August 29, 2023
13 min read

10 Questions with Reunion, Episode 1: Addressing Common Tax Credit Transferability Questions

In our inaugural episode, our founding team explores the ten most common questions we've received about transferability.

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

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?



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 We have some great interviews lined up and will look forward to seeing you on the next video episode. Thank you.

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