The 23 July 2026 day-ahead session produced a pronounced split between Hungary and the northern interconnected markets on one side and the eastern and southern Balkans on the other. HUPX rose by €7.80/MWh to €130.13/MWh, while stronger renewable forecasts, cooler weather and declining consumption pushed prices lower across Romania, Bulgaria, Greece, Serbia, Montenegro and North Macedonia.
The divergence was not caused by a region-wide shortage of electricity. Forecast net imports into Hungary and Southeast Europe fell from 1,715 MW to only 438 MW, while regional consumption declined by 620 MW to 32,096 MW. Solar output was forecast to increase by 1,671 MW to 8,085 MW, with wind rising by another 488 MW to 3,123 MW. These additions more than compensated for the reduction in demand, but their geographical concentration produced very different price outcomes across interconnected bidding zones.
Hungary remained the principal high-price market east of Austria. At €130.13/MWh, HUPX traded €12.48/MWh above Germany, €10.95/MWh above Romania, €18.41/MWh above Bulgaria and Greece, and €44.19/MWh above Serbia. Austria was still more expensive at €138.21/MWh, leaving Hungary at an €8.07/MWh discount, while Italy retained the largest regional premium at €181.08/MWh, or €50.95/MWh above HUPX.
The Hungarian increase was concentrated outside the conventional daytime peak block. HUPX peakload averaged only €99.00/MWh, compared with an off-peak average of €161.30/MWh. The market reached its minimum of €40.50/MWh in hour 11, before climbing to €190.00/MWh in hour 22. The resulting €149.50/MWh intraday high-low range illustrates the growing separation between solar-saturated midday hours and the evening residual-load period.
Germany showed the same pattern, with its day-ahead base price rising by €17.20/MWh to €117.65/MWh, even though peakload averaged just €78.20/MWh. German off-peak power cleared at €157.10/MWh, and the daily maximum also reached €190.00/MWh in hour 22. The synchronized evening cap in Germany, Austria, Hungary, Romania, Bulgaria, Greece, Slovenia and Croatia indicates a highly coupled scarcity signal once solar production falls, even though the midday markets remain fragmented by local renewable availability and border constraints.
Romania moved in the opposite direction to Hungary. OPCOM declined by €2.50/MWh to €119.18/MWh, despite reversing its net position from an 849 MW importer on the previous day to a 265 MW exporter. Forecast Romanian generation increased to 5,832 MW, against consumption of 5,567 MW. Romania exported an average 618 MW to Hungary, 355 MW to Serbia and 862 MW to Bulgaria, while continuing to deliver 178 MW to Moldova.
Romania’s hourly curve was considerably more volatile than its baseload average suggests. The price fell to €10.20/MWh in hour 11, while the evening maximum reached €190.00/MWh in hour 22, producing a spread of almost €180/MWh. Peakload averaged €77.10/MWh, compared with an off-peak price of €161.20/MWh. This is a clear deterioration in daytime capture conditions for merchant solar assets, accompanied by stronger short-duration storage economics and higher balancing exposure around the evening ramp.
Bulgaria and Greece converged exactly at €111.72/MWh. Bulgarian prices fell by €2.80/MWh, while Greece declined by €4.20/MWh. Both markets recorded a minimum of €9.20/MWh in hour 11 and a maximum of €190.00/MWh in hour 22. Their peakload average was only €70.40/MWh, against an off-peak average of €153.00/MWh.
Bulgaria emerged as the largest net exporter in the region, with generation forecast at 5,210 MW against consumption of 3,803 MW, producing a net surplus of 1,407 MW. It sent 862 MW to Romania, 327 MW to Greece and 235 MW to North Macedonia. Bulgaria’s export position increased by 553 MW from the previous session, supported by its nuclear fleet, coal generation and stronger daytime solar output.
Greece also moved from a 151 MW net import position to a 337 MW export position. Consumption fell by 363 MW to 7,802 MW as the average temperature declined from 30.3°C to 27.3°C. Forecast generation reached 8,139 MW. Greece exported 250 MW to Italy, 298 MW to North Macedonia and 124 MW to Albania, while importing 327 MW from Bulgaria. The reduction in cooling demand was therefore central to the fall in Greek prices and the reversal of cross-border flows.
Italy remained the region’s dominant sink. The national day-ahead price rose by €10.90/MWh to €181.08/MWh, with the North zone at approximately €177/MWh. Southeast Europe scheduled around 1,370 MW of exports to Italy, including 587 MW from Montenegro, 533 MW from Slovenia and 250 MW from Greece. Italian demand for imports helped preserve high evening prices throughout the Adriatic and Central European corridor, even as the Balkan mainland developed a much softer daytime balance.
Serbia registered the lowest baseload price in the monitored region. SEEPEX fell by €21.00/MWh to €85.94/MWh, placing Serbia €44.19/MWh below Hungary, €33.24/MWh below Romania and €25.78/MWh below Bulgaria and Greece. Peakload averaged €76.40/MWh, while off-peak power cleared at €95.50/MWh. The daily minimum was €36.00/MWh in hour 14, and the maximum reached €150.00/MWh in hour 20.
The Serbian price decline occurred despite a forecast net import requirement of 440 MW, slightly wider than the previous day’s 359 MW. Generation was estimated at 2,987 MW, against consumption of 3,427 MW. Serbia imported approximately 355 MW from Romania, 282 MW from North Macedonia and 67 MW from Hungary, while exporting 163 MW to Montenegro, 89 MW towards Croatia and a smaller volume towards Bosnia and Herzegovina.
This combination demonstrates that the Serbian discount was not simply a consequence of domestic oversupply. Instead, the market benefited from access to cheaper electricity moving through Romania and North Macedonia, together with weaker southern Balkan prices and limited ability to arbitrage the entire discount into Hungary. The €44/MWh SEEPEX-HUPX spread points to congestion and capacity-allocation limits rather than an economically integrated Serbian-Hungarian hourly market.
Montenegro experienced the largest daily price correction. BELEN fell by €40.40/MWh to €106.84/MWh, reversing the previous session’s exceptionally strong premium. Montenegro remained a net importer of 154 MW, with forecast generation of 272 MW covering only part of its 425 MW consumption. The country imported from Bosnia and Herzegovina, Serbia, Albania and Kosovo while continuing to schedule around 587 MW through the submarine cable to Italy.
BELEN peakload averaged €87.00/MWh, while off-peak power remained much higher at €126.70/MWh. The hourly minimum fell to €30.00/MWh, and the maximum reached €179.10/MWh. The continuing Italian pull preserved evening value, but additional Balkan supply removed the extreme premium observed one day earlier.
North Macedonia declined by €18.10/MWh to €90.13/MWh. It moved into a modest 32 MW export position, with forecast generation of 408 MW exceeding consumption of 376 MW. The market’s peakload average dropped to €63.40/MWh, compared with €116.80/MWh off-peak, and its hourly prices ranged from €21.20/MWh to €170.00/MWh.
Albania was comparatively stable at €102.57/MWh, down €1.90/MWh. Forecast generation of 862 MW left the country with an 81 MW import requirement against consumption of 943 MW. ALPEX nevertheless recorded the widest absolute hourly range among the smaller Balkan exchanges, from €25.00/MWh to €218.00/MWh. This reflects Albania’s continuing exposure to hydrology, limited domestic thermal flexibility and the price influence of interconnected evening markets.
Croatia and Slovenia remained aligned with the Hungarian-Austrian corridor rather than the cheaper eastern Balkans. CROPEX rose by €3.40/MWh to €126.36/MWh, while Slovenia gained €4.50/MWh to €131.52/MWh. Croatia required net imports of 887 MW, up sharply from 342 MW, as generation fell to 1,231 MW. Slovenia imported 270 MW, while exporting 533 MW to Italy and drawing substantial electricity from Austria and Hungary.
The forward curve strengthened more decisively than the spot market. At the 22 July close, Hungarian week 31 power rose by €9/MWh to €140/MWh, while week 32 surged by €16/MWh to €164.50/MWh. Hungarian August 2026 increased by €10/MWh to €156.50/MWh, and calendar 2027 advanced to €130/MWh. The Hungary-Germany premium stood at €14.50/MWh for week 31, €24/MWh for week 32, €23/MWh for August and €20/MWh for calendar 2027.
Fuel and carbon markets reinforced that forward repricing. Austrian CEGH gas increased by €2.50/MWh to €63.17/MWh, Greek gas rose to €54.33/MWh, and EU allowances gained €3.40/t to €86.63/t. Gas-fired generation economics remain expensive even for efficient combined-cycle plants, keeping a strong floor under evening, winter and low-renewable delivery periods. API2 coal contracts also edged higher, with the relevant forward indications around $123-126/t.
The immediate physical balance is comparatively comfortable: cooler weather, lower consumption, stronger solar and wind output, Bulgarian exports and Romania’s return to surplus have reduced the region’s dependence on northern imports. The forward market is pricing a different risk window, marked by expensive gas, higher carbon, evening ramp scarcity and persistent Hungarian congestion premiums. The session therefore combined weak solar capture prices with stronger dispatchable-generation and storage value, while the main cross-border opportunity remained defined by the unusually wide Serbia-Hungary and Balkan-Italy spreads.
