The electricity market in South-East Europe (SEE) is undergoing a significant transformation, as the region’s 400 kV transmission infrastructure increasingly influences price formation and investment strategies. No longer viewed merely as a network for transporting electricity, this grid has become a pivotal economic mechanism that determines the creation and distribution of value within the energy sector.
At the heart of this evolving landscape is Serbia, where the transmission operator EMS oversees a strategically vital grid. The Subotica 400 kV substation serves as a critical junction, connecting to Hungary’s Sandorfalva node and facilitating access to Central European pricing mechanisms. Additionally, the Djerdap–Resita interconnection links Serbia with Romania’s Transelectrica system, which benefits from both nuclear power generation and expanding wind capacity in the Black Sea region. The grid also extends southward to Bulgaria and Greece through the Niš 400 kV node, while connections to Bosnia and Herzegovina are managed via Bajina Bašta and Višegrad.
This extensive network does more than transmit electricity; it fundamentally shapes market behavior. In stable conditions, electricity prices across Hungary, Romania, and northern Serbia typically remain within a narrow range of €5–10/MWh. However, this stability is often disrupted by various factors such as outages or seasonal demand spikes, leading to price differentials that can soar to between €20–60/MWh across different SEE zones.
These price variances reveal underlying transmission bottlenecks. For instance, the Serbia–Hungary corridor, which has a nominal transfer capacity of up to 1,500 MW, frequently operates with an available transfer capacity (ATC) closer to 600–1,000 MW. This limitation hinders the flow of lower-cost electricity from northern regions to higher-priced southern markets.
The fragmented nature of the market results in distinct pricing zones rather than a cohesive market structure. Greece consistently trades at a premium due to its reliance on LNG pricing, often exceeding Central European levels by €10–40/MWh. Meanwhile, Albania and North Macedonia experience heightened price volatility driven by their dependence on hydro resources and limited interconnections. Montenegro plays a dual role as both a transit point and an exporter through the Lastva 400 kV substation, which connects to Italy via a 600 MW HVDC submarine cable. This connection 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 energy markets. For example, along the Serbia–Hungary border, annual rents range from €50–120 million, indicating persistent price differentials stemming from inadequate transmission capacity. Similarly, on the Greece–Bulgaria interconnection, where LNG imports and solar variability create sharp intraday price fluctuations, congestion rents can surpass €200 million.
This monetized scarcity shifts value from constrained markets toward transmission operators and capacity holders. Traders such as MET Group, Axpo, and EFT leverage these constraints for profitable arbitrage opportunities by securing cross-border capacity through explicit auctions on platforms like the Joint Allocation Office.
The current auction framework reflects the transitional state of SEE markets. While countries such as Hungary, Romania, and Croatia engage in implicit day-ahead market coupling under the Single Day-Ahead Coupling framework, Serbia, Bosnia and Herzegovina, and Montenegro still depend heavily on explicit capacity auctions. This hybrid approach leads to inefficiencies that exacerbate price divergences.
The implications for investment are significant; electricity prices are increasingly influenced by geographic location rather than solely by fuel costs or generation merit order. For instance, solar projects located near the Subotica node benefit from proximity to Central European markets with capture prices aligned with regional baseload levels. Conversely, projects in southern Serbia near Vranje face challenges such as curtailment risks and lower capture prices due to limited export capabilities during peak solar production hours.
This spatial differentiation is evident in ongoing renewable investments across Serbia and Montenegro. The planned Gvozd wind farm, developed by EPCG in Montenegro with an approximate capacity of 55 MW, is expected to benefit from robust grid integration through the Nikšić and Lastva nodes. With an estimated capital expenditure of €90–110 million, it aims for equity internal rates of return (IRRs) between 9–12%.
In contrast, solar initiatives under Serbia’s EPS renewable program face more complex dynamics. A typical project featuring a 100 MW solar plant with a 50 MW / 200 MWh battery system could incur total capital expenditures ranging from €140–180 million. Without storage solutions, such projects may achieve unlevered IRRs of only 7–9%, while integrating battery systems could enhance IRR potential up to 15%.
Lenders are increasingly evaluating not just resource quality but also factors like nodal positioning and congestion exposure when assessing project viability. Debt service coverage ratios (DSCR) are closely tied to expected cash flow stability; low-risk nodes typically support leverage levels of around 65–75%, while more constrained areas may see tighter DSCR requirements that limit leverage.
The rise of industrial offtakers is reshaping market dynamics as companies in carbon border adjustment mechanism (CBAM)-exposed sectors seek long-term power purchase agreements for low-carbon electricity. Their readiness to pay premiums of between €5–15/MWh introduces new pricing stability in regions where grid constraints could otherwise suppress revenues.
The upcoming phase of development will be marked by substantial investments aimed at addressing critical transmission bottlenecks. The proposed Trans-Balkan Corridor, which connects Serbia, Romania, and Bosnia and Herzegovina, has an estimated capital expenditure requirement between €300–400 million. Internal upgrades within Serbia around key nodes like Kragujevac and Kraljevo could add another €200–300 million. Additionally, discussions regarding a second Italy interconnector in Montenegro could necessitate investments up to €1.2 billion.
Despite these developments, full convergence of electricity prices across SEE remains unlikely in the short term. While transmission expansion can alleviate some constraints, it will not eliminate them entirely—especially given that renewable capacity continues to grow at a pace outstripping grid infrastructure development.
This ongoing complexity in grid dynamics means that project returns will increasingly depend on strategic navigation within this evolving landscape. Projects positioned near robust interconnections or equipped with storage capabilities stand to capture greater value compared to those situated in constrained areas unless they can secure premium pricing through industrial contracts or effectively manage volatility through hybrid configurations.
The SEE power system is thus becoming characterized by interconnected economic nodes rather than a uniform market structure. Electricity pricing is shifting from being solely production cost-based to being influenced by geographical factors and delivery efficiency. Consequently, transmission infrastructure has emerged as a central element shaping the region’s energy economics.
