If South-Eastern Europe’s electricity market has a single structural feature that repeatedly converts manageable system stress into extreme price volatility, it is congestion. Congestion is not just an engineering term. In SEE it functions as a macroeconomic mechanism. It determines whether neighbouring markets can share surplus and scarcity, whether price spikes remain local or are diluted, and whether the region behaves as a single integrated system or as a set of fragmented islands. In a transition era defined by renewables variability and rapid ramping requirements, cross-border capacity is not simply a trade asset. It is price insurance.
The European electricity market was designed around the logic that trade mitigates scarcity. When one zone experiences tightness, it imports from another. When one zone has surplus, it exports. This mechanism works only if interconnectors are available and market coupling is properly implemented. In SEE, the interconnectors exist physically in many cases, but the operational and regulatory availability of capacity often remains below what the system could use during stress periods. The result is price divergence and volatility that is not purely driven by demand or fuel prices, but by constraints on movement of electricity.
Summer 2024 provided one of the clearest demonstrations. South-East Europe experienced intense evening price spikes, linked to high temperatures, strong demand, and the post-sunset collapse of solar generation. What turned this into a systemic crisis pattern was the inability of the region to import sufficient lower-priced electricity from neighbouring zones in time. ACER’s monitoring of cross-zonal capacities and congestion management concluded that higher availability of cross-zonal capacities in central Europe would have mitigated both the frequency and severity of these high-price events in South-East Europe.
The quantitative findings matter because they put a value on congestion relief. Meeting the legally defined 70% capacity requirement would have prevented approximately half of the most severe price spikes, according to the report. A secondary summary of that same analytical work indicated that implementation of the 70% rule could have enabled an average reduction of peak prices by up to €78/MWh in central and south-east bidding zones when comparing realised day-ahead evening peaks with a counterfactual scenario. This is an enormous number in electricity economics. A €78/MWh reduction is not a marginal improvement; it is the difference between “stress pricing” and “crisis pricing” for industrial users.
The insurance logic becomes clearer when viewed as a system design question. A country can respond to scarcity in two ways. It can overbuild domestic capacity to cover every possible stress event, or it can invest in interconnection and market coupling to access regional surplus when needed. Overbuilding is expensive, politically contentious, and often results in low utilization assets. Market integration is cheaper in the long run but requires coordinated governance, trust among TSOs, and discipline in capacity allocation.
In SEE, this choice has direct competitiveness consequences. Persistently higher wholesale prices in the region compared with many Western European markets have been partly structural, reflecting generation mix and lower nuclear/hydro buffers. But the severity of spikes and the persistence of price divergence are heavily influenced by cross-border constraints. When capacity is withheld from the market or reduced by operational limitations, local scarcity is priced as if the country were an island, even when surplus exists nearby. This undermines industrial competitiveness and amplifies the political sensitivity of electricity costs.
Capacity availability is therefore not a technical add-on. It is a policy lever that determines whether markets behave competitively. In a coupled market, scarcity is shared and moderated; in a fragmented market, scarcity is punished locally.
This is why the cross-zonal capacity debate is not merely a compliance issue. The 70% rule is a quantifiable stability instrument. It forces transmission operators and regulators to prioritise market availability of interconnector capacity, reducing the scope for structural bottlenecks to create artificial isolation. When implementation is incomplete, volatility becomes an outcome. When implementation improves, volatility becomes manageable.
In the SEE context, cross-border capacity is also a decarbonisation enabler. As wind and solar expand, net load becomes more volatile. The system requires access to flexible imports and exports in response to weather shifts. Interconnectors function as balancing valves. If they are constrained, renewables cause curtailment in surplus hours and price spikes in deficit hours. If they are available, renewables can be absorbed regionally, reducing both curtailment and scarcity pricing.
The early 2026 market pattern illustrates this interaction in micro form. In Week 01, prices fell materially as wind output surged, and then rebounded sharply in Weeks 02 and 03 when conditions tightened. In such a regime, the ability to move power across borders during tight hours determines whether volatility remains tolerable. When markets are connected and capacity is available, the system behaves like an integrated portfolio. When borders constrain flows, each national market experiences volatility as if isolated.
Trading behaviour reinforces the importance of this mechanism. As liquidity and cross-border flows increased in January 2026, traders reasserted dominance in monetising volatility. This is not inherently negative. It is the natural consequence of congestion economics: when interconnector capacity is scarce, it becomes valuable. If market coupling and capacity allocation are transparent and robust, congestion rents reflect real scarcity and incentivise investment. If they are opaque or inconsistent, congestion rents become a source of distortion and political tension.
Cross-border capacity as price insurance also has a governance dimension. TSOs must coordinate on capacity calculation, outage planning, and operational security standards. Regulators must ensure that capacity is not withheld excessively under the banner of security margins. Market coupling must work in practice, not just on paper. The Energy Community’s own reporting highlights steady but uneven progress toward deeper integration and completion of market coupling as a core priority. The institutional message is clear: without full integration, SEE will remain structurally exposed to volatility events that are not necessary.
The economic conclusion is equally clear. The value of integration is measurable. If fulfilling the 70% requirement can reduce peak pricing by up to €78/MWh, then cross-border capacity availability is one of the highest-return “investments” the region can make, even before building new plants or storage. Price insurance does not come only from reserves; it comes from connectivity.
The strategic implication for SEE governments and regulators is that congestion management must be treated as an industrial policy issue. When electricity costs swing violently, industry investment decisions change. Export competitiveness is weakened. Households face political backlash. Cross-border capacity policy therefore sits at the center of economic stability.
ACER’s monitoring of cross-zonal capacity suggests that meeting the 70% rule could have prevented approximately half of severe price spikes in South-East Europe; analysis indicates peak price reductions of up to €78/MWh in affected bidding zones; reported spikes reached €1,000/MWh and total major spikes numbered 147 during summer 2024 stress conditions.
By virtu.energy
