Carbon convergence across Europe is widely framed as a force that will marginalise gas over time. In South-East Europe, the opposite effect dominates the medium-term reality. As carbon costs rise and coal and lignite exit faster than grids and flexibility can be rebuilt, gas becomes more important to price formation, system stability, and volatility management—not because it grows in volume, but because it becomes marginal in more hours. Seasonal adequacy assessments by ENTSO-E outline capacity balances under assumed transitions; market behaviour shows that the sequencing of carbon convergence turns gas into the primary transmission channel of risk.
The core of the issue is timing. Carbon pricing, CBAM exposure, and policy pressure compress the economics of coal and lignite quickly. Replacement assets—storage, grid reinforcement, inertia substitutes, and firm low-carbon capacity—arrive slowly. In systems such as Serbia, Romania, and Bulgaria, this sequencing shifts the marginal hour toward gas long before it removes volatility from the system. The result is a paradox: decarbonisation increases gas marginality and volatility at the same time.
Quantitatively, the effect is already visible. As carbon costs rise, coal units that once anchored winter pricing at €25–35/MWh fuel-equivalent costs are displaced. Gas-fired units with all-in marginal costs of €70–120/MWh increasingly set prices during peak and shoulder hours. This does not mean gas runs more; it means that when the system is tight, gas is the only option left. Each coal exit therefore increases the number of hours in which gas becomes marginal, even if total gas burn remains flat.
Forward markets reflect this logic. Winter peak electricity products across South-East Europe carry persistent premia of €40–70/MWh over baseload, even in years when gas curves are flat or declining. This premium is not a bet on higher gas prices; it is a bet on more frequent gas marginality under constrained conditions. Traders price the probability that carbon convergence removes coal before flexibility is ready.
Grid constraints amplify the impact. As coal exits concentrate in specific zones—southern Romania, western Bulgaria, and parts of Serbia—gas marginality increasingly coincides with saturated corridors. When this happens, a gas-driven marginal cost of €90/MWh does not propagate evenly; it fragments. Prices in constrained zones spike to €250–350/MWh, while neighbouring zones clear far lower. Carbon convergence thus turns gas into a locational volatility trigger.
Balancing markets reveal the same story. Coal retirements remove synchronous inertia and ramping capability. Gas plants increasingly provide frequency support and reserve, even when not running at high load. During low-inertia periods, balancing prices in SEE have exceeded €600/MWh, reflecting scarcity of fast response rather than fuel cost. Carbon convergence accelerates these conditions, increasing reliance on gas as a system stabiliser.
For traders, this reframes carbon risk. Carbon convergence does not simply steepen fuel curves; it reshapes state probabilities. The probability distribution shifts toward more frequent high-stress states in which gas sets prices under constraint. Directional gas views capture little of this; conditional exposure captures most of it. The value lies in options, spreads, and intraday positioning that activate when coal is gone and gas is marginal.
For industrial electricity buyers, the implication is equally counterintuitive. Decarbonisation does not automatically reduce price risk. In the transition phase, it increases exposure to gas-driven peaks. Buyers who assume that coal exits lower volatility often face higher peak costs instead. Electricity contracts indexed to gas protect against sustained fuel rallies but not against carbon-driven structural scarcity.
The cost concentration reinforces the point. In decarbonising SEE systems, 20–30% of annual electricity spend can be determined in hours when gas is marginal under constraint. Those hours grow more frequent as coal capacity disappears. Buyers who focus on average €/MWh outcomes miss where the risk migrates. Paying €4–8/MWh more on average to cap peak exposure or secure flexibility often outperforms chasing marginal discounts in a carbon-converging system.
Policy design lags market reality. Capacity mechanisms, where present, remain nationally scoped and energy-centric. They underpay fast response and overpay nominal capacity. The result is underinvestment in the very gas assets that decarbonisation relies on for stability. Markets then price the gap through volatility rather than resolution.
The unified conclusion is structural. In South-East Europe, carbon convergence does not sideline gas; it elevates its systemic importance. Gas becomes the bridge fuel not just for energy, but for price formation and risk transmission. Until grids are reinforced, storage withdrawal expanded, and low-carbon flexibility scaled, gas will remain the marginal stabiliser—and the marginal risk.
Traders who treat carbon convergence as a linear fuel story will misprice convexity. Industrial buyers who assume decarbonisation equals stability will misjudge exposure. The transition will ultimately reduce emissions, but in the medium term it concentrates risk into fewer hours and fewer assets. Gas sits at that fulcrum. How it is paid for—and how its risks are managed—will determine whether the transition is orderly or volatile.