Southeast Europe’s day-ahead electricity market tightened significantly on Wednesday as rising cooling demand collided with reduced nuclear availability in Hungary and Romania. The combination pushed prices sharply higher across much of the central and western region, while strong renewable output allowed Greece and Bulgaria to move in the opposite direction.
The strongest increase was recorded in Serbia, where the SEEPEX baseload price climbed by €29.0/MWh to €145.50/MWh, placing it €13.16/MWh above Hungary and above all neighbouring markets except Albania. Croatia increased by €23.3/MWh to €138.73/MWh, Romania rose by €22.1/MWh to €132.87/MWh, Slovenia gained €16.4/MWh to €141.83/MWh, and Montenegro advanced by €15.7/MWh to €140.79/MWh.
Hungary’s HUPX benchmark increased by €10.3/MWh to €132.34/MWh, remaining close to Germany, where the day-ahead price reached €126.84/MWh. The Hungarian premium over Germany was therefore limited to €5.50/MWh, although this masked a more stressed forward market and significant hourly volatility, particularly during the evening ramp.
In contrast, Greece and Bulgaria experienced lower prices due to strong renewable generation. Greece declined by €11.2/MWh to €95.79/MWh, while Bulgaria fell by €4.4/MWh to €102.59/MWh. Greece traded €36.55/MWh below Hungary and almost €50/MWh below Serbia, reflecting the impact of high solar and wind availability.
Albania remained the most expensive regional market with a baseload price of €148.19/MWh, despite a daily decrease of €10.1/MWh. North Macedonia increased by €7.2/MWh to €114.71/MWh, while Italy continued to represent the region’s premium market at €177.13/MWh, maintaining a wide spread over Southeast European markets.
The main driver behind the price surge was the deterioration of nuclear availability along the Danube. Hungary’s Paks nuclear plant reduced output from unit 1 by around 254 MW due to exceptionally low river levels affecting cooling conditions. At the same time, Romanian producer Nuclearelectrica placed Cernavoda unit 1 into a controlled shutdown. Combined regional nuclear output fell by 542 MW, from 5,560 MW to 5,018 MW.
Hungarian nuclear production dropped from 1,834 MW to 1,577 MW, while Romanian output declined from 1,165 MW to 880 MW. The full impact of the Romanian shutdown was expected to become more visible in Wednesday’s physical balance, as the outage began during Tuesday. With the Danube flow indicator at approximately 4,691 cubic metres per second, river conditions remained a direct operational risk for both Paks and Cernavoda.
The nuclear reduction coincided with higher regional electricity demand, which was forecast to reach 32,490 MW, an increase of 1,417 MW compared with Tuesday. Hungary, Greece, Romania, Bulgaria, Slovenia and Croatia all recorded higher consumption forecasts as temperatures continued to rise and cooling demand increased.
Renewable generation provided important support but was not sufficient to fully offset higher demand and reduced nuclear output. Regional solar production was expected to reach 7,417 MW, while wind generation increased to 2,455 MW. The additional renewable supply helped create deep midday price declines, but it could not eliminate the evening scarcity period after solar production faded.
This imbalance created a strong difference between daytime and evening prices. In Hungary, peak prices averaged €92.00/MWh, while off-peak prices reached €172.60/MWh. The minimum price was €11.80/MWh at hour 14 before rising sharply to €267.60/MWh at hour 21. Germany followed a similar pattern, moving from €0/MWh during the afternoon to €263.60/MWh in the evening.
The evening price spike was even more pronounced in Slovenia and Croatia. BSP reached €305.10/MWh at hour 20, while CROPEX peaked at €289.90/MWh. Although their daily average premiums over Hungary were relatively small, the hourly profile showed that market stress was concentrated during the sunset ramp rather than across the full day.
Serbia also recorded a tight market structure. SEEPEX prices remained above €45.00/MWh throughout the day before rising to €251.10/MWh at hour 21. Serbian peakload averaged €112.90/MWh, while off-peak prices reached €178.00/MWh. The relatively high midday floor reflected limited solar penetration, a tighter domestic balance and continued dependence on imports.
Serbia’s consumption was forecast at 3,457 MW, compared with domestic generation of 2,593 MW, resulting in average net imports of 865 MW. Imports increased during peak hours to 1,173 MW, with Serbia receiving electricity mainly from Romania, North Macedonia, Croatia, Bulgaria and Bosnia and Herzegovina.
The country’s import dependence helps explain the €13.16/MWh SEEPEX premium over HUPX. Serbia was competing for regional supply at a time when Romanian nuclear availability was falling and Croatian demand for imports was increasing. Cross-border capacity availability therefore became a key factor shaping Serbian prices.
Croatia faced an even tighter balance, with consumption rising to 2,369 MW while domestic generation reached only 1,228 MW. The country required average imports of 1,142 MW, including approximately 1,065 MW from Hungary. This explains why CROPEX followed the HUPX trend but experienced stronger evening price pressure.
Montenegro remained a net importer, with consumption of 447 MW and generation of 320 MW. However, exports through the submarine interconnector to Italy continued to provide commercial value, supporting a BELEN price of €140.79/MWh. The Italian market maintained a premium of more than €36/MWh over Montenegro, encouraging westbound electricity flows.
Romania recorded the largest market-position reversal, moving from an average net export position of 350 MW on Tuesday to expected net imports of around 450 MW. Generation declined to 5,036 MW, while consumption increased to 5,486 MW. Bulgaria supplied approximately 1,266 MW to Romania, helping compensate for the loss of nuclear output.
This shift explains the €22.1/MWh increase in the OPCOM price and Romania’s slight premium over HUPX. The Cernavoda outage transformed Romania from a regional balancing source into a market requiring additional external support.
Bulgaria remained the region’s main surplus market, producing around 5,047 MW compared with consumption of 3,915 MW. It exported approximately 1,266 MW to Romania, 294 MW to North Macedonia and 101 MW to Serbia, while importing 517 MW from Greece. Stable nuclear production at Kozloduy and strong solar availability supported Bulgaria’s lower price level.
Greece generated approximately 8,555 MW against consumption of 7,493 MW, creating net exports of 1,061 MW. The country supplied Bulgaria, North Macedonia and Albania, reversing its position from earlier in the week when it had been a net importer.
The Greek market demonstrated the impact of renewable penetration. HENEX peakload averaged only €42.70/MWh, with prices reaching €0/MWh during the afternoon solar peak. However, evening prices remained considerably higher, showing that low daytime prices did not eliminate broader system tightness.
At the regional level, Hungary and Southeast Europe required net imports of 1,753 MW, an increase of 518 MW. Imports from Austria and Slovakia into Hungary and Slovenia rose, while exports toward Italy declined. The region therefore relied more heavily on Central European supply despite continued Italian demand.
Hungary’s own net imports increased to 1,162 MW. The country received electricity from Slovakia, Romania and Slovenia while exporting some power to Croatia. Its balance differed significantly by time period, with relatively stable daytime conditions but heavy dependence on neighbouring markets during evening and overnight hours.
Forward markets indicate that traders expect the pressure to continue. Hungary Week 32 surged to €203.00/MWh, increasing its premium over Germany to €78/MWh. The contract has gained 37.6 per cent since 20 July, reflecting concerns over heat, nuclear availability and regional import capacity.
The Hungarian August contract also increased to €159.50/MWh, while Germany Week 32 eased to €125/MWh and Italy Week 32 remained at €174/MWh. The sharp difference between Hungary Week 32 and Week 33 highlights that the market is pricing the strongest scarcity risk in the immediate period.
Fuel markets did not drive the electricity increase. Gas prices declined, EU carbon allowances weakened slightly and coal markets remained broadly stable. The power-price rally was therefore mainly caused by physical availability constraints, weather conditions and cross-border capacity limitations rather than higher fuel costs.
The main trading risk remains concentrated during evening hours from 19:00 to 22:00, when solar generation falls, cooling demand remains elevated and nuclear output is reduced. Greece and Bulgaria continue to provide important regional support, but Serbia, Croatia and Romania remain the markets most exposed to further supply constraints. With Hungarian forward prices already above €200/MWh, the market is signalling that tight conditions may continue beyond Wednesday’s spot delivery.