Welcome to 10 Questions with Reunion

At Reunion, we are fortunate to occupy a unique position in the clean energy financing market. Sitting at the confluence of buyers, sellers, and external advisors, we receive questions and observations from every corner of the industry. To share our vantage point, we are launching a video series, 10 Questions with Reunion, in which we will field questions, share emerging insights, and engage with a range of experts.

We hope you'll join us and ask questions of your own. Stay tuned to Reunion's LinkedIn page for further episodes and market analysis. If you have a question for our team, please send it to info@reunioninfra.com.

Episode 01 takeaways

• "Rumored" credit prices from $0.95 to $0.98 are not representative of the broader market. Transactions pricing in the mid- to high-90s are not representative of the broader transferability market. Deals with relatively high pricing reflect non-standard features, like extended payment terms.
• Plain vanilla 2023 spot ITCs with scale are pricing in the $0.90 to $0.92 range net to the developer. Potentially a hair higher or lower.
• ‍2023 spot PTCs are pricing around $0.93 to $0.94 net to the developer. Generally, PTCs present less risk than ITCs, so they trade at less of a discount than ITCs.
• Do not assume the conventional wisdom that credit prices will rise with time. Credit pricing is a function of supply and demand. We see a major increase in available credits in 2024 and beyond. The key question is whether credit demand increases at a similar rate.
• The further in advance a tax credit is purchased, the greater the discount. There is a real price for forward commitments. A 2024 credit purchased in 2023, for instance, will carry a greater discount than a 2023 spot credit.
• Medium- to large-size corporate buyers and sophisticated finance groups have been early market entrants. Among corporate buyers, many had considered tax equity but decided it was too complex. Now, with transferability, they're re-engaging.
• Traditional tax equity has been increasingly harder to access. Supply of traditional tax equity has remained constant, while demand for it has grown rapidly. New demand is originating both from new developers and also new credit types.
• Transferability will play a role in most tax equity deals going forward. Traditional tax equity is dominated by a few large banks, and they have a finite tax equity appetite. Layering transferability onto tax equity deals enables large banks to support more clients and more projects.
• The June transferability guidance suggested that the IRS would further scrutinize step-ups. Looking ahead, we could see a market-wide standard for step-ups around 15% to 20% emerge because of limits set by insurance companies. Already, some large banks have implemented similar caps in tax equity deals.
• Due diligence for transferability should be simpler and more standardized than due diligence for tax equity. Unlike tax equity, buying transferable tax credits is not making an equity investment, which minimizes the scope of due diligence.
• Applying tax credits to quarterly tax payments could result in effective IRRs in the teens or higher. The June guidance allows taxpayers to offset their quarterly tax estimated payments with tax credits that they intend to acquire. If a company is paying $0.92 or $0.93 for a tax credit, their effective IRR could be in the teens or higher.

Video chapters

• 0:00 - Introduction and overview of Reunion
• 0:55 - Question 1: There have been rumors of transactions at 95, 96, or even 98 cents on the dollar. Are these numbers real?
• 2:28 - Question 2: How should we think about pricing a Section 48 investment tax credit (ITC)?
• 4:20 - Question 3: How does pricing compare for a Section 45 production tax credit (PTC)?
• 6:46 - Question 4: How should we think about pricing on forward commitments?
• 8:01 - Question 5: What kind of buyers are approaching the transferability market?
• 9:02 - Question 6: Has it become harder for developers to access traditional tax equity?
• 10:50 - Question 7: How will transferability play a role in tax equity deals?
• 12:46 - Question 8: How are market participants thinking about the IRS potentially scrutinizing basis step-ups?
• 13:59 - Question 9: How will due diligence for transferability compare to due diligence for tax equity?
• 15:43 - Question 10: How do buyers think about the return on investment when buying a tax credit?

Transcript

Introductions

Andy Moon: Good afternoon. My name is Andy Moon. I'm Co-Founder and CEO of Reunion, a marketplace that facilitates the purchase and sale of clean energy tax credits from solar, wind, battery storage, and other projects. We currently have over $2 billion in near-term tax credits from leading clean energy developers on our platform. Reunion works closely with corporate finance teams to identify high-quality projects and ensure a low-risk transaction. Together with my colleagues, Billy Lee and Kevin Haley, we have over 40 years of experience financing clean energy projects. Today, we'll be answering ten of the most common questions we get about tax credit transfers. Let's dive in.

Question 1: There have been rumors of transactions at 95, 96, or even 98 cents on the dollar. Are these numbers real?

Andy Moon: There have been rumors of transactions at 95, 96, or even 98 cents. Some project developers say they are holding out for prices in that ballpark. Billy, are these numbers real?

Billy Lee: Thanks, Andy. To answer it quickly, no, we don't think these transactions are really representative and reflect other non-standard features like extended payment terms. For example, we heard of an outlier where a buyer is acquiring 2023 credits but is not required to pay for them until close to the tax filing date in late 2024. In another example, an institution is selling late-year credits along with an investment-grade corporate guarantee to provide additional wrap.

Kevin Haley: Exactly, Billy. I would say that payment terms are a good example of something that's both very important and, in this early market, a little bit under appreciated in terms of price drivers, especially in a high interest rate environment that we're all dealing with today. A seller obviously wants to get paid as quickly as possible once the project's been completed, but the buyer is incentivized to try to come to some agreement to extend those payments when possible. Over time, I think we'll have to see a normalization around payment terms. The later that the payment is delayed, buyers should expect that it'll come with a penalty on the discount and they'll end up paying a slightly smaller discount.

Question 2: How should we think about pricing a Section 48 investment tax credit (ITC)?

Andy Moon: There's a few different types of credits. Why don't we go one at a time. How should I think about pricing on a Section 48 investment tax credit?

Billy Lee: Sure. Let's assume a plain vanilla deal. What I mean by that is 2023 tax year, a well-capitalized sponsor with deep experience, no tax credit insurance required, no material fair market value (FMV) step-up, a project that has scale – say, $20 million of credits or higher – and proven technology such as solar or battery storage. For these credits, we are seeing pricing net to the developer in the 90 to the 92 cent range. Maybe a hair higher or maybe a hair lower.

Andy Moon: I'll add we are seeing a wider discount in a few different scenarios. One is project size. These early deals require a fixed amount of transaction cost and learning just to get the deal done. I think buyers do want a wider discount to motivate them to take on a small project. Second, there's technologies such as biogas that have a smaller pool of buyers compared to solar or battery storage. These deals do carry a slightly larger discount. I think, similarly, there's new technologies that have tax credits for the first time, such as hydrogen or CCS, and they have less buyer demand. I think we'll have to see where the pricing shakes out. One other point is that projects that have unusual risk or complexity do carry a larger discount. Some examples are very large step-ups in the cost basis, or if a project has large indebtedness, that will also impact buyer demand. One final item I'll mention is that if a tax credit buyer requires insurance on a project, that will result in some additional cost in the 2-3% range, which results in a lower final price to the project developer.

Question 3: How does pricing compare for a Section 45 production tax credit (PTC)?

Andy Moon: Kevin, how does pricing compare on a Section 45 production tax credit?

Kevin Haley: I think for the PTC, particularly for 2023 spot credits, there's less risk than an ITC, and we would expect the discount to be lower, and that's what we're observing in the market today. Risk is lower on the PTC because generally there's no recapture risk, and the PTC credit amount is determined by the amount of electricity generated, which is easy to verify, and then it's multiplied by a fixed price per kilowatt PTC credit amount. We're typically seeing PTCs coming off of wind projects in 2023, trade in the 93 to 94 cent range net to the developer, and we would expect solar PTCs to trade in that similar range. Now, the one area where I think there could be a wider discount on PTCs is for other technologies that have lower buyer demand, like you mentioned, Andy. We're starting to see some of the early 45X and 45Q credits. These do carry a small amount of recapture risk on the 45Q side, and that could translate into a slightly better price for the buyer.

Billy Lee: I would interject here. It may seem obvious to most people, but the price of any commodity, including tax credits, is directly related to supply and demand. And there's a conventional wisdom that's been reiterated many times in a number of articles that pricing for tax credits will increase as the buyers become more active. But it's important to note that this assumes a static supply of credits, which will almost certainly not be true. Remember that there is a development cycle for these projects. Most 2023 credits are from projects that were originally developed pre-IRA, so they weren't assuming transferability. The IRA, by all measures, has supercharged clean energy development, and the vast majority of these credits will start to be generated in 2024 and beyond. We have a unique vantage point in the marketplace, and it is very plausible at this point in time that the supply of credits will continue to outstrip demand, which will almost certainly impact pricing on a macro level. The million dollar question is whether the tax credit buyer demand increases at the same rate as a supply of tax credits.

Question 4: How should we think about pricing on forward commitments?

Andy Moon: Developers are looking for forward commitments. In other words, they want a buyer to commit to buying credits now, even though the project may not be placed in service until 2024 or 2025. The reason, of course, is they want to be able to take that commitment, go to a bank, and get a bridge loan. Billy, can you talk more about pricing in this scenario?

Billy Lee: Sure. There's a real cost to the buyer for agreeing to commit early. Even though the money doesn't change hands until the credit is generated, it's a legally binding obligation. That has a cost. Right now, the supply of buyers willing to commit in advance is limited. Currently, most buyers are still very focused on 2023 spot tax credits. In order to get a bridge loan against a commitment, the buyer must be creditworthy. We expect this requirement to relax over time. We believe that lenders will start underwriting and lending against tax credits without a buyer commitment, but that's in the future – not really right now. So, in general, there will be a further discount on 2024 credits and even a larger discount on 2025 credits. The further in advance a commitment gets, the larger the discount.

Question 5: What kind of buyers are approaching the transferability market?

Andy Moon: Kevin, you've been spending a lot of time with buyers. What buyers are you seeing come to the table?

Kevin Haley: Thanks, Andy. It's been really interesting so far, especially because it's such an early market. We only just got Treasury guidance in June. I would say that our early buyers are typically the medium- to large-sized corporation that pays federal income tax. Our earliest adopters have really been coming out of the more sophisticated finance groups, many of whom have previously looked at tax equity investments into wind or solar. Some of them pursued those; others decided tax equity wasn't for them, and now they're coming back for transferability. But I think this is rapidly changing. We have deals in flight right now with a variety of large corporates in manufacturing, specialty finance, retail, insurance, and healthcare. It's really a diverse range across different sectors.

Andy Moon: I think Treasury guidance on June 14th really gave a lot of confidence to tax directors on how the transfer program would work.

Question 6: Has it become harder for developers to access traditional tax equity?

Andy Moon: Switching gears to tax equity, Billy, you've had a hand in many of the earliest tax equity transactions and have watched the market grow over the last 15-plus years. We keep hearing that the tax equity market has changed a lot in the last six months, and it's actually really hard to get tax equity than it was before. Is this true?

Billy Lee: Yes. This is near universal feedback that we're hearing from developers. Again, it's just reflective of supply and demand. There is a lot more demand for tax equity than there is supply. We're hearing of experienced developers with unique and long-standing tax equity experience saying they're struggling to get tax equity on 100-, 200-megawatt contracted utility-scale projects that previously would have been easy to get a tax equity deal. Tax equity has never been a layup, but the market dynamics really have changed. For example, we've already talked to a large bank that said that their tax equity appetite for 2024 has already been committed.

Kevin Haley: Billy, you touched on this earlier with supply and demand dynamics. There's a lot of new first-time credits coming online – 45Q, 45X, 45Z. There's a nuclear PTC. These are all competing for those same tax equity dollars. The demand for credits has increased significantly since the IRA, but the supply of tax equity capital has not really moved much further north of the $20 billion-a-year historical market size that we've seen in the past, and we don't expect that to change dramatically in the near future.

Question 7: How will transferability play a role in tax equity deals?

Andy Moon: That's a great point. And due to this shortage in tax equity, it's now becoming clear that transferability is going to play a role in many tax equity deals moving forward. Can you describe how this will work?

Billy Lee: Sure. I'll even go so far as to say that we think that transferability will start to play a role in the majority of tax equity deals. And this is based on conversations with many of the banks that are involved in tax equity. For example, a bank's ability to invest is limited by not only their total corporate tax liability, but also the amount that they've allocated internally to renewable energy transactions. One option is for the bank to sell some of the credits from a tax equity investment to a third party, which then frees up more space to serve more clients and more projects. In some ways, we think that there will be more corporate buyers who will be particularly interested in buying credits from a tax equity partnership for two main reasons. One, the tax credit buyers can rely on a bank's significant and detailed underwriting and due diligence. Secondly, and really interestingly, if there's a disallowance or reduction in the value of the tax credits, the IRS will first go after the retained credits before they go after transferred credits. So long as the tax equity partner keeps some credits, that's built-in risk mitigation because it provides a first loss mechanism to a tax credit buyer. That said, everything comes with a price and, in an efficient and perfect market, we would expect credits that are sold out of tax equity partnerships to carry a smaller discount than ones that are sold from a standalone tax credit transfer deal.

Question 8: How are market participants thinking about the IRS potentially scrutinizing basis step-ups?

Andy Moon: Switching gears to step-ups, we've heard some chatter that the IRS may start scrutinizing step-ups and that 50% to 100% basis step-ups are a thing of the past. Billy, what do you think about this?

Billy Lee: One surprise back in the guidance was that lease pass-through structures are not going to be allowed to transfer credits. This was the one structure that explicitly allowed for stepping basis up to fair market value. We read this as a potential sign that there will be more scrutiny from the IRS on step-ups. Large banks like JPMorgan and Bank of America have started limiting step-ups to 15% to 20% as an institutional rule. If we start to see more challenges from the IRS on large step-ups, we think the insurance market may go a similar route. And this could create a market standard that establishes what a maximum step-up percentage should be. So in general, overall, yes, we do think there's increased risk both for transfers as well as traditional tax equity deals that have large basis step-ups. The developers should just be aware of this when planning their projects.

Question 9: How will due diligence for transferability compare to due diligence for tax equity?

Andy Moon: Question for you, Kevin. Is the due diligence process in a transfer deal going to be as cumbersome and difficult as tax equity? What does it look like?

Kevin Haley: I think it's a really interesting question, and we certainly hope that transferability will eliminate some of the complexity and some of the hurdles that tax equity investors had to go through on diligence really for two main reasons. One is that a tax equity deal is just that. It's an equity investment into a project. And with that equity stake, a tax credit investor needs to go to a deep level of diligence to ensure the project will perform as planned. The second reason is that tax equity also involves the structuring of a legal partnership between the seller or the project developer behind the credits and, of course, the tax equity investor themselves. These partnerships are oftentimes quite expensive to set up, running into the million dollar or higher range. They come along with substantial legal and accounting complexities. When we've pitched tax equity to corporations over the years, that's oftentimes been a roadblock to their ability to participate. So, yes, Andy, I would say we want to do our best to not fully replicate the diligence exercise behind tax equity when we think about transfer deals.

Andy Moon: I will add that it is important to note that, especially in the early days, transfer deals do have complexity, and this is where Reunion steps in and actively shepherds deals forward. Our team has to help buyers navigate the project identification and due diligence process, and we really ensure that contracts are properly set up and risk mitigation is in place, such as tax credit insurance.

Question 10: How do buyers think about the return on investment when buying a tax credit?

Andy Moon: Final question for today. How do buyers think about the return on investment when buying a tax credit?

Kevin Haley: I think it's been interesting so far. We've seen a number of motivations and metrics that tend to be case-specific to each buyer. One example, we have some large buyers that really are volume-driven. In the early transactions, they're targeting larger projects, even if they are seeing the slightly narrower discount on those deals. But we have other buyers that are very much yield-focused. For them, they want to take on projects that are maybe a little bit more complex. If that will get them a discount of 10%, maybe a little bit higher, that's a trade that they're willing to make.

Billy Lee: Other investors just really care about time value of money. One important point in the June guidance is that taxpayers can offset their quarterly tax estimated payments with tax credits that they acquire or intend to acquire. That's an important three words there. So even if they are paying 92 or 93 cents for a dollar of tax credit, the effective IRR could be in the teens or potentially much higher, to the extent that they're reducing their estimated tax credits during the year and actually acquiring the tax credits late in the year or even in the following year.

Andy Moon: Thanks, Billy. There you have it, ten questions with the Reunion team. Thank you so much for listening today. We're excited about the level of interest in transferable tax credits and will be posting regular analysis on our LinkedIn page.

Questions of your own?

If you have questions you'd like us to answer, please send us an email at info@reunioninfra.com. We have some great interviews lined up and will look forward to seeing you on the next video episode. Thank you.

Introduction

Andy Moon, Co-Founder and CEO of Reunion, joined Shannon Holzer, Joey Lange, and Matt Donath of Edison Energy for an hour-long panel, "Powering Progress: An Overview of Policy Trends Shaping the North American Renewable Energy Landscape," on August 22, 2023. The panel provided a transferability overview, market update, and several policy insights, and concluded with audience Q&A.

Video recording and slides

We invite you to view the recording and download the panel's presentation.

Transcript of Andy's presentation

Overview of Reunion

Andy Moon: I'll start with a very brief introduction on Reunion. We're a marketplace that facilitates the purchase and sale of tax credits from clean energy projects. We currently have over $2 billion in near-term credits from leading clean energy developers available on our platform. We work closely with corporate finance teams to identify high quality projects and ensure a low-risk transaction. Our company was formed in the wake of the IRA, but our team has spent over 40 years in clean energy finance. We have a lot of experience both in tax equity as well as private finance.

Transferable tax credits will transform the way clean energy projects are financed

Andy Moon: When the Inflation Reduction Act passed, we saw a large opportunity in the transferability clause because financing has always been a major challenge for clean energy product developers. Transferability provides a much simpler and more streamlined structure, and tax credits from many technologies can now be transferred. In addition to solar, wind, and battery storage; now biogas, nuclear, manufacturing, and hydrogen projects can be transferred. There's a whole slew of tax credits that are available to be transferred. Historically, tax credit monetization has been dominated by tax equity, which is controlled by a handful of large banks. So, a major goal of transferability is to broaden the pool of investors that are investing in the energy transition. Any corporation that pays US federal tax can now be an investor in clean energy projects.

Corporations are paying attention to clean energy tax credits, given the volume of tax credits and the length of the program

Andy Moon: There's a lot of momentum that we're feeling right now from CFOs and tax teams from companies because the opportunity is large. The chart is from CohnReznick, which shows that the demand for tax credit monetization will reach $70, $80, or $90 billion annually in just a few years.

Andy Moon: And tax credit supply is hovering around the $20 billion range. There's just really a lot of demand for additional investors to come support clean energy projects. The other item is that, as many people here know, ITCs and other incentive programs have been extended piecemeal on a three- or five-year basis. And the Inflation Reduction Act is a long-term program. At the earliest, it will go to 2034. But many observers believe that because tax credits are uncapped until certain emission targets are reached, this program could last 20 or 30 plus years.

Treasury guidance from June 2023 provided certainty to transact

Andy Moon: As Shannon mentioned – just to highlight how new this market is – Treasury released guidance on June 14th, and that is really unlocked a lot of interest from corporate buyers. I think there was always the fear that potentially guidance would come with some unwelcomes surprises, but that certainly was not the case. Transferability, the mechanism, was explained quite clearly over a 108 pages. I think the biggest win is just having a clear sense of the mechanism by which how tax credits can be transferred. There were also some important economic clarifications to the positive side. So one is that tax credits that are purchased can be used to offset quarterly estimated tax payments, which greatly improves the return profile of the investment. And Treasury also clarified that if you buy a tax credit at a discount, so say you buy one dollar tax credit for 92 cents, that eight-cent discount is not taxable. We can go over any questions about the mechanisms in the Q&A, but just in brief – the way it works is the seller of the credit will be required to pre-register their project on an IRS platform and get a pre-registration number. Both the buyer and the seller need to attach a transfer election form when they file their tax reasons.

Purchasing credits is a simple process that drives tangible benefits

Andy Moon: I'll quickly go through a simple example for how a tax credit transfer will work. So if a corporation has, say, $50 million in tax liabilities, they could purchase tax credits from a clean energy developer or through a platform such as Reunion at a discount. And this discount is typically in the 7% to 10% range, but it really depends on a number of factors. So, assume that they pay $45 million in cash, they would then be able to offset $50 million of their federal tax liabilities. And given that the tax credit can now be used to offset quarterly tax payments, this is a big boon for IRR-driven investors, because that means that the effective IRR will be quite compelling.

Buyers face several manageable risks, which can be mitigated through due diligence, seller indemnity, and insurance

Andy Moon: I'll talk a little bit about the risks to be aware of when investing in a tax credit. In general, buyers do need to conduct due diligence on these projects to mitigate the risk that a tax credit is challenged by the IRS. That said, the diligence checklist is much narrower than a tax equity investment because you are just buying a tax credit. You are not making a true equity investment into the project. There are specific categories of diligence that need to be checked. In some instances, you are ensuring the project was actually constructed and connected to the grid, ensuring that the cost basis of the project is properly calculated in the case of an investment tax credit, and really ensuring that some of the bonus credit adders have properly been incorporated.

Beyond due diligence, sellers generally sign a broad indemnity, promising that if the tax credit is recaptured or reduced for any reason, the buyer will be made whole. However, if the buyer needs assurance that if the IRS successfully challenges the tax credit and the seller does not make good on their indemnity, tax credit and insurance is also available to ensure that the buyer doesn't realize a loss. In the future, we also think that diversification of projects will also be an important mitigator of risk.

Observations on current and future market

Andy Moon: Everybody wants to know about price, so I'll give some general observations on what we're seeing in the market. In 2023, which we're already at the end of August, I'd say buyers are very focused on a narrow set of projects. They tend to look for projects that are from very experienced developers that have financial strength behind them. They look for projects, generally with scale, that have proven technologies such as solar, wind and battery storage. And these are generally trading in a fairly narrow band. We're seeing these 2023 credits trade in the $0.90 to $0.92 range to the developer after all expenses.

Now, of course, there are a number of factors that can further impact the price for 2023 projects. One is product size. So, if the project size is small – say, a $5 to $10 million transaction – we're seeing buyers want a larger discount for those small projects just because this is a new asset class and there's a lot of diligence and new education that's required to do a project. So a lower price is required to motivate buyers to the table. Technology – I think there's a smaller pool of buyers for newer technologies. So, even biogas carries a bit of a larger discount, and it remains to be seen where pricing will settle for new technologies such as hydrogen or carbon capture. And then project risk is another piece. Projects that have items like large step-up in cost basis or that have large debt attached to the project can also carry a larger discount.

Production tax credits that are traded spot. 2023 spot credits trade at a narrower discount because there is not the risk of recapture or reduction in credits because those credits are typically sold after they're generated. For 2024 and beyond, conventional wisdom has been that prices on credits will eventually narrow and the discount will narrow over time. However, we are seeing that there's going to be massive influx of credits in 2024 and beyond. We have many projects such as nuclear, solar, and wind, and all these other credit categories that will be competing for the same tax credit buyers. I think the impact on price in 2024 and beyond really does remain to be seen.

We're seeing a lot of developers that have projects that will be constructed in late 2024 or in 2025 who are looking for a commitment from a buyer today to buy the credits when the project is completed. These forward commitments do generally carry a larger discount. The reason why a developer wants the forward commitment is because they want to be able to take that piece of paper to a bank and get a bridge loan against a forward commitment to buy credits in the future. So, that's another example of where buyers can achieve a larger discount and a higher return is by committing to a forward commitment in advance.

Reunion's digital platform has $2B+ in near-term tax credits from leading clean energy developers

Andy Moon: As I mentioned, Reunion launched our digital platform last month. We already have over $2 billion in near-term credits available for transaction with leading clean energy developers. We work very closely with tax credit buyers to really ensure a low risk and streamlined transaction process. If this sounds of interest, we love to talk and answer questions. We do realize that this is new for many people. And so a lot of our job today is really to answer questions and really make sure that buyers and sellers both understand exactly how the process works and feel comfortable with these transactions.

Over the past six months building Reunion, we have interacted with hundreds of market participants – developers, tax equity providers, lenders, syndicators, accountants, and lawyers. We have been excited to see the discussion evolve from binary debates about transferability versus tax equity, into more nuanced conversations about the future of renewable energy financing. In this piece, we reflect on several themes emerging from our conversations:

• Tax equity will continue to play a valuable role in a post-IRA world
• Tax equity is becoming scarcer on a relative basis
• Most tax equity deals will take on hybrid structures, involving components of tax credit transfer
• The sale of investment tax credits from hybrid tax equity deals should, in theory, command a slight premium
• “Standalone” tax credit transfers can close the tax equity supply gap

Tax equity will play a valuable role in the post-IRA world

Much has been written about the cost, complexity, and constraints of tax equity, so we won’t rehash those issues here. Instead, we’ll explore the three principal benefits of tax equity in the post-IRA market.

Monetization of depreciation

In any tax equity transaction, the sponsor expects to get value from monetization of the investment tax credit (ITC) as well as accelerated depreciation. Generally, however, the vast majority of near-term depreciation is allocated to the tax equity partner, so the sponsor is not able to absorb any material tax losses during the early years of the partnership. This is an important and sometimes under-appreciated point, especially in the context of step ups and phantom income (see below).

Flexibility for changes of control

With tax equity, a developer can divest its interest in a project without a material negative financial impact resulting from ITC recapture, because a developer typically owns only 1% of the project’s profits interest during the five-year ITC recapture period. This is important because many developers are owned by private equity or infrastructure funds, and some sponsors may plan to sell their interest within five years. Tax equity was not designed to create liquidity for project sponsors, but it has become a meaningful mechanism to support such secondary sales.

Step up for fair market value

When a project is sold by a developer to a tax equity partnership prior to mechanical completion, the purchase price is typically determined by a third-party appraiser who values the project above the developer’s cost to build. This step up allows the developer to apply the project’s ITC percentage – 30%, for instance – on a higher cost basis. Without detailing the appropriate sizing and risks of FMV step ups, we’ll simply emphasize their substantial value.

However, market participants often overlook that basis step ups create phantom income. If, for example, a developer builds a project for $100 and sells it to a tax equity partnership for a 30% step up to $130, the $30 of gain is taxable income. While the developer benefits from the additional ITC value generated from that incremental $30 – $9 for a project with 30% ITCs – they (or their partners) will realize a tax burden on that gain. Further, almost no depreciation from the project is available to reduce that burden since it has been allocated to the tax equity partner.

If individual partners in the developer live in high-tax states – California, New Jersey, and New York, for instance – those individuals may realize a marginal tax that exceeds the ITC and depreciation benefit from this step up.

Tax equity is becoming scarcer on a relative basis

In our conversations with developers, we’ve noted a near universal theme: tax equity has gotten materially harder to raise since the passage of the IRA, even for sponsors that have significant tax equity experience with large, contracted projects. The reason is simple – supply and demand.

Static supply of tax equity

The supply of existing tax equity is not expected to rise materially beyond the oft-quoted $18-20 billion of the previous several years. Many of the incumbent tax equity suppliers do not expect to budget major increases in the amount of tax liability allocated to tax equity, and we do not expect the arrival of major new entrants who can move the needle, especially given that transferable tax credits are a far simpler alternative.

Increasing demand for tax equity

The developer community, on the other hand, is generating more tax credits and this pace is accelerating. Projects that had not qualified for tax credits before the IRA – storage, biogas, nuclear, carbon capture, manufacturing, hydrogen, etc. – are now generating tax credits. What’s more, the relative number of credits per project is increasing. A solar project can now reasonably generate ITCs worth 40% or even 50%, as opposed to 22% pre-IRA.

Increasing bifurcation between the tax equity “haves” and “have-nots”

The largest sponsors with the deepest tax equity relationships may find themselves in an advantageous market position over the near-term, with the ability to close transactions with the best terms relative to their competitors. The majority of sponsors, however, will find capital raising process more competitive, challenging, and protracted.  

Most tax equity deals will take on hybrid structures, involving components of tax credit transfer

A tax equity investor’s investment appetite is limited by both its total corporate tax liability as well as the amount that has been allocated internally to renewable energy transactions. In our discussions with tax equity investors, virtually all of them have indicated that they intend to use transferability as a “release valve” to spread their tax liability across existing clients who have more projects and more credits.

Investors will continue to underwrite tax equity deals but may retain only a portion of the credits generated from the project and sell off the remainder. This trend carries implications for sponsors.

The amount of credit that the tax equity investor will be able to sell will emerge as a significant point of negotiation

The value of an ITC that is sold (at a discount to a third party) is going to be less than the value of an ITC that is retained. Either (or both) the sponsor, or the tax equity investor, will need to absorb this economic hit. Given the scarcity of tax equity today, it seems unlikely that tax equity will bear the brunt of the discount of transferred ITCs.

Tax equity will become more complicated and expensive

Finally, expect tax equity to become more complicated and expensive. Introducing tax credit transfers to tax equity deals brings a new layer of complexity and deal documentation. This will increase the tax equity barrier to entry.

ITCs from hybrid tax equity deals – those “release valve” credits – should, in theory, command a slight premium

Large, institutional buyers of tax credits may prefer to buy credits from tax equity partnerships for three reasons:

• They can rely on the underwriting diligence of experienced investors
• Most financing in tax equity transactions is back leverage, meaning a borrower default would not result in a foreclosure, causing tax credit recapture
• In the event of an IRS challenge of eligible basis, the IRS will first assess any disallowance to retained credits before assessing them against credits sold to third parties. Said differently, the tax equity partnership takes the first loss (up to the amount of credits it did not sell) for any credit reduction by the IRS

Assuming the tax equity partnership retains a significant portion of credits, tax credit buyers are in a safer position, particularly where there are aggressive step ups or bonus credit adders.

“Standalone” tax credit transfers can close the tax equity supply gap

Luckily there is also the option for a standalone tax credit transfer, which bypasses tax equity altogether. While much simpler and less cumbersome than tax equity, such transactions are still complex and nuanced, and require careful diligence and risk allocation. In a forthcoming article, we will explore a few common transaction structures relating to standalone tax credit transfers and analyze both the merits and pitfalls of each.

Looking forward

Tax equity has been a major source of financing for clean energy for the past 15 years and will remain an important financing tool for the foreseeable future. Tax credit transfers will increasingly be included as part of tax equity deals due to the shortage of tax equity relative to the number of tax credits being generated. In addition, standalone tax credit transfer deals that bypass tax equity all together with emerge as a new financing option, with applicability across a variety of technologies and developer profiles. Reunion is excited to play a role in the rapidly evolving clean energy finance market, working closely with tax credit buyers, project developers, and other ecosystem participants.

If you’d like to learn more about what we do or collaborate on a project, please reach out to billy@reunioninfra.com.

“Having the guidance out is a huge step forward. Now that we know what the rules are, we can start structuring around them and moving transactions.”

-Andy Moon

Andy Moon, Co-Founder and CEO of Reunion, joined Elizabeth Crouse of Perkins Coie and Tony Grappone of Novogradac & Company for a discussion of the Treasury’s latest Inflation Reduction Act (IRA) transferability guidance, released on June 14, 2023. The panel, with over 40 years of experience in the clean energy tax equity market, explores the “winners and losers,” the “pros and cons” of the guidance. Their verdict: the guidance provides vital clarity to the transferability marketplace – and enables transactions to move forward.

To learn more, please reach out to us at info@reunioninfra.com.

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Top 10 Takeaways

• Corporations will be the primary buyers: Passive activity loss and at-risk rules mean that it will likely be more difficult for individuals and closely held C-corporations to purchase credits.
• Recapture risk to buyer is narrowed: Recapture risk generally sits with the buyer, except when a partner in a project owned by a partnership sells their interest. This opens door to more flexibility in how deals are structured.
• Buyers will need to conduct due diligence: Sellers must provide minimum documentation to buyers, which should prompt standardized due diligence packages and risk mitigation processes. Tax credit insurance will continue to play a role.
• Basis step up will be scrutinized: Basis step up risk, among others, could drive a near-term flight to quality among investment opportunities. Long-term, standardization and diversification will serve as key risk mitigation strategies. Also, several sophisticated developers are electing not to take a step up to avoid a taxable gain.
• Base and bonus credits cannot be separated: Tax credits from one project can be sold to multiple buyers, but only in "cake slices" that include the same proportion of base and bonus tax credits for each buyer.
• Tax credits can be applied to quarterly tax payments: The IRS credit registration portal should open in late 2023, and tax credit buyers can apply credits they “intend to purchase” against quarterly estimated taxes. This reduces pressure for buyers to wait until tax year-end to close transactions.
• Emergence of tax equity "light" structures: Developers are exploring a “tax equity light” structure in which they use a traditional partnership flip structure to monetize depreciation, while also transferring tax credits.
• Growing interest among corporates: Purchasing tax credits for cash – versus entering a traditional tax equity partnership – presents a cleaner, more simplified transaction that has many more corporate buyers interested.
• Forecast on credit pricing: Large projects with proven technologies and strong sponsors are seeing pricing in the low $0.90s for 2023 credits. However, price discovery is just beginning, and we anticipate several factors such as sponsor strength, project size, technology, and duration to impact pricing.

Full Transcript

Introductions

Andy Moon, CEO of Reunion, joins Elizabeth Crouse, a Partner of Perkins Coie, and Tony Grappone, CPA, a Partner of Novogradac & Company.

Elizabeth Crouse (Perkins Coie): Thanks, everyone, for joining us. I am Elizabeth Crouse, partner at Perkins Coie. I've got more than a decade of experience in the renewable energy industry as a tax lawyer, doing all sorts of stuff for all sorts of people in renewable energy when it comes to tax credits. Today I’m joined day by two very eminent guests. I'll turn over to them to introduce themselves. Andy, why don't we get started with you.

Andy Moon (Reunion): Thank you, Elizabeth. My name is Andy Moon, and I'm co-founder and CEO of Reunion. We're a new digital marketplace to facilitate the purchase and sale of transferable tax credits between project developers and corporate buyers. Even though Reunion is a new company, our founding team has been in this renewable energy finance space for many years. We have a combined 40 years of experience and have been involved in developing a lot of innovative tax equity and project finance structures. We're excited to bring the same creativity to the transferable tax credit space. This what we think about all day. Excited to be here.

Elizabeth Crouse (Perkins Coie): Tony?

Tony Grappone (Novogradac): Thanks, Elizabeth. My name is Tony Grappone. I'm a partner with the accounting firm Novogradac and Company. Here at the firm, we work with project finance participants on how to structure renewable energy tax credit investments. Our focus is really on trying to help them maximize the value of the tax credits and related tax benefits while, at the same time, complying with all the various rules and regulations. So, we get active on the front end of a project financing and then once a deal is closed, we make ourselves available for ongoing CPA services, like financial statement audits and tax returns. Happy to be here and thanks for including me.

Treasury released proposed regulations on June 14

Proposed regulations guidance is encouraging, and Treasury is still accepting comments.

Elizabeth Crouse (Perkins Coie): Great. Thanks, both of you, for doing this discussion. We’re here to talk about transfer of tax credits. The goal is to talk more about some of the commercial impacts. Last week, Treasury released some proposed regulations around the transfer of several tax credits. The guidance covers everything from solar and wind, to renewable natural gas and carbon capture and hydrogen, and a whole bunch of other fun stuff. For those of you who are in the know here, you know that these proposed regulations are potentially industry changing. We've all been eagerly looking forward to them and have spent the last week and a half parsing through hundreds of pages of guidance and coming up with some initial and a little bit more baked impressions. That's what we're here to talk about today. We're going to do this as a live discussion. Andy and Tony have obviously been in the industry for a long time. We all have our own views and our own perspectives, and we are glad that you're joining us today to discuss them.

A couple of administrative points. Please put your questions in the Q&A box. We will do our best to address them. No question is silly or stupid. Please, just go ahead and pose them. We're all learning here because these are new rules and, in many ways, they're very different.

With that, why don't we go ahead and kick off? I think one of the first things that we need to talk about here, guys, and one of the things that's most pressing – who are the winners and losers? What are the pros and cons of this guidance? Tony, do you want to kick us off?

The guidance came out on June 14. That seems like a long time ago because we've been spending so much time pouring ourselves into these new rules and regulations.

The guidance came out on June 14 – temporary or proposed regulations. And there's a comment period that's open right now where Treasury will accept comments until August 14. So, as Elizabeth pointed out, feel free to put your questions in the Q&A box. If there's something that you think is worth going back to the IRS and Treasury, feel free to share that as well in the Q&A box. I'd love to gather those.

Our firm, Novogradac, sponsors a renewable energy working group, and the members of that group are made up of different industry stakeholders. So, I would love to get your comments on where you think we should be providing additional or requesting additional clarity from the IRS and Treasury. We've got up until August 14 to submit questions and requests for additional clarity from the IRS.

Who is a good buyer of tax credits?

Passive activity loss and at-risk rules mean that it will likely be more difficult for individuals and closely held C-corporations to purchase credits.

Tony Grappone (Novogradac): What we know so far is, as Elizabeth said, there are some winners and losers here and there's some pros and cons. I think one area of disappointment is around who's a good buyer who can buy these credits. During our planning call, Elizabeth, Andy, and I talked about individuals and closely held C corporations. The IRS clarified that individuals and closely held C's are probably not going to be great buyers of tax credits.

I think last fall, when industry stakeholders first reached out to the IRS and Treasury making certain requests around guidance, a lot of people asked for greater flexibility in terms of how different buyers can participate in this program. And part of that was trying to make it easier for individuals and closely helped C's to participate. The temporary regulations that came out essentially make it very difficult for individuals closely held C’s. Elizabeth, you had some thoughts on that as well, right?

Elizabeth Crouse (Perkins Coie): I revisited this issue last night after a conversation, just to make sure I wasn't crazy. I'm not sure it's much worse than what we expected. We've got these passive activity loss rules that are the bane of existence for a lot of individual investors, and it seems like it's the worst-case scenario under those rules as opposed to anything new and exotic. It's not ideal, but it's not going to be expansive.

Tony Grappone (Novogradac): Great point.

Andy Moon (Reunion): I think a lot of folks in industry were expecting the passive activity loss and at-risk rules to continue. So, I would say it wasn't a huge surprise. But, at the same time, the proposed regulations are still open for comment. So, if this is something our audience feels strongly about, it's worth putting a comment in there, because regulations could improve between now and August 15.

Elizabeth Crouse (Perkins Coie): Absolutely. That's a good point, Andy. We’ve seen the comment letters move the needle. I don't know if they're going to do it this time, but we've seen IRS change its mind in some cases. So, worth commenting on that because there's a lot of potential for individuals to participate here and expand the market.

When you think about one of the pros that I had – Tony, I'm sure you'll probably get to this, too – is the potential here for structuring. I’ve been crossing my fingers the last few months, but I think Treasury created a set of rules that allows us a fair bit of flexibility. Andy, do you agree?

Guidance provides clarity around recapture risk

Recapture risk generally sits with the buyer, except when a partner in a project owned by a partnership sells their interest. This opens door to more flexibility in how deals are structured

Andy Moon (Reunion): For sure. I think a lot of observers have mentioned this as well. One great thing about guidance is that the rules were clear and concise. And, knowing what the rules are, we can now start structuring around them.

One example of a win is the IRS did clarify that recapture risk sits with the buyer, which is something new. I think there was a hope that, perhaps, the recapture risk would sit with the seller of the tax credits, but it's clear that it will sit with the buyer – except in one specific instance, which is if a partnership owns a project, and a partner within the partnership sells their partnership interest more than one third, that typically will trigger a recapture. But that recapture risk sits with the seller in this case rather than the buyer of the tax credit. So, I think that does open some flexibility into how you can structure these arrangements such that you can add leverage and other structures behind that.

Tony Grappone (Novogradac): That's a great point, Andy, around the recapture risk. Because when structuring deals, I think what participants fear the most is when a partner sells greater than a third of their interest during the recapture period. So, with the guidance clarifying that if a partner in the partnership that transferred the credits, if that partner sells more than a third of their interest, it's that partner in the seller partnership that is subject to that recapture, not the buyer. I think that's a real victory here in terms of the guidance. As far as other recapture risks, they're typically perceived as lower risks in the overall transaction structure. An overall victory – I love it.  

We're already getting a lot of questions coming in. This is fantastic.

One other point I want to highlight for folks on the passive issue is one area in the guidance that I thought seemed like an oversight was with respect to applying the passive activity rules. The guidance says that the buyer can only use the credits against income generated from the project.

Elizabeth Crouse (Perkins Coie): I don't know. I might argue with you on that one. I don't read the rules that way.

Tony Grappone (Novogradac): Okay, so what are your thoughts there?

Elizabeth Crouse (Perkins Coie): Yeah, when I went back and looked at it last night, it looked to me more like they were talking about character. Whether or not you could change the passive character or not, I think it's clear you cannot change the passive character.

Basically, the point here is that if you're a transferee of a tax credit, if you just bought the thing, you're going to be bound to treating that tax credit as arising in a situation where the passive activity loss rules could apply if you're subject to them, and you're going to be bound to treating it as passive. That's not great news, but it's what we've been dealing with for 30 years since the passive activity loss rules were created. So, it's a new application of them. But I don't read it as saying you have to look to the income of the asset itself because that wouldn't make any sense. They're very clear that you don't have anything to do with that asset.

Tony Grappone (Novogradac): Sure, I hope you're right. I mean, I know there's a lot of chatter going around.

Elizabeth Crouse (Perkins Coie): There is a lot of chatter going around, and that's reflective of the fact that we're all still percolating on that stuff. We're all still thinking it through.

Andy Moon (Reunion): Yeah, for sure.

Tony Grappone (Novogradac): I know there are a lot of fears that the guidance suggests that you can only use the credit against income generated for the project. So, that's one area of these temporary regulations where they're requesting specific comments on. I think that's an area we're going to want to get further clarification on.

Andy Moon (Reunion): Yeah, for sure.

Elizabeth Crouse (Perkins Coie): We've got a question about this point, too. One of the comments here in the Q&A box – could the IRS get comfortable loosening the rules for individuals in a closely held seasonal limited capacity, like a safe harbor rule? I suppose they could. That's worth commenting on because part of the comment process is to give IRS ideas that feel familiar and that are administrable and are not going to open the door for abuse. So, I think that's actually a pretty good suggestion. What do you guys think?

Tony Grappone (Novogradac): I like that comment. I'll take that back and have that as a consideration when we put together our comment letter.

Elizabeth Crouse (Perkins Coie): Okay.

Andy Moon (Reunion): To pull the conversation up from the individual and the passive side, I'll comment that based on the calls we've been receiving in the past few days, I think the overall reaction to guidance has been largely positive and there's real excitement about transactions moving forward.

I would say that corporate buyers, which appear to be the main buyer group, they're not in the business of taking unnecessary risk. And I think there was always a question hanging over folks' heads that guidance could come out with some surprises. So, I think having the guidance out is a huge step forward because now we know what the rules are and they've been written with enough clarity that, as Elizabeth mentioned, we can start structuring around them and moving transactions.

One thing I'll recap for the audience is, in terms of the actual mechanics of the transaction, the transfer must be made to an unrelated third party for cash. Sellers will have to pre-register the projects with the IRS and get a project registration number. And both the buyer and the seller must attach that project registration number to their tax returns and file a transfer election statement.

Buyer due diligence comes to the fore

Sellers must provide minimum documentation to buyers, which should prompt standardized due diligence packages and risk mitigation processes. Tax credit insurance will continue to play a role.

Andy Moon (Reunion): One other interesting item was that the IRS made a point of saying that the seller must provide minimum documentation to the buyer. The seller must provide proof that the project exists, that they've complied with prevailing wage and apprenticeship requirements, and that they qualify for bonus credits. And if they don't provide this information, then that can negate the sale. I thought that was an interesting point that the IRS put in there to say, "Hey, this is actually important. You need to provide proper documentation to the buyer." It's not just, “Hey, you can just buy this and get 90 cents and be done.”

Elizabeth Crouse (Perkins Coie): On that point, in the reasonable cause exception for the penalty for when the credit is overstated, they say not only do you need due diligence, but you also need due diligence that you are buying the amount of credit that's at least equal to the total credit that's available or it's no more than the total credit that's available. I thought was an interesting point.

And it ties into one of the questions that we have here, which is with recapture risk on the buyer, do you think there'll be a higher discount on the purchase price or some kind of a due diligence price? And this sort of gets at the bigger question here, which is what is the buyer going to have to do? Is it good enough to just get a file of documents from the transferor and call it good? I'd argue it's not. But what do you guys think?

Andy Moon (Reunion): I think the IRS is really they're showing their intent, which is they want buyers to do some diligence and not have this be a passive investment. I think that's an important value-add for some of the intermediaries – to put standardized diligence packages together to be able to show the buyer the steps that have been taken to mitigate their risk. I think it also creates the need for other mechanisms to ensure that the buyer is comfortable, that they are not taking undue risk when making investments in these projects.

We've assumed – and I think all the legal documents that have been drafted for these transactions have assumed – that the seller will have to provide a broad indemnity. So, if there's any recapture or haircut on the credit, the seller must provide an assurance to the buyer that they're on the hook and they'll make the buyer whole. And, obviously, not every seller has a creditworthy balance sheet that can back up that indemnity. So, that's where tax credit insurance will play an important role.

Elizabeth Crouse (Perkins Coie): Yeah, definitely. Recapture, though, is also an issue for the tax credit insurance provider, right? Obviously, there's some risk that the transferee bears. And I think there's a big question about recapture because the transferee's risk is about a disposition of the project or the project operating. They're not going to have a lot of control over that other than through reps and warranties.

So, I think one practical question is, is there a way to get the underwriters comfortable and is that way going to be the same every time? Because, on the one hand, if your counterparty is extremely creditworthy and reputable, do you need that? Do you need something extra? If, on the other hand, you're looking at credits from a small project by a developer that's less well financed, do you need something else to back up that insurance?

Andy Moon (Reunion): Yeah, that's a great question.

Tony Grappone (Novogradac): I think in the short run you're going to see buyers looking to traditional third-party due diligence to back up the credit amounts and the eligibility of the credits. So, just like historical tax equity structures, they look for a tax opinion, an appraisal, and a cost segregation study. I think some of those same traditional third-party deliverables are going to be required by buyers of credits.

The IRS and tax credit buyers remained focused on basis step up

Basis step up risk, among others, could drive a near-term flight to quality among investment opportunities. Long-term, standardization and diversification will serve as key risk mitigation strategies.

Tony Grappone (Novogradac): I meet with a lot of potential tax credit equity investors and can tell you that one of the risks that they worry about the most is around basis step up. You can tell the IRS is also focused on basis step up risk, and they make that clear with the 20% penalty that could be assessed if the IRS concludes there was an excessive tax credit transfer where no reasonable cause can be demonstrated. The IRS is basically saying, “Look, if we determine that an excessive credit was transferred, if the taxpayer can't show that they exercise reasonable cause and doing their diligence on the credit amount, then the buyer will be subject to this.” Again, that's one of the biggest risks that's on the minds of buyers and investors – the basis step up.

You're going to see some sellers who may not be able to provide that balance sheet to back up a sponsor indemnity sufficient for that 20% penalty. As a result, you're going to see the buyer either, one, do plenty of diligence so they can show reasonable cause; and/or, two, consider pricing lower or maybe just buying lower credits because another area of the guidance that I thought was interesting was around disallowance.

I think this is a win for the industry and it's going to make underwriting a lot easier because, even though the IRS is saying you might be subject to this 20% penalty if you can't show reasonable cause, the project can sell a portion of the credits. You don't have to sell all. You could sell a portion and you can retain a piece. So, I wouldn't be surprised if some buyers prefer to enter transactions where they're buying a portion of the credits, not the whole credits, where if the IRS comes in and determines that some of the credits need to be disallowed, that the disallowance is first applied to the retained credits. The IRS made that clear: they will look to the retained credits first. If they thought the credits were too high, they will look to the retained credits first and the purchase credits second. I think that's a huge win.

Andy Moon (Reunion): Certain developers will want to retain some credits because they have profits that they want to shield through retained credits. But for many developers – and many developers don't have any sort of tax appetite – if they haircut the amount of credit they sell by 20%, that's a 20% reduction in the amount of cash in their coffers. For those developers, that's going to be a major problem. So, I think finding ways to make their tax credits attractive to buyers is going to be of paramount importance.

I agree with your point, Tony, that in the early days there will be a flight to quality. A lot of buyers will be looking for sponsors with a long track record and strong financials – sponsors they can trust when they purchase the credits. However, for this industry to move forward, it is important that we don't fall into the same tax equity style of transaction where every single item must be diligenced to death – where there are tax opinions, and many transaction costs involved with making this work.

I want to make two follow-on points. First, in the short term, one thing we're focused on is really trying to push the insurers and the underwriters to ask, “Hey, can we put things in a box and try to look at things in a more standardized fashion so not every single project is separate?” Second, over the long term or medium term, once we have a lot of transactions happening, we think diversification can play an important role. A buyer can buy slices of different projects to mitigate their risk.

Elizabeth Crouse (Perkins Coie): Definitely. And I think that's a meaty question because there is an inherent tension between transaction costs and getting that standardization. Somebody must provide third-party certifications, particularly with the wage and apprenticeship and the domestic content bonuses. Being able to rely on some of those third-party certifications, I think, is going to be helpful and move the market.

It's a pricing point too, though, right? I know it's good news for the industry writ large, but for developers on a micro level, this rule kind of sucks. Because what it means is that people don't want to incur the transaction costs, particularly since it's unclear about how we're supposed to account for the transaction costs in transfer. (Treasury asked for comments on that.) But they don't want to incur those costs. So, the pricing is just going to be hit.

Base tax credits cannot be separated from tax credit adders

Tax credits from one project can be sold to multiple buyers, but only in "cake slices" that include the same proportion of base and bonus tax credits for each buyer.

Elizabeth Crouse (Perkins Coie): This is an acute consideration when credits are a layer cake – where you've got the basic credit, the wage and apprenticeship, a bonus, and another bonus. I can transfer a slice but not the layers. But through that pricing mechanism, I can transfer layers, right? I can spread that risk and force the developer to eat it. And that's going to create a lot of tension for developers who are already a little bit optimistic about transfer but still thinking it through. Do you guys have a reaction to that?

Tony Grappone (Novogradac): I love the point that you brought up. And, to clarify for attendees, you can't sell off just the bonus credits as a layer. The IRS and Treasury clarified that – you can sell a portion of your overall credits, but you can't say, “Oh, I'm just selling my domestic content credits.” I totally agree that, because of the perceived risk around some of the adders, that's bound to show up in the overall pricing.

And to close the loop on the diligence stuff, I totally agree with Andy that, in the short run, there'll be more diligence. But, ultimately, to move this industry forward, we'll have to get to a point where you've got standard operating procedures and templated diligence items. I think we'll get there as confidence builds and standard operating procedures are implemented.

Elizabeth Crouse (Perkins Coie): And this is an opportunity for the industry to do that. It's been in need for a long time.

Tony Grappone (Novogradac): Absolutely. Initially, structuring is going to be super interesting as people weigh their options. Like you guys have both said, sponsors are going to be hemming and hawing a bit. Do they retain credits? If they retain credits, that means they're raising overall less money from outside third parties. Their tendency is to raise as much as they possibly can. So, how do you juggle that – the pricing you're going to get from your buyer? Knowing the risk of providing that indemnity or insurance is going to be interesting in the short run.

Andy Moon (Reunion): Yeah, definitely. Elizabeth, I think you raise a great point about optimism, I think, in the development community on the amount of price that will be delivered for the tax credit. We've also heard developers saying, “Maybe I'll wait to the end of the year because there will be less 2023 projects at the end of the year. Why don't I wait and try to get a better price and maybe buy a penny or two pennies from ninety-one cents to ninety-two cents?” We don’t think that makes sense. If you're a developer and have a 10% cost of capital and wait six months, that's going to cost you $0.05. Does it really make sense to wait six months to maybe get a penny or two benefit? We think there is some sort of price discovery that will have to enter the transaction market. And I think that's coming soon.

Buyers can apply tax credits against quarterly estimated tax liabilities

The IRS registration portal should open in late 2023, and tax credit buyers can apply credits they “intend to purchase” against quarterly estimated taxes. This reduces pressure for buyers to wait until tax year-end to close transactions.

Elizabeth Crouse (Perkins Coie): Definitely. And there's a technical point in here, too, that somebody asked about a little earlier: If a credit is purchased early in the year, how would the quarterly estimated tax liabilities and penalties be addressed? I think that's getting at a really important point in the guidance, which is if you "intend" – very interesting term – “intend” to buy tax credits.

Tony Grappone (Novogradac): I love that.

Elizabeth Crouse (Perkins Coie): You can use those credits against your estimated tax liabilities, although you're exposed to underpayment penalties. But what does "intend" mean here?

Tony Grappone (Novogradac): Oh boy, that was very favorable to the marketplace. The guidance uses the words “intend to purchase.” That suggests you don't even have necessarily a fully enforceable contract in place to buy the credits.

Elizabeth Crouse (Perkins Coie): Yeah. Is my non-binding term sheet enough? That would be amazing and potentially abusive, but amazing.

Tony Grappone (Novogradac): It seems too good to be true.

Andy Moon (Reunion): Even if the IRS portal is not open until the end of the year, “intend” opens things up. It makes it clear that you can start transacting now. If you paper the documents or intend to paper the documents, even though you haven't done the pre-registration through the IRS portal, you can still offset your estimated taxes.

Corporate buyers are motivated by different reasons to purchase tax credits. Some, of course, want to be involved in the clean energy economy. Others want to manage their tax bill. But we have many buyers that are IRR or timing-of-cash driven. And this was a huge question for them: Can I offset my June 15 estimated taxes or not? Or do I have to wait until the end of the year? Because if I must wait till the end of the year, I'm going to wait until much later in the year to do a transaction.

I think this really greases the wheels. If you can offset your estimated quarterly taxes, then there's not as much pressure to wait until the last possible day.

Elizabeth Crouse (Perkins Coie): Absolutely. There's a related point here, too. On my read of the regulations – you all tell me what you think – you still must place in service before you can use that estimated tax provision, which makes a lot of sense to me anyway, as a technician. But I think that's another good thing to point out. It might be too good to be true, but it's not that good to be true.

Tony Grappone (Novogradac): I agree with you.

Basis step up revisited

Pending court cases could change how the industry treats basis step up. In the meantime, several sophisticated developers are electing not to take a step up to avoid a taxable gain.

Elizabeth Crouse (Perkins Coie): We've got several questions going back to this basis step up point that you mentioned earlier, Tony.  Do you want to elaborate on that and catch people up on recent events?

Tony Grappone (Novogradac): Sure. I'll give you an example to illustrate basis step up. A common structure you see in the marketplace is where a sponsor develops and constructs a facility, brings it to mechanical completion, and then sells the mechanically complete facility into what I'll call the "tax partnership” – a partnership flip vehicle. So, you've got a development company ("dev co") that sells a mechanically complete facility into a tax partnership at, let's say, the appraised fair market value. And now let's imagine that fair market value is higher – noticeably higher, in some cases – than the developers cost to build it. In those types of transactions, the tax partnership purchases the mechanically complete facility at fair value. The difference between fair value and the developer’s cost represents this step up. Historically, what we've seen in the marketplace is that step up gets allocated to the assets acquired, which includes the energy property.

Okay, breaking news just the other day – a follow up to the Alta Wind case that involved 1603 grants a long time ago. A lower court essentially said they might consider some or a significant portion of that markup to be treated as an intangible asset and not allocated to energy property. This is hot-off-the-press news. This is fresher than the temporary regs that came out on transferability.

Elizabeth Crouse (Perkins Coie): Yeah, this was released from the 20th.

Tony Grappone (Novogradac): Right. We're all still trying to understand if the lower court’s view represents the collective view of the IRS or the Treasury, or is it just one lower court's view in isolation? It could have significant implications for the industry, and I think buyers, I think transferees, are going to be looking at that lower court view and considering whether how much of the step up is being allocated to energy property and how they're going to factor that into the pricing. Never a dull moment.

Andy Moon (Reunion): It's certainly a big question for the industry; not just transferability, but tax equity as well. We'd love to hear your view, Elizabeth.

Elizabeth Crouse (Perkins Coie): I think it's a complicated question, this whole basis step up. When we're thinking about a basis step up, we're thinking about two things, depreciation and ITC – PTC doesn't matter. So, that's one point in favor of wind – onshore, particularly. It's also a point in favor of solar where the PTC makes some sense independently. And PTCs are going to do better under transfer, potentially, because it should be a lighter lift on diligence, and it should also be an easier structure because of the timing issues. So, if we think about winners and losers, PTCs benefit a lot by recent events.

Now, thinking about the step up and the import of the Alta Wind decision, it's an odd decision, candidly, and reading through it, I completely agree. Treasury is saying that if there's some value in the purchase price of a project that's attributable to 1603 grant and by extension the ITC, then that value needs to be allocated to an intangible and you can't get ITC on intangibles, period, end of story. They don't say what that value is; that was not before the court. The value could still be zero.

The thing from that decision that left me scratching my head about was, can we fix this with the appraisal by relying on the income method? And, candidly, what I've seen in the market recently – I'm interested in knowing what you guys have seen, too – is that, because of cost increases in the supply chain and labor, there isn't nearly as much of a delta between cost to construct and the value based on an income method appraisal these days. So, the court seems to be dancing around the idea of they didn't really decide on this.

I think it's crucial to know that they didn't decide on whether the cost to construct is all you can get the ITC on, which, of course, is at the heart of this long, long saga since 2014. So, today, does that delta matter that much? Maybe not, but in five years, maybe it'll matter a lot again.

Tony Grappone (Novogradac): Great point.

Andy Moon (Reunion): That's a great question. One surprising trend that we've seen among some of the developers we work – we have several sophisticated developers that have sizable projects in general storage – is they have elected not to take a step up. And part of that is because when they do the step up, that's a taxable gain. Surprisingly to us, they've elected to have a clean transaction without triggering that taxable gain. That's one interesting observation that we've seen from the market.

Elizabeth Crouse (Perkins Coie): It's important to note, though, that there's this other case winding its way through the courts called Desert Sunlight, where Treasury is addressing some of the prices that go into cost to construct a little more directly. So, even if we agree that you could use the income method, and we agree that there's not much of a difference, if a court comes out with a ruling that says you must look at cost to construct, you may still have challenges. And that's inherently nerve-racking, frankly. It's causing those of us who represent developers to start poking holes in what our clients are doing to try to get more comfortable when we go to finance. And, conversely, those of us who represent investors are getting more aggressive about questioning some of the numbers.

Emerging interest in “tax equity light” structures that can monetize depreciation

Developers are exploring a “tax equity light” structure in which they use a traditional partnership flip structure to monetize depreciation, while also transferring tax credits.

Tony Grappone (Novogradac): Elizabeth and Andy, coming back to structures – do you think you'll still see, now with transferability, the use of partnership flip structures where the partnership flip sells and transfers the credit? Or do you think we're going to see that go away, and sponsors will try to sell the credits? And, if so, what do you see terms of the pros and cons of doing a partnership flip structure where they sell the credit or just scrapping that structure and just selling off the credit?

Andy Moon (Reunion): We're seeing a lot of interest in a "tax equity light" structure that still can monetize depreciation. So, we have several partners that are interested in doing a flip but selling the tax credits off to maximize the benefit to the sellers of the credits, but also as a way of serve clients. If you're a bank, there's a fundamental shortage – going to market dynamics – of tax equity available. If you can take your tax appetite and make that go further and help your clients, I think that's something that a lot of folks are interested in. So, we envision a lot of these hybrid structures where you have tax equity investors that are transferring part of the credits. But we'd love to hear, Elizabeth, what you're hearing from your clients as well.

Elizabeth Crouse (Perkins Coie): I think that's totally right. I think the transfer rules make that more likely because there are going to be situations where a transfer counterparty refuses to buy 100% of the credits for the reasons we talked about a few minutes ago. That means that that tax equity investor is an alternative first loss support.

Andy Moon (Reunion): Great point.

Elizabeth Crouse (Perkins Coie): One of our questions is getting at this – if the tax equity investor underwrites 30%, can their partner transfer the other 10%? Yeah, you can. Although I think about it the other way, which is I'm going to transfer as much as I can and want my tax equity to support me on the residual, which flies in the face of the traditional tax equity structure! Maybe that's converting the role of the banks and the larger players who have had an active role in tax equity for many years now.

Andy Moon (Reunion): Yes, I think that's right. And that's very exciting. I think that's where there's a lot of room for creativity and new structures. I think some folks initially hoped that with transferability you would have a website where you click, and the purchase happens. But I think there's a lot of interesting structures to be created that will help push this market forward.

Tony Grappone (Novogradac): I think this tax equity light partnership flip structure is going to have real momentum for some of the reasons you just mentioned. One of the things that that structure does, it allows the class B member, the sponsor, the option to monetize their sponsor interest during the recapture period without having a massive recapture event. So, if you're a sponsor that builds this project and you don't use this light flip structure and you sell the credits, you don't get the benefit of any potential step up. Your credit basis is as low as it could possibly be. Same with your depreciable basis. So, you give up some value there, but you also give up the option to really monetize your sponsor interest during the recapture period. So, by entering this light structure, the Class B member, they'd have to recapture the 1% credits or whatever. But that's de minimis; we see that all the time. They have optionality, which is fantastic. And in terms of the light structure, I think you guys were both alluding to this.

Picture this: you've got a traditional 99-1 partnership flip structure where you've got your bank that's normally your tax equity partner coming in as your 99% p-flip partner. And the bank says, “We will contribute equity for a 99% interest,” which represents the ‘retained credits’ – the portion of the credits that are perceived to be the riskiest. And, like you said, this flies in the face of their traditional role of coming in and taking a little more risk. So, the bank says, “We're going to contribute some capital for that portion of the step up basis risk and transfer the rest that is perceived to be the safest.” Now you get the best of both worlds. The sponsor can raise as much money as they possibly can on the front end by raising money from the class A that's coming in – that's the traditional investor; they're selling off the lowest risk portion of the credits. And the class B also retains their option to monetize their cash interest during the recapture periods. I could see that structure getting some real attention.

Elizabeth Crouse (Perkins Coie): Let's point out here, too, the reason why that's so attractive. Without that, if the sponsor held on to all of it, they would be exposed to 100% recapture if they sold their interest. You could fix that with a blocker, a corporation, but that's just economically inefficient. The problem, though, Tony, with your scenario is now who's going to be servicing the market? The same players!

Tony Grappone (Novogradac): Except for the buyer that's coming in to pick up the transfer credits.

Andy Moon (Reunion): We forecast that to be a very large part of this market. All these corporates that previously were not involved can fill the gap that tax equity can't fill. Tax equity is like a $20 billion year market. And the market sizes we're seeing are $50 billion of PTC by end of 2024. And when you add hydrogen and carbon capture and all these other technologies that previously didn't have any tax credits, we're looking at very large numbers.

Corporate buyers are more interested than ever because of “cleaner” tax treatment

Purchasing tax credits for cash – versus entering a traditional tax equity partnership – presents a cleaner, more simplified transaction that has many more corporate buyers interested.

Tony Grappone (Novogradac): I meet with potential corporate investors regularly, and one of the attendees asked a question on accounting treatment. A lot of potential corporate investors like a lot of things about these renewable energy deals. They like the returns, they like the asset, they like the clean energy story. They've gotten hung up on the GAAP accounting treatment, however. The GAAP accounting treatment has kept a lot of would-be investors on the sidelines.

One thing that's so great with transferability is many of those investors who have sitting on the sidelines have called to say, now that transferability is out, and we don't have to be a partner in the partnership and we can purchase the credits, we are really looking forward to finally participating in this program. I think that universe of investors is going to really take off.

Andy Moon (Reunion): I think you're totally right. For all of us that have been in the industry for a while, we've been pitching tax equity to corporates for 15 years. A lot of folks have gotten far down the path and been excited about enabling new clean energy. But, when you get to it, hiring specialized team members to manage the portfolio, chasing down the K-1s and the prep payments – it’s a lot.

I think, Tony, you outlined the biggest issue. The accounting treatment, especially for a publicly traded company, is terrible and hard to explain that to investors. A lot of our initial buyers are sophisticated, and they've looked at tax equity and decided it wasn’t for them. But transferability is much simpler, and they’re interested in making something happen.

Tony Grappone (Novogradac): Right. They're so simple – a lot less friction and complexity to the buyer. So, yes, the IRS has said to the buyers, you're going to have to do some due diligence to make sure that you're not just buying frivolous credits. But when you think of the range of issues that a partner in a partnership normally must address, the to-do's for buyers are much shorter under the transferability program.

Elizabeth Crouse (Perkins Coie): There's a correlated point about restrictions from corporations who purchase energy. This is the VPPA and tax equity interplay. Folks are asking if we’re going to see those same issues if they're a transferee counterparty and an energy buyer. I'm not sure that there's a conclusion on that yet from the accounting perspective. Tony?

Tony Grappone (Novogradac): I don't have a good answer for you. I don't have an answer for you there, good or bad. I think it's still unclear.

Elizabeth Crouse (Perkins Coie): That would be nice, frankly, because it could make things work a little bit better. It does call into question that a lot of the energy buyers want the environmental impact story. And is transfer enough to give you that story? I think that's sort of an open question, too.

Tony Grappone (Novogradac): Okay, so here's my two cent on that. I think it's unknown to a certain degree, but my sense is purchasing credits is not going to qualify for their clean energy reporting.

Andy Moon (Reunion): I think, right now, we have a narrow rubric in terms of what you can use to offset your scope to emissions, and that's very focused on RECs. So, a lot of large corporates who have net zero targets are focused on RECs. And we're seeing it in a few projects where there are developers that are part of the RECs because they know that either tax equity or credit buyers want those environmental attributes. But that's a fraction of the entire market.

I think there's some dialogue on what does REC 2.0 look like or is there a way to give some credit? Because, obviously, this is a gating factor if there's no investor to come in and buy the credits. So, it's an ongoing discussion that several nonprofits and trade associations are looking at.

Elizabeth Crouse (Perkins Coie): One more follow-up point going back to the hybrid flip transfer structure: Do you think the partnership flip to transfer structure will affect the 95-5 allocation structure that we typically use? Do you guys have a view on this? No?

Tony Grappone (Novogradac): You're talking about the flip structure?

Elizabeth Crouse (Perkins Coie): Yeah.

Tony Grappone (Novogradac): Tax credit syndicators are getting lots of phone calls from so many corporate buyers – corporate who have a lot of tax credit needs to put to work. I think what their current MO is, “We have a lot of tax appetite we need to address. In the short run, let’s use tried and true structures like the partnership flip.”

Somebody in the chat box pointed out something that I meant to address earlier, and that is – just to make sure everybody knows – the guidance made it clear you can't use the inverted lease structure and do a transfer. I was scrolling through all these questions, a lot of fantastic questions. I feel like either directly or indirectly, we're addressing most of these questions.

Elizabeth Crouse (Perkins Coie): Lease pass-through is clearly off the table. You can still use sale leasebacks and you can still use partnership flips. So that's important. One thing on the sale leasebacks, though, is that Alta Wind discussion we had earlier – that's a sale leaseback. And so potentially more pressure, particularly on the larger projects, particularly when you don't have an income method appraisal on those sale leasebacks. But sale leasebacks are still relevant. And I think the point here is that you do get a step up in a sale leaseback. We don't usually see those in very large projects. They just don't really work that well. But for smaller developers generating smaller projects, that's something we're thinking about. Subject against the discussion we had about Alta Wind, that sort of ongoing saga.

Another point about structure here in the Q&A box is whether there's a way to tranche the tax credits that could be cheaper that are first impacted by penalties. We talked about this a little bit earlier. Do you guys think that field has been exhausted at this point or are there more options for folks to think about?

Tony Grappone (Novogradac): I'll let Andy take the lead on that.

Andy Moon (Reunion): Sorry, the question was about tranching the credits?

Elizabeth Crouse (Perkins Coie): Yeah, so, that it would be possible to basically provide 1st, 2nd, 3rd loss support concepts.

Andy Moon (Reunion): Yeah, it's a good question. I think the IRS guidance that you can't separate the base and bonus adders – I think a lot of folks are thinking about tranching in relation to domestic content or in relation to energy communities or something specific where, perhaps, that I think the thinking previously was, oh, maybe a tax equity investor doesn't necessarily want to deal with the adders and maybe that's something that could be transferred separately. But it's clear that you can't do that. I think the structure that we talked about previously with the partnership flip is interesting because, as mentioned, the tax equity investor in that scenario the first loss and so there probably is some higher risk that they're taking and, therefore, I think they'll have an impact on their yield.

Elizabeth Crouse (Perkins Coie): On the other side, though, I think there's some other possibilities. On the transferee side, transferees can be in a partnership. And, so, if we can get comfortable with the partnership being a real partnership, then in principle we could allocate at the partnership level.

Andy Moon (Reunion): That's correct. That was an interesting tidbit from guidance – that the buyer can be a partnership. That creates some new potential structures in terms of how you might allocate credits amongst a group of buyers.

Elizabeth Crouse (Perkins Coie): And the allocation is not another transfer. There's a question in the chat box: will there be resale after initial sale of credits? No, you can still only sell them once, but within the code we've got a lot of ways that we can accomplish a transfer of economic interest without transfer. And one of those, of course, is allocating through a partnership which Treasury expressly signed off on in the regulations.

Andy Moon (Reunion): Yeah. I think I'll add that Treasury did make very clear a few things that were previously unclear. One was that buyers can ask for an indemnity from the seller, which I'm not sure that needed clarification, but it was good that they put that in there.

They did say brokers and intermediaries can facilitate transactions but cannot take ownership of the credits in the middle. So, to Elizabeth's point, there can only be one sale of the credit.

I think one other point is that they did clarify that when a buyer purchases a credit for $0.92 on the dollar, that eight cents of gain is not taxable. I think that was sort of the big question in some people's minds. Like, will you have to pay tax on that? And the answer is no.

They also mentioned that there's no limitation on the number of buyers that can buy credits from one facility. So, you can split one wind project into many different buyers. I think that's important for future diversification purposes if you want to be able to give a buyer a portfolio of many projects.

Elizabeth Crouse (Perkins Coie): Definitely. However, they share the risk on that overstatement of the amount of credits that are available. That's one important point to bear in mind. And of course, if we use a partnership, we can spread the risk differently in the partnership agreement unless IRS listens to this and says they don't like that idea. So, guys, we've got about five minutes left. You want to hit the last few questions that we haven't gotten to?

Andy Moon (Reunion): Yeah, I see one here asking if guidance clears a path for buyers to move forward if we're still in a waiting period. Our perspective on that, and I think what some other lawyers have observed, is that absolutely, they've released very clear rules and transactions can move forward. I think there's a lot of interest in moving transactions forward, and they will happen in Q3. I think the way to view it is there's a comment period where we can potentially influence the rules and hopefully make them even better. I think the level of optimism on whether we can change them of open to debate. But we have rules that we can move forward with on transactions.

Tony Grappone (Novogradac): I totally agree. I think you can't pre-register yet until later this year. So, there are still some to-do’s here, but I think for most transactions, they can get a lot closer to closing on buy-sell transactions.

Current tax credit market pricing

Large projects with proven technologies and strong sponsors are seeing pricing in the low $0.90s for 2023 credits. However, price discovery is just beginning, and we anticipate several factors such as sponsor strength, project size, technology, and duration to impact pricing

Elizabeth Crouse (Perkins Coie): What are you guys thinking about pricing right now? There's a question in here about where they'll trade now versus the $91 to $0.92 on the dollar that a lot of people have been talking about recently.

Andy Moon (Reunion): I think for 2023 credits, we're going to continue seeing low 90s with the caveat that I think there's going to be a lot of price discovery in Q3. There's been a lot of transactions moving forward – doing term sheets, getting close to papering – but very few fundings yet. But I think the funding will really pick up in Q3, and that's when we'll see true data points on transactions.

I would say that for what we're seeing from the buyer side, low 90s is still accurate for projects that are proven technologies like solar, wind, battery with proven sponsors that are transacting in 2023. Now, of course, as you get to other credits that are less known or have less demand from buyers that will impact price. I think the creditworthiness of the seller matters as well. And I also think duration matters. So, if you're looking at forward commitments for purchases in 2024, 2025, there's still quite a lot of discovery there that's needed. But those will trade at a discount versus for sure 2023 credits.

Tony Grappone (Novogradac): I think you get PTCs with proven sponsors trading the highest. These sort of emerging technologies with emerging sponsors probably trade the lowest. Small deal, a very small project with an emerging technology and an emerging seller probably goes for the least. And big PTCs with well warranted sponsors probably go trade for the highest.

Elizabeth Crouse (Perkins Coie): Definitely. Some of those less well-known technologies might come up in price as we start to get more guidance. We're obviously still on tenterhooks about hydrogen guidance for GHG emissions, which will impact clean transportation fuels under 45Z when that comes into play. We'd really like some guidance about what qualified biogas property is and we might get it this year, although I'm kind of thinking next year at this point. So that'll help, obviously.

Andy Moon (Reunion): Somebody asked about smaller projects. That's one of the biggest promises and impacts of transferability is that many smaller developers just never could get the attention of tax equity and there's supply-demand issues. So that's going to be a very impactful part of transferability.

Elizabeth Crouse (Perkins Coie): Yeah, I think there are also a couple of other questions in here which I think need to be addressed because they are something that we've been trying to figure out. So, one of them is, can you talk a bit about the credits must be purchased only for cash issue and then what that means in terms of sort of other relationships or what other transactions. I think IRS was unequivocal that you can't restructure another transaction to call some of the consideration tax credits. So, if you've got a PPA, the PPA price needs to be reasonable price, it needs to be paid. And then you can do a tax credit transfer on top of that, but you can't just offset. And I think some of us were hoping that that might be allowed, but it was an irrational hope, in my opinion.

Tony Grappone (Novogradac): Yeah, I think they made it very clear. Don't get cute with how you price the credits and the type of consideration being offered.

Elizabeth Crouse (Perkins Coie): Yeah. And cash is defined in the proposed regulations, but not broadly.

Tony Grappone (Novogradac): And they said if they conclude you didn't pay cash for the credits or the transaction wasn't at fair value, then it's a disallowed transaction. I discourage anybody from trying to get cute on that front.

Elizabeth Crouse (Perkins Coie): Yeah, definitely. Well, with that, we're at the top of the hour, guys. Any parting shots?

Andy Moon (Reunion): I would say thanks so much, everybody, for attending. I love that there were so many great questions. And so please feel free to follow up with myself, with Tony, with Elizabeth, because this is a topic we love discussing and would love to continue discussing with all of you.

Elizabeth Crouse (Perkins Coie): Absolutely. Yeah. Thanks so much for joining us today. Hope everybody has a great Friday and a wonderful weekend.

Tony Grappone (Novogradac): Thanks, everybody. Thanks, guys.

Contact us

Reunion is excited to play a part in accelerating the clean energy transaction. To learn more, please reach out to us at info@reunioninfra.com.