South-East Europe entered summer with a tighter electricity balance than May indicated, with average day-ahead prices rising across almost every market during June 2026. Cooling demand accelerated while hydropower weakened in several countries and conventional generation regained influence during the evening peak. Strong solar output continued to depress prices during daylight hours, but a pronounced scarcity event occurred at the end of the month.
Across the seven interconnected European markets, the simple average day-ahead price reached approximately €112.54/MWh. Italy remained the most expensive market at €132.51/MWh, followed by Hungary at €124.67/MWh and Romania at €122.99/MWh. Croatia averaged €115.90/MWh, Serbia €100.71/MWh, Bulgaria €98.08/MWh and Greece €92.93/MWh, while Türkiye averaged only €23.37/MWh.
Regional price spreads and monthly changes
The regional price ladder showed distinct market zones, with Hungary and Romania separated by only €1.68/MWh. Serbia and Bulgaria were also closely aligned, with a spread of €2.63/MWh, while Italy traded €39.58/MWh above Greece. Türkiye’s discount to Greece was €69.56/MWh, and its discount to Italy widened to €109.14/MWh.
Hungary recorded the strongest monthly increase among the interconnected markets, rising 17.05% from May and 48.25% from June 2025. Romania followed with a 12.25% monthly rise and a 42.79% annual increase, while Croatia gained 11.89% month on month and 34.76% year on year. Italy rose 11.02% and 18.54%, respectively, while Greece and Serbia increased by 4.45% and 4.23%. Bulgaria was the only covered market to decline, falling 2.97% to €98.08/MWh while remaining 15.01% higher year on year.
Cooling-driven demand growth and diverging supply
Electricity consumption increases were uneven but substantial, with Greece up 19.5%, Hungary up 18.6%, Croatia up 11.0%, Türkiye up 10.4% and Italy up 10.0%. Romania recorded a comparatively modest 1.4% increase, while Bulgaria remained broadly stable; Serbia reported demand falling by 13.5%. Supply conditions diverged further as renewable generation rose in Türkiye (+27.6%), Bulgaria (+13.5%) and Greece (+10.7%). Renewable output fell in Serbia (-43.8%), Croatia (-24.0%), Romania (-22.9%) and Italy (-6.2%), while Hungary saw renewables increase by only 2.3%.
Hydropower weakened across much of the region, with output down 37.9% in Hungary, 19.6% in Greece, 11.3% in Romania, 10.0% in Türkiye and 3.2% in Croatia . Serbian hydro production was effectively unchanged at -0.1%. Bulgaria and Italy were exceptions, with hydropower output increasing by 11.1% and 6.6%, respectively.
End-of-month scarcity timing across markets
The interaction between stronger consumption and weaker flexible generation appeared on 30 June, when daily averages reached €293.44/MWh in Romania, €290.36/MWh in Hungary, €263.59/MWh in Croatia and €250.98/MWh in Serbia . Bulgaria’s daily average on that date was €148.44/MWh.
Several markets recorded their monthly lows on 13 June, including €35.12/MWh in Serbia, €39.66/MWh in Croatia, €46.03/MWh in Romania and €49.70/MWh in Bulgaria . The shared timing pointed to a region-wide shift from renewable-led surplus conditions toward heat-driven scarcity rather than isolated national events.
Country balances: Hungary, Romania and Croatia
Hungary sat at the centre of the tightening balance as demand rose by 18.6%. Gas-fired generation increased by 68.2%, nuclear output rose by 20.5%, and coal and lignite production gained 9.6%. Renewables excluding hydro increased by only 2.3%, while hydro output contracted sharply.
Imports accounted for 30.81% of Hungary’s electricity balance, with net imports reaching 1,312.39 GWh. Net imports increased by 21.93%, or 236.08 GWh, from May; Hungary imported from Austria, Croatia, Romania and Slovakia while exporting towards Serbia and Ukraine . HUPX traded 2,382.87 GWh, down 8.05% month on month but around 4.1% higher year on year.
Romania reached a similar monthly price through a different generation mix as renewable output fell by 22.9% and hydro production declined by 11.3%. Nuclear generation increased by 122.5%, alongside gas-fired generation rising by 10.8% and coal and lignite output increasing by 7.1%. Despite the nuclear recovery preventing an even tighter balance, imports remained necessary as Romania ended June with net imports of 543.45 GWh, receiving its largest incoming volume from Bulgaria while exporting primarily towards Hungary.
Liquidity weakened alongside higher prices as OPCOM cleared only 888.35 GWh, down 20.05% from May and 63.42% from June 2025 . The combination of higher prices, extreme daily movements and reduced exchange turnover increased basis and execution risk for utilities, industrial consumers and trading companies hedging Romanian exposure.
Croatia saw demand rise by 11.0%, renewable generation fall by 24.0% and hydro output decline by 3.2%. Net imports increased by 32.27% to 772.3 GWh, accounting for 52.18% of the reported electricity balance . Croatia received power from Hungary and Slovenia while exporting to Bosnia and Herzegovina and Serbia.
CROPEX volumes; Italy’s gas-linked premium; Greece exports
CROPEX volume rose by 12.42% to 986.15 GWh, although year-on-year growth was limited to 1.52%. The market’s daily range was €223.93/MWh between a low of €39.66/MWh and a peak of €263.59/MWh . This indicated that increased exchange activity did not reduce physical volatility.
Italy remained the regional price ceiling with an average of €132.51/MWh. Daily prices stayed above €100/MWh on all but four days; the highest daily average occurred on 24 June at €162./MWh alongside demand of 722 GWh. The monthly low was €91./MWh on 14 June.
Italian demand increased by 10.0%, gas-fired generation rose by 30.7%, coal generation more than doubled with a 124.2% increase from a low base . Renewable output fell by 6.2%, while hydro production increased by 6.6%. At an approximate June TTF average of €44./MWh, fuel cost estimates for gas-fired units were close to €90/MWh at 50% efficiency before carbon allowances, start-up costs and variable operations and maintenance; at
a more efficient plant operating at 55%, fuel cost was about
