South-East Europe entered the summer with a considerably tighter electricity balance than May had suggested. Average day-ahead prices rose across almost every market during June 2026, as cooling demand accelerated, hydropower weakened in several countries and conventional generators regained influence during the evening peak. Strong solar production continued to depress prices in daylight hours, but it could not prevent a pronounced scarcity event at the end of the month.
Across the seven interconnected European markets covered by the data, the simple average day-ahead price reached approximately €112.54/MWh. Italy retained its position as the region’s 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. Türkiye remained structurally detached from the European price formation mechanism, averaging only €23.37/MWh.
The regional price ladder reveals several distinct market zones. Hungary and Romania formed a Central European scarcity cluster, separated by only €1.68/MWh. Serbia and Bulgaria were also relatively closely aligned, with a spread of €2.63/MWh, while Italy traded €39.58/MWh above Greece. Türkiye’s discount to Greece reached €69.56/MWh, and its discount to Italy widened to €109.14/MWh.
Hungary recorded the strongest monthly price increase among the interconnected European markets, rising 17.05% from May and 48.25% from June 2025. Romania followed with a 12.25% monthly and 42.79% annual increase. Croatia rose 11.89% month on month and 34.76% year on year, while Italy gained 11.02% and 18.54% respectively. Greece and Serbia recorded more moderate monthly increases of 4.45% and 4.23%. Bulgaria was the only covered European market to register a decline, falling 2.97% to €98.08/MWh, although its price remained 15.01% higher year on year.
The rise in cooling demand was uneven but substantial. Electricity consumption increased by 19.5% in Greece, 18.6% in Hungary, 11.0% in Croatia, 10.4% in Türkiye and 10.0% in Italy. Romania recorded a comparatively modest 1.4% increase, while Bulgaria remained broadly stable. Serbia moved against the regional pattern, with reported demand falling by 13.5%.
Supply conditions diverged even more sharply. Renewable generation increased by 27.6% in Türkiye, 13.5% in Bulgaria and 10.7% in Greece, but fell by 43.8% in Serbia, 24.0% in Croatia, 22.9% in Romania and 6.2% in Italy. Hungary recorded only a 2.3% increase despite the surge in demand.
Hydropower, normally one of the region’s most important sources of flexibility, weakened across much of the market. Output fell by 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 the exceptions, with increases of 11.1% and 6.6%.
The interaction between stronger consumption and weaker flexible generation became visible on 30 June, when daily averages reached €293.44/MWh in Romania, €290.36/MWh in Hungary, €263.59/MWh in Croatia, €250.98/MWh in Serbia and €148.44/MWh in Bulgaria. Several markets had 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 common timing points to a region-wide transition from renewable-led surplus conditions to heat-driven scarcity rather than isolated national events.
Hungary sat at the centre of that tightening balance. Demand increased by 18.6%, while gas-fired generation rose 68.2%, nuclear output increased 20.5% and coal and lignite production gained 9.6%. Renewables excluding hydro increased by only 2.3%, while hydro output contracted sharply.
Imports represented 30.81% of Hungary’s electricity balance. Net imports reached 1,312.39 GWh, increasing by 21.93%, or 236.08 GWh, from May. Hungary imported electricity 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 almost the same monthly price through a different generation configuration. Renewable output fell by 22.9% and hydro production by 11.3%, but nuclear generation increased by 122.5%, apparently reflecting the return of capacity following outages or maintenance. Gas-fired generation rose 10.8%, while coal and lignite output increased 7.1%.
The nuclear recovery prevented an even tighter Romanian balance but did not eliminate the need for imports. Romania ended June with net imports of 543.45 GWh, receiving its largest incoming volume from Bulgaria while exporting primarily towards Hungary.
Liquidity weakened at the same time as Romania’s price and volatility increased. OPCOM cleared only 888.35 GWh, down 20.05% from May and 63.42% from June 2025. This combination of higher prices, extreme daily movements and reduced exchange turnover creates additional basis and execution risk for utilities, industrial consumers and trading companies attempting to hedge Romanian exposure.
Croatia experienced a more direct renewable and import shock. Electricity demand increased by 11.0%, renewable generation fell 24.0% and hydro output declined 3.2%. Net imports consequently rose by 32.27% to 772.3 GWh, accounting for 52.18% of the reported electricity balance.
Croatia received electricity from Hungary and Slovenia while exporting to Bosnia and Herzegovina and Serbia. CROPEX volume increased 12.42% to 986.15 GWh, although year-on-year growth was limited to 1.52%. The market’s daily range of €223.93/MWh, measured between the €39.66/MWh low and €263.59/MWh peak, showed that growing exchange activity had not reduced the underlying physical volatility.
Italy remained the regional price ceiling. Its average increased to €132.51/MWh, and daily prices stayed above €100/MWh on all but four days. The highest daily average was recorded on 24 June at €162.66/MWh, alongside electricity demand of 722 GWh. The monthly low of €91.15/MWh occurred on 14 June.
Italian demand increased 10.0%, while gas-fired generation rose 30.7%. Coal generation more than doubled, increasing 124.2% from a low base. Renewable output fell 6.2%, although hydro production increased 6.6%.
Italy’s reliance on gas explains much of the persistent premium. At an approximate June TTF average of €44.8/MWh, a gas-fired unit operating at 50% efficiency faced a fuel cost close to €90/MWh before carbon allowances, start-up costs and variable operations and maintenance. A more efficient plant operating at 55% still carried a fuel cost of about €81.5/MWh.
Net electricity imports increased 14.92% to 4,259.03 GWh, with supplies arriving from France, Switzerland, Austria, Greece, Montenegro and Slovenia. Italy exported only to Malta. Imports provided important system support but could not displace gas as the marginal price-setting technology.
IPEX cleared 25,620.73 GWh, an increase of 11.42% from May and 3.97% year on year. Italy represented approximately 68% of the 37.64 TWh traded across the seven exchanges for which June volume data were available, highlighting the difference between Italian liquidity and the much thinner markets of Romania, Serbia and Croatia.
At the lower end of the interconnected market, Greece and Bulgaria converted comparatively favourable low-carbon supply into export capacity. Greece averaged €92.93/MWh, up 4.45% from May and 8.79% year on year. HEnEx volume increased 15.57% to 4,482.02 GWh, although it remained 7.03% below June 2025.
Renewables supplied 56.01% of Greek generation and increased output by 10.7%. Gas-fired production rose 23.7% to balance higher cooling demand, while hydro fell 19.6% and lignite production declined 41.3%. Greece nevertheless exported a net 726.98 GWh to Albania, North Macedonia, Bulgaria and Italy. Türkiye was its only import source. Greek exports to Bulgaria reached 390.98 GWh, the country’s largest reported bilateral electricity flow.
Bulgaria’s monthly price declined to €98.08/MWh as nuclear generation rose 11.0%, renewables increased 13.5% and hydropower gained 11.1%. Coal and lignite output fell 23.9%, while gas-fired generation declined 28.2%. Nuclear accounted for 34.65% of generation, renewables 31.91% and hydro 18.72%.
This combination allowed Bulgaria to export a net 386.55 GWh while reducing thermal dispatch. It exported towards North Macedonia, Romania and Serbia and received electricity from Greece and Türkiye. IBEX volume reached 2,708.01 GWh, increasing 1.20% from May and 18.50% year on year.
Serbia’s June balance was particularly revealing. The SEEPEX average increased to €100.71/MWh, or 17.49% above June 2025, despite the reported 13.5% decline in demand. Coal and lignite generation rose 22.9%, while gas-fired output increased 135.4% from a low base. Renewables fell 43.8%, and hydro production was nearly unchanged.
Coal and lignite represented 63.72% of Serbian generation, compared with 30.42% for hydro, 4.22% for other renewables and 0.91% for gas. Serbia moved into a net exporting position of 100.63 GWh, sending electricity towards Bulgaria, Montenegro, Croatia and Kosovo while importing from Hungary, North Macedonia, Bosnia and Herzegovina and Kosovo.
The monthly average hides a much more significant intraday development. Serbia’s average hourly price fell towards approximately €40/MWh around midday, when solar production was strongest, before climbing to almost €200/MWh during the evening peak. No other covered market displayed such a pronounced average transition between daytime surplus and post-sunset scarcity.
This two-speed price curve creates an increasingly credible commercial case for battery storage. A theoretical 50 MW/100 MWh battery charging at €40/MWh and discharging at €200/MWh, with 85% round-trip efficiency, would generate a gross daily arbitrage margin of roughly €15,300. That spread would not be available every day, but a combined arbitrage and balancing model could potentially support gross annual revenue of approximately €100,000-€150,000 per MW under favourable market-access conditions.
At an indicative installed cost of €260-€360 per kWh, the investment envelope for such a project would be approximately €26-€36 million. A diversified revenue model combining day-ahead trading, intraday optimisation and balancing services could target a base-case unlevered return in the low-to-mid teens, with an upside case in the high teens. A 12-18 month connection delay would remove at least one summer trading season, increase interest during construction and could reduce equity IRR by approximately 1.5-3.5 percentage points.
SEEPEX volume reached 569.14 GWh, only 0.5% higher than in May and 5.01% lower year on year. The limited liquidity increases route-to-market and basis risk, making access to balancing services and bankable optimisation arrangements as important as the visible day-ahead spread.
Türkiye presented the region’s sharpest statistical rebound but remained commercially detached from European price levels. Its average more than doubled from May, rising 109.28% to €23.37/MWh, yet remained 52.20% below June 2025.
Turkish demand increased 10.4%, renewable generation rose 27.6% and coal-fired output increased 56.7%. Hydropower declined 10.0% but still accounted for 41.01% of the generation mix. Coal and lignite supplied 26.11%, other renewables 22.73%, gas 9.94% and oil 0.21%. Gas-fired output declined 3.3%, insulating the Turkish market from Europe’s higher gas-based marginal costs.
Türkiye exported 286.88 GWh, including 184.12 GWh to Georgia, 75.44 GWh to Bulgaria and 27.32 GWh to Greece. These exports were small relative to the theoretical value implied by the cross-border spreads, reflecting the limits imposed by interconnection capacity, market arrangements and system-security requirements.
June confirmed that South-East Europe is becoming more interconnected without becoming uniformly priced. Solar generation is compressing midday prices, but hydro variability, thermal availability, grid constraints and evening ramping requirements are concentrating value into fewer hours. The result is a market offering stronger signals for storage and flexible generation while exposing import-dependent countries to increasingly severe late-day scarcity.
