April 2026 witnessed a substantial month-on-month correction in the Central and South East European power markets, marking one of the most pronounced adjustments since late summer 2025. The wholesale electricity prices across the HU+SEE region experienced a notable decrease due to several factors, including weaker gas prices, deteriorating fossil-fired generation economics, reduced consumption, and record levels of solar production.
The regional benchmark on HUPX concluded at €96.55/MWh, reflecting a decline from €117.35/MWh in March, equating to a drop of 17.7% month-on-month. Similar trends were observed across various exchanges in the region: Croatian CROPEX averaged €90.42/MWh, Slovenian BSP €88.79/MWh, Bulgarian IBEX €90.99/MWh, Serbian SEEPEX €91.51/MWh, and Greek HENEX fell to €88.72/MWh. This correction effectively brought regional prices to their lowest since August 2025.
Despite the overall price decline, the structural spread between Hungary and Germany remained persistently high, averaging €18.04/MWh, slightly above March levels. This indicates ongoing congestion and FBMC constraints that hinder price convergence between CWE and SEE markets. The DE-HU MaxExchange capacity also remained among the lowest recorded levels since 2024, despite slight improvements.
A significant trend during April was the acceleration of solar cannibalization across SEE markets, with peak solar generation reaching an April record of 8,272 MW, up by 15.6% month-on-month and 15.2% year-on-year. This surge drastically altered intraday price dynamics; average prices on HUPX during the H14-H15 period turned negative, resulting in a total of 84 negative-price hours compared to just 18 hours in March. Meanwhile, Germany reported 123 negative-price hours.
This shift has led to a market increasingly characterized by low midday solar prices contrasted with elevated evening balancing costs. Evening critical-hour pricing on HUPX averaged around €209/MWh in H21, highlighting that flexible generation capabilities and storage solutions are gaining importance even amid overall bearish market conditions.
The economic viability of fossil-fired generation has sharply declined; coal generation fell by nearly 2,000 MW month-on-month, while gas-fired generation decreased by approximately 2,200 MW. Coal output reached its lowest level for April since at least 2016, with reports linking part of this decline to the operational impacts of the Carbon Border Adjustment Mechanism (CBAM). Serbia and Bosnia and Herzegovina notably experienced a reduction in coal-fired output alongside deteriorating export positions.
The power balance for Serbia deteriorated significantly compared to April 2025, with the country’s net export position weakening by around 440 MW year-on-year. Contributing factors included:
- 200 MW lower coal-fired generation
- 60 MW lower hydro output
- 75 MW lower gas-fired generation
This evolving landscape is critical for Serbian market participants; pricing on SEEPEX is increasingly influenced not only by domestic production costs but also by external factors such as CBAM-related export distortions, declining coal profitability, negative-price spillovers from EU solar oversupply, FBMC congestion constraints, Ukrainian import demand, and evening ramping scarcity.
The report emphasizes that exports toward Ukraine and Moldova act as an additional structural “consumption unit” for SEE markets. Although these flows are technically transit-oriented, they tighten regional supply-demand balances and increase reliance on imports from CORE and Italy.
A significant decrease in hydro generation was also noted in April, declining by 1,105 MW month-on-month, falling below average seasonal levels for the first time in five months. Wind generation simultaneously dropped by approximately 14% month-on-month, partially offsetting gains from solar energy.
This situation underscores an increasing reliance on solar-heavy midday structures within SEE power systems while raising vulnerabilities during evening ramping periods. Consequently, there is a growing business case for deploying battery energy storage systems (BESS), flexible gas generation solutions, ancillary services provision, balancing assets development, and interconnection optimization.
The gas market conditions eased notably during April as well; Austrian CEGH spot gas prices averaged €47.17/MWh, down by 11.3% month-on-month, although still significantly higher than levels recorded in April 2025.
Lowers gas prices did not alleviate challenges for gas-fired generation economics; Clean Spark Spreads remained deeply negative due to weak daytime power prices alongside high EUA costs and severe price suppression resulting from solar energy influxes. High-efficiency gas plants experienced base-load losses of approximately €23.1/MWh after accounting for fuel and carbon costs while low-efficiency units faced losses nearing €38.7/MWh .
This trend signals a critical juncture for future thermal investment strategies within SEE. Merchant gas generation without capacity remuneration or monetization opportunities is becoming increasingly challenging under current market conditions dominated by solar oversupply coupled with high carbon costs.
The carbon market remained elevated throughout April; EUA prices averaged €73.8/t during this period—around 5.5% higher than March levels.
The CBAM’s implications are becoming clearer as it reshapes electricity trading dynamics within the Western Balkans; commercial cross-border electricity exchanges reportedly declined by approximately 25% in Q1 2026 even while Western Balkan power prices stayed roughly €30/MWh lower than neighboring EU markets.
This mechanism erodes traditional arbitrage opportunities as imported electricity is subject to default fossil-carbon assumptions irrespective of actual generation mix specifics—Montenegro’s EPCG reported around €13 million losses linked to CBAM implementation during Q1 alone.
The strategic implications for Serbia, Bosnia and Herzegovina, and Montenegro are increasingly evident: coal-heavy export structures are rapidly losing competitiveness while renewable-backed exports with verifiable emissions attributes gain value over time.
This shift indicates a transition from a purely €/MWh framework toward an integrated electricity-and-carbon valuation structure within regional markets.
The regional market is entering a fundamentally new phase distinct from the energy crisis cycle observed between 2021–2023; rather than being solely driven by scarcity-induced price spikes, April 2026 highlighted an emerging coexistence of midday negative pricing alongside evening scarcity premiums along with structurally weaker fossil economics compounded by carbon-border distortions and divergent performance between flexible versus inflexible generation assets.
The developments throughout April signal that SEE markets are evolving into a complex system characterized by solar saturation alongside carbon constraints where asset valuation increasingly hinges on hourly positioning rather than traditional baseload metrics alone.
