Romania is emerging as Southeast Europe’s strongest example of how long-term revenue stabilisation can accelerate wind investment without removing the need for rigorous project due diligence. Its Contracts for Difference (CfD) programme has reached scale quickly. The first auction awarded 1.5 GW of renewable capacity, including 1 GW of onshore wind.
A second auction, completed in August 2025, awarded a further 2,751 MW of wind and solar capacity. The two rounds together brought awards to 4.2 GW, exceeding the country’s initial 3.5 GW target under its Recovery and Resilience Plan, according to EBRD information.
Revenue protection and auction awards
Romania’s mechanism uses a two-way CfD, giving projects long-term revenue protection around an agreed strike price while keeping them integrated into the electricity market. The arrangement substantially reduces price uncertainty, but it does not make wind generation predictable. Romania’s official CfD register shows the range of prices awarded to onshore wind projects.
For first-round onshore wind contracts shown in the initial register, strike prices range from €54.4898/MWh to €77.325/MWh. Across all CfD contracts signed during 2025, OPCOM reported 2,630.48 MW of onshore wind covered by 41 contracts. Those contracts have strike prices ranging from €54.4898/MWh to €79.50/MWh.
For lenders, price protection can strengthen debt capacity by reducing revenue volatility and the importance of an extended period of weak merchant electricity prices. If other risks are acceptable, the resulting capital structure may support longer tenors or higher leverage than an equivalent fully merchant project. The Vifor project illustrates the financing effect.
Financing benefits and project-level risks
The EBRD participated in additional financing facilities worth €331 million for the wind farm’s 269 MW second phase, bringing its total planned capacity to around 461 MW. A 240 MW portion of the extension secured a CfD in Romania’s first auction, according to the EBRD.
The support mechanism reduces a major uncertainty in a capital-intensive project, allowing banks to focus more closely on risks that can be managed through project design and contractual allocation. It does not remove those risks. Wind resources may underperform, turbine availability may deteriorate, wake losses may exceed assumptions, and construction may be delayed.
Grid outages can reduce delivered volumes, while forecasting and balancing costs remain. A CfD protects the price mechanism; it does not guarantee the volume of eligible MWh a plant will produce. Investors should therefore not treat supported projects as quasi-sovereign bonds, and financing still depends heavily on the technical assumptions behind contracted revenue.
A P90 production case remains relevant even when electricity prices are substantially stabilised. Availability guarantees, the O&M structure, grid connection and curtailment analysis also remain important. Negative-price treatment and settlement rules can affect project economics as well.
Market incentives and regional relevance
European policy has increasingly focused on providing investment certainty through CfDs without encouraging generators to keep producing when the system does not need the electricity. The European Commission says well-designed two-way CfDs can lower financing costs while preserving efficient system operation and limiting unnecessary renewable curtailment, as set out in European Commission material.
These design considerations become more important as renewable penetration rises. A poorly structured support mechanism could shield generators from market signals so fully that they have little incentive to respond to surplus conditions. A better design reduces long-term revenue risk while retaining operational discipline.
Romania’s experience is relevant beyond its borders. Southeast European countries share the challenge of financing renewable projects with large volumes of private capital while merchant power markets can remain too volatile to support efficient long-term debt. CfDs can bridge that gap, but they are a risk-allocation mechanism, not a substitute for bankability analysis.
Projects still need credible resource assessments, turbines must perform, and grids must be able to accept the electricity. Forecasts must be accurate enough to manage market exposure, while O&M arrangements must protect availability over two decades. Romania’s model shows how public policy can reduce the long-term wholesale electricity price risk that private developers have limited ability to control; the remaining risks still sit with the project, which is why the model can work.