Southeast Europe entered Wednesday with a much tighter and more fragmented day-ahead market as increasing cooling demand collided with nuclear availability constraints in Hungary and Romania. The result was a sharp price rebound across the central and western part of the region, while strong renewable generation allowed Greece and Bulgaria to move in the opposite direction.
The clearest upward move came in Serbia. The SEEPEX baseload price rose by €29.0/MWh to €145.50/MWh, placing Serbia €13.16/MWh above Hungary and above every neighbouring market except Albania. Croatia advanced by €23.3/MWh to €138.73/MWh, Romania gained €22.1/MWh to €132.87/MWh, Slovenia climbed €16.4/MWh to €141.83/MWh, and Montenegro increased by €15.7/MWh to €140.79/MWh.
Hungary’s HUPX benchmark rose by €10.3/MWh to €132.34/MWh. It remained close to Germany, where the day-ahead price increased to €126.84/MWh, leaving the Hungarian premium over Germany at only €5.50/MWh. That relatively narrow daily baseload spread conceals a much more stressed Hungarian forward position and pronounced hourly volatility around the evening ramp.
Greece fell by €11.2/MWh to €95.79/MWh, while Bulgaria declined by €4.4/MWh to €102.59/MWh. Greece consequently traded at a discount of €36.55/MWh to Hungary, €49.71/MWh to Serbia and almost €81.34/MWh to Italy. Bulgaria stood €29.75/MWh below Hungary despite remaining a substantial exporter.
Albania retained the highest regional baseload price at €148.19/MWh, although this represented a daily decline of €10.1/MWh. North Macedonia rose by €7.2/MWh to €114.71/MWh, leaving it €17.63/MWh below Hungary. Italy remained the regional premium market at €177.13/MWh, maintaining a spread of €44.79/MWh over HUPX.
The central driver was the deterioration in nuclear availability along the Danube. Hungary’s Paks nuclear plant reduced the output of unit 1 by approximately 254 MW because exceptionally low Danube water levels constrained cooling conditions. Romanian producer Nuclearelectrica simultaneously moved Cernavoda unit 1 into a controlled shutdown. The combined effect was already visible in Tuesday’s average nuclear production, which fell by 542 MW, from 5,560 MW to 5,018 MW across the covered region.
Hungarian nuclear production decreased from 1,834 MW to 1,577 MW, while Romania’s nuclear output fell from 1,165 MW to 880 MW. Because the Romanian shutdown only occurred during Tuesday, its full-day impact is likely to be more pronounced in Wednesday’s physical balance. The Danube flow indicator stood at approximately 4,691 cubic metres per second, with low river conditions remaining a direct availability risk for both Paks and Cernavoda.
The nuclear reduction was particularly important because regional electricity consumption was forecast to rise to 32,490 MW, an increase of 1,417 MW from Tuesday. Hungary added 185 MW of demand to reach 4,569 MW, Greece gained 184 MW to 7,493 MW, combined Romanian and Bulgarian consumption increased by 529 MW, and Slovenia and Croatia added 507 MW. Forecast temperatures point to further warming toward the end of the week, particularly in Hungary, Serbia, Croatia and Montenegro, keeping cooling demand on an upward trajectory.
Renewable generation offered substantial relief but could not fully cover the increase in demand and lost nuclear output. Regional solar production was forecast at 7,417 MW, up by 476 MW, while wind was expected to increase by 536 MW to 2,455 MW. The combined increase of slightly more than 1 GW explains the deep midday price compression, but its timing did little to remove the evening scarcity signal after solar production declined.
That imbalance produced an unusually pronounced inversion between conventional peak and off-peak products. HUPX peak averaged only €92.00/MWh, while off-peak averaged €172.60/MWh. The Hungarian minimum fell to €11.80/MWh at hour 14, before the price accelerated to €267.60/MWh at hour 21. Germany displayed almost the same shape, ranging from €0/MWh at hour 15 to €263.60/MWh at hour 21.
The evening premium was even more severe in Slovenia and Croatia. BSP reached a maximum of €305.10/MWh at hour 20, while CROPEX peaked at €289.90/MWh, also at hour 20. Their daily baseload premiums over Hungary were only €9.49/MWh and €6.39/MWh, respectively, but the hourly profiles show that the real trading exposure was concentrated in the sunset ramp rather than in the daily average.
Serbia displayed a similar but structurally firmer profile. SEEPEX fell no lower than €45.00/MWh, compared with €11.80/MWh in Hungary and zero in Greece, before rising to €251.10/MWh at hour 21. Serbian peakload settled at €112.90/MWh, while off-peak reached €178.00/MWh. The relatively high Serbian midday floor points to a tighter domestic balance, limited solar penetration compared with neighbouring coupled markets and continued dependence on imports.
Serbian consumption was forecast at 3,457 MW, while domestic generation was estimated at 2,593 MW, leaving average net imports of 865 MW. The deficit expanded from 705 MW on Tuesday and became particularly pronounced during peak hours, when imports reached 1,173 MW. Serbia drew an average 378 MW from Romania, 320 MW from North Macedonia, 129 MW from Croatia, 101 MW from Bulgaria and 94 MW from Bosnia and Herzegovina, while supplying approximately 156 MW to Montenegro.
This import requirement helps explain the €13.16/MWh SEEPEX premium over HUPX. Although Hungary was itself a net importer, Serbia competed for southbound and westbound capacity at a time when Romanian nuclear availability was falling and Croatia was also heavily short. Serbia’s dependence on regional imports is therefore being priced not only through generation costs but through the availability and direction of cross-border capacity during the evening ramp.
Croatia’s balance was tighter still. Consumption rose to 2,369 MW, against domestic generation of only 1,228 MW, producing average imports of 1,142 MW. Peak imports reached 1,295 MW, including approximately 1,065 MW from Hungary. Croatia’s dependence on Hungarian supply explains why CROPEX followed the HUPX curve but developed a sharper hour-20 premium as local solar generation declined.
Montenegro remained a net importer by approximately 127 MW, with consumption of 447 MW and generation of 320 MW. Imports from Bosnia and Herzegovina, Serbia, Albania and Kosovo were partly offset by exports of approximately 484 MW through the submarine interconnector to Italy. This maintained BELEN at €140.79/MWh, above HUPX but below Serbia and Albania. The Italian link continued to draw electricity westward because the Italian market retained a premium exceeding €36/MWh over Montenegro.
Romania recorded the most significant change in physical positioning. The country moved from an average net export of 350 MW on Tuesday to a forecast net import of 450 MW. Generation declined from 5,808 MW to 5,036 MW, while consumption increased slightly to 5,486 MW. Bulgaria supplied Romania with approximately 1,266 MW, offsetting Romanian exports of 383 MW to Hungary, 378 MW to Serbia and 154 MW to Moldova.
This reversal explains the €22.1/MWh increase in OPCOM and Romania’s small €0.53/MWh premium over HUPX. The Romanian price effectively converged with Hungary because the Cernavoda outage transformed Romania from a source of regional flexibility into a market requiring substantial Bulgarian support.
Bulgaria remained the region’s principal surplus market, producing around 5,047 MW against consumption of 3,915 MW and exporting an average 1,133 MW. Most of this surplus moved north into Romania. Bulgaria exported approximately 1,266 MW to Romania, 294 MW to North Macedonia and 101 MW to Serbia, while importing around 517 MW from Greece. Its €102.59/MWh price reflected continued nuclear stability at Kozloduy, solar availability and access to lower-priced Greek electricity.
Greece generated approximately 8,555 MW against consumption of 7,493 MW, creating net exports of 1,061 MW. Exports included 517 MW to Bulgaria, 364 MW to North Macedonia and 166 MW to Albania. This was a dramatic reversal from Monday, when Greece had been a net importer by 273 MW.
The Greek hourly curve also reflected strong renewable pressure. HENEX peakload averaged only €42.70/MWh, with the minimum reaching €0/MWh at hour 16. Off-peak prices remained much firmer at €148.80/MWh, while the daily maximum of €173.50/MWh appeared during hour 7. Greece’s low baseload price was therefore not a sign of universally loose conditions, but the product of a deep solar-driven daytime trough combined with strong wind availability and substantial exports to northern neighbours.
At the aggregate 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 to 2,493 MW, while exports toward Italy decreased to approximately 870 MW. The region therefore depended more heavily on the Central European system even as the Italian price premium continued to pull available electricity westward.
Hungary’s own net imports increased to 1,162 MW. The country received approximately 1,501 MW from Slovakia, 383 MW from Romania and 438 MW from Slovenia, while exporting 750 MW to Croatia. Its balance was sharply divided by delivery period: Hungary was a modest net exporter of approximately 199 MW during peak hours, but imported an average 2,523 MW off-peak, reflecting heavy evening and overnight dependence on neighbouring systems.
Forward trading shows that the market does not consider the Hungarian tightness a single-day event. Hungary Week 32 rose by €28.50/MWh to €203.00/MWh, taking its premium over Germany Week 32 to €78.00/MWh. The contract has gained 37.6 per cent since 20 July. By comparison, Germany Week 32 eased to €125.00/MWh, while Italy Week 32 stood at €174.00/MWh.
The Hungarian August contract increased to €159.50/MWh, widening its premium over Germany to €35.50/MWh. Hungary Week 33 remained considerably lower at €146.00/MWh, indicating that the most severe scarcity premium remains concentrated in the immediate horizon. The €57/MWh backwardation between Week 32 and Week 33 is a direct measure of the market value currently assigned to heat, nuclear availability and cross-border capacity during the first week of August.
Fuel markets did not account for the increase in near-term power risk. CEGH gas declined by €1.70/MWh to €57.89/MWh, Greek gas fell by €1.20/MWh to €47.79/MWh, and EU carbon allowances eased to €81.73 per tonne. Coal was broadly stable on the nearby contract and lower for the fourth quarter. Hungarian power therefore strengthened while gas, carbon and coal weakened, confirming that the premium was being driven by physical availability and location rather than a general increase in marginal fuel costs.
The immediate trading risk remains concentrated in hours 19–22, where falling solar output, growing cooling demand and reduced nuclear availability overlap. Greece and Bulgaria retain the strongest potential to supply the northern and western Balkans, but their export contribution is already substantial. Serbia and Croatia remain the most exposed short markets, while Romania’s ability to provide balancing energy has been materially reduced by Cernavoda. With Hungary Week 32 already above €200/MWh, the forward curve is pricing continued scarcity well beyond Wednesday’s spot delivery.
