The 30 June 2026 daily data show a sharp scarcity-driven repricing across the northern and central SEE corridor, with HUPX at €290.71/MWh, up €68/MWh day on day, and Romania’s OPCOM at €293.44/MWh, up €69.9/MWh, making Romania the highest-priced market in the monitored set. Serbia also moved aggressively, with SEEPEX rising to €250.98/MWh, up €101/MWh, while Croatia and Slovenia cleared close to Hungary at €263.03/MWh and €262.05/MWh respectively. The market split was severe: Albania stayed at only €116.33/MWh, Greece at €137.72/MWh, Bulgaria at €148.44/MWh, North Macedonia at €148.05/MWh, and Montenegro at €157.14/MWh. That left Hungary trading more than €142/MWh above Bulgaria, almost €153/MWh above Greece, and more than €174/MWh above Albania.
The core signal is not only higher demand, but congestion and evening scarcity. Regional HU+SEE consumption increased to 35,949 MW, up 1,175 MW from the previous day, while the system’s net import position deepened to 2,859 MW, an increase of 1,023 MW. Imports from the Core direction, mainly AT+SK into HU+SI, reached 2,946 MW, confirming that Hungary and the northern SEE belt were pulling heavily from Central Europe. At the same time, the HU-DE spot spread widened to €103.38/MWh, showing that Hungarian scarcity was much more acute than the German market signal.
The hourly shape is especially important. The spike was concentrated in the evening ramp rather than in the solar-heavy midday period. Hungary’s HUPX reached a maximum of €923.10/MWh at H21, Romania reached €954.60/MWh at H21, Croatia reached €946.60/MWh, Slovenia reached €1,041.50/MWh, and Serbia reached €800/MWh. This explains the unusual structure where off-peak averages were higher than peak averages in several markets: in Hungary, off-peak cleared at €320.80/MWh, above the peak average of €260.60/MWh, because the evening scarcity hours sit outside the standard peak block. The data point to a classic summer ramp problem: solar supports midday balance, but the post-solar evening interval becomes highly exposed to import limits, gas/thermal availability, and cross-border congestion.
Country balances show where the stress was concentrated. Hungary was the largest importer at 1,841 MW, with consumption at 5,819 MW and domestic generation at only 3,977 MW. Romania was also structurally short, with consumption at 6,605 MW, generation at 5,225 MW, and net imports of 1,380 MW, despite strong hydro output and substantial imports from Bulgaria. Croatia remained heavily short as well, importing 1,336 MW against consumption of 2,814 MW and generation of 1,478 MW. Serbia imported 697 MW, with consumption at 4,046 MW and generation at 3,348 MW, which explains why SEEPEX moved sharply even though Serbia’s absolute price remained below Hungary, Romania, Croatia and Slovenia.
The opposite side of the system was Greece and Bulgaria. Greece exported 1,620 MW, with consumption of 7,425 MW and generation of 9,045 MW. Its production stack was supported by high gas, solar and wind output, including 2,837 MW of gas, 2,880 MW of solar, and 2,219 MW of wind on the prior-day detailed balance line. Greece remained a comparatively low-priced market at €137.72/MWh, even while exporting northward through Bulgaria, Albania, North Macedonia and Italy. Bulgaria exported 801 MW and cleared at €148.44/MWh, functioning as a regional transit and supply market: the data show a very large BG > RO flow of 1,855 MW, while Bulgaria simultaneously absorbed power from Greece on the GR > BG direction.
For Serbia, the trading implication is clear: the country was caught between lower-priced southern supply and high-priced northern scarcity. SEEPEX at €250.98/MWh was far above Greece, Bulgaria, Montenegro, Albania and North Macedonia, but still below Hungary, Romania, Croatia and Slovenia. Serbia’s net import position of 697 MW and its evening maximum of €800/MWh indicate that the Serbian market followed the regional ramp-stress pattern, with cross-border access and evening adequacy more important than average daily generation alone. The key corridor signals were negative flows toward Bosnia, Croatia, Bulgaria, North Macedonia and Montenegro on a net basis, while Serbia retained limited export direction toward Hungary and Romania in some blocks, reflecting constrained, hour-specific arbitrage rather than a simple surplus or deficit story.
Forward markets confirmed that the prompt Hungarian risk premium is no longer only a day-ahead event. HU Week 29 rose to €144/MWh, up €20/MWh day on day, while HU July 2026 rose to €135/MWh, up €12.5/MWh. The HU-DE July spread reached €30/MWh, and the HU-DE Week 29 spread reached €27.5/MWh. Longer-dated products were much calmer, with HU Cal-27 at €111/MWh, which means the market is pricing the shock as a front-summer congestion and adequacy issue rather than a structural repricing of the full forward curve.
Fuel and carbon did not fully explain the spot move. CEGH gas rose to €43.95/MWh, Greek gas to €43.84/MWh, and coal forwards moved higher, but EUA fell to €78.78, down €1.5/MWh day on day. That combination points to physical power scarcity, interconnection limits and evening ramp pressure as the dominant drivers, rather than a pure carbon-led marginal cost increase. The weekly carbon section also notes that EU allowances were holding near €80/t, but with a neutral-to-bearish short-term outlook as heatwave effects were expected to ease in parts of Europe.
The next trading signal will depend on whether the forecast cooling materialises. The weather tables show the SEE+HU average excluding Greece easing from around 29.0°C on 30 June to 26.2°C on 1 July and near 22.7°C afterwards, while Hungary is shown falling from 31.1°C to 27.7°C and then near 22°C. That should reduce cooling demand and soften the most extreme evening scarcity risk. However, if Hungary, Romania, Croatia and Serbia remain structurally short while solar ramps down into H20-H22, the market can still retain a high evening premium even with lower average temperatures.