Transmission operators across South-East Europe are moving into a high-spend phase that will reshape cross-border power flows through 2030, even as market convergence remains partial. A multi-country investment pipeline totalling more than €2.5–4.0 billion is designed to relieve long-standing constraints and support higher renewable output. The engineering challenge is not only adding capacity, but ensuring that new infrastructure does not simply shift congestion to other parts of the network.
Capital-intensive transmission programme expands cross-border transfer capacity
System operators including EMS Serbia, Transelectrica Romania, ESO Bulgaria, CGES Montenegro and IPTO Greece are advancing a coordinated set of transmission projects that collectively exceed €2.5–4.0 billion through 2030. The stated aim is to increase transfer capacity and enable greater renewable penetration while moving the region closer to the price convergence seen in Central and Western Europe. However, the expected outcome is a more complex grid system where integration improves without delivering full alignment in market outcomes.
The largest Western Balkans initiative is the Trans-Balkan Corridor, linking Serbia, Romania and Bosnia via a series of 400 kV upgrades and new lines. Investment is estimated at €300–400 million, targeting higher north–south transfer capacity alongside improved system stability. In parallel, Serbia is budgeting an additional €200–300 million for internal reinforcements around Kragujevac, Kraljevo and the Belgrade load centre to reduce internal congestion and improve utilisation of cross-border interconnections.
Country-by-country network upgrades focus on renewable export corridors
Romania’s transmission operator Transelectrica is prioritising reinforcement between the western and eastern parts of the country, including upgrades connecting the Banat region with Transylvania and Dobrogea. These projects are supported by EU funding mechanisms and are intended to integrate wind generation from the Black Sea region while enabling export towards Central Europe. The planning emphasis reflects how grid access requirements increasingly shape where renewable projects can deliver power reliably into broader markets.
Bulgaria’s ESO is pursuing similar reinforcement along the north–south axis linking Varna, Sofia and the Greek border, with investments exceeding €500 million. In Greece, IPTO is expanding its northern network and interconnections through upgrades intended to facilitate flows between Thessaloniki and neighbouring systems. Together, these works are aimed at improving corridor performance where physical constraints have historically limited cross-border transfers.
HVDC expansion plans in Montenegro and new interconnectors in the west
Montenegro’s approach follows a different sequencing logic after commissioning a 600 MW HVDC link to Italy. Attention has shifted to reinforcing internal networks and evaluating a second cable, with CAPEX estimated at €800 million to €1.2 billion. If advanced, the expansion would double export capacity and further integrate the Adriatic corridor into European markets.
Albania and North Macedonia are also progressing interconnection plans designed to reduce reliance on limited existing routes. A planned 400 kV line between Tirana and Bitola carries investment estimates of €150–250 million, reflecting efforts to improve regional connectivity ahead of higher renewable output. For developers, these interconnectors matter because they influence whether generation can be exported during periods when local demand cannot absorb all production.
More capacity may narrow spreads in some zones while leaving structural differences
Across key corridors such as Serbia–Romania and Bulgaria–Greece, available transfer capacity could rise by 20–40 per cent by the end of the decade. In theory, this should reduce price differentials by allowing more electricity to move from lower-cost markets to higher-cost ones. In practice, analysts expect a more nuanced relationship between capacity additions and convergence because congestion can reappear elsewhere as flows redistribute.
Experience from other European grids suggests expansion often redistributes congestion rather than eliminating it entirely. In South-East Europe, this effect is expected to be amplified by rapid renewable growth: solar and wind capacity across the region could exceed 20–25 GW by 2030 from roughly 10–12 GW today. As variability increases, oversupply and undersupply periods are likely to become more pronounced, affecting both dispatch patterns and intraday price behaviour.
Volatility outlook: narrowing in north nodes but persistent divergence in southern markets
The interaction between increased transfer capability and increased variability is expected to shape regional price dynamics through 2030. In northern nodes connected particularly to Hungary and Romania, convergence with Central European markets is likely to strengthen as integration improves. Price spreads averaging €5–10/MWh could narrow to €2–5/MWh under this scenario.
In central zones including much of Serbia and Bulgaria, spreads may moderate but remain significant due to internal constraints and variable generation influencing flows. Typical spreads are expected in the €5–15/MWh range. Southern markets are forecast to retain higher divergence: Greece’s reliance on gas-fired generation alongside rapidly expanding solar capacity is expected to sustain strong intraday volatility.
Average price premiums of €10–30/MWh relative to northern markets are likely to persist even as interconnection capacity increases. Albania and North Macedonia—characterised by smaller systems and limited export routes—are expected to remain vulnerable to local imbalances during periods of high renewable output. For market participants, this implies that opportunities shift from corridor-level arbitrage towards managing intra-zonal volatility.
BESS deployment becomes more central as flexibility value rises
As variability grows alongside grid expansion, flexibility requirements are expected to rise for both system operation and commercial optimisation. Battery energy storage systems are positioned as key tools for bridging gaps created by changing flow patterns and intraday swings in prices. By 2030, installed storage capacity in South-East Europe could exceed 3–5 GW, with Greece, Romania and Bulgaria leading deployment.
These assets would interact directly with transmission networks by smoothing flows and reducing congestion impacts while also creating new patterns of price differentiation linked to how storage participates in balancing needs. The operational relevance extends beyond energy shifting into ancillary service revenues where market design allows batteries to monetise fast response capabilities.
Investment returns depend on curtailment outcomes rather than capacity alone
The financial implications for project planning hinge on whether transmission upgrades translate into reduced curtailment rather than simply added theoretical transfer capability. In scenarios where upgrades reduce curtailment from 15–20 per cent down to 5–10 per cent, equity internal rates of return could increase by 2–3 percentage points assuming other factors remain equal. If new congestion points emerge as flows redistribute, those gains could be offset through lower capture prices or higher volatility.
For renewable developers preparing engineering studies and EPC packages, this means grid analysis must be treated as an ongoing input rather than a one-off feasibility step. Improved transmission can reduce curtailment in constrained areas with limited export routes, but new congestion can arise when projects cluster in resource-rich regions or when network constraints move location after reinforcement. Site selection therefore increasingly depends on detailed modelling of both steady-state power flows and operational variability across seasons.
Contracts, market coupling expansion, and physical limits shape delivery risk
Industrial demand is also expected to influence system behaviour as energy-intensive sectors adapt under carbon constraints. Long-term contracts for renewable electricity are projected to become more prevalent, anchoring demand in specific locations that can affect flow patterns and potentially reduce volatility in some areas. At the same time, contract structures increase the importance of reliable delivery aligned with grid capability.
The regulatory framework is expected to continue evolving alongside infrastructure delivery through expanded market coupling integrating more countries into European day-ahead and intraday markets. While this improves efficiency and transparency, it does not override physical constraints imposed by transmission topology or operational limits. The distinction between market integration and physical convergence remains central: convergence depends on infrastructure development plus operational coordination across TSOs.
Broader industry implications: a connected grid with persistent spread management needs
The emerging “2030 grid” picture points towards a system that is more connected but not fully unified across pricing zones. Transmission investment across EMS Serbia, Transelectrica Romania, ESO Bulgaria, CGES Montenegro and IPTO Greece should raise corridor capability—potentially by 20–40 per cent on selected routes—while renewable growth pushes variability higher than today’s levels suggest. For investors, developers, contractors and utilities alike, value capture will increasingly depend on combining transmission access with flexibility through storage or other responsive resources rather than assuming that added lines automatically deliver stable convergence.
Across project pipelines—from 400 kV corridor works in the Western Balkans to HVDC expansion considerations in Montenegro—engineering readiness will likely be judged by how effectively upgrades reduce curtailment risk under real operating conditions. More capacity can improve average conditions while leaving structural price spreads intact due to congestion redistribution dynamics amplified by wind and solar output growth through 2030.