The UK is putting public money behind technologies designed to store electricity for at least 100 hours, reflecting a growing recognition that a power system increasingly dependent on wind and solar cannot rely solely on short duration batteries to manage prolonged periods of low renewable generation.
The £28 million Ultra Long Duration Energy Storage challenge announced on August 20 will support two areas: electrochemical technologies that have not yet reached commercial scale and the development and testing of underground hydrogen storage. The program is intended to advance technologies capable of supplying clean electricity for four days or more.
The distinction is important. Britain is not simply looking for more battery capacity. It is attempting to address a different system problem: how to maintain electricity supply during extended periods when renewable generation is low, while reducing reliance on gas fired generation. That challenge becomes more significant as the UK pursues its Clean Power 2030 objective.
Long duration electricity storage already exists in Great Britain, but its scale remains limited. The country has approximately 2.8 GW of long duration storage across four pumped storage hydropower facilities in Scotland and Wales, according to Ofgem. No new pumped storage scheme has been commissioned in Britain for more than four decades.
Ofgem defines long duration electricity storage as systems capable of storing electricity for extended periods, generally eight hours or more. Its first cap and floor procurement window is intended to support projects capable of operating at the scale required by a more renewable electricity system.
The regulator provisionally selected 16 projects for its first LDES portfolio in June, although final determinations are still pending. The initial application window was designed around an indicative capacity range of 2.7 GW to 7.7 GW, based on system requirements identified by the National Energy System Operator.
The government’s new research funding therefore sits alongside a separate effort to create an investment framework for commercially deployable storage.
A technology can demonstrate that it works technically without demonstrating that it can earn sufficient revenue in electricity markets to justify construction. The cap and floor model is designed to address that problem by providing a minimum revenue level while returning excess revenues above a defined cap to consumers.
Hydrogen enters the storage discussion because its physical characteristics make it potentially suitable for much longer storage durations than conventional electrochemical systems.
Electricity can be converted into hydrogen when renewable generation exceeds immediate demand. The hydrogen can then be stored and converted back into electricity when the power system requires it. Underground storage, particularly in suitable salt formations, offers the possibility of holding large quantities of energy for extended periods.
That makes hydrogen fundamentally different from a lithium ion battery optimized around daily cycling.
The UK government’s interest in the technology is also linked to the country’s existing gas infrastructure and geological resources. But the potential should not be confused with established commercial economics. Underground hydrogen storage at the required scale still requires further technical validation, including the behavior of hydrogen in subsurface formations, well integrity, cycling performance, purity requirements and the economics of compression and reconversion.
The £28 million challenge is consequently better understood as technology development funding than as an infrastructure deployment program. The government is attempting to reduce technical and commercial uncertainty before larger amounts of capital are committed.
That is consistent with the broader UK approach to longer duration storage. The government’s Longer Duration Energy Storage Demonstration Programme, which ran from 2021 to 2026, was explicitly designed to accelerate innovative storage technologies toward demonstration. Its supported technologies included power to X, thermal storage and electrical storage.
The scale of the new funding also puts the policy intervention into perspective. £28 million is meaningful for research, engineering and demonstration, but it is not enough to finance a national hydrogen storage network. The more important financial mechanism for eventual deployment is likely to be the Ofgem cap and floor regime.
Ofgem’s framework is explicitly designed around the problem that LDES projects have high upfront capital requirements and long development periods while their future market revenues remain uncertain. The regulator’s technical framework allows projects to recover efficient capital and operating costs through the regulated revenue mechanism, subject to the scheme’s conditions.
That creates two different stages of market development. The first is proving that a technology can operate reliably at the required duration and scale. The second is creating a revenue structure capable of supporting commercial investment. Hydrogen storage currently remains much closer to the first stage than the second.
This matters because the economics of hydrogen storage cannot be assessed solely through the cost of producing hydrogen. The full system calculation must include electrolyzer utilization, renewable electricity costs, compression, storage construction, cycling losses, reconversion efficiency and the value of electricity delivered during periods of scarcity.
If hydrogen is produced using renewable electricity that would otherwise have been curtailed, the opportunity cost of the electricity can be relatively low. If dedicated renewable generation is required specifically to produce hydrogen for storage, the economics become considerably more demanding.
The case for ultra long duration storage does not mean every period of low wind and solar generation should be covered by hydrogen.
Different storage technologies operate on different timescales and have different cost structures. Short duration batteries can provide rapid balancing and shifting over hours. Pumped storage can provide longer periods of discharge. Other technologies, including compressed air, liquid air and flow batteries, are being developed for different duration and cycling requirements. Ofgem’s current LDES framework explicitly encompasses a range of technologies rather than prescribing hydrogen as the solution.
That is where the system value can potentially outweigh its lower round trip efficiency compared with batteries. Converting electricity into hydrogen and then back into electricity involves significant energy losses. But if the alternative is curtailing renewable generation or maintaining large amounts of gas generation to cover relatively infrequent multi day shortages, the relevant comparison is not simply round trip efficiency.
This is also why four day storage is a different proposition from daily energy shifting. A battery designed to cycle every day can monetize frequent differences between electricity prices. A hydrogen storage facility designed primarily for rare periods of prolonged renewable scarcity may cycle far less frequently. Its business case therefore depends more heavily on the value of capacity, security of supply and avoided system costs than on conventional energy arbitrage.
The UK government’s assessment of underground hydrogen storage has placed potential energy system savings between £14 billion and £50 billion over 2035 to 2050. The breadth of that range is itself revealing.
A difference of £36 billion between the lower and upper estimates means the economic outcome depends heavily on assumptions about renewable deployment, gas prices, storage requirements, electricity demand and the performance and cost of competing technologies.
Such estimates should therefore be interpreted as an indication of potential system value rather than a forecast of guaranteed savings.
The uncertainty is particularly relevant because the storage requirement will depend on the structure of the future power system. More interconnection, demand flexibility, nuclear generation, renewable overbuild, grid expansion and alternative storage technologies could all reduce the amount of hydrogen storage ultimately required.
Conversely, faster electrification of transport and heating could increase electricity demand and make flexibility and storage more valuable.
The value of hydrogen storage will therefore emerge from interactions across the electricity system rather than from hydrogen economics in isolation.
The most consequential development for UK hydrogen storage may ultimately be regulatory rather than technological.
Ofgem’s first LDES cap and floor window has moved through eligibility and project assessment, with 16 projects provisionally identified for support. Final decisions are expected later in 2026. The regulator has also been developing the special license conditions that successful projects will operate under.
If an eligible storage project earns less than its regulated revenue floor, consumers provide support through the mechanism. If revenues exceed the cap, additional value is returned to consumers.
That structure recognizes a problem inherent to long duration storage: the technologies may provide significant system value without generating predictable merchant revenues.
For hydrogen storage, the question is whether the same regulatory logic can eventually accommodate assets whose primary value may emerge during relatively infrequent periods of system stress.
If it can, the UK could move from funding demonstrations toward financing infrastructure.
If it cannot, the sector risks remaining trapped between successful pilot projects and commercially difficult large scale deployment.
The UK is therefore pursuing two separate but connected objectives. The first is technological. The Ultra Long Duration Energy Storage challenge is intended to determine which emerging technologies can reliably deliver 100 hours or more of stored electricity.
The second is financial and regulatory. Ofgem is developing a mechanism designed to make long duration storage investable despite uncertain market revenues.
Hydrogen occupies an unusual position between those efforts. It has the potential to store energy for periods far longer than conventional batteries, but its comparatively complex conversion chain means that its value depends heavily on how often the system actually needs multi day storage and what alternatives are available.
That makes the next phase of development less about proving that hydrogen can store energy and more about establishing where doing so creates enough system value to justify the additional infrastructure and conversion losses.
The £28 million program can help answer the technical questions. The cap and floor regime will be more important in determining whether the answers translate into assets on the British energy system.
For the UK, that distinction is becoming increasingly important as renewable generation expands. The strategic challenge is no longer simply adding more clean electricity. It is building enough flexibility to ensure that electricity generated during periods of abundant wind and solar can remain useful when those resources are unavailable for days rather than hours.
Underground hydrogen storage is being tested against precisely that problem, but whether it becomes a major component of Britain’s future power system will depend on something more difficult than demonstrating technical feasibility: proving that four days of stored energy can deliver enough system value to warrant the capital required to build it.
