A power purchase agreement (PPA) offering a renewable project a price of €70/MWh may appear to provide a straightforward hedge against electricity-market volatility. However, the headline price alone reveals little about the level of risk actually transferred by the contract.
Two PPAs with identical nominal prices can generate significantly different cash flows depending on their structure, delivery obligations and allocation of market risks. For renewable developers, investors and lenders across Southeast Europe, understanding these differences is becoming increasingly important as electricity prices become more volatile and captured prices come under pressure.
Under a pay-as-produced PPA, electricity is generally settled according to the renewable plant’s actual generation. This structure can reduce exposure to wholesale-price fluctuations, but its effectiveness depends on how the contract addresses curtailment, negative prices, imbalance costs and electricity that cannot be delivered.
A baseload PPA creates a different risk profile. The generator may be required to deliver a relatively constant volume of electricity regardless of its actual renewable output. When production falls below the contracted obligation, the shortfall may need to be covered through market purchases, potentially at prices significantly above the agreed PPA rate.
In this case, market-price risk has not disappeared; it has shifted from the selling price to the cost of meeting delivery obligations.
Shaped and fixed-volume agreements introduce further variations. Price floors and caps can provide partial protection while preserving some exposure to market upside, while hybrid contracts may combine merchant revenues with guaranteed minimum payments.
AleaSoft Energy Forecasting highlights that the contribution of a PPA to project stability depends on several interconnected factors, including the agreed price, contracted volume, delivery profile, contract duration and obligations assumed by each party.
For lenders, these provisions must be translated into their potential impact on project cash flow and debt-service capacity.
Negative-price clauses are becoming particularly important as renewable generation increasingly coincides with periods of low or surplus electricity supply. One PPA may suspend payments when wholesale prices remain negative for a specified period, while another may continue compensating the generator. A different agreement may require the producer to curtail output under certain market conditions.
Although these contracts may quote the same price per megawatt-hour, their financial outcomes can differ substantially.
Curtailment provisions are equally important. When a transmission system operator restricts generation, the contract must establish whether the buyer compensates the producer for deemed generation, whether compensation applies only to specific types of curtailment, and who bears the risk when a technically available plant cannot export electricity.
The allocation of curtailment risk can directly influence a project’s ability to maintain reliable cash flows during periods of grid congestion.
Balancing responsibility introduces another important distinction. A generator that remains financially responsible for deviations between forecast and actual production may face significant imbalance costs. By contrast, a PPA under which the buyer or an aggregator assumes some or all of this exposure can provide a different level of financial protection.
Counterparty credit risk must be assessed separately from the protection offered against electricity-market volatility. A long-term PPA provides limited security if the buyer cannot fulfil its payment obligations.
Lenders therefore need to examine credit guarantees, collateral arrangements, termination rights and replacement mechanisms alongside the contracted electricity price.
Termination compensation deserves particular attention. If an offtaker defaults before the end of the financing period, the contract should be assessed for the extent to which it protects the project against lost revenues, refinancing difficulties and the cost of securing a replacement buyer.
A weak termination framework can leave a project exposed to merchant-market prices at precisely the point when its original revenue arrangements fail.
Merchant-tail risk creates another potential weakness. If a project has a 10-year PPA but a debt tenor of 15 years or more, part of the financing period may depend on electricity prices available after the contract expires. Even where debt matures before the PPA ends, the asset’s residual value may depend on assumptions about future merchant revenues.
For this reason, PPA bankability should be assessed as a combination of contractual protections and residual market exposure, rather than through a single headline price.
Lenders and investors need to establish which volumes are protected, during which hours the protection applies, which market risks are transferred, who bears imbalance and curtailment costs, how negative-price periods are treated, what happens if the buyer defaults and how much merchant exposure remains after the contract ends.
The headline price answers none of these questions on its own.
As renewable penetration increases across Southeast Europe, the commercial structure of PPAs will become increasingly important to project valuation, financing terms and long-term revenue stability. The distinction between a nominally attractive contract and a genuinely bankable one will depend on how effectively it allocates risks under different market conditions.
The strongest PPA will not necessarily be the one offering the highest price, but the one that best preserves project cash flow when actual market conditions diverge from the original financial model.
