Regional net electricity imports rose 27.4% to 5,354 MW for Thursday delivery on 5 November 2026, as weaker wind generation, colder weather and higher consumption pushed day-ahead prices up across Southeastern Europe. Regional day-ahead market data showed imports covered 15.2% of consumption, compared with approximately 12.1% in the previous trading session. The rise in immediate prices contrasted with softer forward electricity and gas quotations.
Imports increased by 1,150 MW from Wednesday’s 4,204 MW, while forecast regional consumption rose by 353 MW to 35,135 MW. Projected domestic generation fell by 797 MW, from 30,578 MW to 29,781 MW. Forecast wind generation dropped by 1,110 MW from the previous day to 4,013 MW, and solar output declined 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. The session’s spot-market increases coincided with lower wind generation and higher import needs, while longer-dated energy quotations moved lower.
Import exposure lifts national prices
Albania recorded the region’s highest day-ahead average at €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 generation of 463 MW implied a net import requirement of 502 MW.
The Albanian 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 price 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 decline from 6,111 MW to 4,598 MW, while demand slipped slightly to 6,726 MW. The country remained exposed to reduced nuclear availability, with both Cernavoda units absent from the preceding day’s generation mix. The planned return of Cernavoda’s approximately 700 MW Unit 1 was scheduled for 6 November, subject to operating conditions, and could ease Romania’s import requirements.
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 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, above 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, and 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; actual trading returns depend on transmission rights, congestion and contract positions.
Regional spot and forward prices diverge
Day-ahead prices rose to €312.88/MWh in Bulgaria, €304.93/MWh in Croatia, €302.28/MWh in Slovenia and €314.68/MWh in North Macedonia. 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 increased to €307.07/MWh, compared with €257.38/MWh in Germany, leaving a Hungarian 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. 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 over Germany.
Hungarian forward quotations weakened despite higher spot prices. 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 fell 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 also declined, while European carbon allowances remained broadly stable near €90 per tonne. The split 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.
Hourly price exposure, firm cross-border capacity, flexible generation and battery storage were relevant 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 important near-term market factors. The stated market risk included both sustained high average prices and greater variation between countries and hours, which can create procurement costs and trading exposure even as longer-dated electricity prices decline.