Transmission investment across South-East Europe is entering its most capital-intensive phase in decades. System operators including EMS Serbia, Transelectrica Romania, ESO Bulgaria, CGES Montenegro and IPTO Greece are advancing a pipeline of projects that collectively exceed €2.5–4.0 billion through 2030, targeting bottlenecks that have long constrained cross-border flows. The strategic objective is clear: increase transfer capacity, enable higher renewable penetration and move the region closer to the price convergence observed in Central and Western Europe. The outcome, however, is unlikely to be full alignment. Instead, the next phase of grid development is set to produce a more complex system where convergence improves, but structural spreads persist.
The largest single programme in the Western Balkans is the Trans-Balkan Corridor, linking Serbia, Romania and Bosnia through a series of 400 kV upgrades and new lines. With estimated investments of €300–400 million, the project aims to increase north–south transfer capacity and improve system stability. In parallel, Serbia is advancing internal reinforcements, including upgrades around Kragujevac, Kraljevo and the Belgrade load centre, with an additional €200–300 million in planned expenditure. These investments are designed to reduce internal congestion and improve the utilisation of cross-border interconnections.
Romania’s transmission operator, Transelectrica, is focusing on strengthening links between the western and eastern parts of the country, including upgrades to corridors connecting the Banat region with Transylvania and Dobrogea. These projects, supported by EU funding mechanisms, target the integration of wind generation from the Black Sea region and its export towards Central Europe. Bulgaria’s ESO is advancing similar reinforcements, particularly along the north–south axis linking Varna, Sofia and the Greek border, with investments exceeding €500 million. Greece, through IPTO, is expanding its northern network and interconnections, including upgrades that facilitate flows between Thessaloniki and neighbouring systems.
Montenegro’s strategy is more focused but equally significant. Following the commissioning of the 600 MW HVDC link to Italy, attention has shifted to reinforcing internal networks and evaluating a second cable. The potential expansion, with CAPEX estimated at €800 million to €1.2 billion, would double export capacity and further integrate the Adriatic corridor into European markets. Albania and North Macedonia are advancing new interconnections, including a planned 400 kV line between Tirana and Bitola, with investment estimates of €150–250 million, aimed at improving regional connectivity and reducing reliance on limited existing routes.
Taken together, these projects represent a substantial increase in transmission capacity across the region. On key corridors, such as Serbia–Romania and Bulgaria–Greece, available transfer capacity could increase by 20–40 per centby the end of the decade. In theory, this should reduce price differentials by allowing more electricity to flow from lower-cost to higher-cost markets. In practice, the relationship between capacity and convergence is more nuanced.
Experience from other European regions suggests that grid expansion tends to redistribute congestion rather than eliminate it. As capacity increases on one corridor, flows adjust, often creating new bottlenecks elsewhere. In South-East Europe, this effect is likely to be amplified by the rapid growth of renewable generation. Solar and wind capacity across the region is expected to exceed 20–25 GW by 2030, up from current levels of roughly 10–12 GW. This expansion will introduce greater variability into the system, with periods of oversupply and undersupply becoming more pronounced.
The interaction between increased capacity and increased variability will shape price dynamics. In northern nodes, particularly those connected to Hungary and Romania, convergence with Central European markets is likely to strengthen. Price spreads that currently average €5–10/MWh could narrow to €2–5/MWh, reflecting improved integration. In central zones, including much of Serbia and Bulgaria, spreads may moderate but remain significant, typically in the €5–15/MWh range, as internal constraints and variable generation continue to influence flows.
Southern markets are expected to retain the highest degree of divergence. Greece, with its reliance on gas-fired generation and rapidly expanding solar capacity, will continue to exhibit 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, with smaller systems and limited export routes, will remain susceptible to local imbalances, particularly during periods of high renewable output.
For traders, these conditions imply a shift rather than a disappearance of opportunities. Cross-border arbitrage may become less pronounced on some corridors, but intraday and intra-zonal volatility is likely to increase. The ability to capture spreads will depend more on flexibility—through storage, demand response or flexible generation—than on simple access to transmission capacity. Firms active on platforms such as Electricity.Trade are already adapting, focusing on more granular analysis of price patterns and flow constraints.
For renewable developers, the implications are equally significant. Improved transmission capacity will reduce curtailment in some areas, particularly those currently constrained by limited export routes. However, as generation increases, new forms of congestion will emerge, often linked to the concentration of projects in resource-rich regions. Developers will need to incorporate more detailed grid analysis into site selection and project design, recognising that capacity expansion does not guarantee unconstrained operation.
The financial impact of these dynamics is reflected in project returns. In scenarios where transmission upgrades successfully reduce curtailment from 15–20 per cent to 5–10 per cent, equity internal rates of return can increase by 2–3 percentage points, all else being equal. However, if new congestion points emerge, these gains may be offset by lower capture prices or increased volatility. The net effect is that grid investment improves average conditions but does not eliminate risk.
Storage is expected to play a central role in bridging this gap. As variability increases, the value of flexibility rises, creating opportunities for battery systems to capture both intraday spreads and ancillary service revenues. By 2030, installed storage capacity in South-East Europe could exceed 3–5 GW, with Greece, Romania and Bulgaria leading deployment. These assets will interact with the transmission network, smoothing flows and reducing the impact of congestion, but also creating new patterns of price differentiation.
Industrial demand will further influence the system. As energy-intensive sectors adapt to carbon constraints, long-term contracts for renewable electricity will become more prevalent. These contracts will anchor demand in specific locations, affecting flow patterns and potentially reducing volatility in some areas. At the same time, they will increase the importance of reliable delivery, reinforcing the need for both transmission capacity and flexible resources.
The regulatory framework will continue to evolve in parallel. Market coupling is expected to expand, integrating more countries into the European day-ahead and intraday markets. This will improve efficiency and transparency, but it will not override physical constraints. The distinction between market integration and physical convergence will remain, with the latter dependent on infrastructure development and operational coordination.
For investors, the key takeaway is that the 2030 grid will be more connected but not fully unified. Opportunities for arbitrage and optimisation will persist, though they may shift in location and form. Assets that combine access to transmission with flexibility—whether through storage, hybrid generation or strategic positioning—will be best placed to capture value.
The scale of investment currently underway reflects a recognition that transmission is central to the energy transition. Without it, renewable capacity cannot be fully utilised, and markets cannot function efficiently. However, the relationship between infrastructure and market outcomes is not linear. More capacity reduces some constraints but introduces new dynamics, particularly in systems with high shares of variable generation.
South-East Europe is moving towards a more integrated and resilient electricity system, but the process is incremental and uneven. Price convergence will improve, but it will remain incomplete. The grid will continue to shape market outcomes, and understanding its evolving structure will be essential for anyone seeking to navigate the region’s energy landscape.
