Southeast European day-ahead electricity prices surged on Monday, October 19, as the return of weekday demand, weaker renewable generation forecasts and continued reliance on imports tightened the regional power balance. Serbia recorded the highest price in the region, with SEEPEX climbing above €300/MWh, while the premium over western European markets widened.
Serbia’s SEEPEX market settled at €300.22/MWh, rising €46.3/MWh from Sunday. Hungary’s HUPX followed at €292.39/MWh, up €36.4/MWh, while Romania reached €281.07/MWh. Bulgaria settled at €279.48/MWh, Albania at €280.60/MWh, North Macedonia at €277.18/MWh and Montenegro at €276.23/MWh. Croatia and Slovenia recorded €260.47/MWh and €254.49/MWh, respectively. Greece remained the lowest-priced SEE market at €232.43/MWh, despite registering a daily increase of €51.7/MWh.
The broad-based increase shows that the move was not limited to Serbia but represented a regional repricing following the weekend. All major SEE day-ahead markets recorded significant gains, with daily increases ranging from around €36/MWh in Hungary to nearly €58/MWh in Albania.
The main driver was the sharp recovery in weekday electricity demand. Combined Hungary and SEE consumption was forecast at 31,426 MW, almost 3 GW above Sunday levels. At the same time, regional net imports increased by 635 MW to 3,525 MW, indicating that additional domestic generation was not sufficient to fully cover the increase in consumption.
Renewable generation provided less support to the regional balance. Forecast solar output fell by 677 MW to 3,800 MW, while wind generation was expected at 2,412 MW, down 42 MW from Sunday. Imports from core Central European markets reached 3,431 MW, another 132 MW higher than the previous day.
The wider regional balance also pointed to a tightening market. Consumption increased from 28,454 MW on Sunday to 31,426 MW on Monday, while imports rose from 2,889 MW to 3,525 MW. On Sunday, regional generation totalled 25,565 MW, including 3,236 MW of hydro, 6,763 MW of coal, 4,796 MW of gas, 2,455 MW of wind and 4,478 MW of solar generation.
Serbia records the region’s strongest premium
The most significant pricing signal came from Serbia, where SEEPEX reached €300.22/MWh. The market traded €7.83/MWh above Hungary, around €68/MWh above Greece and almost €92/MWh above Germany.
Serbia’s domestic balance improved compared with Sunday, but remained insufficient to remove its dependence on imports. Electricity consumption increased to 3,871 MW from 3,629 MW, while generation recovered to 2,650 MW from 2,180 MW. The country nevertheless remained a substantial net importer, averaging around 1,221 MW.
The hourly price profile was even more important for generators, traders and battery-storage operators. SEEPEX dropped to a daily minimum of €185/MWh around H14 before rising to a maximum of €404/MWh at H19. Peak-load electricity averaged €297.7/MWh, while off-peak prices averaged €302.7/MWh, highlighting that tight market conditions extended beyond traditional peak-demand periods.
The price structure increasingly strengthens the commercial case for flexible generation and battery storage. Relatively softer prices during parts of the day can be followed by sharp evening increases, creating potentially attractive arbitrage opportunities even when the daily average price is already elevated.
Montenegro showed a similar pattern. BELEN increased by €39.6/MWh to €276.23/MWh, while the hourly maximum reached €360/MWh. Its minimum price remained relatively high at €210/MWh, indicating less daytime price compression than in some southern SEE markets.
Greece highlights the value of flexibility
Greece offered one of the clearest examples of the changing intraday economics of the regional electricity market. HENEX averaged €232.43/MWh, almost €60/MWh below Hungary, but hourly prices ranged from only €2.8/MWh to €375.8/MWh.
The minimum occurred during the daytime, when renewable generation was strongest, while the maximum was recorded at H21. Greek peak-load prices averaged €171.6/MWh, compared with €293.2/MWh for off-peak power, illustrating the impact of strong daytime renewable production followed by a steep evening price increase.
This growing volatility is becoming an increasingly important feature of Southeast Europe’s power markets. Average daily prices can hide significant differences between individual hours, particularly in solar-heavy systems where prices can approach zero during periods of high renewable output before rising sharply during the evening ramp.
Albania provided another example of the extreme evening pricing environment, with its hourly maximum reaching €449/MWh, the highest level among the markets covered. Its daily average nevertheless stood at €280.60/MWh.
Wide Germany-Hungary spread signals continued regional constraints
The Hungary-Germany price spread remains one of the most important indicators of the regional market imbalance. German day-ahead electricity settled at €208.44/MWh, compared with €292.39/MWh on HUPX, leaving Hungary with a premium of €83.96/MWh.
The spread widened by €3.2/MWh from Sunday despite more than 3.4 GW of imports from core Central European markets into the Hungary-SEE region. Austria traded at €236.72/MWh and Italy at €262.63/MWh, leaving much of Southeast Europe significantly more expensive than major western and central European markets.
The persistence of these premiums despite strong import flows highlights the limitations of existing cross-border transmission capacity during periods of regional stress. Access to cheaper western European electricity can reduce the imbalance, but it is not sufficient to fully eliminate the scarcity premium during the tightest hours.
Forward markets indicate that traders expect spot prices to moderate, although the regional premium is expected to remain. Hungarian Week 43 power was quoted at €268/MWh, Week 44 at €262.50/MWh and November at €246.50/MWh. The Hungary-Germany forward spread remained particularly wide at €92/MWh for Week 43, €78/MWh for Week 44 and €55/MWh for November.
Fuel markets are also providing limited immediate relief. Austrian CEGH gas was trading at €89.56/MWh, while November gas stood at €89/MWh. EUA carbon allowances were at €85.41/tonne and November coal at €152.5/tonne, keeping the marginal cost of thermal generation elevated.
The October 19 market therefore highlights an increasingly familiar Southeast European power-market structure: stronger weekday demand is driving higher imports and widening regional premiums over Germany, while renewable-heavy markets are experiencing increasingly pronounced intraday price swings.
Serbia’s €300/MWh daily price and €404/MWh evening peak illustrate where immediate scarcity pressures are particularly strong. At the same time, the broader regional trend points toward growing investment value for transmission infrastructure, battery storage and flexible generation, as the gap between low-cost renewable hours and expensive system-balancing periods continues to widen.
