The Southeast European (SEE) power market experienced a notable surge in electricity prices as of March 30, 2026, driven primarily by a rebound in demand and shifts in cross-border electricity flows. The increase reflects a complex interplay of regional consumption dynamics and generation capacity constraints rather than a straightforward tightening of supply. Gas prices remained stable, playing a crucial role in the marginal pricing of electricity.
Day-ahead electricity prices across the region saw significant increases, with Hungary’s HUPX clearing at €138.72/MWh, marking an increase of €50.5/MWh from the previous day. Romania’s OPCOM reached €133.13/MWh, while Bulgaria’s IBEX stood at €134.57/MWh. Slovenia and Croatia reported similar figures around €127/MWh, whereas Greece lagged at €118.01/MWh. In contrast, Serbia and Montenegro maintained lower price points, with SEEPEX at €105.95/MWh and BELEN at €101.77/MWh, highlighting ongoing regional price fragmentation. Italy continued to set the benchmark high at €151.03/MWh.
This price surge was mainly attributed to increased regional consumption, which rose to 34,648 MW, up by 2,285 MW. In contrast, total generation fell to 30,758 MW, necessitating greater reliance on imports to meet demand. Net imports were recorded at 1,584 MW, with significant inflows from Austria and Slovakia into Hungary and Slovenia amounting to 3,890 MW.
A key factor influencing price formation was the widening of the HU-DE spread, which increased to €80.28/MWh, up by €58/MWh. This spread reflects the marginal cost associated with importing electricity into Hungary from Western Europe, setting a precedent for pricing throughout the SEE corridor. Following Hungary’s elevated prices, downstream markets such as Romania and Bulgaria typically adjust accordingly; however, Serbia and Montenegro lag due to local generation capabilities and limited interconnection liquidity.
The generation mix further illustrates these market dynamics: hydro output decreased by 416 MW, coal generation fell by 494 MW, and gas production dropped by 710 MW. While wind energy saw an increase of 624 MW, solar output remained relatively unchanged. Nuclear generation held steady at 5,913 MW, providing stability but not influencing marginal pricing significantly.
The stability in gas prices also plays an important role in this context. Austrian CEGH gas traded around €56.81/MWh, while Greek gas was slightly higher at €47.07/MWh. The divergence between stable gas prices and rising power costs indicates that spark spreads have widened significantly in Hungary and Romania, underscoring the economic relevance of gas-fired generation despite lower dispatch volumes.
The forward gas market signals further reinforce this trend; April 2026 contracts indicated moderate pressure with recent declines of approximately -11%. This suggests that while spot electricity prices have surged due to short-term scarcity concerns, the long-term cost structure for power generation remains stable.
Additions from coal and carbon markets have also contributed to maintaining marginal costs within reasonable bounds; API2 coal trends downward while EUA carbon prices stabilize around €71.67/t. Nonetheless, reduced coal output has tightened supply-demand balances without capping rising prices.
An analysis of intraday price curves reveals vulnerabilities during non-solar hours where demand peaks are pronounced across HUPX, BSP, and OPCOM markets. The insufficient solar generation during these times necessitates reliance on imports and flexible generation sources—primarily gas and hydro—which were both reduced on this day.
The trading landscape indicates a tightening pattern early in the week driven by structural constraints within the system. Key indicators include widening cross-zonal spreads and heightened import dependency into Hungary alongside diverging pricing trends between northern and southern SEE nodes. While gas remains stable overall, it plays a strategic role as it underpins the marginal cost framework even when not fully utilized.
The overarching trend suggests that SEE is transitioning toward an electricity pricing mechanism increasingly influenced by system flexibility, interconnection capabilities, and variability in renewable energy sources rather than immediate fuel costs alone.
