Regional net electricity imports in Southeastern Europe rose 27.4% to 5,354 MW for Thursday delivery on 5 November 2026, as weaker wind generation, colder weather and higher consumption lifted day-ahead prices across the region, regional day-ahead market data showed. Imports covered 15.2% of consumption, up from approximately 12.1% in one trading session.
The 1,150 MW increase from Wednesday’s 4,204 MW coincided with a 353 MW rise in forecast consumption to 35,135 MW. Projected domestic generation fell by 797 MW, from 30,578 MW to 29,781 MW, while forecast wind generation dropped by 1,110 MW to 4,013 MW. Solar output was forecast to decline by 38 MW to 3,051 MW.
Prices rose across all major Southeastern European markets, with the strongest gains in Albania, Romania, Serbia and Montenegro. Spot prices increased while forward electricity and gas quotations softened, as immediate generation availability and cross-border supply conditions had more influence than longer-term energy costs.
Imports drive prices in exposed markets
Albania recorded the region’s highest average day-ahead price, €375.70/MWh, up €42.7/MWh from Wednesday. Its premium over Hungary widened to €68.63/MWh, and the hourly price reached €700/MWh during hour 23. Forecast consumption of 965 MW against projected generation of 463 MW left a net import requirement of 502 MW. The hourly peak illustrated the exposure of hydro-dependent and import-reliant systems to scarcity pricing when sufficient competitively priced cross-border supply is unavailable.
Romania’s OPCOM day-ahead average reached €324.13/MWh, an increase of €23.3/MWh. Its forecast net import requirement rose from 715 MW to 2,128 MW, more than the 1,150 MW increase in regional imports, as deficits eased in some neighbouring markets. Romanian generation was projected to fall from 6,111 MW to 4,598 MW, while demand slipped slightly to 6,726 MW.
Reduced nuclear availability left Romania exposed, with both Cernavoda units absent from the preceding day’s generation mix. The planned return of the approximately 700 MW Unit 1 was scheduled for 6 November, subject to operating conditions, and could ease the country’s import requirements.
Serbia’s SEEPEX day-ahead price rose by €25.2/MWh to €317.64/MWh, €10.57/MWh above Hungary’s and approximately €60/MWh above Germany’s. Forecast consumption of 4,367 MW compared with domestic generation of 3,105 MW, leaving a net import requirement of 1,262 MW, nearly 29% of consumption. That requirement was marginally lower than the previous day, but import dependence remained substantial.
The Serbian hourly price reached €422.6/MWh during hour 18, reflecting exposure to evening demand when domestic generation and available imports could not suppress peak prices. Montenegro’s BELEN day-ahead average rose by €23/MWh to €322.17/MWh, exceeding Serbian and Hungarian prices. Projected generation of 172 MW covered less than half of forecast consumption of 367 MW, leaving net imports of approximately 195 MW.
The preceding day’s Montenegrin generation mix showed no coal production and very limited hydropower output. Scheduled imports from Italy through the Montenegro–Italy interconnection averaged approximately 577 MW, alongside commercial electricity flows with neighbouring Balkan markets. Italy’s national electricity price was €277.64/MWh, approximately €44.53/MWh below Montenegro’s; actual trading returns depend on transmission rights, congestion and contract positions.
Spot and forward markets move in opposite directions
Day-ahead prices rose to €314.68/MWh in North Macedonia, €312.88/MWh in Bulgaria, €307.07/MWh in Hungary, €304.93/MWh in Croatia and €302.28/MWh in Slovenia. Greece’s price was €293.37/MWh, and the country was forecast to be a net electricity exporter of approximately 1,811 MW.
Hungary’s day-ahead price stood at €307.07/MWh, compared with €257.38/MWh in Germany, a premium of €49.69/MWh. Forecast net inflows through Austria and Slovakia into the Hungarian and Slovenian part of the regional system were approximately 4,154 MW, while electricity entering the region from Italy averaged approximately 1,205 MW. Regional import volumes and network conditions were insufficient to eliminate Hungary’s price premium.
Hungarian week-46 forward electricity fell by €10.50/MWh to €303.50/MWh, and week-47 forward electricity declined by €21/MWh to €273/MWh. December baseload electricity weakened by €9/MWh to €253/MWh, while the Hungarian–German week-46 forward spread narrowed by €24/MWh to €51.50/MWh. December gas forwards declined, while European carbon allowances remained broadly stable near €90 per tonne.
The divergence between rising spot prices and falling Hungarian forward quotations reflected a session shaped by short-term generation availability, weather variability and transmission constraints rather than a uniform rise in electricity supply costs. The session underscored the importance of hourly price exposure, firm cross-border capacity, flexible generation and battery storage for electricity traders, industrial consumers and renewable generators.
Serbia and Montenegro remained particularly sensitive to import requirements and evening peak prices, while Romania’s nuclear availability and regional wind production were identified as important near-term market conditions. The risk was not only sustained high average prices but also wider differences between countries and hours, which can create procurement costs and trading exposure even as longer-dated electricity prices decline.