Southeast Europe’s traditional response to grid congestion has been straightforward: build another transmission line, transformer or interconnector. The logic is clear. More renewable generation and rising electricity demand require stronger networks. But construction takes years, permitting can be difficult and equipment supply chains remain under pressure. ACER’s 2026 analysis is therefore significant because it places greater emphasis on better utilisation of existing networks and grid-enhancing technologies, alongside conventional infrastructure investment.
The shift is subtle but important. The electricity grid is no longer simply a collection of physical assets. It is increasingly becoming an operating system that can unlock additional capacity through data, automation, digital controls and flexible demand.
Dynamic line rating provides one of the clearest examples. Transmission lines are often operated according to conservative seasonal limits, even though their actual thermal capacity changes with ambient temperature, wind conditions and solar heating. Sensors and analytical models can determine a higher real-time operating limit when conditions allow. ACER estimates that capacity gains above 50% can be possible in relevant circumstances.
This does not mean that a transmission line permanently becomes 50% larger. The additional capacity depends on weather, location and operating conditions. Nevertheless, dynamic line rating can release valuable network capacity during many hours at a fraction of the time and cost associated with constructing an entirely new transmission corridor.
From copper to algorithms
Grid-enhancing technologies go well beyond dynamic line rating. Advanced conductors can increase transfer capability within existing rights of way, while topology optimisation can adjust network configurations to manage power flows more efficiently.
Improved outage coordination can prevent simultaneous maintenance on critical corridors, while curative remedial actions allow transmission system operators to operate closer to network limits while retaining tools to respond following a contingency. Flow-based capacity calculation can also make a greater share of the physical network available to market coupling.
In each case, engineering information is converted into additional market capacity without necessarily requiring a new physical asset.
At distribution level, the equivalent solution is local flexibility. A transformer may become constrained for only a few hours during winter evenings or periods of peak summer tourism. Instead of immediately reinforcing the entire feeder, a distribution system operator could pay batteries, EV fleets, factories or commercial buildings connected behind that node to modify their electricity consumption during those periods.
Slovenia and other more advanced markets provide early examples of this approach. The economic value of flexibility is highly dependent on location. A megawatt available on the wrong side of a network constraint may have little or no value. Flexibility markets therefore introduce a strong geographical dimension to distribution-system economics.
Investment consequences
This approach also changes how regulators should assess network investment. Traditional regulatory frameworks can favour capital expenditure because utilities typically earn regulated returns on physical infrastructure. Flexibility contracts and software-based solutions may instead appear as operating expenditure, even when they deliver a lower overall system cost.
If regulation fails to recognise that difference, network companies have a rational incentive to continue building physical assets. A modern regulatory framework should therefore compare the net present cost of traditional reinforcement with alternatives such as dynamic line ratings, contracted flexibility, automation and curative network operation.
The implications are equally important for renewable-energy and infrastructure developers. Grid connection is becoming increasingly scarce, and flexible connection agreements could allow projects to connect earlier in exchange for accepting occasional limitations.
A data centre could temporarily reduce non-critical loads, an EV depot could delay charging, while a battery could absorb local surplus electricity. Such arrangements create a middle ground between full firm grid access and rejection of a connection application.
They also create a mechanism for putting a direct economic value on flexibility at the exact location where it is needed.
Regional market impact
Better utilisation of existing transmission infrastructure could reduce electricity price separation between Southeast Europe and Central Europe during periods of network stress, although it will not eliminate structural bottlenecks.
ACER’s finding that limited cross-border capacity intensified price spikes in 2024 demonstrates how directly network operation affects wholesale electricity markets. Increasing available capacity can reduce scarcity rents, change congestion revenues and alter the economics of generation on both sides of a transmission constraint.
As a result, grid-enhancing technology is no longer simply an engineering or procurement issue. It can influence trading strategies, renewable capture prices, industrial electricity costs and the bankability of new energy projects.
A transmission corridor that gains several hundred megawatts of usable capacity can materially change cross-border price spreads even when no new tower or line is constructed. Market participants will therefore increasingly need to monitor the deployment of operational technologies with the same attention they currently give to new interconnectors and transmission projects.
The emerging model
Southeast Europe will still require major investment in its electricity networks. Dynamic line ratings cannot resolve every bottleneck, while local flexibility cannot replace reinforcement where electricity demand is growing structurally.
The emerging model is therefore layered: build where capacity is permanently required, optimise existing infrastructure where operating limits are conservative, and procure flexibility where constraints are temporary.
The most important change may ultimately be institutional rather than technological. TSOs and DSOs will increasingly need to become buyers of technology and flexibility services, rather than acting primarily as builders of regulated infrastructure. Regulators will need to recognise solutions whose value comes from avoided congestion, improved utilisation and deferred capital expenditure.
Customers, batteries, EVs, industrial facilities and other distributed assets will increasingly become part of network planning.
In that sense, the next stage of Southeast Europe’s grid development is not simply about building more infrastructure. It is about turning the existing network into a more dynamic, intelligent and market-responsive system—using prices, contracts, data and digital control to extract more capacity from infrastructure that is already in place.
