European electricity trading is built on the idea that inter-zonal trade reduces scarcity. When one market is tight, it can import from another, while surplus zones can export. The mechanism depends on interconnectors being available and on market coupling operating as intended. In South-Eastern Europe, interconnectors exist in many cases, but operational and regulatory availability of capacity can fall short during stress periods.
When cross-border movement is constrained, prices can diverge across zones. The resulting volatility is not attributed solely to demand or fuel costs. Instead, it reflects limits on transferring electricity between markets. This pattern affects whether SEE behaves as a single integrated system or as separate pricing areas.
Summer 2024 evening spikes and cross-zonal capacity constraints
Summer 2024 showed how these constraints can translate into extreme price outcomes. South-East Europe recorded intense evening price spikes associated with high temperatures and strong demand. The spikes also coincided with the post-sunset collapse of solar generation. ACER monitoring linked the escalation to an inability to import enough lower-priced electricity from neighbouring zones in time.
ACER’s assessment of cross-zonal capacities and congestion management concluded that higher availability of cross-zonal capacity in central Europe would have reduced both the frequency and severity of high-price events in South-East Europe. The monitoring results were framed around capacity availability during stress periods rather than physical interconnector existence alone.
The 70% capacity requirement and quantified peak price relief
The report’s quantitative findings were presented as a way to value congestion relief. Meeting the legally defined 70% capacity requirement would have prevented approximately half of the most severe price spikes, according to ACER’s monitoring work. A secondary summary of the same analytical material indicated that applying the 70% rule could reduce average peak prices by up to €78/MWh. The comparison referenced realised day-ahead evening peaks against a counterfactual scenario.
The analysis also reported that summer 2024 stress conditions included price spikes reaching €1,000/MWh. It stated that total major spikes numbered 147. These figures were used to contextualise the scale of volatility events in the region during that period.
Interconnection versus domestic overbuild in a coupled market
The congestion-relief logic was described as a system design choice for responding to scarcity. One option is overbuilding domestic generation capacity to cover stress events. Another option is investing in interconnection and market coupling so regional surplus can be accessed when needed. Overbuilding was characterised as expensive, politically contentious, and often associated with low utilisation.
Market integration was presented as cheaper over the long run but dependent on coordinated governance. It requires trust among transmission system operators and discipline in how capacity is allocated. In SEE, these design choices were tied to competitiveness outcomes through how often cross-border constraints force local scarcity pricing.
Competitiveness effects from withheld or limited cross-border capacity
The source material linked persistent wholesale price levels in parts of SEE compared with many Western European markets to structural factors such as generation mix and lower nuclear or hydro buffers. It also stated that spike severity and ongoing price divergence are heavily influenced by cross-border constraints. When capacity is withheld from the market or reduced by operational limitations, local scarcity can be priced as if a country were isolated.
This dynamic was described as weakening industrial competitiveness and increasing political sensitivity around electricity costs. Capacity availability was framed as a policy lever affecting whether markets operate competitively. In a coupled market, scarcity is shared and moderated, while in a fragmented market it is punished locally.
Decarbonisation impacts: renewables variability and balancing through imports
Cross-border capacity was also described as relevant for decarbonisation as wind and solar expand across the region. As renewables increase, net load becomes more volatile, increasing the need for flexible imports and exports when weather shifts occur. Interconnectors were characterised as balancing mechanisms for responding to those changes across borders.
If interconnectors are constrained, renewables can face curtailment during surplus hours while deficit hours experience price spikes. If interconnector capacity is available, renewables can be absorbed regionally, reducing both curtailment and scarcity pricing. This connects congestion management with both operational outcomes for renewables and pricing behaviour during stress conditions.
Early 2026 volatility pattern alongside changing cross-border flows
The source described an early 2026 market pattern showing interaction between wind output and prices over consecutive weeks. In Week 01, prices fell materially as wind output surged, followed by a sharp rebound in Weeks 02 and 03 when conditions tightened. It stated that moving power across borders during tight hours affects whether volatility remains tolerable.
When markets are connected and capacity is available, the system was described as behaving like an integrated portfolio. When borders constrain flows, each national market experiences volatility as if isolated. The material also connected this mechanism to trading activity changes over time.
Trading incentives, congestion rents, and governance requirements
As liquidity and cross-border flows increased in January 2026, traders were described as reasserting dominance in monetising volatility. The source linked this behaviour to congestion economics: when interconnector capacity is scarce, it becomes valuable for market participants. It also stated that if market coupling and capacity allocation are transparent and robust, congestion rents reflect real scarcity and can incentivise investment.
If congestion rents are produced through opaque or inconsistent allocation rules, they were described as becoming a source of distortion and political tension. The governance dimension was further tied to coordination responsibilities for transmission system operators on capacity calculation, outage planning, and operational security standards.
Regulators were described as needing to ensure that capacity is not withheld excessively under security margin justifications. Market coupling was described as needing to work in practice rather than only on paper. The Energy Community reporting cited steady but uneven progress toward deeper integration and completion of market coupling as a core priority.
Policy implications tied to measurable peak price effects
The economic case presented in the source material focused on measurable value from integration through reduced peak pricing under the 70% rule. It stated that fulfilling the requirement could reduce peak pricing by up to €78/MWh. It also characterised cross-border capacity availability as one of the highest-return investments for the region relative to building new plants or storage.
The material further stated that congestion management should be treated as an industrial policy issue because large swings in electricity costs affect industry investment decisions. It said export competitiveness can be weakened and households can face political backlash when costs rise sharply due to volatility patterns driven by cross-border constraints.