The electricity market in South-East Europe (SEE) is undergoing a significant transformation, driven by the region’s 400 kV transmission infrastructure, which is increasingly influencing price formation and investment strategies. This shift emphasizes the importance of transmission networks as active economic mechanisms rather than mere conduits for electricity flow. The region’s power grid, particularly in Serbia, is becoming a critical determinant of market behavior and capital allocation.
Serbia stands at the heart of this evolving landscape, with its transmission operator EMS overseeing a strategically vital network. The Subotica 400 kV substation serves as a key link to Hungary’s Sandorfalva node, facilitating access to Central European price dynamics. Additionally, the Djerdap–Resita interconnection connects Serbia to Romania’s Transelectrica system, which benefits from stable nuclear power and an increasing share of wind energy from the Black Sea region. The Niš 400 kV node extends connectivity southward towards Bulgaria and Greece, while western flows are managed through Bajina Bašta and Višegrad into Bosnia and Herzegovina.
The operational characteristics of this network have profound implications for pricing. Under normal circumstances, electricity prices across Hungary, Romania, and northern Serbia exhibit limited variability—typically within a €5–10/MWh range—due to robust interconnections. However, during periods of constraint—such as outages or spikes in demand—price discrepancies can surge dramatically, reaching €20–60/MWh between northern and southern zones.
These price fluctuations are closely tied to transmission limitations. For instance, the Serbia–Hungary corridor has a nominal capacity of 1,500 MW but often operates with much lower available transfer capacity (ATC) due to technical constraints. Similarly, the flow capacity from Serbia towards Bulgaria and North Macedonia is restricted, preventing cost-effective northern generation from reaching more lucrative southern markets.
This fragmentation results in a market that resembles a series of isolated pricing zones rather than a cohesive entity. Greece consistently experiences higher prices—€10–40/MWh above Central European benchmarks—largely driven by its reliance on liquefied natural gas (LNG). In contrast, Albania and North Macedonia face heightened price volatility due to their dependence on hydro resources and limited interconnections. Montenegro plays a dual role as both a transit hub and an export point through its Lastva 400 kV substation connected to Italy via a 600 MW HVDC submarine cable. This connection enables SEE electricity to capitalize on Italian price premiums, generating congestion rents estimated between €70–150 million annually.
Congestion rents serve as critical indicators of regional market imbalances. For example, along the Serbia–Hungary border, annual rents range from €50–120 million due to persistent price differentials caused by inadequate transmission capacity. In contrast, the Greece–Bulgaria interconnection can generate rents exceeding €200 million due to volatility stemming from LNG imports and solar generation variability.
These revenues reflect monetized scarcity within constrained markets and are pivotal for traders like MET Group and Axpo who leverage cross-border capacity through auctions on platforms such as the Joint Allocation Office. The current auction framework highlights the transitional nature of SEE markets; while countries like Hungary and Romania engage in implicit day-ahead market coupling under the Single Day-Ahead Coupling framework, Serbia continues to rely heavily on explicit auctions that do not always align capacity allocation with real-time demand.
The implications for renewable energy investments are substantial. Prices in SEE are increasingly determined by geographical factors rather than solely by fuel costs or generation merit order. Projects situated near strategic nodes such as Subotica can achieve favorable capture prices aligned with regional baseload levels. Conversely, projects located in southern regions like Vranje may encounter lower prices due to local oversupply during peak generation periods.
A notable example includes the planned Gvozd wind farm in Montenegro with an approximate capacity of 55 MW; it benefits from strong grid integration via Nikšić and Lastva nodes that provide partial access to export markets through Italy. With anticipated capital expenditures between €90–110 million, this project aims for equity internal rates of return (IRR) between 9-12%, supported by potential structured off-take agreements.
In contrast, solar developments under Serbia’s EPS renewable program face more nuanced challenges related to grid conditions. A typical solar plant paired with battery storage in constrained areas may require total investments ranging from €140-180 million but could see IRRs fluctuate significantly based on market conditions and curtailment risks.
The financial viability of these projects hinges not only on resource quality but also on their nodal positioning within the grid. Lenders are increasingly focused on debt service coverage ratios (DSCR), which vary based on expected cash flow stability linked directly to congestion exposure. In low-risk nodes with stable revenue streams, DSCR profiles support higher leverage ratios compared to more constrained areas where tighter requirements necessitate lower leverage without long-term power purchase agreements or storage integration.
Industrial consumers in sectors vulnerable to carbon border adjustments are beginning to influence market dynamics by entering long-term power purchase agreements aimed at securing low-carbon electricity at premiums above standard pricing levels. This trend introduces additional price stability into regions otherwise affected by grid constraints.
Looking ahead, significant investment is anticipated across SEE aimed at addressing critical bottlenecks within the transmission network. Key projects include the Trans-Balkan Corridor linking Serbia with Romania and Bosnia and Herzegovina with an estimated capital cost between €300-400 million; internal upgrades within Serbia around Kragujevac and Kraljevo will require an additional €200-300 million; discussions regarding a second Italy interconnector could necessitate up to €1.2 billion in investments.
Despite these developments, achieving full price convergence across SEE remains unlikely in the immediate future due to ongoing constraints exacerbated by rapid growth in renewable energy capacity relative to existing grid infrastructure capabilities.
The evolving landscape underscores that successful navigation through this complex grid environment will be essential for maximizing returns on investment in SEE’s energy sector moving forward.
