Southeast European day-ahead electricity prices surged on October 29, with most regional markets trading above €300/MWh as stronger demand, declining wind generation and elevated fuel costs tightened supply ahead of the evening peak. The rally highlights growing pressure on the region’s electricity systems as renewable output shifts throughout the day and demand increasingly relies on conventional generation and cross-border imports.
Serbia’s SEEPEX price increased by €37.4/MWh to €330.04/MWh, moving above Hungary and most neighbouring markets. Montenegro recorded an even larger increase of €46.4/MWh to €312.80/MWh, while North Macedonia rose by €41.1/MWh to €325.80/MWh. Albania registered the region’s highest daily average at €366.85/MWh, up €64.8/MWh. Romania settled at €323.76/MWh, while Bulgaria reached €320.13/MWh.
Although the increase was widespread, hourly market data suggests that the rally was driven primarily by evening supply tightness rather than a uniform increase throughout the day. The concentration of high prices around the evening peak reflects the challenge of balancing electricity demand as solar generation declines and wind output weakens.
On SEEPEX, Serbian peak-load electricity averaged €369.7/MWh, while the maximum hourly price reached €500/MWh at H18. Even the session’s minimum remained relatively high at €205/MWh, indicating that buyers had limited access to genuinely inexpensive electricity during the trading day.
Montenegro experienced a particularly pronounced evening price increase. The BELEN base price climbed to €312.80/MWh, with peak-load electricity averaging €347.4/MWh. The maximum hourly price reached €555.1/MWh at H18, compared with €400/MWh in the previous session. The increase illustrates how quickly costs can escalate when demand remains strong as available generation becomes more constrained.
Albania recorded the most expensive daily average in the region. ALPEX reached €366.9/MWh, while peak-load prices averaged €392.2/MWh and the hourly maximum surged to €600/MWh at H18. The simultaneous evening peaks in Serbia, Montenegro and Albania point to a shared regional challenge: electricity supply becomes significantly tighter as solar generation fades while consumption remains elevated.
Regional electricity consumption was forecast to average 34,054 MW, an increase of 740 MW compared with the previous day. Net imports rose by 196 MW to 3,886 MW. Although solar generation was expected to increase by 360 MW, wind output was forecast to decline by 436 MW, reducing one of the main sources of renewable supply during the later hours of the day.
This generation mix helps explain why stronger solar production failed to prevent the daily price increase. Additional photovoltaic output primarily supports supply during daylight hours, when market conditions may be less restrictive. Lower wind generation, however, can leave the system more exposed as solar production declines and evening demand remains high. The timing of renewable generation is becoming just as important as its total volume in determining wholesale electricity prices.
Greece remained the clearest exception to the broader regional price rally. The HENEX day-ahead market averaged €238.80/MWh, placing Greek electricity almost €86/MWh below Hungary and more than €91/MWh below Serbia. Prices fell to just €32.3/MWh around H10 before rising sharply to an evening maximum of €450/MWh at H18.
The Greek price profile illustrates the increasingly pronounced dynamics of a solar-intensive electricity market. Strong midday solar generation can push prices sharply lower, while the withdrawal of that supply in the evening triggers rapid repricing. As a result, Greece maintained a substantial daily price discount despite experiencing the same broad evening tightening affecting neighbouring markets.
Central European prices moved closer to Southeast European levels during the session. Hungary’s HUPX price increased by €21.2/MWh to €324.58/MWh, while Germany recorded a much larger rise of €65.6/MWh to €314.85/MWh. The spread between Hungary and Germany narrowed to just €9.73/MWh, a reduction of approximately €44/MWh in a single session.
Evening price spikes were also evident in both markets. Germany’s hourly maximum reached €559.6/MWh, while Hungary peaked at €526.8/MWh, with both maxima occurring around the evening ramp. The movement sharply reduced the Hungarian premium over Germany that had characterised previous sessions, signalling a closer alignment between central European and Balkan wholesale electricity conditions.
Romania and Bulgaria traded close to Hungary, with prices respectively €0.82/MWh and €4.45/MWh below HUPX. Serbia, by contrast, maintained a €5.46/MWh premium over Hungary, suggesting that supply and demand conditions in Serbia and the western Balkans remained marginally tighter even as central European prices increased.
Italy provided a comparatively lower-priced source of electricity for the wider region. The Italian national day-ahead price reached €278.47/MWh, approximately €46/MWh below Hungary and more than €34/MWh below Montenegro. Net electricity entering the wider Southeast European balance from Italy increased by 147 MW to around 593 MW, consistent with the economic incentive to move electricity from a lower-priced market towards neighbouring systems facing higher prices, subject to available transmission capacity and market arrangements.
Forward-market movements suggest that traders were not viewing the day-ahead rally as an isolated event. Hungarian Week 45 power increased by €8.5/MWh to €315.50/MWh, while Week 46 rose by €7.5/MWh to €304.50/MWh. The November contract gained €13/MWh to €295.50/MWh, indicating continued upward pressure on near-term wholesale electricity expectations.
The increase coincided with higher fuel and carbon prices. CEGH gas rose by €4.8/MWh to €102.05/MWh, EU carbon allowances climbed to €89.1/t, and November coal advanced to €147.5/t. Higher fuel and emissions costs can increase the marginal cost of thermal generation, reinforcing upward pressure on electricity prices when renewable output is insufficient to meet demand.
The resulting regional market structure is becoming increasingly differentiated. Greece remains a lower-priced market during strong solar hours, while Italy offers a comparatively cheaper western supply source. Hungary, Romania, Bulgaria, Serbia and North Macedonia have converged around €320–330/MWh, whereas Albania can move substantially above neighbouring markets when its domestic supply-demand balance tightens.
For Serbia and Montenegro, the most important signal is the growing difference between midday and evening electricity prices. The region is not necessarily short of electricity throughout the day, but available generation may not be located in the right market or accessible through the right interconnector at the hour when demand is highest. Transmission constraints, changing renewable output and differences in national supply balances can all influence the final price paid by buyers.
This growing mismatch between the timing and location of electricity supply and demand is becoming a defining feature of Southeast European power trading. For utilities, traders and large industrial consumers, managing exposure to peak-hour prices will increasingly depend on procurement strategies, cross-border access, flexible generation and storage, rather than on average daily prices alone.
