The Southeast European day-ahead electricity market entered Monday, 27 July 2026, with a pronounced return-of-week demand effect, sharply higher Serbian prices and renewed dependence on imports from the CORE region. Regional consumption was forecast at 30,522 MW, an increase of 4,777 MW, or 18.6 per cent, from Sunday. The shift coincided with a 2,176 MW reversal in the regional power balance, from net exports of 530 MW to net imports of 1,646 MW.
The Monday comparison should be treated with some caution because the preceding session covered a Sunday. Nevertheless, the scale of the changes pointed to more than a routine weekday recovery. Germany remained heavily affected by midday renewable generation, while Serbia and parts of the central and southern Balkans faced materially tighter residual-load conditions. The result was wider cross-border price dispersion, even as Hungary, Romania, Bulgaria, Croatia and Slovenia remained relatively closely aligned.
Serbia emerged as the regional premium market. SEEPEX’s baseload price almost doubled from Sunday, rising by €56.9/MWh to €114.43/MWh. This was the highest price among the monitored Balkan and Central European exchanges outside Italy, placing Serbia at a premium of €18.85/MWh to Hungary, €19.40/MWh to Romania, €21.40/MWh to Bulgaria and €17.38/MWh to Croatia.
The Serbian price curve was also structurally different from those of the more strongly coupled Hungarian-Romanian-Croatian corridor. SEEPEX recorded a minimum hourly price of €70/MWh, compared with approximately €10/MWh in Hungary, Romania, Bulgaria, Greece and Croatia. Serbia therefore avoided the deep solar-driven midday trough visible across neighbouring markets, while its maximum reached €187.40/MWh in hour 22 as the evening ramp tightened after solar production disappeared.
Serbian peak power averaged €104.50/MWh, while off-peak power was even higher at €124.30/MWh. The inverted relationship partly reflected the low midday prices included in the standard peak block, but the Serbian trough remained significantly shallower than elsewhere. The pattern indicated that domestic supply tightness and restricted cross-border access outweighed the regional solar surplus during the central hours.
Serbia was forecast to consume 3,471 MW, up 408 MW from Sunday, while generation was expected to reach only 2,871 MW. The resulting net-import requirement stood at 600 MW, compared with 627 MW on Sunday. Serbia was scheduled to import electricity from Croatia, North Macedonia, Bosnia and Herzegovina, Hungary and Romania while continuing to export approximately 147 MW to Montenegro.
The market separation was reinforced by the absence of scheduled commercial flows on the Bulgaria-Serbia border. Bulgaria cleared at only €93.03/MWh, yet no direct commercial flow was recorded between the two markets. Imports from Hungary averaged only 106 MW despite Hungary trading almost €19/MWh below Serbia. The price difference therefore reflected a combination of local supply tightness, limited exchange liquidity and border-allocation constraints, rather than a shortage across the entire region.
Hungary cleared at €95.58/MWh, only €3.6/MWh above Sunday. Romania was virtually identical at €95.48/MWh, while Croatia reached €97.05/MWh and Slovenia €98.17/MWh. The narrow €2.69/MWh range between Hungary and Slovenia showed that the northern Southeast European corridor remained effectively coupled at the baseload level.
Bulgaria was slightly cheaper at €93.03/MWh, a discount of €2.55/MWh to Hungary. Greece cleared at €101.76/MWh, establishing a €6.18/MWh premium to HUPX and an €8.73/MWh premium to Bulgaria. Strong scheduled Bulgarian exports towards Greece, averaging 775 MW, helped bridge the difference but did not eliminate it.
Montenegro rose by €23.3/MWh to €103.11/MWh, while North Macedonia gained €25.9/MWh to €97.69/MWh. Albania moved in the opposite direction, falling €8.9/MWh to €73.80/MWh, the lowest Balkan price. This created a discount of €21.78/MWh to Hungary and almost €41/MWh to Serbia.
Albania’s low baseload price was accompanied by a considerably more volatile hourly profile. Its minimum fell to €2.90/MWh, while the maximum reached €200/MWh. The combination pointed to a relatively shallow market in which hydrological availability, limited domestic demand and border schedules can produce large hourly movements without generating stable convergence with neighbouring exchanges.
Italy remained the dominant high-price destination. The national Italian price reached €185.06/MWh, while the northern zone cleared at approximately €183.40/MWh. The region was scheduled to export an average of 1,197 MW towards Italy, including almost 599 MW over the Montenegro-Italy interconnector. Italy’s premium of almost €90/MWh to Hungary continued to pull available western Balkan and Slovenian supply westward, reducing the energy available to relieve local Serbian and central Balkan tightness.
Germany fell by €13.1/MWh to €77.09/MWh, opening an €18.49/MWh discount to Hungary. German peak power averaged only €39.90/MWh, compared with off-peak power at €114.30/MWh. The minimum hourly price was slightly negative at minus €0.70/MWh, while the evening maximum recovered to €179/MWh.
Hungary followed a similar curve but with less severe midday compression. HUPX recorded a minimum of €10.50/MWh in hour 13 and a maximum of €179.30/MWh in hour 22. Peak power averaged €66.70/MWh, against off-peak power at €124.50/MWh.
The widening Germany-Hungary spread coincided with a strong increase in imports from Austria and Slovakia into Hungary and the wider Southeast European region. CORE imports were forecast at 2,813 MW, up 2,097 MW day on day. These flows were essential to cover the Monday demand recovery but were insufficient to produce full price convergence farther south, particularly in Serbia.
The latest complete generation data, covering Sunday, showed total regional output falling to 26,275 MW, down 1,354 MW from Saturday. The most significant change was wind production, which declined by 1,742 MW, or approximately 56 per cent, to only 1,396 MW.
Gas-fired generation increased by 315 MW to 3,767 MW, partly compensating for the loss of wind. Solar production rose by 589 MW to 5,684 MW, while nuclear generation remained stable at 5,604 MW. Coal output eased marginally to 5,570 MW, and hydropower fell by 268 MW to 3,854 MW.
The decline in hydroelectric generation is becoming increasingly important for Serbia and the inland Balkan markets. Serbian hydropower averaged 586 MW on Sunday, down from 638 MW on Saturday, while coal generation declined to 2,008 MW. Total Serbian generation consequently fell to 2,437 MW, leaving the country dependent on imports for roughly one-fifth of demand. Reported Danube flows of approximately 4,786 cubic metres per second remained weak enough to constrain hydro flexibility during higher-value hours.
For Monday, regional generation was forecast to recover to 28,876 MW, while solar output was expected to rise to 7,734 MW and wind generation to 2,042 MW. These renewable gains were not sufficient to match the 4,777 MW increase in consumption, leaving a 1,646 MW system deficit to be covered through net imports.
The largest individual demand increases were forecast in Romania, up 1,170 MW to 5,375 MW, Greece, up 1,049 MW to 6,658 MW, Hungary, up 690 MW to 4,364 MW, and Bulgaria, up 671 MW to 3,727 MW. Greece shifted from a Sunday export position of 148 MW to imports of 385 MW, while Hungary’s deficit expanded from 235 MW to 1,101 MW.
Bulgaria remained the region’s principal exporter at 1,322 MW, supported by nuclear generation and stronger forecast solar output. Romania was expected to export 251 MW, while Bosnia and Herzegovina retained an export balance of 227 MW. Croatia’s import requirement widened to 1,050 MW, reflecting forecast generation of only 1,100 MW against demand of 2,150 MW.
The forward market retained a strong weather and scarcity premium. The Hungarian Week 31 contract stood at €143/MWh, carrying a €15/MWh premium to Germany’s equivalent contract at €128/MWh. Italy remained substantially higher at €179/MWh. Week 32 showed a steeper Hungarian risk premium, with Hungary trading at €175.50/MWh, Germany at €144.50/MWh and Italy at €181/MWh.
The increase from €143/MWh for Week 31 to €175.50/MWh for Week 32 indicated that the forward market was pricing a material increase in residual-load and weather risk. Hungary’s Week 32 premium to Germany widened to €31/MWh, more than double the Week 31 spread. Italy’s premium to Hungary, by contrast, narrowed from €36/MWh to only €5.50/MWh, suggesting that Central and Southeast European tightness could approach Italian levels.
Fuel and carbon markets continued to provide a firm thermal floor. Austrian CEGH gas was assessed at €64.46/MWh, the Greek gas reference at €45/MWh and EU allowances at €83.40/tCO₂. Gas forwards stood near €64.50/MWh for the 2026 average and €65/MWh for the fourth quarter, while coal was indicated at $121/t for the annual average and $126/t for the fourth quarter.
At these input levels, gas-fired generation remains expensive enough to support elevated evening power prices whenever solar output falls and wind availability disappoints. The decisive trading feature for the next sessions is therefore the contrast between very weak German and regional midday prices and a much tighter evening ramp.
Serbia remains particularly exposed to any further deterioration in hydrological or wind conditions. Its exceptionally high minimum price, continued dependence on imports and limited access to cheaper Bulgarian supply leave SEEPEX more vulnerable than the better-coupled northern markets to local supply tightness. The 27 July session therefore highlighted a widening structural divide within the region: cheap renewable-driven midday electricity in the north and a much tighter, import-dependent evening market in Serbia and parts of the central Balkans.