Electricity prices across South-East Europe (SEE) moved sharply higher in Week 16, even as gas benchmarks softened, underlining a widening decoupling between fuel inputs and power price formation as system conditions tightened across interconnected European markets.
Regional day-ahead prices climbed across most SEE exchanges during the week of 13–19 April, with several markets posting double-digit gains. Croatia, Hungary, Romania and Bulgaria led the upward movement, while Greece maintained a mid-range position near €93.82/MWh. Italy remained the structural high-price anchor at €123.19/MWh, continuing to define the upper bound of regional pricing despite only marginal weekly gains. Serbia, in contrast, remained broadly stable at ~€90/MWh, reflecting more balanced domestic conditions, while Türkiye diverged sharply, with prices collapsing to €18.43/MWh amid strong domestic supply dynamics.
The divergence between rising power prices and declining gas benchmarks is particularly notable. Dutch TTF futures averaged €42.47/MWh, down nearly 11% week-on-week, driven by easing geopolitical tensions linked to the reopening of the Strait of Hormuz. Under conventional marginal pricing logic, this would have translated into softer electricity prices, particularly in gas-dependent systems. Instead, the opposite occurred.
The explanation lies in system-level dynamics rather than fuel costs. Renewable generation volatility, hydro weakness in key markets, and tightening cross-border balances pushed marginal units higher up the cost curve, effectively offsetting any benefit from lower gas input costs.
Across Central and Western Europe, similar price patterns reinforced this trend. Germany climbed to €109/MWh, while France more than doubled week-on-week, reflecting a rebound from suppressed levels and tightening availability. Austria, Belgium, and the Netherlands converged around the €106–109/MWh range, signalling strong price coupling across core markets. These dynamics transmitted directly into SEE via interconnected trading zones, compressing spreads and reinforcing upward pressure across the region.
Within SEE, price dispersion remained wide, ranging from €18/MWh in Türkiye to over €120/MWh in Italy, highlighting structural asymmetries in generation mix, demand profiles and cross-border positioning. Italy’s persistent role as a net importer continued to underpin its price premium, drawing power from neighbouring systems and effectively exporting its higher marginal cost structure into the broader region.
Daily price formation followed a typical intra-week pattern, with peaks observed early in the week—particularly on Tuesday, 14 April—before softening toward the weekend. This reflects a combination of industrial demand cycles and renewable generation variability, particularly wind output fluctuations, which played a central role in shaping hourly and daily clearing prices.
Demand fundamentals, however, offered limited support for the price rally. Total electricity consumption across SEE increased only marginally, by 1.04% week-on-week to 15,379 GWh, with growth concentrated primarily in Italy, which rose by over 6%. In contrast, Serbia and Romania recorded notable demand declines of -4.89% and -5.64%, respectively, suggesting that weather-driven or structural consumption factors were softening demand in parts of the region.
This disconnect between weak demand and rising prices further underscores the supply-side nature of the current market tightening. Reduced solar output across multiple markets, combined with uneven wind generation and declining hydro availability, constrained low-cost supply. As a result, systems increasingly relied on thermal generation—particularly gas and coal—to meet marginal demand.
Thermal output across SEE remained broadly stable overall, but internal shifts were significant. Gas-fired generation increased, particularly in Italy and Hungary, while coal output declined modestly at the regional level but remained dominant in markets such as Serbia, where lignite continues to anchor baseload supply. Italy, facing rising demand and renewable variability, significantly increased thermal output, reinforcing its reliance on gas and coal to stabilise the system.
Cross-border flows amplified these dynamics. Net imports across the region declined by over 13%, while export activity surged by more than 65%, reflecting a redistribution of generation availability. Greece, Bulgaria and Türkiye strengthened their export positions, while Serbia shifted from a marginal exporter to a net importer, indicating tightening domestic supply conditions. Italy further expanded its already dominant import position, exceeding 1 TWh of net imports, reinforcing its role as the region’s primary demand sink.
The increasing volatility in cross-border flows highlights the growing importance of transmission corridors in shaping price formation. As SEE becomes more deeply integrated with Central European markets, interconnectors are acting not merely as balancing tools but as primary conduits for price signals. This has profound implications for market participants, particularly traders and utilities, as arbitrage opportunities become more dependent on real-time system conditions rather than structural price differentials.
Looking forward, the key question is whether the current decoupling between gas and power prices will persist. While lower gas prices provide a theoretical floor for power markets, the increasing share of intermittent renewables and the variability of hydro output are introducing new layers of complexity. In such an environment, marginal pricing is increasingly dictated by system flexibility rather than fuel costs alone.
This suggests that power markets in SEE—and across Europe more broadly—are entering a phase where volatility will be structurally embedded. Short-term price movements will be driven less by traditional fuel linkages and more by a combination of renewable output variability, cross-border constraints, and real-time balancing requirements.
At the same time, the broader geopolitical context continues to exert influence. While the reopening of the Strait of Hormuz has eased immediate concerns around LNG supply disruptions, underlying risks remain. Europe’s continued reliance on LNG imports, coupled with cautious storage refill strategies, leaves the market exposed to potential shocks later in the year. Should LNG flows tighten again, the current decoupling could reverse rapidly, reintroducing strong gas-to-power price linkages.
For now, however, Week 16 provides a clear signal: the SEE power market is increasingly governed by internal system dynamics rather than external fuel costs. This marks a structural shift in how prices are formed, with significant implications for trading strategies, asset optimisation, and risk management across the region.