April 2026 marked one of the sharpest month-on-month corrections in Central and South East European power markets since late summer 2025, with wholesale electricity prices across the HU+SEE region falling materially as weaker gas prices, collapsing fossil-fired generation economics, lower consumption and record solar production reshaped regional market dynamics.
The regional benchmark on HUPX settled at €96.55/MWh, down from €117.35/MWh in March, representing a decline of 17.7% month-on-month. Most SEE exchanges followed the same trajectory, with Croatian CROPEX averaging €90.42/MWh, Slovenian BSP €88.79/MWh, Bulgarian IBEX €90.99/MWh, Serbian SEEPEX €91.51/MWh, and Greek HENEX falling to €88.72/MWh. The correction effectively pushed regional prices to their lowest levels since August 2025.
Despite the broad decline in outright prices, the structural spread between Hungary and Germany remained stubbornly elevated. The HU-DE spread averaged €18.04/MWh, slightly above March levels, demonstrating that congestion and FBMC constraints continued to distort price convergence between CWE and SEE. The report notes that DE-HU MaxExchange capacity remained among the weakest levels recorded since 2024 despite marginal improvements.
One of the defining themes of April was the acceleration of solar cannibalisation across SEE markets. Solar generation reached a new April record, with peak regional solar output averaging 8,272 MW, up 15.6% month-on-month and 15.2% year-on-year.
This surge fundamentally altered intraday price structures. On HUPX, average prices during H14-H15 turned negative, while the market recorded 84 negative-price hours in April versus only 18 hours in March. Germany simultaneously registered 123 negative-price hours. The result was a market increasingly split between heavily depressed midday solar hours and expensive evening balancing periods.
The shape of the curve became even more important than the monthly average itself. Evening critical-hour pricing remained elevated, with HUPX averaging around €209/MWh in H21, demonstrating that flexible generation, balancing capability and storage arbitrage continue to gain structural value even during bearish outright market conditions.
At the same time, fossil-fired generation economics deteriorated sharply. Coal generation across the region fell by nearly 2,000 MW month-on-month, while gas-fired generation dropped by approximately 2,200 MW. Coal output reached the lowest April level recorded since at least 2016, according to the report.
The report directly links part of this collapse in non-EU coal generation to the operational impact of CBAM. Serbia and Bosnia and Herzegovina in particular experienced visibly weaker coal-fired output and worsening export positions.
Serbia’s power balance deteriorated materially versus April 2025. The country’s net export position weakened by around 440 MW year-on-year, driven by:
- 200 MW lower coal-fired generation
- 60 MW lower hydro output
- 75 MW lower gas-fired generation
This is becoming increasingly important for Serbian market participants because SEEPEX pricing is no longer determined only by domestic production costs or hydrology. Instead, the market is increasingly shaped by:
- 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 repeatedly highlights exports toward Ukraine and Moldova as an additional structural “consumption unit” for SEE markets. Even though these flows are technically transit-oriented, they tighten regional supply-demand balances and increase dependence on imports from CORE and Italy.
Hydro generation also weakened materially in April, declining by 1,105 MW month-on-month, dropping below average seasonal levels for the first time in five months. Wind generation simultaneously fell by around 14% month-on-month, partially offsetting the solar surge.
The broader implication is that SEE power systems are increasingly dependent on solar-heavy midday structures while becoming more vulnerable during evening ramping hours. This creates a structural business case for:
- BESS deployment
- flexible gas generation
- ancillary services
- balancing assets
- and interconnection optimisation.
Gas markets themselves eased materially during April. Austrian CEGH spot gas prices averaged €47.17/MWh, down 11.3% month-on-month, although still substantially above April 2025 levels.
Yet lower gas prices did not rescue gas-fired generation economics. Clean Spark Spreads remained deeply negative due to:
- weak daytime power prices
- elevated EUA costs
- and severe solar price suppression.
The report states that high-efficiency gas plants recorded base-load losses of approximately €23.1/MWh after fuel and carbon costs, while low-efficiency units lost nearly €38.7/MWh. Peak-product economics were even worse.
This is a major signal for future SEE thermal investment strategy. Merchant gas generation without capacity remuneration, balancing revenues or ancillary-service monetisation is becoming increasingly difficult to justify under current market structures dominated by solar oversupply and high carbon costs.
Carbon markets themselves remained elevated. EUA prices averaged €73.8/t during April, around 5.5% higher than March levels.
The report’s CBAM section provides one of the clearest early operational indications of how the mechanism is reshaping Western Balkan electricity trading. According to Energy Community Secretariat assessments cited in the review, commercial cross-border electricity exchanges declined by roughly 25% in Q1 2026, even while Western Balkan power prices remained around €30/MWh lower than neighboring EU markets.
The mechanism is effectively eroding traditional arbitrage economics because imported electricity is treated under default fossil-carbon assumptions regardless of actual generation mix. Montenegro’s EPCG already reported approximately €13 million in Q1 losses linked to CBAM introduction.
For Serbia, Bosnia and Herzegovina and Montenegro, the strategic implication is increasingly clear:
- coal-heavy export structures are losing competitiveness rapidly,
- while renewable-backed exports with verifiable emissions attributes become progressively more valuable.
This shifts the market from a pure €/MWh framework toward a combined electricity-and-carbon valuation structure.
The regional market is therefore entering a fundamentally different phase from the 2021–2023 energy crisis cycle. Instead of scarcity-driven price explosions alone, April 2026 demonstrated the growing coexistence of:
- midday negative pricing,
- evening scarcity premiums,
- structurally weaker fossil economics,
- carbon-border distortions,
- and widening divergence between flexible and inflexible generation assets.
For investors and traders, the key conclusion from April is not simply that prices declined. The deeper structural signal is that SEE markets are transitioning into a solar-saturated, carbon-constrained and flexibility-dependent system where asset value increasingly depends on hourly positioning rather than baseload generation alone.