Hydrogen and the valley of realization

Hydrogen has entered a critical but necessary phase in its development. After several years of ambitious targets, large project announcements and expectations of rapid cost reductions, developers are confronting the practical constraints and long lead times of large-scale energy deployment. Securing affordable low-emissions supply, sustained demand, infrastructure, permits and finance take longer than early projections often assume.

This phase, which I call the “valley of realization,” exposes the gap between technical feasibility and commercial viability within integrated energy systems. Project delays and cancellations are often interpreted as evidence that hydrogen has failed. But they can also reflect a process of industrial learning and market selection, helping to clarify where, and under what conditions, hydrogen can generate sufficient value to justify investment.

Solar and wind offer useful precedents. Both industries experienced periods of heightened expectations, policy-driven expansion, difficult economics and consolidation, requiring repeated adjustments to business models and support mechanisms. Their progress depended on manufacturing improvements and learning by doing, alongside effective project execution, grid integration, dependable revenues and reliable supply chains.

Hydrogen is undergoing a comparable process, although its trajectory and eventual scale will reflect different technical and market conditions. The experience of solar and wind demonstrates the importance of commercial discipline and adaptation across energy systems, but it does not establish that every hydrogen application will eventually become competitive.

The connection goes beyond this historical parallel. The renewed interest in hydrogen owes much to the substantial cost reductions achieved by solar and wind, technologies once considered too expensive for widespread adoption. Their increasing competitiveness, together with advances in electrolyzer technology and manufacturing, has improved the prospects for low-carbon hydrogen at scale. Progress in one part of the energy system has opened opportunities in another.

Why this cycle is different

Lower renewable generation costs do not automatically translate into affordable hydrogen delivered to customers. The final cost depends on electricity procurement, electrolyzer utilization, capital costs, operating performance, water availability, compression, storage, transport and certification. Variable renewable generation creates a trade-off: electricity may be inexpensive when available, but electrolyzers must operate enough hours to recover their capital costs. A project designed around the lowest electricity price may therefore produce more expensive hydrogen than one using a higher cost but more consistent power supply. The comparison with solar and wind has limits: falling component costs do not guarantee equivalent reductions in the cost of the service delivered by the complete system.

Hydrogen is an energy carrier, not a primary energy source: producing it consumes energy, and further losses arise from conversion, storage and use. Direct electrification will often provide a more efficient pathway. Hydrogen has a stronger case where molecules serve as an essential feedstock or provide a service that electricity cannot deliver as effectively or at lower total system cost. Such applications include existing industrial uses (such as refining and ammonia production), industrial processes that are difficult to decarbonize, hydrogen-derived fuels and, under suitable conditions, long-duration energy storage.

Hydrogen can complement renewable and nuclear generation by converting low-emissions electricity into chemical form for later use, potentially enabling long-duration or seasonal storage. Stored hydrogen can then supply industrial users or be reconverted into electricity, although the value of this flexibility must be weighed against conversion losses and infrastructure costs.

These applications must be assessed by comparing the costs, emissions, reliability and performance of complete systems delivering equivalent services. The comparison should also include the emissions and energy security implications of continued reliance on incumbent fuels.

From announcements to investment decisions

Deployment remains modest relative to earlier ambitions. Low-emissions hydrogen accounts for only a small fraction of global hydrogen production (less than 1% in 2025, according to the IEA), and current project pipelines suggest that conventional hydrogen will continue to dominate supply through the end of the decade.¹ Announcements alone therefore remain a poor measure of progress.

The hydrogen sector is moving beyond a race for technological leadership and capacity expansion, fueled partly by subsidies and the pursuit of first-mover advantages. Early access to public support encouraged developers to announce projects and secure strategic positions before markets and infrastructure had matured. Attention is now turning to industrial reliability, system integration and bankable demand.

Electrolyzer manufacturers illustrate this adjustment. They face slower-than-anticipated demand growth, higher financing costs and manufacturing overcapacity, despite accumulating technical and commercial experience. This combination is characteristic of the valley of realization: knowledge continues to grow, but the investment pipeline narrows as early assumptions are tested against the realities of deployment.

Limited deployment and investment in low-carbon hydrogen constrain manufacturing experience, infrastructure development and the cumulative learning through which costs and risks decline. Innovation at this stage is not confined to electrolyzer technology; it also involves project design, financing, infrastructure, contracting and market formation.

A bankable hydrogen project requires more than a subsidy or a favorable production cost estimate. It needs customers prepared to enter into long-term purchase agreements, reliable electricity or feedstock supply, equipment backed by credible performance guarantees, and access to storage and transport. Securing such commitments is particularly challenging where low-emissions hydrogen carries a substantial premium over conventional alternatives. Industrial customers operating in competitive markets may be unable or unwilling to absorb that premium unless regulation, carbon pricing, procurement requirements or other market mechanisms reward emissions reductions.

Construction, regulatory and market risks must be allocated to the parties best able to manage them. Certification and tracking along the value chain must substantiate the product’s emissions benefits. Public support can bridge initial cost gaps and reduce revenue uncertainty, provided it is sufficiently stable and predictable to support the long-term financing typical of the energy sector. Deployment targets cannot, by themselves, create these commercial conditions.

The policy challenge is to sustain commitment over the time required to build energy infrastructure and markets at scale. Jurisdictions able to align industrial policy, infrastructure development, financing and demand creation over long time horizons may be better positioned to bring technologies into commercial use than those relying primarily on individual project incentives.

Disciplined project selection can improve capital allocation. Projects serving established industrial demand, supported by firm offtake agreements and located near enabling infrastructure have a clearer route to final investment decision. Those that depend on export terminals, pipelines, import rules and premium-paying customers all developing in parallel face interdependent risks. Coordinated infrastructure investment and efficient market designs may resolve some of these challenges. Other projects will need to be redesigned, developed in stages or cancelled.

Efficiency at the system level

A race to maximize capacity through individual projects can duplicate infrastructure and leave assets underutilized or stranded. Regional hydrogen hubs offer a more coherent approach by bringing production, identifiable demand and shared infrastructure together. As with natural gas, regional networks are likely to provide a foundation for wider trade as infrastructure, demand and commercial agreements mature, although hydrogen and its derivatives may follow different pathways.

Anchor customers can support the initial investment in production, storage and transport, allowing additional users to join as the network develops. In some regions, replacing conventional hydrogen in refining and ammonia production may establish demand sooner than creating entirely new applications. In others, the location of industrial clusters, ports or suitable storage resources may favor a different sequence. Resource availability, industrial structure, power market design and regulation will determine which configurations are most viable.

Spain’s Puertollano project, inaugurated in 2022, integrates a 100 MW solar photovoltaic plant, a 20 MW electrolyzer, a 20-MWh lithium-ion battery system and about 6 tons of hydrogen storage to supply an existing ammonia plant. The €150 million facility was designed to produce up to 3,000 tons of renewable hydrogen per year. Iberdrola estimates that the plant avoids about 39,000 tons of CO₂ per year.² Hydrogen storage helps maintain a stable supply to the ammonia plant while enabling a more efficient use of variable renewable generation. The project is a concrete example of the complementarity of renewable electricity, batteries and hydrogen storage, although published information does not establish a cost advantage over conventional hydrogen production.

The hub approach makes these relationships central to investment decisions. Production capacity must be developed alongside the infrastructure and demand needed to use it, with expansion based on credible expectations of utilization. Commercial discipline can help developers and investors assess whether projects can deliver reliable emissions reductions at acceptable costs. For EU Member States, the priority is to align policy commitments with infrastructure lead times and credible demand, while retaining the flexibility to redirect support as evidence develops. Success should be judged by the contribution of the overall system to affordability, energy security and decarbonization, rather than announced capacity alone.

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