The north-south corridor connecting Hungary, Serbia, Bulgaria, and Greece is critical to this transformation. Despite an installed transfer capacity often exceeding 1,200 to 1,500 MW on major borders, actual commercially available capacity frequently ranges between 600 and 1,000 MW. This discrepancy is fundamental to understanding the emergence of congestion rents within the regional market.
For instance, the Serbia-Hungary border stands out as one of the most active interconnections in SEE. Here, annual congestion revenues can fluctuate significantly, ranging from €50 million to €120 million based on market volatility. These revenues tend to spike during periods of price divergence; for example, when Hungary aligns with Central European pricing while Serbia’s prices reflect more localized factors such as coal baseload generation and hydro variability. During peak demand periods or gas-driven price surges in Greece, price spreads can reach €40 to €60/MWh, marking this corridor as one of Europe’s most lucrative trading routes.
In contrast, the Bulgaria-Greece interconnection showcases even more pronounced monetization potential. Greek electricity prices are often influenced by LNG-linked marginal generation, leading to sustained price spreads with Bulgaria of €20 to €40/MWh over longer durations. In times of high volatility, annual congestion rents on this border have been known to exceed €150 million to €200 million due to persistent demand pressures in Greece coupled with limited transmission capacity heading north.
Further along the Adriatic corridor lies the Montenegro-Italy HVDC link with a capacity of 600 MW. This connection serves as a direct export channel from Montenegro’s hydro-dominated energy system into Italy’s premium market. Arbitrage opportunities here typically yield spreads between €20 and €50/MWh during peak demand in Italy. This infrastructure has allowed Montenegro’s surplus generation access to higher-value markets, generating annual congestion revenues estimated between €70 million and €150 million.
The structural durability of these congestion revenues can be attributed to the complex interactions between network topology and generation mix across SEE. Unlike Western Europe—where market coupling has led to tighter price alignment—the SEE region grapples with internal bottlenecks and loop flows that hinder full market integration. Even where coupling occurs, such as between Hungary and Romania, benefits quickly dissipate when faced with southern constraints.
This layered pricing environment results in northern nodes tracking Central European baseload prices closely within a narrow band (€2–8/MWh), while moving southward reveals progressively widening spreads—often reaching premiums of up to €40/MWh in southern corridors influenced by gas pricing and solar intermittency.
Market participants are adapting their strategies accordingly. Companies like MET Group and Axpo are not operating under a unified regional price curve but are instead focusing on specific corridors and timeframes through long-term transmission rights acquired via auctions. These rights provide optionality; when price spreads widen, they translate directly into profit margins.
The auction framework itself further reinforces this monetization structure across the region. While some areas engage in implicit day-ahead market coupling, significant portions—especially Serbia and Bosnia—still rely on explicit auction mechanisms like those managed by JAO. These auctions allocate capacity across various timeframes and effectively create a forward market for congestion rights.
From an operational perspective, transmission constraints act similarly to infrastructure tolls that generate predictable cash flows for system operators while simultaneously creating arbitrage opportunities for traders. Unlike generation assets subject to fluctuating fuel costs or policy changes, congestion rents arise from structural imbalances that often take years to address.
As renewable developments proliferate within this framework, they face both challenges and opportunities based on their geographical positioning relative to high-capacity interconnections. For example, solar plants in northern Serbia can capture prices close to Hungarian benchmarks (€70–85/MWh), whereas similar facilities in southern regions may contend with effective prices dropping down to €45–65/MWh due to curtailment risks associated with congested networks.
Moreover, integrating battery energy storage systems (BESS) into projects can significantly alter financial outcomes by shifting energy generation from low-price periods into high-demand windows—capturing intra-day spreads that may exceed €20–60/MWh during volatile conditions.
As industrial demands evolve alongside carbon border mechanisms aimed at managing emissions from energy-intensive sectors, long-term renewable supply agreements are becoming increasingly sought after. These agreements often command premiums over standard merchant-adjusted prices due to their strategic importance for export competitiveness.
In summary, the SEE power system is evolving beyond its traditional view as a collection of national markets; it is emerging as an interconnected financial ecosystem where infrastructure plays a critical role in value creation amidst physical constraints and market dynamics. As transmission investments continue shaping the regional landscape, understanding these complexities will be essential for stakeholders navigating future market participation strategies within South-East Europe’s electricity sector.
