South-East Europe’s 2030 grid buildout: more capacity, shifting spreads and a higher premium on flexibility

South-East Europe is heading into the most capital-intensive transmission phase in decades, but investors and market participants should expect a less straightforward path to value than “more wires equals full convergence.” While new interconnection capacity is designed to raise transfer capability and support higher renewable penetration, the region’s power flows are likely to become more dynamic—meaning price spreads may narrow in some places while persisting or even relocating.

Across the region, system operators including EMS Serbia, Transelectrica Romania, ESO Bulgaria, CGES Montenegro and IPTO Greece are advancing project pipelines that together exceed €2.5–4.0 billion through 2030. The stated goal is to tackle constraints that have limited cross-border electricity movement for years. In Central and Western Europe, similar integration efforts have been associated with greater price alignment; South-East Europe’s planners are aiming for comparable progress—though not necessarily an outcome of complete alignment.

A corridor-led push—and internal reinforcement at the same time

The largest programme highlighted in the Western Balkans is the Trans-Balkan Corridor, which links Serbia, Romania and Bosnia via a sequence of 400 kV upgrades and new lines. With estimated spending of €300–400 million, the project targets increased north–south transfer capacity and improved system stability.

Alongside cross-border expansion, Serbia is also investing in internal reinforcements—upgrades around Kragujevac, Kraljevo and the Belgrade load centre. The planned additional expenditure of €200–300 million is intended to reduce internal congestion and improve how efficiently cross-border interconnections can be used.

Romania’s operator Transelectrica is concentrating on strengthening links between western and eastern parts of the country. That includes upgrades along corridors connecting the Banat region with Transylvania and Dobrogea, supported by EU funding mechanisms. The focus is on integrating Black Sea wind generation and improving export routes toward Central Europe.

Bulgaria’s ESO is pursuing reinforcement particularly along the north–south axis linking Varna, Sofia and the Greek border, with investments exceeding €500 million. Greece’s IPTO plans network expansion in its northern areas as well as upgrades that facilitate flows between Thessaloniki and neighbouring systems.

The Adriatic dimension after HVDC—and new links further south

Montenegro’s approach follows a different sequencing logic: after commissioning a 600 MW HVDC link to Italy, attention has shifted toward reinforcing internal networks and assessing whether a second cable should be added. If pursued, CAPEX for potential expansion is estimated at €800 million to €1.2 billion. The implication would be doubled export capacity and deeper integration of the Adriatic corridor into European markets.

Albania and North Macedonia are also moving toward additional interconnections. A planned 400 kV line between Tirana and Bitola, estimated at €150–250 million, would aim to improve regional connectivity while reducing reliance on limited existing routes.

Bigger capacity may narrow gaps—but it can also reshuffle congestion risk

Taken together, these projects point to a substantial increase in transmission capacity across South-East Europe. On key corridors such as Serbia–Romania and Bulgaria–Greece, available transfer capacity could rise by 20–40 per cent by end of the decade.

Theoretically, stronger transfer capability should help reduce price differentials by enabling more electricity from lower-cost areas to reach higher-cost markets. Yet experience from other European regions suggests grid expansion often redistributes congestion rather than removing it permanently: when one bottleneck eases, flows adjust—and another constraint can emerge elsewhere.

This effect may be amplified by rapid growth in variable renewables. Solar and wind capacity across the region are expected to exceed 20–25 GW by 2030 (from current roughly 10–12 GW). As variability increases, periods of oversupply or undersupply could become more pronounced—raising questions about where volatility shows up once physical constraints start changing.

Northern convergence gains; central moderation; southern divergence persists

The interaction between added capacity and increased variability will shape price outcomes across zones. In northern nodes—particularly those connected to Hungary and Romania—convergence with Central European markets is expected to strengthen. Price spreads that currently average about €5–10/MWh