On May 5, South-East European day-ahead power markets exhibited a notable upward correction, particularly in the Central and North-Western regions, while Southern markets displayed more subdued activity. This divergence underscores a market increasingly influenced by intraday renewable volatility, the re-emergence of thermal generation, and shifting cross-border dynamics rather than consistent regional fundamentals.
Key day-ahead baseload prices saw significant increases across major hubs. Hungary’s HUPX market cleared at 119.28 €/MWh, marking an increase of 4.9 €/MWh from the previous day, while Romania’s OPCOM rose to 118.85 €/MWh, up by 7.9 €/MWh. The most pronounced price surges were observed in Slovenia and Croatia, with Slovenia’s BSP reaching 126.89 €/MWh (+14.6 €/MWh) and Croatia’s CROPEX at 120.43 €/MWh (+10.1 €/MWh). In contrast, Serbia’s SEEPEX fell to 97.36 €/MWh (-5.7 €/MWh) and Greece’s HENEX declined slightly to 98.73 €/MWh (-0.2 €/MWh), highlighting the growing disparity between core and southern balancing zones.
This emerging price fragmentation reflects a tightening system within the Central European corridor, where diminished renewable output coupled with increased thermal generation has elevated marginal costs. Conversely, localized oversupply and structural export positions have continued to depress prices in southern markets.
The total regional generation capacity climbed to 28,155 MW, an increase of 2,541 MW compared to the previous day, primarily driven by a resurgence in dispatchable capacity. Coal-fired generation rose to 4,632 MW (+1,032 MW) while gas-fired output increased to 3,015 MW (+651 MW). This indicates a renewed role for thermal units as marginal price setters. Solar production surged to 6,153 MW (+1,448 MW) due to favorable daylight conditions; however, wind output experienced a significant decline to 1,786 MW, down by 1,318 MW, marking one of the largest day-on-day drops in recent sessions.
The interplay between rising solar generation and declining wind output has created a distinct “dual regime” within the market. Midday hours saw price suppression driven by solar energy, while evening hours necessitated rapid thermal ramping, leading to heightened peak prices and increased market volatility. Hourly price profiles from HUPX, BSP, and OPCOM indicate that evening peaks frequently surpassed 150–300 €/MWh, contrasting sharply with lower midday levels.
A slight uptick in regional demand contributed further to the upward price trend, with consumption rising to 28,500 MW, an increase of 551 MW. This rise correlates with warmer temperatures averaging between 17°C and 18°C. While still within shoulder-season norms, this incremental load increase combined with reduced wind availability has tightened supply-demand balances during critical hours.
The role of cross-border flows remains crucial in shaping regional pricing dynamics. The system continues to be structurally import-dependent with total net imports recorded at -145 MW, reflecting a slight reduction in import intensity compared to prior sessions. Core imports from Austria and Slovakia into the SEE region amounted to 663 MW, emphasizing ongoing reliance on Central European inflows.
<pExamining country-specific balances reveals persistent imbalances: Romania maintained a robust export position averaging around +1,160 MW, bolstered by a stable generation mix and lower marginal costs. Greece also remained a net exporter at approximately +686 MW, benefiting from lower domestic pricing structures. In contrast, Serbia operated as a structural importer with average flows around -605 MW, indicative of limited domestic flexibility and reliance on external balancing resources.
The evolving nature of these flow patterns is increasingly shaped by structural changes within the region, particularly regarding energy storage advancements. In Bulgaria, battery systems are now absorbing substantial volumes of electricity during periods of low pricing, effectively functioning as flexible demand sources. This shift alters traditional interpretations of import-export balances as imports may reflect strategic storage charging rather than indicating system deficits.
Pricing dynamics reveal that spreads between Central European markets and SEE remain pivotal for cross-border optimization strategies. The Hungary-Germany spread narrowed to -9.4 €/MWh, indicating tighter conditions relative to previous sessions but still reflecting a premium within the regional market context. Although arbitrage opportunities with Western Europe have moderated somewhat, the SEE region continues to operate at structurally elevated price levels due to tighter supply conditions and infrastructure constraints.
The fuel and carbon markets presented a mixed backdrop for power pricing; Austrian gas hub prices (CEGH) rose to 47.47 €/MWh, providing upward support for marginal generation costs associated with gas-fired units. Meanwhile, EU carbon allowances (EUA) experienced slight declines that eased pressure on coal and lignite generation costs. The overall effect was broadly neutral to mildly bullish for power prices while reinforcing the significance of thermal generation in pricing mechanisms.
The intraday dynamics further emphasize the market’s evolving structure; pronounced solar peaks during midday hours continue to suppress prices significantly—occasionally driving them toward zero or even negative values—while evening ramps driven by thermal generation create sharp price spikes. This “duck curve” effect is becoming increasingly prevalent across SEE markets, amplifying intraday volatility and enhancing the value proposition for flexible assets such as battery storage systems and fast-ramping gas units.
Hydro conditions remain supportive but not dominant; river flow metrics indicate moderate recovery without sufficiently offsetting variability introduced by wind and solar generation.
The market appears poised for transitional dynamics typical of late spring as renewable generation continues to be a primary source of volatility—particularly concerning wind output variability which poses significant uncertainty factors for future pricing trends.
Cross-border flows are expected to maintain their dynamic nature; Romania and Greece will likely continue their export roles while Serbia and Hungary will rely on imports for balancing needs.
In the near term, price expectations are projected within a broad range of 90–130 €/MWh with notable intraday volatility potential alongside localized spikes.
The overall market landscape is increasingly characterized by three interrelated factors: renewable intermittency, thermal flexibility, and cross-border constraints shaping operational strategies across the region.
This complex environment signals an ongoing transition within the SEE power market towards greater intricacy where flexibility in operations will be crucial for navigating both trading strategies and system management effectively.
