On May 5, South-East European day-ahead power markets witnessed a notable upward correction, particularly in the Central and North-Western regions, while Southern markets lagged behind. This divergence underscores a market increasingly influenced by intraday renewable fluctuations, thermal generation adjustments, and changing cross-border interactions, rather than consistent regional fundamentals.
Key hubs reported significant increases in day-ahead baseload prices. Hungary’s HUPX market cleared at 119.28 €/MWh, reflecting a rise of 4.9 €/MWh from the previous day. Romania’s OPCOM market also rose to 118.85 €/MWh, up 7.9 €/MWh. The most pronounced increases were observed in the Central European periphery, with Slovenia’s BSP reaching 126.89 €/MWh (+14.6 €/MWh) and Croatia’s CROPEX at 120.43 €/MWh (+10.1 €/MWh). Conversely, Serbia’s SEEPEX declined to 97.36 €/MWh, down 5.7 €/MWh, while Greece’s HENEX edged down to 98.73 €/MWh, a decrease of 0.2 €/MWh.
This price fragmentation reflects tightening conditions in the Central European corridor, where diminished renewable output coupled with increased thermal generation has elevated marginal costs. In contrast, localized oversupply and structural export positions have continued to suppress southern pricing.
The overall generation capacity across the region rose to 28,155 MW, an increase of 2,541 MW. This growth was largely attributed to a rebound in thermal generation: coal-fired output climbed to 4,632 MW (+1,032 MW), while gas-fired production increased to 3,015 MW (+651 MW). Solar energy production surged to 6,153 MW (+1,448 MW), benefiting from favorable daylight conditions; however, wind generation saw a sharp decline to 1,786 MW (-1,318 MW), marking one of the largest drops seen in recent sessions.
The interplay between rising solar output and falling wind production has created a distinct “dual regime” within the market dynamics. During midday hours, prices were suppressed by solar generation; however, evening hours necessitated rapid thermal ramping which led to elevated peak prices and heightened volatility. Price profiles across HUPX, BSP, and OPCOM indicated that evening peak prices frequently surpassed 150–300 €/MWh, contrasting sharply with lower midday levels.
Demand trends further supported the upward price trajectory as regional consumption increased to 28,500 MW (+551 MW), driven by slightly warmer temperatures averaging between 17°C and 18°C. Although still within shoulder-season norms, this uptick in demand coupled with reduced wind availability tightened supply-demand balances during critical hours.
The role of cross-border flows remained crucial in shaping regional pricing dynamics. The system maintained its import-dependent structure with total net imports recorded at -145 MW, reflecting a slight reduction in import intensity compared to earlier periods. Core imports from Austria and Slovakia into the SEE region totaled 663 MW, highlighting ongoing reliance on Central European inflows.
<pExamining individual country balances reveals persistent disparities: Romania sustained a robust export position averaging around +1,160 MW, aided by a stable generation mix and lower marginal costs. Greece also functioned as a net exporter at approximately +686 MW. In contrast, Serbia operated as a structural importer with average flows around -605 MW, indicating limited domestic flexibility and reliance on external balancing resources.
The evolving energy landscape is increasingly shaped by emerging structural changes within the region—particularly through enhanced energy storage capabilities. In Bulgaria, for instance, battery systems are now absorbing substantial electricity volumes during low-price periods, functioning as flexible demand that alters traditional import-export balance interpretations.
The pricing environment remains influenced by spreads between Central European markets and those in SEE regions; notably, the Hungary-Germany spread narrowed to -9.4 €/MWh. This tightening suggests moderated arbitrage opportunities with Western Europe while indicating that SEE continues to operate at higher price levels due to tighter supply conditions and infrastructural challenges.
The fuel and carbon markets presented mixed influences on pricing: Austrian gas hub prices (CEGH) rose to 47.47 €/MWh (+2.7 €/MWh), lending support for marginal generation costs associated with gas-fired units; meanwhile EU carbon allowances (EUA) experienced slight declines easing pressure on coal and lignite generation.
The intraday dynamics reveal an increasingly complex market structure characterized by pronounced solar peaks suppressing midday prices—occasionally driving them toward zero or negative levels—while evening ramps create sharp spikes driven by thermal generation. This “duck curve” effect is becoming more prevalent across SEE markets amplifying intraday volatility while enhancing the value of flexible assets like battery storage and fast-ramping gas units.
A moderate recovery in hydro conditions is noted but remains insufficient to offset variability caused by wind and solar inputs; thus hydro continues its role as a balancing resource rather than acting as a primary price driver.
The market is anticipated to enter a transitional phase typical of late spring where renewable generation will remain the key volatility factor—with wind output posing significant uncertainty risks for pricing structures moving forward.
This dynamic landscape suggests that cross-border flows will continue evolving; Romania and Greece are expected to maintain their export roles while Serbia and Hungary will likely persist in relying on imports for balancing needs. The increasing integration of battery storage systems is poised to further complicate flow patterns and introduce new arbitrage opportunities based on price differentials.
A broad range for near-term price expectations remains set between 90–130 €/MWh with notable intraday volatility anticipated alongside potential localized spikes due to structural fragmentation across the region despite ongoing integration efforts.
The current market structure is shaped by three interrelated forces: renewable intermittency impacting pricing curves; thermal flexibility asserting itself as marginal price setter; along with cross-border constraints influencing overall dynamics within this evolving landscape.
This transition towards complexity presents opportunities where flexibility timing and cross-border optimization will be paramount for trading strategies within this intricate power market environment.
