Day-ahead electricity prices fell across most of Southeast Europe and Hungary on Wednesday, led by a sharp drop in Serbia, while Italy remained near €225/MWh, widening regional spreads despite broadly unchanged power demand.
Serbia’s SEEPEX baseload price dropped by €69/MWh, or almost 39%, to €109.33/MWh, the lowest among the monitored markets. Hungary fell €15.90 to €160.65/MWh, while Romania declined to €162.70, Croatia to €162.74 and Slovenia to €167.29. Bulgaria settled at €153.31/MWh and Greece at €140.54/MWh.
The southern Balkan markets also weakened, with Albania dropping €32.10 to €150.20/MWh, Montenegro falling €21.10 to €171.27 and North Macedonia easing to €153.63. Serbia consequently traded at a €51.32/MWh discount to HUPX, while Montenegro retained a €10.62/MWh premium over Hungary. Italy was about €64/MWh above HUPX, preserving a strong westward price gradient.
The most striking feature was not only Serbia’s lower daily average but the shape of its hourly curve. SEEPEX fell to just €5/MWh around hour 11 before climbing to €246/MWh in the evening. Serbia’s peak-period average of €102.10/MWh was below its €116.50/MWh off-peak average, an increasingly important inversion as daytime renewable output compresses conventional peak pricing.
Similar price compression was visible elsewhere. Greece’s peak average was €89.40/MWh compared with €191.60/MWh off peak, while Hungary recorded €123.80/MWh for peak hours against €197.50/MWh off peak. The regional forecast showed solar generation rising to around 7.52 GW, up about 1.67 GW from the previous day, while wind was broadly unchanged at 2.09 GW.
The price decline came without a material fall in overall demand. Combined Hungary and Southeast European consumption was forecast at 31.62 GW, effectively unchanged from the previous day. Net regional imports, however, fell to around 479 MW from 970 MW, while inflows from the Austria-Slovakia core declined to 1.59 GW from 1.96 GW.
Serbia’s unusually deep discount developed even though the country remained a net importer. Average Serbian consumption rose marginally to 3.55 GW, while generation increased to 3.01 GW from 2.81 GW, cutting the net import requirement to about 540 MW from 730 MW a day earlier. The combination of higher domestic availability and accessible imports appears to have loosened the Serbian balance sufficiently to produce a much deeper spot correction than in neighbouring markets.
The Serbian market nevertheless remained connected to substantial surrounding flows, importing on a baseload basis from Bulgaria, North Macedonia and Romania while exporting toward Montenegro and, during some periods, Hungary. The resulting price discount despite net imports points to short-term congestion, bidding patterns and hourly supply conditions rather than a simple regional surplus.
Bulgaria remained one of the strongest supply centres, with average exports of about 1.72 GW against domestic consumption of 3.88 GW and generation of 5.60 GW. At the wider regional level, roughly 1.48 GW continued to flow toward Italy, where substantially higher prices maintained the economic incentive for westbound exports.
The spot correction was not matched by a broad decline in the forward complex. Hungarian week-38 power slipped €1 to €180/MWh, but week 39 rose €4.50 to €192.50/MWh. October power eased to €187/MWh, while the calendar contract increased to €146.50/MWh. Austrian CEGH gas rose €2.30 to €77.38/MWh and EU carbon allowances gained €0.70 to €85.42 a tonne.
Wednesday’s trading therefore points more to short-term spot fragmentation than a broad bearish repricing of Southeast European power. Serbia has moved to an exceptional discount, while the Italian premium remains intact and the Hungarian forward curve continues to price substantially higher power later in September.
For traders, the widening gap between low midday prices and expensive evening hours is becoming as important as the traditional country-to-country spread. The €5-to-€246/MWh Serbian intraday range, combined with Italy near €225/MWh, highlights a market increasingly driven by hourly renewable availability, cross-border capacity and the ability to shift electricity between periods and bidding zones.