Electricity.Trade monitoring of environmental markets shows that EU carbon allowances remain a decisive variable in regional power pricing. On 24 February 2026, EUA December 2026 contracts traded near 71–75 EUR/tCO₂, reinforcing the cost burden on coal and gas-fired generation across Central and South-East Europe.
For coal-heavy systems, carbon costs directly erode competitiveness. A coal plant emitting roughly 0.9 tons of CO₂ per MWh faces carbon-related costs exceeding 60 EUR/MWh at current allowance levels. Electricity.Trade analysis indicates that such costs increasingly determine whether coal units operate during marginal hours or yield to gas or imports.
In Hungary and Romania, where gas-fired plants often set marginal prices during peak hours, carbon pricing interacts with gas costs to define the clean spark spread. On days like 24 February, when Hungarian day-ahead prices exceeded 115 EUR/MWh, the implied clean spark margin remained positive but sensitive to small fluctuations in gas or carbon costs.
Electricity.Trade notes that carbon pricing amplifies volatility rather than smoothing it. When wind output declines or demand surges, the need for thermal generation exposes markets to combined fuel and carbon cost escalation. Conversely, during high renewable output, marginal costs drop sharply, compressing spreads.
As SEE markets integrate more deeply with EU structures, carbon pricing will exert increasing influence even in partially coupled systems. Electricity.Trade concludes that modeling clean spark and clean dark spreads is now indispensable for accurate regional risk assessment.
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