How long-duration energy storage works, what it costs, and why it matters for renewable grids
- Editorial Team SDG7
- 14 minutes ago
- 6 min read
Published on 3 April 2026 at 03:28 GMT
By Editorial Team SDG7
Long-duration energy storage is becoming a grid necessity. As solar and wind expand, electricity systems face a practical problem: clean power does not always arrive when demand is highest. Solar production fades in the evening, wind output can weaken for hours or days, and grid operators still need to keep supply and demand in balance at every moment. This is why long-duration energy storage, often defined as storage that can discharge for more than eight to 10 hours, is moving from technical niche to mainstream energy policy. The International Energy Agency says storage is essential to meet the flexibility needs of increasingly renewable power systems.
It moves electricity across time. The principle is straightforward. When renewable generation is plentiful and power prices are low, a storage system absorbs electricity or converts it into another form of stored energy. Later, when demand rises or renewable output falls, that stored energy is released back to the grid. The technologies differ in how they store energy, how long they can discharge, how efficient they are, where they can be built and what they cost. Some are designed to shift solar power from midday into the evening. Others are aimed at overnight balancing, backup during multi-day weather events, or firm capacity in systems with very high renewable shares.
Pumped hydro is still the dominant long-duration storage technology. It works by using electricity to pump water uphill into an upper reservoir. When electricity is needed, the water is released downhill through turbines to generate power. The method is well established, scalable and capable of storing large volumes of energy for many hours. It also explains why pumped storage remains the largest form of energy storage globally. The International Hydropower Association reported that global hydropower capacity grew by 24.6 GW in 2024, including 8.4 GW of pumped storage, and that the development pipeline now exceeds 600 GW for pumped storage projects.
Lithium-ion batteries dominate the current market, but usually at shorter durations. They are modular, relatively fast to deploy and already widely used for hourly balancing, grid services and evening peak shifting. The International Energy Agency notes that batteries are typically used for sub-hourly, hourly and daily balancing, which helps explain their rapid growth in modern power systems. But when lithium-ion projects are extended to eight or 10 hours, costs usually rise significantly because more battery cells must be added. That makes lithium-ion highly useful, but not always the most economical answer for every long-duration use case.
Flow batteries are designed with longer duration in mind. These systems store energy in liquid electrolytes held in external tanks. During charging and discharging, the liquid flows through electrochemical cells. Their main attraction is that power and energy can be scaled more independently than in lithium-ion systems, which can make them more suitable as discharge duration increases. The trade-off is that they are generally less mature commercially, with lower energy density and a smaller deployment base. Still, many planners view them as a serious candidate for six-hour, 10-hour and even longer storage applications where repeated cycling matters.
Mechanical and thermal systems widen the field beyond batteries. Compressed air energy storage uses electricity to compress air, often into underground caverns or engineered vessels, then releases that air later to generate power. Liquid air systems cool air into a cryogenic liquid and later reheat it for expansion through turbines. Thermal systems, by contrast, store energy as heat in materials such as molten salts, hot solids or other media, then use that heat directly or convert it back into electricity. These options can offer lower-cost storage media than electrochemical batteries, but they often depend more heavily on site conditions, engineering choices and system integration.
Hydrogen is better suited to very long storage than daily balancing. Surplus renewable electricity can power electrolysers that split water into hydrogen and oxygen. The hydrogen can then be stored and used later in turbines, fuel cells or industrial processes. This route is attractive where energy may need to be stored for long periods or used across sectors, not only in electricity generation. Its main weakness is efficiency, because converting electricity into hydrogen and then back into electricity loses much more energy than a battery cycle. Even so, hydrogen remains relevant in debates about seasonal storage and system resilience, especially where very large volumes of stored energy may be needed.
Costs vary sharply by duration, geology, scale and design. That is why long-duration energy storage cannot be compared through a single headline number. For lithium-ion, the National Renewable Energy Laboratory, or NREL, modelled utility-scale costs across two, four, six, eight and 10 hours, with a four-hour system used as a core benchmark. Its 2025 projections put a four-hour utility-scale battery at about €211/kWh in the mid-case for 2035, with lower and higher cases of roughly €128/kWh and €294/kWh.
Emerging long-duration storage technologies are often quoted in broad ranges. The EPRI long-duration energy storage review cites pilot and early commercial cost estimates that vary by technology family, but some reported capital costs sit around €130 to €191 per kWh, while thermal retrofits in existing steam assets have been cited at roughly €52 to €91 per kWhe, again converted using the same European Central Bank reference rate. These are not universal benchmarks, and they should not be treated as directly comparable with every battery project. They are useful mainly because they show how duration, configuration and context can matter more than technology labels alone.
The cheapest option on paper is not always the most valuable on the grid. A four-hour battery may earn strong revenues in an evening peak market, while a longer-duration asset may prove more important during prolonged renewable shortfalls, transmission congestion or reserve shortages. This is where market design becomes decisive. Storage earns money not only by buying low and selling high, but also by providing reliability, frequency support, congestion relief and system adequacy. Analysts have increasingly argued that long-duration storage should be judged on its whole-system value, not only on up-front equipment costs.
Renewables change the shape of the grid. In systems with low shares of wind and solar, flexible fossil fuel plants have often balanced demand swings. In systems with high renewable penetration, the problem shifts to matching variable supply with demand over longer periods, including evenings, cloudy days and weak-wind stretches. Without enough flexibility, grids end up curtailing low-cost renewable electricity when output is high, then returning to gas or coal when output falls. That can mean higher costs and higher emissions at the same time. Long-duration storage is not the only answer, because transmission, demand response and more flexible consumption also matter, but it is becoming one of the central answers.
Policy is now as important as engineering. Many power markets still reward fast-response, shorter-duration batteries more clearly than longer-duration assets because ancillary services and short arbitrage windows are easier to monetise. Longer-duration technologies often need capacity contracts, public procurement, reliability mechanisms or other market reforms to become financeable. The US Department of Energy has tried to accelerate the field through its Long Duration Storage Shot, which targets a 90 per cent reduction in the cost of grid-scale storage that can provide more than 10 hours of energy, with a pathway to about €0.043 per kWh levelised cost of storage, converted from the original $0.05/kWh benchmark using the same European Central Bank rate.
Every technology comes with trade-offs. Pumped hydro can involve land use disputes, ecosystem concerns and long permitting timelines. Battery supply chains raise questions about minerals, refining, labour standards and end-of-life management. Hydrogen can require expensive infrastructure and may strain water resources in some locations. Thermal and mechanical systems can reduce some materials risks, but may depend on specific industrial settings or geological conditions. The most suitable solution therefore depends not only on cost, but also on social consent, environmental constraints and the structure of the local grid.
This issue connects directly to SDG 7 (affordable and clean energy), SDG 9 (industry, innovation and infrastructure) and SDG 13 (climate action). The link is practical rather than symbolic. Without more flexible grids, countries can add wind and solar capacity without fully capturing its value, because clean electricity generated at the wrong time cannot displace fossil generation effectively. Long-duration energy storage is therefore not only a technology story. It is a question of infrastructure planning, regulatory design, industrial policy and public interest. Long-duration storage could decide how far renewable grids can go.
Further information:
· International Energy Agency, provides global analysis on grid-scale storage, renewable integration and power-system flexibility.
· International Hydropower Association, tracks pumped storage deployment and the global hydropower project pipeline. https://www.hydropower.org
· EPRI, examines pilot projects and cost metrics across electrochemical, mechanical, thermal and chemical long-duration storage. https://www.epri.com
