The hardest hour in a renewable power system is not necessarily the hour with the highest demand.
It is seven o’clock on a cold, windless evening: demand is still high, solar output has disappeared, an interconnector is constrained and every available source of flexibility is suddenly valuable.
That hour may last four hours. It may last forty, or become a multi-day weather event.
We often discuss energy storage as though it were a single answer to all of these problems. It is not. A battery that smooths short fluctuations, a system that shifts solar electricity into the evening, and an asset designed to cover several windless days provide fundamentally different services.
Yet electricity markets, procurement programmes and investment models do not always recognise those differences. They can count megawatts while overlooking time.
That is the central finding of my new executive briefing, The missing market for time, based on a structured review of 50 interviews from my Climate Confident and associated podcast archives.
The conclusion is not that technology no longer matters. It plainly does. The more interesting conclusion is that long-duration energy storage is not waiting for one decisive invention. In many cases, it is waiting for power systems to define the service they need, value it properly, contract it over an investable period and create a credible route from procurement to operation.
Battery storage is booming. Long duration is not
Storage is already one of the fastest-moving parts of the energy economy. According to the International Energy Agency’s Global Energy Review 2026, 108 GW of battery storage was deployed worldwide in 2025, 40% more than in 2024. Installed capacity is now eleven times higher than in 2021.
That is amazing progress. It can also obscure the problem.
The IEA says most projects still cluster around two hours, although durations are beginning to lengthen. Those systems can shift solar output, provide balancing services and reduce peaks. But success in short-duration batteries does not mean the market for assets covering ten hours, several days or longer is advancing at the same rate.
The scale required across the broader storage category is substantial. The IEA estimates that global capacity must reach 1,500 GW by 2030 to support the tripling of renewable generation while maintaining electricity security. Batteries provide most of that growth in its scenario. This is not, however, a 1,500 GW target for long-duration storage.
Even the term “long-duration” is unsettled. A US National Renewable Energy Laboratory review found definitions ranging from more than two hours to seasonal storage, with ten hours a common threshold. Buyers can discuss Long Duration Energy Storage (LDES) without agreeing on the problem it must solve.
Start with the uncovered period. Model what remains after transmission, interconnection, demand response, renewable diversity, short-duration storage and firm generation have all been considered. Then specify the necessary duration, location, response speed, cycling pattern and reliability.
The correct unit of analysis is not “a storage project”. It is the system condition that must be covered.
Electricity markets are good at pricing energy. Time is harder
In my recent Climate Confident conversation with Julia Souder, CEO of the Long Duration Energy Storage Council, her central argument was that markets still struggle to price time.
Wholesale markets can put a visible price on electricity delivered now and reward short-term balancing or reserve. Fewer provide stable, duration-sensitive revenues for dependable availability across a prolonged period of system stress.
An LDES asset can potentially provide energy arbitrage, capacity, congestion relief and ancillary services. On a presentation slide, these can be assembled into an attractive “revenue stack”. In the real market, however, the asset may not have access to every service, may not receive payment from every beneficiary, or may lack sufficient certainty about future revenues to support financing.
Value exists. A bankable cash flow may not.
The US Department of Energy’s 2025 commercial-liftoff analysis reaches a similar conclusion. It considers capacity markets, long-term bilateral contracts, cap-and-floor mechanisms, targeted tenders and more transparent system modelling among the potential routes to scale.
The striking point is not that one design has won. It is that technology improvement and market design must proceed together.
Targets do not finance projects. Contracts do
Governments and utilities increasingly recognise the need for storage. Recognition is welcome, but a target is not a transaction.
A developer cannot finance a project with a press release announcing a future gigawatt goal. Investors need to understand construction risk, performance, counterparties and lifetime revenues.
Procurement design therefore matters enormously.
If a tender is written around a familiar short-duration product, longer-duration technologies may be excluded before their system value is compared. If selection is dominated by initial capital cost, an asset with a longer useful life, more cycles or lower replacement costs can appear uncompetitive even when it offers a better lifecycle result.
Procurement should be technology-neutral and performance-specific. Buyers should define the service, require evidence, allocate risk explicitly and allow qualified resources to compete.
Where merchant markets cannot yet support financing, competitive long-term contracts may be needed to bridge the gap. These should retain demanding availability and performance obligations. Public support should help discover prices, build operating evidence and reduce risk, not guarantee every project a return.
The goal is a repeatable asset class, not an endless parade of demonstrations.
A signed contract is not an operating asset
Grid connection queues are long. Permitting can take years. New designs may depend on immature supply chains. Utilities demand exacting reliability and service arrangements, often before manufacturers have accumulated enough production and operating evidence.
Technologies bring different constraints. Compressed-air storage has site requirements. Flow batteries trade energy density for long cycle life. Hydrogen incurs substantial losses when electricity is converted to hydrogen and back. Thermal storage can be compelling for industrial heat, but depends on the duty and integration pathway.
That variety is a strength. It also makes the idea of declaring “LDES is ready” or “LDES is not ready” largely meaningless.
Ready for what, where, for how long and against which alternatives?
The archive evidence supports readiness in the plural. Some technologies are commercially credible for defined applications now. Others still need cost reductions, operational proof or supply-chain development. None should be selected through a technology beauty contest detached from the system requirement.
Five decisions that would move the market
For senior energy leaders and policymakers, the practical agenda is clearer than the technology debate suggests.
First, model the residual flexibility gap. Identify the hours or days that remain difficult after other resources have been included. Do not begin with a preferred storage chemistry.
Second, specify the service in time. Duration, location, availability, recovery time and cycling requirements should appear in operational language that procurement teams and investors can use.
Third, create a route to investability. Targets must become competitive tenders and contracts with sufficient revenue certainty, measurable performance and a credible allocation of risk.
Fourth, make deliverability an investment gate. Grid access, planning permission, manufacturing capacity, testing, warranties, skilled labour and long-term service should be assessed before an award, not left as implementation details.
Fifth, govern a portfolio rather than a favourite technology. Storage must be compared with transmission, flexible demand, interconnection, firm clean generation and renewable overbuild. The objective is not to maximise storage. It is to deliver the required reliability at the lowest credible system cost.
The market is moving, but not evenly
The 108 GW of battery capacity added in 2025 shows that storage can scale rapidly once technologies, revenues and customer needs align. Around 80% of those additions were utility-scale, according to the IEA. Durations are gradually increasing too, with more projects reaching four hours or beyond.
But four hours is not forty. The commercial momentum behind lithium-ion systems should not be mistaken for proof that every longer-duration pathway has crossed the same threshold. Interviews in my archive point to larger projects and accumulating performance data, but much of that evidence comes from technology providers and has not been independently audited.
Industrial applications are broadening the opportunity too. My conversation with Rondo Energy CEO John O’Donnell explored electric thermal storage as a way to convert renewable electricity into dependable industrial heat. That is not interchangeable with every grid-storage application, but it illustrates a crucial point: storage becomes valuable when it is designed around a specific service and connected to a real operating need.
Moving energy through time, and through space
Return to that difficult hour after sunset.
Storage can move plentiful electricity from an earlier period into it. But storage cannot solve every constraint. Sometimes the required electricity exists at the same moment in another region. The obstacle is the network between them.
This is the complementary infrastructure challenge at the heart of the energy transition:
Storage moves energy through time. Grids move energy through space.
The IEA estimates that meeting the global renewable goals agreed at COP28 requires not only 1,500 GW of storage by 2030, but also 25 million kilometres of new or modernised electricity grids. If grids and storage lag behind generation, its modelling shows more curtailment, higher prices and almost 40% more coal generation than under full implementation.
I will return to that second half of the equation in another executive briefing in the coming weeks, examining what prevents electricity networks from expanding and adapting at the pace the transition requires.
For now, the storage lesson is direct. We do not merely need more capacity. We need power markets and institutions capable of identifying which hours matter, paying for dependable service and turning technical capability into assets that can be financed, connected and operated.
That is the focus of my new executive briefing, The missing market for time. Drawing on evidence from 50 interviews, it sets out a practical decision framework for leaders responsible for energy planning, procurement, investment and delivery.
Read The missing market for time.
The next phase of the energy transition will be defined not simply by how much clean electricity we produce, but by whether we can deliver it at the right place and the right time.
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