South East Europe’s electricity market is entering a new phase in which the timing and location of high prices matter as much as their level. The region’s power market has increasingly been shaped by solar generation, steep evening ramps, limited system flexibility and grid bottlenecks. Cross-border transmission capacity and carbon-adjusted electricity trade are also becoming more prominent in market outcomes.
ACER links 2024 evening stress to limited flexibility
ACER’s 2026 assessment warns that summer stress events in 2024 saw significant evening price pressure across multiple bidding zones. ACER said the issue was not the growth of solar generation itself. Instead, it pointed to a lack of flexible resources able to replace solar output quickly after production declined after sunset.
ACER cited reduced gas-fired generation availability, low hydro reservoir levels and insufficient storage capacity among contributing factors. It also referenced limited demand response and constrained cross-zonal transmission. These constraints affected the system’s ability to respond during periods when solar output falls.
The resulting price pattern described by ACER features low-cost or depressed prices during sunny midday hours, followed by expensive scarcity-driven prices in the evening. Solar generation suppresses demand for conventional generation during daylight. When solar output fades, supply must shift to hydro plants, gas-fired generation, battery storage, imports or demand-side flexibility.
Solar expansion raises exposure during evening ramps
Solar expansion across South East Europe is reinforcing the shift in price structure described by ACER. The agency reported that solar PV capacity in selected EU markets of the region reached approximately 29 GW in 2025. It also noted that dispatchable generation capacity did not expand at the same pace.
This combination leaves the system with more low-cost electricity during daylight while increasing exposure to scarcity and volatility during evening ramps. Where flexible resources are insufficient to cover the post-sunset decline in solar output, prices can rise sharply. The market outcome therefore depends on how quickly other assets can ramp up or be made available.
Cross-zonal capacity limits affect imports during stress
Cross-border transmission capacity has emerged as a second major driver of price outcomes. South East Europe is connected to wider European markets, but ACER found that interconnection value depends on how much capacity is actually released for commercial trading. During periods of market stress, limited cross-zonal capacity restricted the region’s ability to import lower-priced electricity from Central Europe.
ACER also highlighted implementation of the EU requirement for 70% cross-zonal capacity. The rule obliges transmission system operators to make at least 70% of relevant physical transmission capacity available for cross-border trade while preserving system security.
CBAM changes arbitrage economics along the EU–Western Balkans border
A third driver identified by ACER is carbon costs along the EU–Western Balkans border. From 2026, the Carbon Border Adjustment Mechanism (CBAM) enters its definitive phase, requiring authorised declarants and certificate settlement for covered imports including electricity. This adds compliance steps and cost elements to cross-border transactions.
The Energy Community’s first-quarter 2026 CBAM report showed Western Balkan day-ahead electricity prices averaging around €30/MWh lower than neighbouring EU markets. However, it reported that cross-border trade did not expand in line with what a simple price-spread model would suggest .
Market participants therefore need to account for carbon costs, default emissions factors and compliance requirements. ACER also pointed to documentation risks, route selection and transit exposure, alongside a growing distinction between scheduled and physical electricity flows . Lower day-ahead prices are not automatically tradable arbitrage opportunities under these conditions.
Implications for procurement, revenues and trading strategies
For industrial consumers, annual average prices are becoming a less useful benchmark for procurement decisions. Strategies increasingly need to consider load profiles, peak-hour exposure and hedging opportunities rather than relying only on yearly averages.
For generators, merchant revenues depend more on capture prices than on average market prices. For traders, performance is no longer defined solely by buying low and selling high across borders; it increasingly depends on managing time intervals, shape of positions, congestion effects, balancing risk and carbon exposure .
The overall shift described by ACER is toward prices that are more uneven, more locational and more time-sensitive across South East Europe. The market outcome becomes less about rewarding energy production alone and more about rewarding flexibility when supply needs change rapidly .
