Electricity prices in South-East Europe (SEE) experienced a significant increase during the week of April 13-19, 2023, despite a notable decline in gas prices. This trend highlights a growing disconnect between fuel costs and electricity pricing mechanisms as market conditions tighten across interconnected European networks.
During this period, day-ahead electricity prices rose sharply across several SEE exchanges, with Croatia, Hungary, Romania, and Bulgaria leading the surge with double-digit increases. Greece’s prices settled around €93.82/MWh, while Italy remained the highest at €123.19/MWh. In contrast, Serbia’s prices held steady at approximately €90/MWh, indicating stable domestic conditions. Türkiye saw a dramatic drop to €18.43/MWh, driven by robust domestic supply.
The divergence between rising electricity prices and falling gas benchmarks is particularly striking. Dutch TTF futures averaged €42.47/MWh, reflecting an almost 11% decrease week-on-week, primarily due to reduced geopolitical tensions following the reopening of the Strait of Hormuz. Traditionally, such a decline in gas prices would lead to lower electricity prices in gas-reliant markets; however, this was not the case.
This anomaly can be attributed to various system-level factors rather than merely fuel costs. The volatility of renewable energy generation, diminished hydroelectric output in key markets, and tightening cross-border balances have pushed marginal generation costs higher, negating any potential benefits from reduced gas prices.
Similar pricing trends were observed in Central and Western Europe, where Germany’s prices rose to €109/MWh, and France’s more than doubled from previous weeks due to improved availability. Austria, Belgium, and the Netherlands also saw their prices converge around the €106–109/MWh range, reinforcing strong price coupling through interconnected trading zones that exert upward pressure on SEE markets.
Price disparities within SEE remain pronounced, with figures ranging from €18/MWh in Türkiye to over €120/MWh in Italy. This variation underscores structural differences in generation mixes, demand profiles, and cross-border trade dynamics. Italy’s status as a net importer continues to support its premium pricing by drawing power from neighboring regions while exporting its higher marginal cost structure.
The daily price formation followed a typical intra-week pattern with peaks occurring early in the week—especially on Tuesday, April 14—before tapering off towards the weekend. This pattern reflects industrial demand cycles and variability in renewable energy generation, particularly wind output fluctuations that significantly influence hourly and daily clearing prices.
<pDespite these price increases, overall electricity consumption across SEE saw only marginal growth of 1.04% week-on-week to 15,379 GWh, with most of this increase concentrated in Italy (over 6%). Conversely, Serbia and Romania reported significant demand declines of -4.89% and -5.64%, respectively, indicating that weather patterns or structural factors were impacting consumption levels in certain areas.
This disconnect between weak demand and rising prices further emphasizes the supply-side nature of current market dynamics. Reduced solar generation across multiple markets combined with inconsistent wind output and declining hydro availability has constrained low-cost supply options. Consequently, there has been a growing reliance on thermal generation—particularly gas and coal—to meet marginal demand.
Thermal output has remained relatively stable across SEE; however, there have been notable internal shifts. Gas-fired generation has increased significantly in Italy and Hungary, while coal output has seen a modest decline regionally but remains dominant in markets like Serbia where lignite continues to provide baseload supply. Italy’s rising demand coupled with renewable variability has led to an uptick in thermal output reliant on gas and coal for system stabilization.
Cross-border electricity flows have further amplified these trends. Net imports decreased by over 13%, while export activities surged by more than 65%, indicating a redistribution of generation resources across the region. Countries such as Greece, Bulgaria, and Türkiye enhanced their export capabilities while Serbia transitioned from being a marginal exporter to a net importer amid tightening domestic supply conditions. Italy expanded its import position significantly, surpassing 1 TWh of net imports, solidifying its role as the primary demand sink within the region.
The increasing volatility of cross-border flows underscores the critical role of transmission corridors in shaping price formation dynamics. As SEE integrates more closely with Central European markets, interconnectors are evolving from mere balancing tools to primary conduits for price signals. This shift has profound implications for market participants as arbitrage opportunities become increasingly contingent on real-time system conditions rather than historical price differentials.
The future trajectory of decoupling between gas and power prices remains uncertain. While lower gas prices theoretically set a floor for power markets, the growing share of intermittent renewables alongside hydro variability introduces additional complexities into pricing structures. In this evolving landscape, marginal pricing is increasingly influenced by system flexibility rather than solely by fuel costs.
This suggests that power markets throughout SEE—and Europe at large—are entering an era characterized by embedded volatility where short-term price fluctuations are driven more by renewable output variability and real-time balancing requirements than by traditional fuel linkages.
The broader geopolitical landscape continues to impact market conditions as well. Although recent developments have alleviated immediate concerns regarding LNG supply disruptions following the Strait of Hormuz reopening, persistent risks remain due to Europe’s ongoing dependence on LNG imports coupled with cautious storage refill strategies that could expose markets to potential shocks later this year. Should LNG flows tighten again, previously established gas-to-power price correlations could re-emerge rapidly.
This week’s developments signal a pivotal moment: the SEE power market is increasingly influenced by internal system dynamics rather than external fuel costs alone. This evolution marks a significant shift in pricing mechanisms with far-reaching implications for trading strategies and risk management practices throughout the region.
