Electricity traders once focused primarily on forecasting demand, generation and weather. With flow-based coupling and increasingly sophisticated capacity calculations, another variable has become equally important: the border itself. The amount of transmission capacity available between markets can now influence spreads almost as strongly as the fundamentals within each market.
The basic logic of cross-border electricity trading appears simple.
Buy power where it is cheaper and sell it where it is more expensive.
In practice, however, there is one crucial condition: transmission capacity must be available.
When a border is unconstrained, arbitrage tends to push prices toward convergence. When capacity is limited, neighbouring markets can separate sharply.
Transmission capacity can therefore be viewed as an economic option on price convergence.
A megawatt of capacity may have little value when two markets clear at similar prices. When the markets separate by €50/MWh, however, that same megawatt can become highly valuable.
For Southeast European traders, this means forecasting national fundamentals is no longer enough. Network conditions have become part of the price forecast.
ACER’s 2026 analysis of Southeast European electricity markets continues to highlight cross-zonal capacity as an important factor in regional price formation, while calling for greater availability of transmission capacity for cross-border trading and improved utilisation of the network.
The commercial implication is straightforward.
A trader may correctly forecast a Bulgarian surplus at the same time as anticipating a Greek shortage. But the size of the eventual BG-GR spread will depend partly on how much Bulgarian electricity can actually be transferred south.
The same principle applies to Hungary-Romania, Hungary-Croatia and other interconnected markets.
This creates what can be described as capacity surprise risk.
Imagine a trader expects 1,000 MW of commercial capacity across a relevant interface. A subsequent calculation reduces that figure to 600 MW.
National demand has not changed.
Solar output has not changed.
Fuel prices have not changed.
Yet the expected price spread can widen significantly because the market has lost part of its ability to arbitrage the difference.
The opposite can happen when additional capacity becomes available.
A previously isolated spread can suddenly become tradable, while an attractive price difference can disappear once new transmission capacity allows more power to flow.
This is why cross-border capacity increasingly deserves the same attention as weather and generation forecasts.
The challenge becomes more complex with flow-based market coupling.
Instead of treating each border independently, flow-based calculations consider how transactions affect critical network elements across a broader interconnected system.
A trade between two bidding zones can therefore consume capacity on network elements that are not physically located on their direct border.
The result should be more efficient use of the grid because market coupling reflects the physical behaviour of the wider network more accurately.
For traders, however, it also means that traditional bilateral ATC-style analysis is becoming less sufficient.
The implementation of Core Advanced Hybrid Coupling in June 2026 adds another layer to this evolution. The approach incorporates selected Core external borders into a more coordinated flow-based framework, further strengthening the relationship between market coupling and regional network conditions.
For SEE trading desks interacting with Core markets, border behaviour is therefore increasingly determined by regional network optimisation rather than a simple bilateral capacity figure.
That requires an evolution in the trading model.
The first layer remains the fundamentals forecast: load, renewable generation, hydro conditions, thermal availability and fuel economics.
The second layer is expected price formation in each bidding zone.
The third is network-state forecasting.
Which critical network elements are likely to become constrained?
Which borders could receive additional capacity?
Where might remedial actions alter available margins?
How much capacity is likely to remain after wider European optimisation?
Not every trading desk needs to develop a full transmission-system-operator-grade grid model.
But increasingly, ignoring capacity calculations carries a similar risk to ignoring the weather forecast.
There is also an important intraday dimension.
Day-ahead capacity is calculated using a particular set of system assumptions. As delivery approaches, network conditions become clearer and available capacity can be reassessed using more recent information.
Cross-border optionality can therefore change significantly after the day-ahead auction.
A spread that initially appears trapped may suddenly become arbitrageable.
A spread that looks highly attractive may become impossible to access.
The economic value of the border can therefore change throughout the trading day.
This creates a new category of short-term strategy: capacity-event trading.
The signal is not simply that Market A is cheaper than Market B. The more valuable signal may be that new information about transmission capacity changes the probability that the price difference will persist.
That could become one of the defining differences between traditional Southeast European electricity trading and the next generation of regional power desks.
Fundamentals explain why two markets should diverge.
Capacity determines whether that divergence can survive.
Elevated by virtu.energy