Southeast European electricity markets entered Thursday with a stronger renewable generation outlook and lower regional import dependence, but the improvement in physical supply conditions did little to restore price convergence. Instead, the day-ahead market produced one of the clearest examples this week of continued regional fragmentation: Hungary, Romania, Slovenia and Croatia settled in the €130–134/MWh range, Serbia and Bulgaria formed a lower middle tier, Greece and Albania traded below €100/MWh, while Montenegro and Italy maintained significant premiums.
The regional price signal was shaped by two opposing forces. Forecast electricity demand across Hungary and Southeast Europe increased by 1,111 MW, or approximately 3.5%, reaching 32,972 MW, as average temperatures rose by 1.4°C to 25.8°C. At the same time, renewable availability improved significantly. Expected solar generation increased by 508 MW to 7,767 MW, while wind generation rose by 767 MW to 3,207 MW. The combined renewable gain of 1,275 MW exceeded demand growth and reduced the region’s net import requirement by 442 MW, bringing it down to 1,410 MW.
However, the improvement was more visible in the physical supply balance than in market price formation. Imports from Austria and Slovakia into Hungary and Slovenia remained elevated at 2,140 MW, although they declined by 447 MW day on day. Meanwhile, exports from Southeast Europe towards Italy increased slightly to 888 MW, leaving the region exposed simultaneously to central European imports from the north and strong Italian demand from the west.
Hungary remained one of the region’s key price drivers. HUPX settled at €132.14/MWh, almost unchanged from Wednesday despite stronger renewable forecasts. Hungarian consumption increased to 4,672 MW, while domestic generation was forecast at only 3,174 MW, leaving a net deficit of 1,498 MW. The deficit widened from 1,208 MW on the previous day, keeping Hungary dependent on imports even as regional renewable availability improved.
The hourly structure of the Hungarian electricity market was more significant than the daily average. Prices fell to €12.20/MWh in hour 14, when solar generation was strongest, before rising sharply to €296.10/MWh in hour 20. The nearly €284/MWh difference between the daily minimum and maximum shows that additional photovoltaic capacity is suppressing midday prices but remains unable to solve evening system adequacy requirements. The market is increasingly valuing flexibility, ramping capability and cross-border availability rather than only overall energy supply.
Hungary maintained a €10.82/MWh premium over Germany, more than double the previous day’s spread. Germany settled at €121.33/MWh, while Austria remained slightly above Hungary at €134.13/MWh. Slovenia almost exactly matched HUPX at €132.19/MWh, while Croatia followed at €130.96/MWh. This northern price cluster reflected similar exposure to reduced firm generation and continued import requirements. Nuclear output across monitored markets declined by 552 MW to 4,466 MW, following constraints linked to low Danube water levels and reduced production at major nuclear facilities.
Romania reflected the same structural pressure. OPCOM settled at €130.15/MWh, only €1.99/MWh below Hungary, while Romanian consumption was forecast to rise by 172 MW to 5,574 MW. Generation was projected at 5,075 MW, leaving Romania with a 499 MW supply deficit. Despite this, commercial flows remained strong towards Hungary during peak periods, including average Romanian-to-Hungarian peak transfers of 1,224 MW. Romania also relied heavily on Bulgarian electricity imports, with Bulgarian-to-Romanian flows reaching approximately 1,641 MW on a baseload basis.
Bulgaria continued to operate as one of Southeast Europe’s main surplus electricity markets. Forecast generation of 4,998 MW exceeded consumption of 3,840 MW, creating a net export position of 1,158 MW. Nevertheless, IBEX increased by €9.80/MWh to €112.37/MWh. Bulgaria remained €19.77/MWh below Hungary but narrowed part of the previous session’s discount as exports towards Romania absorbed additional domestic surplus production.
The Bulgarian hourly curve remained relatively weak during solar production hours, reaching a minimum of €12.10/MWh in hour 15, while the evening peak was limited to €170.80/MWh. The country’s nuclear fleet and expanding solar capacity provided a more stable supply base than markets farther north. Its ability to export more than 1.6 GW towards Romania during parts of the day was central to balancing the Romanian and Hungarian systems.
Greece recorded one of the lowest liquid-market prices in Southeast Europe. HENEX declined by €3.30/MWh to €92.52/MWh, widening its discount to Hungary to €39.62/MWh. Greek peakload prices averaged only €42.70/MWh, while midday prices reached zero in hour 11. At the same time, Greece moved into a forecast net export position of 1,576 MW, compared with 1,015 MW on Wednesday.
The lower Greek price was supported by cooler weather conditions, with average temperatures expected to decline by 2°C to 26.8°C, reducing cooling demand while renewable and thermal availability remained sufficient. The large price gap between Greece and Hungary created a strong south-to-north trading signal, although transmission constraints and incomplete regional market coupling prevented full monetisation of the arbitrage opportunity.
Serbia recorded the largest day-on-day price decline among established regional exchanges. SEEPEX fell by €40.70/MWh to €104.77/MWh, leaving Serbia €27.37/MWh below Hungary. Electricity consumption was forecast to rise sharply to 3,859 MW, while generation recovered to 3,317 MW. The resulting deficit narrowed from 865 MW to 543 MW because generation growth exceeded demand growth.
The Serbian hourly price profile was less extreme than Hungary’s, with SEEPEX reaching €30.10/MWh in hour 12 and a maximum of €208/MWh in hour 20. Serbia continued importing electricity from neighbouring systems, including approximately 342 MW from North Macedonia, 253 MW from Bulgaria and 85 MW from Romania on average, while maintaining exports of around 156 MW towards Montenegro.
The SEEPEX decline reflected improved domestic availability, stronger regional renewable generation and cheaper imports from southern and eastern neighbours rather than a structural return to surplus. Serbia remained dependent on imports, particularly during peak hours, when the deficit widened to approximately 881 MW.
Montenegro moved in the opposite direction. BELEN increased by €10.90/MWh to €151.71/MWh, becoming the most expensive Southeast European exchange and placing the market €19.57/MWh above Hungary. Consumption increased to 469 MW, while forecast generation reached only 337 MW, leaving a deficit of 132 MW.
The Montenegrin market recorded a minimum price of €53/MWh in hour 9 and a maximum of €250/MWh in hour 21. Off-peak prices averaged €180.30/MWh, indicating that scarcity extended beyond the traditional evening peak. Montenegro continued receiving electricity from Bosnia and Herzegovina, Serbia, Albania and Kosovo, while transferring approximately 514 MW towards Italy through the submarine interconnector.
Italy remained the region’s dominant external price benchmark. The Italian national price increased by €5.30/MWh to €182.43/MWh, creating a premium of €50.29/MWh over Hungary. Northern Italy settled at €180.20/MWh, while the southern zone reached €184.60/MWh. The national minimum remained exceptionally high at €150.10/MWh, indicating persistent Italian market tightness throughout the day.
The Italian premium supported continued westward flows from Slovenia and Montenegro and limited the amount of surplus Balkan electricity available to ease pressure in Hungary and Croatia. Croatia remained a significant deficit market, with consumption of 2,429 MW against generation of only 1,155 MW. Its net import requirement widened to 1,274 MW, although integration with Slovenia and Hungary kept CROPEX close to the northern regional price cluster.
The forward market delivered an even stronger warning about Hungarian system tightness. Hungarian Week 32 increased by €9/MWh to €212/MWh, while Week 33 rose by €11.50/MWh to €157.50/MWh. The Week 32 premium over Germany widened to €84/MWh, compared with Hungary trading at a €32.50/MWh discount to Italy for the same product.
This unusual pricing structure, with Hungary trading above Germany and Italy in some contracts, indicates that traders are assigning a substantial risk premium to Hungarian and interconnected regional supply availability during the first week of August. The move was reinforced by the wider energy complex, with Austrian CEGH gas rising to €60.83/MWh, EU carbon allowances increasing to €82.02/t and API2 coal advancing to $122.50/t.
Thursday’s stronger renewable generation outlook reduced immediate import demand but failed to remove the scarcity embedded in evening prices and forward markets. The main trading opportunity remains the widening gap between lower-priced southern markets and expensive Hungarian and Italian demand centres. Ultimately, the ability to capture that value depends less on regional generation volumes and more on available cross-border transmission capacity.