The South East European electricity market entered April under the influence of two opposing forces: a predictable seasonal decline in demand tied to the Easter holiday period, and a less predictable tightening of regional supply conditions driven by weather volatility, fuel pricing and cross-border balancing constraints. The result was not a synchronized correction, but a fragmented pricing landscape that continues to define the SEE power market as structurally distinct within the broader European system.
Week 14 of 2026, covering the period from 30 March to 5 April, provides a clear snapshot of this divergence. Across Southern Europe, most markets remained firmly above the €100/MWh threshold, despite a broader softening trend across Western and Central Europe. The pricing range within SEE was unusually wide, extending from €19.32/MWh in Türkiye to €136.15/MWh in Italy, with the core Balkan and Central SEE markets clustering tightly in the €106–€114/MWh range.
This pricing structure underscores a persistent structural reality: SEE is no longer a peripheral extension of the EU power market but a semi-autonomous pricing zone where internal fundamentals often override continental trends. While Iberian markets collapsed to €12–€13/MWh levels, supported by strong renewable generation and low demand, SEE markets largely resisted downward pressure. Instead, several posted significant weekly increases, including Serbia (+21.64%), Greece (+14.36%), Bulgaria (+11.78%), and Romania (+8.49%).
At the core of this divergence lies the imbalance between demand contraction and supply-side variability. Electricity consumption across SEE declined by 2.30% week on week, reflecting reduced commercial and industrial activity. The contraction was particularly visible in Bulgaria (-6.81%), Hungary (-6.27%), and Italy (-3.78%), confirming a region-wide Easter effect.
However, the supply side failed to adjust in a way that would typically support price declines. Variable renewable energy generation fell by 5.2%, driven primarily by a 6.2% drop in wind output, with particularly severe declines in Serbia (-63.4%), Bulgaria (-23.7%), and Romania (-18.2%). This contraction removed a critical source of low-cost generation at precisely the moment when demand was weakening, forcing systems to rely more heavily on thermal generation.
Hydropower offered partial relief, increasing by 3.6% week on week, but its impact was uneven. Strong gains in Romania (+37.7%) and Croatia (+240.7%) contrasted sharply with declines in Serbia (-25.0%), Bulgaria (-27.4%), and Greece (-27.3%), reinforcing the localized nature of supply conditions in the region.
Thermal generation dynamics further complicated the picture. While total thermal output declined slightly by 1.4%, the composition shifted meaningfully. Coal and lignite generation fell by 6.8%, while gas-fired generation increased by 3.8%, indicating a gradual but incomplete shift toward gas as a marginal fuel. In markets such as Italy, gas-fired generation rose 22.1%, while Serbia experienced a 55.2% surge in lignite output, reflecting country-specific balancing strategies.
Cross-border flows added another layer of complexity. Total net imports across SEE fell by 11.3% to 1,188.7 GWh, indicating reduced dependence on external supply. Yet beneath this aggregate figure were significant shifts. Serbia increased net imports by over 130%, while Greece’s net exports collapsed by nearly 80%, and both Bulgaria and Romania moved away from export positions toward balance or net import status.
These dynamics reveal a system that remains highly sensitive to short-term changes in generation availability and interconnection flows. In contrast to Western Europe, where high liquidity and diversified generation portfolios dampen volatility, SEE markets continue to exhibit sharp price reactions to relatively small changes in supply conditions.
Looking ahead, early indications from the start of Week 15 suggest some normalization. Day-ahead prices on 8 April ranged between €80.41/MWh in Bulgaria and Greece and €97.39/MWh in Serbia, reflecting easing tightness. Yet this normalization does not alter the structural conclusion. SEE remains a high-volatility, premium-priced sub-market within Europe, where price formation is driven as much by localized constraints as by continental fundamentals.
European gas prices CW14 retreat, but structural tightness persists into refill season
The European gas market presented a contrasting narrative during the same period. While SEE electricity markets remained elevated and fragmented, gas prices moved decisively lower, reflecting a temporary easing of geopolitical risk and a seasonal decline in demand.
During Week 14, Dutch TTF gas futures averaged €50.829/MWh, representing a 6.9% week-on-week decline. Prices fell sharply early in the week, reaching a low of €47.51/MWh on 1 April, before stabilizing toward the end of the period. As the market transitioned into April, the one-month forward contract declined further to €44.605/MWh, indicating continued bearish sentiment in the short term.
The primary driver of this correction was a reduction in geopolitical risk premiums. Reports of diplomatic outreach related to the U.S.–Iran conflict eased concerns about potential disruptions to LNG flows through the Strait of Hormuz. Given Europe’s growing dependence on LNG, particularly from Qatar, any perceived reduction in supply risk translates quickly into lower TTF pricing.
Seasonal factors reinforced this trend. The Easter holiday reduced industrial gas demand across Western Europe, while mild weather conditions limited heating needs. This combination of lower demand and reduced risk premiums created a favorable environment for price correction.
However, the underlying market structure remains far from relaxed. European gas storage levels reached their seasonal low at just below 28% of capacity, significantly below comfortable levels entering the refill season. Moreover, the start of storage injections was delayed by approximately one week, as late-season demand temporarily exceeded expectations.
The refill outlook for 2026 appears particularly challenging. Historical data indicates that EU gas demand during the injection season typically ranges between 140 bcm and 145 bcm, requiring substantial supply inflows to rebuild storage levels. In 2025, this balance was achieved through a combination of 90 bcm of pipeline gas, over 20 bcm of domestic production, and approximately 85 bcm of LNG imports.
Entering 2026 from a lower storage base means Europe must secure even higher LNG volumes to achieve similar end-of-season storage levels of around 83%. While LNG imports reached record highs in March, supported by strong inflows from Qatar, the outlook remains uncertain. Potential disruptions in the Strait of Hormuz or increased competition from Asian markets could constrain LNG availability.
Regional gas flows provide additional insight into emerging structural dynamics. In Week 14, LNG inflows to Greece declined by 31.6% to 454.08 GWh, while Italy increased inflows by 4.31% to 3,963.05 GWh, and Croatia recorded a 32.0% increase to 709.25 GWh. These shifts highlight the growing importance of southern LNG entry points in balancing the European gas system.
Italy remains the dominant LNG gateway, but Croatia’s Krk terminal is increasingly significant for Central and South East Europe, while Greece’s variability reflects its role as a flexible but less stable entry point. These dynamics will become more critical as Europe seeks to manage supply risks during the refill season.
The broader conclusion is that while short-term price pressure has eased, the European gas market remains structurally tight. The combination of low starting storage levels, uncertain LNG availability, and ongoing geopolitical risks suggests that upward price pressure could re-emerge quickly if supply conditions tighten.
EU–SEE energy prices CW14 relationship tightens as structural gaps persist
The interaction between EU and SEE energy markets is becoming increasingly complex, reflecting both deeper integration and persistent structural differences. Week 14 illustrates this duality clearly. While SEE markets are influenced by broader European trends, they continue to exhibit distinct pricing behavior driven by localized factors.
On the electricity side, the divergence is particularly pronounced. Western and Central European markets experienced broad price declines due to reduced demand and strong renewable output, yet SEE markets remained elevated or even increased. This divergence highlights the limited transmission of price signals across the European grid, despite growing interconnection.
Italy plays a central role in this relationship. As both a major SEE market and a core EU pricing hub, it acts as a bridge between regions. In Week 14, Italy maintained the highest average price in the region at €136.15/MWh, while also remaining a key net importer, even as imports declined by 23.6%.
Hungary serves a similar function within Central SEE, acting as a major import hub and price reference point for neighboring markets. Its reduction in net imports by 38.9% contributed to the overall decline in regional cross-border flows, but did not prevent elevated prices in surrounding markets.
The gas market further reinforces the interconnected nature of EU and SEE energy systems. Southern European LNG terminals in Italy, Greece, and Croatia play a critical role in supplying not only their domestic markets but also inland SEE countries. Variations in LNG inflows at these entry points directly affect regional gas availability and pricing.
At the same time, structural differences remain significant. SEE markets are more dependent on hydro and coal, more sensitive to weather variability, and less liquid than Western European markets. These factors contribute to higher price volatility and limit the convergence of price levels.
The implications for market participants are substantial. Traders must navigate a system where price signals from core EU markets are only partially transmitted to SEE, while local factors can create significant deviations. Utilities and industrial consumers in SEE face higher and more volatile prices, affecting competitiveness and investment decisions.
Looking forward, the relationship between EU and SEE energy markets is likely to tighten further as interconnection expands and market integration deepens. However, structural differences will continue to create divergence, particularly during periods of supply stress or renewable variability.
Week 14 demonstrates that SEE is not merely following the European market but operating within it on its own terms. This duality—integration without full convergence—will remain a defining feature of the region’s energy landscape in the years ahead.