The June market signal is clear: late-month heat, cooling demand and system flexibility scarcity overwhelmed softer gas prices. The report compares 16–30 June with 1–15 June, and the second half of the month moved sharply higher across most markets. HUPX Hungary rose to €149.01/MWh, up €48.7/MWh, while Romania’s OPCOM rose to €146.80/MWh, up €47.6/MWh. Croatia and Slovenia followed with strong increases, reaching €136.67/MWh and €134.33/MWh respectively. Serbia’s SEEPEX rose to €114.87/MWh, up €28.3/MWh, while Montenegro’s BELEN moved to €108.63/MWh. Bulgaria and Greece were the exceptions in relative terms, rising only modestly to €99.72/MWh and €95.72/MWh, leaving a wide Hungarian premium over the southern Balkan markets.
The key driver was demand. Average HU+SEE consumption increased from 28,054 MW in the first half of June to 31,414 MW in the second half, a jump of 3,360 MW. The same table shows average temperature for HU+SEE excluding Greece rising from 20.3°C to 25.5°C, while Greece moved from 24.1°C to 26.7°C. That temperature shift converted June from a renewables-led shoulder-month market into an early-summer scarcity market. The end of the period was particularly tight: the regional balance moved from occasional export surplus into deep import positions, with HU+SEE net export averaging -466 MW in the second half and falling to -2,682 MW on 30 June in the daily table on page 82.
The generation response shows why prices still rose despite lower gas. Gas-fired generation increased by 1,177 MW to 4,757 MW, coal rose by 476 MW to 5,014 MW, nuclear rose by 922 MW to 4,901 MW, wind increased by 841 MW, and solar increased by 894 MW. Hydro, however, declined slightly by 130 MW to 6,098 MW. The regional mix remained structurally renewable-heavy, with solar at 23%, hydro at 20%, coal at 17%, gas at 16%, nuclear at 16% and wind at 8%, but the marginal price was increasingly set by evening flexibility rather than average daily renewable output.
This is the most important trading signal in the report: solar lowered mid-day prices but intensified evening ramps. Several markets recorded near-zero or negative minimum prices, while evening maximums became extreme. Hungary recorded a maximum of €923.1/MWh, Romania €954.6/MWh, Slovenia €1,041.5/MWh, Croatia €946.6/MWh and Serbia €800/MWh during the observed period. This confirms that the regional market is no longer pricing only energy volume; it is increasingly pricing dispatchability, ramping capacity, interconnector availability and storage scarcity.
Gas did not explain the price rally. Average CEGH gas fell from €49.35/MWh to €43.06/MWh, while Greek gas fell from €46.14/MWh to €41.37/MWh. At the same time, EUA carbon rose from €77.85/t to €80.31/t. In market terms, this means the second-half June power rally was driven less by fuel input costs and more by weather, outages, nuclear cooling constraints, import dependence and evening residual-load scarcity.
Hungary became the stress point of the regional price curve. The report records a new summer demand peak of 7,488 MW on 29 June, while NPP Paks faced temporary operating constraints because Danube cooling-water temperatures exceeded the normal environmental threshold. The Energy Ministry allowed a temporary exemption to avoid a much larger output reduction, limiting the additional cut to 40 MW instead of a potential 640 MW. This combination of heat-driven load, nuclear cooling sensitivity and import needs explains why HUPX became the premium reference market for the region.
Romania delivered the opposite signal: huge solar penetration did not prevent price tightness. The report notes a new dispatchable solar record of 2,952 MW, with prosumers adding around 1,930 MW, bringing total mid-day solar close to 5 GW. Yet Romania still averaged -637 MW net import across the second half of June. The market is therefore showing a structural split between mid-day surplus and evening shortage, which supports the investment case for co-located storage, flexible gas, demand response and grid reinforcement.
Greece remained the main southern pressure valve. Its average price was only €95.72/MWh, but the country averaged 1,385 MW net exports in the country data, supported by a generation mix of 36% gas, 33% solar and 22% wind. In practice, Greece was exporting surplus and flexible generation northward into Bulgaria, North Macedonia and Albania during much of the period, while still relying heavily on gas to support system balance.
Serbia’s market signal was mixed but important. SEEPEX rose to €114.87/MWh, and the June day-ahead market reached an all-time traded-volume record of 569,139 MWh, up 12.6% year on year. Serbia remained structurally import-exposed in the second half, with average net exports at -706 MW, while generation remained dominated by coal at 66% and hydro at 32%. This reinforces the bankability logic behind Serbia’s 1 GW solar plus at least 200 MW / 400 MWh battery storage program, Bistrica pumped-storage financing talks, and new wind projects such as Alibunar.
Montenegro’s data show why domestic generation availability remains financially critical. BELEN averaged €108.63/MWh, but Montenegro’s power balance stayed import-negative at -77 MW in the observed period. The EPCG section is more strategic: the utility spent €142 million on electricity imports in 2025 during TPP Pljevlja downtime and weak hydrology, with 780 GWh imported to replace Pljevlja output and another 320 GWh linked to lower hydro production. CGES grid upgrades at Perucica and Pljevlja could create room for about 550 MW of new renewable connections, while the cross-border HTLS upgrade could lift the Trebinje–Perucica–Podgorica–Vau i Dejes corridor to around 600 MW.
The investment trend across the whole report is unmistakable: storage, grids and hybrid plants are moving from optional add-ons to core market infrastructure. Bulgaria commissioned or acquired multiple battery projects, including Solarpro’s 602 MWh Burgas facility. Hungary commissioned storage at Tiszaujvaros and Ajka. Romania’s pipeline includes solar-plus-storage, standalone batteries, hybrid PPAs, major grid financing and several hundred MWh of approved battery projects. This is exactly the asset class that captures June’s market spreads: charging during solar-heavy low-price hours and discharging into the evening scarcity window.
The broader market conclusion is that SEE is entering a new pricing regime. The old pattern of thermal baseload plus hydro balancing is being replaced by a system where solar sets the daytime floor, gas and imports set the evening ceiling, and interconnectors determine local scarcity premiums. June’s data show that average RES growth does not automatically reduce market risk; without storage, grid capacity and flexible demand, it can deepen intraday volatility. For investors, the most attractive positions are no longer simple merchant solar projects, but hybrid solar-storage, wind with balancing strategy, pumped storage, grid-connected batteries, and industrial PPAs with hourly matching and flexibility clauses.
