Regional net electricity imports rose 27.4% to 5,354 MW for Thursday delivery on 5 November 2026, lifting day-ahead prices across Southeastern Europe as wind generation weakened, colder weather and higher consumption increased the region’s need for imports. Regional day-ahead market data showed imports covered 15.2% of consumption, up from approximately 12.1% in one trading session. The increase of 1,150 MW from Wednesday’s 4,204 MW was the highest regional import level in seven days.
Forecast consumption climbed by 353 MW to 35,135 MW, while projected domestic generation fell by 797 MW, from 30,578 MW to 29,781 MW. Forecast wind generation dropped by 1,110 MW to 4,013 MW, from 5,123 MW the previous day, and solar output fell by 38 MW to 3,051 MW. Prices rose in all major Southeastern European markets, with the strongest gains in Albania, Romania, Serbia and Montenegro.
The spot-market increases contrasted with softer forward electricity and gas quotations. The session’s prices reflected immediate generation availability and cross-border supply conditions more than longer-term energy costs, while December gas forwards declined and European carbon allowances remained broadly stable near €90 per tonne.
Import needs 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 over Hungary widened to €68.63/MWh, and its hourly price reached €700/MWh during hour 23. Forecast consumption of 965 MW exceeded projected generation of 463 MW, leaving 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 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 total regional net import increase 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.
Romania remained exposed to reduced nuclear availability, 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 requirement.
Serbia and Montenegro face import exposure
Serbia’s SEEPEX day-ahead price increased by €25.2/MWh to €317.64/MWh, €10.57/MWh above Hungary’s and approximately €60/MWh above Germany’s. Forecast Serbian 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.
Although Serbia’s net import requirement was marginally lower than the previous day, import dependence remained substantial. SEEPEX’s hourly price reached €422.6/MWh during hour 18, when 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, 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 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. The difference illustrated the commercial importance of the Adriatic interconnection, although actual trading returns depend on transmission rights, congestion and contract positions.
Spot gains contrast with falling forward quotations
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 against €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 premium over Germany.
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.
The divergence between rising spot prices and falling Hungarian forward quotations pointed to short-term generation availability, weather variability and transmission constraints shaping the session, rather than a uniform rise in electricity supply costs. Hourly price exposure, firm cross-border capacity, flexible generation and battery storage remained considerations for electricity traders, industrial consumers and renewable generators. Serbia and Montenegro remained particularly sensitive to import requirements and evening peaks, while Romania’s nuclear availability and regional wind production were near-term market factors. Larger differences between countries and hours also exposed market participants to procurement costs and trading risks even as longer-dated electricity prices declined.
