The Southeast European (SEE) power market experienced a significant surge in electricity prices on March 30, driven by a rebound in demand and tightening physical balance across the region. The day-ahead prices reflected this upward trend, with Hungary’s HUPX clearing at €138.72/MWh, marking an increase of €50.5/MWh from the previous day. Romania’s OPCOM and Bulgaria’s IBEX also saw notable increases, reaching €133.13/MWh and €134.57/MWh, respectively. Slovenia and Croatia reported prices around €127/MWh, while Greece lagged behind at €118.01/MWh. In contrast, Serbia and Montenegro continued to show structural discounts, with SEEPEX at €105.95/MWh and BELEN at €101.77/MWh, highlighting ongoing regional fragmentation.
This price movement can be attributed to a notable increase in regional consumption, which rose to 34,648 MW, up by 2,285 MW. However, total generation fell to 30,758 MW, necessitating increased reliance on imports to meet demand. Net imports reached 1,584 MW, with core flows from Austria and Slovakia into Hungary and Slovenia climbing to 3,890 MW, indicating a strong north-to-south dependency within the region.
A critical factor in the recent price formation was the widening of the HU-DE spread, which expanded to €80.28/MWh, an increase of €58/MWh. This spread effectively set the marginal cost for importing electricity into Hungary from Western Europe, influencing pricing across the SEE corridor. As Hungary’s prices rise, downstream markets such as Romania, Bulgaria, and Slovenia tend to follow suit; however, Serbia and Montenegro remain insulated due to local generation buffers and limited interconnection liquidity.
The generation mix further illustrates the challenges facing the system. Hydro output decreased by 416 MW, coal generation dropped by 494 MW, and gas generation fell by 710 MW, removing essential balancing capacity from the grid. Wind energy production increased by 624 MW, partially offsetting these declines, while solar output remained relatively flat. Nuclear power remained stable at 5,913 MW, serving as a base stabilizer but not affecting marginal pricing significantly.
Gas prices have shown relative stability despite their critical role in setting marginal costs for thermal units. Austrian CEGH gas traded at €56.81/MWh, while Greek gas was slightly higher at €47.07/MWh. This disparity between stable gas prices and rising electricity prices has resulted in significantly widened spark spreads, particularly in Hungary and Romania. Although gas-fired generation faced reduced dispatch volumes, it maintained economic relevance due to the elevated power price environment.
The forward gas market signals indicate moderate pressure on April 2026 contracts and Q2 pricing, with recent declines of approximately -11% in Austrian gas forwards. This suggests that the underlying cost structure for power generation has not escalated alongside spot electricity prices; instead, the market appears to be pricing short-term scarcity rather than long-term fuel inflation.
The dynamics of coal and carbon also played a stabilizing role in this context. API2 coal exhibited a downward trend while EUA carbon prices remained firm at around €71.67/t. Although reduced coal output did not cap prices effectively, it contributed to tightening the supply-demand balance—indirectly supporting higher electricity prices.
An analysis of intraday price curves reveals systemic weaknesses during non-solar hours, with pronounced morning and evening peaks across HUPX, BSP, and OPCOM markets indicating insufficient solar generation to smooth load curves. Consequently, the system is increasingly reliant on imports and flexible generation during peak periods, heightening volatility when gas and hydro resources are diminished.
The current trading landscape reflects early-week tightening trends exacerbated by structural constraints within the market. Key indicators include widening cross-zonal spreads and heightened import dependence into Hungary alongside increasing divergence between northern and southern SEE nodes. While gas remains stable overall, its strategic importance persists as it establishes the marginal cost floor even when not fully utilized.
This evolving scenario suggests that SEE is transitioning into a phase where electricity price formation is increasingly decoupled from immediate fuel costs. Instead, it is becoming more influenced by factors such as system flexibility, interconnection capacity, and variability in renewable energy sources. In this context, value is shifting towards assets capable of navigating volatility rather than merely tracking directional trends.
