Why curtailment is becoming a financing issue in South-East Europe’s renewable buildout

In South-East Europe, the discussion around curtailment is moving beyond day-to-day operations and into the mechanics of how projects are financed. With renewable capacity set to accelerate toward 20–25 GW by 2030, investors are finding that legacy transmission layouts—built around centralised generation—are not keeping pace with where new supply is being added, turning congestion into a structural cost.

Curtailment describes how this shift shows up first at the project level: measurable and persistent revenue erosion is increasingly being reflected in PPA structures, debt sizing and equity return expectations. Rather than treating curtailed energy as an outlier event, lenders and developers are now modelling it as part of the base case for cash flows.

Where curtailment risk looks contained—and where it does not

The geography of the problem is uneven. In northern parts of the region—especially areas linked to Central Europe through Hungary and western Romania—curtailment remains limited. Around the Subotica–Sandorfalva 400 kV corridor, transfer capacity reaches 1,200–1,500 MW, while ATC typically sits at 600–1,000 MW. In that corridor zone, curtailment is still below 3–5%.

Solar economics in these comparatively stable nodes also look less pressured: capture prices remain close to baseload benchmarks, with discounts of about €2–5/MWh. That profile supports steadier revenue streams and helps explain why some projects can still be structured with heavier reliance on debt.

The picture changes in central zones. Around Kragujevac, Kraljevo and the Morava corridor, congestion tends to appear during high solar output periods even as EMS implements reinforcements worth €200–300 million. Forward models increasingly treat curtailment levels of 5–15% as standard.

The article illustrates what those percentages mean in practice using a common reference point: for a 100 MW solar plant producing 150 GWh annually, curtailment translates into roughly 7–20 GWh of lost production. At realised prices of about €80–100/MWh, that implies annual revenue losses in the range of €0.6–2.0 million.

Bottlenecks intensify across southern corridors and parts of Romania and Bulgaria

Bosnia and Herzegovina shows similar constraints around key nodes such as Tuzla and Sarajevo nodes. There, grid limitations tied to ageing infrastructure restrict export capacity, with new solar clusters increasingly modelled at curtailment levels of 10–20%, particularly during summer months when hydro output is high but local demand cannot absorb all generation.

The most acute risk described lies further south. In regions including southern Serbia, North Macedonia and Albania, constrained northbound transfer capacity—often limited to 400–700 MW ATC-interacts with rapidly expanding solar pipelines. Curtailment levels of 20–30%

The same example used earlier makes the financing implications clear: for a 100 MW plant, lost output could reach roughly 30–45 GWh annually, corresponding to foregone revenue of about €2.5–4.5 million per year. The article also links this directly to investor returns—compressing equity IRRs by approximately 3–5 percentage points.

Romania adds another layer because interconnection strength varies within the country. While northern and western nodes benefit from stronger links, the article highlights constraints in the Dobrogea region, which hosts Romania’s largest wind fleet. Even with installed wind capacity exceeding 3 GW, transmission limitations toward inland demand centres create periodic curtailment events—estimated at about 5–10%, with peaks above 15%.

Bulgaria exhibits comparable asymmetry. Northern nodes aligned with Romania operate relatively stably, but southern corridors toward Greece face volatility driven by solar saturation and cross-border flows. Curtailment in southern Bulgaria can reach 15–25% during peak solar periods, especially when export capacity is constrained or Greek prices fall midday.

A financing lens on technology exposure—and why storage matters more than ever

Curtailment risk does not affect all technologies equally. Solar appears most exposed due to its concentrated generation profile around midday hours when system demand is lower and prices tend to be suppressed. Wind generally experiences lower average curtailment—typically 3–8% in less constrained zones and 10–15% in saturated regions—but wind projects in Dobrogea or coastal Bulgaria can still encounter significant constraints during high-output periods.

The financial impact extends beyond simply losing volume. The article notes that curtailment interacts with price formation by amplifying capture discounts: when solar output is curtaled, remaining generation often coincides with lower-price intervals, reducing realised revenues further. In heavily constrained nodes combined effects can cut effective prices by about €15–30/MWh </bcompared with baseload benchmarks.

This dual mechanism changes how lenders underwrite risk. Debt sizing increasingly relies on P90 or even P95 production scenarios adjusted for curtailment rather than theoretical generation potential—for instance shifting an original estimate such as 150 GWh/year </bto an underwriting range closer to 110–130 GWh </bdepending on location. With reduced available cash flow for debt service comes lower leverage potential and higher equity requirements.

PPA flexibility grows alongside grid investment plans—and data tools become part of development workstreams

The mitigation toolkit described starts with storage as the most direct lever. By capturing excess generation and shifting it into higher-demand periods, batteries can recover part of curtailed energy. A 200 MWh battery </bpaired with a 100 MW solar plant can reduce effective curtailment from aboutb20–25% /emphasis>’/>to belowb10-12% /emphasis>’/>depending on dispatch strategy and market conditions.

The article estimates that recovery could add roughlyb €1.5–3.0 million /emphasis>’/>in annual revenue—partially offsetting losses from curtailed production.

Curtailment risk also influences contract design through PPAs. Industrial off-takers are increasingly willing to accept variable delivery profiles—in particular where they face carbon costs—in exchange for lower pricing or flexible terms. Contracts are being structured so pricing reflects actual delivered energy rather than theoretical output.

An example cited involves discussions in Serbia with industrial consumers includingZijin Mining and HBIS. The article says PPAs there incorporate flexibility clauses along with pricing adjustments tied to delivery performance.

Grid reinforcement remains important but uneven across time and space. Projects such as the Trans-Balkan Corridor (aboutZijin Mining and HBIS)? ‘/>The source text states investments including  ‘/>’/>and Bulgaria-Greece reinforcements (about €500 million+) are expected to increase transfer capacity by 20–40%, ‘/>reducing curtailment in some areas. ‘/>Still, ‘/>as renewable additions rise, ‘/>new congestion points may emerge where resource concentration outpaces network expansion.