Wind and solar deployment across South-East Europe surpassed 34 GW by the end of 2025, with more than 11 GW added over the previous four years. Serbia, Romania, Greece, Croatia, and Bulgaria account for most of the installed capacity. Bosnia and Herzegovina, North Macedonia, and Montenegro are also moving into utility-scale solar and wind development. By 2030, variable renewables are projected to exceed 45% of annual electricity generation, up from less than 25% a decade earlier.
Flexibility constraints from hydrology, thermal ageing and fuel costs
South-East Europe’s power systems rely on conventional hydropower and thermal generation for flexibility. Hydropower remains significant in Serbia, Bosnia and Herzegovina, and Montenegro, but is increasingly seasonal and hydrologically volatile. Thermal fleets are ageing and carbon-intensive, with exposure to rising fuel and emissions costs. Short-duration batteries deployed alongside solar parks provide intraday balancing but cannot cover multi-day renewable shortfalls.
Long-duration energy storage is positioned to address that gap by delivering electricity for 8 to 72 hours or longer. System modelling for the region points to destabilising events including extended low-wind periods in winter and prolonged summer heatwaves with weak wind output. Multi-day solar deficits are also expected when weather systems move across the Balkans. By 2030, South-East Europe is forecast to experience 5–10 multi-day low-renewable events per year where variable renewable output falls below 20% of installed capacity for more than 48 hours.
In the absence of long-duration storage, those events are covered through lignite generation, gas imports, or emergency cross-border balancing. The source figures indicate that these approaches carry increasing economic and political risk. Long-duration storage is therefore linked to system-level flexibility needs rather than being treated as a supplementary technology layer. The operational focus is on multi-day coverage rather than intraday support.
Dispatch economics and capacity replacement for multi-day deficits
A single 1 GW / 24 GWh long-duration storage asset can replace the firm capacity contribution of roughly 1.3–1.6 GW of open-cycle gas turbines under South-East European load profiles, using a loss-of-load probability basis. At system level, deploying 10–15 GWh of long-duration storage per country would allow most Western Balkan systems to cover critical multi-day deficits without resorting to emergency fossil dispatch. That deployment level is associated with reducing peak-period imports by 20–35%. The figures relate storage output to capacity adequacy during extended shortfalls.
Frequency containment and balancing cost impacts during low-renewable periods
The stability effects are tied to lower inertia margins in South-East European transmission systems compared with Western Europe. The difference is most relevant during high renewable output periods when synchronous thermal units are offline. Frequency deviations, voltage excursions, and ramp-rate stress already lead to measurable costs through redispatch and reserve activation. When configured for grid services, long-duration storage provides sustained frequency containment and ramping capability over many hours rather than minutes.
Studies referenced in the source material on mixed renewable-storage systems indicate that each gigawatt of long-duration storage can reduce annual balancing energy costs by €35–55 million. The cost reduction is described as coming mainly from dampening prolonged imbalance periods rather than short spikes. This links grid services from longer-duration assets to longer-lasting operational stress scenarios.
Curtailment reduction and integration benefits for solar and wind
Curtailment rates for utility-scale solar in parts of South-East Europe reach 6–10% during spring and early summer due to midday oversupply and constrained export capacity. Wind curtailment in coastal and mountainous zones is lower on an annual basis but spikes during prolonged high-wind episodes followed by grid congestion. Long-duration storage absorbs surplus generation over extended windows rather than only daily peaks. This changes how variable generation can be utilised during sustained weather-driven patterns.
The modelling cited indicates that adding 1 MWh of long-duration storage per 1.5–2 MW of solar capacity can cut curtailment by more than 60%. It also lifts effective solar capacity factors by 2–4 percentage points. For wind, the uplift is smaller but still considered material where export capability is limited.
Cross-border market coupling constraints and regional storage coordination
The cross-border dimension reflects partial market coupling across South-East Europe and frequent interconnector utilisation constraints during stress events. Long-duration storage deployed in one jurisdiction can reduce peak exports and imports during critical hours, easing congestion on shared corridors. Regional simulations suggest coordinated deployment of 40–50 GWh of long-duration storage across South-East Europe could reduce cross-border emergency flows by 25–30%. The same simulations associate the outcome with lower redispatch costs across multiple transmission zones.
Adequacy margins, industrial demand exposure, and investment requirements
The source material links adequacy needs to reserve margins that are below 15% during peak periods in several Western Balkan systems. With limited tolerance for outages or renewable underperformance, long-duration storage contributes firm capacity when short-duration batteries and demand response saturate. A portfolio of 5–7 GW of long-duration storage across the region by 2035 is described as enabling retirement or reduced operation of at least 3–4 GW of the least efficient thermal capacity without compromising reliability.
The figures also include an estimated annual emissions impact: cutting annual power-sector emissions by about 6–9 million tonnes of CO₂. Industrial demand adds another element through exposure to volatile power prices and carbon-related compliance costs in Serbia, Romania, and Bulgaria. For large industrial sites consuming 200–400 GWh per year, behind-the-meter or contracted long-duration storage is described as reducing annual electricity procurement costs by 8–12%. The source also notes improved carbon intensity metrics under EU trade and financing frameworks.
Main barriers: limited visibility in planning, fragmented revenue streams, permitting treatment
The principal barriers described are structural rather than technical. Long-duration storage remains largely absent from national adequacy assessments, capacity remuneration mechanisms, and grid planning processes across South-East Europe. Revenue streams are fragmented, duration value is not monetised, and permitting frameworks often treat storage as an ancillary add-on rather than core infrastructure. As a result, private capital prices long-duration storage as high-risk despite system value.
The source quantifies the investment needed to close the flexibility gap at cumulative levels of €18–25 billion in long-duration storage by 2040, depending on technology mix and deployment pace. It states that this investment is comparable to maintaining ageing thermal fleets over the same period while delivering different system outcomes including lower emissions, higher renewable utilisation, and improved security of supply.