The Basics of Project Finance

Hello everyone,
There’s not a lot of information explaining project finance, especially at a rudimentary level, so I thought I’d write something up.

Project finance is a form of non-recourse financing, meaning essentially all of the collateral sits on the project being constructed rather than the broader sponsor. This is done through the creation of a special purpose vehicle (SPV). Let’s say it’s a solar farm project called Blue Solar. The sponsor may create an SPV called Blue Solar LLC. Since it’s a non-recourse financing, a bank generally cannot go after the assets of the sponsor, only those of Blue Solar LLC and the contracts tied to the project.

Prior to the project, like any other acquisition or development, the sponsor and advisors will determine the optimal mix of debt and equity to fund the project. Unlike companies with actual operating history, many project finance transactions are greenfield projects, meaning they are built 100% from scratch. As a result, there are no historical income statements or cash flows to underwrite. Instead, the revenues banks and sponsors use in evaluating the project are projections derived from contractual agreements, market assumptions, or bottoms-up operating models.

Before construction begins, there may already be some kind of revenue agreement depending on the project type. Energy projects often have power purchase agreements (PPAs) with another party called an offtaker, usually a utility or large tech/industrial firm, where the offtaker agrees to purchase power from the project over a long-term contract. Infrastructure projects may instead have tolling, leasing, concession, or availability-based agreements.

It is worth noting that project financings tend to have revenues that are more predictable than standard businesses since assets like toll roads, airports, or utility-scale solar farms operating under long-term agreements generally have more visible cash flows than a typical corporate business. As a result, debt-to-equity ratios are often more aggressive and debt pricing is generally lower than what you would typically see in standard corporate financings.

Once the optimal debt-to-equity ratio is determined, the actual structuring can occur. Let’s say Blue Solar is a $1 billion solar farm financed with 20% equity and 80% debt.

Two common ways equity can be injected into a project financing are fully upfront or pro rata. Fully upfront is more lender-friendly and, in the case of Blue Solar, the full $200 million of equity would be injected before meaningful debt funding occurs. Under pro rata equity funding, both debt and equity fund the project proportionately as costs occur. For instance, if there are $100 million in project costs incurred, $80 million would be funded with debt and the sponsor would inject $20 million in line with the target capital structure.

In a project finance deal, debt structures are very bespoke and are generally sized around a project’s cash flow available for debt service (CFADS). CFADS is broadly calculated as:

EBITDA – Cash Taxes +/- Change in Working Capital – Maintenance Capex

CFADS is used to calculate the debt service coverage ratio (DSCR), which is calculated as:

CFADS / Debt Service

For instance, if Blue Solar had CFADS of $120 million and debt service of $100 million in Year 1, then the DSCR would be 1.2x in Year 1.

The various tranches of a project finance transaction are then structured and sized around minimum coverage requirements. For instance, let’s say a bank financing Blue Solar is issuing a $200 million construction loan with a minimum DSCR requirement of 1.3x during the operating period. The repayment schedule and total debt sizing would need to be structured such that projected DSCRs do not fall below 1.3x over the amortization period under the lender’s base case assumptions.

DSCRs are also used in the process of “debt sculpting,” where the repayment schedule of each tranche is tailored around the project’s projected cash flows in order to maintain a target minimum DSCR throughout the life of the loan. Unlike a traditional corporate loan with a fixed repayment schedule, project finance debt amortization is often specifically shaped around the expected cash generation profile of the underlying asset.

When structuring a project finance transaction, lenders and sponsors utilize scenario analysis for different revenue and repayment scenarios, but it differs from the standard base/best/worst case framework often used in corporate financings. Instead, project financings frequently use a probabilistic downside analysis, or P-level analysis, in which probabilities are assigned to different operating outcomes.

This analysis is generally presented as P50/P90/P99. A P50 case means there is a 50% probability actual production or cash flow will exceed that level. A P90 case means there is a 90% probability actual production or cash flow will exceed that level, and so on. Higher P-levels therefore represent more conservative operating cases.

In renewable energy projects, these P-levels are typically tied to actual energy generation. For instance, Blue Solar may have:
• P50 energy generation of 500 MWh (megawatt-hours)
• P90 generation of 490 MWh
• P99 generation of 450 MWh

P50 can generally be thought of as the base case, while P99 represents an extreme downside case.

One quick way to assess a project’s operating riskiness is the spread between P50 and P99 generation. A tighter spread implies more predictable generation and lower variability, while a wider spread suggests greater uncertainty in project performance.

Projected generation is then used to determine revenue either through contracted prices under a power purchase agreement (PPA) or through prevailing market electricity prices in merchant exposure scenarios. Renewable deals typically have two types of revenue: contracted revenue and merchant revenue. Contracted revenue comes from agreed energy purchases under a PPA, while merchant revenue is based on prevailing market electricity prices. For example, if Blue Solar has 80% contracted revenue and 20% merchant exposure, then 80% of generation is sold at the fixed PPA price and 20% is sold at market prices.

Infrastructure projects are very similar in their use of P-level analysis; however, rather than being tied to energy generation, the scenarios are typically tied to utilization metrics such as traffic volume, passenger counts, throughput, or usage rates. For instance, in a toll road project, the P50 case may represent expected annual vehicle traffic, while the P90 or P99 cases reflect downside traffic scenarios. These assumptions are then used to project toll revenue and determine the project’s ability to service debt under different operating conditions.

In infrastructure projects, revenue is also typically driven by either explicit contractual frameworks or quasi-contracted demand structures, similar in concept to a power purchase agreement (PPA) in renewables. Instead of PPAs, infrastructure assets often rely on tolling agreements, concession agreements, availability payments, or ticket-based pricing mechanisms depending on the asset class.

For example, a toll road or bridge may operate under a concession agreement where the sponsor is granted the right to operate the asset and collect tolls over a fixed concession period. In some cases, toll rates are regulated or pre-agreed within a contract framework, which reduces pricing risk and makes cash flows more predictable. In other structures, demand risk is fully absorbed by the project company, meaning revenues fluctuate directly with traffic volumes.

Similarly, airports, rail systems, and ports may generate revenue through usage-based charges (tickets, landing fees, container handling fees) and contractual arrangements with governments or anchor users. Some infrastructure assets also use availability-based payment structures, where the government or counterparty pays a fixed fee as long as the asset meets performance or service-level requirements, effectively shifting demand risk away from the project.

Because of these contractual and semi-contracted structures, infrastructure cash flows tend to be more stable than typical corporate operating businesses, which is why lenders are often willing to apply higher leverage and rely heavily on P-level downside cases when sizing debt and structuring amortization profiles.

Finally, once the debt structure is set and cash flows are modeled through the P-level scenarios, the same framework is used to determine equity returns and overall project IRRs.

From the sponsor’s perspective, the key output of the model is not just DSCR compliance, but the equity cash flows after debt service. After CFADS is allocated to debt repayment based on the sculpted amortization schedule, the remaining cash flows are distributed to equity investors. These distributions typically occur after construction is complete and the project reaches operations, though in some structures partial distributions may occur earlier depending on cash sweep mechanics and reserve requirements.

Equity returns are then evaluated using standard IRR and multiple-based metrics. The equity IRR is calculated based on the timing and magnitude of all equity contributions versus all post-debt-service distributions back to equity holders. Because project finance structures are highly levered and cash flows are relatively stable under contracted or semi-contracted frameworks, equity IRRs are highly sensitive to leverage levels and the conservatism of the underlying P-level case used in sizing debt.

In practice, sponsors typically run equity returns across:
• P50 case (base case)
• P90 case (downside case)
• Stress cases (lower prices, higher capex, construction delays)

This allows sponsors to evaluate downside protection and upside leverage effects, while lenders remain focused on ensuring debt service is covered even under conservative scenarios.

In short, project finance is a balancing act between maximizing leverage while maintaining DSCR discipline, and generating acceptable equity returns under conservative operating assumptions.