Day-ahead power prices across Southeast Europe and Hungary experienced a significant increase on Monday, reversing the previous weekend’s downward trend. This surge was primarily driven by a dramatic decline in wind generation, which necessitated a shift towards thermal output and higher-cost imports to meet demand.
Hungary’s HUPX market set the pace with a clearing price of €120.45/MWh, establishing itself as the pricing benchmark for the region. Other interconnected markets followed suit, with Serbia’s SEEPEX reaching €109.08/MWh, Croatia’s CROPEX at €106.06/MWh, Slovenia’s BSP at €105.12/MWh, and Romania’s OPCOM at €103.52/MWh. In contrast, southern markets such as Greece, Montenegro, and Albania remained at lower price points, with values of €83.41/MWh, €88.28/MWh, and €78.83/MWh, respectively.
The scale of the price rebound was particularly notable in the western Balkans, where Serbia recorded the largest daily increase of +€44.4/MWh. Hungary followed with an increase of +€36.6/MWh, while Romania saw a rise of +€31.1/MWh. These changes indicate a coordinated regional repricing influenced more by supply constraints than by increased demand.
A sharp contraction in renewable energy output, especially from wind sources, was the fundamental driver behind this market shift. Total regional generation fell to 27,590 MW, down by 966 MW day on day, while consumption hovered around 25,487 MW, leading to greater reliance on imports.
Wind generation plummeted to 1,510 MW, a decrease of 2,785 MW compared to the prior day, significantly reducing low-cost supply options. Although solar generation saw a modest increase to 4,641 MW, it was insufficient to compensate for the loss in wind capacity, particularly during non-daylight hours.
The response from the energy system was characterized by a notable ramp-up in thermal generation. Gas-fired output rose to 2,702 MW (+296 MW), while coal production increased slightly to 4,608 MW (+63 MW). Nuclear generation remained stable at 5,794 MW, and hydroelectric contributions were slightly lower at 5,866 MW. Other sources also saw an uptick in output to 2,469 MW, reflecting additional balancing measures within the grid.
This shift toward higher-cost thermal units resulted in increased marginal costs across the region. The enhanced import dependency was evident as net regional imports reached 1,185 MW, with significant inflows from Austria and Slovakia into Hungary rising to 2,604 MW.
The widening price differential between Hungary and Germany—now around €22–23/MWh—further facilitated the transmission of higher-cost electricity into Southeast Europe, reinforcing upward pricing trends. Despite this surge in prices, overall demand remained relatively weak; regional consumption declined by 1,520 MW day on day, underscoring that the price increases were mainly due to supply-side constraints rather than growth in load.
The intraday price dynamics reflected typical spring volatility but showed pronounced fluctuations. Midday prices softened into the range of €30–40/MWh due to solar contributions; however, evening hours saw sharp spikes as solar output diminished and thermal generation dictated marginal pricing. Peak prices soared above €270/MWh in Hungary and reached between €150–175/MWh across SEE markets, particularly during the evening hours.
The persistent divergence in regional spreads highlighted ongoing interconnection constraints and localized supply-demand balances that limited full market convergence. Hungary continued to command a premium price over its neighbors—Serbia was approximately €11/MWh lower, Croatia and Slovenia were around €14–15/MWh lower, while southern markets experienced discounts exceeding €35/MWh.
The cross-border flow patterns confirmed tightening market conditions within Southeast Europe as it remained a net importer from Central Europe. Increased inflows from Austria and Slovakia into Hungary reinforced its role as a critical transmission hub for higher-cost electricity entering the region.
In contrast to spot market strength, forward markets displayed signs of softening; near-term baseload contracts for Weeks 17–18 and May-26 traded within the range of €90–100/MWh. This indicates that market participants perceive the current price spike as temporary. Gas prices stabilized around €42–47/MWh, while carbon allowances hovered near €77/t. The divergence between spot and forward curves suggests that recent price movements are weather-driven rather than indicative of structural changes.
This session highlighted the growing importance of flexibility among market participants. Assets capable of capitalizing on evening peaks—particularly hydro and gas-fired plants—benefited significantly from the steep ramping demands during peak hours, while those with flat exposure faced heightened risks.
The evolving landscape of power markets in Southeast Europe is increasingly characterized by interactions between renewable intermittency, thermal backup costs, and cross-border import dependencies. As wind output remains volatile, similar patterns are expected to persist in the near future: soft midday pricing coupled with aggressive evening ramps and ongoing sensitivity to flows from Central Europe.
