Electricity prices across South-East Europe moved lower during calendar week 13 (23–29 March), but the decline was measured rather than structural, with underlying market fundamentals continuing to point toward a tight and volatile pricing environment.
Across the region, day-ahead baseload prices softened modestly. Greece averaged €96.75/MWh, down 3.55% week-on-week, while Bulgaria declined by 2.33%. Serbia recorded one of the more pronounced corrections, falling to €93.02/MWh, a 4.83% decrease, reflecting both easing gas input costs and a temporary improvement in supply conditions. Italy, which continues to act as the structural premium market for Southern Europe, dropped by 7.22% to €138.28/MWh, yet remained significantly above neighbouring SEE markets.
The primary driver behind the week’s decline was the movement in European gas markets. TTF front-month futures softened during early sessions, moving from levels above €56/MWh toward the €52–54/MWh range, reducing marginal costs for gas-fired generation. Given that gas continues to set the marginal price across much of SEE, even relatively small shifts in TTF pricing quickly feed through into electricity markets.
However, the reduction in power prices remained shallow. Market participants broadly agreed that the downside was capped by persistent geopolitical risk, particularly the evolving situation involving the United States and Iran. While there were intermittent signals suggesting de-escalation, the market continued to price in the possibility of supply disruptions—especially those affecting LNG flows through critical maritime routes such as the Strait of Hormuz.
This dynamic has created what traders increasingly describe as a “compressed downside environment.” Prices may ease on short-term fundamentals such as lower gas prices or improved renewable output, but any correction tends to be limited in both magnitude and duration. Forward curves reflect this asymmetry, remaining elevated and relatively flat across Q2 delivery periods.
Türkiye stood apart from the broader regional trend. Prices there rose by 9.52%, driven by a significant increase in domestic electricity demand. The divergence underscores the degree to which local fundamentals—particularly demand-side pressures—can override broader regional trends in markets with distinct structural characteristics.
At a regional level, the pricing corridor remained firmly elevated. Most SEE markets continued to trade within a €90–120/MWh range, well above historical averages for late March. This suggests that while volatility remains high, the system is operating around a higher equilibrium level compared to pre-crisis years.
Another notable feature of the week was the persistence of convergence pressures across interconnected markets. Although price spreads between countries narrowed slightly, full convergence remains constrained by grid bottlenecks, differences in generation mix, and varying levels of import dependency.
The broader conclusion from CW13 is that SEE electricity markets are no longer driven by a single dominant factor but instead reflect a layered interaction between gas prices, renewable output, hydrological conditions, and geopolitical developments. Within this framework, gas remains the anchor, but its influence is increasingly mediated by system flexibility and cross-border flows.
Looking ahead, traders are positioning for continued volatility rather than directional moves. While short-term corrections are expected to persist, the structural tightness of the system—combined with external risk factors—suggests that prices will remain supported, particularly during periods of increased demand or reduced renewable generation.
