Electricity prices in South-Eastern Europe (SEE) continue to demonstrate significant volatility and remain consistently higher than those in Western Europe. Over the past two years, average wholesale prices have typically hovered between €85 and €105 per megawatt-hour (MWh), with notable spikes during periods of market stress. In contrast, many Western European markets have enjoyed extended stretches of average prices below €60/MWh, particularly during times of high renewable energy generation or robust nuclear output.
A key factor contributing to this price divergence is the limited interconnection within SEE’s electricity grid. The region is among the least interconnected areas in Europe relative to its demand, resulting in national markets often operating in isolation. This lack of connectivity leads to local scarcity pricing, even when nearby regions may have surplus capacity. Consequently, this fragmentation not only amplifies price volatility but also sustains elevated average electricity costs.
Analysis of recent market events reveals that inadequate cross-zonal capacity has played a critical role in driving extreme price fluctuations. For instance, during the summer of 2024, it was determined that adhering to the 70% cross-border capacity availability rule could have mitigated approximately half of the severe price spikes observed in central and south-eastern Europe, potentially lowering peak prices by up to €78/MWh in affected areas. This underscores the structural nature of these pricing challenges.
The rigidity of the generation mix further exacerbates the situation. SEE countries predominantly rely on lignite, coal, and gas for electricity generation, lacking substantial nuclear power resources that typically offer low marginal costs and stability. Although there has been growth in renewable energy sources, they have not yet reached levels sufficient to significantly lower prices over extended periods. As a result, fossil fuel plants frequently set prices during peak demand hours, especially during winter surges or evening periods.
Moreover, exposure to carbon pricing compounds these issues. While not all SEE nations are fully integrated into the EU’s carbon market, the indirect effects of rising CO₂ prices influence regional pricing through imports and market coupling mechanisms. This results in gas- and coal-based marginal pricing reflecting carbon risks even where domestic regulations differ, pushing overall market clearing prices higher compared to regions with more substantial zero-carbon baseload resources.
Flexibility within the energy system also remains a pressing concern. Unlike their Western European counterparts, which increasingly utilize advanced balancing markets and storage solutions to manage volatility, SEE systems are still evolving these capabilities. When renewable generation fluctuates or import scenarios tighten, reliance on expensive marginal resources becomes necessary, leading to sharp price increases. Such dynamics were evident in early 2026 when prices escalated from approximately €90/MWh to over €110/MWh within weeks and surged further toward €170–175/MWh during periods of low wind and heightened demand.
Liquidity issues and shallow forward markets present additional challenges for SEE electricity markets. Limited hedging options for suppliers and industrial consumers increase risk premiums embedded within retail pricing structures. Even when spot prices experience temporary declines, forward market curves often remain elevated due to ongoing uncertainties surrounding congestion, fuel availability, and regulatory risks.
Institutional fragmentation also plays a role in maintaining price discrepancies across the region. While progress has been made in market coupling initiatives, inconsistent implementation across borders hampers stabilization efforts. The absence of comprehensive intraday and balancing integration restricts the system’s ability to respond dynamically to market changes, resulting in unevenly distributed volatility rather than smoothing it out.
The implications for energy-intensive industries in SEE are significant; they face not only higher average electricity costs but also less predictability regarding future pricing trends. This uncertainty can hinder investment decisions and lead companies to rely more heavily on self-generation or bilateral agreements outside organized market frameworks.
However, it is essential to note that this price gap is not fixed. It stems from identifiable structural factors that can be addressed through strategic initiatives such as enhancing interconnection capacity, accelerating market coupling efforts, expanding flexibility resources, and improving forward market liquidity. While these solutions require coordinated investments and regulatory commitment across borders, they hold the potential for long-term reductions in electricity prices within the region.
In conclusion, understanding South-Eastern Europe’s electricity pricing landscape necessitates recognizing it as a reflection of an evolving system rather than merely a lag behind Western Europe. Until improvements are made in grid integration, flexibility resources, and overall market depth align with continental standards, price convergence will likely remain inconsistent and episodic.
