Curtailment in South-East Europe has shifted from an operational anomaly to a structural financial variable. As renewable capacity accelerates toward 20–25 GW by 2030, the region’s transmission system—anchored in legacy 400 kV corridors designed for centralised generation—has not expanded at the same pace or in the same spatial configuration. The consequence is not only congestion, but measurable and persistent revenue erosion at project level, increasingly priced into financing, PPA structures and equity returns.
The geography of curtailment is now clearly defined. In northern nodes—particularly those connected to Central Europe through Hungary and western Romania—curtailment remains limited. Around the Subotica–Sandorfalva 400 kV corridor, where transfer capacity reaches 1,200–1,500 MW with ATC typically 600–1,000 MW, curtailment is still below 3–5%. Solar capture prices remain close to baseload benchmarks, with discounts of €2–5/MWh, enabling stable revenue profiles and supporting debt-heavy structures.
The situation changes markedly in central zones. Around Kragujevac, Kraljevo and the Morava corridor, where EMS is implementing reinforcements worth €200–300 million, congestion emerges during high solar output periods. Curtailment levels of 5–15% are now standard in forward modelling. For a 100 MW solar plant producing 150 GWh annually, this equates to 7–20 GWh of lost production, translating into revenue losses of €0.6–2.0 million per year at realised prices of €80–100/MWh.
In Bosnia and Herzegovina, similar patterns are visible around Tuzla and Sarajevo nodes, where grid constraints and ageing infrastructure limit export capacity. Curtailment levels are increasingly being modelled at 10–20% for new solar clusters, particularly in summer months when hydro output is high and local demand is insufficient to absorb generation.
The most acute curtailment risk lies in southern corridors. In southern Serbia, North Macedonia and Albania, constrained northbound transfer capacity—often limited to 400–700 MW ATC—interacts with rapidly growing solar pipelines. Curtailment levels of 20–30% are now embedded in financial models for projects in these regions. For the same 100 MW plant, this implies 30–45 GWh of lost output annually, equivalent to €2.5–4.5 million in foregone revenue, compressing equity IRRs by 3–5 percentage points.
Romania presents a more complex case. While northern and western nodes benefit from strong interconnection, the Dobrogea region, home to the country’s largest wind fleet, is increasingly constrained. Despite installed capacity exceeding 3 GW of wind, transmission limitations toward inland demand centres create periodic curtailment events. Current estimates place curtailment at 5–10%, with peaks above 15% during high wind and low demand conditions. Transelectrica’s ongoing investments aim to reduce these levels, but the concentration of generation remains a structural challenge.
Bulgaria’s grid exhibits similar asymmetry. Northern nodes aligned with Romania maintain relatively stable operation, while southern corridors toward Greece experience volatility driven by solar saturation and cross-border flows. Curtailment in southern Bulgaria can reach 15–25% during peak solar periods, particularly when export capacity is constrained or Greek prices collapse midday.
Montenegro’s position is distinct due to the presence of the 600 MW HVDC link to Italy, which provides an export outlet for surplus generation. However, internal constraints and limited domestic demand still create localised curtailment risks, particularly as new renewable projects—such as those linked to the Masdar–EPCG platform (targeting €3–4 billion of investment and multi-GW capacity)—come online. Without parallel reinforcement of internal networks, curtailment could rise from negligible levels to 5–10% in certain nodes.
Curtailment is not uniform across technologies. Solar is the most exposed due to its concentrated generation profile, particularly in midday hours when system demand is lower and prices are suppressed. Wind, with more distributed output, experiences lower curtailment on average, typically 3–8% in less constrained zones and 10–15% in saturated regions. However, wind projects in Dobrogea or coastal Bulgaria can still face significant constraints during high-output periods.
The financial impact of curtailment extends beyond lost volume. It interacts with price formation, amplifying capture discounts. When solar output is curtailed, the remaining generation often coincides with lower price periods, further reducing realised revenues. In heavily constrained nodes, combined effects of curtailment and capture discounts can reduce effective prices by €15–30/MWh relative to baseload benchmarks.
For lenders, this dual impact is critical. Debt sizing is increasingly based on P90 or even P95 production scenarios adjusted for curtailment, rather than theoretical generation. A project originally modelled at 150 GWh/year may be underwritten at 110–130 GWh, depending on location. This reduces available cash flow for debt service, lowering leverage and increasing equity requirements.
Mitigation strategies are becoming central to project design. Storage is the most direct solution. By capturing excess generation and shifting it to higher-demand periods, batteries can recover a significant portion of curtailed energy. A 200 MWh battery paired with a 100 MW solar plant can reduce effective curtailment from 20–25% to below 10–12%, depending on dispatch strategy and market conditions. This recovery can add €1.5–3.0 million in annual revenue, partially offsetting losses.
Curtailment risk is also influencing PPA structures. Industrial offtakers, particularly those exposed to carbon costs, are increasingly willing to accept variable delivery profiles in exchange for lower prices or flexible terms. Contracts are being structured to accommodate curtailed volumes, with pricing mechanisms that reflect actual delivered energy rather than theoretical output. In Serbia, discussions with industrial consumers such as Zijin Mining and HBIS illustrate this trend, with PPAs incorporating flexibility clauses and pricing adjustments linked to delivery.
Grid investment remains a long-term solution, but its impact is uneven. Projects such as the Trans-Balkan Corridor (€300–400 million) and Bulgaria–Greece reinforcements (€500 million+) are expected to increase transfer capacity by 20–40%, reducing curtailment in some areas. However, as renewable capacity grows, new congestion points are likely to emerge, particularly in regions with high resource concentration.
Data analytics is becoming a critical tool in managing curtailment risk. Platforms like Electricity.Trade provide granular insights into nodal congestion, flow patterns and price dynamics, enabling developers and investors to model scenarios with greater accuracy. This data-driven approach is increasingly embedded in both project development and financing processes.
The emergence of curtailment as a structural cost is reshaping investment decisions across South-East Europe. Developers are prioritising locations with stronger grid access, even if resource quality is slightly lower, recognising that realised output and pricing are more important than theoretical potential. Investors are differentiating between projects based on their exposure to grid constraints, allocating capital to those with clearer pathways to market.
Curtailment is no longer an externality; it is a core component of project economics. Its distribution across the region reflects the interaction of generation growth, transmission capacity and market structure. Understanding this distribution—and the ways in which it can be mitigated—has become essential for any participant seeking to operate effectively within South-East Europe’s evolving electricity system.