The gap between commercial electricity schedules and physical power flows widened across the Western Balkan transmission network during the second quarter of 2026, creating an increasingly complex operational challenge for transmission system operators (TSOs).
The most striking example was the Bosnia and Herzegovina–Croatia border. Scheduled exports from Bosnia and Herzegovina to Croatia fell by around 43% year on year, to approximately 282 GWh. Physical flows in the same direction, however, increased by roughly 270%, with more than 800 GWh actually crossing the border.
Physical electricity therefore flowed at almost three times the volume indicated by commercial schedules. The discrepancy had already emerged in the first quarter but became significantly more pronounced during Q2.
The Albania–Greece border showed the opposite pattern. Scheduled Albanian exports remained close to their usual level, increasing by around 3%, while physical flows fell approximately 63%. Electricity commercially scheduled towards Greece appeared instead to flow northwards through Montenegro and Bosnia and Herzegovina.
Broader physical-flow data confirm the strengthening of a south-to-north electricity route. Physical flows from Greece to North Macedonia increased by more than 200%, while North Macedonia-to-Serbia flows rose by a similar magnitude. Physical flows from Montenegro to Bosnia and Herzegovina also increased by more than 200%. The interconnected network was therefore carrying electricity towards Croatia and other EU borders regardless of where commercial transactions had been nominated.
For transmission system operators, commercial schedules are a critical input into grid-security analysis. They allow operators to estimate expected network loading, determine available margins and prepare remedial actions. When physical electricity follows a different path from the commercially nominated transaction, TSOs must maintain larger safety margins and intervene more frequently through redispatch, countertrading and other corrective measures.
These interventions create additional system costs. While the initial costs may be borne by TSOs, they can ultimately be reflected in network tariffs, congestion-management costs and lower transmission capacity available to market participants. The mismatch can also weaken the locational logic of congestion revenues, with income accruing at one border even when the underlying physical congestion occurs elsewhere in the network.
CBAM may be contributing indirectly by changing the commercial routes through which electricity is scheduled. Traders respond to national default emission factors, cross-border price spreads and eligibility requirements, while physical electricity continues to follow the laws of the interconnected grid. The greater the divergence between commercial incentives and physical power flows, the greater the operational pressure placed on grid operators.
The problem cannot be addressed by a single TSO. Coordinated capacity calculation, common network modelling and regional congestion management will become increasingly important across the Western Balkans and neighbouring EU markets. Greater transparency around loop flows, together with harmonised approaches to sharing the costs of remedial actions, will also be needed.
The regional electricity market is being commercially reconfigured faster than the physical grid can adapt. That growing gap creates an infrastructure and regulatory cost that will ultimately be reflected in network tariffs, grid investment requirements and the amount of cross-border transmission capacity that can safely be made available to traders.
