The electricity market in South-East Europe (SEE) is undergoing a significant transformation, moving beyond traditional metrics of generation capacity and fuel mix to focus on infrastructure dynamics. Central to this evolution is the region’s 400 kV transmission network, which is increasingly influencing price formation, investment strategies, and capital allocation. This shift marks the transition from a passive infrastructure to a critical economic mechanism that defines value creation and distribution within the energy sector.
Serbia stands at the heart of this transformation, with its transmission operator, EMS, overseeing one of the most strategically important grids in continental Europe. The Subotica 400 kV substation serves as a vital link to Hungary’s Sandorfalva node, establishing a key corridor that connects SEE markets with Central European pricing mechanisms. Additionally, the Djerdap–Resita interconnection integrates Serbia with Romania’s Transelectrica system, which benefits from Cernavoda’s nuclear power and expanding wind capacity in the Black Sea region. The grid also extends southward through the Niš 400 kV node towards Bulgaria and Greece, while connections to Bosnia and Herzegovina are facilitated via Bajina Bašta and Višegrad.
This intricate network does more than transmit electricity; it plays a crucial role in determining market prices. Under normal circumstances, electricity prices across Hungary, Romania, and northern Serbia tend to align within a narrow band of €5–10/MWh. However, this apparent stability can quickly dissolve under pressure from outages, seasonal demand fluctuations, or renewable energy variability, leading to price spreads that can soar to €20–60/MWh between northern and southern regions.
The widening price gaps are not arbitrary but stem from specific transmission bottlenecks. The Serbia–Hungary corridor, which has a nominal transfer capacity of up to 1,500 MW, often operates with an available transfer capacity (ATC) closer to 600–1,000 MW, constrained by loop flows and security measures. Similarly, the southbound capacity toward Bulgaria and North Macedonia is limited, hindering access for lower-cost generation from northern areas to reach higher-priced southern markets.
This situation has led to a fragmented market landscape characterized by isolated pricing zones rather than a cohesive system. For instance, Greece consistently trades at a premium due to its LNG-based pricing model—typically €10–40/MWh above Central European rates. Meanwhile, Albania and North Macedonia face heightened volatility due to their dependence on hydroelectric resources and limited interconnections. Montenegro’s role is particularly notable as it acts as both a transit point and an export hub through the Lastva 400 kV substation, which connects to Italy via a 600 MW HVDC submarine cable. This arrangement allows SEE electricity access to Italian price premiums, generating annual congestion rents estimated between €70–150 million.
The emergence of congestion rents highlights structural imbalances within the region’s power market. Along the Serbia–Hungary border, annual congestion rents range from €50–120 million, indicating persistent price differentials tied to inadequate transmission capacity. In contrast, the Greece–Bulgaria interconnection, influenced by LNG imports and solar variability, can see rents exceed €200 million, emphasizing the economic significance of cross-border capacities.
This monetization of scarcity effectively reallocates value from constrained markets to transmission operators and capacity holders. Traders such as MET Group, Axpo, and EFT leverage these constraints for arbitrage opportunities by securing cross-border capacities through explicit auctions on platforms like the Joint Allocation Office. This strategy enables them to capitalize on embedded price differentials within the grid.
The auction framework itself reflects the transitional characteristics of SEE markets. While countries like Hungary, Romania, and Croatia engage in implicit day-ahead market coupling under the Single Day-Ahead Coupling framework, Serbia along with Bosnia and Herzegovina and Montenegro still rely heavily on explicit capacity auctions. This hybrid approach introduces inefficiencies that exacerbate price divergence since capacity allocation does not always align with real-time demand.
The implications for investment are substantial as electricity prices in SEE are increasingly influenced by geographic location rather than solely by fuel costs or generation order. For instance, solar projects located near the Subotica node benefit from proximity to Central European markets with competitive capture prices close to regional baseload levels. Conversely, similar projects near Vranje in southern Serbia face curtailment risks and lower capture prices due to local oversupply during peak solar production hours.
This geographical differentiation is becoming evident in project economics across Serbia and Montenegro. The planned Gvozd wind farm, developed by EPCG in Montenegro with an estimated capacity of approximately 55 MW, enjoys favorable grid integration through the Nikšić and Lastva nodes, allowing partial access to export markets via Italy. With projected capital expenditures (CAPEX) ranging from €90–110 million, this project aims for equity internal rates of return (IRR) between 9–12%.
In contrast, solar developments under Serbia’s EPS renewable program face more complex challenges. A representative project featuring a 100 MW solar plant combined with a 50 MW / 200 MWh battery system could incur total CAPEX of about €140–180 million. Without storage capabilities, such projects might yield an unlevered IRR of only 7–9%, impacted by capture price discounts and potential curtailment rates of up to 15–25%. However, integrating battery storage can enhance IRR prospects significantly by enabling generation shifts during peak demand periods.
The financial viability of these projects is closely tied to grid conditions as lenders increasingly evaluate not just resource quality but also factors like nodal positioning and congestion risks. Debt sizing correlates directly with anticipated cash flow stability as measured by debt service coverage ratios (DSCR). In less risky nodes, DSCR profiles typically range from 1.30–1.40x, supporting leverage levels between 65–75%. However, in more constrained areas where revenue volatility is pronounced, DSCR requirements tighten considerably.
The evolving landscape also sees industrial consumers adapting their strategies by entering long-term power purchase agreements (PPAs) for low-carbon electricity. Companies in sectors affected by carbon border adjustment mechanisms are willing to pay premiums of around €5–15/MWh above merchant-adjusted prices. These contracts provide additional price stability in regions where grid constraints might otherwise suppress revenues.
The next phase for regional development will be characterized by increased investments aimed at addressing critical bottlenecks within the grid system. Key projects include the proposed Trans-Balkan Corridor, which links Serbia with Romania and Bosnia and Herzegovina at an estimated CAPEX of between €300–400 million. Additional internal upgrades within Serbia around the Kragujevac and Kraljevo 400 kV nodes could require another €200–300 million. Furthermore, discussions regarding a second Italy interconnector in Montenegro could necessitate investments upwards of €1.2 billion.
Despite these advancements, achieving full convergence of electricity prices across SEE remains unlikely in the short term due to ongoing constraints exacerbated by rapid renewable capacity growth outpacing grid infrastructure development. As such, congestion is expected to remain a persistent characteristic rather than a temporary issue.
This evolving scenario creates an environment where returns are increasingly dictated by how well stakeholders navigate grid complexities. Projects situated near robust interconnections or those equipped with storage solutions stand to gain significantly more value compared to those located in constrained areas unless they secure premium pricing through strategic contracts or leverage market volatility effectively.
The SEE power system is thus transforming into a network defined by economic nodes rather than a singular market entity. Electricity pricing now hinges not only on production costs but also on geographical factors influencing delivery efficiency. The role of transmission infrastructure has shifted from being merely supportive to becoming central in shaping the region’s energy economics.
