In South-Eastern Europe (SEE), the traditional focus on electricity capacity is undergoing a significant transformation. While the region has historically prioritized the sheer number of megawatts available as a measure of energy security, recent market behaviors indicate that flexibility has become the new critical constraint. The ability to adapt to rapid fluctuations in net load, manage variable renewable energy sources, and stabilize the grid during peak demand times is increasingly essential for maintaining system reliability.
Recent trends illustrate this shift vividly. In early January 2026, SEE spot prices experienced a notable decline, dropping from €94.82/MWh in late December to €89.73/MWh as wind generation surged and demand fell post-holidays—a decrease of 8.40%. Serbia and Romania saw even more pronounced reductions at -12.80% and -11.53%, respectively. This price movement was attributed to a 125% week-on-week increase in wind output across the region.
However, the situation reversed quickly, highlighting the volatility inherent in the current system. By mid-January, average prices rebounded dramatically to €111.36/MWh, marking a 24.1% increase within just one week. This volatility was further exacerbated in Week 03, with prices soaring by approximately 29%, particularly in Serbia where they jumped by 65.5%, pushing neighboring markets into the €170–175/MWh range. Such rapid price fluctuations underscore the challenges posed by inadequate flexibility in responding to changing weather conditions and cross-border constraints.
In more developed electricity markets, price volatility is typically mitigated through robust flexibility mechanisms such as extensive balancing platforms and demand response systems. While SEE has made strides in these areas, it remains structurally incomplete, leading to pronounced week-to-week price changes and extreme spikes during stress periods.
The flexibility gap becomes particularly evident during evening peaks in both summer and winter months when solar generation declines while demand remains high. For example, summer 2024 saw peak prices spike to €1,000/MWh, with ACER reporting 147 significant price spikes across the region. These spikes were not merely a result of increased demand but rather reflected systemic limitations in importing flexibility when needed most—issues closely tied to cross-border capacity and congestion management.
ACER’s analysis suggests that adherence to the EU’s cross-zonal capacity availability requirement—known as the 70% rule—could have mitigated nearly half of these severe price spikes. Furthermore, enhanced cross-border capacity could have reduced average evening peak prices by up to €78/MWh in central and south-east bidding zones, demonstrating the tangible economic value of flexibility in energy markets.
Flexibility is not solely dependent on cross-border capabilities; it also pertains to internal system dynamics. SEE’s reliance on legacy thermal plants for inertia and balancing is compounded by climate variability affecting hydropower reliability. This situation necessitates a greater emphasis on storage solutions, demand-side responses, and integrated balancing markets—all areas where SEE continues to develop.
The establishment of European balancing platforms has been pivotal for enhancing regional flexibility. Initiatives like PICASSO and MARI facilitate energy exchanges across transmission system operators (TSOs), allowing for more efficient allocation of resources where they are most needed. However, achieving full integration requires alignment of grid codes, operational readiness, and improved interconnector availability.
Emerging trading behaviors within SEE further reflect this shift towards monetizing flexibility. Market participants are increasingly prioritizing flow control and volatility management over mere generation ownership. Reports from January 2026 noted a resurgence of tradable liquidity and intensified cross-border flows, indicating that traders are now acting as key allocators of system optionality amidst fluctuating conditions.
The strategic implications for SEE’s energy systems are profound: success will hinge on building out flexibility rather than merely expanding capacity. A comprehensive approach involving enhanced interconnector availability, deeper market coupling, active participation in European balancing platforms, scalable storage deployment, and effective demand response programs is essential for managing future energy demands effectively.
The economic rationale for addressing this flexibility gap is becoming increasingly clear as market dynamics reveal that scarcity pricing is already being factored into operational costs during extreme events. With average spot prices swinging significantly within short timeframes—evidenced by movements from €89.73/MWh to €111.36/MWh—it is evident that without addressing flexibility deficits, SEE risks becoming an area characterized by persistent volatility that impacts both industrial consumers and households alike.
In conclusion, the flexibility gap represents a critical macroeconomic risk for SEE’s electricity landscape but also presents an opportunity for convergence towards greater market stability within Europe. The region’s ability to enhance its flexible capabilities will determine its resilience against future market stresses.
