Day-ahead power prices across Southeast Europe and Hungary surged on Monday delivery, reversing the softer weekend trend as a sharp fall in wind generation forced a system-wide shift toward thermal output and higher-cost imports.
Hungary’s HUPX cleared at €120.45/MWh, leading the regional rally and setting the pricing anchor for Central and Southeast Europe. Prices followed across interconnected markets, 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 to €103.52/MWh. Southern markets remained structurally discounted, with Greece at €83.41/MWh, Montenegro at €88.28/MWh, and Albania at €78.83/MWh.
The rebound was pronounced in scale, particularly in the western Balkans. Serbia posted the largest day-on-day increase at +€44.4/MWh, followed by Hungary at +€36.6/MWh and Romania at +€31.1/MWh, pointing to a coordinated regional repricing driven by supply-side tightening rather than demand expansion.
The fundamental trigger was a sharp contraction in renewable output, led by wind, which forced a rapid rebalancing of the generation mix. Total regional generation stood at 27,590 MW, down 966 MW day on day, while consumption was around 25,487 MW, leaving the system reliant on imports.
Wind output collapsed to 1,510 MW, a drop of 2,785 MW compared to the previous day, removing a critical low-cost supply layer. In contrast, solar generation increased modestly to 4,641 MW, but this was insufficient to offset the wind deficit, particularly outside daylight hours.
The system responded through a clear thermal ramp-up. Gas-fired generation rose to 2,702 MW (+296 MW), while coal generation increased to 4,608 MW (+63 MW). Nuclear output remained stable at 5,794 MW, and hydro contributed 5,866 MW, slightly lower day on day due to hydrological variability. Other generation sources rose sharply to 2,469 MW, indicating additional balancing actions within the system.
This shift in the production stack materially lifted marginal costs across the region, as higher-cost thermal units replaced lost renewable output. The impact was amplified by stronger import dependence, with net regional imports reaching 1,185 MW and core inflows (from Austria/Slovakia into Hungary and further into SEE) rising to 2,604 MW.
At the same time, Hungary—the region’s primary pricing node—pulled more expensive power from the Central European core, with the Hungary-Germany spread widening to around €22–23/MWh. This widening differential effectively transmitted higher-cost electricity into Southeast Europe, reinforcing the upward price trajectory.
Despite the price surge, demand fundamentals remained relatively soft. Regional consumption declined by 1,520 MW day on day, confirming that the price rally was driven almost entirely by supply-side tightening rather than load growth.
Intraday price profiles showed a classic spring pattern but with elevated volatility. Midday hours softened into the €30–40/MWh range in several markets due to solar output, while evening hours saw sharp spikes as solar faded and thermal generation set the marginal price. Peak prices reached above €270/MWh in Hungary and €150–175/MWh across SEE markets, concentrated in the H20–H21 window, highlighting the growing structural importance of evening ramp dynamics.
Regional spreads remained intact despite the broad-based rally. Hungary continued to trade at a premium, with Serbia approximately €11/MWh lower, Croatia and Slovenia around €14–15/MWh lower, and southern markets discounted by more than €35/MWh. This persistent divergence underscores the role of interconnection constraints and localized supply-demand balances in limiting full market convergence.
Cross-border flows confirmed the tightening conditions. The SEE region remained a net importer, particularly from the Central European core, with increased inflows from Austria and Slovakia into Hungary and onward into Southeast Europe. This pattern reinforces Hungary’s role as the primary transmission hub through which higher-cost electricity enters the region.
Forward markets, however, did not mirror the spot strength. Near-term baseload contracts softened slightly, with Week 17–18 and May-26 products trading in the €90–100/MWh range, suggesting that market participants view the current spike as short-lived. Gas prices remained broadly stable around €42–47/MWh, while carbon allowances hovered near €77/t, and coal forwards edged lower. The divergence between spot and forward curves points to a weather-driven price event rather than a structural shift.
For market participants, the session underscored the increasing value of flexibility. Assets capable of capturing evening peaks—particularly hydro and gas-fired generation—benefited from the steep ramp, while flat exposure and unhedged retail positions faced elevated risk during peak hours.
The evolving structure of SEE power markets is becoming increasingly evident. Price formation is now driven by a tight interaction between renewable intermittency, thermal back-up costs, and cross-border import dependency, with Hungary acting as the central transmission and pricing hub. When wind output collapses, the system rapidly transitions to higher-cost generation and imported power, producing synchronized and often sharp price movements across the region.
With wind output expected to remain volatile, similar dynamics are likely to persist in the near term—soft midday pricing, aggressive evening ramps, and continued sensitivity to flows from the Central European core.