SEE power prices slide in Week 15 as demand drops and solar output surges

Week 15 2026 brought a clear shift in how power is priced across Hungary and the broader SEE region: prices fell materially, but the driver was not primarily thermal fuel pressure. Instead, the market was overwhelmed by softer seasonal demand, a surge in solar output, and holiday-related effects—pushing midday pricing deeper into oversupply territory.

Baseload weakens and spreads ease

The main move came in Hungary’s HUPX baseload, which dropped to €92.19/MWh, down €21.0/MWh week on week. At the same time, the HU-DE spread narrowed to €19.71/MWh from €36.64/MWh. On the input side, CEGH gas eased to €49.28/MWh and EUA stayed broadly flat at €72.10/t, removing part of the thermal cost pressure that had supported regional prices earlier.

Demand destruction meets solar oversupply

The report stresses that this was not simply a fuel-led correction. Average load in the region fell to 29,084 MW—down 4,260 MW from the prior 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 was also higher than a year earlier by 1,951 MW. The result was a collapse in solar-hour pricing and deeper intraday weakness: on HUPX there were 22 negative-price hours during Week 15, double the previous week’s count. The report also notes that average HUPX prices in hours 14 and 15 turned negative—an indicator that midday oversupply is becoming a more structural feature of the spring shoulder season rather than an occasional event.

Wind falls without triggering a typical price rebound

Wind generation moved in the opposite direction but did not provide offsetting support for prices. Regional wind output 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 this would typically support evening pricing more aggressively; however, Week 15’s demand collapse and solar cannibalisation outweighed that effect. The report frames this as an important trading signal for SEE: weak wind is not automatically bullish unless it coincides with stronger demand or weaker solar.

Thermal generation retreats as economics deteriorate

Thermal output also declined hard alongside lower consumption. Coal generation 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 links these changes to lower consumption levels, weaker unit revenues, and maintenance outages.

Even with cheaper gas compared with earlier periods of pressure, clean spark economics deteriorated further because outright power prices fell faster than gas costs. For front-week and balancing assumptions this matters: thermal plants are increasingly acting as residual units during daylight hours when solar is high and demand is soft. Evening scarcity still exists, but its pricing power appears compressed when much of the rest of the day is structurally oversupplied.

Cross-border spreads narrow amid still-favorable fundamentals

Cross-border price relationships became less extreme even though transfer conditions were not fully restored due to maintenance constraints. While HUPX remained above Germany in 127 hours overall, hourly spread narrowing was especially pronounced during solar hours.

The HU-DE spread in hour H21 averaged €34/MWh versus €59/MWh a week earlier. The AT-DE spread also dropped sharply and PL-DE reached a three-week low—developments that helped ease Hungarian premium pressure. The report attributes most of this narrowing to relative market fundamentals rather than any clean restoration of transfer capability.

Regional flows improve but remain uneven

The export-import picture improved but did not fully normalize across SEE. The bloc remained a net importer at -1,172 MW; however this was 744 MW better than the previous week. Bulgaria and Romania improved materially while Serbia remained among the weakest points—the report describes Serbia’s net position as its lowest since December 2024.

Hungary also improved and Bulgaria’s position was described as its best since July last year. From a trading standpoint this suggests loosening at regional level rather than uniform relief across all local markets; some areas still showed structural tightness where hydro or coal underperformed.

Country pricing converges lower; Italy stays an anchor

Country averages moved broadly lower across Week 15: Romania averaged €88.01/MWh baseload; Serbia €91.35/MWh; Bulgaria €86.02/MWh; Greece €84.69/MWh; and Italy North €120.56/MWh. Hungary remained above most nearby SEE markets but still below Italy North by €28.4/MWh.

The Italy premium narrowed most clearly during solar hours, reinforcing Italy North as the higher-priced anchor for parts of the southern complex—while midday conditions temporarily weaken its pull on Hungary and surrounding markets.

A two-regime market: midday weakness versus evening firmness

The report’s key takeaway is that SEE pricing is increasingly split into two regimes. Midday outcomes are dominated by solar oversupply alongside prosumer suppression of visible demand and negative-price risk. Evening pricing remains supported by weaker wind conditions plus limited flexible thermal margins and still-constrained cross-zonal transfers.

This combination tends to flatten weekly averages while increasing intraday volatility—favoring trading approaches built around solar-hour weakness versus evening firmness rather than relying on a simple directional weekly view.

Net-net, Week 15 was bearish for baseload prices in Hungary and SEE—but not because conditions became comfortable overall. Prices fell because demand collapsed faster than supply tightened and because solar more than offset lost wind during key price-sensitive hours. As long as gas stays near €49/MWh with carbon stable around current levels—and holiday or shoulder-season demand remains soft—the HU+SEE complex is likely to keep producing weaker daytime prices. The main risk highlighted would be a rebound in load, sharper deterioration in transmission conditions, or a scenario where low wind coincides with weaker solar rather than stronger solar.