South-east Europe and Hungary started the week with a sharp rise in day-ahead power prices on 15 June 2026. The change was linked to a market increasingly shaped by hourly price structure rather than broad fuel-driven tightness. The daily pattern showed softer prices during solar-heavy midday hours, alongside higher scarcity value in the post-solar evening ramp.
Day-ahead price recovery across SEE
Hungary was the clearest reference point, with HUPX settling at €91.89/MWh, up €31.9/MWh from Sunday. Romania followed at €90.24/MWh, while Slovenia reached €87.85/MWh and Croatia €87.23/MWh. Greece priced at €86.75/MWh and Bulgaria at €85.71/MWh, with the broader SEE complex repricing upward in a coordinated move.
Italy remained the premium market at €130.02/MWh, while Serbia stood out as the deep regional discount at €53.40/MWh. Serbia’s level was €38.49/MWh below HUPX, widening the spread between the SEE core and the regional low-price node. Italy’s premium over Hungary was about €38.13/MWh, supporting an export signal toward Italy.
Flows to Italy were reported at around 1,055 MW. In parallel, Western Balkans pricing stayed lower, with Albania at €64.56/MWh, Montenegro at €72.50/MWh and North Macedonia at €72.05/MWh. The spreads created visible arbitrage value while also highlighting limits to physical integration through factors such as border capacity and balancing risk.
Imports, consumption and interconnector-linked spreads
The physical balance did not indicate an outright regional supply squeeze. Average regional consumption increased to 28,944 MW, up 3,337 MW from Sunday as weekday load returned. Total net imports fell to 1,652 MW, down 1,325 MW day-on-day.
That combination meant the region paid more while importing less, pointing to load shape and residual-hour tightness as key drivers of the price move. Core imports into the Hungary–Slovenia area from Austria and Slovakia remained material at 2,970 MW. The Hungary–Germany spread narrowed to €17.62/MWh from €34.8/MWh previously.
Hourly curve: midday softness and evening scarcity
The hourly profile on HUPX showed a minimum of just €4.9/MWh at H14, during solar-rich midday hours. Prices then rose to a maximum of €182.2/MWh at H21. The baseload settlement of €91.9/MWh therefore masked a highly distorted intraday curve.
The traditional peak block was weaker at €59.4/MWh, while the off-peak block reached €124.4/MWh. This inversion reflected higher value in morning and evening hours outside the solar-suppressed midday window. The shift was described as a commercial signal for managing the midday trough and covering the evening ramp.
Renewables output and country balance positions
Solar output forecast for the region was 7,296 MW, up 2,812 MW day-on-day. Solar generation compressed prices during daylight hours but did not eliminate scarcity, which moved into later hours when residual demand had to be met by hydro, gas, coal, imports and flexible generation. Wind support was described as modest at 1,160 MW, leaving the evening stack exposed to thermal and import marginality.
Bulgaria and Greece were net contributors, exporting around 489 MW from Bulgaria and about 264 MW from Greece. Croatia was the largest importer at roughly 1,141 MW, followed by Romania at 904 MW, Serbia at 418 MW and Hungary at 269 MW. The HU+SEE area remained net short by 1,652 MW, but less short than on the previous day.
Gas, carbon and forward pricing context
The move was not supported by strong fuel or carbon signals on their own. CEGH Austrian gas stood at €47.65/MWh, Greek gas at €45.5/MWh, while EUA Dec-26 was unchanged at €77.17/t. Hungarian power forwards were softer rather than stronger across multiple tenors.
Week 25 traded at €107.50/MWh, Week 26 at €120/MWh, July 2026 at €119/MWh and Cal-26 at €113/MWh. Coal and gas forwards also eased, limiting support for interpreting the spot rebound as a broad bullish repricing of the forward curve.
Batteries and operational implications for market participants
A storage-relevant spread was visible in HUPX prices, with a midday level of €4.9/MWh against an evening high of €182.2/MWh. Such a range supports battery dispatch economics when degradation, efficiency losses, balancing costs and grid fees are controlled . Batteries charging during solar troughs and discharging into H20-H22 scarcity windows can also reduce imbalance exposure for renewable portfolios.
The same hourly structure affects industrial procurement strategies exposed to Hungary, Romania, Bulgaria, Greece or the Western Balkans . Buyers relying on flat baseload approaches face different risk versus hourly outcomes when midday prices soften but evening costs rise sharply.
Southeast Europe spreads versus Italy and Serbia’s discount
The regional spread to Italy stayed one of the strongest external anchors at €130.02/MWh. Italy continued pricing above the SEE core in a way that preserved export incentives where capacity is secured and nomination risk is managed . At the same time congestion, balancing exposure and documentation requirements were cited as factors reducing value from simple directional trades.
Serbia’s €53.40/MWh level represented a low nominal price point within the region but required testing against interconnector access, local balancing costs, credit risk and carbon or origin documentation quality demanded by EU counterparties .
The 15 June session reflected a market structure where solar output compresses midday prices while scarcity value shifts into post-solar evening hours . Wind variability influenced residual tightness alongside interconnector conditions that affected how power moved toward Italy and other premium zones.
