One of the least visible but most systemically important consequences of the Carbon Border Adjustment Mechanism in Southeast Europe’s electricity markets is the growing divergence between commercially scheduled flows and actual physical electricity movements. While price spreads, trade volumes, and carbon costs dominate market headlines, it is this structural misalignment between what traders nominate and what the grid actually delivers that carries the most profound implications for system stability, operational costs, and long-term market design.
Under normal conditions in an integrated electricity market, there is a close alignment between commercial schedules and physical flows. Market participants nominate cross-border trades based on price signals, and these nominations broadly correspond to the physical movement of electricity across interconnectors. The grid, in turn, operates within predictable parameters, allowing transmission system operators to manage congestion, maintain balance, and ensure security of supply. This alignment is a cornerstone of efficient market functioning.
In Q1 2026, that alignment began to break down. Data from across Southeast Europe show that while commercially scheduled exchanges between the Western Balkans and the European Union declined significantly, physical flows through the region remained largely intact—and in some cases even increased along specific corridors. This divergence reflects a fundamental shift in the drivers of electricity movement: commercial decisions are now increasingly influenced by CBAM-related costs and regulatory considerations, while physical flows continue to follow the laws of electrical physics.
The scale of this divergence is illustrated by several corridor-level observations. On the Hungary–Romania interface, commercially scheduled flows declined by nearly 14,000 MWh per day, yet physical flows decreased by only around 4,100 MWh per day. A similar pattern emerged on the Romania–Bulgaria border, where commercial exchanges fell by 8,800 MWh per day, while physical flows dropped by just 2,900 MWh per day. These discrepancies indicate that electricity continued to flow along these paths despite a reduction in scheduled trading activity, effectively bypassing the commercial framework.
This phenomenon is not an anomaly but a predictable outcome of how electricity systems operate. Unlike other commodities, electricity cannot be directed along a single contractual path. It flows through the network according to Kirchhoff’s laws, distributing itself across all available paths based on impedance and network topology. When commercial schedules change—whether due to price signals, regulatory costs, or trading strategies—the physical system does not instantly reconfigure itself to match those schedules. Instead, it continues to operate according to its inherent physical properties.
The introduction of CBAM has intensified this disconnect. By altering the economics of cross-border trade, CBAM has led traders to adjust their nominations in ways that minimise exposure to carbon costs. This has resulted in reduced scheduled exchanges along certain corridors, particularly those involving coal-heavy Western Balkan systems. However, the underlying physical drivers of electricity flows—such as generation patterns, demand centres, and network constraints—have not changed in tandem. As a result, electricity continues to move through the system along established pathways, even when those flows are no longer reflected in commercial schedules.
The south–north corridor through the Western Balkans provides a particularly important case study. This route, running from Greece through Albania and Montenegro to Bosnia and Herzegovina and onward into EU markets, has long been a critical artery for regional electricity flows. In Q1 2026, increased hydro generation in Albania and Greece led to a surge in physical flows along this corridor. At the same time, CBAM-related considerations altered commercial trading patterns, leading to a mismatch between scheduled exports and actual flows. Electricity generated in Albania, for example, was often scheduled for export to Greece but physically flowed through Montenegro and Bosnia and Herzegovina towards other EU destinations.
This divergence has several operational implications. For transmission system operators, the predictability of flows is essential for maintaining system stability. When commercial schedules align with physical flows, TSOs can anticipate congestion points, allocate capacity efficiently, and manage balancing requirements. When this alignment breaks down, the system becomes less predictable. Unscheduled or “loop” flows can emerge, placing unexpected stress on parts of the network and increasing the risk of congestion or even outages.
The risk is not theoretical. The Southeast European grid has experienced significant stress events in recent years, including the blackout of June 2024, which was triggered by the near-simultaneous outage of key transmission lines in Montenegro and Albania. While that event was not directly related to CBAM, it highlights the vulnerability of the system to disruptions in critical corridors. The divergence between commercial and physical flows observed in Q1 2026 introduces an additional layer of complexity that could exacerbate such risks if not properly managed.
Another consequence of this divergence is the inefficient utilisation of transmission capacity. Interconnectors are designed to facilitate cross-border trade based on economic signals. When commercial schedules do not reflect physical flows, capacity may be allocated in ways that do not correspond to actual system needs. This can lead to situations where capacity is reserved but underutilised in commercial terms, while physical flows continue to load the network in different directions. The result is a suboptimal allocation of resources, with potential cost implications for both system operators and market participants.
These inefficiencies are likely to translate into higher system operation costs. TSOs must deploy additional balancing measures to manage unexpected flows, procure reserves to maintain system stability, and invest in monitoring and control systems to cope with increased uncertainty. Over time, these costs are typically passed on to consumers through network tariffs. In this sense, the divergence between commercial and physical flows represents not only a technical challenge but also an economic burden that affects the entire system.
The impact on market participants is equally significant. Traders rely on predictable relationships between schedules and flows to manage their positions and optimise their portfolios. When these relationships break down, the risk of imbalance increases. Positions that appear hedged based on commercial schedules may not align with actual physical outcomes, leading to unexpected costs or penalties. This adds a new dimension to trading risk, one that is closely linked to system behaviour rather than purely market dynamics.
The divergence also complicates the functioning of congestion management mechanisms. In integrated markets, congestion is typically managed through price signals and capacity allocation processes that reflect the scarcity of transmission resources. When physical flows diverge from commercial schedules, these mechanisms become less effective. Prices may not accurately signal congestion, and capacity allocation may not reflect actual system constraints. This undermines the efficiency of the market and can lead to distortions in both pricing and investment decisions.
From a regulatory perspective, the challenge is to reconcile the objectives of CBAM with the operational requirements of the electricity system. CBAM is designed to align carbon costs across borders and prevent carbon leakage, but it does not directly account for the physical realities of electricity flows. The divergence observed in Q1 2026 suggests that additional coordination between market design and system operation may be necessary to ensure that policy objectives do not inadvertently compromise system stability.
One potential avenue for addressing this issue is the enhancement of cross-border coordination among TSOs. Improved data sharing, joint capacity calculation, and coordinated congestion management could help mitigate the impact of unscheduled flows. At the same time, greater clarity in the implementation of CBAM—particularly regarding the treatment of transit flows—could reduce the incentive for traders to alter schedules in ways that exacerbate divergence.
Another consideration is the potential evolution of market design to better integrate physical and commercial realities. This could include mechanisms that more accurately reflect the impact of unscheduled flows in pricing and settlement processes, or the development of tools that allow market participants to manage the risks associated with divergence more effectively. Such changes would require careful design to avoid introducing additional complexity or unintended consequences.
Looking ahead, the persistence of divergence between commercial schedules and physical flows will depend on how both market participants and policymakers respond to the new environment created by CBAM. If current patterns continue, the region may face increasing operational challenges, higher system costs, and a gradual erosion of market efficiency. Conversely, proactive measures to align policy, market design, and system operation could mitigate these risks and support a more stable transition to a carbon-adjusted trading framework.
What is clear from Q1 2026 is that the integration of carbon pricing into cross-border electricity trade has implications that extend beyond economics into the physical operation of the grid. The divergence between what is traded and what flows is a manifestation of this broader transformation—a signal that the system is adapting to new constraints but has not yet reached a new equilibrium. Managing this transition will be critical to ensuring that Southeast Europe’s electricity markets remain both efficient and secure in the evolving energy landscape.
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