Southeast Europe’s day-ahead electricity market entered 7 August 2026 with a striking divergence between lower regional averages and intensifying physical import requirements. Prices fell sharply across most interconnected markets as stronger solar output moderated daytime scarcity, but Serbia moved against the regional direction, with SEEPEX rising to €179.51/MWh and establishing a substantial premium over neighbouring exchanges.
The wider SEE system is forecast to consume an average 35,033 MW, an increase of 311 MW from the previous day. Regional generation reaches only 32,008 MW, leaving a net supply deficit of 3,025 MW. Imports therefore cover approximately 8.6% of aggregate demand, compared with 6.6% a day earlier.
The daily import requirement has increased by 725 MW, or nearly 32%, despite slightly cooler regional temperatures. Gross inflows from Austria and Slovakia towards Hungary and Slovenia rise to 4,065 MW, up 816 MW, while SEE exports 853 MW towards Italy. The market is consequently absorbing more electricity from the north while continuing to supply the higher-priced Italian system.
That configuration explains why the fall in average spot prices should not be interpreted as an easing of the regional capacity balance. The system remains physically short. What changed is the hourly distribution of scarcity, driven principally by a forecast increase in solar production to 8,333 MW, up 1,492 MW day on day. Wind output is expected to fall by 554 MW to 1,924 MW, limiting the benefit from stronger photovoltaic generation outside the central daytime window.
Hungary fell €24.50/MWh to €157.93/MWh, while Romania settled at €158.31/MWh, Slovenia at €158.66/MWh and Croatia at €158.38/MWh. The four markets effectively formed a common price cluster within a range of less than €0.75/MWh. Bulgaria, at €156.47/MWh, and Montenegro, at €158.20/MWh, also traded close to this central regional level.
Austria declined to €152.02/MWh, leaving HUPX at a premium of €5.91/MWh to the Austrian market. Germany moved in the opposite direction, rising €22.60/MWh to €122.08/MWh, but remained €35.85/MWh below Hungary. The narrower Hungary–Germany spread, down from €82.90/MWh a day earlier, reflects both the German price recovery and the easing of the Hungarian day-ahead average.
The continuing €35.85/MWh German discount nevertheless provides a strong commercial incentive for electricity to move east and south. Available transmission capacity, rather than the absence of lower-cost generation in Central Europe, remains the principal constraint on further regional price convergence.
Italy stayed at the top of the broader interconnected market at €184.23/MWh, despite a daily fall of €14.10/MWh. Its premium over Hungary stood at €26.30/MWh, preserving the incentive for regional exports across the Adriatic. Italy’s relatively flat hourly profile is particularly important: its peak average was €180.90/MWh and off-peak average €187.50/MWh, producing a much smaller intraday discount than in solar-heavy markets further east.
The most conspicuous departure from regional convergence came from Serbia. SEEPEX increased €4.10/MWh to €179.51/MWh, placing it €21.59/MWh above Hungary, €21.13/MWh above Croatia, €23.04/MWh above Bulgaria and almost €27/MWh above North Macedonia. Serbia was only €4.72/MWh below the Italian national price.
The Serbian premium is supported by a tightening domestic balance. Consumption is forecast at 4,105 MW, while generation reaches approximately 3,487 MW, leaving the system dependent on average net imports of 619 MW. Imports cover about 15% of Serbian demand, increasing from 564 MW on the previous day.
The imbalance is materially more pronounced during peak hours, when Serbia’s net import requirement rises to 976 MW. That is equivalent to almost 24% of average daily consumption and helps explain why the SEEPEX peak contract rose to €170.90/MWh, considerably above the €141.10/MWh Hungarian peak and €138.30/MWh Bulgarian peak.
Serbia’s hourly minimum was also unusually high at €113.10/MWh, compared with €96/MWh in Hungary, €95.80/MWh in Bulgaria and €62.90/MWh in Albania. Its maximum reached €290/MWh in hour 21, against €245.50/MWh on HUPX and €249.80/MWh in Greece and Bulgaria. The Serbian curve therefore signals both elevated baseload tightness and an additional evening scarcity premium.
Cross-border schedules reinforce that reading. Serbia imports an average 356 MW from Bulgaria and 315 MW from North Macedonia, with peak inflows rising to 400 MW and 419 MW, respectively. Romania supplies Serbia with an average 59 MW, increasing to 197 MW during peak hours. Serbia simultaneously exports around 70 MW to Montenegro, leaving its balance reliant on southeastern and eastern inflows.
Domestic Serbian generation remains dominated by lignite. The latest available production composition shows coal providing approximately 74%, hydropower 22%, gas 2% and wind 2%. Coal output fell to an average 2,426 MW on 6 August, down from 2,838 MW, while wind declined to only 53 MW. Hydropower remained comparatively stable at 722 MW, but was insufficient to offset the reduction in thermal and wind availability.
This creates a particularly exposed evening structure. Solar generation can depress surrounding regional prices during midday, but Serbia has less domestic photovoltaic capacity available to reshape its net-load curve than Hungary, Greece, Bulgaria or Romania. When regional solar production falls after sunset, Serbia must compete for imports while its own wind contribution remains weak and coal units carry most of the residual load.
Hungary presents a different form of exposure. Its forecast consumption declines by 169 MW to 5,229 MW, but generation falls sharply to 2,549 MW, leaving net imports of 2,680 MW. Imported electricity therefore supplies more than 51% of Hungarian demand.
Hungary receives approximately 1,656 MW from Slovakia and 1,255 MW from Austria, while Romania supplies only 48 MW on a baseload basis because the Romanian–Hungarian direction reverses during off-peak hours. The Hungarian system also sends 413 MW towards Croatia, demonstrating its continuing role as both a major importing market and a transit route into the western Balkans.
The Hungarian hourly curve remains strongly inverted. HUPX peak power averages €141.10/MWh, while off-peak power trades at €174.80/MWh. The minimum price of €96/MWh occurs in hour 13, while the maximum of €245.50/MWh appears in hour 21. The resulting €149.50/MWh intraday range illustrates the growing separation between solar-supplied daytime hours and the evening thermal and import-dependent ramp.
Germany shows an even deeper structural inversion, with peak power at €89/MWh and off-peak power at €155.20/MWh. Its minimum reaches €13/MWh in hour 14. That low-cost midday generation is not fully transmitted into Hungary and SEE because cross-border capacity becomes saturated, leaving southeastern consumers exposed to much higher evening prices.
Romania’s balance also deteriorates. Consumption rises to 6,150 MW, while generation stands at 5,395 MW, producing net imports of 755 MW. Romania imports more than 1,000 MW from Bulgaria on average, although it exports during peak hours towards Hungary and Serbia. This suggests that Romania remains short on a full-day basis but can become a marginal regional supplier during selected high-value hours.
Bulgaria continues to provide the strongest conventional export buffer in the eastern Balkans. Generation reaches 5,256 MW against consumption of 4,046 MW, allowing average exports of 1,211 MW. Flows towards Romania reach 1,033 MW, including 1,626 MW during peak hours, while exports to Serbia average 356 MW. Stable nuclear production near 1,886 MW, combined with coal, hydro and solar, gives Bulgaria the region’s most important supply stabilisation role.
Greece is also a net exporter, producing 8,620 MW against demand of 7,469 MW. Its 1,151 MW export surplus is distributed towards Bulgaria, North Macedonia, Albania and Italy. HENEX nevertheless rises €11.30/MWh to €152.94/MWh, reflecting lower wind availability and the increasing role of gas generation. Greek gas-fired production averaged 3,306 MW on the previous day, representing around 36% of the generation mix.
Albania records the region’s lowest price at €144.12/MWh, down €32.80/MWh. Generation of 1,093 MW is almost sufficient to cover consumption of 1,104 MW, leaving a negligible net deficit of 12 MW. Albania receives 169 MW from Greece while exporting 195 MW to Montenegro, effectively operating as a transit market. Its discount of €13.81/MWh to Hungary and €35.39/MWh to Serbia reflects local hydro availability and limited immediate scarcity.
Montenegro settles close to the regional cluster at €158.20/MWh, following the return of TPP Pljevlja after a short outage. Domestic generation rises to 363 MW, but consumption reaches 494 MW, leaving net imports of 130 MW. Montenegro receives average inflows of 115 MW from Bosnia and Herzegovina, 70 MW from Serbia, 195 MW from Albania and 166 MW from Kosovo, while exporting 415 MW towards Italy.
The return of Pljevlja reduces Montenegro’s domestic short position, but the country continues to monetise the higher Italian price through transit and export schedules. Its BELEN peak average of €136/MWh is substantially below the Serbian peak, while the off-peak contract reaches €180.40/MWh, showing a strong evening and overnight dependence similar to the broader regional pattern.
Fuel and carbon markets continue to support elevated forward electricity prices. Austrian CEGH gas rises to €56.36/MWh, while September and fourth-quarter gas trade at approximately €57/MWh. EU carbon allowances increase to €81.82/t, and September coal reaches $115/t. These input costs leave limited room for sustained power-price reductions once solar production fades.
The Hungarian forward curve reflects that risk. Week 33 trades at €174.50/MWh, Week 34 at €161.50/MWh and September at €163.50/MWh. The September contract rose €6.50/MWh in a single session, while Calendar 2026 increased to €122.50/MWh. Forward Hungary–Germany spreads remain wide at €43/MWh for Week 33, €39.50/MWh for Week 34 and €32.50/MWh for September.
Spot relief has therefore not translated into a softer forward risk assessment. Europe’s gas storage was only 57% full on 5 August, the lowest early-August level in fifteen years, while low Danube flows continue to affect nuclear generation and fuel logistics. The Danube reference flow of approximately 4,385 cubic metres per second remains a relevant operational constraint for the region.
Slovenia’s government decision to keep the Krško nuclear plant operating at minimum output until mid-August limits the immediate risk of a full nuclear outage, but the plant’s reduced contribution has already weakened the Slovenian balance. Slovenia imports an average 323 MW, with inflows from Austria reaching 1,154 MW, while it exports 682 MW to Croatia.
The decisive trading feature for 7 August is the simultaneous presence of lower regional day-ahead averages and higher physical import dependence. Solar output suppresses the central daytime hours, but it does not remove the regional energy deficit. The deficit reappears in the evening curve, where Serbia is the clearest scarcity market, Hungary remains structurally dependent on northern imports and Italy continues to pull electricity westward through its persistent premium.
For storage operators, flexible gas units and demand-response providers, the value remains concentrated in the solar-to-evening transition. The Romanian industrial peak-reduction programme reflects the same economics: shifting consumption from the evening peak into daylight hours can capture the widening difference between solar-supplied and residual-load periods. Serbia’s €290/MWh evening maximum, against a daily minimum of €113.10/MWh, provides the strongest regional illustration of that increasingly structural intraday opportunity.
