A renewable power purchase agreement (PPA) priced at €70/MWh may appear to give a renewable project a clear revenue hedge. But the headline price alone does not show how much risk the contract removes. PPAs with the same nominal price can generate materially different cash flows because their terms differ.
Delivery profiles shape market exposure
A pay-as-produced PPA generally settles electricity based on the plant’s actual generation. It can reduce substantial market-price risk, but the agreement still needs to specify how it treats curtailment, negative prices, imbalances and volumes that cannot be delivered. These terms affect the project’s exposure even when the agreed price is unchanged.
A baseload PPA creates a different risk profile because the generator may commit to delivering a relatively constant volume regardless of renewable output. If generation falls short of the contracted profile, the producer may need to buy replacement electricity from the market. Price risk has not disappeared; it has taken a different form.
Shaped and fixed-volume agreements add further variations. Floors and caps can offer partial protection while preserving some upside, and contracts may combine merchant pricing with guaranteed minimum revenues. AleaSoft says a PPA’s contribution to project stability depends on its price, contracted volume, delivery profile and duration, as well as the obligations assumed by each party.
Contract provisions determine who bears operating risks
For lenders, the contractual obligations must be translated into their cash-flow consequences. Negative-price provisions are becoming particularly important: a contract may suspend payments if wholesale prices remain negative for a defined period, continue paying the generator, or require the producer to stop generation. Each approach results in a different exposure, even if the headline PPA price is identical.
Curtailment terms are also consequential. If the transmission system operator restricts production, the agreement needs to establish whether the buyer pays for deemed generation and whether compensation applies only to certain types of curtailment. It must also clarify who bears the risk if the plant is technically available but unable to export. These provisions can determine whether a project maintains debt-service capacity during periods of grid stress.
Balancing responsibility is another source of variation. A generator that remains financially responsible for differences between forecast and delivered output may face significant imbalance costs. A contract that assigns this exposure to the buyer or an aggregator has a fundamentally different economic value. Counterparty credit should be assessed separately from the protection provided against electricity-market risks.
Credit terms and contract duration affect financing
A 15-year PPA is useful only if the buyer can continue to meet its obligations. Lenders therefore need to assess guarantees, credit support, termination rights and replacement mechanisms alongside the power price. Termination compensation requires particular scrutiny: if the buyer defaults halfway through the financing period, lenders need to consider whether the protection is sufficient to refinance the project or replace the offtaker.
A weak termination structure can leave a project that was presented as contracted exposed to the merchant market when the original PPA fails. Merchant tail risk creates a different problem: a ten-year PPA financing a project with a 15- or 18-year debt life leaves part of the loan exposed to market prices after the contract expires. Even if the debt matures before the PPA, the asset’s residual value may depend on assumptions about the post-contract period.
PPA bankability should therefore be assessed as a matrix, not a single figure. The key questions are: what volume is protected, during which hours, and against which market risks; who pays for imbalance and who bears curtailment; what happens during negative prices or if the buyer fails; and how much merchant exposure remains? A headline price answers none of these questions.
As Southeast European markets become more volatile and renewable penetration rises, the commercial structure of a PPA will matter as much as the negotiated €/MWh. The strongest contract will not necessarily be the one with the highest quoted price. It will be the one that continues to protect project cash flow when the electricity system behaves differently from the base case.