South-East European day-ahead prices remained elevated on Friday, but the market split sharply between the higher-priced Central European and Italian corridor and a lower-priced Serbian zone.
The regional benchmark HUPX settled at €123.26/MWh, almost unchanged day on day. Slovenia reached €125.40/MWh, Croatia traded at €119.61/MWh, Romania at €116.24/MWh, while Bulgaria and Greece converged at €115.64/MWh. Italy remained the most expensive market at €148.43/MWh. Serbia was the clear regional discount at €106.01/MWh, leaving SEEPEX around €17.25/MWh below HUPX and more than €42/MWh below Italy.
The Serbian market displayed the strongest intraday volatility. SEEPEX fell to €20/MWh at hour 14 before rising to €208.10/MWh at hour 21. The near-€188/MWh intraday spread reflects the growing impact of midday solar surpluses and evening scarcity after photovoltaic output falls.
Regional electricity demand increased slightly to 31,291 MW, while net imports declined to 658 MW from 899 MW a day earlier. Total generation remained close to 30.6 GW. Wind production rose by about 584 MW to 1,771 MW, partly compensating for a 520 MW fall in hydro generation to 4,871 MW. Solar remained strong at 6,302 MW, coal at 6,348 MW, gas at 4,521 MW, and nuclear at 5,579 MW.
Bulgaria was the principal regional exporter, generating around 5,112 MW against consumption of 3,660 MW, producing a net surplus of approximately 1,453 MW. Bulgarian exports averaged around 795 MW towards Romania, 280 MW towards Serbia, 274 MW towards Greece, and 170 MW towards North Macedonia. Stable nuclear generation of about 1,895 MW, combined with close to 1 GW of solar, kept Bulgarian prices below Hungary and supported price convergence with Greece.
Serbia remained structurally short, with consumption of approximately 3,495 MW against generation of 3,022 MW, leaving average net imports of 473 MW. Coal supplied around 2,529 MW, hydro 499 MW, and wind 278 MW. Serbia imported mainly from Bosnia and Herzegovina, Bulgaria, Croatia and Montenegro, while exporting part of its available volume towards Romania and Montenegro.
Romania’s deficit narrowed to about 149 MW as consumption fell to 5,547 MW and generation reached 5,398 MW. Romania imported heavily from Bulgaria but exported towards Hungary during peak hours, with Romania-to-Hungary peak flows averaging approximately 806 MW.
Hungary remained a net importer of about 634 MW, with generation of 3,773 MW below demand of 4,407 MW. Nuclear supplied roughly 1,855 MW, solar 1,248 MW, and gas 448 MW. The spot Hungary–Germany spread narrowed to almost zero, although Hungarian forward prices continued to carry a substantial premium.
Croatia recorded a net deficit of approximately 949 MW, one of the largest in the region. Domestic generation of 1,241 MW covered only slightly more than half of demand. Imports came mainly from Hungary and Slovenia.
Montenegro imported about 97 MW on a net basis, despite exporting approximately 493 MW to Italy through the submarine interconnector. Domestic generation reached 326 MW, including around 201 MW from coal, 32 MW from hydro, and 44 MW from wind. The Montenegro–Italy day-ahead spread exceeded €31/MWh, preserving a strong commercial incentive for westbound exports.
The dominant trading structure was therefore clear: cheap Serbian midday power, strong Bulgarian exports into the eastern region, persistent Croatian and Hungarian import dependence, and Italy acting as the premium destination for Balkan electricity. The evening scarcity signal remained substantially stronger than the daily averages, reinforcing the value of flexible hydro, cross-border capacity and battery storage.