April 2026 power market correction in Central and South East Europe reshapes value around flexibility and carbon

April 2026 brought one of the steepest month-on-month corrections in Central and South East European power markets since late summer 2025, with wholesale prices falling materially across the HU+SEE region. The decline was not simply a demand story: weaker gas prices, deteriorating economics for fossil generation, lower consumption and record solar production together reshaped how supply met demand hour by hour—pushing the region into a more solar-saturated and flexibility-dependent trading regime.

Wholesale price averages slide, but convergence remains distorted

The regional benchmark on HUPX settled at €96.55/MWh, down from €117.35/MWh in March—a 17.7% month-on-month fall. Most SEE exchanges tracked the same direction: 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. The correction effectively took regional prices back to their lowest levels since August 2025.

Yet price convergence between Hungary and Germany stayed stubbornly elevated. The HU-DE spread averaged €18.04/MWh, slightly above March levels, indicating that congestion and FBMC constraints continued to interfere with CWE–SEE alignment. The report also notes that DE-HU MaxExchange capacity remained among the weakest levels recorded since 2024 despite marginal improvements.

Solar cannibalisation accelerates and drives negative midday pricing

April’s defining theme was the acceleration of solar cannibalisation across SEE markets. Regional peak solar output averaged 8,272 MW in April—up 15.6% month-on-month and 15.2% year-on-year—marking a new April record.

This surge altered intraday price structures more than the monthly average itself. On HUPX, average prices during H14–H15 turned negative, while April recorded 84 negative-price hours compared with just 18 hours in March. Germany registered 123 negative-price hours over the same period.

The market increasingly split into heavily depressed midday solar hours versus expensive evening balancing periods. Curve shape became more important than the monthly average: evening critical-hour pricing remained elevated even after outright prices fell, with HUPX averaging around €209/MWh in H21—an indication that flexible generation capability and balancing resources still command structural value.

Fossil output falls sharply as coal economics deteriorate

Alongside cheaper gas and abundant solar supply, fossil-fired generation economics weakened 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.

The report links part of this collapse in non-EU coal generation to operational effects from CBAM (the Carbon Border Adjustment Mechanism). Serbia and Bosnia and Herzegovina saw visibly weaker coal-fired output alongside worsening export positions.

Serbia’s export position weakens as multiple forces converge

Serbia’s power balance deteriorated materially versus April 2025: its net export position weakened by around 440 MW year-on-year due to lower coal-fired generation (down about 200 MW), reduced hydro output (down about 60 MW) and lower gas-fired generation (down about 75 MW).

The report argues that SEEPEX pricing is no longer driven only by domestic production costs or hydrology. Instead it increasingly reflects CBAM-related export distortions, declining coal profitability, negative-price spillovers from EU solar oversupply, FBMC congestion constraints, Ukrainian import demand and evening ramping scarcity.

It also highlights exports toward Ukraine and Moldova as an additional structural “consumption unit” for SEE markets—even when flows are technically transit-oriented—tightening regional supply-demand balances while increasing dependence on imports from CORE and Italy.

Hydro softens; wind declines partially offset solar gains

Hydro generation also weakened materially in April, dropping by 1,105 MW month-on-month and falling below average seasonal levels for the first time in five months. Wind generation fell by around 14% month-on-month, partially offsetting—but not reversing—the impact of strong solar output.

Taken together, these shifts imply growing reliance on solar-heavy midday structures while leaving systems more exposed during evening ramping hours—supporting a business case for BESS deployment, flexible gas generation where it can monetize balancing needs and ancillary services more effectively, balancing assets and interconnection optimisation.

Lower gas prices don’t restore thermal profitability under carbon pressure

Gas markets eased during April as Austrian CEGH spot gas averaged €47.17/MWh, down 11.3% month-on-month (though still substantially above April 2025). However, lower gas did not rescue gas-fired generation economics because clean spark spreads remained deeply negative due to weak daytime power prices combined with elevated EUA costs and severe solar-driven price suppression.

The report states that high-efficiency gas plants recorded base-load losses of approximately €23.1/MWh after fuel and carbon costs; low-efficiency units lost nearly €38.7/MWh. Peak-product economics were even worse.

This is presented as a signal for future SEE thermal investment strategy: merchant gas generation without capacity remuneration or reliable balancing/ancillary-service monetisation is becoming harder to justify under market structures dominated by solar oversupply alongside high carbon costs.

EUA stays elevated; CBAM begins to reshape cross-border arbitrage

EUA prices averaged €73.8/t during April, about 5.5% higher than March levels.

The review’s CBAM section offers early operational evidence of how the mechanism is affecting Western Balkan electricity trading dynamics: Energy Community Secretariat assessments cited in the report indicate commercial cross-border electricity exchanges declined by roughly 25% in Q1 2026 even though Western Balkan power prices remained around €30/MWh lower than neighboring EU markets.

The mechanism is described as eroding traditional arbitrage economics because imported electricity is treated under default fossil-carbon assumptions regardless of actual generation mix. Montenegro’s EPCG reportedly recorded approximately €13 million in Q1 losses linked to CBAM introduction.

A shift from €/MWh scarcity toward hourly flexibility—and combined electricity-carbon valuation

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.

The report frames this as a move away from a pure €/MWh framework toward a combined electricity-and-carbon valuation structure—and describes April as evidence that SEE markets are entering a different phase from the earlier energy-crisis cycle of 2021–2023.

Instead of scarcity-driven price spikes alone, April showed the coexistence of midday negative pricing alongside evening scarcity premiums; structurally weaker fossil economics; carbon-border distortions; and widening divergence between flexible and inflexible assets value profiles based on hourly positioning rather than baseload performance alone.