Southeast Europe remains vulnerable to electricity-price spikes as renewable investment continues to advance faster than cross-border grids, operational coordination and flexible generation capacity, according to an assessment by ACER, with developments during the summer of 2026 further exposing these structural weaknesses.
The EU energy regulator concluded that the electricity price spikes recorded in 2024 were not an isolated event, but rather a sign of deeper weaknesses in the regional power system. ACER proposed 10 measures focused on transmission investment, better coordination of planned outages, storage, demand response, flow-based market coupling and compliance with the EU requirement to make at least 70% of transmission capacity available for cross-border trade.
Developments since the report was published in May have reinforced those concerns. Severe drought and low river levels reduced nuclear, hydro and thermal generation availability across Romania, Hungary, Slovenia and neighbouring markets during July and August. At the same time, increased air-conditioning demand coincided with rapidly declining solar output in the evening, forcing several countries to seek additional imports during the same hours.
Romania’s Cernavodă nuclear power plant temporarily lost both of its approximately 706 MW units during the peak of the drought, removing a significant source of domestic generation that normally accounts for close to one fifth of the country’s electricity supply. Hungary’s 2,000 MW Paks nuclear plant was also heavily constrained as authorities took measures to preserve sufficient Danube water for cooling.
Hydropower generation weakened across parts of the region, while thermal power plants faced cooling and fuel-related constraints. In Montenegro, the overhaul of the 307 MW Perućica hydropower plant was shortened in order to return around 190 MW to service as the power system came under pressure and the 225 MW Pljevlja thermal power plant remained unavailable.
These developments once again turned interconnectors into the region’s main insurance mechanism. However, an interconnector can provide support to neighbouring markets only when sufficient physical capacity is available and transmission system operators make that capacity accessible for cross-border trade.
This makes ACER’s 70% capacity requirement particularly important. Excessive reservation of transmission capacity for domestic congestion management can restrict regional electricity trade and widen price differences between neighbouring bidding zones. Greater availability of cross-border capacity would allow lower-cost generation in one market to replace more expensive generation in another.
At the same time, transmission operators cannot safely release capacity that the network is physically unable to accommodate. Meeting the 70% requirement therefore needs to go hand in hand with grid reinforcement, improved regional network modelling and more effective remedial actions.
Planned grid outages remain another important source of market risk. ACER identified insufficient coordination of planned outages as one factor contributing to avoidable reductions in available transmission capacity. This is particularly significant in Southeast Europe, where maintenance on a single transmission line can alter electricity flows across several neighbouring systems.
Recent partial decoupling and delayed market-coupling results on regional power exchanges have also demonstrated that the institutional architecture remains vulnerable. Even short disruptions can reduce market liquidity, separate bidding zones and force market participants to manage their exposure through more expensive intraday or balancing transactions.
The region’s highly meshed electricity network further complicates congestion management. Electricity traded across one border can physically flow through several other systems, creating differences between commercial schedules and actual physical flows. Energy Community data for the first quarter showed significant discrepancies on corridors linking Greece and Albania with Montenegro and Bosnia and Herzegovina and further towards Croatia, Hungary and Romania.
Such divergences can increase redispatch requirements and make available transmission capacity more difficult to calculate. They also underline the importance of coordinated regional remedial actions rather than isolated national restrictions.
ACER is therefore advocating wider use of flow-based capacity calculation, which assesses how electricity transactions affect the interconnected network as a whole instead of treating individual borders separately. The methodology is already being applied in parts of the EU, but its implementation remains incomplete in Southeast Europe and does not yet fully cover the Western Balkans.
New battery storage capacity could help reduce solar-driven price volatility by charging during periods of low daytime prices and discharging during the evening peak. Bulgaria and Greece have moved quickly to support battery investment, while Romania and Serbia have developed substantial project pipelines.
Serbia has identified 724 MW of prospective battery capacity through transmission-related planning, alongside a further 200 MW/400 MWh included in the EPS investment programme. However, planned storage capacity cannot contribute to system stability until projects are connected, technically prequalified and granted access to energy and balancing markets.
Regulatory barriers remain significant. Some storage projects face issues related to double network charging, unclear connection rules or restricted access to reserve products. Demand response and aggregation also remain relatively underdeveloped across much of Southeast Europe.
As a result, the region could add several gigawatts of renewable generation and battery storage while continuing to depend heavily on existing hydro and thermal power plants for operational flexibility.
Regional wholesale electricity markets are likely to remain volatile through autumn 2026. Cooler temperatures should ease air-conditioning demand compared with the summer, but several of the risks exposed during the summer will continue into the coming months.
Low hydro reserves could restrict the ability of utilities to increase generation during high-price periods. Nuclear availability in Hungary and Romania will remain closely monitored, while planned maintenance at thermal plants and on transmission networks could further reduce available capacity.
European gas prices represent another potential upward risk. Higher gas costs increase the marginal cost of electricity generation in markets such as Greece, Italy and Romania and can subsequently push prices higher across interconnected Southeast European markets. The effect is particularly pronounced during evening hours, when solar generation declines and gas-fired plants increasingly influence the market clearing price.
The most likely autumn scenario is therefore not one of continuous electricity scarcity, but rather repeated episodes of sharp hourly price divergence. Prices could remain relatively low during periods of strong renewable generation before rising sharply during evening ramps, particularly where cross-border transmission capacity is constrained.
Bulgaria could retain a relative advantage when nuclear, coal and battery availability remains strong. Romania and Hungary will remain more exposed to nuclear availability, Danube water conditions and the need for imports. Serbia and Montenegro will continue to depend heavily on hydro availability and the performance of their thermal fleets, while Greece is likely to transmit higher gas-price exposure northward during periods of weak renewable generation.
ACER’s recommendations are unlikely to eliminate these risks before winter. Grid reinforcement and deeper flow-based market integration will take years, meaning that the most important factors for the coming months will be coordinated maintenance, real-time cross-border capacity allocation and the ability of batteries and flexible power plants to respond when several countries require additional electricity at the same time.
Southeast Europe does not lack interconnection. Its vulnerability increasingly lies in how much usable flexibility remains available during the most difficult evening hours, when renewable output falls, demand remains elevated and neighbouring markets compete for the same limited generation and transmission capacity.
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