The 26 June 2026 SEE day-ahead session showed a broad retreat in spot prices, but not a weak market structure. The real signal was a split between a still-expensive northern corridor — Hungary, Romania and Italy — and a much softer southern Balkan block led by Greece and Bulgaria. Regional consumption rose to 33,208 MW, up 1,127 MW day on day, while the region moved to a net import position of around 444 MW, compared with only 25 MW the previous day. Stronger renewable output softened the midday stack, but the evening ramp kept scarcity value high in the northern and central SEE markets.
HUPX remained the regional price anchor at €158.12/MWh, down €17.6/MWh from the previous session, but still the highest SEE-linked market in the dataset. Romania’s OPCOM was almost fully coupled to Hungary at €155.80/MWh, only €2.32/MWh below HUPX, while Italy rose to €155.46/MWh, just €2.66/MWh under Hungary. That near-convergence between HUPX–OPCOM–Italy is the key market message: fuel prices eased, solar and wind improved, but congestion and evening scarcity still supported the upper price band.
The cheaper end of the region was concentrated in the south-east. Greece fell sharply to €87.69/MWh, down €33.6/MWh, while Bulgaria dropped to €96.53/MWh, down €25.0/MWh. The HUPX–Greece spread widened to €70.43/MWh, while HUPX–Bulgaria stood at €61.59/MWh. That spread is not simply a demand story; it reflects a strong solar-led daytime discount in Greece and Bulgaria, combined with insufficient northbound transmission flexibility to fully arbitrage the lower southern prices into Hungary, Romania and the western Balkans.
Serbia was more resilient than the broader market. SEEPEX slipped only €0.8/MWh to €127.53/MWh, leaving Serbia €30.59/MWh below HUPX but still well above Greece and Bulgaria. The reason is visible in the balance data: Serbia remained a substantial net importer, with exports at –750 MW on average and peak import dependence around –1,197 MW. Domestic Serbian generation was around 3,076 MW against consumption of 3,826 MW, with coal still carrying the system, hydro meaningful but not enough, and wind negligible at roughly 25 MW. Serbia was pulling power from Bulgaria, North Macedonia, Croatia and Bosnia and Herzegovina, while only small volumes moved outward to Romania and Montenegro. In trading terms, Serbia behaved less like a low-price Balkan node and more like an import-dependent mid-price corridor exposed to both HUPX scarcity and southern Balkan liquidity.
The hourly profiles confirm that the day was shaped by solar compression and evening ramp risk. In Hungary, the minimum price occurred around H14 at €44.5/MWh, while the maximum reached almost €500/MWh at H21. Romania followed the same structure, with a €45/MWh low and a €477.5/MWh evening high. Serbia had a lower but still steep profile, with a €45/MWh minimum and a €265/MWh maximum at H21. Greece and Bulgaria were much flatter and cheaper at the top, with Greek prices touching €0/MWh and Bulgaria bottoming at €12.2/MWh, while their evening highs remained around €168/MWh. This is exactly the kind of intraday curve that increases the value of batteries, flexible hydro, dispatchable gas, industrial demand response and cross-border nomination discipline.
The flow picture was equally important. The wider SEE region imported 1,361 MW from the Austria/Slovakia direction, up 795 MW day on day, while exporting 855 MW toward Italy. Greece was the largest exporter in the regional balance at 1,665 MW, followed by Bulgaria at 965 MW and Bosnia and Herzegovina at 299 MW. On the deficit side, Croatia imported around 1,220 MW, Serbia 750 MW, Romania 656 MW and Hungary 565 MW. That structure explains why lower Greek and Bulgarian prices did not collapse the whole region: the cheaper south was exporting, but the expensive north-western and central load pockets still needed imports at constrained borders.
Greece’s low price was backed by a strong export position and a renewable-heavy stack. Greek consumption was 6,858 MW, while generation reached around 8,523 MW, leaving average exports at 1,665 MW. The mix included strong solar output of around 2,513 MW, wind near 1,192 MW, gas at 3,238 MW and hydro around 589 MW. Greece exported heavily to Bulgaria, North Macedonia, Albania and Italy, turning its low domestic spot price into a regional supply signal. Bulgaria also played a transit and export role, with 1,561 MW flowing toward Romania and 370 MW toward Serbia, while still absorbing Greek flows on the southern side.
Romania was more complex. Despite a high spot price close to Hungary, Romania remained a net importer at –656 MW. It imported heavily from Bulgaria while exporting strongly to Hungary, making it a key transit corridor between the lower-price south-east and the higher-price Pannonian market. Romanian consumption reached 5,913 MW, generation stood at 5,257 MW, and the mix remained diversified: hydro around 1,535 MW, solar above 1,037 MW, coal 813 MW, gas 638 MW, nuclear 620 MW and wind 366 MW. The high OPCOM price shows that Romania’s role as a conduit to Hungary can support prices even when domestic renewable and hydro output are not weak.
Croatia remained one of the clearest import-stress markets. Consumption was 2,555 MW, generation only 1,335 MW, and net imports widened to 1,220 MW. CROPEX settled at €141.39/MWh, down €6.5/MWh, but still relatively firm compared with Serbia, Montenegro, Albania and North Macedonia. Croatia was importing from Slovenia and Hungary while also exchanging with Serbia and Bosnia and Herzegovina. Its price position again shows that western Balkan and Adriatic markets are increasingly shaped by cross-border access rather than domestic generation alone.
Montenegro’s BELEN price settled at €128.96/MWh, down €8.3/MWh, with net imports around 82 MW. The Montenegrin balance remains structurally interesting because the system can simultaneously import from neighbouring Balkan markets and export via the Italy interconnector. The data show Montenegro > Italy flows around 352 MW on average, while the country also received power from Bosnia and Herzegovina, Albania, Kosovo and Serbia directions depending on the hour. That keeps Montenegro exposed to both Balkan hydrology/thermal conditions and Italian price pull.
The fuel and forward complex gave some relief but did not erase the power premium. CEGH gas was marked at €42.05/MWh, down €0.8/MWh, Greek gas at €40.99/MWh, down €1.2/MWh, and EUA at €80.56/t, slightly lower by €0.2/t. Coal also softened, with July coal at $113.5/t, down $1/t. Yet the Hungarian forward curve retained a clear premium: HU Week 27 stood at €142/MWh, around €36/MWh above Germany, while HU July 2026 was €120/MWh, about €23/MWh above Germany. The market is therefore not pricing only fuel costs; it is pricing transmission constraints, temperature risk and evening adequacy.
The near-term signal is bullish for volatility rather than uniformly bullish for baseload. Rising temperatures across Hungary, Serbia, Romania and the Adriatic will support cooling demand, while stronger solar keeps midday prices vulnerable to sharp discounts. The highest trading value is likely to remain in the ramp hours, especially H19–H22, where Hungary, Romania, Serbia and Croatia show the clearest scarcity exposure. Greece and Bulgaria remain the main downside pressure points in the daytime stack, but their ability to pull the whole SEE complex lower depends on northbound capacity, nomination behaviour and whether Romania and Serbia can absorb cheaper southern flows without creating new congestion.
