A broad upward correction swept across South-East European day-ahead power markets on 5 May, with prices rebounding sharply in the Central and North-Western parts of the region while Southern markets remained comparatively subdued. The divergence highlights a system increasingly driven by intraday renewable volatility, thermal rebalancing and evolving cross-border dynamics rather than uniform regional fundamentals.
Day-ahead baseload prices moved decisively higher in key hubs, with Hungary (HUPX) clearing at 119.28 €/MWh (+4.9 €/MWh day-on-day), while Romania (OPCOM) rose to 118.85 €/MWh (+7.9 €/MWh). The strongest upward pressure was visible in the coupled Central European periphery, where Slovenia (BSP) surged to 126.89 €/MWh (+14.6 €/MWh) and Croatia (CROPEX) reached 120.43 €/MWh (+10.1 €/MWh). In contrast, Serbia (SEEPEX) declined to 97.36 €/MWh (-5.7 €/MWh) and Greece (HENEX) edged down to 98.73 €/MWh (-0.2 €/MWh), reinforcing the widening spread between the core and southern balancing zones.
This re-emerging price fragmentation reflects a tightening system in the Central European corridor, where reduced renewable output and increased thermal dispatch pushed marginal costs higher, while localized oversupply and structural export positions continued to weigh on southern pricing.
The fundamental shift on the day was visible in the generation stack. Total regional generation climbed to 28,155 MW, increasing by +2,541 MW compared to 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 a clear return of thermal units as marginal price setters. At the same time, solar production surged to 6,153 MW (+1,448 MW), reflecting favorable daylight conditions, while wind output collapsed to 1,786 MW (-1,318 MW), marking one of the most significant day-on-day drops in recent sessions.
This combination of rising solar generation and declining wind output created a pronounced “dual regime” in the system. Midday hours were characterized by solar-driven price suppression, while evening hours required rapid thermal ramping, leading to elevated peak prices and increased volatility. Hourly price profiles across HUPX, BSP and OPCOM confirm this pattern, with evening peaks in the H20–H22 range frequently exceeding 150–300 €/MWh, compared to significantly lower midday levels.
Demand conditions provided additional support to the upward price movement. Regional consumption increased to 28,500 MW (+551 MW day-on-day), reflecting slightly warmer temperatures across the region, averaging between 17°C and 18°C. While still within shoulder-season norms, the incremental rise in load, combined with reduced wind availability, contributed to tighter supply-demand balances during critical hours.
Cross-border flows continued to play a decisive role in shaping regional price formation. The system remained structurally import-dependent, with total net imports recorded at -145 MW, although this represented a slight reduction in import intensity compared to previous sessions. Core imports from Austria and Slovakia into the SEE region stood at 663 MW, underscoring the continued reliance on Central European inflows.
A closer look at country-level balances reveals persistent asymmetries. Romania maintained a strong export position, averaging around +1,160 MW, supported by a stable generation mix and relatively lower marginal costs. Greece also remained a net exporter at approximately +686 MW, benefiting from lower domestic pricing and favorable regional spreads. In contrast, Serbia continued to operate as a structural importer, with flows averaging around -605 MW, reflecting limited domestic flexibility and dependence on external balancing resources.
These flow patterns are increasingly influenced by emerging structural changes in the region, particularly the growing role of energy storage. Developments in Bulgaria illustrate this shift clearly, where battery systems are now absorbing significant volumes of electricity during low-price periods, effectively acting as flexible demand. This dynamic alters traditional interpretations of import-export balances, as imports may reflect strategic storage charging rather than system deficit.
From a pricing perspective, spreads between Central European and SEE markets remain a key driver of cross-border optimization. The Hungary-Germany spread narrowed to -9.4 €/MWh, tightening relative to previous sessions but still indicating a premium in the regional market. This suggests that while arbitrage opportunities with Western Europe have moderated, the SEE region continues to operate at structurally higher price levels due to tighter supply conditions and infrastructure constraints.
Fuel and carbon markets provided a mixed backdrop. Austrian gas hub prices (CEGH) increased to 47.47 €/MWh (+2.7 €/MWh), offering upward support to marginal generation costs, particularly for gas-fired units. Meanwhile, EU carbon allowances (EUA) showed a slight decline, easing some pressure on coal and lignite generation. The combined effect of these movements was broadly neutral to mildly bullish for power prices, reinforcing the role of thermal generation in price formation.
Intraday dynamics further highlight the evolving structure of the market. The pronounced solar peak during midday hours continues to suppress prices, occasionally pushing them toward zero or negative territory in certain markets, while evening ramps driven by thermal generation create sharp price spikes. This “duck curve” effect is becoming increasingly dominant across SEE markets, amplifying intraday volatility and enhancing the value of flexible assets such as battery storage, pumped hydro and fast-ramping gas units.
At the same time, hydro conditions remain supportive but not dominant. River flow indicators, including Danube levels, show moderate recovery but are not yet sufficient to offset the variability introduced by wind and solar generation. As a result, hydro continues to play a balancing role rather than acting as a primary price driver.
Looking ahead, the market appears to be entering a transitional phase typical of late spring. Renewable generation will remain the key source of volatility, with wind output representing the primary uncertainty factor. Any recovery in wind generation could rapidly compress prices and reduce spreads, while continued low wind conditions would sustain the current reliance on thermal generation and support elevated price levels.
Cross-border flows are expected to remain dynamic, with Romania and Greece maintaining export roles and Serbia, Hungary and parts of the Western Balkans continuing to rely on imports for balancing. The increasing penetration of battery storage, particularly in Bulgaria, is likely to further complicate flow patterns and introduce new arbitrage dynamics, as storage operators optimize charging and discharging across price differentials.
In the near term, price expectations remain within a broad 90–130 €/MWh range, with significant intraday volatility and potential for localized spikes. The persistence of structural fragmentation across the region suggests that full market convergence remains limited, despite ongoing integration efforts.
The overall market structure is increasingly defined by three interacting forces: renewable intermittency, thermal flexibility and cross-border constraints. Solar generation is reshaping intraday price curves, wind variability is driving short-term volatility, and thermal units are reasserting their role as marginal price setters. At the same time, evolving storage capacity and changing flow patterns are redefining traditional market signals.
Within this framework, the SEE power market is transitioning toward a more complex and opportunity-rich environment, where flexibility, timing and cross-border optimization are becoming central to both trading strategies and system operations.