The financing architecture of wind projects in South-East Europe is undergoing a structural transformation. What began as a subsidy-driven build-out supported by feed-in tariffs is evolving into a multi-layered capital ecosystem, where power purchase agreements (PPAs), structured offtake arrangements, and a broader mix of private and institutional funding are determining whether projects reach financial close—and how they perform over time.
By Q1 2026, this shift is visible across Serbia, Romania, Greece and the wider Western Balkans. Developers are no longer asking whether projects are bankable under regulated schemes. The central question is how to structure revenue and capital in a system increasingly exposed to market pricing, volatility and cross-border dynamics.
From feed-in tariffs to structured PPAs
The early generation of wind projects in SEE relied on feed-in tariffs (FiTs) or quasi-CfD frameworks, providing long-term price certainty and enabling high leverage with relatively low equity risk. That model is now receding.
In its place, PPAs have become the primary instrument for revenue stabilisation, particularly for new projects without access to legacy support schemes. These agreements fall into three broad categories:
Utility-backed PPAs remain the closest substitute for traditional offtake structures. In Serbia and parts of the Western Balkans, state-linked utilities or suppliers continue to play a central role, offering long-term contracts that support project finance. These agreements provide predictable cash flows but are increasingly negotiated at market-reflective price levels rather than fixed subsidies.
Corporate PPAs (cPPAs) are emerging as a critical growth segment, particularly in Romania and Greece, where industrial consumers and data-intensive businesses are seeking long-term price hedging and decarbonisation credentials. These agreements introduce a different risk profile: counterparties are private entities, credit risk is more complex, and contract structures often include floors, caps or indexed pricing.
Merchant-linked PPAs represent the most advanced form of offtake. These contracts combine fixed-price elements with exposure to wholesale markets, allowing developers to capture upside while maintaining a degree of revenue stability. They are increasingly used in larger portfolios where trading capabilities are well developed.
The common feature across all three is that price certainty is no longer absolute. Even long-term PPAs incorporate mechanisms that link revenue to market conditions, reflecting the reality that electricity markets in SEE are becoming more integrated and volatile.
Take-off agreements and portfolio structuring
Beyond standard PPAs, developers are increasingly using take-off agreements as part of broader portfolio strategies. These arrangements go beyond simple electricity sales and often include:
- multi-asset offtake (wind + solar + storage)
- cross-border delivery structures
- balancing and shaping services bundled into contracts
The objective is to create a more bankable revenue profile by smoothing production variability and aligning generation with demand patterns.
In practice, this means that wind farms are rarely financed as standalone assets anymore. Instead, they are part of integrated portfolios, where:
- wind provides bulk generation
- solar adds daytime stability
- storage manages intraday volatility
This approach is particularly relevant in SEE, where price spreads between peak and off-peak periods are widening, and where balancing costs are becoming a significant factor in project economics.
Equity dynamics: From strategic investors to financial capital
The equity landscape in SEE wind has broadened significantly. The first wave of projects was dominated by strategic investors—utilities and developers with long-term operational focus. These players remain active, but they are now joined by a growing pool of financial investors.
Institutional capital—including infrastructure funds, pension funds and sovereign-backed vehicles—is increasingly targeting operational assets and late-stage development projects. These investors are attracted by:
- stable cash flows under PPA structures
- relatively high returns compared to Western Europe
- the growth potential of the region
At the same time, private equity and opportunistic capital are entering earlier in the project lifecycle, taking on development risk in exchange for higher potential returns. This is particularly visible in Serbia and Romania, where pipeline scale offers opportunities for portfolio aggregation and eventual exit.
The result is a two-tier equity market:
- long-term institutional holders focused on yield
- shorter-term investors focused on development and value creation
This dynamic is reshaping how projects are structured. Developers must balance the requirements of different investor classes, aligning risk allocation, return expectations and exit strategies.
Debt financing: From policy banks to market-based lending
Debt financing is also evolving. Early projects relied heavily on:
- multilateral development banks
- export credit agencies
- state-backed lending
These institutions provided long-tenor financing and supported market entry.
By 2026, commercial banks are playing a larger role, particularly for projects with strong PPA backing and experienced sponsors. Debt terms are becoming more market-driven:
- tenors remain in the 12–15 year range
- margins reflect project risk and PPA structure
- covenants increasingly account for merchant exposure
The key shift is that lenders are now evaluating projects not only on contracted revenue, but also on market integration risk, including:
- price volatility
- balancing costs
- curtailment exposure
This raises the bar for bankability. Projects without robust offtake structures or flexibility components face more challenging financing conditions.
SEE market context: Pricing, volatility and bankability
The broader market environment is critical to understanding these changes. In Q1 2026, electricity prices across SEE have frequently moved within the €90–120/MWh range, with volatility driven by renewable variability, hydro conditions and cross-border flows rather than fuel costs alone.
This creates both opportunity and complexity. High prices improve project economics and support PPA negotiations, but volatility increases risk. Developers and financiers must therefore structure contracts that balance:
- downside protection
- upside participation
- operational flexibility
The increasing importance of capture price—the price actually realised by a wind farm—adds another layer. As renewable penetration rises, capture prices can diverge significantly from average market prices, particularly during periods of high wind output.
Forecast: PPA evolution and capital flows through 2030
Looking ahead, several trends are likely to define the evolution of PPAs and funding in SEE:
In the base case, PPAs remain the dominant revenue stabilisation tool, but with increasing sophistication. Corporate PPAs expand, particularly in industrial sectors, while hybrid contracts combining fixed and merchant elements become standard.
In an upside scenario, deeper market integration and improved liquidity enable more advanced financial structures, including:
- portfolio-level PPAs
- cross-border offtake agreements
- structured hedging products
This would attract larger volumes of institutional capital, lowering financing costs and supporting accelerated capacity growth.
In a downside scenario, regulatory uncertainty or grid constraints limit PPA availability, increasing reliance on merchant exposure. This would raise financing costs and slow project development, particularly for smaller or less experienced developers.
From subsidised projects to financially engineered assets
The transformation of wind financing in South-East Europe reflects a broader shift in the energy sector. Projects are no longer defined primarily by their physical characteristics—capacity, location, wind resource. They are defined by their financial architecture.
PPAs, take-off agreements and capital structures are now as important as turbines and grid connections. The ability to design and execute these structures determines whether projects move forward, how they are financed, and what returns they generate.
For developers, this requires new capabilities in:
- contract structuring
- risk management
- investor relations
For investors, it requires a deeper understanding of:
- market dynamics
- regulatory frameworks
- operational risk
South-East Europe is not unique in this transition, but it is moving through it rapidly. The region’s wind sector is evolving from a subsidy-driven market into a financially engineered ecosystem, where success depends on aligning revenue, risk and capital in an increasingly complex environment.
In that sense, the future of wind in SEE will not be decided solely by how much capacity is built. It will be decided by how effectively that capacity is financed, contracted and integrated into the market.