Day-ahead electricity prices across south-east Europe softened for delivery 25 June, but the move was less a full market reset than a partial correction from the previous session’s spike. The region remained split between a high-priced Hungarian-Romanian axis, a lower-priced Greece-Bulgaria-Macedonia block and import-sensitive western Balkan markets where cross-border flows, not only domestic fundamentals, continued to shape marginal pricing.
The clearest signal came from Hungary. HUPX baseload settled at €175.72/MWh, down €25.00/MWh day on day, but still the highest price in the covered SEE-Hungary complex. Romania’s OPCOM followed closely at €171.62/MWh, down €29.30/MWh, leaving the two markets effectively as the northern price anchors. The Hungarian premium remained wide: HUPX was €42.18/MWh above Germany, €42.77/MWh above Austria, €54.39/MWh above Greece, €54.15/MWh above Bulgaria and €47.39/MWh above Serbia. That basis structure points to a market still pricing congestion, residual import needs and evening scarcity, even after the day-on-day fall in outright spot values.
The correction was broad across central and western parts of the region. Germany fell sharply to €133.54/MWh, down €74.30/MWh, while Austria dropped to €132.95/MWh, down €59.40/MWh. Slovenia’s BSP price fell €54.40/MWh to €141.04/MWh, Croatia’s CROPEX dropped €48.50/MWh to €147.89/MWh, and Serbia’s SEEPEX declined €27.80/MWh to €128.34/MWh. Bulgaria and Greece also weakened, with IBEX at €121.58/MWh and HENEX at €121.33/MWh. North Macedonia remained the lowest-priced market at €117.96/MWh, while Albania and Montenegro moved against the regional trend: ALPEX rose €33.60/MWh to €140.46/MWh, and BELEN increased €23.60/MWh to €137.27/MWh.
The hourly shape explains why the market did not feel genuinely bearish despite softer baseload settlements. HUPX reached a daily maximum of €506.70/MWh at H20, after falling to a minimum of €38.10/MWh at H14. Romania showed a similar profile, with OPCOM peaking at €472.00/MWh and bottoming near €38.30/MWh. Germany, Austria, Slovenia and Croatia also showed deep solar-hour discounts followed by expensive evening replacement. In practical trading terms, the market was not simply cheaper; it was more sharply shaped. Midday solar compressed prices, while the evening ramp remained expensive enough to keep baseload values elevated.
The regional balance added to that signal. Total consumption was forecast at 32,531 MW, up 557 MW day on day, while the average temperature rose to 26.7°C, up 1.2°C. The system was still a net importer by 255 MW, even as renewable output forecasts improved. Solar was forecast at 7,806 MW, up 1,435 MW, and wind at 2,159 MW, up 627 MW. That combination is important: stronger renewables helped soften the daily average, but they did not eliminate the need for imports or the exposure to evening ramping. The market remained long solar during the middle of the day and short flexible capacity after sunset.
Weather is becoming the main forward driver. The SEE temperature forecast excluding Greece rises from 25.5°C on 25 June to 28.1°C by 28 June. Hungary is forecast to move from 27.1°C to 30.8°C, Serbia from 26.8°C to 29.8°C, Albania from 27.3°C to 29.7°C, and Montenegro from 29.3°C to 31.8°C. Cooling load risk is therefore shifting from a daily spot issue into a prompt-curve issue. The market has already started to price that risk more aggressively in Hungary than in Germany or Italy.
The flow picture confirmed a familiar SEE pattern: Greece and Bulgaria remained the strongest exporters, while Croatia, Serbia, Romania and Hungary absorbed the regional imbalance. Greece exported an average 1,226 MW, Bulgaria exported 1,044 MW, and Bosnia and Herzegovina exported 368 MW. On the import side, Croatia was the largest deficit market at 1,101 MW, followed by Serbia at 653 MW, Romania at 652 MW and Hungary at 514 MW. The region as a whole was only modestly short, but that aggregate number hides important country-level pressure.
Bulgaria’s position was particularly relevant for regional pricing. It remained a net exporter of 1,044 MW, supported by generation of 4,802 MW against consumption of 3,758 MW. The main commercial direction was Bulgaria to Romania, averaging 1,638 MW baseload, while Bulgaria also sent 310 MW to Serbia. At the same time, Bulgaria was absorbing sizeable south-north flows from Greece, with Greece to Bulgaria at 769 MW. That made Bulgaria less a purely domestic surplus market and more a transit and balancing node between Greek supply, Romanian demand and Serbian import needs.
Greece’s low price relative to HUPX was not a sign of weak system importance. It was the opposite: Greece was exporting heavily while still settling at €121.33/MWh, helped by a supply stack in which gas, solar and wind continued to provide regional flexibility. Greece exported 769 MW to Bulgaria, 337 MW to North Macedonia, 110 MW to Albania and 56 MW to Italy. Its price was low enough to pull power north, but not low enough to collapse the wider SEE complex, because transmission constraints and evening ramping preserved large spreads further north.
Serbia remained structurally import-exposed. SEEPEX baseload fell to €128.34/MWh, but Serbia’s power balance showed consumption of 3,675 MW against generation of 3,022 MW, leaving a net import requirement of 653 MW. The country imported from Bulgaria and North Macedonia, while also receiving flows from Bosnia and Herzegovina and Croatia across parts of the day. The Serbian price was therefore pulled in two directions: lower southern and eastern supply helped cap SEEPEX below Hungary and Romania, but the country’s own import requirement prevented a deeper decline toward the Greece-Bulgaria-Macedonia price floor. Peak-hour Serbian import exposure remained material, with the total peak import position above 1,000 MW.
Croatia was the clearest western Balkan deficit market. CROPEX fell to €147.89/MWh, but Croatia still imported an average 1,101 MW, with consumption of 2,473 MW and generation of 1,371 MW. Its price stayed above Serbia, Montenegro, Greece and Bulgaria, reflecting a tighter domestic balance and dependence on surrounding markets. Slovenia moved in the opposite direction, with BSP falling sharply to €141.04/MWh as its system moved back into a small export position of 82 MW on generation of 1,343 MW and consumption of 1,261 MW.
Montenegro and Albania were the countertrend markets. Montenegro’s BELEN price rose to €137.27/MWh even though broader regional prices softened, while Albania’s ALPEX increased to €140.46/MWh. Montenegro’s physical balance showed a net import of 83 MW, but the Italy link remained important, with Montenegro to Italy averaging 179 MW baseload and 500 MW during peak hours. That creates a different price dynamic from inland Balkan markets: Montenegro can be locally short while still sending peak power westward through the subsea route, depending on border schedules and internal allocation. Albania, meanwhile, was a modest net exporter at 116 MW, with generation of 1,075 MW and consumption of 959 MW, but its price rise suggests local and border-driven tightness rather than a simple surplus signal.
Fuel markets did not provide the main bearish driver. CEGH gas eased only €0.40/MWh to €42.85/MWh, Greek gas was broadly stable at €42.16/MWh, EUA prices held at €80.78/t, and API2 coal softened only slightly to €114.50/t for July. The decline in spot power was therefore more a function of improved renewable forecasts, lower German and Austrian prices, and revised flow patterns than a fuel-led repricing of thermal marginal costs. Gas-fired generation remains relevant, especially in Greece and Hungary, but the daily price formation was dominated by shape and congestion.
The forward market showed a more bullish Hungarian signal than the day-ahead fall would suggest. Hungary Week 27 rose €9.50/MWh to €142.00/MWh, while Germany Week 27 fell to €103.00/MWh and Italy Week 27 held at €136.50/MWh. The Hungary-Germany Week 27 spread widened to €39.00/MWh, up €12.50/MWh day on day. Hungary July remained at €120.50/MWh, keeping a €25.00/MWh premium to Germany July at €95.50/MWh, while Hungary Cal 27 stood at €111.50/MWh. The curve is therefore pricing Hungary as the most exposed prompt market in the region, with heat, import constraints and evening scarcity all feeding the premium.
For traders, the immediate market signal is a split between falling average prices and persistent scarcity optionality. Baseload has corrected, but HUPX and OPCOM remain expensive relative to the southern Balkans, and the evening hours continue to carry the real risk. Serbia and Croatia remain import-sensitive, Montenegro is influenced by the Italy cable, and Bulgaria-Greece flows remain central to regional price containment. The next sessions are set around the same structure: cheap solar hours, expensive replacement hours, rising cooling demand and a Hungarian forward curve that is still refusing to price the region as genuinely loose.
