Net electricity imports in Southeast Europe 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 covered 15.2% of consumption, compared with approximately 12.1% in one trading session. The increase came alongside higher forecast demand and lower projected domestic generation.
Imports rose by 1,150 MW from Wednesday’s 4,204 MW as forecast consumption increased by 353 MW to 35,135 MW. Projected generation fell by 797 MW, from 30,578 MW to 29,781 MW, while wind generation was forecast to fall by 1,110 MW to 4,013 MW. Solar output was expected to decline 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 had a greater bearing on the session than longer-term energy costs.
Import exposure and day-ahead prices
Albania recorded the region’s highest average day-ahead price at €375.70/MWh, up €42.7/MWh from Wednesday. Its premium over Hungary widened to €68.63/MWh, and the hourly price peaked at €700/MWh in hour 23, the highest reported hourly price of the session. Forecast consumption of 965 MW exceeded projected generation of 463 MW, leaving a net import requirement of 502 MW.
The hourly peak showed the exposure of hydro-dependent and import-reliant systems to scarcity pricing when 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, a larger increase than regional imports, as deficits eased in some neighbouring markets.
Romanian generation was forecast to fall from 6,111 MW to 4,598 MW, while demand edged down to 6,726 MW. The country 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 ease Romania’s import needs.
Serbia’s SEEPEX day-ahead price rose by €25.2/MWh to €317.64/MWh, €10.57/MWh above Hungary’s price 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.
Serbia’s hourly price reached €422.6/MWh in 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, above prices in Serbia and Hungary. Forecast generation of 172 MW covered less than half of expected consumption of 367 MW, leaving net imports of approximately 195 MW.
Montenegro’s generation mix on the preceding day showed no coal production and very limited hydropower output. Scheduled imports from Italy through the Montenegro–Italy interconnection averaged approximately 577 MW, while the country 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; trading returns depend on transmission rights, congestion and contract positions.
Regional prices and forward-market movements
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. Regional import volumes and network conditions were insufficient to eliminate Hungary’s price premium.
While spot prices rose, 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. 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 session’s rising spot prices and falling Hungarian forward quotations coincided with short-term generation availability, weather variability and transmission constraints shaping the market 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 peaks in evening demand, while Romania’s nuclear availability and regional wind production were key near-term market variables. The risks included both sustained high average prices and larger differences between countries and hours, creating procurement costs and trading exposure even as longer-dated electricity prices declined.