Carbon pricing has become a central variable in electricity price formation across South-East Europe, reshaping dispatch economics, forward curves and long-term investment signals. While SEE markets still display wide spot price dispersion, the influence of EU carbon pricing is increasingly uniform, acting as a structural cost layer embedded in marginal generation regardless of local price levels. The data from 25 February 2026 confirms that carbon exposure is no longer a peripheral consideration for SEE power markets, but a defining driver of both volatility and trend pricing.
On that date, EUA Dec-26 contracts rose by 2.17%, reinforcing upward pressure on all carbon-exposed thermal generation. This increase occurred against a backdrop of elevated fossil generation in the region, with coal output at 7,182 MW and gas generation at 5,877 MW. Together, these units remain decisive in setting marginal prices during peak hours, particularly in Hungary, Romania and Bulgaria. Carbon costs therefore feed directly into spot and forward pricing, even in markets where daily averages remain comparatively low.
The pass-through mechanism differs across the region. In Hungary, where spot prices reached 107.7 EUR/MWh, carbon pricing is largely internalized through gas-fired marginal units that reference EU fuel and emissions markets. Here, EUA movements translate quickly into power prices, tightening clean spark spreads and elevating forward curves. Slovenia and Croatia follow a similar pattern, reflecting closer integration with EU hubs and higher exposure to carbon-priced generation.
In contrast, Western Balkan markets such as Serbia, Montenegro and Albania cleared between 45.5 and 54.5 EUR/MWhon 25 February. At first glance, these prices appear insulated from EU carbon costs. In practice, however, carbon pricing affects these markets indirectly through imports and peak pricing. When hydro or renewable output is insufficient, marginal imports originate from carbon-exposed systems, embedding EUA costs into local clearing prices. The insulation is therefore conditional, not structural.
Coal-heavy systems face the most pronounced carbon exposure. With coal still accounting for 19% of regional generation on 25 February, rising EUA prices materially alter dispatch order and profitability. Even where coal fuel prices stabilize, carbon costs erode dark spreads and push coal units higher up the merit order. This dynamic accelerates the displacement of coal during non-peak hours while increasing reliance on imports or gas during peak demand.
Gas-fired generation is not immune. Austrian CEGH gas forwards for Mar-26 traded at 33.26 EUR/MWh, while Q2-26 stood at 33.00 EUR/MWh. Combined with rising EUA prices, these levels sustain elevated marginal costs for gas units. Clean spark spreads therefore remain sensitive to even modest carbon price movements, amplifying forward power volatility in gas-exposed markets.
Carbon pricing also reshapes cross-border dynamics. The HU–DE spot spread of 13.7 EUR/MWh reflects not only congestion but differing carbon pass-through intensity. As Germany internalizes higher carbon costs through gas and coal dispatch, price signals propagate into Hungary and onward into SEE via imports. Carbon thus becomes a cross-border transmission mechanism, exporting cost pressure even where local generation is less carbon-intensive.
Renewables partially counterbalance this effect. On 25 February, wind and solar output reached 5,704 MW, suppressing marginal pricing during daylight hours and reducing immediate carbon pass-through. However, this mitigation is temporal. Evening ramps restore thermal marginality, re-exposing markets to carbon costs precisely when demand peaks. As renewable penetration increases, the intraday volatility of carbon influence intensifies rather than diminishes.
Forward markets increasingly reflect this reality. Power forward curves embed expectations of sustained carbon tightening, particularly beyond 2026. Hungarian forward prices around 95–100 EUR/MWh for WK10–WK11 and ~95 EUR/MWh for Cal-26 indicate that markets do not expect carbon relief to offset fuel costs . Instead, forward pricing assumes that carbon will remain a binding constraint on thermal generation economics.
For Balkan markets with limited forward liquidity, carbon exposure manifests through proxy pricing. Utilities and traders hedge via Hungarian or Slovenian contracts, implicitly importing carbon risk into their portfolios. This creates a structural asymmetry: carbon costs influence hedging behavior even where spot prices appear detached. The result is a gradual convergence of risk profiles without equivalent convergence of price levels.
Carbon pricing also interacts with investment signals. Sustained EUA pressure weakens the investment case for new coal capacity and raises hurdle rates for gas projects unless supported by capacity mechanisms or long-term contracts. Conversely, it strengthens the relative economics of hydro, renewables and storage. The emergence of assets such as Bulgaria’s 124 MW / 496.2 MWh battery system reflects this shift, as storage captures value from carbon-driven volatility rather than competing on marginal generation cost .
From a system perspective, carbon pricing accelerates the stratification of SEE markets. Carbon-exposed hubs align more closely with EU pricing, while hydro-buffered markets experience delayed adjustment followed by sharper episodic repricing when constraints bind. This pattern reinforces the layered regional structure observed across spot and forward markets.
The data from 25 February demonstrates that carbon pricing no longer acts solely as an environmental policy instrument. It has become a financial and operational force shaping dispatch, trade flows and hedging strategies across SEE. Even where local prices remain low, carbon costs exert gravitational pull through imports, forward curves and risk management practices.
In this context, SEE power markets are entering a phase of carbon-driven repricing rather than gradual convergence. The influence of EUA markets will continue to expand as renewable penetration rises and coal exits accelerate. For market participants, carbon exposure must therefore be treated as a core structural variable, not a secondary adjustment.
The implication is clear: while SEE remains price-diverse, it is increasingly carbon-unified. Carbon pricing defines the direction of travel, even where local market structures delay its full expression. As a result, future volatility in SEE power markets is likely to be less about fuel scarcity and more about how rapidly carbon costs are absorbed, transmitted and internalized across an increasingly interconnected — but still asymmetric — regional system.
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