Europe’s electricity system entered summer 2026 without a broad adequacy threat, but record-low river levels and simultaneous constraints across nuclear, hydro and thermal generation shifted stress to Southeast Europe. The situation followed severe drought that emerged by August and reduced the availability of some of the region’s largest dispatchable assets.
ENTSO-E’s probabilistic assessment for Summer Outlook 2026 pointed to an overall favourable European balance. The outlook cited rising renewable generation, approximately doubled battery storage and cross-border coordination, while identifying the main structural adequacy concern as concentrated in Moldova.
Nuclear outages as Danube levels fell
As drought deepened, Romania shut both approximately 706 MW units at the Cernavodă nuclear plant when the Danube fell to exceptionally low levels. The plant normally supplies close to 20% of Romania’s electricity.
Hungary’s Paks nuclear plant has a capacity of 2,000 MW, typically providing around one third of national power. Output was reduced to a fraction of normal levels while the government prepared emergency engineering measures aimed at raising water levels near its cooling intake.
Hydropower and thermal limits spread across connected systems
Low water availability also constrained hydropower and thermal generation in Slovenia, Italy, Austria and other connected systems. At the same time, several countries increased reliance on imports as high temperatures lifted cooling demand.
The regional system continued to meet demand, but balancing costs rose. Imports, reserve generation and remaining thermal capacity filled the gap, contributing to sharp evening prices and increasing pressure on interconnectors.
Solar output helped daytime demand but not evening ramps
Rapid photovoltaic expansion prevented the crisis from worsening further during daylight hours. Hungary’s solar fleet was estimated at around 8 GW, supplying much of daytime demand during high-output periods and supporting electricity supply in Romania, Bulgaria and Greece.
The production profile created a second challenge as the sun set. Several gigawatts of output disappeared while temperatures and electricity demand remained high, leaving gas, coal, imports and stored electricity to cover the evening ramp when nuclear and hydro plants could not fully replace generation .
Batteries begin to reduce flexibility gaps
The operational issue was linked to flexible capacity rather than 24-hour energy totals. A system could produce sufficient electricity over a day while still lacking flexibility during three or four critical evening hours.
Bulgaria’s rapid battery storage expansion improved its ability to absorb cheap solar output and release it later. Greece has also built a substantial storage pipeline . Elsewhere, deployment remained slower, with Romania’s storage base still small relative to its solar fleet.
Serbia’s and Montenegro’s larger storage projects were mostly under development rather than fully operational during the period described. This limited how quickly additional flexibility could be added where evening stress was most acute.
Nuclear shortfalls create export opportunities with constraints
Nuclear reductions in Romania and Hungary created potential export opportunities for Serbia, Bulgaria and parts of the Western Balkans. However, those systems were managing their own constraints at the same time .
Serbia remained dependent on lignite generation availability and hydro resources. Montenegro faced simultaneous pressure from the overhaul of Perućica and the outage of the 225 MW Pljevlja thermal plant, leading EPCG to restore 190 MW of hydro capacity earlier than initially planned.
Hydrology dependence and CBAM affect cross-border deliveries
Albania’s position depended heavily on hydrology, while Bosnia’s hydro fleet offered flexibility despite low inflows. Declining reliability of older coal units limited how much volume Bosnia could commit to exports.
The EU carbon border mechanism further complicated Western Balkan deliveries into EU markets. Even when Serbian, Montenegrin or Bosnian electricity was physically available, default carbon charges could make exports commercially unattractive unless supply qualified for verified actual emissions.
Drought risks persist into autumn despite lower cooling demand
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.
Drought effects were expected to continue through autumn in several ways. Hydropower water availability was reduced and reservoir refill opportunities before winter were limited, while utilities may preserve remaining water for highest-value hours rather than use it to suppress average market prices .
Heavy summer import reliance may also have reduced maintenance flexibility. Delayed nuclear, thermal or transmission work could overlap with the start of the heating season.
Gas prices and CBAM continue to shape winter exposure
European gas storage levels and prices became a larger concern for power costs across Southeast Europe. Expensive gas raises marginal generation costs in Greece, Italy and Romania and can transmit higher electricity prices through connected markets.
CBAM restrictions were also expected to persist for Western Balkan exports into EU markets even during EU scarcity. This could sustain price divergence on borders including Serbia–Hungary and Montenegro–Italy .
Winter 2026/27 risk centers on price spikes and operational flexibility
A widespread physical shortage was not described as the base case for winter 2026/27. Restored nuclear generation, lower solar-season demand and regional interconnection were expected to provide a workable capacity margin under normal conditions.
The greater risk was described as a combination of high prices and short-duration scarcity. A cold spell would raise demand across the region; weak hydro would limit flexible supply while high gas prices would increase the cost of replacing missing nuclear, coal or renewable output.
The most sensitive period was likely to be the evening peak during cold, low-wind days when solar output falls but temperatures remain high. Solar could reduce daytime prices, while storage and hydro would determine whether that benefit carries into evening hours .
Romania and Hungary were identified as key markets because of their nuclear fleets’ size and influence on regional imports. Bulgaria may remain a relative exporter when Kozloduy, coal capacity and batteries are available; Greece would transmit gas and LNG costs into its power market; Serbia’s position would depend on EPS coal-unit reliability and hydro reserves .
Montenegro was expected to benefit from Perućica returning to service alongside new wind production at Gvozd. Its small system would remain exposed to Pljevlja availability and import costs; Albania could switch between exporter and importer depending on rainfall .
Operational facts likely outweigh headline capacity in Southeast Europe
The ENTSO-E outlook had identified interconnection and coordination as Europe’s main protection against adequacy stress. The drought demonstrated limits because neighbours can share reserve capacity but cannot all import the same megawatt-hour simultaneously .
For Southeast Europe into winter security planning, outcomes were described as depending less on installed capacity headlines 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 cross borders when every neighbouring system wants it .
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