Of all the technologies in the energy transition portfolio, green hydrogen is the one that provokes the sharpest disagreements. Its proponents argue it is the only molecule capable of decarbonising the heavy industrial sectors that electricity cannot reach — steel, cement, long-haul shipping, aviation, and high-temperature process heat. Its critics point to the fundamental inefficiency of electrolysis: it takes three kilowatt-hours of electricity to produce the energy equivalent of one kilowatt-hour of hydrogen, and then further energy losses occur in transport, storage, and conversion back to power. Why, they ask, would you deliberately throw away two-thirds of your energy when you could simply use electricity directly?
The answer — and the reason we believe green hydrogen represents one of the most significant deep technology investment opportunities of the next decade — is that electricity alone cannot decarbonise everything. The electron is a powerful molecule for many applications: light transport, space heating, and much of industrial process heating below 300°C. But it cannot easily replace the carbon in steel, cannot provide the energy density needed for intercontinental aviation, and cannot power a cement kiln at 1,450°C. For these applications, a carbon-free fuel is required. Green hydrogen, and its derivative ammonia, are the leading candidates.
The Hard-to-Abate Sectors: Why Hydrogen Matters
Understanding the scale of the hydrogen opportunity requires understanding the structure of global greenhouse gas emissions. Of the approximately 37 gigatonnes of CO2 emitted annually, approximately 23 percent — around 8.5 Gt — comes from industrial processes that are structurally resistant to direct electrification. Iron and steel production is responsible for approximately 2.6 Gt, cement for approximately 1.7 Gt, chemicals and petrochemicals for approximately 1.0 Gt, and shipping and aviation for a further 1.2 Gt combined.
These sectors are hard to abate not because their operators lack motivation, but because of the fundamental physical chemistry of their processes. The blast furnace route to steel production requires coke — carbon — not as a fuel but as a chemical reductant that strips oxygen from iron ore. Electric arc furnaces can make steel from scrap metal without carbon, but primary steel production from iron ore requires a reductant. Replacing coke with hydrogen — a process called direct reduction — produces water instead of CO2 and has been commercially demonstrated by SSAB in Sweden with its HYBRIT project, which produced the world's first fossil-free steel in 2021. But hydrogen direct reduction requires a hydrogen supply, and that hydrogen must be green (produced by electrolysis) rather than grey (produced by steam methane reforming of natural gas) for the decarbonisation benefit to be real.
Cement is a different challenge. Approximately 60 percent of cement's CO2 emissions come from the calcination reaction — the chemical conversion of limestone (calcium carbonate) to lime (calcium oxide) — which is inherent to the chemistry of cement production regardless of the energy source. Carbon capture and storage is the primary solution to the process emissions component. But the remaining 40 percent from fuel combustion can be addressed with hydrogen burners, and several cement producers are piloting hydrogen-fired kilns. The French cement manufacturer Vicat has operated a hydrogen-fuelled pilot kiln at its Créchy facility since 2022.
Shipping presents yet another variant of the problem. Container ships have very long operational lifetimes — typically 25-30 years — and burn approximately 300 million tonnes of heavy fuel oil annually. Electrification of deep-sea shipping is not viable at current battery energy densities: a container ship crossing the Pacific at sea would require a battery weighing more than its cargo. Ammonia (produced from green hydrogen) and methanol are the leading low-carbon fuel candidates for deep-sea shipping. Maersk, the world's largest container shipping company, has committed to operating its first methanol-powered vessels in 2024 and to carbon neutrality by 2040, and has placed significant orders for ammonia-ready ships.
The Economics of Green Hydrogen: The Cost Curve That Matters
The central economic question for green hydrogen is simple: at what electricity price, and at what electrolyser capital cost, does green hydrogen become competitive with grey hydrogen (produced from natural gas) and other industrial inputs?
Green hydrogen production cost has three primary components. Electricity cost — typically representing 70-80 percent of the total — is determined by the renewable energy tariff at the installation site. Electrolyser capital cost — the investment required in electrolysis equipment — is determined by technology maturity and manufacturing scale. And operating and maintenance cost — typically 2-3 percent of capital cost per year — is relatively modest.
At current electrolyser capital costs of approximately $700-1,000/kW for proton exchange membrane (PEM) systems, and at solar electricity costs of $20/MWh available in the best global locations (Chile's Atacama Desert, southern Spain, Morocco), green hydrogen can be produced at approximately $2.50-3.50/kg. Grey hydrogen from steam methane reforming costs approximately $1.00-1.50/kg at European natural gas prices. The gap is therefore currently a factor of 2-3x. But the cost trajectory for electrolysers follows a pattern familiar from solar panels and lithium-ion batteries: each doubling of cumulative installed capacity has historically reduced costs by 18-25 percent. With electrolyser manufacturing capacity growing at over 50 percent annually, and with the learning curve effects now clearly visible in the industry data, the green hydrogen cost crossover with grey hydrogen in optimal locations is forecast by the IEA and most independent analysts to occur between 2030 and 2035.
For European industrial applications, which matter most to us given our investment geography, the situation is more challenging. European electricity costs are structurally higher than in the best solar and wind resource locations due to grid infrastructure costs and policy design. The most economically competitive route for European industry is not to produce green hydrogen locally from expensive grid electricity, but to import it from regions with exceptional renewable resource — North Africa, the Middle East, Australia, Chile, and Namibia — as either hydrogen (via pipeline or liquefied shipping) or as derivative products like ammonia. European Commission policy is explicitly targeting this import strategy, with the RepowerEU plan calling for 10 million tonnes of domestic green hydrogen production and 10 million tonnes of imported green hydrogen annually by 2030.
Electrolyser Technology: Three Competing Approaches
Three electrolyser technologies are competing for the green hydrogen market, each with distinct trade-offs in efficiency, capital cost, operating conditions, and manufacturing readiness.
Alkaline electrolysers are the most mature technology, with commercial deployment dating back to the 1920s. Modern alkaline electrolysers use a liquid potassium hydroxide electrolyte and nickel-based electrodes. They are relatively low capital cost — approximately $500-700/kW at current manufacturing scale — and have demonstrated 100,000+ hour operating lifetimes in industrial installations. Their limitations are dynamic response time (alkaline systems respond slowly to power fluctuations, which is a problem when paired with variable renewable energy sources) and relatively low current density (leading to larger system footprints per unit of hydrogen production). Nel Hydrogen (Norway), ThyssenKrupp Nucera (Germany), and John Cockerill (Belgium) are the leading European alkaline electrolyser manufacturers.
Proton exchange membrane electrolysers use a solid polymer membrane as the electrolyte and iridium-based catalysts at the oxygen-evolving anode. PEM systems have higher current densities than alkaline (reducing equipment footprint), faster dynamic response (better compatibility with variable renewables), and the ability to produce hydrogen at higher pressure without mechanical compression. Their current disadvantage is capital cost — approximately $700-1,000/kW — driven partly by the cost of iridium, which is one of the scarcest elements in the Earth's crust with global annual production of approximately 7 tonnes. Our portfolio company Protium Systems has developed a catalyst formulation that reduces iridium loading by 80 percent while maintaining performance, a critical advance for the long-term cost and supply chain resilience of PEM electrolysis. ITM Power (UK), Siemens Energy, and Plug Power are the leading PEM electrolyser companies by installed capacity.
Solid oxide electrolysers operate at 700-900°C and achieve the highest thermodynamic efficiency of the three technologies — approximately 85-90 percent on a higher heating value basis, compared to 65-75 percent for PEM and alkaline at ambient temperature. At high temperature, the electrical energy required for electrolysis decreases because some of the energy required to split water can be supplied as heat rather than electricity. This thermodynamic advantage makes solid oxide particularly interesting for co-deployment with high-temperature industrial processes where waste heat is available. The challenge is durability: the high operating temperature creates thermomechanical stresses that have historically limited cell lifetimes. Elcogen (Estonia) and Sunfire (Germany) are the most advanced European solid oxide electrolyser developers.
Storage and Transport: The Unsolved Challenges
Producing green hydrogen is only the first challenge. Storing it, transporting it, and reconverting it for end use introduce additional technical and economic hurdles that significantly affect the overall system economics.
Hydrogen has a very low volumetric energy density. At atmospheric pressure, one kilogram of hydrogen — the energy equivalent of approximately one litre of diesel — occupies 11.2 cubic metres. Compression to 700 bar (the standard pressure for automotive hydrogen tanks) reduces this to 16 litres per kilogram, but compression itself consumes approximately 10-15 percent of the energy content of the hydrogen. Cryogenic liquefaction, which reduces the volume to approximately 14 litres per kilogram, requires cooling to -253°C and consumes approximately 30-35 percent of the energy content. Neither approach is as energetically benign as storing petrol in a tank or electrons in a battery.
Several alternative hydrogen storage and transport approaches are under development. Liquid organic hydrogen carriers (LOHCs), such as dibenzyltoluene, can absorb and release hydrogen through catalytic hydrogenation and dehydrogenation reactions. LOHCs can be stored and transported at ambient temperature and pressure using existing liquid fuel infrastructure, which dramatically reduces the capital cost of building a hydrogen transport system. Hydrogenious LOHC Technologies, a German company, has built the most advanced commercial demonstration of this approach. Ammonia — NH3 — provides an alternative hydrogen carrier with a volumetric energy density approximately 1.7x that of liquid hydrogen and existing large-scale transport and storage infrastructure from the fertiliser industry. The challenge for ammonia as a hydrogen carrier is the energy cost of decomposition (cracking) back to hydrogen and nitrogen at the point of use.
For European industrial applications, the most economically compelling near-term option for many users is to consume hydrogen locally at the production site — avoiding transport and storage altogether — or to connect to planned hydrogen pipeline networks. The European Hydrogen Backbone initiative, supported by 32 European gas infrastructure operators, proposes a 53,000 km hydrogen pipeline network across Europe by 2040, of which approximately 70 percent would be repurposed natural gas infrastructure. Pipeline transport of hydrogen costs approximately $0.20-0.50/kg per 1,000 km — substantially less than shipping alternatives — and would enable large-scale, economically efficient distribution from coastal import terminals to inland industrial consumers.
Investment Implications: Where the Value Will Be Created
The green hydrogen value chain — from renewable electricity generation through electrolysis to transport, storage, and end use — spans multiple capital-intensive industries. For venture investors, the most interesting opportunities are not in the capital-intensive infrastructure layers but in the enabling technology components where deep technical differentiation can create durable value.
Electrolyser technology is the most directly relevant category. The global market for electrolysers is forecast to reach $50-100 billion annually by 2030 in most bullish scenarios aligned with 1.5°C decarbonisation pathways, though more conservative forecasts project a smaller but still very large market of $15-30 billion. Within this market, the companies that achieve the most durable competitive position will be those with the most efficient catalyst formulations (reducing precious metal loading), the most manufacturable cell designs (enabling high-volume, high-yield production), and the most sophisticated stack management systems (maximising lifetime and efficiency across variable operating conditions). Protium Systems, with its iridium-reduction breakthrough and its 94 percent stack efficiency — both of which we validated independently during due diligence — addresses the two cost drivers that matter most for PEM electrolyser economics.
Balance-of-plant optimisation — the engineering of hydrogen production systems integrating electrolysers, power electronics, control systems, water purification, gas conditioning, and compression — is another area where European engineering expertise creates competitive opportunity. The electrolyser stack itself is only approximately 40 percent of total system cost; the balance of plant accounts for the remaining 60 percent, and there is substantial opportunity to reduce it through intelligent system design and integration.
Hydrogen sensing and safety technology is a market that is often overlooked but that will be substantial. Hydrogen is colourless, odourless, and extremely flammable, with a very wide flammability range (4-75 percent by volume in air). Detecting leaks, managing safety systems in hydrogen environments, and preventing the hydrogen embrittlement of steel pipelines all require specialised sensing and materials technology. The regulatory requirements for hydrogen installations are stringent and are still being defined in most jurisdictions — creating ongoing demand for certified safety technology providers.
Conclusion
Green hydrogen is not a near-term solution to all energy challenges, and the hype cycle of 2020-2022 produced some valuations and project announcements that were clearly disconnected from the engineering and economic realities. But the underlying need — a carbon-free molecule for the hard-to-abate industrial sectors — is real and will only grow as the imperative to decarbonise heavy industry intensifies.
The companies that will capture the most value from the hydrogen economy are not the energy majors and infrastructure companies that will deploy billions in capital to build electrolysis plants and pipelines. They are the deep technology companies that develop the enabling components — better catalysts, more manufacturable cell architectures, more efficient system integration — that make those plants economically viable. These are the companies we seek to fund at the seed stage, and Protium Systems represents our current highest-conviction investment in this theme.
The hydrogen economy will not arrive by 2025, or even fully by 2030. But by 2040, it will be foundational to global industrial infrastructure. The investments made today in the enabling technologies will compound over that time horizon in a way that very few other categories of deep technology investment can match.