Day-ahead electricity prices in Southeast Europe rose sharply on Friday, with Serbia registering the highest daily baseload average among monitored markets. Wholesale pricing moved towards €280/MWh as weaker wind generation, higher cross-border import requirements and persistent supply constraints affected the region. Serbia’s SEEPEX market increased by €24.8/MWh to €277.57/MWh.
Hungary’s HUPX exchange climbed by €16.4/MWh to €269.23/MWh. Romania reached €261.92/MWh and Bulgaria settled at €256.57/MWh, while Montenegro’s BELEN price rose to €239.78/MWh. The increases extended upward pressure across the Western Balkans.
Price changes across SEEPEX, HUPX and regional exchanges
The regional move higher occurred alongside a forecast decline in electricity consumption of 428 MW to 31,810 MW. Forecast wind generation fell by 1,662 MW to 2,909 MW, while net imports increased by 1,023 MW to 3,385 MW. The gap between lower consumption and higher prices aligned with weaker renewable output and greater import dependence.
Greece recorded the strongest percentage increase in the monitored set, with HENEX rising by €45.6/MWh to €206.18/MWh while remaining the cheapest market monitored. North Macedonia increased by €29.3/MWh to €251.64/MWh, Bulgaria gained €23.3/MWh and Albania added €7.5/MWh to reach €257.08/MWh.
The rally also coincided with continued separation from Western European pricing levels. Germany traded at €210.67/MWh, leaving Hungary at a €58.57/MWh premium despite Germany rising faster during the latest session. Hungary’s premium over Greece narrowed to €63.05/MWh from about €92.3/MWh.
Hourly spikes and peak versus off-peak spreads
Hourly profiles showed scarcity signals that were stronger than daily averages suggested. Serbia’s maximum hourly price reached €405.10/MWh at hour 19, while Hungary peaked at €382.30/MWh in the same hour. Albania approached €400/MWh with a maximum of €399/MWh, while Romania and Bulgaria reached €356.90/MWh and €354.70/MWh respectively.
Daily averages also masked differences between peak and off-peak pricing patterns in some markets. Serbia’s off-peak average was €284.60/MWh compared with a peak-period average of €270.50/MWh, and Hungary showed off-peak power averaging €281/MWh against a peak-period figure of €257.40/MWh. These spreads indicated that the standard peak/off-peak contract split can conceal concentrated hourly price risk.
Greece showed a different intraday shape, with its minimum hourly price falling to zero around midday while its maximum rose to €321.10/MWh . The combination of zero-price solar hours and elevated prices at other times reflected shifting value across different time periods for flexible resources.
Generation balance deterioration and cross-border schedule shifts
The physical drivers behind the price move included a deterioration in the region’s generation balance. Forecast electricity production declined by 1,450 MW to 28,425 MW, with wind losses only partly offset by a 233 MW increase in solar generation .
Cross-border schedules adjusted most noticeably at the Italian borders, according to monitored flows. The region shifted from net exports of approximately 79 MW to Italy on Thursday to net imports of 679 MW on Friday, a swing of 758 MW . Over the same period, combined imports through the Austrian and Slovak corridors increased by only 83 MW to 2,766 MW.
Bulgaria’s electricity balance also changed materially as forecast consumption rose by 628 MW to 4,361 MW while domestic production fell by 248 MW to 4,245 MW . Bulgaria moved from being a net exporter of 760 MW on Thursday to a net importer of 116 MW on Friday.
Romania’s net import requirement increased from 641 MW to 818 MW as domestic generation fell against broadly unchanged demand . Greece remained a major exporter but its surplus contracted from 1,657 MW to 1,176 MW as generation declined . The pattern showed that interconnected markets could see rising prices alongside changing import needs.
Serbia’s import requirement rises as domestic output falls
Serbia’s national electricity balance provided an explanation for its elevated market price . Forecast consumption decreased from 3,969 MW to 3,753 MW while domestic generation fell from 2,942 MW to 2,693 MW . The resulting net import requirement increased slightly to approximately 1,061 MW, equivalent to more than 28% of forecast consumption.
Commercial schedules showed deliveries into Serbia from Bosnia and Herzegovina, Bulgaria, North Macedonia and Montenegro . Bosnia and Herzegovina scheduled an average 435 MW towards Serbia, Bulgaria 304 MW, North Macedonia 317 MW and Montenegro 165 MW . At the same time Serbia maintained average scheduled exports of 406 MW towards Hungary despite its overall import deficit.
The pricing spread reflected differing commercial conditions across borders for market participants . Serbia recorded an €8.34/MWh premium over Hungary and a €37.79/MWh premium over Montenegro . For traders this involved exposure to transmission capacity constraints and nomination risks tied to hourly price differences.
Montenegro balance contrasts with regional trading flows
Montenegro presented a contrasting physical balance relative to Serbia’s situation . Forecast domestic generation was set at 348 MW against consumption of 330 MW, leaving an estimated net export position of about 18 MW . Despite that surplus position, Montenegro remained connected through cross-border commercial schedules.
Montenegro’s commercial schedules included average imports of 268 MW from Italy alongside exports of 165 MW towards Serbia and 72 MW towards Kosovo . BELEN pricing remained lower than several neighbouring markets in the monitored set at €239.78/MWh on Friday . The value of any trading opportunities depended on interconnection rights and delivery-hour spreads.
Forward prices point to sustained near-term tightness
The forward electricity market reinforced expectations for near-term price strength . Hungarian week 43 baseload power was quoted at €269.50/MWh while week 44 stood at €260/MWh and November delivery was priced at €243.50/MWh . The week 43 contract carried a premium of €75.50/MWh over Germany which narrowed to €67/MWh for week 44 and €50.50/MWh for November.
The forward rally accelerated between October 7 and October 15 as Hungary’s week 43 contract gained approximately 28.95%. Comparable gains were reported as 15.82% in Germany and 12.26% in Italy . Longer-dated contracts showed a smaller premium: Hungary’s calendar 2027 baseload contract was quoted at €168.50/MWh versus Germany at €145/MWh.
Fuel costs steady while spot electricity rises
Gas and carbon prices remained components of thermal generation costs but their movements were less pronounced than spot electricity changes . The Austrian CEGH gas indicator stood at approximately €87.21/MWh while November gas futures were quoted at €87.50/MWh after falling by about €1/MWh . European carbon allowances declined approximately €1.30 to reach €85.84 per tonne .
The combination of broadly stable gas quotations, slightly weaker carbon prices and sharply higher electricity spot prices supported an emphasis on short-term availability factors within regional system conditions for Friday’s moves . For thermal generators this environment related directly to revenue versus fuel and carbon input costs depending on plant efficiency and operational availability . For wind and solar operators realised revenues could differ when generation concentrates in lower-priced hours such as Greece’s midday zero-price period.
The immediate outlook remained sensitive to wind forecasts, thermal generation availability, cross-border nominations and temperatures . The forward curve indicated expectations for elevated prices into coming weeks even though the scale of Friday’s spot gains should not be extrapolated automatically . Serbia recorded an hourly maximum of €405/MWh, while net imports returned to more than 3.3 GW.
