The weekly power trade in Hungary and the wider SEE region turned materially softer in WK15 2026, with the market driven less by fuel stress and more by a sharp seasonal collapse in demand, strong solar output, and holiday effects. The key move was in HUPX baseload, which fell to €92.19/MWh, down €21.0/MWh week on week, while the HU-DE spread narrowed to €19.71/MWh from €36.64/MWh. At the same time, CEGH gas eased to €49.28/MWh and EUA remained broadly flat at €72.10/t, removing part of the thermal cost pressure that had supported regional prices earlier.
What stands out is that this was not simply a fuel-led correction. The region’s average load dropped to 29,084 MW, down 4,260 MW from the previous week and the lowest level since September, helped by Orthodox Easter holidays, slightly milder temperatures, and stronger prosumer activity. Against that weaker demand base, solar peak output jumped to 8,542 MW, up 2,030 MW week on week and 1,951 MW above the same week last year. That combination crushed solar-hour pricing and produced much deeper intraday weakness, including 22 negative-price hours on HUPX, double the previous week’s count. The report notes that average HUPX prices in hours 14 and 15 turned negative, which is a strong signal that midday oversupply is no longer an occasional event but a structural feature of the spring shoulder season.
Wind told the opposite story. Regional wind generation fell sharply to 1,903 MW, down 1,704 MW week on week, making it the second-lowest level of the year and about 23% below seasonal norms. In a tighter market that would usually have supported evening prices more aggressively, but this week the demand collapse and solar surge overwhelmed that effect. In other words, the market absorbed a major loss of wind without producing a proportionate price spike because load destruction and solar cannibalisation were stronger. That is an important trading signal: for now, in SEE, weak wind is no longer automatically bullish unless it coincides with stronger demand or weaker solar.
Thermal generation also retreated hard. Coal output fell to 4,375 MW, down 1,378 MW week on week, while gas generation dropped to 3,220 MW, down 839 MW. The document explicitly links this to lower consumption, weaker unit revenues, and maintenance outages. Clean spark economics deteriorated further despite cheaper gas, because outright power prices fell faster than gas. That matters for front-week and balancing assumptions: thermal plants are increasingly becoming residual rather than price-setting units during daylight hours, especially when solar is high and demand is soft. Evening scarcity still exists, but its pricing power is now compressed when the rest of the day is structurally oversupplied.
Cross-border spreads also became less extreme. Although HUPX remained above Germany in 127 hours, the hourly spread narrowed materially, especially in solar hours. The report highlights that HU-DE spread in the critical H21 hour fell to €34/MWh on average, down from €59/MWh a week earlier. At the same time, AT-DE spread dropped sharply, and PL-DE spread was at a three-week low, both helping ease Hungarian premium pressure. Even with some improvement in DE-HU MaxExchange, grid conditions remained unfavorable due to maintenance, so the narrowing was driven more by relative market fundamentals than by any clean restoration of transfer capability.
Regionally, the export-import picture improved but did not fully normalize. The SEE bloc remained a net importer at -1,172 MW, but that was 744 MW better than the week before. Bulgaria and Romania improved materially, while Serbia remained one of the weaker points, with the report describing its net position as the lowest since December 2024. Hungary also improved, and Bulgaria’s position was described as the best since July last year. From a trading perspective, that means the regional balance loosened, but not evenly. Some local markets still carried structural tightness, particularly where hydro or coal underperformed.
A useful nuance in the report is that imports from CORE declined in solar hours, yet total flow from CORE remained the second-highest since January. Meanwhile, flows toward Ukraine and Moldovarose but stayed relatively low by recent standards. This matters because the report argues those eastbound flows tend to increase congestion costs or force activation of more expensive regional units, especially in critical evening hours. For WK15, however, those flows were not strong enough to prevent the broader downtrend in prices.
Country pricing showed broad convergence lower. In WK15, average baseload settled 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 remained above most nearby SEE markets but still below Italy North by €28.4/MWh, with that Italy premium narrowing most clearly during solar hours. This reinforces the idea that Italy remains the higher-priced anchor for the southern complex, but midday solar is temporarily weakening its pull on the HU/SEE bloc.
The clearest trading takeaway is that the market is now split into two regimes. Midday pricing is increasingly dominated by solar oversupply, prosumer suppression of visible demand, and negative-price risk, while evening pricing remains supported by the weaker wind backdrop, limited flexible thermal margins, and still-constrained cross-zonal transfers. That creates a flatter weekly average but much more volatile intraday structure. For traders, this favors strategies built around solar-hour weakness versus evening firmness, rather than a simple directional bullish or bearish weekly view.
Net-net, WK15 was a bearish week for baseload, but not because the system became comfortable in an absolute sense. It became cheaper because demand collapsed faster than supply tightened, and because solar more than offset the loss of wind during the most price-sensitive hours. As long as gas stays near €49/MWh, carbon remains stable, and holiday or shoulder-season demand stays soft, the HU+SEE complex is likely to keep printing weaker daytime prices. The real risk to that pattern would be a rebound in load, a sharper deterioration in transmission, or a week where low wind coincides with weaker solar rather than stronger solar.