Friday’s Southeast Europe day-ahead electricity market cleared in three pricing zones for delivery on the same day. Hungary, Germany, Austria, Slovenia, Croatia and Romania converged around €129–133/MWh. Bulgaria and Greece cleared near €124–125/MWh, while Serbia, Albania, Montenegro and North Macedonia remained lower at €92–103/MWh. Italy set the regional high at €170.23/MWh.
Hungary and Germany converge, but net import dependence remains
Hungary’s HUPX settled at €131.01/MWh, only €0.48/MWh above Germany. The day-ahead spread between the two markets was about €12.5/MWh one day earlier. Germany’s price increased by €12.9/MWh to €130.53/MWh, while imports into Hungary and Slovenia from Austria and Slovakia fell by 316 MW to an average of 1,611 MW. The convergence therefore aligned with Germany’s move rather than a rise in physical supply to Hungary.
Hungary’s 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 improved 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.
Easterly tightening lifts Romanian, Bulgarian and Greek prices
The eastern market tightened as Romanian OPCOM rose by €10.8/MWh to €129.98/MWh. Bulgarian IBEX advanced by €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 about 921 MW from 7,719 MW to 6,798 MW, while consumption declined by only 515 MW. That shifted Greece from a 340 MW export position to a 66 MW import requirement. Romania’s balance deteriorated further as generation fell by 604 MW while consumption rose by 94 MW, turning 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. Across the three systems, day-on-day balance strength fell by approximately 1.55 GW, corresponding with the broad eastern price rebound.
Western Balkan balances improve while Serbia stays discounted
Croatian fundamentals moved in the opposite direction as generation increased by 592 MW to 1,852 MW. That reduced Croatia’s 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 nearly doubled from 163 MW to 304 MW, cutting imports to 110 MW.
Serbia’s SEEPEX price recovered by €16.7/MWh to €102.64/MWh but stayed below HUPX by €28.37/MWh and below Romania by €27.34/MWh. The Serbian price was more than €67/MWh under Italy at €170.23/MWh. Serbia was forecast to import an average of 431 MW, with generation of 2,875 MW covering around 87% of projected consumption of 3,306 MW.
Commercial schedules showed average imports of approximately 308 MW from Bosnia and Herzegovina, 151 MW from Croatia, 116 MW from Romania and 112 MW from Hungary. These were partly offset by exports of 189 MW to Montenegro and 67 MW to North Macedonia.
Montenegro records the lowest price amid transit flows toward Italy
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 versus HUPX and €78.04/MWh versus Italy . Montenegro’s commercial position was dominated by transit as it imported electricity from Bosnia and Herzegovina, Serbia, Albania and Kosovo while scheduling about 591 MW toward Italy through the submarine interconnector.
Cable nominations, transmission rights previously acquired, market liquidity and contractual schedules determine what portion of any cross-border price difference can be captured in practice . Even so, Montenegro’s exchange price remained linked to the cheaper Western Balkan pool while its transmission system carried close to 600 MW toward Europe’s most expensive regional market.
Italy premium persists as westward exports decline
Total Southeast European and Hungarian exports toward Italy fell by 227 MW to 1,137 MW. The change reflected Italy’s €10.8/MWh price correction alongside higher prices across Romania, Bulgaria and Greece . Italy still held a premium of €39.23/MWh over HUPX, €45–46/MWh over Bulgaria and Greece, and almost €68/MWh over Serbia and Albania.
The hourly profile showed the main signal in intraday trading patterns rather than only daily averages . HUPX recorded a minimum of €13.50/MWh in hour 14 and a maximum of €200.90/MWh in hour 22 for an intraday range of €187.40/MWh.
Intraday swings invert peak/off-peak economics; solar output rises
Germany displayed an almost identical pattern with prices falling to €6.50/MWh in hour 15 before rising to €203.20/MWh in hour 22 . Romania, Slovenia and Croatia also dropped to around €13/MWh around midday before approaching close to €200/MWh during the evening . This produced an inversion where HUPX peakload averaged only €92/MWh compared with off-peak hours averaging €170/MWh.
The corresponding inversion values were reported as €81.9/MWh for Germany, €78.3/MWh for Romania, €80/MWh for Slovenia and €73.6/MWh for Croatia . The traditional off-peak block included late-evening hours when solar output had disappeared and residual demand was tightest . 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.
Batteries face a wide theoretical spread; forward prices rise on scarcity signals
The HUPX minimum-to-maximum spread implied a theoretical gross price range of €187.40/MWh. With an assumed 85% round-trip efficiency, buying one megawatt-hour at the daily minimum and selling the resulting 0.85 MWh at the maximum would yield about €157/MWh gross energy margin before fees, degradation and balancing costs . Comparable spreads were cited for Germany and Croatia, while Albania’s hourly range reached almost €198/MWh . Persistence of such spreads supported storage economics even when daily baseload levels appeared stable.
The midday solar price was reported at €13.50/MWh, about one-tenth of the daily average implied by the same dataset . The most valuable hours arrived after photovoltaic production had declined . Merchant solar exposure was described as depending on shaping arrangements, storage integration, intraday optimisation and offtake contracts that protect revenues during solar-heavy delivery periods.
Forward contracts show higher premiums; fuel eases but power prices firm
The forward market reinforced scarcity conditions as Hungarian Week 31 rose by €5/MWh to €145/MWh. Week 32 increased by €7.5/MWh to €172/MWh, widening the Week 32 Hungary–Germany premium to €27/MWh. Hungary moved within only €2.5/MWh of Italy on that basis point level; August Hungarian baseload stood at €158/MWh, carrying a premium of €25.5/MWh over Germany .
Main thermal inputs were weaker alongside these increases: CEGH gas eased to
Main thermal inputs were reported as easing with CEGH gas at
Main thermal inputs were reported as easing: CEGH gas eased to **€62.85/MWh**, EU allowances fell by **€2/t**?
