South East Europe’s electricity market is entering a new phase beyond the aftershocks of the 2021–2022 energy crisis, imported gas costs and coal availability. Those drivers still affect supply conditions, but the structural issue is shifting to flexibility. The key market question is increasingly whether the system can deliver the right type of electricity at the right hour.
That change is reflected in how prices develop and how investment decisions are made for security of supply. Instead of focusing only on whether enough electricity exists, market participants are tracking hourly balance between generation and demand. The distinction is becoming central to price formation across bidding zones in the region.
Summer 2024 spikes highlight evening flexibility gaps
The clearest signal came from summer 2024 price spikes identified by ACER. ACER found that most Southeast European bidding zones saw significant price increases during that period, particularly in the evening hours. In some cases, prices reached up to €1,000/MWh.
ACER concluded that the spikes were not only linked to fuel-price movements. The regulator connected them to a lack of flexible resources able to replace solar generation after sunset. ACER also cited limited cross-border capacity for importing cheaper power from other regions.
South East Europe has strong renewable-resource potential, especially solar, alongside legacy hydro, coal and gas assets that can provide firm supply under certain conditions. However, the system is increasingly exposed to the gap between daytime renewable output and evening demand. The issue is therefore not always total annual generation but hourly balance.
Hourly pricing signals reduce value of average baseload benchmarks
Average baseload prices are becoming less useful as a market indicator as price stress concentrates into specific hours. A system can appear adequately supplied on an annual basis while still experiencing severe price outcomes during a small number of evening hours. Low or negative midday prices can coincide with high solar output.
In those conditions, scarcity pricing can emerge just a few hours later. For utilities, traders, renewable developers and industrial consumers, the value of electricity is tied not only to the megawatt-hour but also to the timestamp of delivery. This shift affects how contracts and trading strategies are evaluated across time intervals.
ACER reported that prices in 2025 did not reach the extreme levels seen in summer 2024. Even so, the price gap between Southeast and Central Europe persisted throughout 2025 and into early 2026. The regulator said this points to structural volatility rather than isolated events.
Drivers of structural volatility: solar growth, grid limits and integration
Three factors were identified as explaining structural volatility in South East Europe’s power markets. First, solar growth is outpacing system flexibility. Solar reduces prices during daylight hours, especially at midday, but it does not address evening peak demand on its own.
Without batteries, pumped hydro, flexible gas, demand response or stronger interconnectors, systems can become long during daytime and tight after sunset. Second, grid constraints influence outcomes as strongly as generation mix. When lower-cost electricity cannot move into the region when needed, local prices diverge.
This is why cross-border capacity, market coupling and transmission investment are treated as core market issues. Third, integration levels differ across the region: EU member states in South East Europe operate within the EU electricity-market framework, while Western Balkan markets are still moving toward full integration.
Serbia’s market is progressing closer to EU practice, but wider Western Balkan market coupling remains unfinished. These differences affect how quickly power can be shared across borders during periods of tightness or oversupply.
15-minute day-ahead trading from September 2025
The move to 15-minute day-ahead trading in the EU from 30 September 2025 is part of a broader transition in how markets reflect expected supply and demand. The European Commission said shifting from hourly to 15-minute pricing helps markets capture expected generation and demand more accurately.
The Commission’s rationale is tied to systems with high wind and solar shares, where imbalances can appear over shorter time intervals than those captured by traditional hourly markets. For South East Europe’s operating conditions, this change affects how flexibility needs translate into pricing signals within each day-ahead schedule.
Value shifts toward controllable capacity and grid capability
The transition creates a different hierarchy of value for South East Europe’s electricity system. Pure generation remains important, but flexible generation becomes more valuable under conditions where solar output declines after sunset. Solar remains attractive, while solar paired with storage or flexible offtake carries additional value.
Hydro remains strategic but depends on weather for availability. Coal continues to be relevant for security of supply while its economics weaken under carbon and pollution pressure. Grid capacity also moves from background infrastructure toward an asset that can influence prices when constraints bind.
The investment implications described for the region focus on batteries, pumped hydro, grid upgrades and participation in balancing markets. Demand response is highlighted alongside shaped PPAs and improved trading capabilities designed for more granular scheduling needs. The region is described as needing more controllable megawatts rather than additional megawatts alone.
Flexibility scarcity frames 2026–2028 market outlook
The central thesis for South East Europe’s electricity markets in 2026–2028 is that the crisis has changed shape from shortage-focused concerns toward flexibility scarcity. The emphasis shifts away from only whether supply exists toward whether flexible resources can cover timing gaps between renewable output and demand.
Elevated by virtu.energy