The European Commission’s decision to accelerate and scale up Europe’s electricity grid expansion is not simply a technical upgrade programme. It is a structural market intervention whose consequences will be felt most sharply in peripheral but highly interconnected regions such as South-East Europe (SEE). While the stated objectives are lower energy prices, faster renewable integration and reduced dependence on external suppliers, the real transmission channel runs through cross-border capacity, congestion reduction and price convergence. For SEE, this changes how electricity is priced, financed and traded, and how national energy systems interact with the wider European market.
At the centre of the initiative stands the European Commission, which has explicitly framed grid investment as a prerequisite for Europe’s next electrification phase. Electricity demand across Europe is expected to rise by around 60% by 2030, driven by electric vehicles, heat pumps, data centres and the electrification of industrial processes. In systems already constrained by ageing infrastructure and limited cross-border capacity, this demand growth turns grid adequacy into a macroeconomic variable. For SEE markets, where transmission density is lower and redundancy limited, the sensitivity to these trends is significantly higher than in core EU regions.
One of the strongest economic signals behind the Commission’s move is the cost of congestion. Across Europe, congestion management and redispatch costs have risen from approximately €5.2 billion in 2022 toward a trajectory of roughly €26 billion per year by 2030 if bottlenecks are not structurally addressed. In SEE, congestion costs rarely appear transparently on system operators’ balance sheets, but they materialise indirectly through renewable curtailment, emergency imports, forced exports at depressed prices and ad-hoc regulatory interventions. Grid reinforcement reduces these distortions by allowing surplus power to flow outward and deficit areas to import reliably, smoothing both prices and fiscal exposure.
This is why the Commission’s emphasis on so-called energy highways has disproportionate relevance for the Balkans. These corridors are designed to eliminate the most critical bottlenecks preventing renewable electricity from reaching demand centres. In practical terms, this elevates SEE from a collection of semi-isolated national systems into a functional extension of the EU internal electricity market. Hydropower-dominated systems in the Western Balkans, coastal wind zones and fast-growing solar capacity gain economic value only if electricity can physically move across borders. Grid expansion transforms these assets from local balancing tools into regional resources.
The clearest embodiment of this shift is the Trans-Balkan Electricity Corridor. Rather than a single project, it is a coordinated 400 kV backbone linking Serbia, Montenegro, Bosnia and Herzegovina, Croatia, Hungary and Romania. Key segments include the 109 km Obrenovac–Bajina Bašta line in Serbia with expected completion around 2027, an additional 84 km extension toward the Bosnian and Montenegrin borders targeted for 2028, and Montenegro’s Pljevlja–Lastva section of approximately 220 km, complemented by a shorter 15 km Pljevlja–Serbia border connection. Collectively, these assets redefine the feasible trading envelope of the Western Balkans and materially increase the region’s ability to integrate into Central European power flows.
The market consequences are structural. As interconnection capacity increases, price volatility declines. SEE markets have historically been characterised by sharp price spikes during cold winters or dry hydrological years and deep collapses during periods of high hydro or wind output. Stronger cross-border capacity dampens both extremes. Excess generation can be exported instead of curtailed, while imports cap scarcity pricing during stress events. Over time, this narrows the spread between SEE hubs and Central European benchmarks, reducing the risk premium embedded in industrial tariffs, hedging products and long-term power purchase agreements.
The Adriatic interface further illustrates the depth of interdependence. The existing Italy–Montenegro HVDC link operates at 500 kV DC with 600 MW of capacity and has already altered regional trading dynamics. Plans for a second cable would double this exchange capability to 1,200 MW, with an estimated investment of around €500 million and a target commissioning around 2031. If realised, Montenegro effectively becomes a major gateway between SEE generation assets and the Italian market. The economic value of this gateway, however, depends directly on whether the EU internal grid can absorb these flows. In that sense, Brussels’ internal reinforcements and Balkan interconnectors are economically inseparable components of the same system.
Further south, the planned second Italy–Greece interconnector, commonly referred to as GRITA 2, adds another layer of influence. With up to 1,000 MW of capacity, a length of roughly 300 km and an investment value close to €2 billion, it reshapes congestion patterns and price formation across the wider South-East European and Mediterranean region. Although it does not physically cross the Western Balkans, its effect propagates through interconnected markets, indirectly influencing SEE price signals and balancing conditions.
These transmission investments coincide with the Commission’s broader push to accelerate renewable integration. SEE countries still hold some of Europe’s most significant untapped hydro, wind and solar resources, but grid saturation has acted as a binding constraint on deployment. Grid expansion shifts this constraint materially. Curtailment risk declines, capture prices improve and financing conditions tighten. For lenders and investors, the qualitative change is critical: revenue risk becomes driven more by market fundamentals and less by structural grid limitations.
The grid agenda also intersects directly with industrial electrification. As EU industrial policy pushes steel, chemicals, cement and transport toward electricity-based processes, the credibility of cross-border supply becomes a competitiveness factor. SEE’s relative advantages, including legacy hydro capacity and still-moderate generation costs, gain value when backed by reliable import and export capability. Energy-intensive industries increasingly assess not only national tariffs, but also the resilience of regional supply during peak demand and stress conditions.
Security of supply completes the picture. Reduced dependence on external energy suppliers does not imply national self-sufficiency. It implies deeper mutual dependence within Europe. Stronger interconnections mean that system stress is shared rather than isolated. For SEE governments and state-owned utilities, this lowers the probability of crisis-driven interventions such as emergency imports, subsidies or forced price caps, which have historically translated into fiscal pressure and balance-sheet deterioration.
Over the medium term, the Commission’s grid expansion effectively redraws SEE’s energy map. The region moves from being a volatile edge market toward becoming a structural contributor to Europe’s balancing, flexibility and renewable absorption. The tangible anchors of this transformation are visible in the numbers: 600 MW of existing Adriatic exchange with a pathway to 1,200 MW, 1,000 MW of new Italy–Greece capacity, and a Trans-Balkan 400 kV backbone stretching hundreds of kilometres with completion milestones clustered between 2024 and 2028.
Execution now becomes the decisive variable. Grid assets alone do not deliver integration unless regulatory alignment, system operation and market rules keep pace. The Commission’s measures increase the payoff for convergence and raise the cost of delay. For South-East Europe, the message is unambiguous. Europe’s grid expansion is not an external policy backdrop; it is a direct determinant of price stability, investment bankability and industrial competitiveness in the coming decade.