Southeast Europe’s net electricity imports rose 27.4% to 5,354 MW for delivery on Thursday, 5 November 2026, as weaker wind generation, colder weather and higher consumption lifted day-ahead prices across the region. Imports met 15.2% of consumption, compared with approximately 12.1% in the previous trading session. Regional day-ahead market data showed forecast consumption increasing by 353 MW to 35,135 MW.
Imports grew by 1,150 MW from Wednesday’s 4,204 MW as projected domestic generation fell by 797 MW, from 30,578 MW to 29,781 MW. Forecast wind output fell by 1,110 MW to 4,013 MW, while forecast solar generation decreased by 38 MW to 3,051 MW. Prices increased in all major Southeastern European markets, with the largest gains in Albania, Romania, Serbia and Montenegro.
The spot-market rise contrasted with softer forward electricity and gas quotations. Immediate generation availability and cross-border supply conditions weighed more heavily on the session than longer-term energy costs.
Import requirements lift prices in Albania and Romania
Albania recorded the region’s highest average day-ahead price, at €375.70/MWh, up €42.7/MWh from Wednesday. Its premium to Hungary widened to €68.63/MWh, while the hourly price peaked at €700/MWh in hour 23. Forecast consumption of 965 MW exceeded projected generation of 463 MW, leaving a net import requirement of 502 MW.
The hourly peak showed how hydro-dependent and import-reliant systems can be exposed to scarcity pricing when competitively priced cross-border supply is unavailable. Albania’s peak was the highest hourly price reported for the session.
Romania’s OPCOM day-ahead average rose by €23.3/MWh to €324.13/MWh. Its forecast net import requirement increased from 715 MW to 2,128 MW, a rise greater than the increase in total regional imports as deficits eased in some neighbouring markets. Projected generation fell from 6,111 MW to 4,598 MW, while demand edged down to 6,726 MW.
Romania remained exposed to lower nuclear availability, with both Cernavoda units absent from the previous 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 reduce the country’s import needs.
Serbia and Montenegro remain import-sensitive
Serbia’s SEEPEX day-ahead price climbed by €25.2/MWh to €317.64/MWh. That was €10.57/MWh above Hungary’s price and approximately €60/MWh higher than 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, or nearly 29% of consumption.
Serbia’s net import requirement was marginally below the previous day’s level, but its reliance on imports remained substantial. The hourly price reached €422.6/MWh in hour 18, reflecting exposure to evening demand when domestic generation and available imports could not contain peak prices.
Montenegro’s BELEN day-ahead average increased by €23/MWh to €322.17/MWh, above prices in Serbia and Hungary. Forecast generation of 172 MW was less than half of expected consumption of 367 MW, leaving net imports of approximately 195 MW. The previous day’s generation mix showed no coal output and very limited hydropower production.
Scheduled imports from Italy through the Montenegro–Italy interconnection averaged approximately 577 MW, while Montenegro also maintained commercial electricity flows with neighbouring Balkan markets. Italy’s national electricity price was €277.64/MWh, approximately €44.53/MWh below Montenegro’s. The price difference highlighted the commercial relevance of the Adriatic interconnection, although trading returns depend on transmission rights, congestion and contract positions.
Spot prices rise as forward quotations soften
Day-ahead prices reached €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 exporter of approximately 1,811 MW. Hungary’s price was €49.69/MWh above Germany’s €257.38/MWh.
Forecast net inflows through Austria and Slovakia into the Hungarian and Slovenian part of the regional system were approximately 4,154 MW. Electricity entering the region from Italy averaged approximately 1,205 MW, but regional import volumes and network conditions were insufficient to eliminate Hungary’s price premium.
Unlike spot prices, Hungarian week-46 forward electricity fell by €10.50/MWh to €303.50/MWh, while week-47 forward electricity declined by €21/MWh to €273/MWh. December baseload electricity weakened by €9/MWh to €253/MWh, and 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 contrast between rising spot prices and falling Hungarian forward quotations reflected the influence of short-term generation availability, weather variability and transmission constraints, rather than a uniform increase in electricity supply costs.
Hourly price exposure, firm cross-border capacity, flexible generation and battery storage were central considerations for electricity traders, industrial consumers and renewable generators. Serbia and Montenegro remained particularly sensitive to import requirements and evening demand peaks, while Romania’s nuclear availability and regional wind production were key near-term market variables. Risks included sustained high average prices and wider differences between countries and hours, creating procurement costs and trading exposure even as longer-dated electricity prices fell.
