WIthout a doubt, some of the most dynamic conversations in the clean energy finance space center on how deal terms and structures are evolving to incorporate transferability. The ability to sell, or transfer, clean energy tax credits from a project developer (or its sponsor) to an unaffiliated corporate taxpayer buyer is a new, transformative provision driving rapid evolution in energy project finance.
Crux interviewed the talented team at White & Case for a deep dive into the current state of play for project deal structuring, emerging terms, and the impact of transferability on the project finance market.
Transferability is a powerful tool, opening up a wide range of options for investors and project developers. Engaging experienced advisers, such as Jeff Davis and Hayden Baker with White & Case, is a critical part of successfully navigating these transactions. We’re thankful to them both for lending their time and expertise.
Please note, none of the contents of this blog post should be construed as legal advice.
Crux: What would you say is your top lesson learned from the first year of transferability?
White and Case: Perhaps the biggest take away is just how creative and adaptable our industry is.
The Inflation Reduction Act (IRA) created a whole new option for monetizing federal tax credits. The transferability guidance didn’t land until mid-June. And yet by year end, several distinct financing structures had emerged – ranging from direct transfers, to preferred equity partnerships, to the hybrid t-flips that seem to be the most popular.
Each of those structures is brand new – but, of course, each built upon or tweaked well-established structures like the partnership flip to quickly drive this new market forward.
The market has been aided by the finance and risk folks who embraced and supported these new structures. Lenders broke new ground by underwriting against future transferability – like we have seen in the uncommitted tax equity bridge loans (TEBLs) or lending against future production tax credit (PTC) cash flows, including with section 45X, which is an entirely new credit. Financiers with limited or no tax appetite expanded the market by investing as Class A investors, thereby providing basis step-ups in the case of ITC deals and creating a partnership vehicle to sell credits. And insurance brokers plugged holes where risks could be efficiently allocated to insurers.
One of the most impressive feats is that the industry was papering transferability deals even before the Internal Revenue Service (IRS) issued proposed regulations. And once we received the guidance, the market really took off.
Looking back at how far we’ve come in a year is really impressive, and it’s a testament to the commitment and creativity of many industry participants.
Crux: We know the market is bringing in new players, both on the sides of the investor and the project developer. What are the key factors clean energy project developers need to know about the differences between monetizing tax credits via tax equity or transferability?
W&C: Yes, new entrants have arrived and are continuing to do so. Taking a step back, tax equity has always been the scarcest (and perhaps most expensive) part of the capital stack and, in many ways, limited the ability of smaller developers, more limited pipelines or newer technologies to tap into the tax equity market. Section 6418 was intended to clear that logjam by inviting new sources of capital and thereby increasing the demand for tax credits. All the new and expanded tax credits under the IRA would be pretty useless as an incentive if there weren’t a corresponding demand for that increased supply of credits.
From the developer’s perspective, it’s important to understand that tax equity partnerships typically now include a transferability feature. Similarly, direct transfers can be optimized by using a partnership to achieve the step-up in basis otherwise provided by a tax equity investor. In this sense, tax equity vs. transferability is not so much a binary choice; rather there are features of transfer and partnership that can be combined by the developer when designing their financing structure to achieve the optimal result. And since new entrants are looking to differentiate themselves to grow market-share, developers should be thoughtful about how to use these new features to their advantage.
Now with respect to your question, there two points that are particularly noteworthy:
Crux: Are you seeing examples of “hybrid” partnership deals utilizing transferability emerge yet as a financing tool for new clean energy projects?
W&C: Yes, these hybrid partnerships – increasingly known as t-flips – are really dominating the space.
After the IRA, there was some naïve optimism that transferability would dramatically simplify the transaction structures used to monetize tax credits. But because of the inherent value of third-party investment via a partnership (such as monetizing depreciation and getting a basis step-up) and the benefit of having experienced investors on the front line of diligence and negotiations, for larger projects, tax equity investment through partnerships really has persisted as an investment vehicle. (And some tax equity investors that previously used sale leasebacks or inverted leases are switching over to partnerships to better take advantage of transferability.)
So these hybrid deals are now pretty commonplace. They do have some unique features to account for the fact that a third-party may have paid for the tax credits. For example, in the case of a DG fund with a deficient project, the credit buyer would be entitled to a refund with respect to the Investment Tax Credit (ITC) on the deficient project.
Two interesting observations on these hybrid partnerships:
Crux: Do you have any recommendations for how investors in hybrid tax equity/transferability partnerships should approach these structures?
W&C: At this moment, the terms are somewhat fluid. Provisions that were taken for granted in traditional tax equity partnerships now might be up for negotiation. For example, investors with no tax appetite of their own may want very stringent terms ensuring their ability to sell credits out of the partnership. And new entrants may be willing to accommodate more risk to capture more deal flow and build relationships with leading developers.
Especially for the newer entrants, I think there is value in understanding the history of the renewables industry. The most successful financing relationships in the space have been built over long periods of time by repeat players who see value in the success of these projects and forging mutually beneficial relationships. This is true across procurement, services, equity, debt and tax equity. The industry has had good years and bad. Most developers have lived through both. For newer investors and existing investors designing or demanding new terms, it’s important to realize that you are creating a market. We should all have some sense of responsibility for making enduring, repeatable deals that will make money – but that also will grow the industry over time and help achieve the full potential of these incentives to promote green energy and decarbonize our economy.
Crux: Broadly, how are deal terms evolving to reflect the needs of investors who are entering the market for tax equity today?
W&C: Simplistically, there are really two types of new tax credit investors: (i) Class A investors with no or limited tax appetite and (ii) pure tax credit buyers.
For those Class A investors with no or limited tax capacity of their own, they really need certainty that there will be buyers of the tax credits. This shows up in documentation by having really robust diligence, deliverables, reporting and, ultimately, insurance requirements. We also see this show up in the conditions precedent (CPs) to funding; these investors want pretty stringent conditions around their obligation to fund – including, for example, if they have doubts about the buyer’s ability to buy the credits.
And for the tax credit buyers, those deal terms are actually pretty straight forward – you’re buying or committing to buy a tax credit at a price based on the assurance that comes from certain reps, indemnities and guarantees. PTC deals are simpler, but ITC deals are subject to recapture and other project risk that can make them good candidates for insurance. These buyers really want certainty – they are investing time and effort to reduce their tax liability and want credits with very little, if any, associated risk.
There are two areas where we see some evolution on the part of buyers:
Crux: Have you observed any areas where deal terms are becoming standardized or where deals are able to become more streamlined?
W&C: The basic structure of the t-flip has become largely standardized: tax equity investors have coalesced around a partnership flip structure with the added feature that the investor can cause the partnership to transfer credits. It is easy to take that for granted but it is actually remarkable how quickly the industry rallied around that vehicle for investment. From the developer’s perspective it provides relatively predictable terms and structuring, while allowing for a variety of strategies by the Class A investor for the tax credits – i.e., use, sell or a bit of both.
The basic terms of the tax credit transfer agreement have become quite streamlined. There is not much to the documentation of these sales. The complexity for the buyer really comes in making sure the buyer understands and, if desired, mitigates the associated risk it is taking on – and factors that into the agreed price. One of the chief risks to address is recapture in the case of ITC deals. And from the developer’s perspective as tax credit seller, the real focus is on making sure the tax credit transfer works in the context of the overall financing for the project or portfolio, including with respect to priorities for any indemnity obligations to the tax credit buyer and debt repayment.
Crux: What are some key complexities that credit buyers and sellers should be aware of that you’re finding arise in the process of pursuing a transaction?
W&C: I’ll start by saying there is still a lot of price exploration going on, but the market has definitely tightened. To reach agreement on price, the parties need to agree on the value of the credit.
That sounds simple but, in most cases, the tax credit is really a stack of different layers – the base credit, plus a 5x multiplier for compliance with prevailing wage and apprenticeship, plus any bonus credits (such as for using domestic content or being sited in an energy community).The buyer is essentially purchasing a vertical slice of that stack of credits.
To properly value the credit being purchased, buyer and seller need to align on the certainty (and on the flip side, the risk) associated with each of these different layers.
PWA compliance is particularly important and applies not only during construction but for 5-10 (or in one case 12) years thereafter. Domestic content is hard to obtain and very challenging to diligence, but it should become easier over time. Energy communities sounds simple but even that adder can have an element of complexity.
If the buyer is paying for a layer of the credit, then – as between buyer and seller – seller should wear the corresponding risk of compliance. (In practice, the seller may be able to then lay all or a portion of that risk off to the relevant supplier, contractor or insurer. Where it can’t lay off all the risk, it may be able to use holdbacks or milestone payments to incentivize or reward compliance.)
With a good understanding of the actual credit being purchased and the underlying project, buyers and sellers can more easily reach agreement on price and the appropriate reps, covenants and indemnities around the expected value of PWA compliance and any bonus credits.
Something else that the parties need to keep in mind is that the buyer bears the risk of ITC recapture and the 20% penalty for excessive credit transfers. With respect to ITC recapture, in the case of a direct sale where there is debt that could foreclose, it may make sense to ensure the developer owns the project through an internal 99-1 partnership so a lender could foreclose on the 99% interest and thereby realize the value of most of the collateral without triggering a recapture to the tax credit buyer.
With respect to excessive credit transfers, if a portion of the credit is disallowed by the IRS, the penalty applies only if the amount of credit sold exceeds the amount of credit that is not disallowed. So if a t-flip sells 75% of the credit, and the IRS disallows not more than 25% of the credit, there would not be a penalty for an excessive credit structure. Thus, a buyer has less risk if the seller retains a significant portion of the credit. The buyer also will want to ensure it conducts diligence so it can avail itself of the reasonable cause exception.
Crux: What kinds of deal terms do you recommend that parties reach alignment on early in the deal timeline (e.g., timing of payment, price, target closing date)?
W&C: Price is important, but it is typically a function of terms so it should not be looked at in isolation. Other things to consider or key terms to address up front include the type of project involved and development timeline; the type of tax credit, including any bonus credits and PWA adder expected; the aggregate amount of credits to be transferred (by year if more than one year is involved); the identities of the parties and any guarantors, including the structure of any partnerships (whether as buyer or seller); the identities of any lenders, syndicators, intermediaries or other parties; the length of any exclusivity period, which should be long enough to allow appropriate negotiation, diligence and documentation; any known project development or regulatory uncertainty that may affect the amount or timing of tax credits; whether the seller is providing legal reps or factual reps regarding qualification for the tax credits; whether there will be tax credit insurance; the terms of indemnities and applicable limits on liability; who bears what transaction costs, including with respect to any intermediaries and tax credit insurance; and a termination date for the commitment period.
The other reps and terms are relatively standard (with variation as between a PTC and ITC transfer deal). They should still be spelled out at the term sheet stage, including customary reps and pre- and post-closing covenants, such as matters relating to tax filings, tax audits, remedy for PWA deficiencies, and measures to avoid recapture.
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A tremendous thank you to Jeffrey Davis and Hayden Baker with White & Case for their insights. To get started exploring the market for clean energy tax credits get in touch with us today.
Jeff Davis is a partner in the Tax practice in White & Case's Washington DC office. He advises clients on a wide range of US federal income tax matters, with an emphasis on project finance, development and energy transactions.
Hayden Baker is a partner in the Firm's Global Mergers & Acquisitions practice group, based in the firm's New York office. Hayden assists clients in mergers and acquisitions, energy and infrastructure projects, and financing transactions. He has won recognition from Chambers USA, The Legal 500, Best Lawyers, and New York Super Lawyers. Hayden has extensive experience across a wide range of the power, renewable energy, and energy transition sectors.
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