Southeast Europe prices ease as volatility persists

Day-ahead electricity prices across eastern Southeast Europe moved back towards €160/MWh for 26 September delivery, although large movements within individual trading periods continued to separate the value of electricity at different times of day.

Hungary cleared at around €161.20/MWh, Romania at approximately €162/MWh, Bulgaria at €160.60/MWh, and Greece close to €160/MWh. Those levels represented a marked reduction from the roughly €213–220/MWh seen across several of the same markets for the preceding delivery day.

The lower daily averages did not remove volatility. Hungary and Romania recorded prices around €0.70/MWh during their cheapest solar-heavy periods before values climbed to approximately €251/MWh later in the day. Greek prices fell to around €2/MWh at their lowest point, while Bulgaria reached roughly €15/MWh.

HUPX operates Hungary’s organised electricity markets within Europe’s coupled market framework, alongside the nominated market operators serving neighbouring countries. Available cross-border transmission capacity is incorporated into the day-ahead clearing process, allowing lower-cost electricity to move between bidding zones where the network permits.

That mechanism can narrow geographical price differences, but it cannot eliminate the much larger differences between individual hours. Hungary’s cheapest three-hour period averaged about €10.70/MWh, while its most expensive three-hour period averaged approximately €228/MWh. A daily figure near €161/MWh therefore concealed a spread of more than €200/MWh between different parts of the same delivery day.

Electricity markets increasingly expose that time value at finer resolution. European day-ahead market coupling moved to 15-minute market time units in 2025, allowing commercial schedules to follow changes in generation and consumption more closely than the previous hourly structure. Shorter intervals do not create volatility, but they allow rapid movements in renewable production, demand, and system conditions to appear more precisely in the market.

For battery storage, the spread between charging and discharging periods is generally more useful than the baseload average. A battery can absorb electricity during lower-price intervals and return it when the system is tighter, subject to charging losses, degradation, connection limits, state-of-charge requirements, market fees, and any capacity reserved for ancillary services.

A theoretical difference of €200/MWh between two periods therefore cannot be treated as a guaranteed project margin. The battery must have available capacity when the low-price interval arrives, remain within operating limits, and retain sufficient energy to discharge during the higher-price period. Repeated cycling also carries a long-term degradation cost that has to be reflected in the trading strategy.

The same market shape creates a more difficult position for unhedged solar generation. Photovoltaic plants tend to produce most strongly around the middle of the day, when increasing volumes of low marginal cost generation can depress wholesale prices. Evening prices can then rise sharply after solar production falls, particularly if demand remains high and wind, imports, or other flexible generation cannot close the gap.

Battery optimisation across European wholesale, intraday, and balancing markets has consequently become more important as revenues from individual ancillary services become more competitive. A battery facing a day with near-zero prices followed by values above €200/MWh has several possible revenue opportunities, but choosing between them depends on forecasts, market access, duration, and the value of preserving capacity for later services.

Flexible demand can respond to the same signal without storing electricity. Industrial processes, electric heating, charging loads, and other controllable consumption can move some demand into cheaper periods where operational constraints allow, reducing exposure to expensive evening intervals and absorbing generation that might otherwise be curtailed.

Cross-border capacity remains the other major variable. Markets can only share lower-cost generation if sufficient transmission capacity is available between them. ACER’s work on Southeast Europe has linked previous periods of severe price stress with limited cross-zonal capacity and shortages of flexible resources, particularly around evening periods when solar generation declines.

Those constraints help explain why relatively similar daily averages can coexist with sharp local or temporal price movements. A market may have access to low-cost electricity during one part of the day but face limited imports, reduced renewable generation, or higher consumption several hours later. The price responds to the resource needed to balance the system at that point rather than to the day’s average generation cost.

More renewable capacity is likely to deepen that distinction. Additional solar can increase low-price periods during strong daylight production, while storage and flexible demand gain value from moving electricity away from those hours. Wind can either reduce or intensify evening tightness depending on weather conditions, and transmission capacity determines how much neighbouring systems can assist.

The 26 September market therefore combined a substantial easing in headline prices with continuing evidence of an electricity system placing very different values on the same megawatt-hour depending on when it was available. Around €160/MWh described the daily average; the range from near zero to roughly €251/MWh described the flexibility challenge.