South-east European day-ahead electricity prices strengthened across most markets for delivery on 21 July, but the regional average concealed a pronounced divergence between midday solar hours, increasingly expensive evening generation and the availability of cross-border capacity. Hungary, Romania, Bulgaria, Greece, Slovenia and Croatia converged within a relatively narrow €137–142/MWh band, while Serbia remained cheaper, Montenegro moved to a sizeable premium and Albania separated sharply from the surrounding market.
The regional system entered Tuesday with forecast electricity consumption of 33,986 MW, an increase of 983 MW, or almost 3%, from Monday. Net imports rose by 303 MW to 2,112 MW, while gross imports from Austria and Slovakia into Hungary and Slovenia increased slightly to 3,396 MW. The stronger import requirement came despite forecast solar generation rising by 1,428 MW to 8,389 MW. Wind was expected to fall by 212 MW to 1,258 MW, leaving combined solar and wind output approximately 1,216 MW above the previous day.
This combination explains much of the day’s unusual price structure. Additional solar covered the daytime increase in demand and displaced some thermal and hydroelectric generation, but it did little to reduce the system’s dependence on imports and flexible plants after sunset. Regional generation was estimated at 31,873 MW, only 680 MW higher day on day and therefore insufficient to match the 983 MW increase in consumption. The resulting 303 MW gap was met through higher net imports.
HUPX settled at €137.37/MWh, gaining €9.80/MWh from Monday. Romania closed slightly above Hungary at €138.68/MWh, Bulgaria at €138.17/MWh, Slovenia at €141.93/MWh, Croatia at €141.11/MWh and Greece at €142.21/MWh. Austria was almost perfectly aligned with Hungary at €138.31/MWh, leaving a spread of only €0.94/MWh.
The German market remained materially cheaper. EPEX Germany rose to €112.96/MWh, but the Hungarian premium held at €24.41/MWh. That spread remained virtually unchanged despite higher imports from the north-west, indicating that the constraint was not simply one of German generation availability. The value continued to accumulate along the transmission route into central and south-eastern Europe, where evening flexibility and cross-border transfer capability remained scarce.
The regional price profile was more revealing than the baseload settlement. HUPX peakload averaged only €110.10/MWh, compared with off-peak at €164.70/MWh. Prices fell to a minimum of €46.40/MWh in hour 14 before rising to €211.50/MWh in hour 20. The intraday range reached €165.10/MWh.
This inversion of the conventional peak–off-peak relationship is becoming a defining summer feature of the region. The peak product includes the solar-heavy middle of the day, while the off-peak block captures expensive night and late-evening hours. It therefore no longer follows that a peakload hedge provides the most expensive part of the daily profile. For generators, traders and industrial buyers, the increasingly valuable exposure sits in the sunset ramp and evening hours rather than across the conventional daytime block.
Romania displayed a similar pattern. OPCOM settled at €138.68/MWh, with peakload at €113.10/MWh and off-peak at €164.30/MWh. The minimum of €62.90/MWh occurred in hour nine, while the maximum reached €208.70/MWh in hour 20. Bulgaria’s minimum was €63.50/MWh, also in hour nine, before prices climbed to €208.70/MWh in hour 20.
Greece registered one of the largest daily baseload increases, rising €17.30/MWh to €142.21/MWh. Peakload settled at €115.10/MWh, well below off-peak at €169.30/MWh, while the evening maximum reached €216.50/MWh in hour 21. Greece’s forecast demand increased to 8,508 MW, up 280 MW, and the country remained a net importer at 606 MW.
Bulgarian exports provided the principal balancing route into Greece. Bulgaria exported an average 979 MW southward, compared with 787 MW on Monday, including 928 MW during peak hours and 1,030 MW off-peak. Bulgaria simultaneously maintained total net exports of 1,090 MW, supported by generation of 5,199 MW against consumption of 4,109 MW.
Greece continued to export an average 232 MW to Italy even while importing heavily from Bulgaria. This reflects the commercial pull of the much more expensive Italian market rather than a simple national supply deficit. Italy’s national day-ahead price reached €177.30/MWh, leaving it €35.09/MWh above Greece and €39.93/MWh above Hungary. Scheduled SEE exports to Italy remained substantial at approximately 1,200 MW, although they decreased by 130 MW from Monday.
Italy’s price profile also remained structurally different from that of the solar-heavy SEE markets. Its national minimum was still €156.90/MWh, compared with €46.40/MWh in Hungary, €63.50/MWh in Bulgaria and Greece, and €60.10/MWh in Serbia. The Italian market therefore continued to offer a strong destination for Balkan exports across most hours, not only during the evening peak.
Montenegro was the most expensive SEE market outside Italy. BELEN jumped €27.60/MWh to €148.64/MWh, establishing an €11.27/MWh premium to HUPX and a €17.16/MWh premium to Serbia. Its peakload price reached €135.70/MWh, while off-peak traded at €161.60/MWh. The daily minimum was €75/MWh in hour 13 and the maximum €209.10/MWh in hour 21.
Montenegro’s domestic balance remained structurally short. Consumption was forecast at 491 MW, generation at 338 MW and net imports at 153 MW. The country nevertheless scheduled an average 584 MW toward Italy through the undersea interconnector, including 589 MW during peak hours. Those exports were supported by inflows from Bosnia and Herzegovina, Serbia, Albania and Kosovo. The pattern confirms Montenegro’s role as both a deficit market and a transit platform connecting the western Balkans with Italy.
The Italian pull contributed to BELEN’s premium, but the increase also reflected limited domestic flexibility. The latest available generation mix for 20 July consisted of approximately 200 MW of coal, 94 MW of hydro and only 11 MW of wind. A relatively small change in hydro availability, import schedules or interconnector nominations can therefore move the Montenegrin day-ahead price disproportionately.
Serbia moved in the opposite direction. SEEPEX edged up only €0.20/MWh to €131.48/MWh, leaving it €5.90/MWh below Hungary and around €10–11/MWh below Romania, Bulgaria, Greece, Slovenia and Croatia. The flat baseload movement concealed a shift within the daily profile: peakload declined from €116.80/MWh to €109/MWh, while off-peak increased from €145.80/MWh to €154/MWh. The minimum fell to €60.10/MWh in hour 11, but the evening maximum remained elevated at €201/MWh in hour 20.
Serbian consumption increased from 3,452 MW to 3,512 MW, while generation rose from 3,030 MW to 3,121 MW. Net imports consequently declined modestly from 423 MW to 391 MW. Serbia imported an average 270 MW from Bosnia and Herzegovina and 263 MW from Croatia, while exporting 184 MW toward Montenegro. Imports were strongly concentrated in peak hours, when Serbia’s net deficit widened to 672 MW, compared with only 111 MW off-peak.
This imbalance between peak and off-peak flows matters more than the relatively soft SEEPEX baseload price. Serbia’s thermal-heavy generation portfolio covered a large portion of domestic requirements, but the market still relied on imports during high-demand hours. On 20 July, coal contributed approximately 2,455 MW, or 78% of reported generation, while hydro supplied 577 MW and wind 135 MW. Gas-fired output was negligible at 8 MW. The country therefore had little gas-fired flexibility available to respond to the evening ramp, increasing the value of imports and hydro scheduling.
Albania formed the day’s main downside outlier. ALPEX dropped €23.20/MWh to €102.85/MWh, a discount of €34.52/MWh to Hungary and more than €39/MWh to Greece. The Albanian market was almost flat between peakload at €102.90/MWh and off-peak at €102.80/MWh, although individual hours ranged from €36/MWh to €192/MWh.
Albanian generation was forecast at 1,121 MW, close to consumption of 1,149 MW, leaving a small net import requirement of 28 MW. The country nevertheless exported 126 MW toward Montenegro while importing from Greece and Kosovo on a net basis. The low ALPEX settlement therefore appears to reflect local hydro availability, market liquidity and limited ability to export the surplus efficiently rather than a broader decline in regional fundamentals.
The fuel and carbon complex continued to point upward. Austrian CEGH gas advanced €1.30/MWh to €59.62/MWh, while the Greek gas benchmark gained €2.10/MWh to €49.26/MWh. EU carbon allowances increased €4.20/t to €83.27/t. API2 coal forwards rose to $121/t for the average-2026 product and $124/t for the fourth quarter.
At these input levels, coal and gas generators face a firmer marginal-cost floor precisely when regional systems need their flexibility during the evening ramp. Higher carbon prices are particularly relevant for lignite and hard-coal generation in Serbia, Bulgaria, Bosnia and Herzegovina, Greece and the wider central European market. Gas remains expensive enough to limit continuous operation, but those plants retain considerable option value during hours when solar production collapses and import capacity becomes congested.
Hungarian forward power reflected this division between near-term renewable pressure and later supply risk. Week 31 declined €2/MWh to €133.50/MWh, while Week 32 rose €5.50/MWh to €147.50/MWh. The €14/MWh step between the two weekly contracts signals an expected tightening after the immediate solar-heavy period.
Hungarian August traded at €146.50/MWh, September at €161/MWh and the fourth quarter at €164.50/MWh. The curve therefore carried a premium of approximately €27/MWh between the 21 July spot settlement and the fourth-quarter contract. Hungary’s Week 31 premium to Germany narrowed to €18/MWh, below the current spot spread of €24.41/MWh, while the Week 32 spread stood at €20/MWh.
The trading signal is increasingly hour-specific. Strong solar growth is compressing midday prices but no longer guaranteeing a low baseload settlement, because the evening ramp is being repriced against expensive gas, firmer carbon, constrained cross-border capacity and limited flexible generation. Serbia retains a short-term discount, Montenegro remains exposed to Italian pull, and Hungary continues to price the transmission bottleneck between German supply and the south-eastern deficit zone. The most valuable hedge is shifting away from conventional peakload and toward shaped evening products, flexible hydro, storage capacity and secured cross-border nominations.
