The early impact of the Carbon Border Adjustment Mechanism in Southeast Europe has been widely discussed in terms of pricing, trade flows, and competitiveness. Less immediately visible—but arguably more consequential over the medium term—is its effect on system operation. The first quarter of 2026 reveals that CBAM is not only reshaping market economics but also introducing new layers of operational complexity into the region’s electricity networks. The combination of distorted commercial incentives, unchanged physical flow patterns, and hydro-driven supply surges is beginning to translate into higher system costs, increased grid stress, and elevated operational risk for transmission system operators.
At the core of this dynamic lies the growing mismatch between commercial decisions and physical realities. Market participants, responding to CBAM-related costs, have altered their trading behaviour, reducing scheduled exchanges across certain corridors and rerouting transactions to minimise carbon exposure. However, electricity flows do not respond to commercial signals alone. They are governed by the physical characteristics of the network—impedance, topology, and generation distribution. As a result, even as scheduled flows decline or shift, physical flows continue to follow established pathways, often diverging from the nominated schedules.
This divergence creates a more volatile and less predictable operating environment for transmission system operators. Under normal conditions, TSOs rely on scheduled flows as a key input for system planning. These schedules inform congestion management, reserve allocation, and balancing strategies. When schedules no longer align with actual flows, the effectiveness of these tools is reduced. Operators must rely more heavily on real-time adjustments, increasing the need for ancillary services and raising the cost of maintaining system balance.
The financial implications of this shift are already emerging. Balancing costs, which reflect the expense of correcting deviations between supply and demand, are likely to increase as unpredictability rises. TSOs may need to procure additional reserves to manage unexpected flows, particularly during periods of high renewable output or network congestion. These costs are ultimately recovered through network tariffs, meaning that the impact of CBAM-induced distortions is transmitted to end consumers across both EU and non-EU markets.
The strain on the grid is particularly evident along key transmission corridors. The south–north axis through the Western Balkans—from Greece through Albania and Montenegro to Bosnia and Herzegovina and onward into EU markets—has long been a critical pathway for electricity flows. In Q1 2026, this corridor experienced increased physical loading due to strong hydro generation in Greece and Albania. At the same time, commercial flows along this route were altered by CBAM considerations, leading to a divergence between scheduled and actual usage. The result is a corridor operating under higher stress, with increased risk of congestion and reduced operational flexibility.
Such conditions heighten the risk of system disturbances. The Southeast European grid has a history of vulnerability in this regard, as demonstrated by the blackout event of June 2024, which was triggered by the simultaneous outage of key transmission lines in Montenegro and Albania. While that event was not directly linked to CBAM, it underscores the sensitivity of the system to disruptions in critical corridors. The current divergence between commercial and physical flows introduces additional uncertainty, making it more challenging for TSOs to anticipate and manage potential stress points.
Another dimension of operational risk arises from the inefficient utilisation of transmission capacity. Interconnectors are designed to facilitate economically efficient trade, with capacity allocated based on expected flows. When commercial schedules diverge from physical reality, capacity may be underutilised in some directions while overloaded in others. This inefficiency reduces the overall effectiveness of the network and can lead to situations where available capacity is not used optimally, even as parts of the system experience congestion.
The impact of CBAM on system operation is further complicated by the interaction with generation patterns. The surge in hydro output during Q1 2026 introduced large volumes of low-cost electricity into the system, particularly in the Western Balkans and Greece. While this enhanced supply security and reduced reliance on fossil fuels, it also created new challenges in managing flows. Excess generation must be transported to areas of demand, often across long distances and through constrained corridors. When commercial incentives discourage certain routes, physical flows may concentrate on others, increasing the risk of bottlenecks.
The decline in coal generation, which fell by −16% across the region, also has operational implications. Coal plants, with their relatively stable output, have traditionally provided a degree of predictability to the system. As they are displaced by hydro and other renewables, the variability of generation increases. While hydro is more controllable than wind or solar, its output is still influenced by hydrological conditions, which can change rapidly. The combination of variable generation and distorted trade flows creates a more complex environment for system balancing.
From a cost perspective, the cumulative effect of these factors is likely to be significant. Increased balancing requirements, higher reserve procurement, and the need for enhanced monitoring and control systems all contribute to rising operational expenditures for TSOs. These costs are not isolated; they are distributed across the system through tariffs and charges, affecting consumers and market participants alike. Over time, this could lead to a structural increase in the cost of electricity, partially offsetting the efficiency gains expected from market integration.
The operational challenges posed by CBAM also have implications for investment in grid infrastructure. As flow patterns become less predictable and more concentrated along certain corridors, the need for reinforcement and expansion of transmission networks becomes more pressing. Investments in interconnectors, substations, and control systems may be required to accommodate the new flow dynamics and ensure system stability. However, the economic justification for such investments is complicated by the same factors that are reshaping trade flows. If certain corridors are underutilised due to CBAM costs, the revenue streams that support infrastructure investment may be weakened.
This creates a feedback loop in which market distortions influence infrastructure utilisation, which in turn affects investment decisions and future system capability. Managing this loop will be a key challenge for both regulators and system operators. Strategic planning must account not only for current flow patterns but also for the potential evolution of those patterns as market participants adapt to CBAM and as generation portfolios shift.
Coordination between TSOs becomes increasingly important in this context. Cross-border flows require coordinated capacity calculation, congestion management, and balancing strategies. The divergence between commercial and physical flows makes such coordination more complex, as operators must reconcile differing signals from market schedules and real-time system behaviour. Enhanced data sharing, joint operational planning, and the development of regional coordination centres could help address these challenges, but they require investment and institutional alignment.
Regulatory clarity is another critical factor. Uncertainty regarding the treatment of transit flows under CBAM has been a key driver of the observed divergence in Q1 2026. Providing clear and consistent rules for how electricity passing through non-EU countries is treated could reduce the incentive for traders to alter schedules in ways that exacerbate system inefficiencies. Similarly, adjustments to emission factor methodologies that better reflect actual generation could align commercial incentives more closely with physical realities.
The interaction between CBAM and the EU ETS adds an additional layer of operational risk. As carbon prices fluctuate, the cost of cross-border trade changes, influencing trading behaviour and, by extension, flow patterns. This introduces a dynamic element to system operation, where changes in the carbon market can have immediate effects on electricity flows. TSOs must therefore monitor not only physical and market variables but also developments in the carbon market, integrating these into their operational planning.
Looking ahead, the persistence of CBAM-induced distortions will depend on how market participants and policymakers respond. If current patterns continue, the region may face a sustained period of higher system costs and increased operational complexity. Conversely, measures that align commercial incentives with physical realities—such as improved market coupling, enhanced transparency, and coordinated carbon pricing—could mitigate these effects and support a more efficient transition.
What is clear from Q1 2026 is that the impact of CBAM extends beyond market prices and trade volumes into the fundamental operation of the electricity system. The divergence between commercial schedules and physical flows, the concentration of stress on key corridors, and the rising cost of system management all point to a market in transition. Managing this transition effectively will require a combination of technical, regulatory, and market-based solutions, ensuring that the pursuit of decarbonisation does not come at the expense of system stability and efficiency.
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