Day-ahead power prices across Southeast Europe and Hungary experienced a significant uptick on Monday, reversing the previous weekend’s downward trend. This surge was primarily triggered by a sharp decline in wind generation, which prompted a systemic shift towards thermal generation and increased reliance on higher-cost imports.
Hungary’s HUPX market led the regional price rally, clearing at €120.45/MWh. This set a pricing benchmark for Central and Southeast Europe, with Serbia’s SEEPEX rising to €109.08/MWh, Croatia’s CROPEX to €106.06/MWh, Slovenia’s BSP to €105.12/MWh, and Romania’s OPCOM reaching €103.52/MWh. In contrast, southern markets remained discounted, with Greece at €83.41/MWh, Montenegro at €88.28/MWh, and Albania at €78.83/MWh.
The increase in prices was particularly notable in the western Balkans, where Serbia recorded the largest day-on-day jump of +€44.4/MWh. Hungary followed with an increase of +€36.6/MWh, while Romania saw a rise of +€31.1/MWh. This coordinated regional repricing reflects tightening supply conditions rather than an expansion in demand.
A critical factor behind this price spike was the substantial contraction in renewable energy output, notably from wind sources. Total generation capacity across the region decreased to 27,590 MW, down by 966 MW from the previous day, while consumption was around 25,487 MW, necessitating increased imports.
Wind generation plummeted to 1,510 MW, marking a significant drop of 2,785 MW, which eliminated an essential low-cost energy source. Although solar output rose modestly to 4,641 MW, it was insufficient to compensate for the loss of wind energy during non-daylight hours.
The market responded with a pronounced thermal ramp-up; gas-fired generation increased to 2,702 MW (+296 MW), while coal generation rose slightly to 4,608 MW (+63 MW). Nuclear output remained stable at 5,794 MW, and hydroelectric contributions were recorded at 5,866 MW, slightly lower due to hydrological variability. Other sources of generation also saw increases totaling 2,469 MW.
This transition towards higher-cost thermal generation resulted in elevated marginal costs regionally as more expensive thermal units replaced lost renewable output. The situation was exacerbated by heightened import dependence; net regional imports reached 1,185 MW, with core inflows from Austria and Slovakia into Hungary surging to 2,604 MW.
<pHungary's role as the primary pricing hub became evident as it drew more expensive electricity from Central Europe, leading to a widening spread between Hungary and Germany of approximately €22–23/MWh. This differential effectively transferred higher electricity costs into Southeast Europe and reinforced upward price trends.
Despite these price increases, underlying demand fundamentals remained relatively weak. Regional consumption fell by 1,520 MW day on day, indicating that the recent price rally was largely driven by supply-side constraints rather than rising demand.
The intraday price dynamics reflected typical spring patterns but exhibited considerable volatility. Midday prices softened into the range of €30–40/MWh, thanks to solar output; however, evening hours experienced sharp spikes as solar energy diminished and thermal generation dictated pricing dynamics. Peak prices soared above €270/MWh in Hungary and ranged between €150–175/MWh across SEE markets during peak hours.
The divergence in regional spreads persisted despite the broad-based price rally. Hungary maintained a premium pricing position with Serbia about €11/MWh lower , Croatia and Slovenia trading around €14–15/MWh lower , while southern markets were discounted by over €35/MWh . This ongoing disparity highlights interconnection limitations and localized supply-demand conditions that hinder full market alignment.
The tightening market conditions were further evidenced by cross-border flows; the SEE region remained a net importer from Central Europe with increased electricity inflows from Austria and Slovakia into Hungary before being distributed throughout Southeast Europe. This trend solidifies Hungary’s pivotal role as a transmission hub for higher-cost electricity entering the region.
The forward markets did not reflect the spot strength observed; near-term baseload contracts softened slightly with Week 17–18 and May-26 products trading in the range of €90–100/MWh . This suggests that market participants anticipate the current spike may be temporary. Gas prices stabilized around €42–47/MWh , carbon allowances hovered near €77/t , while coal futures edged lower . The disparity between spot prices and forward contracts indicates this price movement is likely weather-driven rather than indicative of fundamental changes in market structure.
This recent session highlighted the increasing importance of flexibility within power markets. Assets capable of capitalizing on evening peak demands—particularly hydroelectric and gas-fired plants—benefited from steep price ramps during peak hours while those with flat exposure faced heightened risks during these periods.
The evolving landscape of power markets within Southeast Europe is becoming increasingly apparent as pricing mechanisms are shaped by interactions among renewable intermittency, thermal backup costs, and import dependencies from neighboring regions. As wind output remains volatile, similar dynamics are expected to persist short-term—characterized by soft midday pricing coupled with aggressive evening ramps influenced by flows from Central European markets.
