The power markets in Hungary and the broader Southeast Europe (SEE) region witnessed a notable downturn in Week 15 of 2026, primarily influenced by a substantial decline in demand, robust solar generation, and seasonal holiday effects. The HUPX baseload price fell to €92.19/MWh, reflecting a decrease of €21.0/MWh compared to the previous week. Concurrently, the HU-DE spread contracted to €19.71/MWh from €36.64/MWh, indicating shifting market dynamics. Gas prices at CEGH also softened to €49.28/MWh, while EUA prices remained stable at €72.10/t, alleviating some of the thermal cost pressures that had previously bolstered regional pricing.
This week’s developments were not merely a reaction to fuel market fluctuations; rather, they stemmed from a pronounced drop in average load, which decreased to 29,084 MW—a reduction of 4,260 MW from the prior week and the lowest level recorded since September. Contributing factors included the Orthodox Easter holidays, milder weather conditions, and an uptick in prosumer activity. In stark contrast to this diminished demand, solar peak output surged to 8,542 MW, an increase of 2,030 MW week-on-week and 1,951 MW higher than the same period last year. This oversupply led to significant intraday price volatility, with HUPX experiencing 22 hours of negative pricing—double the count from the previous week—highlighting a structural shift towards midday oversupply during the spring shoulder season.
Wind generation presented a contrasting scenario as it plummeted to 1,903 MW, marking a decrease of 1,704 MW week-on-week and representing approximately 23% below seasonal norms. In a tighter market context, this typically would have exerted upward pressure on evening prices; however, the combination of reduced demand and increased solar output negated this effect. The market’s ability to absorb significant wind losses without triggering corresponding price spikes signals that weak wind conditions are no longer automatically bullish unless they coincide with stronger demand or reduced solar output.
Thermal generation also saw significant declines this week. Coal output dropped to 4,375 MW (down 1,378 MW), while gas generation fell to 3,220 MW (down 839 MW). These reductions are attributed to lower consumption levels and maintenance outages impacting unit revenues. As a result, clean spark spreads deteriorated further despite cheaper gas prices because power prices fell more rapidly than gas costs. This trend suggests that thermal plants are increasingly playing a residual role rather than setting prices during daylight hours when high solar output coincides with low demand.
Cross-border trading dynamics have shifted as well; although HUPX remained above German prices for 127 hours during the week, the hourly spreads narrowed significantly—especially during solar hours—with the HU-DE spread averaging €34/MWh in critical hours compared to €59/MWh the previous week. Additionally, spreads with Austria and Poland also contracted sharply, easing pressure on Hungarian premiums despite ongoing maintenance issues affecting grid conditions.
On a regional scale, the export-import balance improved but did not return to normal levels. The SEE bloc remained a net importer at -1,172 MW but showed an improvement of 744 MW from the prior week. Bulgaria and Romania reported notable gains; however, Serbia’s position was described as one of the weakest in the region—its net import levels being the lowest since December 2024. Despite improvements in Hungary and Bulgaria’s positions being noted as their best since July last year, some local markets continue to exhibit structural tightness due to underperformance in hydro or coal generation.
Interestingly, imports from CORE decreased during solar hours even as total flows from CORE reached their second-highest levels since January. Flows toward Ukraine and Moldova increased but remained relatively low by recent standards. These eastbound flows can elevate congestion costs or necessitate activation of more expensive regional units during critical evening periods; however, they were insufficient to counteract the overall downward price trend observed this week.
Pricing across countries reflected a general downward trend with average baseload prices settling at €88.01/MWh in Romania, €91.35/MWh in Serbia, €86.02/MWh in Bulgaria, €84.69/MWh in Greece, and €120.56/MWh in Italy North. Hungary’s pricing remained above most neighboring SEE markets but was still lower than Italy North by €28.4/MWh—a trend particularly evident during solar hours.
The prevailing market conditions indicate a bifurcation into two distinct pricing regimes: midday prices are increasingly influenced by solar oversupply and suppressed visible demand risks leading to negative pricing scenarios; conversely, evening prices are supported by weaker wind generation and limited flexible thermal margins amid constrained cross-zonal transfers. This dynamic results in flatter weekly averages but greater intraday volatility for traders who must adapt their strategies accordingly.
Overall, Week 15 marked a bearish trend for baseload pricing driven by a rapid collapse in demand outpacing supply adjustments and strong solar contributions compensating for lost wind generation during critical pricing hours. As long as gas prices remain around €49/MWh and carbon prices stabilize while holiday or shoulder-season demand persists at low levels, it is likely that daytime prices will continue to reflect this downward trajectory unless there is an unexpected rebound in load or shifts in transmission dynamics.
