The 26 June 2026 SEE day-ahead power session reflected a market that is softening in absolute price terms but remains structurally tight underneath. While spot prices retreated across most of South-East Europe, the underlying signal was not weakness in fundamentals but a clear divergence between a high-priced northern corridor (Hungary, Romania, Italy) and a lower-priced southern Balkan block led by Greece and Bulgaria. Regional demand increased to 33,208 MW, up by 1,127 MW day-on-day, while the system shifted into a net import position of around 444 MW, compared to just 25 MW in the previous session. Strong renewable generation eased midday pricing, but evening scarcity preserved a firm risk premium across the northern and central hubs.
Hungary’s HUPX remained the regional price benchmark at €158.12/MWh, down €17.6/MWh but still the most expensive SEE-linked market. Romania’s OPCOM closely tracked Hungary at €155.80/MWh, while Italy settled at €155.46/MWh, confirming a tight convergence across the northern and western price corridor. This clustering highlights a market where fuel costs have eased, but congestion and evening ramp constraints continue to support elevated marginal pricing across the central European-SEE interface.
In contrast, the southern markets saw a sharp correction. Greece fell to €87.69/MWh (down €33.6/MWh), while Bulgaria dropped to €96.53/MWh (down €25.0/MWh). The widening spreads — €70.43/MWh between Hungary and Greece and €61.59/MWh between Hungary and Bulgaria — reflect not only demand differences but also a structural imbalance: strong daytime solar output in the south combined with limited transmission flexibility to push surplus power northwards into higher-priced markets.
Serbia remained relatively resilient despite regional softness. SEEPEX settled at €127.53/MWh, only marginally lower day-on-day, leaving Serbia positioned below Hungary but still well above Greece and Bulgaria. The market reflects Serbia’s role as a structural importer within the Balkan system, with average net imports around 750 MW and peaks exceeding 1,100 MW. Domestic generation of roughly 3,076 MW against consumption of 3,826 MW underscores continued reliance on coal, supported by hydro and minimal wind output. Serbia effectively acted as a mid-price corridor node, exposed simultaneously to southern low-price flows and northern scarcity pricing.
Intraday curves further reinforced the volatility profile. Hungary and Romania both recorded extreme evening spikes, with prices approaching €500/MWh (Hungary) and €477.5/MWh (Romania) at H21, while midday lows dropped to around €44–45/MWh. Serbia followed a similar but less extreme structure, peaking at €265/MWh, while Greece and Bulgaria saw significantly flatter profiles, including instances of near-zero pricing in Greece and very low midday levels in Bulgaria. This configuration continues to highlight the rising value of flexibility assets such as batteries, hydro modulation, gas peakers and demand response.
Cross-border flows played a decisive role in shaping the day’s structure. The wider SEE region imported heavily from the Austria/Slovakia corridor, while exporting strongly toward Italy. Greece emerged as the largest net exporter at 1,665 MW, followed by Bulgaria at 965 MW and Bosnia and Herzegovina at 299 MW. On the deficit side, Croatia, Serbia, Romania and Hungary absorbed significant imports, reinforcing the split between low-price renewable-exporting south and high-demand central/northern load centres.
Greece’s weak pricing was underpinned by strong renewable availability and export capacity. With consumption of 6,858 MW and generation of 8,523 MW, Greece exported 1,665 MW across multiple borders. Solar output exceeded 2,500 MW and wind contributed nearly 1,200 MW, supported by gas and hydro generation. This allowed Greece to act as a regional price suppressor in daytime hours, exporting surplus renewable energy into Bulgaria, North Macedonia, Albania and Italy.
Bulgaria also maintained a strong export profile, sending power north and west while still absorbing Greek inflows. Its role as both a transit corridor and balancing node reinforced its importance in regional price formation, particularly in managing south-to-north flows toward Romania and Serbia. However, limited northbound capacity continues to restrict full arbitrage of low southern prices into higher-priced central markets.
Romania remained one of the most complex nodes in the system. Despite a relatively high price close to Hungary, OPCOM was shaped by its dual role as both importer and exporter. Romania imported heavily from Bulgaria while exporting into Hungary, positioning itself as a critical transmission corridor between low-price SEE and high-price Central Europe. Its generation mix remained balanced across hydro, nuclear, coal, gas, solar and wind, but not sufficient to eliminate structural import dependence.
Croatia continued to reflect import-driven pricing dynamics. With consumption of 2,555 MW and generation of only 1,335 MW, the system relied heavily on imports from Slovenia, Hungary and regional Balkan flows. CROPEX settled at €141.39/MWh, maintaining a premium relative to southern markets, driven largely by external dependency rather than internal generation conditions.
Montenegro remained structurally sensitive to regional flow volatility. BELEN settled at €128.96/MWh, with modest net imports, while simultaneously engaging in active cross-border exchanges, including significant flows toward Italy. This dual exposure to Balkan and Italian price signals reinforces Montenegro’s position as a hybrid import-export node shaped by hydrology, interconnector availability and Italian market pull.
In the wider fuel complex, conditions eased slightly but did not fundamentally alter power market pricing. Gas benchmarks in Central Europe and Greece softened marginally, EUAs declined slightly, and coal prices eased. However, forward power curves — particularly in Hungary — retained a significant premium over Germany, indicating that the market continues to price structural constraints, ramp risk and evening adequacy concerns rather than fuel costs alone.
Looking ahead, the dominant market feature remains volatility rather than directional trend. Strong solar output continues to compress midday prices, while rising temperatures across Hungary, Romania, Serbia and the Adriatic region support higher evening demand. The most valuable trading window remains the H19–H22 ramp period, where scarcity pricing is most pronounced. The structural split between a low-priced renewable-rich south and a constrained, import-dependent north is likely to persist, with regional flows increasingly determined by transmission capacity, nomination behaviour and intra-hour flexibility rather than simple price convergence.