Europe’s energy transition has entered a phase where ambition is no longer the binding constraint. Capital is available, policy frameworks are largely aligned, and renewable pipelines are expanding at unprecedented scale. What now determines whether projects are built, industries relocate, and markets integrate is far more physical: the ability of transmission and distribution networks to carry power where it is needed, when it is needed. Nowhere is this more consequential than in South-East Europe (SEE), where the interface between EU member states and the wider Western Balkans creates a structurally critical—but increasingly constrained—energy corridor.
The latest system-level evidence underscores the scale of the challenge. At least 120 GW of planned renewable capacity across Europe is at risk due to insufficient grid capacity, with transmission-level constraints alone accounting for a shortfall of roughly 104 GW. Among the most constrained systems are Romania and Bulgaria, two countries that sit at the heart of the SEE–EU electricity interface.
This is not a marginal issue. Romania and Bulgaria are not peripheral markets; they are structural transit systems linking the Black Sea basin, the Balkans, and Central Europe. Constraints in these networks do not remain local. They propagate through cross-border interconnections, influence congestion pricing, shape forward curves, and ultimately determine how effectively SEE integrates into the EU’s internal electricity market.
The result is a shift in how the region must be understood. South-East Europe is no longer simply an emerging renewables cluster or a low-cost industrial periphery. It is becoming a decisive balancing zone in Europe’s energy system—one where grid capacity determines whether EU decarbonisation, industrial relocation, and energy security objectives can physically materialise.
The tension between ambition and infrastructure is already visible in the data. Across reporting countries, some systems can accommodate less than 10% of planned renewable additions by 2030 under current grid conditions. This is particularly striking because many of these same countries are expected to deliver some of the fastest renewable growth rates in Europe.
For SEE, this creates a dual-layered risk. At the project level, developers face rising uncertainty around connection timelines, curtailment exposure, and achievable capture prices. Merchant risk increases, while bankability becomes more dependent on grid-specific assumptions than on resource quality or CAPEX efficiency. At the system level, the region risks becoming a bottleneck in Europe’s broader energy transition, limiting the ability of surplus renewable generation to flow across borders and stabilise continental markets.
The implications extend directly into industrial strategy. Europe’s competitiveness agenda increasingly depends on electrification—of manufacturing, transport, and emerging sectors such as hydrogen production and data infrastructure. Yet the report highlights that in key systems, including Bulgaria and Romania, there is effectively zero available transmission capacity for new large-scale industrial loads.
This fundamentally reshapes the geography of industrial investment. In the previous decade, decisions on plant location were driven by labour cost differentials, tax regimes, and logistics. In the current cycle, access to reliable, scalable electricity infrastructure is emerging as the primary constraint. A battery manufacturer, aluminium processor, or data centre operator cannot wait five to seven years for grid reinforcement. Capital will flow to jurisdictions where connection certainty exists today, not where it is promised in long-term network development plans.
For South-East Europe, this creates a divergence risk within the region itself. Countries that can rapidly expand hosting capacity, streamline connection processes, and deploy flexible grid solutions will position themselves as credible near-shoring hubs for EU industry. Others may remain nominally integrated into the European market but fail to capture the associated investment flows.
At the distribution level, the picture is more nuanced. Many European systems retain sufficient capacity to support electrification at the household level, with grids able to accommodate heat pumps in up to 13–32% of households and EV chargers in 7–18%.
This suggests that, in SEE, the energy transition may proceed unevenly across different layers of demand. Residential electrification and distributed solar can continue to scale, supported by relatively more flexible distribution networks. In contrast, grid-scale industrial demand and large renewable projects remain constrained by transmission bottlenecks.
However, even this layer is not immune to structural limits. At least 16 GW of rooftop solar capacity across Europe is at risk due to distribution constraints, potentially affecting 1.5 million households. For SEE, where distributed generation is often seen as a rapid decarbonisation pathway, this serves as a warning. Without sustained investment in distribution infrastructure, even the most accessible segments of the energy transition can stall.
The most immediate operational challenge is not just limited capacity, but the scale of the connection queue. Across reporting countries, nearly 700 GW of renewable projects are currently awaiting grid connection. In some cases, project pipelines exceed existing system capacity by an order of magnitude.
This has direct relevance for SEE markets, where project announcements frequently outpace infrastructure readiness. The presence of a large pipeline does not equate to deliverable capacity. Without reform of connection processes, prioritisation mechanisms, and technical standards, a significant portion of these projects will remain speculative.
In this environment, grid access itself becomes a scarce economic resource—one that must be actively allocated rather than passively queued. Several European countries have already begun implementing mechanisms to address this, including competitive allocation of grid capacity and reservation of connection rights for high-probability projects. France, for example, has pre-allocated around 71 GW of grid capacity specifically for renewable integration, while Spain operates a tender-based allocation system to prevent speculative congestion.
For SEE, adopting similar frameworks could significantly accelerate project realisation. The alternative is a continued accumulation of queue backlogs, where viable projects are delayed alongside non-viable ones, eroding investor confidence and increasing system inefficiency.
Yet the most critical lever identified in the analysis is the role of non-wire solutions. Technologies such as dynamic line rating, advanced grid monitoring, and flexible connection agreements can unlock between 140 GW and 185 GW of additional capacity across Europe without requiring immediate large-scale infrastructure expansion.
This is particularly relevant for South-East Europe, where financing constraints, permitting delays, and institutional complexity often slow down traditional grid expansion. Non-wire solutions offer a faster, lower-CAPEX pathway to increase effective capacity, allowing systems to accommodate additional generation and demand within existing infrastructure envelopes.
The Dutch experience illustrates the scale of the opportunity. By implementing flexible connection contracts, the transmission operator has already unlocked 9.1 GW of capacity—equivalent to roughly 40% of national peak demand.
For SEE operators, this provides a replicable model. The combination of grid-enhancing technologies and regulatory flexibility can transform grid constraints from a hard physical limit into a manageable operational parameter. It also aligns with the region’s broader role as a flexibility provider within the European system, particularly as intermittent renewable penetration increases.
The broader policy context reinforces the urgency of these developments. European-level initiatives—including the Grid Action Plan (2023), electricity market reforms, and the European Grid Package (2025)—have established a framework for accelerating grid investment and improving connection processes. However, implementation remains decentralised.
In South-East Europe, this decentralisation is both an opportunity and a risk. It allows individual countries to move quickly and differentiate themselves as investment destinations. At the same time, it introduces fragmentation, where uneven progress across jurisdictions can weaken regional integration.
This dynamic is particularly important given SEE’s role in cross-border electricity flows. The region’s interconnections—linking Serbia, Romania, Bulgaria, Hungary, Greece, and the Western Balkans—are not just infrastructure assets. They are price formation mechanisms, balancing tools, and risk transmission channels. Constraints in one part of the network can influence congestion patterns and price spreads across the entire corridor.
As renewable penetration increases, these dynamics become more pronounced. Curtailment risk rises in constrained zones, while neighbouring markets may experience volatility driven by limited transfer capacity. For investors, this translates into a more complex risk environment, where project economics depend not only on local conditions but also on regional grid topology and interconnection performance.
Within this framework, South-East Europe’s interdependence with the EU market is deepening—but also becoming more conditional. Integration is no longer defined solely by regulatory alignment or market coupling. It is defined by physical capacity, operational flexibility, and the ability to deliver projects within system constraints.
The strategic implication is clear. Grid readiness has become a proxy for economic readiness. Countries that can align transmission expansion, distribution investment, regulatory reform, and flexible grid operation will capture the next wave of energy and industrial investment. Those that cannot will face a growing gap between nominal ambition and actual delivery.
In practical terms, this shifts the centre of gravity for energy strategy in SEE. The focus moves from pipeline announcements to connection certainty, from installed capacity targets to hosting capacity maps, and from long-term infrastructure planning to short-term operational optimisation.
The region’s opportunity remains substantial. South-East Europe retains strong renewable resources, a strategic geographic position, and increasing alignment with EU market structures. But realising that opportunity now depends on resolving a fundamentally infrastructural constraint.
The transition from ambition to execution is no longer a question of policy intent. It is a question of whether electrons can move across borders, into industries, and through networks at the scale and speed required. In that sense, the future of Europe’s energy system is not only being decided in Brussels or Berlin, but increasingly along the transmission corridors of South-East Europe—where capacity, congestion, and connectivity define what is possible.
