Europe’s electricity system entered summer 2026 without a broad adequacy threat, but record-low river levels combined with simultaneous nuclear, hydro and thermal constraints to make Southeast Europe the continent’s main power-system stress zone.
The contrast between ENTSO-E’s Summer Outlook 2026 and the events that followed does not indicate that the assessment was fundamentally wrong. Instead, it demonstrated how a power system can have sufficient generation capacity under normal assumptions while remaining highly exposed to correlated weather, hydrological and operational risks.
ENTSO-E’s probabilistic assessment pointed to an overall favourable electricity balance across Europe. Rising renewable generation, a significant increase in battery storage and stronger cross-border coordination supported the outlook, with Moldova identified as the main structural adequacy concern.
By August, however, severe drought had reduced the availability of several of Southeast Europe’s largest dispatchable generation assets. Romania temporarily shut both approximately 706 MW units at the Cernavodă nuclear plant as Danube water levels fell to exceptionally low levels. The plant normally supplies close to 20% of Romania’s electricity.
Hungary’s 2,000 MW Paks nuclear plant, which typically accounts for around one third of the country’s electricity production, was also significantly constrained as authorities prepared emergency engineering measures to maintain adequate cooling conditions.
Low water availability additionally affected hydropower and thermal generation in Slovenia, Italy, Austria and other interconnected markets. Several countries consequently became more dependent on electricity imports at the same time that high temperatures increased cooling demand.
The regional system continued to meet consumer demand, but the cost of maintaining system balance increased. Imports, reserve generation and available thermal capacity helped cover the shortfall, contributing to sharp evening price increases and putting additional pressure on cross-border interconnectors.
Rapid solar expansion prevented the situation from becoming more severe during daytime hours. Hungary’s solar fleet, estimated at around 8 GW, supplied a significant share of demand during periods of strong output, while solar generation also provided important support to Romania, Bulgaria and Greece.
However, the rapid growth of photovoltaic generation created a different operational challenge. As the sun set, several gigawatts of generation disappeared within a relatively short period while temperatures and electricity demand remained elevated.
With nuclear and hydro plants unable to fully compensate for the decline in solar output, gas, coal, imports and stored electricity increasingly had to cover the evening ramp.
This helps explain why regional daily or monthly averages can conceal significant operational stress. A power system may have enough electricity over a full 24-hour period while still lacking sufficient flexible capacity during several critical evening hours.
Battery storage is beginning to address this imbalance. Bulgaria’s rapid expansion of storage capacity has strengthened its ability to absorb low-cost solar electricity during the day and release it during higher-demand periods. Greece has also developed a substantial pipeline of battery projects.
Elsewhere, deployment remains slower. Romania’s operational storage capacity is still relatively small compared with its expanding solar fleet, while larger storage projects in Serbia and Montenegro remain largely under development rather than fully operational.
The nuclear shortages in Romania and Hungary created potential export opportunities for Serbia, Bulgaria and other Western Balkan systems, but those countries were simultaneously dealing with their own generation constraints.
Serbia remained dependent on the availability of lignite-fired generation and hydropower, while Montenegro faced pressure from the overhaul of Perućica and the outage of the 225 MW Pljevlja thermal power plant. EPCG responded by bringing around 190 MW of hydro capacity back into service earlier than initially planned.
Albania’s electricity position remained highly dependent on hydrological conditions. Bosnia and Herzegovina’s hydro fleet provided valuable flexibility, but weak inflows and the declining reliability of some older coal units restricted the volume of generation that could be committed to exports.
The EU’s Carbon Border Adjustment Mechanism (CBAM) added another complication for Western Balkan electricity exports. Even when Serbian, Montenegrin or Bosnian electricity was physically available, carbon-related costs could reduce its commercial attractiveness unless the electricity qualified under the relevant actual-emissions rules.
This means regional adequacy and regional electricity trade are no longer determined by the same calculation. Power can be physically valuable to an importing EU market while remaining commercially disadvantaged because of its origin and associated carbon costs.
The end of the summer cooling season should provide some relief as peak electricity demand declines. The return of nuclear units would also restore a significant block of dependable generation capacity in Romania and Hungary.
Nevertheless, several risks are likely to remain through the autumn. The drought has reduced available water for hydropower and limited the ability of utilities to replenish reservoirs before winter. Remaining water may therefore be preserved for the highest-value periods instead of being used to reduce average market prices.
At the same time, heavy reliance on imports during the summer could reduce the flexibility available for planned maintenance. Delayed work on nuclear, thermal or transmission assets could overlap with the beginning of the heating season, creating additional pressure on regional supply.
European gas prices represent another important risk. Higher gas costs increase the marginal cost of electricity generation in markets such as Greece, Italy and Romania and can subsequently push wholesale electricity prices higher across interconnected Southeast European markets.
CBAM could also continue to limit commercially attractive electricity exports from the Western Balkans into EU markets, even during periods of tight EU supply. This could contribute to persistent price differences across borders such as Serbia–Hungary and Montenegro–Italy.
A widespread physical electricity shortage is not the base case for winter 2026/27. Restored nuclear generation, lower cooling demand and continued 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 prolonged cold spell could increase electricity demand across the region, while weak hydropower availability would limit flexible supply and elevated gas prices would increase the cost of replacing unavailable nuclear, coal or renewable generation.
During such periods, evening electricity prices could rise sharply even if total seasonal energy availability remains sufficient.
Romania and Hungary will remain key markets to watch because of the size of their nuclear fleets and their influence on regional electricity flows. Bulgaria could remain a relative exporter when Kozloduy nuclear generation, coal capacity and batteries are available. Greece will continue to transmit gas and LNG price developments into the electricity market, while Serbia’s position will depend heavily on EPS coal-unit reliability and hydro reserves.
Montenegro should benefit from the return of Perućica and additional wind generation from Gvozd, but its relatively small power system will remain exposed to the availability of Pljevlja and the cost of imports. Albania could shift rapidly between exporter and importer depending on rainfall and hydrological conditions.
The most sensitive period is likely to be the evening peak during cold and low-wind days. Solar generation will continue to suppress daytime prices, but storage and hydropower availability will determine how effectively that benefit can be carried into the evening.
ENTSO-E’s summer outlook correctly identified interconnection and regional coordination as key protections for European electricity security. The summer drought demonstrated their limitations: neighbouring markets can share reserve capacity and electricity, but they cannot all import the same megawatt-hour simultaneously.
For Southeast Europe, winter security will therefore depend less on headline installed capacity than on three operational factors: how much water remains in reservoirs, how many nuclear and coal units are actually available, and how much electricity can cross borders when neighbouring systems are under pressure at the same time.
Elevated by Virtu.Energy
