Southeast European day-ahead electricity markets moved sharply higher on 1 April 2026, with prices converging across the region in a tight €150–158/MWh range, as reduced cross-border inflows and falling renewable output forced a stronger reliance on gas-fired generation.
The regional price rally was broad-based, with Hungary (HUPX) clearing at €154.3/MWh, Romania (OPCOM) at €156.3/MWh, Bulgaria (IBEX) at €155.4/MWh, and Greece (HENEX) reaching €155.0/MWh, marking one of the strongest synchronized upward moves in recent weeks. Serbia’s SEEPEX price settled at €158.5/MWh, maintaining a premium to neighbouring markets, while Croatia and Slovenia followed closely at €151–150/MWh levels.
The only significant divergence came from Albania, where ALPEX dropped to €138.7/MWh, reflecting localized hydro oversupply and weaker coupling with the broader regional price formation.
The convergence of prices across Central Eastern and Southeast Europe highlights a tightening system balance, with shared marginal cost drivers now dominating price formation across interconnected markets.
Import compression drives market tightness
A key catalyst behind the price surge was a sharp contraction in cross-border electricity imports, particularly from Central Europe into Hungary and the wider SEE region.
Total net imports declined to 1,325 MW, down 687 MW day-on-day, while flows from core markets such as Austria and Slovakia dropped even more steeply, falling to 2,765 MW, a reduction of 1,439 MW.
This reduction in external supply significantly tightened liquidity across the region, forcing domestic generation to cover a larger share of demand and pushing marginal prices higher.
At the same time, the Hungary–Germany spread narrowed to around €10/MWh, sharply lower compared to previous sessions, reducing arbitrage incentives and limiting the ability of cheaper Western European power to flow into Southeast Europe.
Renewable output falls, gas generation ramps up
On the supply side, a notable drop in renewable generation played a decisive role in reshaping the generation stack.
Wind output declined by 613 MW, while solar generation fell by 453 MW, removing more than 1.0 GW of low-cost supply from the system.
This shortfall was primarily offset by a strong increase in gas-fired generation, which rose by 1,095 MW to 5,856 MW, becoming the dominant marginal source of electricity in the region.
Coal and hydro output remained broadly stable at 6,007 MW and 7,961 MW respectively, while nuclear generation held steady at around 5,800 MW, indicating that flexibility in the system is increasingly concentrated in gas-fired assets.
The shift in the generation mix underscores a recurring structural pattern in SEE markets: when renewable output weakens and imports decline, gas rapidly becomes the price-setting technology, reinforcing upward price pressure.
Demand softens but not enough to offset supply tightness
Electricity consumption across the SEE region eased slightly to 35,377 MW, down 608 MW from the previous day, reflecting marginally warmer temperatures of around 9°C.
However, the modest decline in demand was insufficient to counterbalance the sharper contraction in supply, leaving the overall system tighter and supporting higher prices.
This dynamic illustrates the current sensitivity of the regional market, where relatively small shifts in supply—particularly imports and renewables—can outweigh demand-side movements.
Cross-border flows highlight structural imbalances
Flow data shows that several key markets remain structurally short, with Hungary and Serbia continuing to rely on imports, recording average net import positions of -741 MW and -724 MW respectively.
In contrast, Greece maintained a net export position of +772 MW, reflecting stronger thermal and renewable availability in the southern part of the region.
These patterns reinforce the persistence of northwest-to-southeast dependency, where constraints on inflows from Central Europe can quickly tighten conditions across multiple SEE markets simultaneously.
Intraday structure signals elevated price floor
Hourly price profiles across key exchanges showed limited intraday relief, with minimum prices remaining above €100/MWh and peak levels exceeding €230/MWh.
The relatively flat but elevated intraday curve indicates a structurally tight system with limited surplus capacity, reducing opportunities for arbitrage and reinforcing baseload-driven pricing.
Market participants are also preparing for the introduction of negative pricing on Serbia’s SEEPEX exchange from May, a development expected to increase intraday volatility and reshape bidding strategies, particularly during periods of high solar output.
Fuel and carbon markets provide mixed signals
In upstream markets, gas prices at Austria’s CEGH hub eased slightly to €55.3/MWh, while coal benchmarks continued a gradual downward trend.
However, EU carbon allowances remained firm, with EUA contracts trading in the €70–80/t range, maintaining upward pressure on thermal generation costs.
The combination of softer gas prices and resilient carbon costs suggests that clean spark spreads remain tight but supportive of continued gas dispatch, particularly in the absence of strong renewable output.
Forward curve indicates potential near-term normalisation
Forward power contracts remain below current spot levels, with April baseload trading around €100–115/MWh, indicating that the market expects some easing in the coming weeks.
Weather forecasts point to gradually rising temperatures toward 11–13°C, which could reduce demand and support higher solar generation, potentially easing prices into the €135–150/MWh range in the near term.
However, upside risks remain in place, particularly if wind output continues to underperform or if cross-border imports fail to recover.
Market direction: Gas-led pricing with import sensitivity
The latest session reinforces several key structural dynamics in SEE power markets.
Price formation remains highly sensitive to import availability from Central Europe, with reduced flows quickly translating into tighter conditions and higher prices. At the same time, renewable volatility continues to drive short-term price swings, while gas-fired generation increasingly acts as the balancing mechanism and marginal price setter.
As a result, the region is entering a period where price direction will be dictated by the interplay between RES variability, cross-border capacity, and gas market movements, with limited buffer from alternative flexible sources.
The persistence of these conditions suggests that elevated price levels are likely to remain a defining feature of the SEE power market in the near term, particularly during periods of weak renewable output and constrained imports.
