green hydrogen is hydrogen produced by splitting water through electrolysis, using electricity sourced from renewable generation. It carries no fossil carbon and emits no CO₂ at the point of production. Today it accounts for less than one percent of global hydrogen supply, but it sits at the centre of almost every credible plan for decarbonising heavy industry.
Why the color codes hide more than they reveal
The shorthand is familiar by now. Green hydrogen comes from renewable-powered electrolysis. Grey from unabated steam methane reforming. Blue from natural gas with carbon capture. Pink from nuclear electricity. Turquoise from methane pyrolysis. Yellow, white, brown, gold, the palette keeps expanding.
The colors are useful as a first sort. They are not a substitute for a lifecycle assessment.
The same kilogram of hydrogen, labelled "green" by one producer, can have a carbon intensity that varies by an order of magnitude depending on the electricity mix powering the electrolyzer, the strictness of the additionality rules applied to that electricity, and whether grid imports during low-renewable hours are counted honestly. European regulation under the Renewable Energy Directive (RED III) and the associated Delegated Acts attempt to define what "renewable hydrogen" really means in practice. The criteria include additionality (the renewable generation must be new), temporal correlation (production must roughly match generation in time), and geographic correlation (production and generation must be on a related grid). These rules are stricter than the public conversation usually implies, and they make a real difference to which projects actually qualify.
For an engineer, the practical implication is straightforward. When you read "green hydrogen" in a project announcement, the relevant question is not the color but the certification scheme and the underlying contract structure. Same color, very different molecules.
How green hydrogen is produced
All green hydrogen comes from the same overall reaction. Two molecules of water are split into two molecules of hydrogen and one molecule of oxygen, with electricity providing the energy. The thermodynamic minimum is well known (about 39.4 kWh per kilogram of hydrogen at standard conditions, on a higher heating value basis). The way that reaction is engineered, however, determines almost everything else about the resulting plant: its cost, its footprint, its dynamic behaviour, its operating window, and which downstream applications it serves well.
Four electrolyzer technologies dominate the conversation in 2026. The differences between them are the single most important commercial choice in any green hydrogen project.
Alkaline electrolysis
The oldest commercial electrolysis technology and still the volume leader globally. Two electrodes sit in a liquid alkaline electrolyte (typically 25 to 30 percent potassium hydroxide), separated by a diaphragm. Operating temperature is in the 60 to 90°C range, at atmospheric to moderately elevated pressure.
Alkaline has the lowest installed capex per kilowatt of any electrolyzer technology and the most mature supply chain. Stack lifetimes are well established, often quoted at 60,000 to 90,000 operating hours before major refurbishment. The technology has been deployed at multi-hundred-megawatt scale for industrial hydrogen production for decades.
The trade-offs are real. Current density is lower than PEM (typically 0.2 to 0.5 A/cm²), meaning a larger physical footprint per megawatt installed. Dynamic response, while substantially improved in modern systems, is still slower than PEM, and rapid load cycling has historically been harder on alkaline stacks. The corrosive liquid electrolyte brings its own balance-of-plant requirements, including caustic-resistant materials throughout the wet sections.
For projects with stable baseload renewable electricity, a partial grid connection, or a hybrid power source that smooths short-term variability, alkaline is very often still the right answer.
PEM electrolysis (Proton Exchange Membrane)
A solid polymer electrolyte, typically a perfluorosulfonic acid membrane in the Nafion family, replaces the liquid alkaline. The change is more consequential than it sounds.
PEM delivers two to four times the current density of alkaline (1 to 2 A/cm², with development targets above 4 A/cm²), which translates directly into a smaller footprint. It responds to load changes within seconds rather than minutes, and operates well across a wide turn-down range. It produces hydrogen at higher pressure directly from the stack (often 30 bar, sometimes more), which reduces or eliminates the need for a first stage of mechanical compression. For projects coupled directly to variable solar or wind, PEM's responsiveness is a genuine advantage.
The catch is materials. PEM relies on precious metal catalysts: iridium on the oxygen evolution side, platinum on the hydrogen evolution side. Iridium is among the rarest metals in the Earth's crust, with global annual production measured in single-digit tonnes. Projected growth of PEM at the scale required for industrial decarbonisation runs directly into iridium supply constraints unless catalyst loadings come down by a factor of five to ten. This is an active research area, with credible progress, but it is not yet solved.
Installed capex per kilowatt is currently somewhat higher than alkaline, though the gap has narrowed substantially and may close further.
AEM electrolysis (Anion Exchange Membrane)
The conceptual best-of-both proposition. A solid polymer membrane like PEM, but with an alkaline chemistry that, in principle, allows the use of non-precious-metal catalysts. The promise is PEM-style performance at alkaline-style materials costs.
AEM is, in 2026, still pre-commercial at large scale. A handful of vendors (Enapter is the most visible) ship commercial units in the kilowatt to low-megawatt range, and several developers are progressing toward multi-megawatt demonstrations. Stack lifetimes, current densities, and durability under sustained industrial operating conditions are still being established. Membrane stability in alkaline conditions has historically been the limiting factor, and recent membrane chemistries appear to have closed much of the gap, though long-duration field data remains thin.
AEM is genuinely promising and worth watching closely. Treating it as a drop-in replacement for alkaline or PEM at multi-megawatt scale in 2026 would be premature. By 2028 to 2030, the answer may look different.
SOEC (Solid Oxide Electrolysis Cells)
The outlier. SOEC operates at 700 to 850°C using a ceramic solid oxide electrolyte. The high temperature does something the other three technologies cannot. It allows a meaningful fraction of the energy required for water splitting to come from heat rather than electricity, pushing electrical efficiency above 80 percent on an LHV basis. If high-temperature waste heat is available at the site (from a steel plant, a cement kiln, a chemical process, a nuclear reactor), the effective system efficiency rises further.
SOEC also enables co-electrolysis: H₂O and CO₂ can be split simultaneously to produce syngas directly, bypassing the conventional reverse water-gas shift step in e-fuels synthesis. For sites integrating with Fischer-Tropsch or methanol production, this can simplify the overall process configuration meaningfully.
The downsides are well understood. Ceramic stacks are sensitive to thermal cycling, which discourages frequent on-off operation. Degradation rates at high temperature remain a development focus. Stack lifetimes in real industrial operation are improving but are not yet at the level of mature alkaline systems. Installed capex remains elevated.
SOEC is moving from pilot to first commercial deployment through 2025 to 2027. Several vendors have shipped multi-megawatt units, and the first hundred-megawatt-class projects are in development. For industrial sites with available high-temperature heat and stable operating profiles, SOEC is the technology to evaluate seriously.
| Property | Alkaline | PEM | AEM | SOEC |
|---|---|---|---|---|
| Operating temperature | 60 to 90 °C | 50 to 80 °C | 40 to 60 °C | 700 to 850 °C |
| Electrolyte | Liquid KOH (25 to 30%) | Solid polymer (PFSA membrane) | Solid polymer (AEM) | Solid ceramic oxide (YSZ) |
| Current density | 0.2 to 0.5 A/cm² | 1 to 2 A/cm² (4+ in development) | 0.5 to 1 A/cm² | 0.3 to 1 A/cm² |
| System efficiency (LHV) | 60 to 68% | 60 to 68% | ~60% (provisional)demo / early | 75 to 85% (electrical), higher with heat integration |
| Stack lifetime | 60,000 to 90,000 hours | 50,000 to 80,000 hours | Provisional, target >40,000 hoursdemo / early | 20,000 to 40,000 hours, improving |
| Installed CAPEX (€/kW, system level) | 700 to 1,200 | 900 to 1,500 | Pre-commercial, target alkaline paritydemo / early | 1,500 to 3,000+ |
| Dynamic response | Minutes; modern systems much improved | Seconds, full range | Seconds (provisional)demo / early | Slow, prefers steady operation |
| Footprint per MW | High | Low | Low (expected)demo / early | Moderate |
| Critical materials | Nickel, steel | Iridium, platinum, titanium | Nickel, steel (no PGM) | Yttria, zirconia, rare earths, ceramics |
| Commercial maturity | Mature, multi-GW deployed | Commercial, scaling rapidly | Early commercial / demonstration | Early commercial, first large units 2024 to 2027 |
What drives the cost of green hydrogen
The levelised cost of hydrogen (LCOH) is the standard way to compare projects, and it breaks down into three principal contributors: electricity, capital, and operating costs. Each behaves differently, and each is the dominant lever in different project configurations.
Electricity dominates almost everywhere. A modern electrolyzer at 65 to 70 percent efficiency consumes 50 to 55 kWh of electricity per kilogram of hydrogen produced. At an electricity price of €40 per MWh (the level achieved by good wind and solar in favourable geographies, on dedicated PPAs), the electricity cost alone contributes around €2.00 to €2.20 per kg. At €100 per MWh (closer to grid prices in much of Europe in 2025), it contributes €5.00 to €5.50 per kg. No realistic improvement in capex or efficiency will make green hydrogen cheap if the electricity is not. Conversely, in geographies with abundant, cheap, dedicated renewable power, the rest of the LCOH calculation matters proportionally more.
Capital cost is the second big lever. Stack costs are falling, and they continue to. Total installed system costs (which include the rectifier and power electronics, the gas processing and drying skid, the balance of plant, the civil works, and engineering) are stickier and represent the larger share of the bill. The marginal cost of installed capacity matters less, in practice, than the load factor at which it operates. An electrolyzer running 8,000 hours per year amortises its capex over far more kilograms of hydrogen than one running 3,000 hours from a solar-only feed. Capex per kg, not capex per kW, is the metric that ultimately matters.
Then there are the contributors that get forgotten. Water treatment (electrolysis-grade water is not free, and at scale the volumes are substantial). Compression and storage (10 to 15 percent of the energy content of the hydrogen is consumed in compressing it to 700 bar). Grid connection costs (often surprisingly large for large electrolyzer installations). The cost of capital itself (for first-of-a-kind projects facing project finance with high risk premia, the WACC can dwarf engineering optimisations).
- Electricity
- CAPEX amortisation
- Stack replacement reserve
- O&M
- Water and utilities
- Compression and storage
- Cost of capital premium
- reference price line
The efficiency cascade
The strongest argument for green hydrogen is that it serves applications where direct electrification is not feasible. The strongest argument against it, in any specific application, is that it is competing with something more efficient.
Energy is lost at every conversion step. The cumulative loss through a long green hydrogen value chain is large enough that, when an alternative pathway exists, the alternative usually wins on energy grounds.
Start with 100 units of renewable electricity at the point of generation. Send it through an electrolyzer at 70 percent efficiency, and 70 units of hydrogen energy remain. Compress that hydrogen to 700 bar for road transport, and another 10 to 12 percent goes, leaving about 60 units. Liquefy it instead for shipping, and the figure falls closer to 50. Convert it to ammonia for long-distance maritime transport, and somewhere between 35 and 45 units remain at the point of arrival, depending on whether the ammonia is used directly or cracked back to hydrogen at the destination. Use it in a fuel cell vehicle to provide motion, and the wheels turn with 15 to 25 units of the original 100. The same 100 units used to charge a battery electric vehicle deliver 70 to 80 units at the wheels.
That is not an argument against green hydrogen. It is an argument for being precise about where it pays.
The implication for project design is clear. Every conversion step removed from the value chain is energy retained. Captive production close to the point of use, where it is possible, is structurally more efficient than long-distance transport. Direct conversion to the end-product on site (the methanol plant next to the electrolyzer, the steel mill next to the hydrogen supply) is structurally more efficient than producing the molecule centrally and shipping it. These are not unbreakable rules. They are the gravitational pull that good project structuring works with rather than against.
- Renewable electricity100
- Electrolysis70−30
- Light compression67−3
- Renewable electricity100
- Electrolysis70−30
- Compression to 700 bar60−10
- Transport losses57−3
- Fuel cell vehicle27−30
- Renewable electricity100
- Electrolysis70−30
- Liquefaction45−25
- Boil-off & reconversion37−8
- Renewable electricity100
- Electrolysis70−30
- Ammonia synthesis58−12
- Shipping55−3
- Cracking back to H₂ (if needed)40−15
- Renewable electricity100
- Electrolysis70−30
- Methanol synthesis50−20
- Marine engine (~50% eff.)25−25
- Renewable electricity100
- Battery charge/discharge88−12
- Motor78−10
Where green hydrogen genuinely makes sense
There is a class of applications where green hydrogen is the only credible decarbonisation pathway. There is a class where it is competing against something more efficient and is likely to lose. Conflating the two is the most common mistake in the public discussion, and it has cost real money in misallocated projects.
Applications where green hydrogen is essential
Replacing fossil hydrogen already in use. Approximately 95 million tonnes of hydrogen are produced globally each year, almost all of it from unabated steam methane reforming. The refining sector and the ammonia industry consume the bulk of it. These users are not going to stop consuming hydrogen. They have to change how it is made. This is the single largest decarbonisation opportunity for green hydrogen, it is the application where the economics work first, and it should arguably have been the priority all along.
Steel via hydrogen direct reduction (DRI). Replacing coke in steelmaking with hydrogen is one of very few credible routes to low-carbon primary steel. Several large pilots and first-of-a-kind commercial plants are in operation or under construction in Europe and elsewhere.
High-temperature industrial heat where electrification is impractical. Cement clinkering, glass production, parts of the chemical industry. Direct electrification of high-temperature heat is technically possible in some cases and progressing, but for many existing installations a hydrogen-fired retrofit is the more realistic pathway.
Long-distance shipping and aviation. The energy density of jet fuel and marine diesel is hard to match with batteries. Ammonia and methanol, both derived from green hydrogen, are credible marine fuels and are already being adopted by several major shipping operators for new builds. Synthetic kerosene, produced from green hydrogen via Fischer-Tropsch or methanol-to-jet routes, is the leading sustainable aviation fuel candidate beyond bio-derived options that are constrained by feedstock availability.
Applications where the hype runs ahead of the engineering
Domestic heating. Heat pumps are roughly three to four times more efficient than hydrogen boilers, the infrastructure cost of distributing hydrogen at scale to households is substantial, and the safety case is not trivial. Multiple government-commissioned studies in Europe and the UK have reached the same conclusion: domestic hydrogen does not stack up against heat pumps for the vast majority of residential heating. The conversation continues in some quarters mostly because the incumbent gas industry has reasons to keep it going.
Light-duty road transport. Battery electric vehicles have decisively won this market. Fuel-cell passenger cars exist but face a structural disadvantage in both efficiency and refuelling infrastructure cost.
General grid-scale power generation. For diurnal balancing, batteries combined with grid interconnection and demand response beat green hydrogen on round-trip efficiency and cost. Hydrogen may yet have a role in long-duration seasonal storage (where its low storage cost compared to batteries matters more than its round-trip efficiency), but this case is genuinely contested and depends heavily on the cost trajectories of competing technologies.
The honest framing is this. Green hydrogen is essential for what cannot be electrified. It is not a one-for-one replacement for fossil energy across everything. Treating it as a universal solvent leads to disappointment, misallocated capital, and reputational damage to the technologies where it really is the right answer.
| Option \ Sector | Existing grey H₂ replacement | Steel (primary) | High-temperature heat | Shipping (long-distance) | Aviation (long-haul) | Heavy trucks (long-haul) | Light vehicles | Rail | Domestic heating | Long-duration storage | Diurnal balancing |
|---|---|---|---|---|---|---|---|---|---|---|---|
| Green hydrogen Shipping via NH₃/MeOH; aviation via SAF | |||||||||||
| Direct electrification | |||||||||||
| Heat pumps | |||||||||||
| Batteries | |||||||||||
| Biofuels & bio-derivatives Aviation via HEFA, etc. | |||||||||||
| Catenary / grid | |||||||||||
| CCS-equipped fossil |
- Best fit
- Competes, sometimes wins
- Usually loses
Storage, transport, and the derivatives question
Hydrogen is the lightest element in the universe, and that is exactly the problem. At ambient conditions, a kilogram of hydrogen occupies about 11 cubic metres, while a kilogram of natural gas occupies about 1.4. The three established options for storing and moving hydrogen at scale are all imperfect, and the right choice depends on the application.
Compression to 350 or 700 bar. The default for short-distance transport, on-site buffer storage, and refuelling stations. Compression consumes 10 to 15 percent of the lower heating value of the hydrogen, requires specialised high-pressure equipment, and gets progressively more expensive at very large scale. For inter-city and inter-site transport, trucked tube trailers are common but inefficient on a delivered-cost basis.
Liquefaction to minus 253°C. Higher volumetric energy density, useful for long-distance transport or large stationary storage. The liquefaction itself consumes about 30 percent of the LHV of the hydrogen. Boil-off losses (hydrogen evaporating during storage and transport) impose a continuous penalty, typically 0.1 to 0.5 percent per day depending on tank insulation and size. Liquid hydrogen is technically mature but the energy penalty is substantial enough that for most applications, an alternative chemistry carries the molecules more cost-effectively.
Chemical carriers. Convert hydrogen into a chemical that is easier to store and ship: ammonia (NH₃), methanol (CH₃OH), liquid organic hydrogen carriers (LOHCs like methylcyclohexane), or hydrogenated forms of other compounds. Each carrier has its own efficiency penalty for forward and reverse conversion, its own infrastructure requirements, and its own end-use compatibility. Ammonia is increasingly the favoured carrier for long-distance shipping, both because of its high hydrogen content and because in many cases (fertiliser, increasingly marine fuel) it can be used as ammonia directly rather than cracked back to hydrogen. Methanol has a strong case as a shipping fuel and a chemical feedstock in its own right.
For most projects today, the right strategic question is not "how do we move hydrogen?" but "do we need to move hydrogen at all, or should we produce the derivative where we consume it?" Captive production close to the user, where geography allows it, removes the entire transport problem. The growing recognition of this point is one of the reasons that the early excitement about long-distance hydrogen import corridors has cooled noticeably since 2023.
Policy, markets, and the gap between announcements and FID
The policy framework is moving fast. The Renewable Energy Directive (RED III) in Europe has set strict definitions for renewable hydrogen, including the additionality, temporal correlation, and geographic correlation rules mentioned earlier. The Inflation Reduction Act in the United States introduced a production tax credit of up to $3 per kilogram, transforming project economics for US producers. National hydrogen strategies have proliferated across most major industrial economies. The European Hydrogen Bank, the Important Projects of Common European Interest (IPCEI Hy2Tech and Hy2Use), and a series of national support schemes have provided meaningful financial backing.
The reality on the ground is more sober. Final investment decisions have consistently lagged announcements, often by years. Several flagship projects have been delayed, scaled down, or quietly cancelled. The 2030 production targets in most national hydrogen strategies are now widely considered unreachable on their original timelines. Offtake agreements remain the persistent bottleneck. Producers want price certainty before sanctioning a project. Buyers want supply certainty and competitive prices before signing long-term offtake. The market sits in the awkward middle phase between policy momentum and bankable economics.
What is changing, slowly, is who is signing. The first wave of green hydrogen offtake agreements is dominated by users with no realistic alternative: replacing grey hydrogen in fertiliser plants, supplying first-of-a-kind hydrogen-DRI steel projects, fuelling pilot e-fuels production for shipping and aviation. These are the no-regret applications. They are also where the next several years of real, contracted demand is most likely to materialise.
The 2020s were the decade of announcements. The late 2020s will be the decade of selection: which projects actually get built, which technologies actually scale, which use cases actually pay.
Frequently asked questions
Is green hydrogen actually available today, or is it still mostly a future technology?+
Green hydrogen exists commercially, but at very small scale relative to total hydrogen demand. Less than one percent of the roughly 95 million tonnes of hydrogen produced globally each year qualifies as green under strict definitions. The technology to produce it is mature for alkaline and PEM electrolysis. The constraint is not technical readiness, it is cost, electricity supply, and the slow pace at which large-scale projects reach final investment decision.
How does green hydrogen compare on cost to grey hydrogen?+
At late-2025 prices, green hydrogen typically costs between €4 and €8 per kilogram delivered, depending on location, scale, and electricity contracting. Grey hydrogen from steam methane reforming, at typical European natural gas prices, costs around €1.50 to €2.50 per kilogram, sometimes higher when gas prices spike. The gap is substantial. Closing it requires sustained reductions in electrolyzer capex, cheap dedicated renewable electricity, carbon pricing on the grey alternative, and (in the near term) policy support to bridge the difference.
Which electrolyzer technology should I choose for my project?+
There is no single answer; the right choice depends on the project's electricity profile, scale, footprint constraints, and intended downstream use. For large industrial projects with stable baseload power, alkaline is often still the most cost-effective choice. For projects coupled directly to variable renewables, PEM's responsiveness is valuable. For sites with high-temperature waste heat or direct coupling to e-fuels synthesis, SOEC is worth evaluating carefully. AEM is promising but not yet mature at multi-megawatt scale. An independent technology selection study, which is one of the things Ionect does, is usually the right way to make this decision.
Does green hydrogen really make sense for home heating?+
For the vast majority of homes, no. Heat pumps are three to four times more efficient than hydrogen boilers, and the infrastructure cost of supplying domestic hydrogen at scale is high. Independent analyses commissioned by governments across Europe and the UK have consistently reached the same conclusion. Domestic hydrogen is mostly being kept alive in the conversation by incumbent gas-distribution interests rather than by the engineering case.
What is the difference between green, blue, grey, and pink hydrogen?+
The color codes describe the source of the energy used to produce the hydrogen. Green hydrogen comes from electrolysis powered by renewable electricity. Grey hydrogen comes from steam methane reforming of natural gas, with no carbon capture, and is by far the dominant production route today. Blue hydrogen comes from steam methane reforming with carbon capture and storage, ideally capturing 90 percent or more of the CO₂. Pink hydrogen comes from electrolysis powered by nuclear electricity. Turquoise hydrogen comes from methane pyrolysis, producing solid carbon as a byproduct. The color is a shorthand, not a substitute for a lifecycle carbon assessment.
Is there enough renewable electricity to produce green hydrogen at scale?+
This is the most important constraint on the long-term scale of the green hydrogen industry. Producing a kilogram of green hydrogen requires roughly 50 to 55 kWh of electricity. Replacing the world's current grey hydrogen consumption alone would require approximately 4,500 to 5,500 terawatt-hours of renewable electricity per year, which is comparable to total global wind and solar generation in 2024. Producing additional green hydrogen for new applications (steel, aviation, shipping, chemicals) requires multiples of that figure. The renewable capacity build-out required is enormous, and one of the reasons that the realistic pace of green hydrogen deployment is slower than the most ambitious policy targets imply.
What is RED III, and why does it matter?+
The Renewable Energy Directive (RED III) is the European framework defining what qualifies as "renewable hydrogen" for the purposes of EU regulation and incentives. It sets the criteria for additionality (the electricity must come from new renewable capacity), temporal correlation (hydrogen production must broadly match renewable generation in time), and geographic correlation (production and generation must be on a connected grid system). These rules are stricter than many early project plans assumed. They have a material effect on which projects qualify for renewable hydrogen status and which do not, and they have shaped the design of many European hydrogen projects over the past two years.
Related content
Related knowledge pages
- Green Ammonia
The largest downstream user of green hydrogen and the leading long-distance carrier.
- Fischer–Tropsch synthesis
The workhorse route from green hydrogen and captured CO₂ to liquid e-fuels.
- e-Fuels
Where green hydrogen meets carbon to make drop-in molecules.
- Power-to-X
The integrated systems perspective on green hydrogen, electricity, and downstream products.
- Techno-economic assessment
The method behind the LCOH numbers.
Related Ionect services and technologies
- Green Hydrogen & Electrolyzers
What Ionect does in green hydrogen and electrolyzer projects.
- Studies
Techno-economic assessment, feasibility, and independent review for hydrogen projects.
- Engineering
Basis of design for green hydrogen plants.
- Technology Development
Pilot integration and commissioning of electrolyzers.
Talk to Ionect about green hydrogen
Whether you are developing a new electrolyzer technology, evaluating hydrogen as part of a decarbonisation strategy, or sanity-checking a project before final investment decision, we can help structure the work.