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The Hydrogen Industry
Between Aspiration and Thermodynamics: Hydrogen has long promised a cleaner future — but physics, economics, and politics have other ideas. Our analysis examines the hydrogen industry’s foundations, structural challenges, and its contested role in the energy transition.
The Hydrogen Foundation: Promise and Premise
Hydrogen, the universe’s most abundant element, is perpetually dubbed the “fuel of the future” and a cornerstone of the global energy transition. For decades, visionaries have promised a “hydrogen economy” that would cleanse our energy system. Today, unprecedented public subsidies are fuelling a new wave of enthusiasm, positioning hydrogen as the silver bullet for decarbonising everything from steel mills to long-haul shipping.
Yet, beneath the political rhetoric and corporate cheerleading lies a more complex reality defined by thermodynamic laws, infrastructural gaps, and a persistent question: Is hydrogen a genuine pathway to net-zero, or a politically convenient placeholder that delays harder decisions on electrification and efficiency?
Feedstock Dependency and the Infrastructure Chasm
The first reality check is hydrogen’s current source. Over 95% of the ~95 million tonnes of hydrogen produced annually is “grey,” derived from fossil fuels—primarily natural gas via steam methane reforming. This existing industry has a carbon footprint comparable to that of the entire United Kingdom. Most of this hydrogen is consumed onsite at refineries and ammonia plants, highlighting that the industry today is largely a captive input, not a traded energy commodity.
The “clean” hydrogen narrative hinges on a colour-coded transition: “blue” (using carbon capture on fossil-based production) and “green” (using renewable electricity to split water). However, these definitions are already leaking.
Blue hydrogen’s viability is entirely contingent on the creation of a vast, commercially unproven CO₂ transport and storage network. Green hydrogen faces its own “additionality” problem—if it draws power from the grid instead of dedicated new renewables, it may simply be shuffling emissions rather than reducing them.
Furthermore, hydrogen has no native large-scale infrastructure. Unlike natural gas, it cannot be easily dropped into existing systems. Transporting it requires specialised pipelines or energy-intensive liquefaction.
This creates a fundamental “chicken-and-egg” paralysis: industrial offtakers are hesitant to reconfigure their processes without a guaranteed, cost-competitive supply, while producers cannot secure financing without firm offtake agreements. The state is thus forced to become the primary market-maker.
A Hierarchy of Use Cases
The hype suggests hydrogen is a universal solvent for climate change. A more sober analysis reveals a strict hierarchy of viability, separating realistic applications from thermodynamic fantasy.
- The Non-Starters: Applications where direct electrification is vastly more efficient. Battery-electric vehicles are already outcompeting hydrogen fuel cells for passenger cars. For residential heating, heat pumps offer far greater efficiency than hydrogen boilers.
- The Potentially Viable: The true test for hydrogen lies in “hard-to-abate” sectors. This includes green steel (as a reducing agent replacing coking coal), sustainable aviation fuel (SAF) production, shipping fuel, and long-duration seasonal energy storage. These are promising, but remain niche and are entirely dependent on a significant drop in hydrogen production costs.
- The Established & Essential: The current, non-negotiable demand lies in traditional industrial feedstocks, namely ammonia production for fertilisers and processes in refineries. This demand is robust but offers limited growth; it is a base, not the frontier of expansion.
Demand Drivers: Separating Structural from Cyclical
The economics of hydrogen are as much about who buys it and why as they are about how cheaply it can be made. To make sensible capital allocations in the hydrogen industry, investors must first separate cyclical swings from structural demand drivers — and then judge which use cases are realistically scalable.
Structural demand is industrial and persistent.
At the core are chemical and refining feedstocks, the birthplace of today’s hydrogen economy. Ammonia production (fertilisers) and refinery hydrogen for desulphurisation represent tens of millions of tonnes per year of near-inelastic demand. Those legacy markets create a baseline of volumetric need against which new-demand scenarios should be judged: they are the “lowest common denominator” of hydrogen off-take, not the speculative frontier.Beyond feedstocks, a smaller set of industrial applications carries structural weight because they require molecular inputs rather than electrons.
Primary steelmaking is the canonical example: replacing coking coal with hydrogen fundamentally changes metallurgical processes and capital flows. If hydrogen proves cost-competitive at scale for DRI, it will create durable regional clusters around cheap renewable or gas-connected sites.
The same logic applies, in a narrower way, to certain chemical syntheses and to synthetic fuels for aviation where energy density and liquid hydrocarbon chemistry remain essential.
Cyclical demand is weather and policy driven.
Near-term hydrogen spot and seasonal requirements will frequently behave like other commodities: they spike on supply disruption, subsidy announcements, or shortfalls in renewable output. Intermittent demand for hydrogen as seasonal storage — for example to buffer unusually low renewable yield across a winter — is plausible in certain geologies (salt caverns, large aquifers), but it is episodic, site-specific, and subject to high round-trip losses.
Where such storage value exists, it will be priced accordingly — not assumed.
Regional differentiation defines the market shape.
A two-speed world is emerging. In OECD Europe, high policy ambition and elevated power prices create incentives and subsidies for electrolytic hydrogen — but those same countries face structural affordability pressures and strong alternatives (electrification, heat pumps).
In contrast, the Middle East, parts of Australia, and some North African locations see the hydrogen narrative as an industrial export play: abundant solar/wind plus proximity to shipping routes make ammonia or e-fuel export projects attractive candidates for state-led investment.
Asia (China, India, Southeast Asia) remains the largest growth market for industrial hydrogen demand given ongoing industrialisation, fertiliser needs, and petrochemical expansion. For investors, regional exposure is therefore a primary risk/return filter.
Offtake certainty, not marginal cost alone, drives financing.
Electrolyser factories and dedicated renewable farms need multi-decade revenue visibility. That incentive structure explains why developers chase anchor offtake agreements with steelmakers, airlines (for SAF), or national champions. Without credible offtake, even the lowest-cost green hydrogen project struggles to attract capital at scale.
Certification, standards and market design matter.
Demand will be shaped not only by physical need but by definitional regimes: how regulators and markets certify “green” or “low-carbon” hydrogen affects eligibility for premiums, corporate procurement, and cross-border trade. Fragmented standards create both opportunity for arbitrage and risk of stranded certification that cannot be monetised.
Supply-side evolution will be gradual and uneven.
Electrolyser unit costs and manufacturing scale-ups are progressing — and that reduces long-run marginal production cost in favourable locations. Yet the physical constraints of liquefaction, transport losses, reconversion inefficiency and storage mean that only a subset of end uses will ever be competitive with direct electrification or emerging battery/storage alternatives.
Investor implications — how to read the signals
Prioritise demand-led projects. Give preference to developments backed by credible industrial offtakers (existing ammonia producers, steelmakers with signed LOIs, national utilities with binding PPAs).
Regionalise exposure. Match capital to regions where the combination of renewable wealth, industrial anchor demand, and political stability reduces execution risk.
Value carriers and intermediaries. Ammonia, LOHC, and methanol value chains — and their logistics and shipping players — may present more bankable early opportunities than pure hydrogen pipelines or tankers.
Stress-test policy durability. Model projects against subsidy withdrawal scenarios and against plausible carbon-price trajectories; strand risk is real.
Look beyond molecules. Electrolyser manufacturing, balance-of-plant engineering, metering, safety systems, and certification services can capture value even if molecule volumes disappoint.
Hydrogen will not fail or succeed as a monolith; it will thrive where the physics, economics, and policy align — and fail where it is merely the artefact of subsidised ambition.
The Economics of Inefficiency
The central economic challenge is thermodynamics. Hydrogen is an energy carrier, not a source. Creating, moving, and using it incurs massive “round-trip” energy penalties. From electrolysis to compression, transport, and final conversion back to electricity or heat, 60-75% of the initial energy input is lost.
This inefficiency is reflected in cost. Grey hydrogen costs less than $1/kg to produce. Green hydrogen, despite projected cost declines, remains at $3–6/kg depending on region and electrolyser utilisation, still multiple times the cost of incumbent grey hydrogen.
The capital intensity is equally staggering, requiring investment not only in electrolysers but also in dedicated renewable power capacity and entirely new transport and storage infrastructure.
While the core thermodynamic inefficiencies are immutable, the economic equation could be reshaped by non-incremental breakthroughs in electrolysis or cracking technologies, a risk that warrants monitoring even if it is not a base-case assumption.
The Hidden Costs of Purity and Distance
Hydrogen’s production cost tells only part of the story. For most industrial uses, 99.95% purity suffices — but fuel cells demand 99.97% or higher, requiring additional purification, compression, and drying steps that can add 10–15% to total energy use. These post-processing costs are rarely reflected in the headline “$4–6/kg” figures for green hydrogen.
Compression to 700 bar and liquefaction at –253°C consume another 10–30% of hydrogen’s energy content, making long-distance transport exceptionally inefficient. To circumvent this, many exporters propose converting hydrogen into ammonia (NH₃) for shipping.
While ammonia leverages existing global logistics, reconverting it back into hydrogen at the destination incurs major energy penalties — leaving as little as 30–40% of the original renewable energy intact.
Hydrogen, unlike oil or LNG, does not travel well. Its economics are local, not global — and the promise of a global hydrogen trade will only hold where production, consumption, and policy align tightly in one geography. Alternative carriers such as liquid organic hydrogen compounds (LOHCs) or methanol add conversion flexibility but introduce further energy losses and capital costs.
The capital intensity is equally staggering, requiring investment not only in electrolysers but also in dedicated renewable power capacity and entirely new transport and storage infrastructure.
The Geopolitics of Subsidy
Given these economic headwinds, the hydrogen industry is less a market and more a policy experiment. The U.S. Inflation Reduction Act offers production tax credits of up to $3/kg for clean hydrogen, effectively bridging the cost gap with grey hydrogen. The EU and Japan are pursuing similar, subsidy-driven strategies.
This has created a “subsidy transition,” where capital allocation follows government incentives rather than organic market signals. The much-touted global hydrogen trade, reminiscent of LNG, faces a fundamental barrier: shipping liquid hydrogen is exponentially more complex and expensive than shipping gas, making the “export illusion” a potent risk for projects banking on overseas demand.
Competing international standards for what constitutes “clean” hydrogen further distort the landscape, creating regulatory arbitrage rather than a cohesive global market. This subsidy-driven model echoes patterns we’ve observed in natural gas market structures, where policy consistently shapes commodity flows.
The Geologic Disruption – White Hydrogen
Current investment focuses on manufacturing hydrogen, but a potential supply-side disruption is emerging: geologic “white” hydrogen. Recent, tangible discoveries—from a potentially billion-ton reservoir in Mali to prospects under exploration in the US and Europe—suggest naturally occurring deposits could be a global reality.
Early wellhead cost estimates for white hydrogen are compelling, projected as low as $1/kg, directly challenging the economics of green and blue production. However, these resources are geographically random, rarely situated near demand centres. This immediately imposes the same logistical penalties that define the helium market, where over 30% of product value can be consumed by cryogenic transport from remote sources like Qatar and Wyoming.
The price differentials are stark evidence of this cost of distance. Bulk liquid helium can be sourced for ~$5-10/kg at production, but end-user prices routinely exceed $30-50/kg; cryogenic transport and distribution can multiply the delivered price by 5x or more versus the wellhead cost.
Hydrogen follows the same brutal arithmetic. A wellhead cost of $1/kg is a mirage; the cryogenic supply chain to deliver it to market would add a minimum of $4-6/kg, erasing its cost advantage and tying its viability to local, not global, demand.
The physics are punishing. Liquefying hydrogen requires cooling it to -253°C, only marginally less than helium’s -269°C boiling point. This process is notoriously energy-intensive, consuming ~30-35% of the hydrogen’s lower heating value, with daily boil-off losses of 0.2-0.3% during shipping—a permanent tax on distance.
The ammonia vector workaround is equally fraught; conversion to NH₃ consumes ~15% of the hydrogen’s energy, and “cracking” it back at destination costs another ~20%, with significant purity challenges for fuel cell use.
Therefore, while white hydrogen presents a compelling geologic narrative, its commercial viability is hostage to the same transport economics that constrain all energy gases. A low wellhead cost is irrelevant if the molecule cannot be delivered to market competitively, a structural reality our helium industry analysis examines in depth.
Structural Risks and the Investment Landscape
For capital allocators, the risks are structural and multifaceted:
- Technology & Supply Chain Risk: The competition between electrolyser technologies (Alkaline, PEM, SOEC) is unresolved, and PEM electrolysers depend on scarce iridium, creating a critical mineral bottleneck.
- Policy Dependency Risk: The industry’s viability is tethered to political will. Stranded asset risk is high if subsidies lapse or priorities shift.
- Offtake & Demand Risk: The projected demand from steel and aviation remains largely theoretical, reliant on future technology adoption and consumer willingness to pay a “green premium.”
- Substitution Risk: Continuous innovation in battery technology for long-duration storage and advanced biofuels for aviation could render hydrogen’s value proposition obsolete in its target niches.
The core insight for investors is a reversal of a traditional energy axiom: in the natural gas value chain, molecules became capital. In hydrogen, capital becomes molecules—a paradigm that demands extreme scrutiny of capital efficiency and policy durability.
For incumbent fossil fuel players, blue hydrogen represents a strategic ‘grey gate’—a way to leverage existing assets and delay wholesale electrification by positioning gas with CCUS as a necessary, long-term transition pillar.
Conclusion
Hydrogen’s future is not one of universal application but of targeted, high-value niches. It will not power our cars or heat our homes, but it may be the only viable solution for decarbonising specific industrial processes like primary steelmaking.
The industry now stands at a crossroads between political ambition and physical reality. It is a case study in the geopolitics of credibility and constraint, where subsidies are deployed to manufacture markets faster than physics allows.
Its ultimate fate—whether it becomes a crucial piece of the decarbonisation architecture or a cautionary tale of subsidised overreach—hinges on its ability to escape the gravity of inefficiency and prove its worth in the hard-to-abate sectors where no other alternatives exist. For investors, the critical question remains: are you funding the defensible infrastructure of the future, or merely the temporary beneficiaries of a subsidy wave?
The hydrogen industry will define whether capital can transcend chemistry — or whether physics, once again, will have the final word.
Frequently Asked Questions
Is hydrogen a good investment?
Hydrogen investments are highly segmented. Infrastructure, logistics, and enabling technologies (such as electrolysers, compression, and ammonia value chains) can offer durable opportunities, but pure-play hydrogen production remains a speculative, subsidy-dependent commodity play with unproven long-term economics. Investors should focus on offtake certainty, regional policy durability, and capital efficiency.
What are the biggest risks in the hydrogen industry?
The primary risks are structural: acute policy dependency on subsidies, unproven offtake demand in key sectors, technological obsolescence, and competition from advancing alternatives like batteries and biofuels. This creates significant stranded asset potential.
Which countries are leading in hydrogen production?
Leadership depends on definition. The US leads in subsidy-backed production under the IRA; the EU drives regulatory frameworks; and the Middle East and Australia are advancing as export hubs. China dominates electrolyser manufacturing and grey hydrogen volumes, while Japan and South Korea lead in end-use technology and fuel-cell deployment.
What is the future outlook for the hydrogen market?
The outlook is divergent. Hydrogen will likely secure a durable role in hard-to-abate sectors such as steel, ammonia, and aviation. However, there is a potential for speculative overbuild in subsidy-chasing production capacity. Success will be selective, not universal.
Who are the major companies in the hydrogen sector?
Major players include industrial gas giants (Linde, Air Liquide), energy majors (Shell, BP), and specialised electrolyser makers (Nel, ITM). Emerging projects are increasingly backed by state-owned or utility-scale players such as ACWA Power, ADNOC, and Sinopec. The segments that receive less attention are in the “picks and shovels” enablers — compression, logistics, and ammonia infrastructure — rather than pure hydrogen production.
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