Grid access becomes the new deal driver for renewable project finance in South-East Europe

Renewable project finance across South-East Europe is being repriced with a sharper focus on grid access and the risk of curtailment. What used to be judged mainly on CAPEX efficiency and resource quality is now being tested against whether output can reliably reach liquid markets without being discounted or shut down.

The change shows up first in how deals are modelled: lenders are effectively underwriting “deliverability,” tied to each project’s connection to the region’s high-voltage transmission system—particularly the 400 kV backbone operated by EMS Serbia, Transelectrica Romania, ESO Bulgaria, CGES Montenegro and IPTO Greece. In this framework, forward power prices matter less than capture rates and congestion outcomes that determine what generators actually earn.

From reference prices to capture discounts—and why location now dominates

Forward baseload curves remain a starting point for revenue modelling. In Hungary (HUPX) and Romania (OPCOM), delivery years 2026–2028 have typically traded around €75–95/MWh. But those benchmarks no longer translate directly into project revenues once grid constraints enter the picture.

A northern Serbia example illustrates how quickly economics diverge by node. Near the Subotica–Sandorfalva 400 kV interconnection, capture discounts tend to stay limited at about €2–5/MWh, with curtailment assumptions usually below 3–5%. For a hypothetical 100 MW solar project producing roughly 140–160 GWh annually, realised annual revenues can land around €10–13 million. Under those conditions, equity IRRs are estimated at roughly 10–12%, with debt ratios of about 65–75%, supported by DSCR levels above 1.30x–1.40x.

If that same plant were instead sited in central Serbia—closer to nodes such as Kragujevac or Kraljevo, where EMS is reinforcing the network—the financing profile changes. Capture discounts widen to approximately €5–12/MWh, while curtailment rises toward 5–15%. Annual revenues fall to an estimated range of €8–11 million, equity IRRs drop to about 7–9%, leverage tightens toward 55–65%, and lenders seek DSCR buffers closer to 1.40x–1.50x.

Curtailment risk becomes structural in southern corridors

The impact intensifies further in southern areas, particularly around the Serbian market near the interface with North Macedonia—around nodes such as Vranje and the Serbia–North Macedonia interface. Here, curtailment levels of roughly 20–30% are increasingly reflected for solar clusters due to constrained northbound transfer capacity (often cited as about 400–700 MW ATC versus higher nominal capacity). Capture discounts can also expand sharply—to around €15–25/MWh.

The combined effect pushes realised prices into an estimated band of roughly €50–65/MWh, even when regional benchmarks run higher. For a hypothetical 100 MW facility under these assumptions, annual revenues may fall below about €7–9 million; equity IRRs then decline toward roughly 5–7%. Developers would typically need either lower leverage (about 50–60% debt) or additional revenue stabilisation mechanisms to satisfy lender comfort levels.

A comparable pattern across Romania and Bulgaria—export access vs congestion pressure

A differentiated but still grid-led structure in Romania and Bulgaria

Romania’s market follows a similar logic but with different fault lines between regions. Projects in the Banat area connected through Hungary via the Arad–Sandorfalva corridors (cited at about 1,500–2,000 MW capacity) benefit from stronger export access and relatively low curtailment.

By contrast, projects in Dobrogea face increasing congestion pressures despite strong wind resources. The issue is linked to concentrated generation and transmission limitations toward inland consumption centres. Transelectrica’s planned reinforcements—including multi-hundred-million-euro upgrades—are expected to reduce curtailment from current peaks of about  10–15%  to closer to  5–8% , though variability remains part of the risk profile.

Bulgaria shows parallel dynamics within its ESO system. Northern nodes aligned with Romania tend toward more stable pricing outcomes, while southern corridors heading toward Greece—particularly along the Maritsa East–Thessaloniki axis—are described as more volatile. Spreads versus Greek prices can exceed  €30–50/MWh , yet local congestion contributes to midday price collapses for solar-heavy areas.

Banks adjust margins based on node strength—and tenors reflect caution too

The financial consequences are now embedded in lending decisions by commercial banks active in the region— UniCredit,  Erste Group,  Raiffeisen Bank International,  Intesa Sanpaolo . Term sheets increasingly incorporate grid exposure rather than treating it as background risk.

The source describes two broad pricing bands: projects located in “Tier 1” nodes with stronger interconnection access may be financed at margins of roughly  250–350 bps over Euribor . Constrained zones can see pricing move higher—to about  350–500 bps over Euribor . Tenors generally remain within a  12–18 year range , but sculpting is becoming more conservative through stronger reserve requirements.

PPA structures and storage help convert volatility into cash-flow certainty

A key response has been contractual re-engineering through industrial PPAs designed to stabilise merchant uncertainty. In Serbia, industrial buyers including steel (HBIS Smederevo), copper (Zijin Bor) ) and fertilisers are exploring long-term renewable supply arrangements aimed at mitigating carbon exposure. Contract discussions cited in the source cluster around €65–85/MWh, whether paired with premiums of roughly €5–10/MWh relative to merchant-adjusted pricing. This premium structure is linked in part to CBAM-driven incentives referenced by the article.

The same theme appears elsewhere. In Romania, industrial consumers are entering PPAs tied to wind and solar assets drawn from a diversified generation mix. In Greece, high wholesale prices—often averaging €100–140/MWh during recent periods -have encouraged industrial demand for long-term renewable contracts even as solar variability adds complexity.

Batteries move from optional add-on to core bankability tool

The source also places energy storage at centre stage for bridging constrained-grid conditions with bankable revenue outcomes. Across South-East Europe battery CAPEX has stabilised around €400–600/kWh, a level that implies investment on the order of €80–€—ü—ü—ü—ü—ü—ü—ü—ü-120 million for a 200 MWh system. (The figure is presented directly as stated.) When integrated alongside a <b&gt100 MW</b&gt solar plant, storage can recover curtailed volumes and shift output into higher-value periods—raising realised prices by an estimated €8–20/MWh.</Strong>