In South-East Europe’s renewables boom, where power can go is becoming the real profit driver

The next phase of renewable investment in South-East Europe is being written less by how much electricity plants can generate and more by where that power can actually flow. Capacity additions continue across Serbia, Romania, Bulgaria and the Western Balkans, but the decisive variable for investors is moving toward the grid: the interaction between generation and transmission—especially the 400 kV backbone that determines whether electricity reaches value-bearing markets or gets stuck in congested nodes.

Serbia shows the clearest split between export access and local saturation

Nowhere is that shift more visible than in Serbia, where EMS operates a network that is both central to regional flows and subject to persistent constraints. The Subotica 400 kV substation, connected to Hungary’s Sandorfalva, functions as a relatively reliable gateway into Central European pricing. Projects situated near it benefit from steadier capture prices, limited curtailment and access to liquidity supported by Hungary and Romania.

By contrast, Serbia’s southern corridor toward Bulgaria and North Macedonia faces structural pressure at the Niš and Vranje 400 kV nodes. Export capacity in this direction remains limited while local renewable growth—particularly solar—has started to saturate midday demand.

Returns are diverging by node: Tier 1 economics versus Tier 3 stress

This geographical mismatch is starting to show up in project-level economics. In northern Serbia and western Romania—described increasingly as Tier 1 nodes—curtailment stays below 5%, while capture prices track closely with regional baseload levels of €70–90/MWh. There, solar and wind projects can deliver equity internal rates of return of roughly 9–12%, with debt leverage up to 70–75% and DSCR around 1.30–1.40x.

The picture changes further south into a transitional band covering central Serbia, Bosnia and Herzegovina, and inland Bulgaria. Curtailment rises to 5–15%, while capture discounts widen to €5–12/MWh, relative to benchmark markets. These Tier 2 zones still attract investment but financing becomes more conditional: lenders look for partial hedging via power purchase agreements or structural enhancements such as storage. Equity returns compress into a 7–10% range as leverage typically falls toward 60–65%, reflecting higher revenue volatility.

The most pronounced impact appears in southern parts of the region—including southern Serbia, North Macedonia, Albania and portions of Greece—where developers describe them as Tier 3 zones. Curtailment reaches 15–35%, especially during peak solar hours when local demand is insufficient and export capacity is constrained. Capture prices can drop by €15–30/MWh, pushing achievable PPA levels down to about €45–70/MWh. Standalone solar projects then struggle to sustain equity IRRs above 6–8%, sometimes falling below bankability thresholds unless backed by additional revenue mechanisms.

A hybrid toolkit is emerging: storage plus industrial buyers

The market’s response is becoming more consistent across technologies—and across risk tiers. Solar-heavy portfolios face increasing exposure to congestion-driven earnings compression through what developers call price cannibalisation, with capture ratios falling to about 0.75–0.90