Europe is entering a battery-investment race. Slovenia has become the latest EU country to obtain European Commission approval for a national support scheme, offering €59 million for the construction of stand-alone battery energy storage systems.

Similar programmes have already been authorised for several other Member States, including Italy, Poland, Hungary, Spain, Greece, Bulgaria, Czechia and Romania. Their budgets vary enormously—from tens of millions to several billion euros—reflecting both different electricity-system needs and radically different national fiscal capacities.

The subsidies are frequently presented as part of Europe’s transition from fossil fuels to electrification. That description is broadly correct, but it can also be misleading. The batteries being financed are not intended to replace strategic oil stocks or underground gas reserves with an equivalent quantity of stored electricity.

They are primarily intended to provide short-duration flexibility: absorbing renewable electricity when production exceeds demand and returning it to the grid several hours later, when electricity is scarce or more expensive.

What governments are actually financing

When a Member State notifies a battery-support scheme to the European Commission, it must explain the purpose of the measure, the market failure being addressed, the eligible technologies, the selection procedure and the conditions under which beneficiaries will receive public support.

The notified schemes normally specify the projects’ power in megawatts, their energy capacity in megawatt-hours and therefore their expected discharge duration. They may also define whether batteries must be connected directly to renewable installations or may operate independently by charging from the electricity grid.

The Slovenian programme supports stand-alone battery systems. Its stated purpose is to promote energy storage, facilitate the integration of renewable electricity and contribute to the decarbonisation of the electricity system.

These batteries will generally be expected to perform one or more commercial and system functions:

• store excess solar or wind electricity;
• supply electricity during evening or other demand peaks;
• provide frequency regulation and balancing services;
• reduce renewable-energy curtailment;
• relieve local grid congestion;
• provide capacity during periods of system scarcity.

This is not strategic energy storage in the traditional sense. A typical lithium-ion grid battery can discharge its rated power for approximately two to four hours. Larger projects increasingly offer four-hour duration, while some systems extend to six or eight hours.

By comparison, strategic oil stocks and underground gas storage are designed to cover disruptions lasting weeks or months. They can retain energy for long periods without the progressive capacity degradation experienced by electrochemical batteries.

Batteries replace gas-fired flexibility—not gas reserves

The most relevant economic comparison is therefore not between a battery and an underground gas reservoir. It is between a battery and the flexible electricity production that would otherwise be required when renewable generation falls or electricity demand rises.

In many European electricity markets, this marginal flexibility is supplied by gas-fired power stations. Gas plants can increase production when required, but their electricity costs depend on volatile fuel prices, carbon allowances, plant efficiency and operating conditions.

A battery charged with low-cost solar or wind electricity can return that electricity during a more expensive period. It may also respond within seconds and provide several services during the same day.

This repeated utilisation is essential to the business case. The International Energy Agency estimates that utility-scale battery-project costs fell by around 40% in 2024, reaching approximately $150 per kWh of installed capacity. The IEA also identifies batteries as one of the most versatile technologies for short-term power-system flexibility.

At this investment cost, a battery that completes hundreds of cycles each year can spread its capital cost over a large quantity of electricity. Depending on charging prices, financing conditions, duration and utilisation, the combined cost of renewable electricity and daily battery storage may broadly fall within a range of approximately €0.10–0.18 per kWh discharged.

This can be competitive with electricity generated by gas-fired peaking capacity, particularly when the battery also receives revenues from balancing, reserve and grid services.

The calculation changes completely if a battery is used only occasionally. A system discharged once per year must allocate nearly all its annual capital cost to a very small quantity of delivered electricity. Its storage cost can then rise into euros—or even tens of euros—per kWh.

Batteries are therefore potentially attractive for daily peaks, but economically unsuitable as a direct replacement for seasonal gas storage or rarely used strategic fuel reserves.

When public support is economically justified

Battery subsidies may be justified where the electricity market does not adequately remunerate all the services storage provides.

A battery may reduce grid congestion, avoid renewable curtailment, provide frequency regulation, delay network reinforcement and contribute to security of supply. However, these benefits are paid for through different markets—or may not be explicitly remunerated at all.

Revenue uncertainty can consequently prevent socially useful projects from obtaining financing. Temporary investment support, competitively awarded, can help overcome this problem.

Public intervention is especially defensible where projects:

• are located in areas with persistent congestion or renewable curtailment;
• replace demonstrably more expensive peak generation;
• provide services that the market does not yet remunerate adequately;
• are selected through open, competitive and technology-neutral tenders;
• share market revenues with the public authority or include clawback provisions;
• remain proportionate to quantified system needs.

The strongest schemes do not begin with a political decision to purchase batteries. They begin with an assessment of the flexibility problem and allow batteries to compete, where appropriate, with other solutions.

The risk of buying batteries before identifying the need

Battery support can become economically inefficient when governments subsidise installed capacity without accurately assessing how frequently it will be used, where it should be located and which system service it is expected to provide.

A battery located in the wrong part of the network may add little congestion relief. A project with excessive duration may cost more than its system value. A project with insufficient duration may receive capacity payments even though it cannot cover the full scarcity period.

There is also a risk of double remuneration. An operator may receive an investment subsidy while simultaneously earning revenues from energy arbitrage, balancing markets, ancillary services and capacity mechanisms.

State-aid approval should therefore ensure that public support covers only the genuine funding gap and does not guarantee private investors returns that the underlying electricity-system benefits cannot justify.

Competition between alternative flexibility resources is equally important. Grid reinforcement, cross-border interconnection, demand response, flexible industrial consumption, pumped hydropower, thermal storage and vehicle-to-grid services can sometimes deliver the same system benefit at lower cost.

A recent Joint Research Centre assessment of European interconnection needs found that, under one of the scenarios analysed for 2030 and 2040, relatively little additional battery capacity was economically required beyond the already substantial capacity assumed in the underlying scenario. The JRC stressed that the conclusion was tentative and depended heavily on those assumptions, but the finding illustrates why batteries should not be planned in isolation from networks and other flexibility resources.

National subsidies could fragment the internal market

The expansion of national support programmes also creates an EU competition-policy problem.

Member States have very different fiscal capacities. Italy’s authorised storage mechanism reaches up to €17.7 billion, while Slovenia’s programme totals €59 million. Even allowing for differences in population and energy-market size, national support conditions can influence where investors build projects and where the associated industrial activity develops.

Large subsidy differences may pull investment towards countries able to offer the most generous support rather than towards locations where storage produces the greatest European system benefit.

Batteries also participate in an interconnected electricity market. A project built in one country may affect prices, congestion and generation in neighbouring markets. Purely national planning risks underestimating these cross-border consequences.

Europe would therefore benefit from more coordinated assessments of storage needs, common tender principles and greater use of cross-border flexibility markets. EU-level financing could also reduce the competitive advantage enjoyed by Member States with greater budgetary resources.

Europe may subsidise demand for imported technology

The battery race is also an industrial-policy challenge. European companies have relevant capabilities in specialised batteries, power electronics, system integration, engineering and software. However, the EU does not currently possess a cell manufacturer with the global scale and cost position of China’s CATL or BYD.

The European Commission’s Joint Research Centre concluded in its 2025 battery-technology report that the EU does not hold a competitive advantage over its principal competitors. It identified particular weakness in lower-cost batteries and stationary energy storage.

European projects can therefore create local value through construction, project development, software, grid integration and operation while still relying heavily on imported cells and battery modules.

State aid may consequently produce a paradox: European taxpayers accelerate the electrification and resilience of the European grid, but a substantial part of the industrial value flows to non-European suppliers.

Procurement conditions cannot simply exclude foreign producers without creating legal, economic and supply-security problems. However, support schemes can legitimately reward lifecycle performance, cybersecurity, recycling, carbon footprint, supply-chain resilience and compliance with the EU Batteries Regulation.

These criteria would improve the strategic value of public expenditure without treating the lowest initial equipment price as the only measure of economic efficiency.

The political choice: subsidise technology or purchase system value?

Batteries are indispensable to an electricity system with growing shares of wind and solar power. They can reduce curtailment, lower peak prices, provide rapid grid services and reduce the number of hours in which gas-fired generators determine the market price.

This does not mean that every proposed battery investment is economically desirable or that batteries can replace all forms of stored fossil energy.

The political test should be whether each publicly supported project purchases a clearly identified system service at lower overall cost than the available alternatives.

Support is justified where batteries cycle frequently, resolve a measurable network or adequacy problem, displace expensive marginal generation and compete through transparent tenders. It is much harder to justify where governments subsidise capacity without a location-specific need, an expected utilisation profile or safeguards against excess returns.

Europe is not converting its oil tanks and gas reservoirs into batteries. It is gradually transferring short-term flexibility from stored fuels and dispatchable power stations to an increasingly digital electricity system.

The success of that transition will depend less on the headline quantity of battery capacity installed than on whether Europe places the right technology, with the right duration, in the right location—and pays no more than the resulting system value.