Southeast Europe is emerging as one of Europe’s most attractive electricity-storage markets, as widening intraday price spreads create a stronger commercial case for batteries than in many mature northern European markets. The opportunity is being driven by rapid solar deployment, constrained transmission networks, volatile hydropower output and continued reliance on thermal generation during evening demand peaks.
ENTSO-E’s latest value indicators place Hungary at the top of Europe’s storage market, followed closely by Greece at €798/MW, Bulgaria at €797/MW and Romania at €792/MW. Croatia recorded €692/MW and Slovenia €668/MW, compared with just €406/MW in Italy, €326/MW in Sweden and €215/MW in Norway.
These indicators measure the average spread between the eight lowest-priced and eight highest-priced hours of each day. They should not be interpreted as annual revenue forecasts, but they provide a useful indication of where energy-arbitrage conditions are strongest. The regional premium reflects frequent low-price periods during solar-heavy hours, followed by sharp price recovery as photovoltaic output declines.
Romania is moving particularly quickly to convert this volatility into an investable asset class. The country received €636.9 million in the latest EU Modernisation Fund allocation, including support for standalone storage. Nova Power & Gas, part of E-INFRA Group, has also announced a €1 billion investment programme through 2029, covering generation, batteries and integrated energy infrastructure.
Greece is another natural market for energy storage. Solar capacity increased from 8.82 GW at the end of 2024 to 11.5 GW at the end of 2025, while the reported solar capture value fell to €43/MWh, the lowest among the covered Southeast European markets. This erosion in solar capture prices is making battery storage increasingly important for protecting the value of new photovoltaic projects.
The investment case, however, requires far more than multiplying a theoretical price spread by available capacity. A lender-grade model must account for round-trip efficiency, degradation, auxiliary consumption, grid charges, state-of-charge restrictions, cycling warranties and potential merchant-price compression. Revenues from balancing, ancillary services, congestion management and capacity mechanisms should also be modelled separately from day-ahead arbitrage.
A typical regional two-hour BESS may require installed CAPEX of approximately €250,000–€400,000 per MW, depending on project duration, grid-connection works, fire-safety requirements and the selected integrator. Four-hour systems require a larger capital envelope, but can offer better protection against solar oversupply and extended evening price peaks.
The highest returns are likely to emerge from projects that secure grid access early and combine multiple revenue streams. Pure merchant batteries remain exposed to spread compression as additional storage capacity enters the market. Co-located systems can help protect solar capture prices, while independently connected batteries can operate more freely across wholesale and balancing markets.
Southeast Europe’s battery opportunity is therefore as much a grid and market-design story as a technology story. The projects reaching financial close will be those supported by robust FEED studies, defensible dispatch simulations and connection agreements that permit the full operating profile envisioned by the developer.
