Southeast European day-ahead electricity prices rose sharply on Friday, with Serbia emerging as the region’s most expensive market as weaker wind generation, higher cross-border import requirements and persistent supply constraints pushed wholesale prices towards €280/MWh.
Serbia’s SEEPEX market increased by €24.8/MWh to €277.57/MWh, recording the highest daily baseload average among the monitored markets. Hungary’s HUPX exchange rose €16.4/MWh to €269.23/MWh, while Romania reached €261.92/MWh and Bulgaria €256.57/MWh. Montenegro’s BELEN market climbed to €239.78/MWh, extending the upward pressure across the Western Balkans.
The price rally came despite a forecast 428 MW decline in regional electricity consumption to 31,810 MW. At the same time, 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 combination of lower demand and higher prices indicates that renewable availability, import dependence and cross-border market conditions were more important short-term drivers than consumption growth.
Greece recorded the strongest percentage increase, with HENEX rising €45.6/MWh to €206.18/MWh, although it remained the cheapest monitored market. North Macedonia climbed €29.3/MWh to €251.64/MWh, Bulgaria gained €23.3/MWh, while Albania increased €7.5/MWh to €257.08/MWh.
The regional rally also highlighted continued price separation from Western Europe. Germany traded at €210.67/MWh, leaving Hungary with a €58.57/MWh premium despite the German market recording a faster increase during the latest session. Hungary’s premium over Greece narrowed to €63.05/MWh from approximately €92.3/MWh, reflecting the particularly strong recovery in Greek prices.
Hourly price data revealed an even stronger scarcity signal than the daily averages suggested. Serbia’s maximum hourly price reached €405.10/MWh at hour 19, while Hungary peaked at €382.30/MWh during the same hour. Albania approached €400/MWh, recording a maximum of €399/MWh, while Romania and Bulgaria reached €356.90/MWh and €354.70/MWh respectively.
The daily averages also masked significant differences in intraday price patterns. Serbia’s off-peak average stood at €284.60/MWh, above its €270.50/MWh peak-period average. Hungary showed a similar pattern, with off-peak prices averaging €281/MWh compared with €257.40/MWh during peak hours. This demonstrates how traditional peak and off-peak classifications can obscure concentrated hourly price risks.
Greece displayed a markedly different intraday profile. Its minimum hourly price fell to zero around midday, while its maximum reached €321.10/MWh. The combination of zero-price solar hours and much higher prices at other times underlines the growing commercial importance of flexible generation, battery storage and demand-side management.
The region’s physical electricity balance also deteriorated significantly. Forecast electricity production declined by 1,450 MW to 28,425 MW, with the reduction in wind output only partly offset by a 233 MW increase in solar generation.
Cross-border schedules showed a particularly notable adjustment on the Italian borders. The monitored region shifted from net exports of approximately 79 MW to Italy on Thursday to net imports of 679 MW on Friday, representing a swing of 758 MW. Meanwhile, combined imports through the Austrian and Slovak corridors increased by only 83 MW to 2,766 MW.
This suggests that much of the additional regional import requirement was covered by a change in the direction and volume of Italian border flows, rather than by a major increase in supplies from Central Europe.
Bulgaria recorded one of the most significant changes in its electricity balance. Forecast consumption increased by 628 MW to 4,361 MW, while domestic generation fell by 248 MW to 4,245 MW. As a result, the country shifted from 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, reflecting lower domestic generation against broadly stable demand. Greece remained a major regional electricity exporter, although its surplus narrowed from 1,657 MW to 1,176 MW as generation declined.
The trading pattern demonstrates how interconnected electricity markets can experience higher prices and rising import requirements at the same time. A shortage in one market can increase demand for cross-border electricity even when neighbouring countries still maintain a production surplus.
Serbia’s national electricity balance provides one of the clearest explanations for its elevated market price. Forecast consumption declined from 3,969 MW to 3,753 MW, but domestic generation fell more sharply, 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 substantial 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 substantial overall import deficit. This highlights the complexity of regional electricity trading, where scheduled cross-border flows reflect contractual obligations and transmission arrangements rather than simply the difference between national daily-average spot prices.
Serbia’s €8.34/MWh premium over Hungary and €37.79/MWh premium over Montenegro demonstrate the differing commercial conditions facing generators, suppliers and large industrial consumers.
For traders, these price differences can create opportunities but also expose market participants to transmission capacity constraints, nomination risks and differences between hourly electricity prices. For Serbian industrial consumers, the main concern remains the cost of securing reliable electricity when domestic generation is insufficient to fully cover demand.
Montenegro presented a contrasting physical balance. Domestic generation was forecast at 348 MW, slightly above consumption of 330 MW, leaving the country with a net export position of approximately 18 MW.
Despite this, Montenegro remained closely integrated into regional trading flows. Commercial schedules included average imports of 268 MW from Italy, alongside exports of 165 MW towards Serbia and 72 MW towards Kosovo.
Montenegro’s relatively lower BELEN price could support trading opportunities towards higher-priced neighbouring markets, although the actual commercial value depends on available interconnection capacity, delivery-hour spreads and transaction costs.
Forward electricity markets also reinforced expectations of continued near-term price pressure. Hungarian week 43 baseload power was quoted at €269.50/MWh, while week 44 stood at €260/MWh and November delivery at €243.50/MWh.
The Hungarian week 43 contract carried a €75.50/MWh premium over Germany, narrowing to €67/MWh for week 44 and €50.50/MWh for November. These spreads indicate that traders continue to price a substantial regional premium into Hungarian electricity during the coming weeks.
The recent forward rally was particularly strong. Between October 7 and 15, Hungary’s week 43 contract gained approximately 28.95%, compared with 15.82% in Germany and 12.26% in Italy.
Longer-dated contracts pointed to a more moderate premium. Hungary’s calendar 2027 baseload contract stood at €168.50/MWh, compared with €145/MWh in Germany. The €23.50/MWh difference was significantly smaller than the nearby weekly spread, suggesting that the market is pricing the strongest scarcity risks into the immediate delivery period rather than uniformly across future years.
Gas and carbon prices remained important components of thermal generation costs, although their latest movements were less pronounced than those seen in spot electricity markets. The Austrian CEGH gas indicator stood at approximately €87.21/MWh, while November gas futures were quoted at €87.50/MWh, down €1/MWh. European carbon allowances declined by approximately €1.30 to €85.84 per tonne.
The combination of relatively stable gas prices, slightly weaker carbon costs and sharply higher electricity spot prices strengthens the view that short-term generation availability and regional system conditions were the main drivers of Friday’s market rally.
For thermal generators, this environment can improve electricity sales revenues relative to fuel and carbon input costs, although actual profitability still depends on plant efficiency, operational availability and generation timing.
For wind and solar operators, the picture is more complex. High regional baseload prices do not necessarily translate into equally strong realised revenues when renewable generation is concentrated in lower-priced hours. Greece’s zero-price midday conditions provided a clear example of this challenge.
For battery storage developers and flexible generators, the large difference between low-priced midday periods and expensive morning or evening hours points to potentially stronger revenue opportunities. However, investment decisions require a detailed assessment of hourly spreads, cycling costs, battery degradation, grid access and balancing-market revenues, rather than relying on a single high-price session.
The immediate market outlook remains highly sensitive to wind forecasts, thermal generation availability, cross-border nominations and temperatures. Forward contracts indicate that traders expect elevated electricity prices to persist into the coming weeks, although the scale of Friday’s spot-price increase should not automatically be extrapolated.
Serbia’s €405/MWh hourly maximum and the region’s return to more than 3.3 GW of net electricity imports illustrate the central challenge facing Southeast European electricity markets: demand can decline while prices still rise sharply when weather-dependent generation weakens and the region becomes more reliant on electricity imports from neighbouring markets.
