The implementation of the Carbon Border Adjustment Mechanism (CBAM) has introduced significant complexities into the electricity markets of Southeast Europe. A notable consequence of this regulatory framework is the increasing disparity between commercially scheduled electricity flows and actual physical movements across the grid. While market discussions often center on price dynamics, trade volumes, and carbon costs, it is this misalignment that poses critical challenges for system stability and operational efficiency.
In a well-functioning integrated electricity market, there typically exists a strong correlation between commercial schedules—nominations made by market participants for cross-border electricity trades—and the actual physical flows of electricity. This alignment facilitates effective management of transmission systems, allowing operators to predict congestion and maintain supply security. However, recent data indicates that this relationship began to deteriorate significantly in the first quarter of 2026.
During this period, exchanges between the Western Balkans and the European Union saw a marked decline in scheduled flows, dropping by approximately 14,000 MWh per day on the Hungary-Romania interface and 8,800 MWh per day on the Romania-Bulgaria border. In contrast, physical flows remained relatively stable, with only a 4,100 MWh per day decrease in Hungary-Romania and a 2,900 MWh per day drop in Romania-Bulgaria. This divergence suggests that while trading activity diminished, electricity continued to traverse these routes largely unaffected.
This phenomenon is not merely incidental; it reflects the inherent nature of electrical systems governed by Kirchhoff’s laws. Unlike other commodities that can be directed along specific contractual paths, electricity flows through networks based on impedance and topology. Consequently, changes in commercial schedules—driven by factors such as CBAM-related costs—do not immediately alter the physical flow patterns within the grid.
The introduction of CBAM has further complicated this dynamic by reshaping the economics of cross-border trade. Traders are now more inclined to adjust their nominations to minimize carbon exposure, leading to reduced scheduled exchanges along certain corridors. However, the fundamental drivers of electricity movement—such as generation sources and demand patterns—remain unchanged, resulting in continued physical flows along established pathways.
An illustrative example is the south-north corridor through the Western Balkans, which serves as a vital route for regional electricity transport. In Q1 2026, increased hydroelectric generation in Albania and Greece contributed to heightened physical flows along this corridor. Yet, CBAM considerations altered commercial trading practices, causing discrepancies between scheduled exports and actual movements. For instance, electricity generated in Albania was often designated for export to Greece but instead flowed through Montenegro and Bosnia and Herzegovina toward other EU markets.
This misalignment carries significant operational implications for transmission system operators (TSOs). Predictable flow patterns are crucial for maintaining grid stability; when commercial schedules diverge from physical flows, TSOs face increased uncertainty. The emergence of unscheduled or “loop” flows can lead to unexpected stress on network components and elevate the risk of congestion or outages.
The Southeast European grid has already experienced considerable stress events, including a major blackout in June 2024 caused by simultaneous outages in Montenegro and Albania’s transmission lines. Although this incident was not directly linked to CBAM, it underscores the vulnerabilities present within critical corridors. The ongoing divergence observed in early 2026 adds another layer of complexity that could heighten operational risks if left unaddressed.
Inefficiencies stemming from this divergence also hinder optimal utilization of transmission capacity. Interconnectors are intended to facilitate cross-border trade based on economic signals; however, when commercial schedules do not align with physical realities, capacity may be allocated inefficiently. This misallocation can result in reserved capacity being underutilized while actual flows impose different demands on the network.
The economic repercussions of these inefficiencies are likely to manifest as increased operational costs for TSOs. Additional balancing measures will be necessary to manage unexpected flows, alongside investments in monitoring systems to navigate heightened uncertainty. Ultimately, these costs may be passed on to consumers through elevated network tariffs.
Market participants also face challenges due to this disconnect. Traders depend on predictable relationships between schedules and actual flows for effective portfolio management. When these relationships falter, positions that appear hedged based on commercial schedules may not correspond with real-world outcomes, leading to unforeseen costs or penalties.
The divergence complicates congestion management mechanisms as well. Effective congestion management relies on accurate price signals and capacity allocation reflecting transmission resource scarcity. When physical flows deviate from commercial schedules, these mechanisms lose efficacy—distorting pricing signals and undermining market efficiency.
Regulatory bodies now face the task of reconciling CBAM objectives with operational realities within electricity systems. While CBAM aims to harmonize carbon costs across borders and curb carbon leakage, it does not directly account for the complexities of physical electricity flows. The divergence noted in Q1 2026 indicates that enhanced coordination between market design and operational requirements is essential to safeguard system stability without compromising policy goals.
To address these challenges effectively, cross-border coordination among TSOs could be improved through better data sharing and joint capacity calculations. Additionally, clarifying CBAM implementation regarding transit flows may help mitigate traders’ incentives to alter schedules in ways that exacerbate divergence.
Looking forward, how market participants and policymakers respond to these evolving dynamics will dictate whether divergence persists or diminishes over time. If left unaddressed, Southeast Europe could encounter escalating operational difficulties and diminishing market efficiency as it adapts to a carbon-adjusted trading environment.
The integration of carbon pricing into cross-border electricity trade has implications extending beyond mere economics; it affects grid operations fundamentally. The observed divergence between traded quantities and actual flows signals an adaptation process within the system that has yet to reach equilibrium—a transition demanding careful management to ensure Southeast Europe’s electricity markets remain efficient and secure amid shifting energy landscapes.
