As carbon pricing reshapes cross-border electricity economics, Southeast Europe is seeing a less visible but system-critical effect: the divergence between what traders schedule and what the grid physically transports. In Q1 2026, commercially scheduled exchanges between the Western Balkans and the European Union fell sharply, while physical flows across key corridors remained largely in place and in some cases increased. The result is a growing misalignment that can affect operational predictability, balancing requirements, and how congestion signals translate into investment decisions.
In integrated power markets, nominations for cross-border trades typically track physical movements across interconnectors closely enough for transmission system operators to manage congestion and maintain system balance. That alignment relies on the assumption that commercial schedules reflect the same constraints that govern real-time power distribution. Electricity, however, cannot be routed like a contract path; it follows network physics shaped by impedance and topology. When schedules shift due to regulatory or carbon-related incentives, the grid continues to distribute flows according to Kirchhoff’s laws rather than commercial intent.
Q1 2026 corridor data show scheduled declines with smaller physical reductions
The scale of the mismatch is visible in corridor-level comparisons between commercial schedules and measured physical flows. On the Hungary–Romania interface, commercially scheduled flows declined by nearly 14,000 MWh per day, while physical flows decreased by only around 4,100 MWh per day. A similar pattern appeared on the Romania–Bulgaria border, where commercial exchanges fell by 8,800 MWh per day but physical flows dropped by just 2,900 MWh per day.
These gaps indicate that electricity continued to traverse the paths even as scheduled trading activity contracted. For developers and investors assessing grid access and market exposure, this matters because it changes how “contracted” outcomes map to actual system loading. For operators, it increases the challenge of translating market schedules into reliable forecasts for congestion management and balancing operations.
CBAM changes nominations while generation and demand still drive physics
The Carbon Border Adjustment Mechanism is cited as a key factor intensifying the disconnect by altering the economics of cross-border trade. Traders adjust nominations to minimise exposure to carbon costs, which can reduce scheduled exchanges along corridors where Western Balkan generation is more coal-heavy. Yet the underlying drivers of physical flows—generation patterns, demand centres, and network constraints—do not change at the same pace as commercial decision-making.
This separation between carbon-influenced scheduling and unchanged physical drivers helps explain why physical movements can persist despite reduced commercial volumes. It also introduces a structural risk for long-term market design: settlement frameworks built around scheduled positions may increasingly diverge from real-time system behaviour if coordination does not keep up with carbon-driven trading adjustments.
South–north Western Balkans route highlights hydro-led physical movement versus altered exports
The south–north corridor through the Western Balkans—from Greece through Albania and Montenegro to Bosnia and Herzegovina and onward into EU markets—illustrates how hydrology can dominate real-time flow patterns even when commercial routing changes. 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, producing a mismatch between scheduled exports and actual physical trajectories.
Electricity generated in Albania was often scheduled for export to Greece but physically flowed through Montenegro and Bosnia and Herzegovina toward other EU destinations. For transmission planning teams preparing studies for new interconnection capacity or reinforcement, such behaviour underscores that operational realities may not align with contractual expectations used in early-stage modelling assumptions.
Operational implications: less predictable congestion, more loop flows, higher balancing needs
When commercial schedules align with physical flows, transmission system operators can anticipate congestion points, allocate capacity efficiently, and manage balancing requirements with greater confidence. When alignment breaks down, predictability declines and unscheduled or “loop” flows can emerge. These loop flows can place unexpected stress on parts of the network and raise the risk of congestion or outages.
The concern is grounded in regional experience: the Southeast European grid has faced major stress events in recent years, including the June 2024 blackout triggered by near-simultaneous outages of key transmission lines in Montenegro and Albania. While that event was not directly tied to CBAM, it highlights vulnerability in critical corridors—conditions that could be exacerbated if divergence increases uncertainty in how power actually moves across borders.
Grid efficiency effects: capacity reserved commercially but loaded physically elsewhere
Divergence also affects how transmission capacity is utilised relative to economic expectations. Interconnectors are intended to support cross-border trade based on economic signals reflected in scheduling. If nominations do not match physical flow paths, capacity may be reserved but underutilised from a commercial perspective while network loading continues in different directions due to real-time physics.
For utilities and market participants preparing procurement strategies for balancing services or operational reserves, this can translate into higher system operation costs. Operators may need additional balancing measures to manage unexpected flows, procure reserves to maintain stability, and invest in monitoring and control systems capable of handling increased uncertainty. Over time, those costs are typically recovered through network tariffs.
Market design consequences: weaker congestion signals and added imbalance risk
The mismatch complicates congestion management mechanisms that rely on price signals and capacity allocation processes reflecting scarcity of transmission resources. If physical flows diverge from scheduled trades, price signals may not accurately represent congestion conditions experienced by the grid. Capacity allocation may also fail to reflect actual constraints, undermining market efficiency and potentially distorting pricing inputs used for future investment decisions.
Traders face parallel risks because hedging strategies depend on predictable relationships between schedules and flows. When those relationships weaken, imbalance risk rises: positions that appear hedged based on commercial schedules may not match actual physical outcomes, leading to unexpected costs or penalties tied to system behaviour rather than purely market dynamics.
Regulatory coordination options: improve TSO data sharing and clarify transit treatment under CBAM
From a regulatory standpoint, CBAM aims to align carbon costs across borders and prevent carbon leakage but does not directly account for how electricity distributes physically across networks. The Q1 2026 divergence suggests additional coordination between market design choices and system operation may be required so policy objectives do not inadvertently compromise stability. This is particularly relevant where transit flows are involved because scheduling incentives can change without corresponding changes in real-time power distribution.
One pathway discussed is enhanced cross-border coordination among transmission system operators through improved data sharing, joint capacity calculation, and coordinated congestion management aimed at mitigating unscheduled flow impacts. Greater clarity in CBAM implementation—especially regarding transit flow treatment—could also reduce incentives for traders to alter schedules in ways that exacerbate divergence.
Implications for project readiness across wind, solar integration and storage-backed grids
For renewable developers planning wind and solar projects connected through regional transmission corridors—and for battery energy storage system owners sizing flexibility for grid services—this divergence reinforces the need for engineering studies that test sensitivity to schedule-flow misalignment under evolving carbon-cost regimes. EPC preparation teams preparing grid connection assumptions may need updated modelling inputs that reflect how hydro-driven or load-driven patterns can route physically beyond contracted expectations.
Broader industry implications extend beyond operations into investment planning: if divergence persists without adjustments to settlement logic or congestion signalling effectiveness, system costs may rise through additional balancing needs while market efficiency erodes gradually. Proactive measures aligning policy design with operational realities could support a more stable transition toward carbon-adjusted cross-border trading while maintaining secure delivery of electricity across Southeast Europe’s interconnected grids.