Electricity prices in South-Eastern Europe have moderated at times, but they remain structurally higher and more volatile than in much of Western and Northern Europe. This price gap is not an anomaly. It reflects persistent structural features of the region’s power system that cannot be explained by fuel costs alone.
Over the past two years, average wholesale electricity prices in SEE markets have frequently clustered in the €85–105/MWh range during normal conditions, with recurrent excursions far above that level during stress periods. By contrast, several Western European markets have recorded extended periods with average prices below €60/MWh, and in some cases significantly lower during high renewable output or strong nuclear availability.
The first driver of this divergence is grid constraint. South-Eastern Europe remains one of the least interconnected parts of the European electricity system relative to demand. Physical interconnectors exist, but operational and market-available capacity is often limited. When borders constrain flows, national markets behave as islands, pricing local scarcity even when surplus exists nearby. This fragmentation amplifies volatility and sustains higher average prices.
Quantitative analysis of recent stress events shows that insufficient cross-zonal capacity availability played a decisive role in extreme price outcomes. During summer 2024, analysis indicated that full application of the 70 percent cross-border capacity availability rule could have prevented roughly half of the most severe price spikes in central and south-east Europe and reduced peak prices by up to €78/MWh in affected bidding zones. This is not a marginal effect; it is a structural price determinant.
The second driver is generation mix rigidity. SEE systems rely more heavily on lignite, coal, and gas than many Western counterparts, and they lack large nuclear fleets that provide low-marginal-cost stability. While renewables are expanding, they have not yet reached the penetration levels necessary to structurally suppress prices for long periods. As a result, fossil units frequently remain price-setting during peak hours, especially in the evening and during winter demand surges.
Carbon exposure compounds this effect. Although not all SEE countries are fully integrated into EU carbon pricing, the indirect impact of higher CO₂ prices is transmitted through imports and regional price coupling. Gas- and coal-based marginal pricing therefore embeds carbon risk even where domestic policy differs. This pushes clearing prices upward relative to markets with larger zero-carbon baseload buffers.
A third factor is flexibility scarcity. Western European systems increasingly rely on deep balancing markets, storage, and demand response to dampen volatility. SEE systems are still developing these tools. When renewables fluctuate or imports tighten, the system turns rapidly to expensive marginal resources, driving prices upward. This dynamic was visible in early 2026, when prices swung from around €90/MWh to over €110/MWh in consecutive weeks, and then surged toward €170–175/MWh in parts of the region during periods of weak wind and rising demand.
Liquidity and forward market depth also matter. Forward electricity markets in SEE remain relatively shallow, limiting hedging options for suppliers and industrial consumers. Thin liquidity increases risk premiums embedded in retail and long-term contract pricing. Even when spot prices fall temporarily, forward curves often remain elevated, reflecting persistent uncertainty around congestion, fuel availability, and policy risk.
Finally, institutional fragmentation sustains price divergence. Market coupling has progressed, but uneven implementation across borders and timeframes reduces its stabilising effect. Day-ahead coupling without full intraday and balancing integration limits the system’s ability to respond dynamically. In such conditions, volatility is not smoothed; it is redistributed unevenly.
The economic consequence is persistent competitiveness pressure. For energy-intensive industries in South-Eastern Europe, electricity costs are not only higher on average but also less predictable. This uncertainty influences investment decisions, discourages electrification, and increases reliance on self-generation or bilateral arrangements outside organised markets.
Importantly, the price gap is not immutable. It is the outcome of identifiable structural features. Strengthening interconnection availability, accelerating market coupling, expanding flexibility resources, and deepening forward market liquidity would all exert downward pressure on prices over time. However, these are not quick fixes. They require coordinated investment, regulatory discipline, and political commitment across borders.
South-Eastern Europe’s electricity prices are therefore best understood not as a temporary lag behind Western Europe, but as a reflection of a system still completing its structural transition. Until grid integration, flexibility, and market depth converge toward continental standards, price convergence will remain partial and episodic.
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