Europe’s electricity system entered summer 2026 with no broad adequacy threat, but record-low river levels and simultaneous nuclear, hydro and thermal constraints turned Southeast Europe into the continent’s main stress zone.
The contrast between ENTSO-E’s Summer Outlook 2026 and subsequent events does not mean the assessment failed. It shows that a system can have sufficient capacity on paper while remaining highly exposed to correlated weather and water risks.
ENTSO-E’s probabilistic assessment found an overall favourable European balance. Rising renewable generation, approximately doubled battery storage and cross-border coordination supported the outlook, while the main structural adequacy concern was concentrated in Moldova.
By August, however, severe drought had reduced the availability of some of the region’s largest dispatchable assets.
Romania shut both approximately 706 MW units at the Cernavodă nuclear plant as the Danube fell to exceptionally low levels. The plant normally supplies close to 20% of the country’s electricity.
Hungary’s 2,000 MW Paks nuclear plant, which typically provides around one third of national power, was reduced to a fraction of normal output as the government prepared emergency engineering measures to raise water levels near its cooling intake.
Low water availability also constrained hydropower and thermal generation in Slovenia, Italy, Austria and other connected systems. Several countries became more dependent on imports at the same time, while high temperatures lifted cooling demand.
The regional system continued to supply consumers, but the cost of maintaining balance increased. Imports, reserve generation and remaining thermal capacity filled the gap, producing sharp evening prices and increasing pressure on interconnectors.
Solar solved the daytime problem, not the evening one
Rapid photovoltaic expansion prevented the crisis from becoming worse. Hungary’s solar fleet, estimated at around 8 GW, supplied much of daytime demand during high-output periods. Solar also supported Romania, Bulgaria and Greece.
But the production profile created a second challenge.
As the sun set, several gigawatts of output disappeared while temperatures and electricity demand remained high. Nuclear and hydro plants were unable to fill the gap fully, leaving gas, coal, imports and stored electricity to cover the evening ramp.
This explains why regional averages can disguise operational stress. A system may produce sufficient electricity over 24 hours but still lack flexible capacity during three or four critical evening hours.
Battery storage is beginning to address the problem. Bulgaria’s rapid storage expansion improved its ability to absorb cheap solar output and release it later. Greece has also built a substantial storage pipeline.
Elsewhere, deployment remains slower. Romania’s storage base is still small relative to its solar fleet, while Serbia’s and Montenegro’s larger projects are mostly under development rather than fully operational.
Western Balkans gained opportunity and risk
The nuclear shortfall in Romania and Hungary created potential export opportunities for Serbia, Bulgaria and the Western Balkans. But those systems were managing their own constraints.
Serbia remained dependent on the availability of lignite generation and hydro resources. Montenegro faced simultaneous pressure from the overhaul of Perućica and the outage of the 225 MW Pljevlja thermal plant, prompting EPCG to restore 190 MW of hydro capacity earlier than initially planned.
Albania’s position depended heavily on hydrology. Bosnia’s hydro fleet offered flexibility, but low inflows and the declining reliability of older coal units limited the volume that could be committed to exports.
CBAM further complicated Western Balkan deliveries into the EU. Even when Serbian, Montenegrin or Bosnian electricity was physically available, default carbon charges could make exports commercially unattractive unless the supply qualified for verified actual emissions.
Regional adequacy and regional trade were therefore no longer governed by the same calculation. Electricity could be technically valuable to an importing EU system while remaining commercially penalised by its declared origin.
Autumn offers demand relief but little hydrological recovery
The end of the summer cooling season should reduce peak demand. Nuclear units returning to service would also restore a large block of dependable generation in Romania and Hungary.
Yet several risks will persist through autumn.
First, drought has reduced the water available for hydropower and limited the opportunity to refill reservoirs before winter. Utilities may preserve remaining water for the highest-value hours rather than use it to suppress average market prices.
Second, heavy reliance on imports during summer may have reduced the scope for maintenance flexibility. Delayed nuclear, thermal or transmission work could overlap with the start of the heating season.
Third, European gas storage and prices have become a larger concern. Expensive gas raises the cost of marginal generation in Greece, Italy and Romania and can transmit higher electricity prices throughout Southeast Europe.
Fourth, CBAM may continue to restrict commercially attractive exports from the Western Balkans to EU markets even during EU scarcity, sustaining price divergence on borders such as Serbia–Hungary and Montenegro–Italy.
Forecast: winter risk shifts from capacity to price and flexibility
A widespread physical shortage is not the base case for winter 2026/27. Restored nuclear generation, lower solar-season demand and regional interconnection should provide a workable capacity margin under normal conditions.
The greater risk is a combination of high prices and short-duration scarcity.
A cold spell would raise demand across the entire region. Weak hydro would limit flexible supply, while high gas prices would increase the cost of replacing missing nuclear, coal or renewable output. During those periods, evening prices could rise sharply even if total seasonal energy remains sufficient.
Romania and Hungary will be the key markets to watch because of the size of their nuclear fleets and their influence on regional imports. Bulgaria may remain a relative exporter when Kozloduy, coal capacity and batteries are available. Greece will transmit gas and LNG costs into the power market, while Serbia’s position will depend heavily on EPS coal-unit reliability and hydro reserves.
Montenegro will benefit from the return of Perućica and new wind production at Gvozd, but its small system will remain exposed to the availability of Pljevlja and the cost of imports. Albania could switch rapidly between exporter and importer depending on rainfall.
The most sensitive period is likely to be the evening peak during cold, low-wind days. Solar will reduce daytime prices, but storage and hydro will determine whether the benefit carries into the evening.
ENTSO-E’s summer outlook correctly identified interconnection and coordination as Europe’s main protection. The drought showed their limit: neighbours can share reserve capacity, but they cannot all import the same megawatt-hour.
For Southeast Europe, winter security will depend less on headline installed capacity than on three operational facts—how much water remains behind dams, how many nuclear and coal units are actually running, and how much electricity can still cross the border when every neighbouring system wants it.
Elevated by Virtu.Energy
