On April 1, 2026, Southeast European day-ahead electricity markets experienced a significant price increase, with prices ranging between €150 and €158/MWh. This surge was primarily driven by a reduction in cross-border electricity imports and a decline in renewable energy output, resulting in a greater reliance on gas-fired generation.
The price increases were observed across several markets: Hungary’s HUPX market cleared at €154.3/MWh, Romania’s OPCOM at €156.3/MWh, Bulgaria’s IBEX at €155.4/MWh, and Greece’s HENEX at €155.0/MWh. Serbia’s SEEPEX reached €158.5/MWh, maintaining a premium over neighboring markets, while Croatia and Slovenia recorded prices around €151 to €150/MWh. In contrast, Albania’s ALPEX fell to €138.7/MWh due to localized hydro oversupply.
This convergence in pricing across Central Eastern and Southeast Europe indicates a tightening balance in the system, where shared marginal cost drivers have become increasingly influential in determining prices across interconnected markets.
Import Reductions Intensify Market Tightness
A notable factor contributing to the price surge was a sharp decrease in cross-border electricity imports, particularly from Central Europe into Hungary and the broader SEE region. Total net imports fell to 1,325 MW, down 687 MW from the previous day, while imports from key markets such as Austria and Slovakia dropped significantly to 2,765 MW—a reduction of 1,439 MW.
This decline in external supply tightened liquidity within the region, compelling domestic generation to meet a larger share of demand and consequently pushing marginal prices higher. Additionally, the Hungary-Germany price spread narrowed to approximately €10/MWh, diminishing arbitrage opportunities and limiting the influx of cheaper power from Western Europe into Southeast Europe.
Declining Renewable Output Leads to Increased Gas Generation
On the supply side, a marked reduction in renewable generation significantly altered the generation mix. Wind output decreased by 613 MW while solar generation fell by 453 MW, removing over 1 GW of low-cost supply from the grid. This shortfall was largely compensated for by a substantial increase in gas-fired generation, which rose by 1,095 MW to reach 5,856 MW—solidifying its position as the dominant marginal source of electricity in the region.
Coal and hydro outputs remained stable at approximately 6,007 MW and 7,961 MW respectively, with nuclear generation steady around 5,800 MW. This shift highlights a recurring trend within SEE markets: when renewable output diminishes and imports decrease, gas quickly becomes the primary price-setting technology.
Demand Eases but Supply Constraints Persist
<pElectricity consumption across the SEE region slightly declined to 35,377 MW—a drop of 608 MW from the prior day—attributed to marginally warmer temperatures around 9°C. However, this modest decrease in demand was not sufficient to counterbalance the more significant contraction in supply, resulting in tighter overall market conditions that supported elevated prices.
This situation underscores the sensitivity of the regional market; minor fluctuations in supply—especially concerning imports and renewables—can have outsized impacts on pricing dynamics.
Cross-Border Flow Dynamics Reveal Structural Imbalances
Analysis of flow data indicates that several key markets remain structurally short on supply. Hungary and Serbia continue to depend on imports with average net import positions of -741 MW and -724 MW respectively. Conversely, Greece has maintained a net export position of +772 MW due to stronger thermal and renewable availability.
These trends emphasize the ongoing northwest-to-southeast dependency within the region; limitations on inflows from Central Europe can rapidly tighten conditions across multiple SEE markets simultaneously.
Intraday Price Structure Signals Tight Market Conditions
The hourly price profiles across major exchanges revealed limited intraday relief with minimum prices remaining above €100/MWh and peak levels surpassing €230/MWh. The generally flat yet elevated intraday price curve indicates a structurally tight system with limited surplus capacity available for arbitrage opportunities.
Market participants are also preparing for the implementation of negative pricing on Serbia’s SEEPEX exchange starting in May—a development anticipated to heighten intraday volatility and alter bidding strategies during high solar output periods.
Mixed Signals from Fuel and Carbon Markets
In upstream markets, gas prices at Austria’s CEGH hub slightly decreased to €55.3/MWh while coal benchmarks continued their gradual decline. However, EU carbon allowances remained robust with EUA contracts trading within the €70–80/t range, sustaining upward pressure on thermal generation costs.
The combination of easing gas prices alongside resilient carbon costs indicates that clean spark spreads remain tight but supportive of ongoing gas dispatch—especially amid weak renewable output conditions.
Forward Curve Suggests Potential Near-Term Normalization
Forward power contracts are currently trading below spot levels with April baseload contracts around €100–115/MWh—suggesting market expectations for some easing ahead. Weather forecasts predict rising temperatures toward 11–13°C which could lower demand while enhancing solar generation potential—possibly easing prices into the €135–150/MWh range shortly.
Nonetheless, risks persist particularly if wind output underperforms or if cross-border import levels do not recover adequately.
Market Outlook: Gas-Driven Pricing Amid Import Sensitivities
The recent developments reinforce critical structural dynamics within SEE power markets. Price formation remains acutely sensitive to import availability from Central Europe; reduced flows can swiftly lead to tighter market conditions and increased prices. Concurrently, renewable volatility continues to induce short-term price fluctuations while gas-fired generation increasingly serves as both a balancing mechanism and marginal price setter.
This evolving landscape suggests that price direction will be shaped by interactions among renewable energy variability, cross-border capacity constraints, and gas market movements—with limited flexibility from alternative sources available for balancing purposes. The persistence of these conditions is likely to establish elevated price levels as a defining characteristic of the SEE power market in the near future—particularly during periods marked by weak renewable output coupled with constrained imports.
