The SEE power market opened the week with a sharp scarcity-price reset, led by Hungary and Romania, where day-ahead baseload rose to €222.73/MWh on HUPX and €223.54/MWh on OPCOM. Both markets more than doubled versus the previous session, with Hungary up €126.5/MWh and Romania up €127.9/MWh. The move was not fuel-led: gas and EUA indicators were broadly stable. The real driver was the Monday rebound in demand, hot weather, evening ramp scarcity and limited transferability between the low-priced southern markets and the high-priced Central-East corridor.
The regional load signal was decisive. Total SEE consumption was forecast at 34.3 GW, up 3.76 GW day on day, while net regional imports increased to 1.77 GW. Hungary alone moved to 5.58 GW of consumption, while Romania and Bulgaria together reached almost 9.89 GW. The region was still forecast to have strong solar output at 8.30 GW, up 2.16 GW, but this did not protect the evening hours. The spot curve shows the structural problem clearly: solar-heavy midday blocks were no longer the price-setting hours; the scarcity value migrated to the evening peak, where HUPX reached €759.3/MWh at H21 and OPCOM reached €766.7/MWh at H21.
The market split into two clear zones. Hungary and Romania formed the high-price pole, both above €222/MWh. Croatia and Slovenia followed at €184.01/MWh and €172.59/MWh, reflecting their exposure to Central European tightness and import dependence. Serbia settled at €149.94/MWh, materially below Hungary but still up €88.6/MWh day on day. By contrast, Greece and Bulgaria remained the low-price pole, at €86.50/MWh and €90.32/MWh, despite exporting northward. The resulting spread was extreme: Romania traded €137/MWh above Greece, while Hungary traded €132/MWh above Bulgaria.
Flows confirm that the region was not short in aggregate everywhere, but short in the wrong places. Greece exported an average 1.72 GW, supported by a renewables-heavy generation mix, while Bulgaria exported 738 MW and acted as a transit and supply bridge into Romania. Yet the high-price corridor still needed imports: Hungary was a net importer of 1.28 GW, Romania imported 1.04 GW, Croatia imported 1.39 GW, and Serbia imported 543 MW. The main structural flow was from Austria and Slovakia into Hungary/Slovenia, with CORE imports around 2.44 GW, while the region simultaneously exported 634 MW to Italy. That combination points to congestion and shape risk rather than a simple regional energy shortage.
Serbia’s position was weaker than the SEEPEX headline suggests. Serbian consumption rose to 3.95 GW, generation reached 3.41 GW, and the system remained a net importer by 543 MW. Peak-hour import dependence was heavier, with Serbia’s peak net import at 937 MW. SEEPEX’s baseload at €149.94/MWh was below Croatia, Slovenia, Hungary and Romania, but the Serbian price profile still showed a late-day stress point, with a maximum of €455.1/MWh at H21. Serbia’s latest settled generation mix was still coal-heavy, with coal at around 73% of generation on 28 June, making the system more exposed to availability, outages and import price transmission when evening demand rises.
Montenegro remained small but strategically relevant because of the Italy link. BELEN settled at €117.67/MWh, while Italy’s national price was €156.65/MWh, preserving an export incentive toward Italy. Montenegro was still a net importer by 120 MW, but it exported around 180 MW to Italy on average, with peak exports close to 296 MW. The country effectively balanced lower-cost regional imports and hydro/thermal availability against the higher Italian price signal. This makes Montenegro less important as a volume market, but highly relevant as a congestion and arbitrage node between the Western Balkans and Italy.
Forward markets are already pricing Hungary as the stress market. HU Week 27 rose to €152/MWh, up 18.29% over the seven-day comparison, while Germany Week 27 fell to €108.5/MWh and Italy Week 27 to €133.5/MWh. The HU-DE Week 27 spread widened to €43.5/MWh, and the July Hungarian contract stood at €122.5/MWh, roughly €25/MWh above Germany. That spread structure shows traders are treating Hungary not simply as a weather-driven day-ahead spike, but as a market carrying near-term congestion, import-dependence and evening-shape risk.
The fuel complex did not justify the size of the spot move. CEGH gas was near €42.37/MWh, Greek gas at €41.34/MWh, EUA at €80.28/t, and coal forwards were broadly stable. This means the spot spike was mainly a power-system flexibility event. The daily data fits the broader project news in the report: EU storage deployment, Bulgarian and Romanian battery projects, and EPCG’s renewable investment programme are not abstract transition stories; they are direct responses to the value now appearing in evening ramp, congestion management and intraday balancing.
The immediate risk into the next sessions is softer but not eliminated. Temperatures are forecast to remain high on 30 June, with Hungary still around 30.7°C and Serbia close to 29.9°C, before a broader cooling trend into 1–2 July. That should reduce consumption pressure and ease part of the scarcity premium. But the market signal from 29 June is clear: SEE and Hungary are entering a summer pattern in which solar depresses midday, imports set the evening margin, and cross-border constraints decide whether cheap southern power can actually reach the high-price northern load centres.
