Executive Summary

Electricity storage is becoming a core component of Europe’s energy system. The rapid expansion of wind and solar generation, the electrification of transport, heating and industrial processes, and the progressive reduction of dispatchable fossil generation are increasing the value of flexibility across timescales ranging from milliseconds to seasons.

Europe does not need one storage technology. It needs a layered storage architecture in which technologies compete according to response time, discharge duration, location, expected utilisation, lifecycle cost and security value. A technology that is highly efficient for daily cycling may be economically unsuitable for a reserve retained for weeks or months.

Battery storage can reduce renewable curtailment, defer some network investment, provide balancing and ancillary services and displace expensive gas-fired peak generation.

Lithium-iron-phosphate systems are currently the commercial benchmark for frequent cycling over one to eight hours, but their energy cost rises broadly with the number of cells required.

Pumped hydro, flow batteries, compressed air, thermal storage, metal-air systems and hydrogen address different duration ranges and should not be assessed through a single efficiency ranking.

Public policy should define the required system service before selecting the technology. Tenders should normally specify MW, MWh, duration, location, availability and performance.

The industrial issue is as important as the power-system issue: public support may create European construction and integration activity while a substantial share of cell-manufacturing value remains outside the EU.

1. Why Electricity Storage Is Becoming Strategic

The traditional European electricity system was organised around dispatchable generation. Coal, gas, nuclear and reservoir hydropower could adjust output, while fuels themselves provided large inventories of stored primary energy. A system with much larger shares of variable wind and solar generation requires flexibility to be supplied through storage, networks, flexible demand, interconnection and dispatchable low-carbon resources.

Storage creates value in several ways: it moves electricity between periods, responds to deviations between supply and demand, relieves congestion, supports voltage and frequency, supplies capacity during scarcity events and improves resilience. These services differ technically and economically. Treating them as one generic storage requirement leads to poor investment decisions.

The European Commission’s key facts indicate that storage capacity could rise from roughly 89 GW in 2024, mainly pumped hydro, to more than 200 GW by 2030 and 600 GW by 2050. The same material anticipates around 128 GW/300 GWh of additional electrochemical storage by 2030. These figures are scenario-based rather than binding targets, but they illustrate the scale of the expected transformation.

2. Storage Functions: From Milliseconds to Seasons

Power and energy must be stated separately. A 100 MW facility with 100 MWh can operate at rated power for one hour; a 100 MW facility with 800 MWh can do so for eight hours. A headline expressed only in MW is therefore insufficient to evaluate adequacy or resilience.

3. Current Deployment and the European Outlook

Pumped-storage hydropower remains the dominant mature form of European electricity storage. It benefits from long asset lives, large unit sizes and low incremental energy-capacity costs at favourable sites. Its expansion is constrained by geography, permitting, environmental impacts and construction lead times.

Electrochemical battery deployment is growing much faster. Utility-scale systems, commercial and industrial installations and household batteries are being added in parallel. Lithium-iron-phosphate chemistry has become particularly important for stationary projects because it combines relatively low cost, long cycle life and reduced dependence on nickel and cobalt.

The IEA reported that global battery-storage additions reached 108 GW in 2025 and that LFP accounted for around 90% of deployments. European conditions differ by market, but the global manufacturing scale and pricing of LFP strongly influence European project choices.

4. Main Storage Technologies

Efficiencies are not perfectly comparable. Thermal storage can be highly efficient when heat is used directly, but significantly less efficient if reconverted into electricity. Hydrogen has low power-to-power efficiency, yet may be economically superior for rare seasonal use because large-volume storage can be comparatively inexpensive.

5. Why Lithium-Ion Dominates—and Where It Stops Making Sense

Lithium-ion systems dominate new electrochemical projects because they are modular, fast to build, highly efficient and supported by a global manufacturing base initially scaled for consumer electronics and electric vehicles. They can respond in milliseconds, cycle daily and combine energy arbitrage with ancillary-service and capacity revenues.

• Daily charge and discharge cycles
• Two-, four- and six-hour installations
• Rapid response and precise dispatch
• Modular deployment close to demand or generation
• Mature inverters, controls and warranties
• Strong global supply chains and declining costs

The limitation is the close relationship between duration and cell quantity. Increasing a four-hour project to eight hours generally requires much more electrochemical material, container capacity and capital. Lithium-ion therefore becomes progressively less attractive when energy must be retained for days rather than hours, especially when the asset is rarely discharged.

6. Long-Duration and Seasonal Alternatives

6.1. Redox-Flow Batteries

Flow batteries store energy in liquid electrolytes held in external tanks. Power is determined mainly by the electrochemical stack, while duration is increased by enlarging electrolyte volumes. This separation can make longer duration cheaper than adding equivalent lithium-ion cells. Advantages include high cycle life and relatively low fire risk; limitations include space, balance-of-plant cost and material exposure in some chemistries.

6.2. Sodium-Based Batteries

Sodium-ion technology uses abundant sodium and can reduce exposure to lithium, nickel and cobalt. Lower energy density is less problematic in stationary applications than in vehicles. Sodium-sulphur systems already have a commercial track record at grid scale, although operating temperature and safety requirements limit their market.

6.3. Iron-Air and Metal-Air Systems

Metal-air developers target durations measured in tens of hours or days. Their proposition is not superior round-trip efficiency but low-cost abundant active materials and a lower marginal cost of adding energy capacity. Commercial maturity remains limited and performance claims require project-level validation.

6.4. Pumped-Storage Hydropower

Pumped hydro is the benchmark large-scale long-duration technology. It can operate for decades and provide energy shifting, inertia, reserves and black-start capability. Expansion depends on site availability, permitting and social acceptance. Upgrades and conversion of existing reservoirs may offer lower-impact opportunities.

6.5. Compressed Air and Thermal Storage

Compressed-air systems use electricity to compress air into caverns or engineered vessels and later expand it to produce power. Advanced designs retain compression heat to improve efficiency. Thermal systems store hot water, molten salts, rocks, sand, cold or phase-change energy. They are particularly compelling when the final demand is heat, avoiding the losses and cost of reconversion to electricity.

6.6. Hydrogen and Renewable Molecules

Hydrogen is a leading candidate for seasonal storage because very large quantities can potentially be held in salt caverns and used in industry, turbines or fuel cells. Its low round-trip efficiency makes it unattractive for daily cycling, but storage duration and low utilisation can reverse the economic ranking. Renewable gases and synthetic liquids may also preserve strategic fuel functions in sectors that cannot be fully electrified.

7. Technology and Cost Comparison

Storage costs should be assessed through several measures: capital cost per kW of power, capital cost per kWh of energy, fixed and variable operating costs, efficiency, degradation, cycle life, financing cost, utilisation and residual value. A single cost per kWh cannot describe every use.

8. The Economics of Utilisation

A storage asset’s annualised capital cost is spread across the energy it actually discharges. A one-kWh battery cycled almost daily may deliver hundreds of kWh per year. The same battery held as a reserve and discharged once per year delivers only one kWh against a similar annual capital charge.

Using an illustrative utility-scale installed battery cost around €140 per kWh, a 15-year life, a 7% cost of capital, operating allowances and 85% round-trip efficiency, daily cycling can yield an infrastructure cost of roughly €0.06–0.07 per discharged kWh before charging energy. With low-cost charging, total discharged electricity may fall broadly around €0.10–0.18 per kWh. If discharged only once annually, the capital component can rise to tens of euros per kWh.

These figures are scenarios, not universal prices. Their purpose is to show that utilisation, not only efficiency, determines economic suitability.

9. Networks, Interconnections and Demand Response

Storage is one flexibility resource among several. Network reinforcement can remove persistent congestion; interconnection can aggregate geographically diverse production and demand; demand response can shift industrial and household consumption; flexible generation and limited renewable curtailment may sometimes cost less than storing every surplus kWh.

The correct counterfactual for a battery project is therefore not “no storage”. It is the least-cost portfolio of storage, networks, demand response, generation flexibility and controlled curtailment that provides the same system service.

10. Industrial Supply and European Dependencies

The global battery supply chain is concentrated in Asia, particularly China. CATL, BYD, EVE Energy, Hithium, CALB, Gotion and other Chinese manufacturers have strong positions in LFP cells and stationary systems. Korean and Japanese producers remain important, while Tesla is a major system integrator that also relies on external cell supply.

Europe has relevant capabilities in specialised batteries, engineering, power electronics, software and integration. Companies and projects include Saft, Automotive Cells Company, Verkor, Wärtsilä, Fluence, Siemens Energy and Hitachi Energy. The EU’s position is weaker in competitively priced mass-produced cells for stationary applications. The JRC’s 2025 assessment states that batteries for lower-cost vehicles and stationary storage are falling short relative to European ambitions.

Policy should distinguish the origin of cells from the location of integration and value creation. European value can be generated through project development, construction, converters, controls, cybersecurity, maintenance and recycling even where cells are imported. Strategic vulnerability nevertheless remains if critical components, software or materials are concentrated in a small number of external suppliers.

11. Public Financing and State Aid

Since September 2022 the Commission has authorised a series of national schemes supporting electricity-storage facilities. Their technologies and functions differ. Some measures explicitly support battery systems; others, notably Italy’s mechanism, are technologically open and procure longer-duration capacity through competitive procedures.

State aid can be justified where storage provides system benefits that markets do not fully remunerate, where revenue uncertainty prevents financing or where rapid deployment is needed. Risks include technology bias, overcompensation, poor location, inappropriate duration, duplicated revenue streams, subsidy competition and increased import dependence.

This eDossier treats State aid as one instrument within a broader storage strategy. A separate eBriefing provides the detailed regulatory analysis.

12. Investment Opportunities and Principal Risks

Investors should test expected utilisation, location, connection rights, market access, warranty conditions, degradation, augmentation requirements, merchant-price exposure and the compatibility of multiple revenue streams. Public authorities should evaluate whether the selected project provides lower system cost than the alternatives.

13. European Scenarios to 2030 and 2050

The Commission’s indicative pathways point to more than 200 GW of storage by 2030 and 600 GW by 2050. The precise technology mix will depend on renewable deployment, electrification, interconnection, market reform, permitting and the cost trajectories of emerging technologies.

14. Policy Recommendations

The following recommendations are based on three complementary considerations: the requirements applied by the European Commission when assessing support measures for electricity storage, the economic need to ensure that public and private investment delivers proportionate system value, and the objective of integrating storage optimally within national electricity networks and the wider European power system. They are intended to help public authorities identify the service required before selecting a technology, compare storage with alternative flexibility solutions, limit overcompensation and ensure that national measures contribute to efficient, secure and coordinated electricity-market development.

• Define the required system service before choosing the technology.
• Require every programme and project to publish both MW and MWh, together with discharge duration.
• Use technology-neutral procurement where technologies can genuinely provide equivalent performance.
• Include location, availability, response time, duration and expected annual utilisation in tender design.
• Compare storage with networks, interconnection, demand response, flexible generation and controlled curtailment.
• Prevent overcompensation by accounting for energy, balancing, ancillary-service and capacity revenues.
• Develop an EU strategy for long-duration and seasonal storage rather than relying on short-duration batteries by default.
• Support industrial resilience through lifecycle, cybersecurity, recycling and supply-chain criteria compatible with EU law.
• Coordinate national schemes and evaluate cross-border effects on the internal electricity market.
• Improve public data on installed MW, MWh, duration, technology, utilisation and project economics.

15. Conclusions

Electricity storage will become indispensable to Europe’s decarbonised power system, but installed capacity is not an objective in itself. The policy and investment objective must be to obtain the required flexibility, adequacy and resilience at the lowest total system cost.

Lithium-ion batteries are likely to remain dominant in short-duration applications. Pumped-storage hydropower will continue to provide large-scale, mature storage, while flow batteries, sodium-based systems, metal-air technologies, compressed-air storage, thermal storage and hydrogen will compete across longer durations. Their success will depend on bankability, site conditions, market design and the economic value assigned to resilience.

Europe’s strategic advantage will therefore come not from selecting a single technological winner, but from building a layered architecture and a competitive market in which the appropriate technology is selected for each service. The central rule is simple: define duration, location, utilisation and security value first; select the technology second.

This principle becomes even more important as the European Union expands electricity interconnections not only between Member States but also with neighbouring third countries. The European Commission has supported this development through its Union lists of Projects of Common Interest and Projects of Mutual Interest. These include the ELMED interconnector between Italy and Tunisia, the GREGY interconnector between Greece and Egypt and, more recently, the Medlink connections between Italy, Algeria and Tunisia.

Such interconnections can provide genuine economic and environmental benefits. They can diversify electricity supply, permit access to renewable generation located in regions with favourable solar or wind resources, smooth differences in production patterns and reduce the overall cost of balancing an increasingly integrated European power system.

However, cross-border electricity imports cannot be treated as the functional equivalent of physically held oil and gas reserves.

Hydrocarbon stocks constitute material energy assets located within—or under the direct control of—the importing country. Subject to the availability of the necessary conversion and distribution infrastructure, they can remain stored for weeks or months and can continue to supply the economy after an external delivery route has been interrupted.

Imported electricity is different. It is delivered as a continuous flow and must be consumed, redirected or stored almost instantaneously. Unless the importing system has sufficient domestic generation, storage, reserve capacity and demand-response resources, the loss of a major external interconnector can remove a large block of supply within seconds.

Power systems are designed to withstand individual contingencies, and the interruption of one connection should not automatically cause a blackout. Nevertheless, if the lost import exceeds available reserves or coincides with other generation and network constraints, the resulting imbalance can produce a rapid fall in frequency, automatic load shedding and, in an extreme case, cascading outages.

An electricity strategy based excessively on imports from third countries could therefore replace one form of external energy dependence with another that has different—and potentially faster—failure dynamics. Fossil-fuel dependence exposes Europe to price shocks and the gradual depletion of physical stocks. Excessive dependence on imported electricity could expose it to the immediate interruption of energy flows because of technical failure, cyberattack, physical sabotage, contractual disputes or geopolitical decisions taken outside the Union.

This does not mean that electricity interconnection with neighbouring countries should be rejected. It means that imported electricity should complement, rather than substitute for, adequate European production, storage and system reserves.

Projects connecting the EU with third countries should consequently be assessed not only according to their expected electricity price and decarbonisation benefits, but also against their contribution to—or possible deterioration of—European strategic resilience. Their evaluation should include:

• The maximum share of national and regional demand dependent on each external corridor
• The availability of domestic replacement generation and stored energy
• The time required to replace a sudden loss of imports
• Physical and cybersecurity risks affecting cables, converter stations and foreign networks
• The reliability and political stability of supplier and transit countries
• The availability of automatic reserves, demand response and controlled load shedding
• The consequences of simultaneous disruption to more than one interconnector

The strategic objective should therefore be a balanced European electricity system combining domestic low-carbon generation, internal and external interconnections, short- and long-duration storage, flexible demand and sufficient autonomous reserves.

Europe should benefit from imported renewable electricity where it reduces costs and strengthens diversification. It should not allow the availability of apparently inexpensive external power to weaken the domestic production and storage capacity required to operate the European economy during a prolonged geopolitical or infrastructural disruption.