Regional net electricity imports for delivery on Thursday, 5 November 2026, increased 27.4% to 5,354 MW as weaker wind generation, colder weather and higher consumption lifted day-ahead prices across Southeast Europe. Imports covered 15.2% of regional consumption, up from approximately 12.1% in the previous trading session. Regional day-ahead market data showed the increase in import dependence alongside higher spot prices.
Imports rose by 1,150 MW from Wednesday’s 4,204 MW as forecast consumption increased by 353 MW to 35,135 MW. Projected domestic 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. Forecast solar output declined by 38 MW to 3,051 MW.
Prices increased across all major Southeastern European markets, with the strongest gains in Albania, Romania, Serbia and Montenegro. The spot-market rise came alongside weaker forward electricity and gas quotations. Immediate generation availability and cross-border supply conditions weighed more heavily in the session than longer-term energy costs.
Import requirements and scarcity pricing in the western Balkans
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, while the hourly price reached €700/MWh in hour 23, the session’s highest reported hourly price. Forecast consumption of 965 MW was higher than 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 rose by €23.3/MWh to €324.13/MWh. Its forecast net import requirement increased from 715 MW to 2,128 MW, more than the rise in total regional imports, as deficits eased in some neighbouring markets.
Romanian generation was projected to drop 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 preceding day’s generation mix. The approximately 700 MW Unit 1 was scheduled to return on 6 November, subject to operating conditions, and could reduce Romania’s import needs.
Serbia’s SEEPEX day-ahead price increased 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, resulting in a net import requirement of 1,262 MW, nearly 29% of consumption. That requirement was marginally lower than the previous day, but Serbia remained substantially dependent on imports.
Serbia’s hourly price peaked at €422.6/MWh in hour 18, as evening demand coincided with domestic generation and available imports being unable to suppress the peak. 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 output and very limited hydropower generation. 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, where trading returns depend on transmission rights, congestion and contract positions.
Regional spot prices and cross-border flows
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 not sufficient 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. 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. Spot prices rose as Hungarian forward quotations fell, with short-term generation availability, weather variability and transmission constraints shaping the session rather than a uniform increase in electricity supply costs.
Trading exposure and near-term market variables
Hourly price exposure, firm cross-border capacity, flexible generation and battery storage were key considerations for electricity traders, industrial consumers and renewable generators. Serbia and Montenegro remained particularly sensitive to import requirements and price peaks in the evening, while Romania’s nuclear availability and regional wind production were near-term market variables.
The 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 declined.