Curtailment has evolved into a significant structural cost in South-East Europe, impacting the financial viability of renewable energy projects. With renewable capacity projected to reach 20–25 GW by 2030, the region’s transmission infrastructure, primarily based on outdated 400 kV corridors, has not kept pace with this growth. This mismatch has led to congestion and persistent revenue losses at the project level, which are increasingly factored into financing arrangements, power purchase agreements (PPAs), and equity returns.
The geographical distribution of curtailment varies across the region. In northern areas, particularly those connected to Central Europe via Hungary and western Romania, curtailment rates remain relatively low. For instance, around the Subotica–Sandorfalva 400 kV corridor, where transfer capacity ranges from 1,200–1,500 MW and available transfer capability (ATC) typically falls between 600–1,000 MW, curtailment levels are reported at less than 3–5%. This stability allows solar capture prices to remain close to baseload benchmarks, with minimal discounts of €2–5/MWh.
In contrast, central regions such as Kragujevac, Kraljevo, and the Morava corridor face heightened curtailment risks. Here, the state-owned operator EMS is investing between €200–300 million in grid reinforcements to alleviate congestion during peak solar output periods. Current modeling indicates standard curtailment levels of 5–15%, translating to potential production losses of 7–20 GWh annually for a typical 100 MW solar plant, resulting in revenue losses ranging from €0.6–2.0 million per year.
The situation is similarly concerning in Bosnia and Herzegovina around nodes like Tuzla and Sarajevo, where aging infrastructure limits export capacity. New solar clusters are facing curtailment levels estimated between 10–20%, especially during summer months when hydroelectric output peaks and local demand fails to match generation levels.
The southern regions—including southern Serbia, North Macedonia, and Albania—exhibit the most severe curtailment challenges. Here, constrained northbound transfer capacities often range from 400–700 MW ATC, which significantly impacts rapidly expanding solar projects. Financial models for these areas now incorporate expected curtailment rates of 20–30%, suggesting that a 100 MW plant could see annual output losses of 30–45 GWh, equating to foregone revenues of approximately €2.5–4.5 million.
Romania’s energy landscape presents a complex scenario as well. While northern and western nodes benefit from robust interconnections, the Dobrogea region, which hosts over 3 GW of wind capacity, faces increasing transmission limitations that lead to periodic curtailments. Current estimates suggest curtailment rates between 5–10%, with spikes exceeding 15% during conditions of high wind output coinciding with low demand.
Bulgaria’s grid also reflects this asymmetry; while northern nodes operate stably, southern corridors toward Greece experience volatility due to solar saturation and fluctuating cross-border flows. During peak solar production periods, curtailment can reach as high as 15–25%, particularly when export capacities are constrained or when Greek market prices drop significantly.
The situation in Montenegro is somewhat unique due to its connection via a 600 MW HVDC link to Italy. This link provides an outlet for excess generation; however, local demand constraints still pose risks for curtailment as new renewable projects come online without corresponding internal network reinforcements.
Differentiation among technologies reveals that solar energy is particularly vulnerable due to its concentrated generation profile during midday hours when demand is lower. Wind energy typically experiences lower average curtailment rates—ranging from 3–8% in less constrained areas to about 10–15% in more saturated zones—though significant constraints can still occur in high-output regions like Dobrogea or coastal Bulgaria.
The financial implications of curtailment extend beyond mere volume loss; they also affect price formation dynamics by amplifying capture discounts. When solar output is curtailed, remaining generation often occurs during lower price periods, further diminishing realized revenues. In heavily constrained nodes, the combined effects of curtailment and capture discounts can reduce effective prices by as much as €15–30/MWh.
This dual impact necessitates a shift in how lenders assess project viability. Debt sizing is increasingly based on adjusted production scenarios that account for expected curtailments rather than theoretical maximum outputs. Consequently, a project initially modeled for 150 GWh/year may now be underwritten at only 110–130 GWh, resulting in reduced cash flow available for debt servicing and increased equity requirements.
Curtailment mitigation strategies are becoming integral to project design considerations. Energy storage solutions represent a direct approach; for example, pairing a 200 MWh battery with a 100 MW solar plant can effectively lower curtailment rates from an estimated 20–25% down to below 10–12%. This recovery mechanism could potentially generate an additional annual revenue stream of between €1.5–3.0 million.
The evolving landscape of PPAs reflects these challenges as industrial consumers become more amenable to accepting variable delivery profiles in exchange for favorable pricing or flexible terms. Contracts are increasingly structured to accommodate anticipated curtailed volumes, with pricing mechanisms that align more closely with actual delivered energy rather than theoretical outputs.
The long-term solution lies in grid investments aimed at enhancing transfer capacities. Projects such as the proposed Trans-Balkan Corridor (€300–400 million) and Bulgaria-Greece reinforcements (exceeding €500 million) are expected to boost transfer capabilities by approximately 20–40%. However, as renewable capacity continues to grow, new congestion points may arise in areas with high resource concentrations.
The role of data analytics is becoming increasingly vital in managing curtailment risks effectively. Platforms like Electricity.Trade offer detailed insights into congestion patterns and price dynamics at specific nodes, enabling stakeholders to model scenarios with enhanced accuracy—a crucial aspect for both project development and financing processes.
Curtailment has transitioned from being merely an operational concern to a core element influencing investment decisions across South-East Europe’s energy sector. Developers are now prioritizing locations with better grid access over sites with higher resource quality but weaker connections, recognizing that actual output and pricing take precedence over theoretical potential. As such, understanding the nuances of curtailment distribution and mitigation strategies has become essential for all market participants navigating this evolving electricity landscape.
