The Southeast European day-ahead market divided into three distinct pricing zones for Friday delivery. Hungary, Germany, Austria, Slovenia, Croatia and Romania converged around €129–133/MWh, the southern eastern markets of Bulgaria and Greece cleared near €124–125/MWh, while Serbia, Albania, Montenegro and North Macedonia remained substantially cheaper at €92–103/MWh. Italy continued to form the region’s premium outlet at €170.23/MWh.
Hungarian HUPX settled at €131.01/MWh, only €0.48/MWh above Germany, compared with a spread of approximately €12.5/MWh one day earlier. The convergence was driven principally by Germany’s €12.9/MWh increase to €130.53/MWh, rather than additional physical supply into Hungary. Imports from Austria and Slovakia into Hungary and Slovenia actually declined by 316 MW to an average 1,611 MW.
This distinction matters. Hungary’s near-perfect convergence with Germany does not indicate that its structural import requirement has disappeared. Hungarian generation was forecast at 3,560 MW against consumption of 4,195 MW, leaving the country dependent on 635 MW of net imports. The balance improved sharply from Thursday because domestic generation increased by 243 MW while demand fell by 299 MW, but Hungary remained exposed to imported marginal pricing and transmission availability.
The eastern market experienced more fundamental tightening. Romanian OPCOM rose €10.8/MWh to €129.98/MWh, Bulgarian IBEX advanced €12.4/MWh to €124.08/MWh, and Greek HENEX gained €13.1/MWh to €124.85/MWh. The combined Romania-Bulgaria consumption forecast increased by 523 MW, even as aggregate regional demand declined by 220 MW to 30,514 MW.
Greece’s generation was forecast to fall by approximately 921 MW, from 7,719 MW to 6,798 MW, while consumption declined by only 515 MW. The country consequently moved from a 340 MW export position to a 66 MW import requirement. Romania’s balance deteriorated even more sharply: generation fell by 604 MW while consumption rose by 94 MW, converting Thursday’s 424 MW net export into a 274 MW net import. Bulgaria’s demand increased by 429 MW, reducing its export surplus from 1,354 MW to 909 MW. Together, these three systems lost approximately 1.55 GW of day-on-day balance strength, explaining the broad eastern price rebound.
Western Balkan fundamentals moved in the opposite direction. Croatian generation increased by 592 MW to 1,852 MW, cutting its net import requirement from 857 MW to 183 MW. Bosnia and Herzegovina raised generation by 157 MW while demand fell, expanding net exports to 472 MW. Montenegro’s generation almost doubled from 163 MW to 304 MW, reducing imports to 110 MW despite higher consumption. These improvements helped keep the western Balkan price cluster below both HUPX and the Bulgarian-Greek zone.
Serbian SEEPEX recovered by €16.7/MWh to €102.64/MWh, but remained €28.37/MWh below HUPX, €27.34/MWh below Romania and more than €67/MWh below Italy. Serbia was still forecast to import an average 431 MW, with generation of 2,875 MW covering only about 87% of projected consumption of 3,306 MW. Commercial schedules included average imports of approximately 308 MW from Bosnia and Herzegovina, 151 MW from Croatia, 116 MW from Romania and 112 MW from Hungary, partly offset by exports of 189 MW to Montenegro and 67 MW to North Macedonia.
The Serbian discount therefore cannot be read simply as a domestic generation surplus. It reflects fragmented exchange liquidity, separately allocated cross-border capacity and commercial nominations that do not automatically follow day-ahead exchange price signals. Serbia’s import position alongside a €28/MWh discount to Hungary shows the limits of price convergence across uncoupled borders.
Montenegro recorded the region’s lowest price at €92.19/MWh, down €14.6/MWh day on day. BELEN traded at a discount of €38.81/MWh to HUPX and €78.04/MWh to Italy. The country’s commercial position was dominated by transit: Montenegro imported power from Bosnia and Herzegovina, Serbia, Albania and Kosovo while scheduling approximately 591 MW toward Italy through the submarine interconnector.
This does not imply that traders could freely capture the full Montenegro-Italy price difference. Cable nominations, previously acquired transmission rights, market liquidity and contractual schedules determine the accessible margin. It nevertheless demonstrates the commercial value of the Italy-facing corridor. Montenegro’s exchange price remained linked to the cheaper western Balkan pool even while its transmission system carried close to 600 MW toward Europe’s most expensive regional market.
Total SEE and Hungarian exports toward Italy declined by 227 MW to 1,137 MW, reflecting Italy’s €10.8/MWh price correction and higher prices across Romania, Bulgaria and Greece. Italy nevertheless retained a premium of €39.23/MWh over HUPX, €45–46/MWh over Bulgaria and Greece, and almost €68/MWh over Serbia and Albania. The Italian market therefore remained the dominant westward pull on regional commercial flows.
The most important signal was inside the hourly price curves. HUPX recorded a minimum of €13.50/MWh in hour 14 and a maximum of €200.90/MWh in hour 22, producing an intraday range of €187.40/MWh. Germany displayed an almost identical pattern, from €6.50/MWh in hour 15 to €203.20/MWh in hour 22. Romania, Slovenia and Croatia also fell to approximately €13/MWh around midday before approaching **€200/MWh during the evening.
As a result, conventional peakload products were markedly cheaper than off-peak products. HUPX peakload averaged only €92.00/MWh, compared with €170.00/MWh for off-peak hours. The corresponding inversion was €81.9/MWh in Germany, €78.3/MWh in Romania, €80.0/MWh in Slovenia and €73.6/MWh in Croatia. The statistical off-peak block includes the late-evening hours in which solar output has disappeared and residual demand is at its tightest, making the traditional peak/off-peak label increasingly misleading for operational trading.
Forecast solar output increased by 705 MW to 6,861 MW, while wind generation was expected to fall by 810 MW to 1,817 MW. The combination explains the extreme hourly shape. Additional solar supply depressed the central part of the day, but weaker wind left less renewable generation available during the evening ramp. Thermal units and imports consequently had to cover a much steeper residual-load increase after sunset.
For battery storage, the HUPX minimum-to-maximum spread represents a theoretical gross price range of €187.40/MWh. At 85% round-trip efficiency, purchasing one megawatt-hour at the daily minimum and selling the resulting 0.85 MWh at the maximum would produce approximately €157/MWh of gross energy margin before fees, degradation and balancing costs. Comparable opportunities existed in Germany and Croatia, while Albania’s hourly range reached almost €198/MWh. The persistence of these spreads supports storage economics even when daily baseload prices appear comparatively stable.
Solar capture economics were much weaker than the €131.01/MWh HUPX baseload suggests. The midday price of €13.50/MWh was barely one-tenth of the daily average, while the most valuable hours arrived after photovoltaic production had fallen. Merchant solar exposure is therefore becoming increasingly dependent on shaping arrangements, storage integration, intraday optimisation and offtake contracts that protect revenue during the solar-heavy delivery block.
The forward market reinforced the scarcity signal. Hungarian Week 31 increased by €5/MWh to €145/MWh, while Week 32 rose by €7.5/MWh to €172/MWh. The Week 32 Hungary-Germany premium expanded to €27/MWh, whereas Hungary moved to within only €2.5/MWh of Italy. August Hungarian baseload stood at €158/MWh, carrying a €25.5/MWh premium to Germany.
These increases occurred while the main thermal inputs weakened. CEGH gas eased to €62.85/MWh, EU allowances fell by €2.8/t to €83.88/t, and August coal declined to 121. The power rally was therefore driven less by rising fuel costs than by regional electricity scarcity premiums, expected renewable variability, transmission constraints and the risk attached to thermal availability.
Friday’s data leave traders with two different exposures. Baseload convergence between Hungary and Germany has tightened dramatically, but Hungary’s forward premium shows that the market does not expect the physical balance to remain comfortable. At the same time, the €28–39/MWh discounts across Serbia, Albania, Montenegro and North Macedonia preserve substantial cross-border basis risk. Solar will continue to pressure midday prices, while low wind, constrained hydrology and regional import dependence keep the evening ramp as the principal source of upside volatility.
