Southeast European electricity markets entered Thursday with a stronger renewable forecast and lower regional import dependence, but the improvement in physical supply did little to restore price convergence. The day-ahead session instead produced one of the clearest examples this week of fragmented regional pricing: Hungary, Romania, Slovenia and Croatia settled around €130–134/MWh, Serbia and Bulgaria formed a lower middle tier, Greece and Albania traded below €100/MWh, while Montenegro and Italy retained substantial premiums.
The regional system price signal was shaped by two opposing forces. Forecast electricity consumption across Hungary and southeast Europe increased by 1,111 MW, or approximately 3.5%, to 32,972 MW, as average temperatures rose by 1.4°C to 25.8°C. At the same time, renewable generation forecasts strengthened materially. Solar output was expected to rise by 508 MW to 7,767 MW, while wind increased by 767 MW to 3,207 MW. The combined renewable gain of 1,275 MW was sufficient to cover the increase in demand and reduce the region’s net import requirement by 442 MW, to 1,410 MW.
The improvement was most visible in the physical balance rather than in the core price formation. Imports from Austria and Slovakia into Hungary and Slovenia remained high at 2,140 MW, although they declined by 447 MW day on day. Exports from southeast Europe towards Italy increased slightly to 888 MW, leaving the region exposed simultaneously to central European imports in the north and strong Italian pull in the west.
HUPX settled at €132.14/MWh, almost unchanged from Wednesday, despite the stronger renewable outlook. Hungary’s consumption increased to 4,672 MW, while domestic generation was forecast at only 3,174 MW, producing a net deficit of 1,498 MW. The deficit widened from 1,208 MW on the previous day and left the Hungarian market dependent on imports even as regional renewable availability improved.
The structure of the Hungarian hourly curve was more important than the flat daily average. Prices fell to €12.20/MWh in hour 14, when solar production was strongest, before rising to €296.10/MWh in hour 20. The difference of almost €284/MWh between the daily minimum and maximum demonstrates that additional photovoltaic generation is suppressing midday prices but remains unable to address the evening adequacy requirement. The market is increasingly pricing flexibility, ramping capability and cross-border availability rather than daily energy scarcity alone.
Hungary maintained a premium of €10.82/MWh 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 converged almost exactly with HUPX at €132.19/MWh, and Croatia followed at €130.96/MWh.
This northern cluster reflected common exposure to reduced firm generation and continuing import demand. Nuclear output across the monitored region had fallen by 552 MW on Wednesday to 4,466 MW, following availability constraints associated with low Danube water levels and reduced production at major nuclear plants. Solar generation reached 7,259 MW and wind rose to 2,440 MW, but the loss of continuous nuclear output increased the value of evening supply.
Romania illustrates that tension particularly clearly. 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 deficit. Commercial flows nevertheless showed strong transfers towards Hungary during peak hours, including an average Romanian-to-Hungarian peak flow of 1,224 MW. Romania simultaneously imported heavily from Bulgaria, with the Bulgarian-to-Romanian flow reaching approximately 1,641 MW on a baseload basis.
Bulgaria therefore operated as one of the region’s principal surplus markets. Forecast generation of 4,998 MW exceeded consumption of 3,840 MW, creating a net export position of 1,158 MW. IBEX nevertheless 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 domestic surplus production.
The Bulgarian price curve retained a relatively weak midday profile, reaching a minimum of €12.10/MWh in hour 15, but the evening maximum was limited to €170.80/MWh. Bulgaria’s nuclear fleet and growing solar portfolio 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 the region. HENEX fell by €3.30/MWh to €92.52/MWh, widening its discount to Hungary to €39.62/MWh. Greek peakload 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. Flows towards Albania and North Macedonia increased, while the internal Bulgaria–North Macedonia–Albania corridor delivered a combined 1,556 MW towards Greece under the report’s regional-flow convention.
The low Greek price was supported by lower temperatures, with the national average forecast to decline by 2°C to 26.8°C, reducing cooling demand at a time of adequate renewable and thermal availability. The divergence between Greece and Hungary provides a strong south-to-north arbitrage signal, but transmission constraints and the absence of full regional market coupling prevent that differential from being fully monetised.
Serbia experienced the largest meaningful day-on-day decline among the established regional exchanges. SEEPEX fell by €40.70/MWh to €104.77/MWh, leaving Serbia €27.37/MWh below Hungary. Serbian consumption was forecast to rise sharply to 3,859 MW, an increase of 352 MW, while generation recovered to 3,317 MW. The resulting deficit narrowed from 865 MW to 543 MW because generation increased faster than demand.
The Serbian hourly profile remained less extreme than Hungary’s. SEEPEX reached a minimum of €30.10/MWh in hour 12 and a maximum of €208/MWh in hour 20. Serbia continued importing from most surrounding systems, including approximately 342 MW from North Macedonia, 253 MW from Bulgaria and 85 MW from Romania on average. It maintained exports of around 156 MW towards Montenegro.
The fall in SEEPEX therefore represented a combination of improved domestic availability, stronger regional renewable production and cheaper imports from the south and east. It was not evidence of 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, making it the most expensive SEE exchange and placing it €19.57/MWh above Hungary. Consumption rose to 469 MW, while forecast generation reached 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. Its off-peak average reached €180.30/MWh, indicating that scarcity was not confined to the conventional 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. That westward export schedule, combined with limited domestic generation and relatively shallow exchange liquidity, helps explain why BELEN remained substantially above neighbouring Serbia and Albania.
Italy provided the region’s dominant external price signal. The Italian national price increased by €5.30/MWh to €182.43/MWh, 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, demonstrating that Italian scarcity persisted throughout the day rather than emerging only during the evening ramp.
This Italian premium supported continued westward flows from Slovenia and Montenegro and limited the amount of surplus Balkan generation available to ease conditions in Hungary and Croatia. Croatia remained a particularly large 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 rose by €9/MWh to €212/MWh, while Week 33 increased by €11.50/MWh to €157.50/MWh. The Week 32 premium over Germany widened to €84/MWh, compared with a Hungarian discount of €32.50/MWh to Italy for the same product. This inversion—Hungary priced far above Germany and even above Italy—indicates that traders are attaching a substantial risk premium to Hungarian and interconnected regional availability during the first week of August.
The move was reinforced by the fuel complex. Austrian CEGH gas increased by €2.90/MWh to €60.83/MWh, EU carbon allowances rose to €82.02/t, and API2 coal advanced to $122.50/t. Hungarian August baseload climbed to €164/MWh, compared with €128/MWh in Germany, while Hungarian Q4 traded at €169/MWh, a premium of €27/MWh to Germany.
Thursday’s renewable recovery has reduced immediate import demand, but it has not removed the scarcity embedded in the evening curve or the forward market. The central trading opportunity remains the widening gap between low-priced southern supply and expensive Hungarian and Italian demand centres. Available interconnection capacity, rather than regional generation volume, is determining where that value can be captured.
