The Southeast European day-ahead 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%, from Sunday. The change 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 needs to be treated carefully because the preceding session covered a Sunday. Nevertheless, the size of the changes reveals more than a routine weekday recovery. Germany remained heavily affected by midday renewable output, while Serbia and parts of the central and southern Balkans faced materially firmer residual-load conditions. The result was wider cross-border price dispersion even as Hungary, Romania, Bulgaria, Croatia and Slovenia remained relatively closely aligned.
Serbia becomes the regional premium market
Serbia’s SEEPEX base price almost doubled from Sunday, rising by €56.9/MWh to €114.43/MWh. This was the highest price among the covered Balkan and Central European exchanges outside Italy and placed 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 curve was also structurally different from those in 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. Its maximum reached €187.40/MWh in hour 22, reflecting a tight evening ramp once 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 reflects the low midday prices included in the standard peak block, but Serbia’s trough remained much shallower than elsewhere. This indicates that domestic scarcity 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 at only 2,871 MW. The resulting net-import requirement was 600 MW, compared with 627 MW on Sunday. Serbia was scheduled to import 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 whole region.
Hungary, Romania and the northern Balkans remain closely coupled
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 SEE corridor remained effectively coupled at the base-price 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 a €8.73/MWh premium to Bulgaria. Strong scheduled Bulgarian exports towards Greece, averaging 775 MW, helped bridge this 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 base price was accompanied by a much more volatile hourly profile. Its minimum fell to €2.90/MWh, while the maximum reached €200/MWh. The combination suggests a relatively shallow market in which hydrological availability, limited domestic demand and border schedules can produce large hourly movements without delivering 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.
German solar output reshapes the Hungary spread
Germany fell by €13.1/MWh to €77.09/MWh, opening a €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 at €124.50/MWh.
The widening Germany–Hungary spread was accompanied by a strong increase in imports from Austria and Slovakia into Hungary and the wider SEE region. CORE imports were forecast at 2,813 MW, up 2,097 MW day on day. This flow was essential to cover the Monday load recovery, but it was insufficient to produce full price convergence farther south, particularly in Serbia.
Wind collapse leaves gas to stabilise the Sunday system
The latest complete generation data, covering Sunday, show total regional output falling to 26,275 MW, down 1,354 MW from Saturday. The most important change was wind production, which declined by 1,742 MW, or approximately 56%, 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 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 fall in hydro is becoming increasingly important for Serbia and the inland Balkan markets. Serbian hydropower averaged 586 MW on Sunday, below 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. The reported Danube flow 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 to 2,042 MW. Those renewable gains were not enough to match the 4,777 MW increase in consumption. The remaining 1,646 MW system deficit had to be supplied 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.
Forward curve retains 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: Hungary traded at €175.50/MWh, Germany at €144.50/MWh and Italy at €181/MWh.
The jump from €143/MWh for Week 31 to €175.50/MWh for Week 32 indicates 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, implying expectations 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 high 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’s exceptionally high minimum price, continued import dependence and limited access to cheaper Bulgarian supply leave SEEPEX particularly exposed to any further deterioration in hydro or wind conditions.
