Green hydrogen — hydrogen produced by electrolysing water using renewable electricity — has moved from a niche idea into mainstream energy transition planning. It promises a zero-carbon fuel or feedstock for sectors that are difficult to electrify directly: steelmaking, ammonia and fertiliser production, heavy transport (shipping and some aviation concepts), and seasonal or international energy trade. Governments and companies have announced billions of dollars of projects and targets, and the global project pipeline expanded dramatically over recent years.
But the reality on the ground in 2025 is more complex than headlines suggest. Production remains tiny compared with incumbent, fossil-based hydrogen; costs are still high in many markets; manufacturing capacity for electrolysers and supply chains for key inputs face bottlenecks; and several marquee projects have been delayed or scaled back because commercial conditions, permitting or policy support did not materialise as expected. This article lays out the current technical and commercial state of play, the main industrial use cases that could justify scale, and the concrete policy and market measures that would move green hydrogen from ambition to reality.
Global hydrogen production stood near 100 million tonnes in 2024, but low-emissions hydrogen accounted for less than 1% of that total. Announced low-emissions projects have grown, yet the IEA’s 2025 review shows the pace of realised deployment is slower than many early forecasts: low-emissions hydrogen production grew about 10% in 2024 and is on track to approach 1 million tonnes in 2025, still a small share of the market. Based on announced projects, potential low-emissions capacity by 2030 has been revised down from earlier, more optimistic estimates.
Those numbers matter because they frame two uncomfortable truths: first, even rapid percentage growth from a low base leaves green hydrogen a niche for several years; second, announced pipelines are volatile — projects are routinely postponed or cancelled when the commercial case weakens.
Producing green hydrogen requires three expensive items at scale: plentiful cheap renewables, large electrolyser capacity, and water and balance-of-plant infrastructure (compression, storage, transport). In many regions today green hydrogen production costs are still several times those of fossil-based hydrogen without carbon capture. The premium narrows when cheap renewable power is plentiful and capital costs fall, but material reductions in cost require large manufacturing scale-up for electrolysers, cheaper finance, and learning-by-doing across whole project supply chains. The IEA and recent industry analyses stress that the cost decline trajectory for electrolysers is likely more gradual than the steep curves seen for other mass-market clean technologies.
Market signals matter too: companies making heavy capital commitments need credible long-term offtake contracts or policy support (subsidies, guaranteed prices, hydrogen banks) to justify building first-of-a-kind commercial facilities. Without stable demand and predictable policy frameworks, projects become risky and financing dries up.
Electrolysers — the devices that split water into hydrogen and oxygen — are the immediate choke point for scaling green hydrogen. Manufacturing capacity is concentrated in a few countries and firms, and many announced national industrial programmes (for example production-linked incentive schemes) face timing pressure or delays as companies struggle to commission new factories and source components. In some markets companies selected for incentive schemes have sought to defer launches by a year, reflecting real-world constraints in building gigafactories for electrolysers.
Improving electrolyser economics requires more than factory gates: reducing costs of catalysts, membranes and bipolar plates; scaling supply of critical materials; improving manufacturing yield; and shortening lead times. Each incremental improvement reduces levelised hydrogen cost and expands the range of viable industrial applications.
A few countries and corporate clusters are emerging as likely early leaders. China has been installing a large share of electrolyser capacity, benefitting from low renewable costs, local supply chains and strong industrial policy. Regions with very cheap renewable power and willing governments — parts of the Middle East, Australia, and certain regions in Asia and Latin America — can produce green hydrogen more cheaply than Europe or North America. Recent IEA analysis notes that some jurisdictions can produce green hydrogen at 40–45% lower cost than high-cost regions due to cheaper capital and electricity.
At the same time, the announced global hydrogen project pipeline has proved volatile: after aggressive project announcements, analysts have tracked a contraction in the pipeline as weaker projects are shelved or delayed, though committed projects continue to grow in value and sophistication.
Ammonia production is the largest single industrial use case for hydrogen today. Green hydrogen used to make green ammonia offers a direct emissions pathway for the fertiliser sector and also provides a practical shipping fuel or energy carrier for global trade. Several large ammonia projects and pilot conversions are underway where industrial clusters have cheap renewables and local demand or export plans. For countries seeking energy export products or to decarbonise agriculture inputs, green ammonia is one of the most immediate, scalable use cases.
Steelmaking is carbon-intensive and hard to decarbonise; hydrogen-based direct reduced iron (DRI) processes can replace coke or natural gas with hydrogen as the reducing agent. Pilot projects have shown technical feasibility, but the economics hinge on hydrogen cost and stable supply. Some major steelmakers have delayed expansion phases of green-steel projects because the hydrogen market and regulatory incentives have not matured as expected. These decisions underscore how sensitive heavy industry capex choices are to policy and market readiness.
For long-distance shipping and heavy trucking, batteries are often impractical. Hydrogen, or hydrogen-derived fuels such as ammonia or e-fuels, offer higher energy density per unit mass and faster refuelling. Several pilot voyages and trials using ammonia and hydrogen blends are advancing, but full-scale adoption depends on bunkering infrastructure, safety standards, and fuel price parity with conventional marine fuels.
Green hydrogen can store surplus renewable electricity seasonally and be reconverted to power or heat when needed. For grid operators facing seasonal mismatch between wind/solar supply and demand, hydrogen provides a molecule-based storage option that batteries cannot economically match at multi-month durations. This remains an expensive option today but is attractive in regions with extreme seasonal variation and abundant renewable resources.
Hydrogen is also a feedstock for chemicals beyond ammonia (methanol, certain refining processes) and can provide high-temperature heat for industrial processes that resist electrification. These niche but important uses create a diversified first-market for green hydrogen if costs can be reduced.
Big projects attract headlines but face practical obstacles that often drive delays or revisions. Common reasons include:
Regulatory and permitting delays: building large electrolysis plants, renewable generation and associated infrastructure requires complex approvals.
Offtake uncertainty: without long-term purchase agreements or policy guarantees, project developers face revenue risk.
Financing and capital markets: high initial capex and uncertain returns make it hard to attract cheap finance; some projects require public guarantees or price supports.
Supply chain and factory build constraints: component shortages, skilled labour gaps and manufacturing ramp problems slow delivery of electrolysers and balance-of-plant. Recent company reports indicate deferred timelines for electrolyser factory commissioning in some incentive schemes.
These bottlenecks mean pragmatic smaller-scale projects and hub approaches (co-locating electrolysers, renewables and industrial demand) often have higher near-term success rates than singular mega-projects without secured markets.
To turn projects into operating green-hydrogen economies, policymakers have several effective instruments:
Contracts for Difference (CfDs) or hydrogen purchase guarantees: guarantee a price floor for producers or a ceiling for purchasers, bridging the gap between current costs and target prices.
Production incentives and grants for early plants: de-risk first movers, drive local manufacturing and create learning effects.
Green hydrogen banks or tender programmes: competitive auctions to allocate limited support to the most cost-effective projects. Some experiments have shown mixed results and need careful design to avoid stranded costs.
Regulatory streamlining and permitting fast tracks: reduce time to market for integrated projects while maintaining environmental and social safeguards.
Blending mandates and phased quotas: require a share of hydrogen in certain industrial inputs or transport fuels to create guaranteed demand.
Investment in grid and water infrastructure: many projects require new transmission, desalination or water management resources; public co-investment can be decisive.
Policy design should target systemic barriers — finance, demand visibility, permitting — rather than only subsidising symptoms.
Because the best green hydrogen resources are not always near demand centres, an export economy for hydrogen carriers (liquid hydrogen, ammonia, or e-fuels) is emerging as a strategic play for countries with cheap solar or wind. Recent industry partnerships exemplify plans for long-distance supply chains linking production basins to major importers. Export models require investment in liquefaction or ammonia synthesis, shipping solutions, and downstream cracking or direct use infrastructure in destination markets. Successful trade will also need harmonised safety rules, certifications of origin (to ensure emissions credentials), and transparent pricing mechanisms.
Green hydrogen is not automatically sustainable: electrolysis consumes water, and scaling projects in water-stressed regions requires careful planning (desalination or wastewater reuse can be integrated, but at extra cost). Lifecycle emissions depend on the additional renewable capacity built: hydrogen is only as green as the power used. Policymakers must avoid perverse outcomes — for instance, diverting renewables from direct electrification where that would deliver greater emissions reduction per dollar.
Banks and insurers are increasingly cautious, demanding demonstrable technical and market risk mitigation. Projects with credible offtake arrangements, strong project sponsors and proven technology choices secure lower financing costs. Public guarantees, blended finance structures, and multilateral development bank involvement can bridge early gaps — especially to support projects in emerging markets where capital costs are higher.
Near term (0–3 years): Focus on cluster projects where industrial demand is concentrated (ports, steel clusters, chemical hubs). Support electrolyser factory ramp-up and pilot exports. Implement targeted auctions and CfD pilots.
Medium term (3–7 years): Build out cross-border trade corridors, scale manufacturing capacity, and broaden sectoral demand via mandates for steel, fertiliser and shipping pilots. Enhance certification and traceability systems.
Long term (7–15 years): Integrate hydrogen into seasonal grid balancing strategies, develop mature international trade in carriers like ammonia, and normalise low-cost production in multiple geographies as electrolyser cost and renewables finance improve.
The key is sequencing: build credible demand first, then scale factories and pipelines so that supply growth is matched by stable offtake.
Electrolyser cost curves and factory announcements — credible, funded production lines with firm timelines are the best indicator of future cost declines.
Large industrial offtake contracts from steel, fertiliser or shipping companies that specify duration and price — these create bankable cashflows.
Policy auctions and hydrogen bank designs — successful, transparent tenders accelerate market confidence; poorly designed schemes risk wasting capital and chilling private investment.
Geographic cost spreads — regions with low renewable prices and fast permitting will lead in competitiveness; watch project economics in the Middle East, Australia and parts of Asia.
Green hydrogen sits at a genuine crossroads: it is technically viable and strategically important for decarbonising several heavy sectors, but the road from demonstration to scale requires patient engineering, hardened supply chains, credible policy frameworks and realistic project sequencing. The headlines about “hydrogen megaprojects” are useful for raising interest and capital, but long-term success will be earned in factories, permitting offices, and by contracts that lock in real demand.
If governments and industry align on robust procurement tools, support electrolyser manufacturing and avoid chasing vanity projects without market foundations, green hydrogen can move from promise to practical decarbonisation tool for the hardest parts of the economy. Until then, expect an uneven but steadily maturing market where early cluster successes and exported lessons build the foundation for broader adoption.
This article is for informational purposes only. It synthesises recent public reports, industry commentary and market signals current to 2025 and does not constitute investment, technical or regulatory advice. Readers should consult primary sources and specialist advisors for operational decisions.
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