Electricity prices in South-Eastern Europe (SEE) have consistently outpaced those in Western Europe, reflecting deep-rooted structural issues within the region’s energy markets. Over the past two years, average wholesale prices in SEE have typically ranged between €85 and €105 per megawatt-hour (MWh), with significant spikes during periods of high demand or system stress. In contrast, several Western European markets have enjoyed prolonged periods with average prices below €60/MWh, particularly during times of high renewable energy production or robust nuclear generation.
A primary factor contributing to this price divergence is the limited interconnectivity of the SEE electricity grid. Despite the existence of physical interconnectors, operational capacity is often insufficient, leading to a scenario where national markets operate in isolation. This fragmentation results in local shortages being priced at a premium, even when nearby regions may have surplus capacity. Such conditions exacerbate volatility and maintain elevated average prices across the region.
Recent analyses highlight that inadequate cross-zonal capacity availability has significantly influenced extreme price fluctuations. For instance, a study conducted during the summer of 2024 indicated that adherence to the 70 percent cross-border capacity availability rule could have mitigated approximately half of the severe price spikes observed in central and south-east Europe, potentially lowering peak prices by as much as €78/MWh in affected areas.
The rigidity of the generation mix in SEE further complicates matters. The region relies heavily on lignite, coal, and gas for electricity production, lacking substantial nuclear resources that could provide stable low-marginal-cost power. Although there has been an increase in renewable energy sources, their current penetration levels are insufficient to drive down prices consistently. Consequently, fossil fuel-based plants often dominate price-setting during peak consumption hours, particularly during winter demand surges.
Additionally, carbon pricing mechanisms introduce another layer of complexity. While not all SEE countries are fully aligned with EU carbon pricing regulations, the indirect effects of rising CO₂ prices impact regional market dynamics through imports and price coupling arrangements. This marginal pricing mechanism embeds carbon risk into electricity costs, further inflating clearing prices relative to markets with more extensive zero-carbon resources.
The scarcity of flexibility in SEE systems also contributes to price volatility. Unlike their Western European counterparts that utilize advanced balancing markets and storage solutions to stabilize supply and demand fluctuations, SEE markets are still evolving these capabilities. When renewable output fluctuates or import levels decrease, reliance on costly marginal resources becomes inevitable, leading to dramatic price swings—as evidenced by instances where prices escalated from around €90/MWh to over €110/MWh within weeks.
Market liquidity and forward market depth play crucial roles in shaping pricing dynamics as well. The relatively shallow forward electricity markets in SEE limit hedging opportunities for suppliers and industrial consumers alike. This lack of liquidity tends to inflate risk premiums embedded within retail pricing structures and long-term contracts despite temporary decreases in spot prices.
Institutional fragmentation further perpetuates this pricing divergence. While market coupling initiatives have made progress across borders, inconsistent implementation hampers their stabilizing potential. The absence of comprehensive intraday and balancing integration restricts dynamic responses to market changes; thus, volatility tends to be redistributed unevenly rather than mitigated.
The economic implications are significant for energy-intensive industries operating within South-Eastern Europe. Higher average electricity costs coupled with unpredictable pricing patterns create challenges for investment decisions and may deter electrification efforts while increasing reliance on self-generation or informal bilateral arrangements outside organized markets.
Nevertheless, it is essential to recognize that this price gap is not fixed; it stems from identifiable structural characteristics within the region’s energy landscape. Enhancing interconnection capacity, expediting market coupling processes, expanding flexibility resources, and improving forward market liquidity could collectively exert downward pressure on electricity prices over time. However, achieving these objectives requires coordinated investments and regulatory commitment across national borders.
Ultimately, understanding South-Eastern Europe’s electricity pricing requires viewing it not merely as a temporary lag behind Western Europe but as a reflection of an evolving system still undergoing significant structural transformation. Until improvements in grid integration and market depth align more closely with continental standards are realized, price convergence will likely remain inconsistent and episodic.
