Southeast European day-ahead electricity prices moved sharply higher for Wednesday, 26 August, with the main Hungary–Romania–Bulgaria–Greece cluster consolidating around €184–187/MWh, as stronger cross-border demand, reduced regional net imports and a steep late-evening price ramp outweighed improving nuclear availability in Hungary.
Hungary’s HUPX day-ahead baseload settled at €184.04/MWh, up €8.70/MWh day on day. Romania was the most expensive market in the central SEE cluster at €186.50/MWh, rising €11.50/MWh, followed by Bulgaria at €185.33/MWh, up €11.60/MWh, and Greece at €184.47/MWh, up €10.70/MWh. Croatia gained €7.50/MWh to €182.56/MWh, while Slovenia rose €6.10/MWh to €181.82/MWh. The six markets were therefore compressed into a narrow band of less than €5/MWh, pointing to strong price convergence across the core Hungary–SEE trading area.
The rise was not driven by a significant increase in regional electricity demand. Forecast consumption across Hungary and SEE increased by only 100 MW day on day to an average 33.755 GW, while the regional temperature forecast eased slightly. Instead, cross-border positioning became less comfortable. Total net imports into the region fell by 182 MW to 2.521 GW, even as inflows from the Austria-Slovakia core increased by 354 MW to 3.235 GW. At the same time, exports towards Italy increased by about 446 MW, from 651 MW to 1.097 GW.
That combination is important for the price signal. More electricity was entering the northern part of the SEE system from Central Europe, but a larger volume was simultaneously being drawn south-west towards the higher-priced Italian market. Italy was assessed at €198.08/MWh, around €14.03/MWh above HUPX, giving traders a strong economic incentive to maintain westbound and south-westbound flows where capacity was available. Germany, in contrast, remained at only €153.65/MWh, leaving Hungary at a substantial €30.39/MWh premium to the German day-ahead market. Austria, at €178.19/MWh, sat much closer to Hungary.
The resulting structure left SEE positioned between relatively cheaper German supply and materially more expensive Italian demand. The HU-DE spread of €30.39/MWh narrowed by around €3.60/MWh from the previous session but remained large enough to support continued south-eastward imports. At the other end of the system, the Italian premium over Hungary widened the economic pull on electricity available in Slovenia, Croatia and the Western Balkans.
The hourly curves provide an even clearer explanation for the elevated baseload prices. HUPX fell to a daily minimum of €129.90/MWh in hour 14, but then climbed sharply as solar production faded, reaching €246.50/MWh in hour 23. The Hungarian peak-load average was only €169.20/MWh, while the off-peak product averaged a much higher €198.90/MWh, reflecting the unusually expensive late-evening hours included in the off-peak block.
Romania showed an almost identical profile. OPCOM fell to €124/MWh in hour 14 before reaching €251.80/MWh in hour 23. Its off-peak average of €205.10/MWh was substantially above the €167.90/MWh peak average. Bulgaria recorded a minimum of €124.30/MWh and a maximum of €249.10/MWh, also in hour 23, while Greece ranged from €121/MWh around the solar-heavy middle of the day to €250/MWh in the evening.
The profile charts across the spot markets therefore show a market increasingly defined by the solar ramp rather than by the conventional working-day peak. Midday renewable output continues to suppress prices, but the withdrawal of solar generation creates a steep requirement for dispatchable generation and imports between roughly hours 19 and 23. For short-term traders, the most valuable scarcity hours are consequently shifting further into the evening.
Renewables provided a mixed signal for Wednesday. Regional solar output was forecast at around 7.923 GW, an increase of approximately 1.453 GW day on day, but wind was forecast to collapse by about 867 MW to just 1.137 GW. The net renewable increase was therefore considerably smaller than the solar headline suggested, while most of the additional photovoltaic production was concentrated in hours when power prices were already at their daily lows.
The latest available generation mix also showed the system increasingly relying on dispatchable capacity. Coal generation rose by 577 MW to 7.218 GW, gas-fired generation increased by 539 MW to 5.248 GW, and nuclear output increased by 298 MW to 4.055 GW. Wind generation, by contrast, dropped 766 MW to 2.003 GW, solar declined 389 MW to 6.470 GW, while hydro slipped 137 MW to 4.945 GW.
The thermal increase is significant because it means that the marginal SEE price remains exposed to gas, coal and carbon even during a period of strong installed solar output. The CEGH gas marker stood at €68.02/MWh, down €1.10/MWh on the session, while the Greek gas marker rose €3.40/MWh to €65.43/MWh. EU allowances were at €84.42/t, up €0.60/t. September coal stood at $127.50/t, up $0.50, while the Q4 product eased to $128/t. The mixed direction in the underlying fuel complex suggests that Wednesday’s sharp power move was more closely associated with short-term physical balancing and hourly scarcity than with a broad increase in generation costs.
Hungary is particularly notable because prices increased despite the continuing recovery of the Paks nuclear plant. Three reactors were already operating close to full capacity on 25 August, with units 1-3 producing around 1,448 MW, while unit 4 had restarted and was producing roughly 244 MW, taking site output to around 1.69 GW. Full production of around 2 GW was expected to be restored shortly as Danube conditions improved.
The Hungarian generation data show nuclear production averaging approximately 1.632 GW on 25 August, compared with 1.304 GW a day earlier and only 828 MW on 23 August. Yet Hungary remained a sizeable net importer for 26 August, at around 942 MW on average.
This is an important change in the trading narrative around Paks. During the earlier low-Danube restrictions, reduced nuclear availability was an obvious bullish factor for HUPX. The 26 August market indicates that restoring nuclear output alone is not sufficient to remove Hungary’s premium. Hungary remains embedded in a wider regional system in which cheaper electricity arriving from Slovakia and Austria can be transmitted onwards towards Romania, Croatia, Serbia and Slovenia, while Italy continues to provide a higher-priced outlet further south-west.
Romania was one of the clearest tightening points. Its system moved to an average net import position of around 751 MW on 26 August, compared with only 290 MW on the previous day, while consumption increased to approximately 5.94 GW. The higher Romanian requirement is consistent with OPCOM trading €2.45/MWh above HUPX, while commercial Hungary-to-Romania flows reached around 756 MW baseload, including more than 1.4 GW during off-peak periods.
Bulgaria remained structurally stronger, exporting an average 896 MW, although this was down from 1.018 GW a day earlier. Greece was close to balanced at an average net import of only 25 MW. Hungary imported 942 MW, Croatia around 945 MW, and Serbia approximately 426 MW, leaving the combined Hungary-SEE region with its 2.521 GW net import requirement. The regional balance chart on page 2 of the daily data highlights this split between Bulgaria’s export position and the sizeable import requirements of Hungary, Croatia, Romania and Serbia.
The Western Balkan exchanges remained substantially cheaper than the tightly coupled central SEE cluster. Serbia’s SEEPEX increased only €4.80/MWh to €162.78/MWh, leaving it €21.26/MWh below HUPX. North Macedonia’s MEMO gained €3.80/MWh to €169.31/MWh, a €14.73/MWh discount to Hungary, while Montenegro’s BELEN rose €11.60/MWh to €176.23/MWh, still €7.82/MWh below HUPX.
Albania was the major exception to the regional rally. ALPEX fell €17/MWh to €153.65/MWh, widening its discount to HUPX to more than €30/MWh. Serbia’s hourly profile ranged from a minimum of €113.10/MWh in hour 12 to a maximum of €228/MWh in hour 20, while Montenegro ranged from €130/MWh to €230/MWh. North Macedonia reached as high as €240.50/MWh, despite its lower baseload average.
The divergence confirms that the Western Balkans remain only partially exposed to the price formation of the HUPX-OPCOM-IBEX-HENEX core. The economic price signal remains north-south rather than uniform: cheap German electricity at around €154/MWh, a central SEE cluster at roughly €182–187/MWh, discounted Western Balkan markets between €154 and €176/MWh, and Italy close to €198/MWh.
The short-term forward curve also strengthened. Hungarian Week 36 rose €7.50/MWh to €154/MWh, Week 37 gained €5/MWh to €156/MWh, and September increased €2/MWh to €165/MWh. By contrast, Calendar 2026 slipped €0.50/MWh to €133/MWh.
That steepening at the front while the calendar remained stable is consistent with a market pricing near-term operational tightness rather than a broad structural repricing of power. The most immediate variables are wind availability, the final restoration of Paks, Romania’s import requirement and the volume of SEE electricity continuing towards Italy.
For the next trading sessions, the principal risk remains concentrated in the evening ramp. Strong solar generation can continue to depress hours 12-16, but Wednesday’s curves demonstrate that this does little to eliminate scarcity once photovoltaic output disappears. With HUPX, OPCOM and IBEX all approaching or exceeding €250/MWh in individual late-evening hours, the spread between midday and evening is increasingly as important for trading strategy as the conventional country-to-country baseload spread.
