The cost of building power assets in South-East Europe is not determined by engineering alone. It is also a sovereign function. Developers can procure the same inverter, battery rack or wind turbine model in Serbia, Romania, Bulgaria or Greece, yet the resulting weighted average cost of capital will differ materially because lenders and equity investors price not only technology and merchant risk, but also the sovereign backdrop in which each asset sits. That difference is now large enough to alter project rankings, reshape portfolio allocation and, in several cases, determine whether a renewable or storage project closes at all.
A useful starting point is the government bond market, because it provides the cleanest observable reference for sovereign funding cost before project-level risk is added. In late March 2026, Romania’s 10-year government bond yield was around 7.2–7.25%, Serbia’s 10-year sovereign yield was roughly 5.2–5.23%, while Serbia’s own January 2026 10-year local-currency auction cleared at 5.07% and its March 2026 5-year dinar issue cleared at 4.55%. These are not project finance rates, but they establish the sovereign floor from which energy-sector borrowing is built. Romania is therefore entering renewable and grid financing discussions from a meaningfully higher sovereign base than Serbia, even before technology, merchant exposure or connection risk is considered.
That sovereign floor immediately feeds into debt pricing. A utility-scale solar or wind project in a Western European core market may still finance senior debt at a relatively modest spread over the reference curve if backed by a solid PPA and low curtailment risk. In South-East Europe, the same project is more likely to face all-in pricing that reflects a sovereign premium, regulatory uncertainty premium and market-structure premium layered on top of the technology risk. In practical terms, that means debt margins for good projects in stronger SEE jurisdictions often sit around 250–350 basis points over Euribor, while projects with weaker offtake structures, higher congestion exposure or less mature legal environments can move toward 350–500 basis points. In absolute terms, that changes DSCR headroom far more than many sponsor models initially assume.
Romania is currently the clearest example of how macro risk can overwhelm strong sector fundamentals. The country has one of the region’s strongest renewable resource bases, a large power market, functioning market coupling with Hungary and a serious long-term decarbonisation pipeline. Yet a sovereign yield above 7% means that even otherwise attractive renewable assets carry a more expensive financing stack than peers in lower-risk jurisdictions. For a 100 MW solar project costing €70–85 million, a debt package priced 150–200 basis points higher than originally assumed can remove roughly 1.5–2.5 percentage points from equity IRR, depending on tenor, grace period and amortisation structure. For wind assets with CAPEX of €120–160 million per 100 MW, the absolute impact is even larger because the debt quantum is bigger and the repayment burden extends over a longer cash-flow horizon.
Serbia’s position is more nuanced. Its observed sovereign market levels in early 2026, around 5.1–5.2% at the 10-year point, are materially lower than Romania’s current 10-year level, which in purely financing terms is supportive for renewable and storage projects. That does not automatically make Serbian power assets cheaper to finance in practice, because the project-level premium added by grid access uncertainty, connection queues, offtake structuring and non-coupled market status can still be large. But the sovereign base is not the binding constraint it is in Romania. In other words, Serbia’s challenge is less about the macro curve and more about how market design, congestion and connection risk are layered onto that curve by lenders.
Bulgaria sits in a different category again. Available market snapshots show Bulgarian 10-year sovereign yields materially below Romanian levels and closer to the lower end of the regional spectrum, reflecting euro-area anchoring effects and a more compressed sovereign-risk profile than the rest of the non-euro Balkan markets. That does not mean project finance in Bulgaria is “cheap” in absolute terms, but it does mean that the sovereign premium component is lighter. For well-positioned solar, wind or BESS projects, particularly those with exposure to the Greece interconnection and strong optimisation potential, this creates an interesting financing asymmetry: volatility and trading opportunity remain high, but sovereign drag is lower than in markets with similarly attractive merchant upside.
The effect of sovereign risk becomes even clearer when translated into lender metrics. In a low-risk environment, a strong contracted renewable project can often support a minimum DSCR of around 1.20x–1.25x. In South-East Europe, lenders frequently look for 1.30x–1.40x as the practical floor for well-structured assets, with 1.45x–1.60x not uncommon for projects carrying material merchant tail, congestion exposure or uncertain capture-price behaviour. The reason is not simply conservatism. Higher sovereign and macro volatility mean that debt providers want larger cash-flow cushions against refinancing risk, inflation risk, political risk and exchange-rate pass-through, even when nominal project revenues are euro-linked. A project that appears bankable at first glance can therefore lose leverage simply because its macro environment forces a wider DSCR buffer.
This matters directly for equity returns. Consider a 100 MW solar project in northern Serbia, with CAPEX around €75 million, annual production of 140–160 GWh, realised prices of €75–85/MWh, and low curtailment. At 70% debt leverage, debt pricing near the lower end of the regional range and a base-case DSCR above 1.30x, the project can support equity IRRs of roughly 10–12%. Shift the same project into a higher-spread financing environment, reduce leverage to 55–60% and tighten the DSCR requirement to 1.45x, and equity returns can fall toward 8–9%, even before any change in power-price assumptions. The technology did not deteriorate. The sovereign and credit overlay did.
The same mechanism is even more decisive for battery storage. BESS revenues are more volatile, less historically banked and more dependent on optimisation quality than fixed-price renewable revenues. That means lenders already assign them a higher risk premium. Add a higher-sovereign-risk jurisdiction, and the result is often a funding structure with lower leverage, shorter tenor and more aggressive reserve requirements. A 50 MW / 200 MWh battery costing €80–120 million may be capable of generating attractive gross revenues in a high-volatility market such as Greece or Bulgaria, but if senior debt is priced expensively and leverage is capped at 50–60% rather than 65%+, the project’s equity case becomes much more sensitive to operational underperformance. Sovereign risk therefore shapes not only the cost of debt, but the strategic attractiveness of whole asset classes.
Greece deserves separate treatment because its sovereign backdrop interacts with a very different merchant environment. The Greek market offers some of the strongest intraday and balancing value in the region, supported by LNG-linked price formation, solar saturation and a deepening storage market. That can justify higher-risk capital and support stronger revenue stacks for optimised BESS and hybrid assets. But even there, financing costs are not determined only by volatility upside. Lenders still test merchant assumptions hard, and the project’s debt package depends on how much of the revenue stack is contracted, how much sits in ancillary services and how much depends on active trading. Sovereign risk does not disappear in a higher-value market; it is simply mediated by stronger earnings potential.
For sponsors, this creates a growing divide between nominal and real project value. On paper, a Romanian or Greek asset may have a higher merchant revenue envelope than a Serbian one because wholesale prices or spreads are larger. In practice, once sovereign and credit spreads are applied, a lower-volatility asset in a slightly less stressed financing environment may deliver the stronger risk-adjusted return. This is increasingly visible in portfolio construction. Investors are not just asking which node captures the highest price or which border offers the largest spread. They are asking which jurisdiction allows those revenues to be financed at acceptable leverage and debt cost.
That is why the role of development finance institutions remains disproportionately important in South-East Europe. When institutions such as the EBRD or EIB support transmission upgrades, renewable platforms or storage build-out, they do more than provide capital. They compress risk. Their involvement can reduce effective funding cost, improve tenor and, just as importantly, crowd in commercial lenders who might otherwise remain cautious. In several SEE markets, the difference between a merchant-heavy asset financed on fully commercial terms and the same asset financed with multilateral participation is the difference between a marginal and an investable return profile. This is especially true where the sovereign curve is elevated, because concessional or quasi-concessional layers help offset macro drag that the project itself cannot control.
The sovereign effect is also visible in sponsor equity hurdles. In core Western Europe, utility-scale contracted renewables can still clear investment committees with target equity returns in the high single digits. In South-East Europe, sponsors typically underwrite toward 10–15% depending on asset class, market structure and offtake certainty. Storage and strongly merchant hybrid platforms often require the upper end of that range, or more, because they stack merchant, optimisation and regulatory risk on top of sovereign exposure. That hurdle-rate gap is one reason the region continues to attract infrastructure and opportunistic capital even as financing conditions remain tighter than in the EU core: the return expectations are higher because the risk is visibly higher.
This also explains why project structuring is becoming as important as project location. Sponsors that can anchor revenues through industrial PPAs, floor-price mechanisms, route-to-market agreements or hybrid storage structures are effectively compressing their own credit spread. A Serbian solar project with a credible industrial offtaker and low-curtailment node can price closer to the stronger end of the regional debt range. A Romanian merchant wind asset with no firm offtake and meaningful curtailment exposure may price much worse despite stronger market coupling and a larger system. The financing market is now discriminating less by technology label and more by how convincingly a project converts volatile system conditions into durable cash flow.
There is a further macro layer that investors increasingly model explicitly: refinancing risk. South-East European projects financed today may have debt maturities or refinancing points that land in a very different rates environment. If sovereign curves remain elevated, the refinancing of merchant tails becomes materially more expensive, especially for assets without contracted backstops. This is particularly relevant for storage, where lenders may still prefer shorter tenors than for contracted wind or solar. A BESS asset may generate excellent cash returns in years one to seven, yet still carry material refinancing uncertainty if sovereign spreads widen or volatility revenues normalise. That uncertainty has become part of the valuation discussion, not an afterthought.
In this environment, data and comparability matter. One of the most useful shifts in the regional market is that platforms such as Electricity.Trade increasingly allow sponsors and investors to connect power-market fundamentals with capital-market realities. Grid congestion, basis risk, capture prices and balancing revenue can be modelled in the same frame as sovereign funding cost, debt margin assumptions and DSCR sizing. That is where a lot of traditional project-development thinking is still too static. A megawatt in South-East Europe is not just a unit of installed capacity. It is a credit instrument whose value is filtered through sovereign spreads, lender caution and macro liquidity conditions.
The consequence is that sovereign risk is no longer a background discount rate used by investment committees at the end of the model. It has become an active commercial variable shaping how projects are designed from the start. It influences whether sponsors prefer a northern Serbian node over a Romanian one, whether a Bulgarian battery is financed on merchant terms or paired with contracted services, whether a Greek hybrid asset is leveraged aggressively or conservatively, and whether portfolio capital goes first into grid-adjacent wind, industrial PPAs or storage. In short, sovereign spreads are now part of the physical economics of the system.
That is likely to remain true through the 2030 build-out cycle. South-East Europe still offers some of the most attractive volatility, spread and structural-transition opportunities in the European power market. But it is not an EU-core financing environment, and investors who model it as such will misprice risk. The winning strategies will be those that treat sovereign cost not as an abstract macro penalty, but as a measurable component of asset design, capital structure and route-to-market planning. In a region where congestion, curtailment and volatility already define the power market, the cost of capital is becoming just as location-specific as the electricity price itself.
