The SEE power market opened the week with a sharp scarcity-driven price surge, led by Hungary and Romania, where day-ahead baseload prices jumped to €222.73/MWh on HUPX and €223.54/MWh on OPCOM. Both markets more than doubled compared to the previous session, rising by over €126/MWh in Hungary and nearly €128/MWh in Romania. The move was not driven by fuels, as gas and EUA prices remained broadly stable, but by a combination of higher Monday demand, hot weather, evening peak tightness, and limited cross-border transfer capacity between low-priced southern markets and higher-priced Central and Eastern Europe.
The regional demand signal was the key driver. Total SEE consumption rose to 34.3 GW, up 3.76 GW day-on-day, while net imports increased to 1.77 GW. Hungary alone reached 5.58 GW of consumption, while Romania and Bulgaria combined approached 9.89 GW. Despite strong renewable output, including 8.30 GW of solar generation, the system remained tight during evening hours. The price structure clearly shifted away from midday solar-driven lows toward evening peak scarcity pricing, with H21 reaching €759.3/MWh on HUPX and €766.7/MWh on OPCOM.
The market effectively split into two pricing zones. Hungary and Romania formed the high-price core above €222/MWh, while Croatia and Slovenia followed at €184.01/MWh and €172.59/MWh, reflecting their exposure to Central European tightness. Serbia settled at €149.94/MWh, still sharply higher day-on-day, while Greece and Bulgaria remained the low-price zone at €86.50/MWh and €90.32/MWh, despite being net exporters. This created extreme spreads, with Romania trading €137/MWh above Greece and Hungary about €132/MWh above Bulgaria.
Cross-border flows confirm that the issue was not a uniform regional shortage, but a location and congestion imbalance. Greece exported around 1.72 GW, supported by strong renewable generation, while Bulgaria exported 738 MW and acted as a transit corridor toward Romania. However, Hungary still imported 1.28 GW, Romania 1.04 GW, Croatia 1.39 GW, and Serbia 543 MW. The main physical flow originated from Austria and Slovakia into Hungary and Slovenia, with CORE imports at 2.44 GW, while the region simultaneously exported 634 MW to Italy, highlighting congestion and bottleneck-driven price divergence.
Serbia’s market position was weaker than the headline suggests. Consumption rose to 3.95 GW, while generation reached 3.41 GW, leaving the system a net importer of 543 MW. Peak-hour dependency was even higher, with imports reaching 937 MW. Although SEEPEX settled at €149.94/MWh, below most Central European markets, intraday stress remained evident, with peak prices reaching €455.1/MWh at H21. Serbia’s generation mix remained heavily reliant on coal, at around 73%, increasing sensitivity to evening demand spikes and import price transmission.
Montenegro remained small in scale but strategically important due to its Italy interconnection. BELEN settled at €117.67/MWh, compared to €156.65/MWh in Italy, sustaining export flows toward the Italian market. Montenegro remained a net importer overall at around 120 MW, but still exported approximately 180 MW to Italy, peaking near 296 MW, effectively acting as a regional arbitrage and congestion bridge between SEE and Italy.
Forward markets already reflect expectations of continued tightness in Hungary. The HU Week 27 contract rose to €152/MWh, up 18.29%, while Germany and Italy traded significantly lower at €108.5/MWh and €133.5/MWh. The widening HU-DE spread to €43.5/MWh signals that traders are pricing Hungary not as a temporary weather spike, but as a market exposed to structural congestion, import dependence, and evening peak risk.
Despite the sharp price surge, the fuel complex remained stable. Gas and EUA prices showed no significant movement, reinforcing that the rally was driven by power system flexibility constraints rather than upstream cost pressure. This aligns with broader regional developments in storage and renewable investment, where new battery and grid projects across Bulgaria, Romania, and the Western Balkans are increasingly targeting exactly these evening ramp and congestion-driven price spikes.
Short-term risk remains conditional on weather. Forecasts suggest temperatures will stay high on 30 June, supporting continued demand pressure, before easing into early July. However, the structural message from this session is clear: SEE power markets are entering a phase where solar dominates midday pricing, imports define evening marginal supply, and cross-border constraints increasingly determine price formation across the region.