Renewable project finance in Southeast Europe is moving beyond debt sizing based on a single central revenue case. As the gap between wholesale electricity prices and renewable captured prices grows, lenders increasingly need to assess a distribution of potential revenues.
From generation forecasts to captured prices
Renewable project financing has traditionally translated a relatively small set of assumptions into a debt capacity. Expected generation was multiplied by forecast electricity prices to estimate revenue, operating costs were deducted, and the resulting cash flow determined how much debt a project could service. That framework remains necessary, but it is no longer sufficient.
The analysis needs to follow the chain from production to captured price, curtailment, imbalance and operating costs, cash flow, DSCR and debt capacity. Each step can materially affect the next. The first requirement is to model production by hour, because annual P50 output alone does not show when electricity will be generated. For photovoltaic projects in particular, generation timing determines exposure to periods of system surplus.
A second requirement is a captured-price curve specific to the technology. A baseload forecast should not automatically be treated as the price available to a solar or wind project; hourly production needs to be matched with hourly market prices to estimate the realised price. AleaSoft argues that average market prices are no longer sufficient for photovoltaic valuation and that captured prices, hourly production and curtailment should be included in the assessment.
Availability and curtailment form another layer: production that cannot reach the market cannot be valued in the same way as delivered electricity. Technical availability, grid restrictions, connection conditions and contractual compensation therefore need to be reflected in cash-flow assumptions. Balancing costs also matter, since forecasting errors and profile deviations can impose costs even when the gross electricity price remains attractive.
Contract terms and financing tests
Contractual exposure is a further component. PPAs, CfDs, floors, caps and merchant exposure should be reflected hour by hour where appropriate, rather than represented only by one annual average selling price. Financing ratios should be tested only after these variables have been combined.
AleaSoft draws a distinction between an asset retaining enough cash to make scheduled principal and interest payments and meeting the DSCR thresholds set out in its financing agreements. The difference is particularly important when revenues deteriorate gradually rather than collapsing outright. A project may remain economically viable even as its financial structure becomes inappropriate.
In that situation, possible responses include extending tenor, reshaping amortisation, resizing debt, changing reserve requirements or refinancing, rather than abandoning the asset. Probabilistic modelling should be central to the process. AleaSoft says a single long-term forecast curve cannot capture the range of possible market outcomes and advocates analysing multiple revenue scenarios with associated probabilities.
For lenders, a broader framework would combine P50/P75/P90 generation cases; central and downside captured-price scenarios; curtailment and balancing-cost stresses; PPA counterparty and expiry scenarios; merchant-tail assumptions; interest-rate and refinancing sensitivities; and DSCR and LLCR outcomes.
Consistent downside scenarios and integrated reviews
Correlation matters when constructing those scenarios. A project should not combine pessimistic variables that cannot logically occur together, but adverse variables should not be assumed to be independent either. High renewable output may coincide with depressed captured prices and increased curtailment, producing substantially worse cash flows than separate, small discounts to production and price.
The methodology therefore needs to move away from arbitrary conservatism and towards internally consistent downside scenarios. Technical, market and financial advisers can no longer work in isolated workstreams. The engineer’s production model affects the market consultant’s captured-price calculation, while the grid review affects available volumes; those results feed into the financial model, and the PPA changes how the resulting exposure is allocated.
For Southeast European banks, this changes the nature of renewable lending. It is becoming less like lending against a predictable infrastructure yield and more like lending against an actively managed electricity-market exposure. The most important figure in a credit paper may no longer be the project’s average expected electricity price, but the debt that remains serviceable when several plausible adverse market conditions occur at the same time.