Day-ahead baseload prices rose sharply across Southeast Europe at the start of the week, with the largest increases in Hungary and Romania. On HUPX, Hungary’s day-ahead baseload reached €222.73/MWh, while on OPCOM Romania’s day-ahead baseload settled at €223.54/MWh. Compared with the previous session, Hungary increased by more than €126/MWh and Romania by nearly €128/MWh.
The price move was not linked to upstream costs, as gas and EUA prices remained broadly stable. Instead, the surge coincided with higher Monday demand, hot weather, evening peak tightness, and limited cross-border transfer capacity between lower-priced southern markets and higher-priced Central and Eastern Europe.
Demand growth and evening tightness shift pricing away from midday
Total SEE consumption increased to 34.3 GW, up 3.76 GW day-on-day. Net imports rose to 1.77 GW as several markets moved toward higher import dependence. Hungary reached 5.58 GW of consumption, while Romania and Bulgaria together approached 9.89 GW.
Renewable output remained strong, including 8.30 GW of solar generation, but the system stayed tight during evening hours. The pricing pattern shifted away from midday lows associated with solar output toward scarcity levels at the evening peak. At H21, prices reached €759.3/MWh on HUPX and €766.7/MWh on OPCOM.
Two pricing zones emerge across SEE day-ahead markets
The market split into two pricing zones based on country-level outcomes in day-ahead trading. Hungary and Romania formed a high-price core above €222/MWh, while Croatia and Slovenia followed at €184.01/MWh and €172.59/MWh respectively. Serbia settled at €149.94/MWh, still sharply higher versus the previous session.
Greece and Bulgaria remained in the low-price zone at €86.50/MWh and €90.32/MWh despite both being net exporters. The resulting spreads were wide, with Romania trading €137/MWh above Greece and Hungary about €132/MWh above Bulgaria.
Cross-border flows point to congestion-driven location effects
Cross-border flows indicated that the tightness was not uniform across the region but reflected location and congestion imbalances. Greece exported around 1.72 GW supported by strong renewable generation, while Bulgaria exported 738 MW and acted as a transit corridor toward Romania.
Despite these exports, several markets still imported power: Hungary 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.
At the same time, the region exported 634 MW to Italy, reinforcing bottleneck-driven price divergence across borders.
Serbia’s import position rises alongside intraday peak stress
Serbia’s market position was weaker than suggested by its settlement price alone. Consumption rose to 3.95 GW while generation reached 3.41 GW, leaving Serbia as a net importer of 543 MW.
Peak-hour dependency was higher still, with imports reaching 937 MW during the evening period referenced by H21 pricing levels. Although SEEPEX settled at €149.94/MWh below most Central European markets, intraday stress was visible as peak prices reached €455.1/MWh at H21.
Serbia’s generation mix relied heavily on coal at around 73%, increasing sensitivity to evening demand spikes and import price transmission.
Montenegro exports to Italy amid a wider regional spread
Montenegro remained small in scale but retained strategic relevance through its interconnection with Italy. BELEN settled at €117.67/MWh compared with €156.65/MWh in Italy.
Montenegro was a net importer overall at around 120 MW but still exported approximately 180 MW to Italy, peaking near 296 MW during the session window described by the review.
Forward curve signals continued tightness in Hungary
Forward markets reflected expectations of continued tightness in Hungary through HU Week 27. The 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 indicated that traders were pricing Hungary with exposure beyond a short-lived weather effect, tied to congestion patterns, import dependence, and evening peak risk.
Fuel prices stable; weather remains the near-term driver
Despite the sharp price increase in power markets, gas and EUA prices showed no significant movement during the period described in the review. This supported a view that the rally aligned with power system flexibility constraints rather than upstream cost pressure.
The near-term risk remained conditional on weather conditions for demand levels into early July. Forecasts indicated temperatures would stay high on 30 June, supporting continued demand pressure before easing into early July.