South-East Europe’s Power Grid: A New Economic Mechanism

The electricity landscape in South-East Europe (SEE) is undergoing a significant transformation, shifting from a focus on generation capacity to the critical role of transmission infrastructure. The region’s 400 kV transmission backbone is now central to price formation, investment returns, and capital allocation, evolving into an economic mechanism that influences how value is generated and distributed across markets.

Serbia plays a pivotal role in this infrastructure, with its transmission operator, EMS, managing a strategically located grid that connects SEE to Central European markets. The Subotica 400 kV substation serves as a key node linking Hungary’s Sandorfalva and facilitating the flow of electricity within the region. This interconnection enhances market liquidity while also integrating with Romania’s Transelectrica system through the Djerdap–Resita interconnection, which benefits from both nuclear energy and renewable resources.

Electricity pricing in the region reflects this complex interplay of infrastructure and market dynamics. Generally, prices across Hungary, Romania, and northern Serbia exhibit convergence within a narrow band of €5–10/MWh. However, this stability can be deceptive; during periods of system stress—such as outages or seasonal demand spikes—price spreads can surge to between €20–60/MWh, particularly between northern and southern zones.

The underlying cause of these price divergences lies in transmission bottlenecks. The Serbia–Hungary corridor, designed for up to 1,500 MW, often operates with an available transfer capacity (ATC) much lower—typically around 600–1,000 MW. This limitation restricts access for lower-cost generation in northern regions to higher-priced southern markets. Similar constraints affect southbound flows towards Bulgaria and North Macedonia.

This situation results in a fragmented pricing landscape across SEE. Greece frequently trades at a premium, often between €10–40/MWh above Central European levels, while Albania and North Macedonia face increased price volatility due to their reliance on hydroelectric power and limited interconnections. Montenegro’s unique position as both a transit hub and export node through the Lastva 400 kV substation, which connects to Italy via a 600 MW HVDC submarine cable, allows it to tap into Italian market premiums, generating annual congestion rents estimated between €70–150 million.

The phenomenon of congestion rents indicates persistent structural imbalances within the region’s electricity market. For instance, annual rents along the Serbia–Hungary border range from €50–120 million, highlighting ongoing price differentials linked to insufficient transmission capacity. In contrast, rents on the Greece–Bulgaria interconnection, driven by LNG imports and solar variability, can exceed €200 million.

This monetization of scarcity has significant implications for traders like MET Group, Axpo, and EFT. These entities leverage cross-border capacities secured through explicit auctions on platforms such as the Joint Allocation Office to capitalize on embedded price differentials within the grid.

The current auction framework illustrates the transitional nature of SEE energy markets. While countries like Hungary, Romania, and Croatia engage in implicit day-ahead market coupling under the Single Day-Ahead Coupling framework, Serbia and its neighbors still depend heavily on explicit capacity auctions. This hybrid approach creates inefficiencies that exacerbate price divergences by not always allocating capacity optimally based on real-time demand.

The implications for future investments are substantial as electricity prices across SEE are increasingly influenced by geographic location rather than just fuel costs or generation merit order. Projects situated near critical nodes like Subotica can achieve capture prices aligned with regional baseload levels; conversely, projects in constrained areas face curtailment risks that suppress their economic viability.

An example includes Montenegro’s planned Gvozd wind farm, with an estimated capacity of around 55 MW. This project benefits from strong grid integration at Nikšić and Lastva nodes while targeting estimated CAPEX between €90–110 million. In contrast, solar projects under Serbia’s EPS renewable program face more challenging economics due to local oversupply issues during peak solar hours.

The financial viability of renewable projects is increasingly tied to their positioning within the grid. Lenders assess not only resource quality but also factors such as nodal positioning and congestion risks when determining debt sizes linked to expected cash flow stability through debt service coverage ratios (DSCR). In less risky nodes, DSCR profiles typically support higher leverage levels compared to constrained areas where tighter requirements limit financing options.

This evolving landscape sees industrial players entering long-term power purchase agreements (PPAs) for low-carbon electricity supply. Entities in sectors exposed to carbon border adjustment mechanisms are willing to pay premiums ranging from €5–15/MWh above merchant-adjusted prices, providing additional revenue stability in regions where grid constraints might otherwise depress prices.

The next phase for SEE involves substantial investment aimed at alleviating critical transmission bottlenecks. Major projects include the proposed Trans-Balkan Corridor, connecting Serbia with Romania and Bosnia-Herzegovina at an estimated cost of €300–400 million. Additionally, internal upgrades within Serbia could require another €200–300 million. Montenegro is also exploring options for a second Italy interconnector that may add up to another 600 MW HVDC capacity, potentially costing up to €1.2 billion.