As Southeast Europe navigates the complexities of energy transition, the dynamics of carbon convergence are reshaping the power landscape. Contrary to the prevailing narrative that suggests a diminishing role for gas, recent trends indicate that gas is becoming increasingly critical for price formation and system stability in the region. This shift is largely driven by rising carbon costs and accelerated coal and lignite retirements, which outpace the development of alternative energy sources and grid enhancements.
The timing of these changes is crucial. With carbon pricing mechanisms and policies like the Carbon Border Adjustment Mechanism (CBAM) intensifying pressure on coal and lignite, their economics are rapidly deteriorating. However, the necessary replacement technologies—such as energy storage, grid reinforcements, and low-carbon capacity—are lagging behind. In countries like Serbia, Romania, and Bulgaria, this transition is pushing gas into a marginal role much sooner than anticipated, leading to increased volatility in electricity prices.
Quantitative evidence supports this trend. As carbon costs escalate, traditional coal units that previously set winter prices at €25–35/MWh are being replaced by gas-fired units with marginal costs ranging from €70–120/MWh. This does not necessarily mean that gas consumption will rise; rather, it indicates that during periods of tight supply, gas becomes the only feasible option available. Consequently, each coal unit retirement increases the number of hours where gas sets market prices, even if overall gas usage remains stable.
Market behavior reflects this emerging reality. Winter peak electricity products in Southeast Europe are trading at premiums of €40–70/MWh over baseload prices. This premium is not merely a speculation on rising gas prices; it represents an expectation of more frequent instances where gas will be the marginal source of electricity under constrained conditions. Traders are pricing in the likelihood that coal will exit before sufficient flexibility can be integrated into the system.
Grid limitations further exacerbate these developments. As coal retirements occur in concentrated areas such as southern Romania and western Bulgaria, gas marginality often aligns with congested transmission corridors. In such scenarios, a marginal cost for gas at €90/MWh can lead to price spikes in constrained zones reaching €250–350/MWh, while neighboring areas experience significantly lower prices. This phenomenon illustrates how carbon convergence transforms gas into a trigger for locational volatility within power markets.
Balancing markets also highlight these shifts. The exit of coal reduces synchronous inertia and ramping capabilities within power systems. Gas plants are increasingly relied upon for frequency support and reserve capacity, even when operating below full load. During periods characterized by low inertia, balancing prices in Southeast Europe have surged beyond €600/MWh due to a scarcity of rapid-response resources rather than fuel costs alone. Carbon convergence accelerates these dynamics and heightens dependence on gas for system stability.
This evolving landscape redefines carbon risk for traders. The implications of carbon convergence extend beyond mere fuel price escalations; they significantly alter state probabilities within market conditions. The distribution of potential outcomes shifts toward scenarios where high-stress situations become more common, necessitating a focus on conditional exposures rather than simplistic directional views on gas prices. The strategic value lies in options trading and intraday positioning that activate when coal exits the market.
For industrial electricity consumers, these developments present counterintuitive challenges. The transition toward decarbonization does not inherently reduce price volatility; instead, it may increase exposure to peaks driven by gas pricing during transitional periods. Buyers who assume that phasing out coal will lead to lower volatility may find themselves facing higher peak costs instead. Contracts indexed to gas may offer some protection against sustained price rallies but fall short against structural scarcities driven by carbon dynamics.
The concentration of costs reinforces this point further. In decarbonizing Southeast European markets, approximately 20–30% of annual electricity expenditures can be dictated by hours when gas is marginal under constrained conditions. As coal capacity diminishes, these critical hours become more frequent. Buyers focusing solely on average €/MWh outcomes risk overlooking where their exposure truly lies; investing an additional €4–8/MWh to mitigate peak exposure or secure flexibility may yield better results than pursuing marginal discounts in a transitioning market.
Unfortunately, policy frameworks have yet to catch up with these market realities. Existing capacity mechanisms tend to be nationally focused and energy-centric, often undervaluing fast-response capabilities while overvaluing nominal capacity. This misalignment has led to underinvestment in essential gas assets necessary for maintaining stability during this transition period. Consequently, market participants are experiencing increased volatility instead of resolution.
Ultimately, the structural implications are clear: in Southeast Europe, carbon convergence does not diminish the importance of gas; it elevates its role within the power system significantly. Gas is transforming into a bridge fuel essential not only for energy supply but also for price formation and risk management. Until infrastructure improvements are made—such as grid enhancements and expanded storage capabilities—gas will continue to serve as both a stabilizer and a source of risk within the region’s electricity markets.
