Southeast Europe’s day-ahead electricity market split into three distinct pricing zones for Friday delivery. Hungary, Germany, Austria, Slovenia, Croatia and Romania converged around €129–133/MWh, while Bulgaria and Greece cleared near €124–125/MWh. Serbia, Albania, Montenegro and North Macedonia remained substantially cheaper at €92–103/MWh. Italy continued to represent the region’s premium market, clearing at €170.23/MWh.
Hungary’s HUPX settled at €131.01/MWh, just €0.48/MWh above Germany, compared with a spread of approximately €12.5/MWh one day earlier. The convergence was driven primarily by Germany’s €12.9/MWh price increase to €130.53/MWh, rather than by a significant increase in physical supply to Hungary. Imports from Austria and Slovakia into Hungary and Slovenia actually declined by 316 MW to an average of 1,611 MW.
That distinction is important. Hungary’s near-perfect convergence with Germany does not mean that its structural dependence on imports has disappeared. Hungarian generation was forecast at 3,560 MW against consumption of 4,195 MW, leaving the country dependent on approximately 635 MW of net imports. The balance nevertheless improved sharply from Thursday, as domestic generation increased by 243 MW while demand fell by 299 MW. Hungary remained exposed to imported marginal pricing and transmission availability.
The eastern market experienced a more fundamental tightening. Romanian OPCOM rose by €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. Combined consumption forecasts for Romania and Bulgaria increased by 523 MW, even as total 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 position into a 274 MW net import requirement. Bulgaria’s demand increased by 429 MW, reducing its export surplus from 1,354 MW to 909 MW.
Together, the 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 increased 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.
Serbia’s SEEPEX price 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 of 431 MW, with generation of 2,875 MW covering only around 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. These flows were partly offset by exports of 189 MW to Montenegro and 67 MW to North Macedonia.
Serbia’s discount therefore cannot be interpreted simply as evidence of a domestic generation surplus. It reflects fragmented exchange liquidity, separately allocated cross-border capacity and commercial nominations that do not automatically follow day-ahead price signals. Serbia’s simultaneous import requirement and €28/MWh discount to Hungary demonstrate 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 electricity from Bosnia and Herzegovina, Serbia, Albania and Kosovo while scheduling approximately 591 MW towards Italy through the submarine interconnector.
This does not mean that traders could freely capture the full Montenegro–Italy price difference. Cable nominations, previously acquired transmission rights, market liquidity and contractual schedules determine the margin that can actually be accessed. The price structure nevertheless demonstrates the commercial value of Montenegro’s Italy-facing corridor. Montenegro’s exchange price remained linked to the cheaper Western Balkan pool even as its transmission system carried close to 600 MW towards Europe’s most expensive regional market.
Total Southeast European and Hungarian exports towards 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 appeared in 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 showed an almost identical pattern, falling to €6.50/MWh in hour 15 before rising 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.
The result was a significant inversion of traditional peak and off-peak economics. HUPX peakload averaged only €92/MWh, compared with €170/MWh for off-peak hours. The corresponding inversion was €81.9/MWh in Germany, €78.3/MWh in Romania, €80/MWh in Slovenia and €73.6/MWh in Croatia.
The traditional off-peak block now includes late-evening hours when solar output has disappeared and residual demand is at its tightest. The conventional peak/off-peak classification is therefore becoming 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 price profile. Additional solar supply depressed midday prices, but weaker wind generation left less renewable output available during the evening ramp. Thermal generators and imports consequently had to cover a much steeper increase in residual load after sunset.
For battery storage, the HUPX minimum-to-maximum spread represented 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 such spreads continues to support storage economics even when daily baseload prices appear relatively stable.
Solar capture economics were considerably weaker than the €131.01/MWh HUPX baseload price 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 declined. Merchant solar exposure is therefore increasingly dependent on shaping arrangements, storage integration, intraday optimisation and offtake contracts capable of protecting revenues during solar-heavy delivery periods.
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, while Hungary moved to within only €2.5/MWh of Italy. August Hungarian baseload stood at €158/MWh, carrying a €25.5/MWh premium over Germany.
These increases occurred despite weaker main thermal inputs. 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 thermal-availability risk.
Friday’s market left traders facing two distinct exposures. Baseload convergence between Hungary and Germany tightened dramatically, but Hungary’s forward premium indicates that the market does not expect the physical balance to remain comfortable. At the same time, discounts of €28–39/MWh across Serbia, Albania, Montenegro and North Macedonia preserve substantial cross-border basis risk.
Solar generation will continue to pressure midday prices, while low wind output, constrained hydrology and regional import dependence keep the evening ramp as the principal source of upside volatility.