Southeast Europe’s electricity market is entering autumn with increasingly frequent zero-price solar hours but persistent evening prices above €200/MWh, after a summer in which drought, nuclear constraints and grid congestion widened the gap between abundant daytime energy and scarce flexible supply.
The shift was visible across the region during July and August but became particularly pronounced late in the summer.
Serbia’s SEEPEX baseload price rose from an average €109.43/MWh in July to €136.70/MWh in August, an increase of almost 25%.
The August average concealed a much larger hourly divide.
Serbian electricity averaged only about €66/MWh around midday, when solar generation was strongest, but rose to €210.97/MWh at hour 19, €243.65/MWh at hour 20 and €240.25/MWh at hour 21.
The evening price was therefore almost four times the midday value.
Romania experienced an even tighter August.
Its day-ahead market averaged 793.19 lei/MWh, or roughly €150/MWh, around 25% higher than July.
Low Danube flows reduced hydropower production and forced prolonged restrictions at the Cernavodă nuclear plant, at times removing both roughly 700 MW units and about 1.4 GW of low-marginal-cost generation from the market.
The same hydrological conditions affected Hungary’s Paks plant and Bulgaria’s Kozloduy nuclear station during parts of August, turning Danube water availability into a regional power-market variable.
Summer therefore produced an unusual combination.
Europe as a whole had sufficient installed generation capacity, and ENTSO-E identified no general continental adequacy threat.
But Southeast Europe repeatedly experienced scarcity during individual hours because firm capacity, hydro availability and cross-border transfer capability were insufficient to fully offset the evening decline in solar output.
Solar simultaneously created the opposite problem during daylight hours.
Greece, Bulgaria and increasingly Serbia experienced very weak midday prices during periods of strong photovoltaic production.
Hungary, Romania, Croatia and Slovenia followed the same direction when weather conditions aligned across the region.
By Sept. 6, Hungary, Romania, Croatia and Slovenia were posting negative prices during the solar peak, while Greece and Bulgaria cleared around zero for several consecutive intervals.
Only hours later, Hungarian and Romanian electricity returned to roughly €225-230/MWh.
That move captured the main structural change of summer 2026.
Southeast Europe is no longer dealing only with a shortage of generating capacity.
It is increasingly dealing with too much electricity in some hours and too little in others.
That makes daily baseload averages progressively less representative of the value actually captured by individual technologies.
Standalone solar is the most exposed.
A photovoltaic project can operate during a day when baseload power averages €150/MWh but sell most of its output during hours worth €20, €10 or zero.
Additional solar capacity intensifies that cannibalisation unless storage, flexible consumption or export capacity expands at a similar pace.
The same market creates a strong opportunity for batteries.
Romania had reached around 1.1 GW/2.3 GWh of operating battery storage by the start of September and has opened a €150 million programme targeting at least another 2.17 GWh.
Developers are also moving toward longer-duration systems capable of covering several hours of the evening ramp rather than concentrating solely on short balancing services.
But storage deployment remains too small to eliminate the price divide.
Romania’s 2.3 GWh fleet, for example, represents only a fraction of the energy required to cover several hours of national peak demand.
Reservoir hydropower consequently retains a powerful competitive position.
Hydro operators able to preserve water during weak-price solar hours and dispatch it after sunset can capture a growing flexibility premium.
The problem this summer was that reservoir and river conditions were themselves weak across parts of the region.
Transmission became the second major constraint.
Central SEE markets repeatedly traded far above Western Europe even when cheaper electricity was available in Germany.
On Sept. 3, Hungary traded almost €63/MWh above Germany.
A day later, the gap widened to nearly €91/MWh, even as power flows from the west increased.
The spreads showed that more cheap generation elsewhere in Europe does not automatically reduce SEE prices when cross-border corridors are saturated.
Storage and transmission therefore address different parts of the same problem.
Batteries move electricity between hours.
Interconnectors move it between countries.
The summer showed the region needs both.
September should remain highly volatile but may be softer on average than the tightest August periods.
Cooling demand should decline and solar generation remains strong enough to produce recurring midday oversupply, particularly during weekends.
That creates a base case in which central SEE baseload markets such as Hungary and Romania frequently trade in a broad €130-180/MWh range, while southern and Western Balkan markets can fall materially below that level when solar and hydro conditions are favourable.
Weekend averages below €100/MWh remain plausible, as early September has already demonstrated.
But evening prices are unlikely to fall proportionately.
Gas near €70/MWh raises the short-run cost of flexible thermal generation, while low Danube flows remain a risk to both hydro and nuclear availability.
At Romania’s Baziaș entry point, Danube flow was around 1,550 cubic metres per second at the start of September, less than half the long-term September average of about 3,800 cubic metres per second, with flows forecast to weaken further in early September.
That leaves September evening prices of €200-300/MWh plausible on days combining weak wind, limited hydro or nuclear availability and strong demand.
October changes the balance.
Shorter daylight hours should reduce the frequency and duration of zero and negative solar prices.
That will improve solar captured prices but also remove some of the cheap electricity currently suppressing daily baseload values.
Cooling demand will largely disappear, but heating-related consumption begins to return and solar generation falls more rapidly during the late afternoon.
The evening ramp is therefore likely to move earlier in the day.
Current Western European forwards already show October power considerably firmer than recent weekend spot prices, with German October baseload around €150/MWh.
Southeast Europe has repeatedly carried a premium to Germany during constrained periods.
If Cernavodă remains restricted, Danube hydrology stays weak and gas remains near €70/MWh, Hungary and Romania could spend much of October around €150-190/MWh, with higher levels on tight days.
A more benign scenario would require nuclear capacity to return, hydro conditions to improve and Gulf gas risks to ease.
Under those conditions, central SEE October prices could move closer to €120-160/MWh, while the southern markets retain a discount during renewable-heavy periods.
The main risk is that October combines weak hydro with expensive gas and the seasonal decline in solar production.
That would remove the cheap midday buffer without restoring enough firm supply, producing another period of high baseload prices and evening spikes above €250/MWh.
Serbia should remain more volatile relative to Hungary rather than maintaining a fixed discount.
SEEPEX moved from €184.92/MWh on Sept. 3 to about €60/MWh by Sept. 6, demonstrating how rapidly its basis can change with domestic supply, imports, renewable forecasts and border constraints.
For traders, that makes the Serbia-Hungary spread an increasingly important exposure in its own right.
The autumn outlook is therefore less about forecasting a single power price than forecasting the shape of each day.
September is likely to retain cheap solar hours and expensive evenings.
October should have fewer zero-price intervals but potentially firmer baseload and peak prices as daylight shortens.
The assets gaining most value from that structure are those able to respond to both changes: BESS, reservoir hydro, flexible thermal generation, demand response and cross-border transmission capacity.
Summer 2026 demonstrated that Southeast Europe can have ample electricity and scarcity at the same time.
September and October are likely to test whether the region’s expanding flexibility fleet can begin narrowing that gap before winter demand arrives.
