How to raise capital for a solar project: stop selling panels, sell certainty

Crescent Dunes had permits, a long-term power contract and a $737 million US Department of Energy guarantee. It still failed when mechanical problems stopped it generating and its power contract was terminated. That is the uncomfortable lesson for solar developers: a PPA is not the same as financeability. Lenders need site control, grid clarity, revenue that survives stress, contracts that allocate construction and operating risks, and evidence that debt can still be repaid when assumptions deteriorate.

Crescent Dunes looked, on paper, like the sort of project that had cleared the hard part.

The 110MW US plant had permits. It had a long-term power purchase agreement with NV Energy, the electricity buyer contracted to take its output. It had a $737 million guarantee from the US Department of Energy, the federal agency backing the project’s debt.

Then the plant suffered chronic mechanical failures. NV Energy terminated the PPA in 2019. Crescent Dunes entered Chapter 11 in 2020. The Department of Energy reported that, offline and without its power contract, the project could no longer service its debt.

That sequence should unsettle anyone who thinks solar fundraising begins with a lender list. If permits, contracted revenue and a government-backed loan guarantee were not enough, what is a lender really financing?

Not panels. Not sunshine. Not even a PPA on its own.

It is financing the chance that a project will keep producing cash after the assumptions in the presentation have been tested by reality.

Crescent Dunes shows that permits and contracted revenue cannot neutralise unaddressed performance risk. Photo: n8foo / Wikimedia Commons, CC BY-SA 4.0.

The contract was real. So was the risk.

Most developers know the usual advice: secure land, obtain permits, sign a power contract, then raise debt. It is sensible as far as it goes. But it can create a dangerous impression that each completed document removes a risk.

It does not. It tells the lender where the risk now lives.

At Crescent Dunes, the power contract mattered only while the plant could perform. Once mechanical failures took generation away, the project lost both its revenue and its ability to make debt payments. A lender therefore asks a more practical question than, “Do you have a PPA?” It asks: what happens if construction is late, output is lower than forecast, the grid cannot take the electricity, or an essential contract fails?

This is where most people stop looking. They see a solar asset. The lender sees a chain of promises. If one breaks, it wants to know who pays.

That affects the amount of debt available. More uncertainty means a lender may lend less against the same project, because future cash has to cover a wider range of bad outcomes. It also affects pricing, because higher uncertainty commands a higher return. And it affects covenants, the operating promises built into loan documents, which can require the project to maintain agreed financial and contractual protections.

A risk left unresolved is not merely a red flag. It is a smaller loan, more expensive money, stricter conditions, or no debt at all.

The queue can be more dangerous than the quote

For a solar project, the interconnection process is the route into the electricity grid. It determines whether power can physically reach a buyer, when that can happen and what network upgrades the project must fund.

That makes it a capital decision, not a technical footnote.

Lawrence Berkeley National Laboratory found that completed projects in five non-ISO US territories averaged $194 per kW in interconnection costs during 2018 to 2024. Its separate queue report found that only 13% of capacity entering US queues between 2000 and 2019 had reached operation by the end of 2024. Median request-to-operation time now exceeds four years.

The interesting part is not the average cost. It is what happened to the projects that did not make it. Most withdrew after receiving high upgrade estimates.

Imagine you are sizing a loan against a project expected to start selling power on a certain date. A grid delay pushes that date out. Upgrade costs consume money that was meant for construction or reserves. If the connection cannot carry the expected output, projected revenue falls. Each problem narrows the margin available to repay debt.

A place in a queue is therefore not a grid connection. It is an early-stage claim on a process whose eventual cost and timetable may still move. That distinction matters in who pays when the grid rejects renewable power.

The Federal Energy Regulatory Commission, or FERC, the US body that sets rules for interstate electricity markets and transmission, has made site control part of this discipline. Under its post-Order 2023 framework, projects must show 90% site control when requesting interconnection and 100% when signing the facilities-study agreement. In plain English: before the grid system undertakes its deeper work, the developer must show it controls the place where the project will actually sit.

Zambia proved that a winning bid is only the beginning

Zambia’s Scaling Solar programme was designed to make the early work easier. It offered prepared sites, standard PPAs, government support and available finance from IFC, the lender and World Bank Group institution involved in the programme, alongside EIB and OPIC finance.

Neoen and First Solar bid 6.015 US cents per kWh for 25 years for a 47.5MW project. The project was structured at an estimated $60 million, with 75% debt and 25% equity.

Yet financial close took 28 months, against a 14-month target. Enel’s project took 34 months. Land clearance, soil conditions, incentive interpretation and document changes slowed both.

The lesson is not that standardisation failed. It did the opposite. Government preparation of sites, grid studies and contracts gave the projects a much stronger starting point than an unprepared tender.

But a standard PPA cannot clear a site. It cannot settle a soil problem. It cannot decide how an incentive will be interpreted. The documents reduced uncertainty without abolishing it.

Put Zambia beside Crescent Dunes and a pattern appears that neither story says outright: solar finance is not a checklist where each signed item earns a tick. It is a system. Land, grid, revenue and delivery contracts must work together. The weakest live risk can still determine the whole project’s cost of capital.

When one roof is too small for debt

In the United Arab Emirates, SirajPower, a developer of commercial rooftop and carport solar systems, faced a different problem. Individual installations were too small to attract debt on their own.

In July 2020, APICORP, the lender providing the facility, extended $50 million of long-term non-recourse financing to SirajPower. Non-recourse means repayment comes primarily from the project portfolio’s cash flow and assets rather than the sponsor’s wider balance sheet.

SirajPower had built more than 50MWp of operating history and aggregated contracted customer leases into one portfolio.

SirajPower made distributed solar debt-sized by aggregating contracted leases and operating history. Photo: RDNE Stock project / Pexels, Pexels licence (free commercial use).

That was the move. Not “find a more adventurous bank”. Build a fundable unit.

The portfolio gave the lender a larger body of contracted payments and operating evidence to assess. It changed the question from whether each roof was worth an individual loan to whether the combined portfolio could support one. For developers of distributed solar, this is often the more useful thought: the asset being financed may be the portfolio, not the installation.

The exception that proves the rule

Chile’s Luz del Norte is the useful counterexample. First Solar’s 141MW project sold power at spot prices rather than under a long-term PPA. IFC approved a $60 million loan towards the $366 million project.

No PPA, then. No problem?

Not quite. IFC said that long-tenor debt and a willingness to accept merchant risk were necessary, alongside First Solar’s sponsorship and IFC environmental standards. Merchant risk means exposure to market electricity prices instead of contracted payments.

Luz del Norte illustrates that merchant solar finance requires unusual sponsor strength and specialist risk appetite. Photo: Gobierno de Chile / Wikimedia Commons, CC BY 2.0.

The project was financed because specialised capital was prepared to accept a risk conventional project lenders usually avoid. That does not mean a merchant forecast can replace contracted revenue in an ordinary debt process. It means the source of capital must match the risk left in the project.

The same principle explains ReNew Vyoman in India. ADB, the lender signing the financing, agreed $331 million in November 2025 for an 837MW wind-solar project with 415MWh of batteries. Expected total debt was $477 million. The project was built to provide 300MW of round-the-clock peak power and guaranteed baseload.

It was not simply selling more intermittent generation. It was designed around the buyer’s required product.

What investors are actually pricing

The US Department of Energy Loan Programs Office reviews much more than projected generation. Its underwriting materials cover the power contract and market forecasts, sponsor and lender models under stress, construction and operating counterparties, ownership, permits, real estate, environmental matters, defaults and termination rights. It looks favourably on full-wrap EPC contracts, where one contractor takes broad responsibility for engineering, procurement and construction, and requires an independent owner’s-engineer report.

That is not bureaucracy for its own sake. It is an attempt to find the gap between a project’s expected cash flow and the cash flow a lender can depend on.

Larger financings can add the Equator Principles, a framework used for managing environmental and social risk in project finance. Its official framework applies to project finance with total project costs of at least $10 million and calls for categorisation, environmental and social assessment, independent review, action plans, covenants and monitoring where applicable.

For a founder, this can feel like capital providers are asking the same question in twenty forms. They are. They are testing whether one unresolved issue can turn an apparently healthy project into a debt-service problem.

GI Network's view: The first raise should pay for the next risk-reduction milestone, not disguise a development-stage project as one ready for long-term debt. If the grid cost, site rights or revenue assignment is unresolved, identify it plainly and seek capital able to bear that specific risk.

Build the case before you build the book

For businesses, the practical sequence is unforgiving but clear.

Choose the ownership model first. Under a PPA or lease, a third party owns and operates the system. Under self-ownership, the host needs capital or borrowing capacity. That decision determines who owns the asset, signs the revenue contract and can pledge the project.

Then secure site or roof rights, including access, easements and lender step-in rights. Screen planning, environmental, technical and community constraints. Enter the grid process and model both the expected connection outcome and the ugly version. Contract the strongest realistic revenue route. Complete permits, construction, supply, operating, insurance and decommissioning arrangements.

Only then assemble one data room and one downside model. The model should show what happens to revenue, costs and debt payments if production, construction cost, curtailment or timing worsen. Do not give different versions of the project to different investors.

The Department of Energy’s Credit-Ready Checklist, developed with more than 40 banks, green banks, CDFIs and credit unions, contains roughly 50 checks covering siting, ownership, capital structure, revenues and costs. That is the real fundraising agenda.

For investors, the question is less “is solar attractive?” than “which risk is this return paying me to take?” At development stage, capital may be funding land, grid studies and permits. During construction, it is exposed to completion and performance. Once operating, it is exposed to output, counterparty payments and market conditions.

Experienced investors do not confuse a high headline return with a good risk-adjusted return. They check who owns the asset, whether rights can transfer after default, whether grid costs are known, whether revenue can be assigned, and whether the project survives its downside case. The difference between a metric and a bankable conclusion reaches far beyond solar, as the difference between a metric and a bankable verdict explains.

GI Network would begin by testing the project’s structural weak points before investor outreach: site control, grid path, revenue enforceability, construction protections and the downside model. We would then align the data room and capital structure with the remaining risk, identify whether the project needs development equity, construction debt, portfolio finance or specialist merchant capital, and rehearse the objections an investment committee is likely to raise.

The solar capital chain

Before contacting capital providers, use the Solar Capital Chain. A project can move forward only when each link supports the next:

1. 1.Owner: Is it clear who owns the system, incentives and revenue rights?
2. 2.Place: Are the site, roof, access and transfer rights enforceable?
3. 3.Grid: Are connection cost, upgrades, timing and curtailment exposure understood?
4. 4.Revenue: Can cash flow survive buyer, volume, price and termination stress?
5. 5.Delivery: Do permits and construction, supply and operating contracts put risk with parties able to carry it?
6. 6.Proof: Does one evidence-backed downside model support the requested debt and equity?
7. 7.Match: Is the proposed capital provider being asked to bear the risk it is actually built to bear?

Break one link and the lender notices. Strengthen them in order, and fundraising stops being a search for someone willing to believe in solar. It becomes a case for backing a project that can survive being wrong.