Southeast Europe’s electricity market is entering autumn with an increasingly divided price structure, as abundant solar generation pushes daytime prices toward zero while evening power regularly climbs above €200/MWh. The pattern became increasingly visible during July and August, as drought, nuclear availability constraints and transmission congestion widened the gap between cheap midday electricity and scarce flexible supply after sunset.
The divergence was particularly evident in Serbia. SEEPEX baseload prices increased from an average of €109.43/MWh in July to €136.70/MWh in August, an increase of almost 25%. However, the monthly average concealed a much wider hourly spread. Serbian electricity averaged only around €66/MWh around midday, when solar production was strongest, before rising to €210.97/MWh at hour 19, €243.65/MWh at hour 20 and €240.25/MWh at hour 21.
Evening electricity was therefore trading at almost four times the midday price, highlighting the growing value of flexibility in the Southeast European power market.
Romania experienced an even tighter market in August. Its day-ahead electricity price averaged 793.19 lei/MWh, equivalent to roughly €150/MWh and about 25% above the July average. Weak Danube flows reduced hydropower production while prolonged restrictions at the Cernavodă nuclear plant at times removed both approximately 700 MW units from the market, taking around 1.4 GW of low-marginal-cost generation offline.
The same hydrological conditions affected Hungary’s Paks nuclear plant and Bulgaria’s Kozloduy nuclear station during parts of August, turning Danube water availability into an increasingly important regional power-market variable.
The result was an unusual summer market structure. Europe as a whole continued to have sufficient installed generation capacity, and ENTSO-E identified no general continental adequacy threat. Yet Southeast Europe repeatedly experienced hourly scarcity because firm generation, hydro availability and cross-border transmission capacity were not always sufficient to compensate for the rapid decline in solar output during the evening.
At the same time, solar generation created the opposite problem during daylight hours. Greece, Bulgaria and increasingly Serbia experienced very weak midday prices during periods of strong photovoltaic output, while Hungary, Romania, Croatia and Slovenia followed the same pattern when favourable weather conditions coincided across the region.
By Sept. 6, Hungary, Romania, Croatia and Slovenia were recording negative prices during the solar peak, while Greece and Bulgaria traded around zero for several consecutive intervals. Only a few hours later, Hungarian and Romanian electricity prices had returned to approximately €225-230/MWh.
That price swing captures the main structural change in Southeast Europe’s electricity market during summer 2026. The region is no longer dealing simply with insufficient generating capacity. Instead, it is increasingly dealing with too much electricity in some hours and too little in others.
This makes traditional daily baseload averages less representative of the actual value captured by individual generation technologies. Solar power is particularly exposed to this shift. A photovoltaic project can operate on a day when the baseload average reaches €150/MWh while selling much of its production during midday periods priced at €20, €10 or even zero.
As solar capacity expands, this price cannibalisation effect is likely to become more pronounced unless battery storage, flexible consumption and export capacity grow at a similar pace.
The changing price structure is creating a strong opportunity for battery storage. Romania had reached approximately 1.1 GW/2.3 GWh of operating battery capacity by the beginning of September and has launched a €150 million programme targeting at least another 2.17 GWh.
Developers are also increasingly considering longer-duration systems capable of shifting electricity across several evening hours rather than focusing exclusively on short-duration balancing services. However, current storage capacity remains far too small to eliminate the regional price divide.
Romania’s existing 2.3 GWh battery fleet, for example, represents only a fraction of the energy required to cover several hours of national peak demand. Reservoir hydropower therefore retains a significant competitive advantage. Operators capable of conserving water during low-priced solar hours and dispatching generation after sunset can capture an increasingly valuable flexibility premium.
The problem this summer was that hydro conditions themselves were weak across parts of the region. Low reservoir levels and reduced river flows limited the ability of hydropower to perform that balancing role precisely when the market needed it most.
Transmission represented the second major constraint. Central Southeast European markets repeatedly traded well above Western European prices even when cheaper electricity was available in Germany. On Sept. 3, Hungary traded almost €63/MWh above Germany, while the following day the spread widened to nearly €91/MWh despite higher electricity flows from the west.
These spreads demonstrated that additional cheap generation in Western Europe does not automatically translate into lower Southeast European prices when cross-border transmission corridors become constrained.
Storage and transmission therefore solve different parts of the same problem. Batteries move electricity between hours, while interconnectors move electricity between countries. The summer market showed that Southeast Europe increasingly needs both.
September should remain volatile, although average prices could be softer than during the tightest August periods. Cooling demand is expected to decline, while solar generation should remain strong enough to produce recurring midday oversupply, particularly during weekends.
A reasonable base case is for central Southeast European markets such as Hungary and Romania to trade frequently within a broad €130-180/MWh range, while southern and Western Balkan markets could fall materially below those levels when solar and hydro conditions are favourable. Weekend averages below €100/MWh remain plausible, as early September has already demonstrated.
Even so, evening prices are unlikely to decline at the same pace. Gas prices near €70/MWh are keeping the short-run cost of flexible thermal generation elevated, while weak Danube flows continue to pose a risk to both hydro and nuclear availability.
At Romania’s Baziaș entry point, Danube flow stood at around 1,550 cubic metres per second at the start of September, less than half the long-term September average of approximately 3,800 cubic metres per second. Forecasts pointed to further weakening in early September, increasing the risk of tight evening power markets.
Under a combination of weak wind, limited hydro or nuclear availability and strong demand, September evening prices of €200-300/MWh remain plausible.
October will change the market balance. Shorter daylight hours should reduce the frequency and duration of zero and negative solar-price intervals. That should improve the captured price for solar generators, but it will also remove some of the cheap midday electricity currently suppressing daily baseload averages.
Cooling demand will largely disappear, while heating-related consumption begins to return. At the same time, solar generation will decline more rapidly during the late afternoon, bringing the evening ramp forward and increasing the importance of flexible generation.
Western European forward markets already point toward firmer October conditions, with German October baseload around €150/MWh. Southeast European markets have repeatedly traded at a premium to Germany during periods of transmission and generation constraints.
If Cernavodă remains restricted, Danube hydrology stays weak and gas prices remain close to €70/MWh, Hungary and Romania could spend much of October in the €150-190/MWh range, with significantly higher prices possible during tight days.
A more benign scenario would require the return of nuclear capacity, improving hydro conditions and easing gas-market risks. Under those circumstances, central SEE October prices could move closer to €120-160/MWh, while southern markets could continue to trade at a discount during periods of strong renewable generation.
The main upside risk is that October combines weak hydro availability with expensive gas and the seasonal decline in solar output. Such a combination would remove much of the cheap midday buffer without restoring sufficient firm generation, potentially producing another period of high baseload prices and evening spikes above €250/MWh.
Serbia is likely to remain more volatile relative to Hungary rather than maintaining a consistent price discount. SEEPEX moved from €184.92/MWh on Sept. 3 to around €60/MWh by Sept. 6, demonstrating how rapidly the Serbian market can change in response to domestic generation, imports, renewable forecasts and cross-border constraints.
That volatility makes the Serbia-Hungary spread an increasingly important exposure in its own right, particularly for traders and market participants managing regional positions.
The autumn outlook is therefore less about predicting a single electricity price and more about forecasting the shape of each trading day. September is likely to retain the combination of cheap solar hours and expensive evenings, while October should bring fewer zero-price intervals but potentially firmer baseload and peak prices as daylight hours shorten.
The assets best positioned to benefit from this structural shift are those capable of responding to both sides of the market: battery energy storage systems, reservoir hydropower, flexible thermal generation, demand response and cross-border transmission capacity.
Summer 2026 demonstrated that Southeast Europe can simultaneously experience abundant electricity and power scarcity. The key question for September and October is whether the region’s expanding flexibility infrastructure can begin narrowing that gap before winter demand places additional pressure on the system.
