SEE day-ahead power prices rebound as thermal output returns and cross-border flows tighten

South-East Europe’s day-ahead power market staged a broad upward correction on 5 May, but the move was far from uniform. Prices rebounded strongly in the Central and North-Western parts of the region while Southern markets remained comparatively subdued, underscoring a market that is being driven less by shared regional fundamentals and more by intraday renewable volatility, thermal rebalancing and shifting cross-border dynamics.

Day-ahead prices diverge between core and southern balancing zones

Baseload day-ahead prices moved higher across several key trading points. Hungary’s HUPX cleared at 119.28 €/MWh (+4.9 €/MWh day-on-day), while Romania’s OPCOM rose to 118.85 €/MWh (+7.9 €/MWh). The strongest upward pressure appeared in the coupled Central European periphery: Slovenia’s BSP surged to 126.89 €/MWh (+14.6 €/MWh) and Croatia’s CROPEX climbed to 120.43 €/MWh (+10.1 €/MWh).

By contrast, Serbia’s SEEPEX fell to 97.36 €/MWh (-5.7 €/MWh) and Greece’s HENEX edged down to 98.73 €/MWh (-0.2 €/MWh). The result was a widening spread between core and southern balancing zones—an outcome consistent with a tightening system in the Central European corridor where reduced renewable output and higher thermal dispatch pushed marginal costs up, while localized oversupply and structural export positions continued to weigh on southern pricing.

Generation mix flips toward thermal flexibility as wind drops

The price shift tracked changes in the generation stack. Total regional generation increased to 28,155 MW, up by 2,541 MW versus the previous day, driven by a sharp rebound in dispatchable capacity. Coal-fired generation rose to 4,632 MW (+1,032 MW) and gas-fired output increased to 3,015 MW (+651 MW), signaling that thermal units were back as marginal price setters.

At the same time, renewables moved in opposite directions. Solar production jumped to 6,153 MW (+1,448 MW), supported by favorable daylight conditions, while wind output collapsed to 1,786 MW (-1,318 MW). This “dual regime” helps explain both intraday suppression during sunny hours and the need for rapid thermal ramping later in the day.

The “duck curve” effect lifts evening peaks

With solar pushing prices down around midday and wind weakness requiring thermal support into evening hours, hourly profiles across HUPX, BSP and OPCOM reflected a pronounced duck-curve pattern. Evening peaks in the H20–H22 range frequently exceeded 150–300 €/MWh compared with significantly lower midday levels—an intraday volatility profile that tends to reward flexibility.

Demand rises slightly as supply tightens during key hours

Demand also contributed modestly to tighter balances. Regional consumption increased to 28,500 MW (+551 MW day-on-day), supported by slightly warmer temperatures averaging between 17°C and 18°C across the region. While still within shoulder-season norms, higher load combined with reduced wind availability helped tighten supply-demand conditions during critical hours.

Cross-border flows remain crucial—yet show signs of changing structure

Cross-border trading continued to shape price formation through import dependence into the SEE region. Total net imports were recorded at -145 MW—still structurally import-dependent even if import intensity was slightly lower than in prior sessions.

Core imports from Austria and Slovakia into SEE stood at 663 MW, highlighting continued reliance on Central European inflows for balancing needs.

Country-level balances showed persistent asymmetries: Romania averaged around +1,160 MW of exports and Greece around +686 MW of exports, both supported by relatively favorable spreads versus domestic pricing conditions described in the report. Serbia remained a structural importer at roughly -605 MW on average.

The article also pointed to an emerging factor complicating traditional interpretations of flow data: storage charging. In Bulgaria, battery systems are absorbing significant electricity volumes during low-price periods—functioning as flexible demand—so imports may reflect strategic charging rather than a system deficit.

Fuel-cost signals are mixed; flexibility remains central

Fuel and carbon markets provided a mixed backdrop for marginal generation costs. The Austrian gas hub (CEGH) rose to 47.47 €/MWh (+2.7 €/MWh), offering upward support for gas-fired dispatch economics. EU carbon allowances (EUA) declined slightly, easing some pressure on coal and lignite generation; overall effects were described as broadly neutral to mildly bullish for power prices.

Outlook: renewable uncertainty will keep fragmentation alive

The report framed current conditions as part of a late-spring transition where renewables remain the main source of volatility—especially wind output as the primary uncertainty factor. Any recovery in wind could compress prices quickly and reduce spreads; continued low wind would sustain reliance on thermal generation and keep elevated price levels intact.

Near-term expectations were placed within a broad 90–130 €/MWh range for price outcomes amid significant intraday volatility and potential localized spikes. Structural fragmentation across South-East Europe is expected to persist despite ongoing integration efforts.

Overall market structure is being defined by three interacting forces: renewable intermittency reshaping intraday curves (with solar suppressing midday pricing), thermal flexibility reasserting itself as marginal supply when wind weakens (driving evening spikes), and cross-border constraints influencing how those imbalances translate into regional spreads—while growing storage capacity further alters flow patterns through optimized charging and discharging strategies.