Southeast Europe’s electricity price crisis can no longer be explained simply by temporary fuel costs or extreme weather events. ACER’s 2026 assessment found that the price gap between Southeast European and Central European markets persisted throughout 2025 and into early 2026, pointing to structural weaknesses in flexibility, network utilisation and regional market integration.
The regulator examined the extreme summer conditions of 2024, when average peak electricity prices in the affected Southeast European markets reached around €350/MWh. The most significant pressure emerged after sunset, when solar generation declined rapidly while electricity demand remained elevated. The region lacked sufficient flexible resources to replace the lost solar output, while limited import capacity—including restrictions linked to planned network maintenance—prevented cheaper Central European electricity from fully relieving the shortage.
ACER estimates that 147 of the most severe price spikes could have been avoided if the EU requirement to make at least 70% of relevant transmission capacity available for cross-zonal trade had been met. This does not mean every transmission line must operate at 70% of its physical thermal capacity at all times, as the regulatory methodology accounts for reliability margins and contingencies. However, it highlights how domestic congestion and insufficiently coordinated operational decisions can leave too little transmission capacity available to the integrated electricity market.
The affected Southeast European markets include Slovenia, Croatia, Hungary, Romania, Bulgaria and Greece, while Austria and Slovakia provide the relevant Central European comparison. Electricity flows across this corridor are influenced by outages and network constraints that can occur far from the national border where transmission capacity is allocated. Flow-based market coupling and stronger regional coordination are therefore increasingly important because bilateral capacity figures cannot fully capture the behaviour of a highly interconnected and meshed electricity network.
ACER is calling for improved outage planning, greater use of curative remedial actions, faster delivery of high-impact network investments and full implementation of flow-based market coupling. It also supports greater use of grid-enhancing technologies, including dynamic line rating, which can increase available transmission capacity by more than 50% on certain constrained network elements under favourable conditions.
However, stronger interconnection alone will not solve the region’s evening supply problem. If several Southeast European countries experience the same post-sunset decline in solar generation, neighbouring markets may all attempt to import electricity simultaneously. Storage, demand response, flexible hydropower and fast-start generation therefore remain essential components of a resilient regional system. Cross-border trading can reduce the cost of scarcity by pooling available resources, but it cannot create surplus electricity when the entire region faces a simultaneous shortage.
The commercial implications are substantial. Persistent price separation creates opportunities for battery storage and electricity traders, but increases costs for energy-intensive industrial consumers and weakens the expectation that renewable expansion will automatically translate into cheaper electricity. It also changes the relative value of generation and flexibility assets. A megawatt of flexible capacity located near a congested border or within a constrained market can potentially be more valuable than an equivalent megawatt located in an unconstrained area.
ACER’s findings therefore shift the policy debate away from simply building more transmission lines. Southeast Europe needs to use existing infrastructure more efficiently, coordinate network outages more effectively and apply common market rules consistently. Operational reforms and additional flexibility could provide some of the fastest reductions in price volatility while larger interconnectors and grid investments are being developed.
The region’s electricity-price problem is increasingly a market-design and flexibility challenge as much as a generation challenge. Closing that gap will require Southeast Europe to treat its electricity system as an integrated regional market rather than a collection of national grids.
