South East Europe’s electricity market is entering a new phase. The defining issue is no longer simply whether power prices are high or low. The more important question is when prices are high, where they diverge, and which assets can respond fast enough.
In the old market narrative, South East Europe was often described through annual baseload prices, hydro conditions, coal availability and import dependency. Those factors still matter. But they no longer explain the whole story. The region is now moving toward a market shaped by solar output, evening ramps, limited flexibility, grid bottlenecks, cross-border capacity and carbon-adjusted trade.
ACER’s 2026 analysis of South East Europe is a useful warning. During the 2024 summer stress events, several bidding zones in the region experienced significant evening price pressure. ACER found that the problem was not solar growth itself, but the lack of flexible resources able to replace solar generation quickly when output declined in the evening. Reduced gas-plant availability, low hydro reservoir levels, insufficient storage, limited demand response and constrained cross-zonal capacity all contributed to the pressure.
This is the new price structure of the region: cheap or even depressed midday hours, followed by expensive evening scarcity hours. Solar generation reduces demand for conventional power in the middle of the day. But once the sun sets, the system needs hydro, gas, imports, batteries or demand reduction to fill the gap. Where those resources are insufficient, prices can rise sharply.
The regional solar buildout makes this pattern stronger. ACER reports that solar PV capacity in selected South East European EU markets reached about 29 GW in 2025, while dispatchable capacity did not increase in parallel. That creates a system with more low-cost energy in sunny hours, but more exposure to scarcity during evening ramps.
Cross-border capacity is the second major price driver. South East Europe is connected to the rest of Europe, but the value of those interconnections depends on how much capacity is actually available to the market. ACER found that limited cross-zonal capacity constrained the region’s ability to import lower-priced electricity from Central Europe during stress periods. It also highlighted the importance of implementing the EU’s 70% cross-zonal-capacity requirement, which obliges TSOs to make at least 70% of relevant physical capacity available for cross-border trade while maintaining system security.
A third driver is emerging at the EU–Western Balkans border: carbon. From 2026, the EU Carbon Border Adjustment Mechanism entered its definitive phase, requiring authorised CBAM declarants and certificate settlement for covered imports, including electricity under the relevant CBAM framework. The Energy Community’s first Q1 2026 CBAM report showed that Western Balkan day-ahead prices were on average about €30/MWh lower than neighbouring EU markets, yet cross-border trade did not expand as a simple price-spread model would suggest.
That is a major market signal. A lower day-ahead price is no longer automatically a tradable arbitrage. Traders must now consider carbon cost, default emissions factors, documentation risk, route selection, transit exposure and the difference between scheduled and physical flows.
For industrial consumers, this means annual averages are becoming less useful. Procurement strategies need to account for profile risk, peak-hour exposure and hedge availability. For generators, merchant revenue depends increasingly on capture price, not just market price. For traders, the prize is no longer just buying low and selling high across borders. It is managing time, shape, congestion, imbalance and carbon.
South East Europe’s prices may remain high in certain periods, but the deeper story is that they are becoming more uneven, more locational and more time-sensitive. The market is no longer rewarding only energy production. It is rewarding flexibility.
