10 Questions with Reunion, Episode 5: Tax Credit Investor Default Insurance in IRA Tax Credit Transactions

Introduction

In episode 6, Reunion's CEO, Andy Moon, chats with Craig Smith of Wiley Rein to understand how buyers and sellers of transferable tax credits can borrow lessons-learned from the Davis-Bacon Act when navigating the IRA's prevailing wage requirements. The episode includes Craig's view on the November 2023 §48 ITC guidance, which included key PWA updates.

In Craig's view, it's important for transacting parties to strike the right balance between information and enforcement.

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Guest: Craig Smith, Wiley Rein

Craig Smith is a partner at Washington, DC-based Wiley Rein. Craig has dedicated a significant portion of his practice to the Davis-Bacon Act, which has several key parallels to the prevailing wage and apprenticeship requirements in the Inflation Reduction Act.

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10 Questions with Reunion is now available as a podcast on Spotify and Apple.

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Video

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Chapters

0:00 – Introductions

1:47 – Question 1: What are the PWA requirements for the purposes of IRA tax credits?

2:33 – Question 2: Are there substantive differences between the PWA requirements under the IRA and the Davis-Bacon Act?

3:29 – Question 3: How will the recent major updates to the Davis-Bacon Act – the first in almost 40 years – impact buyers of IRA tax credits?

5:27 – Question 4: What's the process for complying with DOL requirements?

7:46 – Question 5: How does a developer ensure they are using the correct timing of a wage determination?

8:55 – Question 6: How are developers documenting PWA?

10:09 – Question 7: How are buyers mitigating the risk of deviations from PWA requirements? How deep should they go with diligence?

11:42 – Question 8: What should developers keep their eyes on with respect to documenting PWA?

13:09 – Question 9: What is the role of consultants when it comes to documenting PWA compliance?

16:02 – Question 10: Under the Davis-Bacon Act, has it been common for a contractor to require subcontractors to submit certified payroll?

17:04 – Question 11: How does the PWA "cure period" work?

20:54 – Question 12: What is the after-the-fact process for locating and properly compensating a worker who was underpaid?

23:05 – Question 13: Any parting wisdom?

24:08 – Question 14: What has been the role, if any, of insurance when prevailing wages were not paid under the Davis-Bacon Act?

25:45 – Question 15: What should the clean energy market know about the November 2023 PWA guidance?

26:44 – Question 16: What can you tell us about the annual PWA reporting requirement during the recapture period?

27:25 – Question 17: The November Section 48 ITC guidance did not reference to the use of apprentices during the recapture period. Any insights on whether apprentices are a requirement for the alteration and repair period?

28:32 – Question 18: Any closing comments?

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Transcript

Introductions

Andy Moon: Hello and welcome to another episode of 10 Questions with Reunion. My name is Andy Moon, and I'm the co-founder and CEO of Reunion, the leading marketplace for clean energy tax credits. We work closely with corporate finance teams to purchase high quality tax credits from solar, wind, and other clean energy projects.

Today's guest is Craig Smith, a partner at the law firm Wiley Rein in Washington, D.C. Craig has significant experience in prevailing wage issues for federal contractors. 

We are excited to have you on the show, Craig. Can you start by sharing a brief introduction on you and your practice?

Craig Smith: Thanks so much, Andy. Delighted to be here. It feels just like just yesterday I got thrown into the world of federal prevailing wage requirements with the American Recovery and Reinvestment Act of 2009, which many people may remember pumped billions of dollars into the economy through grants and other agreements.

My practice has expanded to other types of prevailing wage requirements, which we're going to talk about today, in both the federal contracting space and other vehicles ever since. 

Andy Moon: This is a hot topic for many clean energy developers. For many of the current projects selling IRA tax credits in 2023, they tend to be exempt from prevailing wage and apprenticeship requirements, otherwise known as PWA, because construction on these projects started prior to January 29th, 2023. But PWA compliance is becoming a big topic for 2024 projects, which requires diligence.

Question 1: What are the PWA requirements for the purposes of IRA tax credits?

Andy Moon: Craig, will you summarize PWA requirements for the purposes of IRA tax credits?

Craig Smith: Sure. I think the key term to keep in mind is “Davis-Bacon Act,” which is what all this is based on. It's a nearly hundred-year-old law that directly imposes requirements to pay certain wages and fringe benefits to the laborers and mechanics – which are general terms – who work on federal construction projects.

That requirement has expanded to all sorts of other projects over the years, but the key points are the same: In a given area, you must pay certain wages and fringes to certain classes of workers over the lifespan of the project.

Question 2: Are there substantive differences between the PWA requirements under the IRA and the Davis-Bacon Act?‍

Andy Moon: Are there substantive differences between the PWA requirements under the IRA and the prevailing Davis-Bacon wage requirements?

Craig Smith: It's a bit like if my son were to come to me and say, “Dad, you don't have to pay me an allowance, but every week you have to give me $5 for not doing anything.”

I've been hearing this argument that you just have to pay wages in accordance with the Davis-Bacon Act – you don't have to comply with the Davis-Bacon Act. For most folks, there's no real trade space between those two.

For a lawyer like me, who's thinking about enforcement and working with companies directly, there are some differences in the administration, record-keeping, and other obligations.

And the implementation has, so far, recognized these differences. By and large, though, if you're  thinking about what you need to make sure that people are getting paid, I don't see too much difference.

Question 3: How will the recent major updates to the Davis-Bacon Act – the first in almost 40 years – impact buyers of IRA tax credits?

Andy Moon: That’s very helpful. On that note, the first substantive updates in almost 40 years to Davis-Bacon and related acts became effective recently. Were there any major changes? If so, how will this impact buyers of IRA tax credits?

Craig Smith: There are two that should draw the [clean energy] market’s attention, both of which will take some time to be more salient and will require attention and diligence.

One is that DOL has reverted to a prior method of calculating the prevailing wage. They have certain methodologies where they ask, “Are most people in an area making a single wage rate?” For the last 40 years, if the answer was no, DOL just took a weighted average.

DOL has reinserted in that methodology a 30% threshold – a big plurality, if you will. Where I think you're going to see that make a difference is in geographic areas where there's a fair amount of union labor, but not a majority. At some point in the next few years – perhaps next year, perhaps in five years – the wage rate for iron workers or electricians pops up to reflect that change. Not a today change or a tomorrow change, but something developers need to account for.

The other change is that the site of the work that's covered – who's in the area where you must pay the wages – is steadily expanding. As modular construction continues to grow, the Department of Labor is focused on getting the same kinds of work covered at these secondary sites of work.  

It's going take a little while to see how these [site] changes play out in practice. If you are – to use an easy expression – delivering the windows for the building, [historically] that's just supply. I think when you start assembling things offsite, it's going to get more complicated and require more attention.

Question 4: What's the process for complying with DOL requirements?

Andy Moon: Let’s go into some practical details. Let’s say you’re a developer and trying to make sure you get the correct labor calculation. How should you think about the geography of work, and what’s the process for ensuring that you're complying with DOL requirements? 

Craig Smith: Geography is the easiest place to start because wages are set first by geographic area under the Davis-Bacon Act. Counties are the most common dividing line. For example, you'll see a given county is in wage determination 12345, along with three or four other counties. (There are some projects that, of course, cover multiple counties or other geographic areas. But let's save that for the 201 interview. For now, you can just think about one county.)

Then you must understand what kind of work is being done, because there are four Davis-Bacon wage determination types. They're fairly self-explanatory – building, highway, residential, and heavy. Of course, at the edges, it can get tricky. But DOL has provided some guidance that solar and wind projects should use heavy.  

When you click through the website where these are published, www.sam.gov, you'd start with heavy. Then, you look at who's going to do the work. DOL has recognized we don't have a labor category for installer of solar panels or fabricators of wind turbines. So, really distilling – do we have electricians? Do we have iron workers? What are the trades involved? From there you go down, and it'll have a wage rate and a fringe benefit rate.

A key factor to bear in mind is fringes can be paid as part of a cash wage. A developer doesn’t have to run out and sign everyone up for a 401(k) and a health plan. Instead, the dollars they’re spending per worker per hour must match up with what's in that wage determination. 

Question 5: How does a developer ensure they are using the correct timing of a wage determination?

Andy Moon: Another common question is the timing of the work. You mentioned that the prevailing wage for ironworkers might increase. How does the developer ensure that they are using the correct timing of the wage determination?

Craig Smith: The lodestar is when construction of the facility begins or the other work where the installation work is being done.There are cases at the edges, but for getting familiar with the concept, a developer should think about when they are going to start swinging hammers or digging shovels.

What's important to realize is you'll be able to go online and see the wage determination today. The challenge, then, is you'll already have the contracts, you might have already bought long-lead items, you already have pricing – the project is going to be well-advanced.  

Therefore, understanding the mechanism to confirm you have the right wage determination and if there are any changes [will be important]. That process exists for a federal construction contractor who, say, gets a contract from the General Services Administration to construct a building. It's a little painful, but everyone knows what it is. Under the IRA, [the process is less defined]. It’ll be important to have a plan if that situation arises. 

Question 6: How are developers documenting PWA?

Andy Moon: How are developers currently documenting this PWA?

Craig Smith: There's a wide range of ways to do it. Let me give you some context from Davis-Bacon, which has been around for a long time.

Some companies do it in a manual way, perhaps in Excel. They have an admin who keys all [the information] in. Some have automated systems. Others rely on payroll and plan to extract the data (although I'd say make sure you can do that before you try it).

As you get further and further down the subcontracting chain – and this is important to realize – some companies are flatly unaware of [the requirements]. A partner of mine and I were on a project some years ago, for example, and we were talking with a third- or fourth-tier subcontractor who had never heard of the Davis-Bacon Act.

This is critical for a taxpayer [who is buying tax credits] to know because they are one step further removed from a prime contractor or general contractor.

Question 7: How are buyers mitigating the risk of deviations from PWA requirements? How deep should they go with diligence?

Andy Moon: Because the taxpayer is the one that's on the hook for deviations from the PWA, how are buyers mitigating risk? Are there situations where they can rely on the representations from the EPC or construction company? How deep does the buyer need to go on the diligence side?

Craig Smith: People get into this business because they have some appetite for taking risks and investing. I think buyers need to think carefully about their appetite for risk and the information available to them.  

A compliance lawyer would say you must have detailed documentation of every hour worked by every person on this project. You must have contact information. You must know what's going on week by week because that's the gold-plated way to make sure you're handling compliance. But, as your investors and buyers probably know, you pay for that.  

So, the question is, what's your risk tolerance? A certification may be effective if it's a company you know is familiar with Davis-Bacon or it's a tax credit seller who's using a contractor you know is sophisticated.

I think it’s the right blend of information and enforcement that's going to work with me where the investment still makes sense.

Question 8: What should developers keep their eyes on with respect to documenting PWA?

Andy Moon: We’ve heard that contemporaneous documentation is one of the key elements in ensuring that documentation is sufficient. What are some other points that you would advise developers to keep an eye on as they are documenting PWA?

Craig Smith: Let me give you a variation of that contemporaneous documentation item, which is you've got to make sure everyone knows that this requirement applies. How would someone who's just there to install solar panels know? So, the first consideration is making sure everybody knows what we're supposed to be doing in terms of wages.

Then, you want to understand how these [construction] companies are tracking payroll. What [information] are they accumulating? Maybe [the developer] is not getting the information on a real-time basis, but they should understand the [payroll] process, so they can go back and reconstruct it.

You don’t want to hear, “We had some electricians who came in and paid their guys in cash, and they've all disappeared to the wind.” You don’t want to end up $5 per hour short on a multimillion-dollar tax credit and be unable to find the workers.

Question 9: What is the role of consultants when it comes to documenting PWA compliance?

Andy Moon: I understand what you say when some developers are tracking this manually with spreadsheets, while others are using their certified payroll. What is the role of consultants when they are involved in ensuring that PWA documentation is happening?

Craig Smith: Let me talk about that certified payroll term for just a second, because that may be new to a lot of folks. Under the Davis-Bacon Act itself (and some of the “related acts” that impose the requirements), every week a contractor and subcontractor who are covered has to prepare what's called a “certified payroll,” which lists out all the Davis-Bacon covered workers, their hours by day, how much they got paid, and someone certifies under the Federal False Statements Act that Davis-Bacon wages and fringes have been paid. You can think of that, again, as a gold standard.

But [certified payroll] is not required under the IRA. That's clear. However, the government will tell you it’s a really good idea.

So, when understanding what kind of information you might get, you might see some companies give you certified payrolls, or maybe they use the certified payroll form. Viewers can see the PDF online by searching WH-347. Some companies are sending PDF after PDF. Other companies have moved ahead in how they handle it.

With that context in mind, consultants can help on a few fronts. They can help you wrangle all the information because you might be learning this on the fly. If it's a more construction-oriented consultant, they can help you assess if the labor categories that a contractor has chosen are realistic. Are these workers, for instance, really journeyman ironworkers?

You could also have consultants who help with automating the process of consolidating unstructured data. They could take whatever [data] they get from the general contractor – who's just going to roll up everything from the subs – and put it into a single, clean report. You could, for enough of these projects, have a consultant who builds a light website that handles this.

There is a range of services out there that someone could build, depending on their familiarity with the Davis-Bacon Act. Perhaps they are just technically proficient and can help you automate a workflow. 

Question 10: Under the Davis-Bacon Act, has it been common for a contractor to require subcontractors to submit certified payroll?

Andy Moon: Going back to certified payroll, has it been common under the Davis-Bacon Act for a contractor to require subcontractors to submit certified payroll?

Craig Smith: It’s a contractual requirement, so there's no getting around it. Think of a reverse cascade: payrolls are supposed to make their way to the contracting or the grant-making agency.

If you have a contractor who is familiar with the federal space, they may be the simplest pathway because they already have a workflow for it. Others might say, “We do [certified payroll] for federal projects, but we are not doing them for your project.”

Certified payroll gives you a frame of reference for the type of information you’ll want to have for in-process monitoring and if there are questions five years later when the IRS comes calling to reconstruct what happened.

Question 11: How does the PWA "cure period" work?

Andy Moon: One item that's been talked about a lot in the context of IRA credits is the cure period. If a taxpayer or a developer is determined that workers were not paid prevailing wage, the tax credit is not automatically repealed. There is a chance for the prevailing wage failure to be cured by paying the worker the difference in wages plus an underpayment rate plus an additional $5,000 for each worker that was underpaid. Can you comment a bit on the cure period and, practically, how would it work?

Craig Smith: My comments are generally about how poorly thought out this is. Let me try, however, to help folks think about how to approach the cure mechanism. I’ll contrast it with a regular Davis-Bacon project where, even with the most compliance-oriented companies, people get underpaid. This is hard. So, I want people to understand that this is going to be really hard because you don't have some of the infrastructure from federal projects.

Typically, under Davis-Bacon, the Department of Labor would determine that, let’s say, some workers were paid wages from an outdated version of a wage determination. You would owe them all $2 an hour more for some number of hours, and you would remit the funds. Then, if you can’t find the workers – and this is also true in the services space – you can pay the money over to DOL, and they will try to find the workers.

So, there are two principal differences for any type of cure. One, the proposed guidance is written as though the [buyer] is paying [the cure]. Although the tax credit investor is technically responsible – I think everyone understands that – they don’t have an employer and/or independent contractor relationship [with the workers].

Some companies, especially if they’re publicly traded, have internal controls. It'd be a nightmare for them to pay the workers because they’re not their employees.

I hope that, as the [PWA] rules get finalized by the Internal Revenue Service, this will get fixed. (The comment period is open). If not, taxpayers may need to think about how they’re potentially going to be paying people.  

The second principal difference is the mechanism for paying workers you can't find. It's one thing in the middle of a project to realize there's been a mistake, and you're able to arrange for a back payment. It’s another thing when the project is over – perhaps there's a challenge to the tax credit years later. In this case, you’re trying to find the workers.

So far, all the IRS has said is in their proposed rulemaking is, “Look to state law for how you would pay these people.” I find that deeply unsatisfying, and I hope that gets resolved by the time anyone has these issues.  

The good news, as you mentioned, is we're just now starting to see projects come online that are subject to these requirements. It's going to be some time before we're trying to do after-the-fact fixes.

Right now, projects should have mechanisms in place for validating in-process compliance. They should be able to handle shortfalls in the ordinary course of back pay, whether it's on a paycheck or a special payment. It's going to be a lot easier to catch these [shortfalls] in the moment. 

Question 12: What is the after-the-fact process for locating and properly compensating a worker who was underpaid?

Andy Moon: If there was an underpayment on prevailing wage, I assume the first course of action would be for the developer to make the buyer whole because the developer has a fulsome indemnity. The developer would have a strong incentive to play a role in curing the underpayment of wages.

If that is not able to happen, I thought you had mentioned that the penalty can be paid to the DOL, which will make their best effort to locate the folks who were underpaid. Can you talk through those mechanics? 

Craig Smith: That's how we work in the ordinary course of a Davis-Bacon project. [With the IRA], we don't have that mechanism. Instead, let's say I'm a developer or an investor, I have an uncooperative general contractor, and I don’t have legal recourse. In this case, it’s important to know where the project is located and to engage local counsel who’s familiar with construction projects in that jurisdiction.

This won't be the first time that workers are discovered to be owed money after the fact [in that jurisdiction]. So, for the time being, the best advice we have is look to state law, just like the proposed rules from the IRS say to do. It's not a satisfying solution, but it's the best one that we have. 

The other point to consider is that, although they’re on opposite sides of the bargain, the developer (the seller of the credits) and the buyer have aligned interests. They both want to ensure everyone’s getting paid the correct rate. As you move further from that core transaction under the IRA, however, people have other things to do in life. So, you ultimately need to make sure that everyone is rowing in the same direction.

Question 13: Any parting wisdom?

Andy Moon: Craig, you've been in this space for along time. Is there anything that I could have asked or anything that we missed in this discussion today about prevailing wage?

Craig Smith: I want to reemphasize that companies who spend a lot of money to get this right still run into difficulties. So, [developers should] want to understand PWA requirements from a practical perspective.  

Before they start trying to quantify the risk and model it out, they should think about the right balance of information and enforcement. Some companies might look at this and determine they prefer a strong [with] liquidated damages. Others may want to be more proactive based on their comfort and understanding. But if you just look at this as, “Make sure people get paid the right wages and fringes,” that should take care of itself.  

I have a career in this field for a reason. It's because it's hard to do, even for those who work hard to get it right.

Question 14: What has been the role, if any, of insurance when prevailing wages were not paid under the Davis-Bacon Act?

Andy Moon: That's good feedback, Craig. I'd like to bring up a final item. Tax credit insurance is one area that buyers are using to mitigate risk on these projects. And tax credit insurance does cover qualification of the credit, which would include verification of prevailing wage and apprenticeship requirements.  

How have you seen this play out in Davis-Bacon projects where it’s been determined that prevailing wage was not paid. Has there been insurance available and, if so, how has it mechanically worked?

Craig Smith: It's a too early to see how it's playing out because we're less than a year in. I think this is a question for this time next year when we’ll see how [insurance] is getting bought and sold and if we’re running into these kinds of issues.

If nothing else, we'll have had our first tax filing season, and you can pay someone prevailing wages right away if there's a shortfall. The $5,000 or greater penalty wouldn't be due until tax day, so there is a time lag before we start seeing what's the reality on the ground. 

Andy Moon: Thanks so much, Craig, for coming on the show today. It's great to learn from your experience of working on federal contracting issues and certainly hope to work with you in the future.

Craig Smith: Thanks so much, Andy. This was a blast. Really appreciate it.

Question 15: What should the clean energy market know about the November 2023 PWA guidance?

Andy Moon: Hi, Craig. Happy new year – great to see you again.

Craig Smith: Great to be back.

Andy Moon: The IRS issued an update to Section 48 ITC guidance in November 2023, and it included some updates to the prevailing wage and apprenticeship guidance. We would love for you to give an overview to our audience on what they should know about the PWA.

Craig Smith: When we recorded questions 1 through 14, I said there were a lot of PWA pieces and processes that still had to be defined. Without going into too much granularity, the latest guidance brought some of those pieces together – in particular, around reporting and record-keeping.

There are some pieces, however, that may take more time. For example, we don't know how, in practice, the IRS is going to handle the returns that will include these tax credits. How the IRS will handle disputes is also an open question.

But it still felt like things are starting to come together.

Question 16: What can you tell us about the annual PWA reporting requirement during the recapture period?

Andy Moon: Is there anything in particular that buyers and sellers should be aware of? For example, there was a specific requirement for an annual PWA compliance report to the IRS. What does that look like?

Craig Smith: It's similar to an aggregated report of wages. Perhaps not surprisingly, the November update drew a parallel between the reporting requirements during the construction phase with the reporting requirements during the alteration and repair phase – that is, the recapture period – of a qualifying facility.

Question 17: The November Section 48 ITC guidance did not reference to the use of apprentices during the recapture period. Any insights on whether apprentices are a requirement for the alteration and repair period?

Andy Moon: On the topic of the five-year recapture period, the November guidance did not have any references to the use of apprentices during this period. Any insights on whether apprentices are a requirement for the alteration and repair period on 48 ITCs?

Craig Smith: One of the things that I do as a lawyer is go back to the start with the source text. And I'd say that is an area that isn't as crisply written in the IRA as some of the others when it comes to prevailing wage and apprentices.

For companies that are looking to be in this market, they should be focused on a final answer from the iRS in the Federal Register. And then any challenges to that, one way or the other, will take time to play out.

I think the most important thing to say is, "If we want to be risk averse, we should probably plan for apprentices." If that's not the direction you're going in, then you should have a plan ready if apprentices are part of the ultimate outcome. Within that plan, allocating risks and responsibilities will be an important discussion point.

Question 18: Any closing comments?

Andy Moon: Anything I haven't asked that I should have?

Craig Smith: I think it's important to pay attention to the Department of Labor, which recently published substantially updated Davis-Bacon rules. The market should follow these in-the-field developments.

Said differently, we don't want to over-focus on the IRS. We should keep an eye on Davis-Bacon rules and keep in mind that that there are changes afoot, even if they might feel like they're not quite as forefront as record-keeping or reporting.

Andy Moon: Thanks so much, Craig.

Craig Smith: Thanks for welcoming me back, Andy.

Introduction

In Episode 3, our CEO, Andy Moon, gleans expert insights and unique market observations from Hilary Lefko, a partner at Norton Rose Fulbright. According to Hilary, "It's amazing how much the market has grown since the regulations came out in June."

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Takeaways

Transferability market activity has experienced incredible growth since regulations came out in June

• First movers were traditional tax equity investors purchasing credits. Now, we are seeing tax credit transfers across various sizes and technologies
• Every traditional tax equity deal that Hilary is working on has a transferability component

The bridge lending market is rapidly developing. Transfer deals with committed buyers are seeing advance rates similar to traditional tax equity bridge loans in the mid-90s

• If there's no tax credit purchasers signed up, we're seeing much lower advance rates – 75% and below

Technology and tax year is driving pricing, with higher pricing for 2023 tax year and established technologies

• 2023 tax credits are being priced much higher than later years
• Wind, solar, and storage are trading a little bit higher than technologies like biogas, where people are less familiar with the risks. PTCs are trading a little bit higher than ITCs

Key negotiation points include audit rights and scope of diligence

• Negotiations around audit are ending up similar to where tax equity is. Generally, each party controls an audit at their own level, meaning an audit of the tax credit buyer will be controlled by the buyer. If the seller has an indemnity obligation, they'll likely have notice, participation, and maybe consent over an audit that's going to result in an actual indemnity obligation
• Surprisingly, some developers are trying to limit the amount of due diligence buyers can do. They tends to be smaller developers who have insurance in place and don’t see the need for additional diligence; this will likely result in a lower price for the seller
• Limit of liability is also a negotiation point (e.g., is indemnity sized at the full tax credit amount, or the discounted amount that the buyer paid). Market is gravitating towards the purchase price of the credits plus some amount such as 20%. Important to remember that it’s rare to have a wholesale disallowance of credits

Basis step-ups continue to be important to developers, and structures are emerging to enable step-ups

• “Cash equity” structures with third party investors are emerging to help developers take advantage of step-ups. The third party investor must take true risk on their investment in order for the transaction to be respected by the IRS; however, this structure is markedly simpler than tax equity
• Not seeing many step-ups above the 20% range; traditional tax equity is capping the basis step-ups at 15% to maybe 20%. Some newer entrants with less sophisticated tax counsel are trying to go higher, though insurance will play an important role (and insurance markets may or may not be willing to insure larger step-ups)

Structures are also emerging to mitigate risk to buyers from recapture

• An internal partnership can be structured to own a project company, with one partner pledging their interest to the lender to mimic the collateral structure in back-leveraged tax equity. This can mitigate recapture risk for the buyer

Credit adders have varying levels of maturity. Energy community is the most common

• Energy community deals are appearing frequently. Projects that qualify on statistical area or on a closed coal fire and generating plant or closed mine are straightforward. Brownfield sites, which are more challenging to diligence, are beginning to emerge
• LMI bonus should appear soon. The application portal for the LMI bonus credit, which is allocated by the IRS, opened in late October
• For now, use of the domestic content bonus is limited. The market is waiting on further guidance and manufacturers are reluctant to disclose costs. Hilary has seen domestic content on two solar deals

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Chapters

• 0:00 - Introductions
• 0:59 - Question 1: What sort of transferable tax credit deals are you seeing? What have been the smallest and largest transactions you’ve worked on?
• 2:14 - Question 2: What interesting structures are emerging with transferability?
• 3:12 - Question 3: What terms are you seeing on bridge loans?
• 4:17 - Question 4: How does tax credit pricing differ between standalone deals and hybrid tax equity deals?
• 5:28 - Question 5: When negotiating tax credit transfer agreements between buyers and sellers, what negotiating point has surprised you the most?
• 6:30 - Question 6: What type of sellers have the leverage to limit a buyer’s diligence?
• 7:24 - Question 7: What specific limits are sellers putting on due diligence?
• 9:34 - Question 8: What are you seeing with respect to audit rights during transfer negotiations?
• 10:44 - Question 9: What is the 50th percentile in terms of negotiating audit rates?
• 11:33 - Question 10: Are you seeing structures emerge for developers to take advantage of a basis step-up?
• 13:20 - Question 11: What level of ownership is required to make buyers comfortable that it's a true third-party owner?
• 14:58 - Question 12: Are you still seeing tax credit transfers with step-ups above 20% to 30%?
• 15:38 - Question 13: Are you seeing any structures emerge to mitigate risks to the buyers?
• 16:50 - Question 14: What types of limits of liability are you seeing in tax credit transfer agreements?
• 19:06 - Question 15: Are you seeing buyers get comfortable with sellers not providing a guarantee when there's insurance?
• 21:09 - Question 16: Are you seeing deals with the energy community and domestic content bonuses?
• 22:39 - Question 17: What types of deals are using domestic content?
• 23:31 - Question 18: Are you seeing deals with the LMI bonus?
• 24:33 - Question 19: Are you seeing deals outside of solar, wind, and battery storage? Are you getting calls from people ready to transact on newer technologies?
• 26:28 - Question 20: Will a flood of new credits from different technologies drive pricing down over time?

Transcript

Introductions

Andy Moon: Welcome to another episode of 10 Questions with Reunion. My name is Andy Moon, and I'm the co-founder and CEO of Reunion, the leading marketplace for clean energy tax credits. We work closely with corporate finance teams to purchase high-quality tax credits from solar, wind, and other clean energy projects.

Today's guest is Hilary Lefko, who needs no introduction to practitioners of renewable energy finance. Hilary is a partner at Norton Rose Fulbright in Washington, DC and has significant transactional experience with Section 45 production tax credits, Section 48 investment tax credits, and is now spending a lot of time advising clients on tax credit transfers via the Inflation Reduction Act.

Hilary, great to have you here today.

Hilary Lefko: Nice to be here. Thanks for having me.

Question 1: What sort of transferable tax credit deals are you seeing? What have been the smallest and largest transactions you’ve worked on?

Andy Moon: Specific to Section 6418 tax credit transfers, what deals are you seeing? What's the smallest transaction you've worked on and what's the largest?

Hilary Lefko: We're seeing all kinds of transactions. What I think is interesting relates to Congress's whole reason behind transferability: to open financing to much smaller projects than would traditionally be financed by tax equity. The first projects we saw were projects that would be financed by tax equity, and it was tax equity investors buying the credit.

But now the market is exploding. We're seeing small projects getting financed. We're seeing portfolios getting financed. We're seeing portfolios of wind and solar. We're seeing solar plus storage, small commercial and industrial solar (C&I), biogas, very large wind farms, and solar. We're even seeing nuclear and renewable natural gas (RNG).

It's incredible how much the market has grown since the regulations came out in June.

Question 2: What interesting structures are emerging with transferability?

Andy Moon: What are you seeing in terms of other interesting structures that are coming to light with transferability?

Hilary Lefko: The first deals we saw were existing wind tax equity, selling off some credits from the last few years of the PTC period. Then, we started to see portfolio deals with people bundling up existing wind farms and selling the tax credits from them.

Then, we started to see the market move into greenfield projects. We're seeing new builds for solar, new builds for wind, storage, biogas. I think everything is bespoke right now. We're seeing the plain vanilla standalone deal, but I would say every traditional tax equity deal I'm doing right now has a transferability component to it.

Transferability has become such an important part of the market. It's a feature of every transaction I'm working on right now.

Question 3: What terms are you seeing on bridge loans?

Andy Moon: You mentioned working on bridge loans against commitments of tax credit transfers. What terms are you seeing on bridge loans?

Hilary Lefko: We've seen lenders that traditionally offered tax equity bridge loans step into the transferability bridge market. I'm seeing relatively similar terms and similar advance rates: if there's a purchaser that's already signed a tax credit transfer agreement, [we're] seeing advance rates in the low to mid 90s. If there's no tax credit purchasers signed up, we're seeing much lower advance rates – 75 and below.

For the most part, the lenders that have been doing tax equity bridges have been willing to jump into the transfer bridge market.

It was, however, a steep learning curve for them. They had to get used to the fact that money was coming in later than it does with tax equity, that payment structures look different, that there are different risks, and that different structures may be necessary. But we're seeing the debt market pick up.

Question 4: How does tax credit pricing differ between standalone deals and hybrid tax equity deals?

Andy Moon: As tax equity partnerships sell credits out of the partnership, how does pricing differ on those deals versus a standalone deal? Is it a smaller discount?

Hilary Lefko: It depends. The trends I'm seeing are 2023 credits are trading much higher than 2025 or 2026 credits. 2024 credits are a little bit higher than those future credits as well.

I don't know that the structure is driving the pricing so much as the timing of the credits. I also think the technology [is a factor] – wind, solar, and storage are going to trade a little bit higher than technologies like biogas, where people are not familiar with the risks. I think wind is trading a little bit higher, too. PTC is trading a little bit higher than ITC.

It'll be interesting to see once we get into the beginning of next year when 2023 tax liability has firmed up for many companies. I think we're going to see prices go up.

Question 5: When negotiating tax credit transfer agreements between buyers and sellers, what negotiating point has surprised you the most?

Andy Moon: That's very interesting. As you're negotiating tax credit transfer agreements between buyer and seller, what's come up in negotiations that surprised you the most?

Hilary Lefko: The thing that surprised me the most was a lot of sellers are trying to limit the amount of due diligence that buyers can do. Sellers are saying, "You're either getting a guarantee or you're getting a tax credit insurance policy, and you need to take our word for it – we're giving you representation."

The initial entrants into the market were traditional tax equity investors, and they were looking to do the same level of diligence that they would do on a tax equity transaction to confirm qualification for the credit.

Some of the newer entrants – corporates who haven't done tax equity before – are relying more on counsel, doing a little bit less diligence, but still wanting to kick the tires and make sure that the project qualifies. They're looking for tax credits, not an insurance payout.

Question 6: What type of sellers have the leverage to limit a buyer’s diligence?

Andy Moon: What type of sellers have the leverage to say there's limits on what due diligence you can do? Is that mainly the tax equity partnerships or the large banks who are putting those limits in place?

Hilary Lefko: I see it more from the smaller developers that want to sell their tax credits and think that they bought this insurance policy and that's going to make everything okay.

I think it has an impact on pricing. If you're not getting to kick the tires as much, you're not going to pay as much. There's a supply and demand aspect to it: if what you're offering doesn't have the same protections as what some other developer is offering, a buyer is not going to pay as much.

I think the market's going to take care of those sellers who don't want diligence being done, and they're going to get less for their tax credits than the sellers who are allowing buyers to do full diligence.

Question 7: What specific limits are sellers putting on due diligence?

Andy Moon: What specific limits are they putting on the diligence? Are they saying you can't dig into the cost segregation analysis, or are there specific areas that they want to curb diligence in?

Hilary Lefko: They’re saying, "Here's a cost segregation report, [and] you have an insurance policy. You have to trust us that we started construction. You have to trust us that the project is up and running. We've told you it's in service. You don't need to look at an independent engineer (IE) report."

"Why do you care if it's on a superfund site?" "If it is, then we get an energy community bonus." “But you can't look at environmental reports."

It's really limiting all those third-party deliverables the tax equity is used to viewing. We're seeing sophisticated tax counsel saying, "Well, you still have issues of tax ownership. We want to look at your O&M agreement, your off takes, [and] any revenue contracts to make sure that ownership of the project isn't shifting to someone else." And sellers are coming back and saying, "You don't need to look at an O&M agreement. It's an ITC. Why do you care if the project operates?" You do care during the recapture period, so there are considerations as well.

In the ITC context, we’ve seen sellers try and say, "Well, you can look at it up to placed-in-service, but you don't need to be concerned after that. We got you a recapture policy." That's just not been acceptable to a lot of buyers.

Andy Moon: That's been our experience, too. We've counseled buyers that it's important to do a comprehensive due diligence process and understand what you're buying.

There is some art, however, in making sure that this doesn't become another tax equity transaction where there is belt-and-suspenders diligence on every item. But proper diligence is important.

Hilary Lefko: Absolutely. I'm seeing some sellers try and limit the ability to get a tax opinion or what that tax opinion can cover. But, generally, more sophisticated buyers are looking for an opinion or a memo of counsel confirming that the project qualifies for tax credits in the full amount.

Question 8: What are you seeing with respect to audit rights during transfer negotiations?

Andy Moon: One other interesting point that you made is that audit rights and control of audit was one of the biggest negotiation points on the tax credit transfer agreement. Can you say more about what you're seeing there?

Hilary Lefko: Audit rights has become a big sticking point on a lot of these deals. The issue being that the regulations make clear that the audit can and will occur at the buyer.

Generally, these tend to be relatively buyer-friendly agreements, in which the seller has a lot of indemnities to the buyer. When the seller has an indemnity, they're going to want some level of control or participation in an audit. But you have corporates that aren't used to doing tax equity, and the thought of someone meddling in their audit is foreign to them.

Further, tax equity investors are buying these credits through their bank entities, and they can't have somebody else participating in an audit at the bank entity level.

So, [we've seen] a lot of negotiation on what kinds of rights sellers get where they do have an indemnity, where the buyer is clearly being protective of their audit process and should be.

Question 9: What is the 50^th percentile in terms of negotiating audit rates?

Andy Moon: Where would you say the 50th percentile is netting out in terms of audit rights?

Hilary Lefko: I think similar to where tax equity is. If the seller has an indemnity obligation, they have notice and participation rights [in the audit]. Ultimately, though, the buyer is going to control any audit at the buyer level. With respect to seller audits, we've seen a little bit more give – some sellers are willing to give buyers a bit more participation rights.

Generally, where the market is settled is you control an audit at your own level. If there are indemnity rights, we'll let you be involved, we'll let you have notice, participation, and maybe consent over an audit that's going to result in an actual indemnity obligation.

Question 10: Are you seeing structures emerge for developers to take advantage of a basis step-up?

Andy Moon: Flipping over to other structures that you've seen, we've heard a lot of talk of structures within transfers to enable a basis step up in the case of an investment tax credit - for example, an affiliate sale of a project company to a joint venture (JV). Have you seen this happening in practice?

Hilary Lefko: In terms of the step-up partnerships, I think this is going to be the key to unlocking the market. I think that everyone doing ITC deals is looking for a way to do a step-up partnership to get more value from the tax credit.

Initially, people were referring to these as accommodation parties, but I think to me it's more of a cash equity transaction. It's not tax equity. The investor is putting money in and getting a return on cash back. They're looking for credit card-like returns.

Initially, people were looking at these step-up partnerships as if they needed to look like tax equity and needed to satisfy the revenue procedure. “We need to have a pre-tax profit.”

To me, it's different. This is more like a cash equity transaction, where you have someone putting cash in and wanting a cash return.

Yes, a large portion of that return is coming early in the partnership because the partnership is selling tax credits. However, I think there needs to be some variability, and investors need to have some skin in the partnership game, some entrepreneurial risk – upside and downside. They're getting some of their return from the actual operations of the partnership – not just selling tax credits.

There was handwringing over making these interests look like tax equity when they're not tax equity. They're more like cash equity, which no one ever had these concerns about structuring cash equity.

Question 11: What level of ownership is required to make buyers comfortable that it's a true third-party owner?

Andy Moon: Do you have any sense of what level of ownership is required to make buyers comfortable that it's a true third-party owner?

Hilary Lefko: I think in terms of what percentage do these cash equity accommodation parties, whatever we're calling them, need to have. I think initially people said 20% because that's what we think of as a meaningful stake in the partnership. I think we'll start there. No one wants to be the guinea pig. I think the first deals are going to get done at 20% or higher.

The issue is if you're stepping up the basis of a tax credit, there needs to be a robust appraisal supporting that fair market value. The partner interest to me is a little bit more of a red herring.

While they do need to be respected as a partner – and I'm not writing that off or being flippant about not making sure that they're a true partner in the partnership – I think we're losing sight of the bigger issue, which is, can we support the step up? Is the step up too much? Is there an appraisal behind it?

I'm not saying that we don't need to make sure the partner is a real partner; I'm absolutely saying that. I think we're losing sight of the bigger issue, and that's we still need to be able to support the step up.

Andy Moon: For sure. We have two separate issues. One is to ensure that the IRS respects the partnership as a true third-party transaction. And the second is the level of step up. The latter is an ongoing question. The IRS didn't provide clear guidance or a clear line on what's acceptable in terms of step-up level. I think that'll be very interesting to see.

Question 12: Are you still seeing tax credit transfers with step-ups above 20% to 30%?

Andy Moon: Are you still seeing tax credit transfers with step-ups above 20% to 30%?

Hilary Lefko: Not really. We're seeing the traditional tax equity want to cap it at 15%, maybe 20%. Newer entrants into the market, if they're not represented by sophisticated tax counsel, can be convinced to go higher.

Some of the insurance markets are more conservative than others. Some will insure step-ups over 20%, while others will not. A lot of people view that step-up over 20% like an insurance arbitrage – we're going to get our tax credits, or we're going to get our insurance.

Question 13: Are you seeing any structures emerge to mitigate risks to the buyers?

Andy Moon: Are you seeing any structures emerge to mitigate the risk to the buyers? For example, if you have a partnership own a project company, that can help mitigate the risk of recapture if there's an upstream change in control.

Hilary Lefko: Absolutely. In the ITC space, we're seeing a lot of internal partnerships. These are not being done for step-ups. Rather, they're being done to mitigate recapture risk.

It almost creates a synthetic tax equity partnership where you have your class A interest that's getting tax benefits, and your class B interest that's getting more cash. The synthetic class B member can pledge that interest to the lender to mimic the collateral structure in traditional tax equity that they would have with back leverage.

I think if you can get that in place, lenders are getting comfortable. With deals that are already placed in service, though, where they didn't have the foresight to put something like that in place, lenders are saying, "Too bad, we have asset-level security. We're not going to forbear during the recapture period unless we have access to that sponsor-level interest as collateral."

Question 14: What types of limits of liability are you seeing?

Andy Moon: And flipping back to the tax credit transfer agreement, what limits of liability are you seeing? Are buyers asking for liability coverage in excess of the credit amount?

Hilary Lefko: I literally had two calls about this today! One with a lender, and one with a purchaser about what's "market" on sizing of indemnities for tax credit transfer deals.

If you're a purchaser, you're going to argue that market is the face value of the tax credits, and it should be uncapped. If you're the seller, you're going to say, "No, why should I pay you the face value of the tax credits? I should only be out for my purchase price."

We're seeing the "true" market settle somewhere between those two positions. We're seeing purchasers get comfortable if their indemnity amount is sized to the actual value of the tax credits – that is, the dollar amount of the tax credits. Then, they're willing to accept some limit on liability, such as purchase price plus 20%.

It's rare to have a wholesale disallowance of tax credits. Usually, you're looking at the basis step up or you have a piece of property that you claimed ITC on that you shouldn't have in the cost segregation. It's rare for the IRS to say you shouldn't have gotten the ITC at all.

For that reason, we're seeing purchasers accept some cap as long as they're getting the indemnity and the amount of the credit.

It also goes to the size of your insurance policy. We didn't talk about this, but all these deals I'm seeing are done with either insurance or a strong, creditworthy parent guarantee. To a seller that has insurance, if their tax credit insurance policy is sized to the face value of the tax credits, then they're fine with their indemnity looking like that because their agreement is going to say the buyer must go against the insurance policy before they can seek recourse against the seller.

Question 15: Are you seeing buyers get comfortable with sellers not providing a guarantee when there's insurance?

Andy Moon: That's fascinating. Are you seeing buyers get comfortable with sellers not providing a guarantee when there's insurance?

Hilary Lefko: I've seen several deals done with insurance only with a very limited parent guarantee. If you have insurance, what you're really looking at is retention (the uncovered amount) and whether contest costs count towards the retention.

You can quantify what's not covered by the policy and see how comfortable you can get with or without a guarantee. But I've seen deals done insurance only, with the seller pushing back on a guarantee or pushing back on a creditworthy parent giving a guarantee.

Andy Moon: That's fascinating. It's great to talk to you, Hilary, because you see so many deals in the market. It's interesting to see what each party is willing to accept because, at the end of the day, it's a negotiation.

Hilary Lefko: I would say "no guarantee" is the exception rather than the rule, and it certainly is going to impact pricing.

All these levers are levers that you can pull economically, and if you're willing to go without a guarantee, perhaps you can get a better deal on pricing. If you're insisting on a guarantee, then maybe the seller won't be is willing to work with you on pricing and some other factors.

The scope of the indemnity – whether it's just breaches (bad act-type things) or if it's more comprehensive (any loss disallowance recapture) – factors into the deal’s economic terms. All these deals are bespoke, and everyone's negotiating what they want out of them.

Andy Moon: Right. We've seen some buyers express that they want the indemnity from the seller to prevent moral hazard – that is, to make sure that the seller doesn't do anything that might trigger a recapture. Nobody wants to deal with having to get claims from an insurance policy.

Hilary Lefko: That's consistent with what we've seen as well.

Question 16: Are you seeing deals with the energy community and domestic content bonuses?

Andy Moon: Let's flip to bonus credits because there's still outstanding guidance on domestic content. What are you seeing in energy community, domestic content, and LMI?

Hilary Lefko: For the energy community bonus, I'm not seeing any issues with purchasing credits from projects that qualify on statistical area or on a closed coal fire and generating plant or closed mine.

It's been a bit more difficult to get a brownfield financed, and I think the reason for that is the determination must be made by an environmental lawyer. Environmental lawyers are not tax lawyers and are not used to writing opinions.

It's been hard to get the level of support and the documentation that tax credit investors expect when you're talking about a brownfield. I'm not saying it can't be done. There probably have been a few, but it's been difficult to get brownfield financed.

The other two, however, are easy to diligence: you look at the address and see if it's on the appendix. You must make sure the test year works in terms of whether it's placed in service, or every year during the credit period for PTC, or if you fit into the beginning-of-construction safe harbor. But I think that's probably the more difficult qualification piece than the underlying qualification itself.

Question 17: What types of deals are using domestic content?

Andy Moon: Are the deals you're seeing on domestic content win re-powers, or are they traditional solar installations?

Hilary Lefko: I have not seen a lot of domestic content financed. I know of two deals, and they have insurance. For the most part, sellers are finding that, right now, the market is not willing to finance domestic content. The reason for that being that it's just impossible to get manufacturers to disclose their direct and labor costs.

Everyone's putting this wait-and-see approach on domestic content. If we get better guidance or if we get manufacturers to disclose costs, then we're going to include the domestic content bonus. The projects that I know included the domestic content bonus in sizing were solar.

Question 18: Are you seeing deals with the LMI bonus?

Andy Moon: Fascinating. What are you seeing on LMI credits?

Hilary Lefko: The LMI portal opened last week, and everyone's scrambling to get their applications in. (Although you don't have to scramble because it's not first in, first out if you meet the [30-day] deadline. All applications [submitted within the first 30 days] get considered at the same time, based on the weighting criteria.)

If [the developer] get an allocation and other conditions are met, then we'll finance the credit.

People were hesitant until the portal opened and were worried that it wouldn't open – that we wouldn't, initially, have awards.

The DOE and the Treasury have been doing a road show of webinars, so everyone's gotten more comfortable with how you apply and how you qualify. We've been seeing more LMI elements added to these deals.

Question 19: Are you seeing deals outside of solar, wind, and battery storage? Are you getting calls from people ready to transact on newer technologies?

Andy Moon: Looking forward, we know there's a lot of demand for solar, wind, and battery storage tax credits. What are you seeing in terms of other technologies? Are buyers willing to purchase credits from other technologies?

Hilary Lefko: I am, although I am seeing lower pricing for other technologies. We are seeing a lot of sellers going to market with other tax credits. I think the next biggest category would be biogas and renewable natural gas (RNG). I think there's going to be a lot of those. There are a few projects that came online in 2023, and I think we'll see more 2024.

Anytime a potential seller comes to me with those types of credits and says, "I can get 96 cents of credit," I say, "Well, you're not selling 2023 wind [credits]. You probably can't [get that pricing]. You need to redo your economic projections assuming a much lower price per credit and make sure that this is still economically viable for you. Anything above that is going to be crazy.”

We've heard of some 45U nuclear credits coming out – maybe some other nuclear facilities selling technology-neutral credits. It'll be interesting to see what those trade at.

I think there's a lot of considerations with public perception around nuclear and whether investors will be willing to buy those credits and be associated with those technologies. It'll be interesting to see what the market will bear. It may be a great way for companies to get a bargain on tax credits.

As we start to see newer technologies flood the market with lower pricing, it'll be interesting to see if those impact the other end of the market – that is, the credits with which people are [familiar] and the technologies that investors are comfortable financing.

Andy Moon: I think that's right. There's a lot of expectation among developers that pricing will go up – that there will be a smaller discount as the market matures.

Question 20: Will a flood of new credits from different technologies drive pricing down over time?

Andy Moon: If there's a flood of new credits from many different technologies all competing for the same tax credit buyer dollars, will that provide downward pressure on pricing over time?

Hilary Lefko: I think it's going to be interesting to track.

Andy Moon: Thanks for coming on the show today, Hilary. It's been great to have you. Great to see you, as always.

Hilary Lefko: Yes, this was great. Great chatting.

Introduction

In episode 4 of 10 Questions with Reunion, our president, Billy Lee, chats with Marc Schultz of Snell & Wilmer about how individuals and closely held C-corporations can purchase transferable tax credits.

Marc provides a close look at an exception to the passive activity rules that applies to closely held C-corporations – an exception, Marc notes, that "has helped many closely held C-corporations invest in tax equity deals."

Listen on Spotify or Apple

10 Questions with Reunion is available as a podcast on Spotify and Apple.

Takeaways

• Individuals can purchase transferable tax credits to offset passive income. Passive activity rules limit an individual's ability to offset active income with transferable tax credits. However, individuals can apply tax credits to passive income or income associated with leasing.
• Portfolio income cannot be offset with transferable tax credits. Portfolio income includes dividends and capital gains. There is one exception: the sale of assets that generate passive income would result in passive income at capital gains rates.
• Like individuals, closely held C-corporations are subject to passive activity rules.  A closely held C-corporation has five or fewer shareholders owning more than 50% of the equity.‍
• Marc and Billy do not believe the Treasury will revisit the passive loss rules with respect to individuals buying transferable tax credits.
• There is an exception to the passive activity rules that apply to closely held C-corporations, which enables them to purchase transferable tax credits. To get this exception, the company needs to have five or fewer shareholders owning more than 50% of the equity in the company where such shareholders with at least 50% of the equity are material participants in the business. If they are material participants and the company purchases credits, the company can use those credits against its active income or its passive income, but not its portfolio income.‍
• Banks that are closely held C-corporations that generate most of their income from interest can purchase transferable tax credits. If the bank is active in the business of lending, it can use the tax liability from its mortgage portfolio as active income (instead of portfolio income) for the purpose of purchasing tax credits. The bank's shareholders would have to meet the material participation exception.

Video

Chapters

• 0:00 - Introductions
• 2:19 - Question 1: What are the passive activity rules and how do they apply to tax credit purchases by individuals?
• 4:45 - Question 2: Which individuals should consider transferable tax credit purchases?
• 8:03 - Question 3: Is income from dividends and capital gains considered passive income?
• 9:31 - Question 4: Will you comment on speculation in the market about the Treasury revisiting the passive loss rules with respect to individuals buying transferable tax credits?
• 12:55 - Question 5: What groups, other than individuals, are subject to the passive activity rules?
• 14:34 - Question 6: What is the exception to passive activity rules that apply to closely held C-corporations?
• 16:20 - Question 7: Does this exception apply to tax credit transfer transactions?
• 16:46 - Question 8: How would a closely held C-corporation calculate its material participation and credit value?
• 17:55 - Question 9: Would banks that are closely held C-corporations be able to benefit from transferable tax credits?
• 19:41 - Question 10: What best practices should a closely held C-corporation consider when acquiring transferable tax credits?

Transcript

Introductions

Billy Lee: Thank you for joining us on our webinar series, 10 Questions with Reunion. My name is Billy Lee, and I'm the President and Co-Founder of Reunion, the leading marketplace for clean energy tax credits. We work with corporate finance teams to purchase tax credits from solar, wind, battery, and other clean energy projects.

Today, we are joined by Marc Schultz, a partner at Snell & Wilmer and a well-known tax attorney in the energy and federal tax credit space.

Marc, welcome. Can you tell us about yourself and your practice?

Marc Schultz: Thank you, Billy. I appreciate the invite to speak to you. I am a tax credit finance attorney and have been practicing since 1997. I live in Phoenix. I am the co-head of our renewable energy practice and the head of our tax credit financing practice at Snell & Wilmer. We have 16 offices, our largest office being in Phoenix and our farthest east office being in Washington, DC. We have three California offices, too.

I do everything from private equity real estate transactions, opportunity zone incentive transactions, and then quite a bit on the tax credit financing side – low-income housing, new markets, historic tax credits, and, as we're going to talk about, renewable energy tax credits, both ITCs and PTCs.

Question 1: What are the passive activity rules and how do they apply to tax credit purchases by individuals?

Billy Lee: Today, we're talking about investing in renewable energy as an individual. Historically, this has been challenging. Unlike real estate, where many individuals participate in the direct ownership of rental real estate, we haven't seen this type of broad investment into solar, wind, and other renewables despite becoming a large asset class.

One of the main barriers is the passive activity rules. Can you briefly explain what these rules are and what they're meant to achieve?

Marc Schultz: The passive activity rules apply to both credits and losses – we’ll call them "passive activity credit rules" and "passive activity loss rules." These rules were put in place in the 1980s to curb an abuse that Congress thought was going on with respect to individuals who were investing in assets that were highly levered and quickly depreciated. Folks were putting a little cash in, but, because of the leverage, they were able to use the tax losses to wipe out all their income.

A physician, for example, might invest in a movie tax shelter, end up with a bunch of losses, and then use those losses to wipe out his/her income from practicing medicine. (There are quite a few movies that we've all seen that were set up as tax shelters.)

Congress imposed an at-risk rule and a passive activity loss rule. If you are subject to these rules and are not a material participant in the trade or business, then your losses are passive. You can only use passive losses to offset income from other passive activities. [It should be noted that leasing is an activity that is considered to be passive regardless of material participation.]

The corollary to that are the credit rules. If I have an activity that generates a credit and I'm not a material participant in that activity, then I can only use that credit against my tax liability from other passive activities.

Question 2: Which individuals should consider transferable tax credit purchases?

Billy Lee: The Inflation Reduction Act (IRA) included a provision that allows a number of different credits to be bought and sold between unrelated parties. We call this "transferability," and this is what Reunion's business is focused on.

Over the past year, we've received tons inquiries from individuals who are eager to reduce their tax liability by buying renewable energy tax credits. What type of individual taxpayers, if any, should consider tax credit purchases?

Marc Schultz: The Inflation Reduction Act doesn't mention the application of the passive activity credit rules. But the proposed regulations that Treasury released in June 2023 say that the passive activity credit rules apply to folks who are subject to these rules.

The word "activity" is important here – you must have an activity in a trade or business. Some folks were hoping, "Well, if I buy these credits, there's no real activity. I'm just using the credits against my tax liability. There's no activity here, so the purchase shouldn't be subject to the Section 469 rules."

Instead, the guidance said buying transferable tax credits is going to be an activity. If you are subject to these rules, buying transferable tax credits is an activity subject to these rules.

If you're an individual and you buy transferable tax credits, you can only apply these credits to your tax liability from other activities that you’ve invested in where you do not have material participation [or the activity involves leasing].

Let's say I invest in your restaurant. It's making lots of money. It's an LLC, and you give me a K-1 every year, and it's got taxable income that's being allocated to me, but I am not a material participant in your restaurant. That income would generate a tax liability for me, and I would be able to use those credits that I purchased from a solar project against that tax liability. That would be your perfect example of a situation where an individual could take advantage of this.

(Now, there are also rules that say you can't wipe out more than 75% of your tax liability, but that's beside the point. I know that's not what we're talking about today, but there are some other limitations.)

Generally, if an individual gets a K-1 that has trade or business income, and they are not a material participant, then they would be able to use those credits against that tax liability.

Billy Lee: Said differently, only taxpayers with tax liability from passive income should consider these tax credit purchases.

Question 3: Is income from dividends and capital gains considered passive income?

Billy Lee: We all know people who have done well selling businesses, selling stocks, or having securities portfolios. What about income from dividends and capital gains? Is this passive income?

Marc Schultz: There's a third category of income called "portfolio income." Think about it this way: on the loss and credit side, we've got passive and active. We've got passive losses, passive credits; we've got active losses, active credits. On the income side, we have three buckets: active, passive, and portfolio.

An individual subject to the passive loss rules, who has a passive credit that they have purchased, cannot use that credit against the tax liability from active or portfolio income. If I get dividend income, that's going to be portfolio income for me.

Billy Lee: To summarize, portfolio income, such as dividends and capital gains, is "bad" income for purposes of tax credit transfers.

Marc Schultz: [There is one exception: the sale of assets that generate passive income would result in passive income at capital gains rates.]

Question 4: Will you comment on speculation in the market about the Treasury revisiting the passive loss rules with respect to individuals buying transferable tax credits?

Billy Lee: You mentioned earlier that the proposed regulations that came out in June said that these credits can only offset liability from passive income.

However, there was an article in Bloomberg tax that was titled, Treasury floats allowing individuals to buy energy tax credits. (The article is from October 2023).

Marc, you and I were on a tax working group call organized by an accounting firm this week, and this article caught a lot of people by surprise. Can you provide any context here?

Marc Schultz: The Bloomberg article, which I've not seen, was referring to a week-long ABA tax section meeting. On Monday, they had the energy subcommittee meeting, and there were two folks from Treasury on the call.

Questions were asked about the passive loss rules. The individual from Treasury said that they've received two buckets of comments. Some of the comments said we need individuals in the marketplace. If we didn't have to worry about the passive loss rules, the market would have more capacity to purchase credits. We have eleven new credits with the Inflation Reduction Act. Folks are anticipating that we're going to need a lot more purchasing power in the marketplace for all these credits. There was quite a few of these comments. I was involved in drafting one of those comment letters with an individual that spoke at Treasury.

There were several comment letters that focused on the legal issue, in the sense that the statute doesn't mention anything about the application of passive loss rules. And since it doesn't mention that, do we have an activity? If all I'm doing is purchasing tax credits, for the passive loss rules to apply, we must have trade or business activity. So, do you really have a trade or business activity if you're just an individual purchasing credits to use against your tax liability? If we don't have an activity, then arguably you don't have to worry about the passive activity rules. But the IRS is deeming it to be an activity under these proposed regs.

Those are the two buckets of comments. All Treasury said is that they're reviewing the comments. In fact, one of the comments that the IRS made is that their data didn't show that they needed the individuals in the marketplace to purchase the amount of tax credits that they think will be available.

I like the title of the article but am not as optimistic as some other folks.

Question 5: What groups, other than individuals, are subject to the passive activity rules?

Billy Lee: Individuals aren't the only group of taxpayers subject to the passive activity rules. Can you discuss the other groups?

Marc Schultz: If you're a widely held C-corporation, then you're not subject to the at-risk or the passive loss rules. Generally, if you're not a widely held C-corporation, you should be thinking through the passive loss rules.

A widely held C-corporation is a corporation that's not a closely held C-corporation, and a closely held C-corporation is a C-corporation that has five or fewer shareholders owning more than 50% of the equity value in the corporation. If you're a widely held C-corporation – the usual suspects that purchase tax credits on the tax equity market – they may not even know what the 469 passive activity rules are because they don't have to worry about them, nor do they have to worry about the at-risk rules (except in some special circumstances called inverted leases, but that's beyond the scope of what we're talking about.)

Generally, if you're not a widely held C-corporation, you should become acquainted with these rules if you're thinking about purchasing tax credits.

Question 6: What is the exception to passive activity rules that apply to closely held C-corporations?

Billy Lee: To add another wrinkle, you have written about an exception to the passive activity rules that apply only to closely held C-corporations. Will you elaborate on this?

Marc Schultz: As I mentioned, you have three buckets of income: portfolio, active, and passive. Then, you have two buckets for credit-loss limitation rules: passive and active. There is an exception to the passive activity rules that apply to closely held C-corporations for which individuals don't get the same benefit.

Let's say you have a closely held C-corporation, an auto dealership, where a father and son own more than 50%, and they both work in the auto dealership. To get this exception, the company needs to have five or fewer shareholders owning more than 50% of the equity in the company where such shareholders with at least 50% of the equity are material participants in the business. If they are material participants and the company purchases credits, the company can use those credits against its active income or its passive income, but not its portfolio income.

This exception has helped many closely held C-corporations whom I've represented invest in tax equity deals.

Question 7: Does this exception apply to tax credit transfer transactions?

Billy Lee: Would the same apply to transfer transactions as well?

Marc Schultz: That is correct. A closely held C-corporation whose shareholders meet these material participant requirements, with your five or fewer shareholders, would be able to take advantage of this exception and use transferable tax credits against its active income.

Question 8: How would a closely held C-corporation calculate its material participation and credit value?

Billy Lee: To qualify, must all the shareholders be material participants, or is it a pro-rata amount? That is, if 30% of shareholders are material participants, do you get 30% of the credit value?

Marc Schultz: My recollection is that you must get over the 50% threshold. So, you look at the individuals with material participation who own over 50% of the equity. You may not need all the shareholders to be material participants, but you'd have to identify enough individuals that cross over the 50% threshold and make sure that they're material participants.

If that C-corporation is involved in multiple activities, and you're looking at the tax liability for one of those activities, you have to make sure that the individuals are material participants in that activity. The classic example of material participation is spending more than 500 hours annually in that activity.

Question 9: Would banks that are closely held C-corporations be able to benefit from transferable tax credits?

Billy Lee: Let's revisit something you said about closely held C-corporations who have this exception: they can use passive credits against active and passive income. Now, let's talk about portfolio income because there are lots of banks that are closely held C-corporations, and the character of their income is slightly different than a typical closely held C-corporation. Most of their income is interest income that comes off loans, which is what we previously said was portfolio income, not active income. Would these banks that are closely held C-corporations not be able to benefit?

Marc Schultz: Although you have a mortgage portfolio and are getting interest income, if you're active in the business of lending, then you can use the tax liability from that mortgage portfolio as active income for this purpose – that is, for the purpose of using tax credits to offset the tax liability from the interest from the mortgage portfolio.

You have to look at those five for fewer individuals and make sure they're active in the business of lending. If the bank has multiple businesses, you must identify the owners and make sure that they're material participants in the business of lending. We work with small banks that invest in tax credits, and they use this exception as closely held C-corporations.

Question 10: What best practices should a closely held C-corporation consider when acquiring transferable tax credits?

Billy Lee: Are there any other requirements for a closely held C-corporation to take advantage of this exception? Are there specific best practices that you recommend that a closely held C-corporation undertake when thinking about acquiring tax credits?

Marc Schultz: The situation where this would be important is when you have five or fewer shareholders – that is, when you have five or fewer shareholders owning more than 50% of the C-corporation.

I also mentioned that you must pass this material participation test. If you have shareholders that are engaged in other businesses – for example, your bank has a lawyer, and the lawyer has a full-time practice but needs to justify that they've spent more than 500 hours in the mortgage lending business – the firm should keep track of the time that the lawyer spends in the mortgage lending business in case of an audit.

It's important to document how much time each day that they spend in this business and record exactly what they're doing for the business. This practice will help you if you're ever audited.

Billy Lee: Great advice, Marc. I think everyone should take into heart that carefully documenting and preparing for future inquiries or audits is important and should be a best practice in any of these transactions.

That wraps up our ten questions with Marc Schultz. Marc, thank you for joining us today, and we look forward to talking to you again soon.

Marc Schultz: Thank you, Billy. Really appreciate it.

Welcome to Episode 2 of 10 Questions with Reunion. In this 60-minute installment, our CEO, Andy Moon, had the privilege of exploring the latest developments in the transferable tax credit marketplace with Brian Murphy of EY and Adam Kobos of Troutman Pepper.

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 02 takeaways

• We are seeing a meaningful uptick in tax credit transfer-related activity as we enter Q4. Many buyers are looking to close their first deal, creating a sense of urgency. There's a lot of pressure to get a deal “across the finish line" in the 2023 tax year.
• 2023 credit prices are forming a bell curve in the low 90-cent range, with tails extending to $0.90 and $0.96. Projects will emerge that are willing to accept larger discounts as well. PTCs generally have a lower discount due to simplicity of transaction and lack of recapture risk.
• The headline discount only tells part of the story; payment terms and timing are critical when evaluating the economics of tax credit transfers. Purchasing credits early in the year allows buyers to offset estimated quarterly tax payments. Buyers that can delay payment for credits can achieve very strong returns, which should in turn impact the headline discount number. Buyers looking for these returns should start looking now at 2024 credits to get under contract in Q1.
• Select buyers are growing comfortable with offsetting quarterly tax payments prior to the generation of a tax credit. When transacting with established developers, some buyers are comfortable signing a tax credit transfer agreement early in the year and applying the tax credit amount against their quarterly estimated tax payments, even though the credits will not be generated until later in the year. If the credits do not materialize as predicted, buyers will need to find replacement tax credits, or face underpayment penalties
• The market remains hopeful that the IRS will have the registration portal open by calendar year-end. Ideally, the portal will be open in time for the last quarterly estimated payment date of December 15th, but time will tell.
• Tax credit insurance should be able to take a view on placed-in-service (PIS) date. It is important that the PIS date is correct, since it determines the tax year that the tax credits apply to. PIS date is not straightforward, and it is determined by a five-part test. Panelists believe that tax credit insurance should be able to take a view on when PIS occurred (though will not insure a future PIS date)
• Buyers are expressing preferences for certain technologies, credit types, and bonus credits. Buyers prefer established technologies, like wind and solar. Some buyers prefer PTCs, which carry a lower discount, because of their simplicity and risk profile. Few near-term projects are pursuing the domestic content bonus.
• Collecting labor and wage data contemporaneously is critical for compliance with prevailing wage and apprenticeship requirements. Simply trusting contractors (and subcontractors) to collect, maintain, and furnish the data presents undue risk.
• Early buyers are looking for “airtight” indemnities with credit support. Tax credit insurance is an important tool for early buyers purchasing from entities that cannot provide a creditworthy indemnity.
• Panelists predict that utilities will be net sellers of tax credits near-term, before becoming net buyers. Many utilities have accumulated depreciation and credits on their balance sheet; however, once these credits are used they will become buyers of credits… and it could happen relatively soon.
• Hybrid tax equity structures are becoming common, if not universal. Tax equity partnerships are building in the ability to sell credits from tax equity partnerships. Panelists predict that many tax equity investors will sell credits from partnerships to make room to do more deals.
• We’ll continue to see a range of valid basis step-ups. However, many projects will cluster around the 15% to 20% “standard” from the tax equity market, which is largely driven by institutional players.
• Excitement around using transferability to finance portfolios of smaller projects or newer technologies. One of the great promises of transferability is to expand access to financing for clean energy, and panelists are optimistic that innovative financing solutions will emerge.

Video

Video chapters

• 0:00 - Introductions
• 2:34 - Question 1: Are you sensing a recent increase in the level of interest in tax credit transfers?
• 5:44 - Question 2: Aside from the headline discount, how else should buyers think about the economics of tax credit transfers?
• 9:42 - Question 3: How comfortable are buyers with leveraging the "intends to purchase" language to offset quarterly estimated payments?
• 12:09 - Question 4: When do you think the IRS will have the pre-registration portal stood up?
• 14:49 - Question 5: Are buyers growing comfortable with signing tax credit transfer agreements early in the year for credits that will be generated later in the year?
• 17:31 - Question 6: How are buyers thinking about placed-in-service risk?
• 23:04 - Question 7: Will insurance companies take a view on placed-in-service dates for transferable tax credit deals?
• 24:34 - Question 8: Are buyers expressing preferences for certain technologies and credit adders?
• 32:08 - Question 9: What documentation should developers collect at the construction stage to ensure the prevailing wage and apprenticeship requirements are met?
• 34:25 - Question 10: How are developers ensuring they have the correct wage determination?
• 41:23 - Question 11: What are buyers expecting on indemnity coverage?
• 43:06 - Question 12: What are buyers looking for in terms of seller creditworthiness?
• 46:32 - Question 13: Will utilities be net buyers or net sellers of tax credits?
• 47:36 - Question 14: Are developers finding ways to step up their basis in transfer deals?
• 53:13 - Question 15: Where will we see basis step-ups in the next few years?

Transcript

Introductions

Andy Moon: Hi, everybody. Welcome to Reunion's webinar series. I'm Andy Moon, CEO of Reunion, the leading marketplace for clean energy and tax credits. We work with corporate finance teams to purchase tax credits from solar, wind, battery, and other clean energy projects. A big part of our work is walking buyers and sellers step by step through the transaction process with a close eye for managing risk. Today, we're excited to have Brian Murphy, partner at EY, and Adam Kobos, partner at the law firm, Troutman Pepper, joining us. I'd love to kick-off by asking each of you to give a short introduction. Brian, can we start with you?

Brian Murphy: Absolutely, Andy. Thanks for having me. I am our Americas Power and Utility Tax Leader, and the IRA seems to have consumed all since its passage, including the development of the tax credit transfer market. We are spending a fair amount of time working with clients to start to not only put together deals, but to anticipate and think about: is this market the right place for them, how to think about the market, and how to start to think about the risks, and how to manage those risks on both buy and sell side. So, it's an exciting time. It's evolving quickly, and I'm looking forward to our conversation today.

Andy Moon: Adam, can you introduce yourself and provide a few thoughts on what you're seeing in the market?

Adam Kobos: Thanks, Andy, for having me today. I'm Adam Kobos, partner in the tax group at Troutman Pepper. Our energy practice is a soup-to-nuts practice. We represent sponsors, investors, and regulated utilities in the market on everything from early stage development right on through various financing transactions, including now post-IRA tax credit transfers. Like Brian said, we're seeing a lot of activity in the tax credit transfer market, particularly following the issuance of the proposed regulations. We're working with buyers and sellers. I'm looking forward to our discussion today because it's a new and fluid market. There's a lot of variety out there - a lot of interesting things to discuss. Thank you again, Andy, for having me today.

Question 1: Are you sensing a recent increase in the level of interest in tax credit transfers?

Andy Moon: I think the market opened for business on June 14th when the proposed Treasury regulations came out. However, we are feeling a palpable uptick in buyer interest as we head into Q4. There is a feeling that, if you want to get in on 2023 tax-year credits, now is the time to be signing term sheets and preparing transactions. Are you feeling any changes in the last few weeks in terms of level of interest or engagement on tax credit transfers?

Adam Kobos: I think the usual thing happened. After Labor Day, everybody came back with a renewed sense of purpose. Andy, I think you're right. The desire to get tax credit transfer deals done this year has fueled a recent surge. And I think this is new to everybody. Everybody wants to get their first deal done, so they can understand how transferability works and work out the kinks. I think there's a lot of pressure, even if it's a smaller deal, to get one across the finish line, so that everybody has done at least one. We're seeing a big push now.

Andy Moon: That's a great thought. What's been surprising for us is that buyers are broadly aware of the opportunity. Six months ago, people weren't sure what a transferable credit was, but I've been surprised by the recent level of awareness. And I think a lot of buyers are clicking one level deeper to understand the transaction mechanics, the risks, and what it will take to get a deal done in 2023. Brian, any observations from your end?

Brian Murphy: As we think about these bilateral transactions that are already coming together with increasing level of frequency in the last few weeks, what's interesting is the evolution of the buy side of the market. As awareness and interest levels ratchet up, we expect that to begin to influence terms, conditions, and pricing. So, if we were to talk about what we're seeing so far in terms of pricing, there's a distribution, and it follows a little bit of a bell curve. (I'd love to hear, Andy and Adam, if you see things much differently.) But if I were to look at that bell curve, it feels like the tails are in the $0.90 to $0.91 area and the $0.95 to $0.96 area. But deals are really coming together in the middle of that bell curve - around $0.93 and $0.94. A lot of focus has been on the terms and conditions. There's a lot of uncertainty. The IRS has not stood up this registration portal yet, so there's some critical gating factors still to come. But as you watch the buy side really become cognizant of this market and start to understand the impact that it can have on their cash and tax payments, and the value for them to unlock, the expectation is that the buy side will continue to grow, and it will start to have an influence on terms, conditions, and prices.

Question 2: Aside from the headline discount, how else should buyers think about the economics of tax credit transfers?

Andy Moon: Adam, in an earlier discussion, we talked about pricing and how there's a lot of talk of the discount and the headline number of 92, 93 cents on the dollar. But maybe that's a bit simplistic in terms of how to think about pricing. Any thoughts you want to add in terms of payment terms or other ways to think about the discount?

Adam Kobos: I think there are a couple of things to talk about here. First of all, I would agree with Brian's range of pricing. That seems to be where the prices are clustering now. With the deals that we're seeing, the prices are being agreed to before the payment terms. The payment terms here are really important. There's the headline discount, which is significant, but there's also the time-value-of-money component. At the end of the day, transferability is a way of managing tax payments from the buyer's perspective. The proximity of the outflow, the purchase of the credit to the next estimated tax payment - that's a big deal. What we're seeing now, I think, is a desire for everybody to get their first deals done. They're not as sensitive to time-value factors. But I do think as time goes on and people get more comfortable with the baseline transactions, there's going to be a lot more focus on those timing questions and maybe a bit more sophistication in the documents to capture those nuances.

Brian Murphy: Adam, I think you hit it right on the head. There is a critical focus on just that price, but the time value of money is so important here. And the regulations brought the clarity that if you have acquired these credits or the intent to acquire these credits - and we can drill into what that looks like in the market - the buyer gets to factor that in to their estimated payment. So, Adam, I agree that time-value-of-money can potentially bring tremendous value to the buyer. And to talk about price without talking about those timing issues is disconnected. It really doesn't tell you the whole value story. And I start to see the market becoming cognizant of that, Andy, and would expect that to become a critical discussion point.

How soon in the lifecycle of a project can you actually pencil to acquire that credit? Do you aim that to be an intent to acquire the credit, count it in your estimated payment, and yet have a substantial deferral from when you really have to write that check?

Andy Moon: Those are great points, and I think this will be a big issue as we go into 2024. I think it makes sense that buyers are fixated on discounts in 2023 because most projects are constructed already. They're already placed in service, or they will be placed in service in a matter of weeks. Because of that, most of the estimated tax payment dates have passed for 2023. (I think there's one left.) For that reason, in 2023, the discount is more relevant. And I think the ranges that you mentioned, Brian, make sense. Perhaps the one addendum I would say is, we've seen a fairly wide range. I think spot PTCs that are lower risk are trading in the mid-$0.90s. ITCs from well-capitalized sponsors and experienced projects with some scale - we're seeing those trade in the low $0.90s. And there are fewer projects in 2023 that are small, employ new technologies, or present other factors that would merit a trade in the $0.80s.  

I think the time value of money question and the payment terms question become big deals in 2024, as buyers can now factor in estimated payment tax offsets from purchasing or intending to purchase these credits.

Question 3: How comfortable are buyers with leveraging the IRS "intends to purchase" language to offset quarterly estimated payments?

Andy Moon: Brian, the IRS was clear that if a transferee purchases or intends to purchase a tax credit, they can use that to offset their quarterly estimated tax payments. What are you seeing in terms of buyers being comfortable with making those offsets?

Brian Murphy: There's a continuum, Andy. If you keep reading in the proposed guidance, it says, if you have the intent to acquire the credit as a transferee, you can factor it into your estimated payment. The guidance goes on to say, if you actually don't have that credit when the day comes to file your taxes, that shortfall is on the transferee. There is, I think, a variation across buyers, and a lot of it will come to whether buyers feel they need the IRS registration number. Do they need the IRS portal stood up and transacting?

Part of that [question] is associated with the real or perceived quality of the seller. Is the project already built? Is it on? Is it delivering? Does the seller have a track record in this space? Do they have the history of placing in service, being audited, and sustaining their credit? There's a lot of factors that'll go into a buyer's level of comfort that a transaction will ultimately happen. Maybe delayed a little bit just for timing, maybe the portal is not stood up - what's the level of comfort that I have a deal that is going to produce a credit for me to use?

I see buyers all over the continuum. Some are focusing on the IRS portal, not necessarily as  a rigid toll gate of the registration number, but as evidence that the process the IRS is going to put the seller through has some value and merit to say, "That project is real. That project is going to produce a credit that I have on my bilateral contract an agreement to buy." I think as we get into 2024, time-value is going to become a lot more impactful and a lot more of a focus because of its ability to impact that estimated payment.

Question 4: When do you think the IRS will have the pre-registration portal stood up?

Andy Moon: I know both of you have had some dialog with the IRS in terms of getting feedback on the portal. Any predictions as to when that pre-registration portal might get stood up?

Brian Murphy: I'll go first, Adam, and I'm the somewhat optimistic, glass-half-full person. I had a unique opportunity - and many others have had it as well, though - to be in a small practitioner group to meet with the IRS and get a check-in on where they are in the lifecycle of developing their process and their portal. This was several weeks ago - maybe three weeks ago. I was impressed with the thoroughness of the process - how they're approaching the development of the platform. The web pages they showed us were user-friendly and tightly aligned with the guidance that we've received so far. I will also say this is not just putting out guidance; it is more challenging. The portal is a complex piece of technology, so the IRS would not commit to a date. From my view, they still had a little ways to go [in the development process]. To see it stood up before, let's say, December 15th - that next estimated payment date - is not impossible but would be impressive. I would probably say to get it by the end of November, early December is 50-50 at best. There's a lot of work that has to go into a tool like that.

Andy Moon: That's a great insight. Adam, any thoughts there?

Adam Kobos: I've got no better information than Brian on this, but I think there's institutional pressure and external pressure to get the portal finalized as soon as possible. The IRS tipped its hand a few months ago, saying it wanted to be done by the end of the year. To Brian's point, that last estimated tax payment date would be a reason for them to try to get it done maybe a few weeks before then, in late November. That's the target. But, to Brian's point, it's a big technology project, and we've seen prominent displays through the years of technology rollouts that haven't gone well for the federal government. I'm sure they'll want to get this right. Fingers crossed it'll be there by the end of the year, but we'll have to see.

Question 5: Are buyers growing comfortable with signing tax credit transfer agreements early in the year for credits that will be generated later in the year?

Andy Moon: We recently wrote a blog post detailing some of the time-value-of-money scenarios under which a buyer can purchase a credit. Let me talk about the most optimistic scenario and get your thoughts on it. For 2024, the best case is when a buyer commits to buying credits at the beginning of the year for a project where they don't have to pay until later in the year. Let's say they commit in January, and the project is placed in service later in the year. The buyer can pay for the credits in Q3 or Q4 and, therefore, start offsetting their quarterly taxes even before any cash has gone out the door, right? As a business owner, you're almost getting working capital efficiency from the government, right? You're offsetting your taxes and you don't pay any cash until late in the year. Are buyers excited or comfortable with this approach? It's certainly what's been outlined in the regulations and is very attractive from a cash management standpoint.

Brian Murphy: Adam, I'll go first. There's an expectation from sellers who have been in this business for a while and view themselves as high quality: "You can count on our pipeline, our construction schedule, our delivery, and the substance of our credit." They are expecting that they'll be able to get the buyer comfortable that they can execute that contract in January, even though that asset may not come into service until November or December. With that added level of confidence, the buyer can start to layer credits into their estimated tax payments and get that - we'll call it, "full-year" - benefit of that time-value. That looks to be real in the market.

Those same high quality sellers would, I think, have an expectation that there may be other sellers in the market that aren't able to generate quite the same level of comfort for the buyer, and that that difference should start to generate some discount spread. Because that seller who says, "I'm high quality - you're going to get this time value," is probably also going to expect a smaller discount on the credit because they're going to want buyers to look at this holistically. What's the entire value impact for you? It's the discount and the time value.

Andy Moon: That's a great point. Just another factor that plays into what the headline discount rate might be on the credit.

Question 6: How are buyers thinking about placed-in-service risk?

Andy Moon: Adam, can you talk about the risk that a buyer signs a tax credit transfer agreement for credits from a project that should go into service late in the year, but [the project is not placed in service in time]? What happens in that scenario? Is the buyer stuck trying to find replacement credits? How does a buyer deal with that situation?

Adam Kobos: We're seeing different approaches in the market in terms of how to handle that risk. In some transactions, there's really nothing done to cover that risk. It could be that the parties decide to just walk away, and the transaction is never completed. But in the tax equity markets, some financing parties will charge a breakage fee. We expect to see that [mechanism] creep into some tax credit transfer transactions as well. If the seller fails to deliver a credit on time, they may owe some fee to the buyer to compensate the buyer for reserving that tax capacity and then not delivering on the credits. I think there are a couple different ways that could go. Maybe that risk could be factored into the upfront pricing - that is, that risk is priced in with a higher discount at the beginning and then absorbed by the buyer on a global basis. I think there are a few different ways for that to work its way through, and we're not seeing any one-size-fits-all approach. It's a bit all over the place right now.

Andy Moon: Our viewers love to go into the nitty-gritty details. There is one question about projects that are scheduled to be placed in service in December. We all know that developers are optimistic about construction timelines, and sometimes December projects end up getting placed into service on December 25th or they slip into January. Adam, how do buyers deal with that uncertainty around when, exactly, the placed-in-service date is on the project?

Adam Kobos: That is a tough issue. It's a tough issue, even in tax equity financing transactions, because the year when the project is placed in service is the year when you get the credit. There are return metrics and other things that make a difference. But in the tax credit transfer market, it's an existential risk. Obviously, buyers are going to be looking to fill or deal with tax capacity in various years. It may be that they need credits in one year but can't use or don't want them as much in the next. Maybe they've already reserved capacity. That's one issue.

The other issue is that the placed-in-service test is, unfortunately, a five-factor test. It's a gray area. If you've got none of the factors, you know you're not in service. If all of the factors are satisfied, you're in service. But if you have three or four factors, you're in this gray area. When that happens right around the end of the year, you could have serious questions as to whether it's in service in 2023 or in service in 2024. The problem is that there doesn't appear to be any way to account for that in the tax credit transfer registration process. You must pick the year and get it right. If you get it wrong, it's not really clear that your registration would carry over to the next year. In addition to all of this capacity stuff, you have a qualification issue. If you don't really know with certainty what year the project is placed in service, there's a chance of guessing wrong.

Brian Murphy: I have another thought on that, Andy. Sometimes a developer knows that they have zero of the factors right, and the project slides into 2024. We haven't seen a lot of it yet, but I do expect buyers to start looking for terms and conditions that carry some make-whole provision or some cure provision. If the buyer intended to acquire a 2023 credit or a 2024 credit, and the developer is unable to deliver that particular credit, the buyer might have to go to the market [for a replacement credit]. The make-whole provision would protect the buyer. But it may not be crystal clear when you get to December, January, or February whether you have a project that was in service in time.

Adam Kobos: In the tax equity market, for solar transactions, you have a two-step funding. If the ITC is at issue, the investor will often invest, say, at mechanical completion of the project with the further investment at substantial completion. Those bookends are there to deal with placed-in-service concerns. The first funding is on a date when you know the project hasn't been in service, and the last funding is on a date when you're certain the project has been placed in service. It may be that that bookend approach creeps into the tax credit transfer market where you say, "If we have a 2023 credit, we're going to want all of those factors to be satisfied before the end of the year. If we've got a 2024 credit, we're going to want to make sure that none of those factors were satisfied at the end of 2023."

Question 7: Will insurance companies take a view on placed-in-service dates for transferable tax credit deals?

Andy Moon: That's a great point, Adam. In the tax equity transactions, tax credit insurers are generally willing to take a view on placed-in-service date as part of the qualification insurance. Do you anticipate that they will also take a view on placed-in-service dates for transferable deals?

Adam Kobos: I think they should. I think they should be able to get there. That's a risk that they ought to be able to insure. We've seen policies where, initially, the placed-in-service date is carved out as an exclusion. But we've been able to get [insurers] to keep it as a conditional exclusion until the project actually is placed in service. I think their issue is they don't want to insure when the project is only mechanically complete that it will be placed in service in the future. But I think they're comfortable, with the proper diligence, insuring over that placed-in-service risk. I think the insurance market should get there.

Brian Murphy: Adam, I would agree. You just alluded to this - that this is probably more of an ITC issue than a PTC issue. And, Andy, I know we may talk a little bit later around how the market might view different credits and different components of that credit differently, but that's a great case in point that the extent you're going to market with ITC becomes very binary when you're in that December window.

Question 8: Are buyers expressing preferences for certain technologies and credit adders?

Andy Moon: Absolutely. Let's flip to buyer preferences in terms of technologies or various credit adders. I know, Brian, you have some thoughts. Maybe we start with you. What are you seeing from buyers in terms of their preference on technology or credit adders?

Brian Murphy: I've started to see a preference for established technologies, like wind and solar. We've also started to see a preference for the production tax credit. I think that's correlated to both the real and perceived simplicity of the credit and the amount of diligence it takes to get comfortable that the asset is qualified and may already be in service, producing the credit. Also, the math that goes with how much production tax credit did you generate is relatively straightforward compared to the ITC. The benefit of the ITC is that the value of that credit comes in at once, right up front. But there are other risk factors coming with that investment tax credit, particularly from the buyer lens. We just touched on some of them with Adam: Was that really in service on time? Do I know it's a 2023 or a 2024 credit?

But there's also the question around the basis of the energy property that's qualifying for the credit. In the tax equity market - Adam knows this as well as anyone else - for years, these investment tax credit deals have been put together in a manner where there is fundamentally a transaction that captures the step-up between the cost and that fair value to really optimize that investment tax credit.

There might be some question, and the developer owner says, "I just want to sell my ITC." Are they giving up something between their cost and fair value? How do they rethink their construction cycle, their structuring? Are there paths to get to it? But buyers are also going to say, "Well, there's more complexity to that investment tax credit. There are more things I have to understand. There's more risk. There's the clawback. There's the potential for recapture in the investment tax credit." I think those factors are going to start to creep into, not just terms and conditions, but also price.

Andy, I think you alluded to this - we haven't seen a lot of new or emerging technologies yet, but as they come on the scene in the future, they're probably going to have some risk-adjusted pricing associated with them, and we probably shouldn't leave out the fact that there will be nuclear production tax credits in the market as well. And, so, I do think buyers are going to look at these technologies differently.

I've also had indications from buyers that they want to understand the composition of the credit - the base credit and the bonus credit. They want to know, for instance, is there an energy community adder in there? Is there a domestic content adder in there? Without a doubt, I'm seeing a bias for simplicity for the base and the bonus credit. The adder that gets the most attention is probably domestic content. I am seeing large credit buyers out of the gate have a little bit of a preference for simplicity and not want to look at deals with a domestic content adder. The energy community, I think, is probably easier to get comfortable with as an adder. Maybe even easier than understanding for projects that were subject to the prevailing wage and apprenticeship. Did they check all the right boxes and accumulate enough to say, Yes, we absolutely have the bonus credit? So Adam, Andy, your views are obviously just as informed, if not more current than mine. Curious what you're seeing and you're thinking.

Andy Moon: I think there's a lot of great points you brought up with technology, credit type, and credit adders. Maybe we start with credit adders. On our platform, we have $3 billion of credits looking to be sold. We see very few with domestic content adders. Given the lack of clarity in the guidance, developers are also hesitant to add that into projects because the guidance was clear that you can't split the adder from the base credit. And so if there is a disallowance of credits for any reason, that will impact developers because they're on the hook for the indemnity.

Adam Kobos: I would say, with respect to domestic content, it is the hardest adder to work through. We're working with a couple of sponsors now who are committed to making it work, but it is very, very complicated. So, I think there are some strategies both on the solar side and on the wind side to get there, but the analysis that you have to go through is tough. I do think when the deals start coming to market, it's going to be novel. Getting financing parties and tax credit buyers comfortable is going to be an adventure. But I think we will see them. But, as both of you have alluded to before, some of the other adders are almost humdrum by this point. The fossil fuel adder, the coal closure adder - the IRS did a great job in making those just about as straightforward as they could be. I think the market's gotten comfortable with those, and we're seeing those in our deals now. The brownfield exclusion is a little trickier, but we're confident that we'll see those transactions financed as well, tax credits purchased from those.

Adam Kobos: I think Brian alluded to this as well. On the labor requirements, the regs are still new. I do think people are trying to figure out exactly what everybody wants to see from a buy side in terms of the support for compliance with the labor requirements. Will it be just reps or will there be some third-party report? What is that going to look like? I don't think we quite know yet what that's going to look like. But, again, I do think that's something fairly quickly that people are going to get comfortable with and transact on.

Andy Moon: We've also been seeing a lot of energy community.

Andy Moon: For prevailing wage, luckily, many 2023 tax-year projects are exempt because they started construction before January 29th. But in 2024, it's going to be a big issue to ensure that all the documentation is in place. And, Brian, I think you had some great points about there is a provision in the regs that if labor is underpaid during the construction process or during major repairs afterwards, that could trigger a reduction in credit. However, there is a cure period that's allowed where you can true up the payments and not be subject to a reduction in the credit level. However, you do have to know how to locate the people and provide the payment.

Question 9: What documentation should developers collect at the construction stage to ensure the prevailing wage and apprenticeship requirements are being met?

Andy Moon: Brian, any thoughts on what documentation would be useful to collect at the construction stage to ensure that PWA is met?

Brian Murphy: When we talk to our clients that have projects that started construction after January 29, they are going to have to meet this standard. The simplest message is collection of the data contemporaneously to give you the ability to identify those short pays and have a cure. But even if you have something miscategorized, at least to the extent you've contemporaneously collected the data, even a subsequent audit, you have that opportunity to take advantage of those cure provisions. I would caution developers and others to not take too much comfort in a strategy of, "Hey, EPC or contractor, you could accumulate the data, and, if and when I need it, I'll call you and you provide the data." I think that introduces a little bit of risk around the requirement of being able to accumulate the data, and provide the data to the buyer. So contemporaneously is - I don't know if it means weekly, biweekly, or monthly - but it is a cadence with your counterparties as a developer through the construction and placed-in-service cycle to collect it, analyze it, have access to it. Because those cure provisions are there, you just need to make sure you put yourself in a position to be able to avail yourself.

Brian Murphy: The worst thing will be, subsequent to an audit, you say, "Okay, you had contractor A, B, and C. We need the detail at an employee level of boots-and-gloves-on-the-ground," and they say, "Well, we just have a collective number and we can't unpack it." Let's go to the contractor and the contractor is not there, or the contractor doesn't have the records. Then to your point, Andy, your provisions may not be your lifeline if you don't have the ability to apply them.

Question 10: How are developers ensuring they have the correct wage determination?

Andy Moon: That's right. In terms of certifying the payroll and really ensuring that you're compliant with the Department of Labor's wage determination, we've heard of some developers that will do it manually - that is, track it in Excel and sign the forms. Others will use software providers, others will use consultants. There's plenty of Davis-Bacon service providers who are available. Are you seeing any preferences emerge in terms of how buyers and sellers are dealing with ensuring they have the correct wage determination?

Brian Murphy: I'll start, Adam. Particularly in this industry, when you get to utility-scale wind and solar, it's not an inconsequential number of parties that are putting boots and gloves on a work site. EY - and we're not the only ones in the market - we developed a tool and a process to help clients go through this. It works directly with the sam.gov website to repeatedly go back and make sure we have the right wages for when new employees come on, and mapping those jobs to the wages and trying to find those gaps and deal with them on a real-time basis. It's not that it's not possible to do manually, but you really want to make sure you don't underestimate the volume of data. It's simple in concept and execution, but it's really a heavy data-intensive exercise to accomplish, and to accomplish in a way that you have your records organized for your own purposes, for IRS, for buyer.  I ultimately look at this as somewhat of a due diligence process. The seller has an obligation to have a sell-side due diligence package available to that buyer, so they have comfort and confidence in the fact that this is a credit that they can acquire and take on their return.

Adam Kobos: I would agree with that. I think we're seeing all sorts of different approaches at this point, some doing it internally in an informal way through Excel or otherwise, some hiring third-party consultants for a deal-specific review of what's been done, and then others really trying to figure out systems internally. Some of our larger clients, utility clients, or other large IPPs figuring out how they're going to bring this function inside and maybe with some software solutions or outside consulting to get those systems in place. What is clear is that the regulations are not rocket science. When you read through them, they make sense step by step, it works. When you start thinking about how it's going to work in practice, your head explodes. I was working on an EPC contract this morning trying to get this on paper, and it's flow charts and if-then statements and decision trees - it really does get complicated. It does seem like the perfect thing for an in-house function or third-party service provider, somebody who's coming with expertise or develops that expertise to handle it. The industry will get there. But in the meantime, this interim period is going to be painful as we all try to figure out the ins and outs.

Andy Moon: Going back to buyer preferences, Adam, you mentioned a lot of buyers looking to get their first deal done in 2023. So given that PTCs can be simpler and don't have recapture risk, are you seeing a preference for PTCs or evenly split between PTC and ITC?

Adam Kobos: Our deal mix has been maybe in volume, overall credits may be tilted a little bit more to PTCs, but we've seen a lot of ITC deals. And some of that just has to do with the fact that tax credit transfers are the only way to monetize credits for some of these smaller deals. A year and a half ago, a standalone battery storage didn't qualify for anything. A renewable natural gas waste-to-energy facility didn't qualify for any credits. So the tax credit transfer, it's really the only game in town for some of these technologies that don't fit neatly into a tax equity structure or just got placed in service before there was time to get one in place. There is this like a glut of novel, sometimes smaller, deals that are ITC weighted. But the points that both of you have made earlier, PTCs are so much easier to deal with. The qualification issues for the ITC are really complicated, particularly when you've got projects owned in a pass-through form. Some of the disqualifying rules are really difficult to deal with. Then this concept of recapture -  something after the project has been in service could invalidate the credit that you took a few years ago. That's just a tough issue to deal with. PTCs are simple and attractive from a buyer perspective, no doubt.

Andy Moon: We're excited about the possibility of providing financing that didn't exist before on some of these smaller projects. I think that's always been the promise of transferability: that it's not just the huge projects that get funded. In 2023, I think there are buyers that prefer established counterparties and large projects to do a  discrete, bilateral transaction. But I do think that the creativity for mitigating risk on the smaller portfolio is going to be exciting.

Adam Kobos: Andy, to that point, I think that is really the promise of tax credit transferability. The tax equity market is incredibly selective and, at this point, oversubscribed. The large tax equity providers get to pick their sponsors, and they're going to pick the sponsors that they've worked with. They're going to pick the sponsors who are the most established, the most reliable, and those sponsors are delivering huge amounts of projects. The promise of tax credit transfers is allowing people to monetize the tax benefits from some of these projects that are either developed by smaller sponsors who don't have access to tax equity, or it might be projects that don't fit neatly into the tax equity framework - projects like a standalone battery project that the owner would like to operate merchant. Tax equity providers aren't going to be comfortable with merchant projects. But if you can make more money that way and then sell your credit, that looks very attractive. I think there are classes of projects that really fit neatly into the tax credit transfer market, which is one of the exciting things about this market. It's going to grow the tax credit monetization pool significantly.

Question 11: What are buyers expecting on indemnity coverage?

Andy Moon: Absolutely. We got a lot of great questions from readers about the details of what's market in terms of transactions. Maybe we can go through these in a bit of a lightning format. There's a lot of questions. Brian, what are buyers expecting on indemnity coverage?

Brian Murphy: Without a doubt, buyers coming to market want to view this transaction as almost debt - time-value-of-money. Mitigating risk is the name of the game. To some of the points Adam just made, those are the reasons I think I'm seeing and will continue to see a lean toward PTC. It's what's the simplest digestible transaction where an indemnity is something that can be drafted that will be really effective to sit right on top of the PTC. And the timeline, the realization for the PTC, I think brings a lot of comfort. The ITC with the recapture has a long tail. So, I think we're going to see indemnities that are crafted to really give a buyer the comfort that this looks and feels like a debt transaction. They just want to make whatever that spread is on the time value and the discount, and almost view this as a treasury function and not an investment in renewable energy or the project.

Adam Kobos: I would agree. If you spend 95 cents on a tax credit, expecting to get a dollar and you lose the 95 cents, it's a nightmare. Buyers are looking for airtight indemnities and credit support. So it's a creditworthy, guarantee, tax insurance, letter of credit, something to backstop the indemnity.

Andy Moon: Indemnity payments are taxable to the seller, and so sellers generally have to gross up the payments to account for taxes.

Adam Kobos: That's an interesting question. The discount, the portion of the discount might be taxable, probably is taxable. If we can characterize the indemnity payment with respect to the purchase price as a return of purchase price, then maybe it's not taxable. I can't speak very confidently about that. We don't have the guidance we'd like to have, and the issues are a little bit abstract. But there may be an argument for non-taxability. But I think buyers are going to insist on the payment being made after tax. So, whatever the answer is, they're going to want to be grossed up if they need to be grossed up to be made whole.

Question 12: What are buyers looking for in terms of seller creditworthiness?

Andy Moon: What are buyers looking for in terms of seller creditworthiness?

Adam Kobos: That'll vary. So the credit determination - and I'm a tax person, so I'm not there in terms of evaluating credit - if they're looking at a credit from a major utility, there's going to be a creditworthy parent and the structure that's going to provide the buyer with the comfort that it needs. But if it's a small sponsor or if it's a private equity-backed sponsor, there may not be a guarantor for the buyer to go after, at least as a first resort. So, tax insurance is really going to be a tool in many of these transactions that will need to fill the gap.

Brian Murphy: Let's talk about the quality of seller and how that correlates to price and risk management. If I focus on the regulated utilities, in most instances, they are going to have an expectation that they have a certainty of revenues and that there's pros and cons to that regulatory overlay. I think some of the pros would be that the regulated utility would say, "My balance sheet is incredibly strong, my outlook is strong, and my indemnity is solid as a result of my balance sheet and the nature of my regulated business." I would say as a seller, regulated utility, it's probably double-sided that as they go into the market and they look to sell credits, that they have that additional layer that may create some comfort that the credit is a good credit with a good balance sheet behind it. But it also injects for the utility the situation where ultimately the regulator may look back and say, "Well, when you sold credits, what price did you get? How did that compare to the market?"

Brian Murphy: I think regulated utilities may look through that lens, and in order to ultimately feel good about the price and that the price will hold up to scrutiny on the sale, not just by their shareholders, but by their regulators. I expect they may take advantage of a variety of contracts and platforms. Andy, you and I talked about everything Reunion is doing and what EY is doing. EY will ultimately run a different type of credit sale market and auction process. One of our thoughts would be, well, that auction, even if it's only periodic by a utility, gives them checkpoints that they are really selling at a market price. I think there's a lot of pros and cons for the utility and for a buyer interacting with a utility.

Question 13: Will utilities be net buyers or net sellers of tax credits?

Andy Moon: We've seen utilities on both sides of the ledger. We've seen utilities looking to sell credits out of projects they own. We've also seen utilities looking to purchase tax credits as well. Where do you think the market shakes out on average? Will utilities be net buyers or sellers of credits?

Brian Murphy: I expect net sellers for a while. I think we're still in that NOL period. The sale of these credits are going to be very attractive to the utility. Most utilities - Adam, you know better than anyone else - really haven't found their way into the tax equity market. A lot of depreciation and credits have accumulated on their balance sheet. But I do see in short order, in years '24, '25, '26, more and more utilities running off that balance sheet and starting to see themselves flipping into a net buyer position. But I guess the observation is every utility should be a buyer or a seller. To sit on the fence and have just enough credits, but not too many, is not probable.

Question 14: Are developers finding ways to step up their basis in transfer deals?

Andy Moon: Earlier, Brian, you touched on basis step-ups in transfer deals. We've seen a lot of interest in developers finding ways to step up the basis. We have not seen that many in practice, but I would love to hear what you both are seeing.

Brian Murphy: I would say two things. One, the market is considering if there is room for tax equity and credit transfer in the same structure. For the traditional banks that have been that tax equity investor, does this transferability provision potentially give them a little more capacity? If they, at any point, see themselves potentially long on credit, they now have an ability to direct that partnership to sell the credits instead of allocating them out. So, there may be an opportunity for some hybrid [structures]. Second, I also see a strong migration to PTC away from ITC. Some of that migration, even in the solar space, has been from a general improvement in the technology. So, as prices come down to build a particular solar facility, and its output and its efficiency start to go up, the math just continuously starts to creep away from ITC and toward PTC. I see an evaluation of portfolios - which projects are economically ready to make that flip into the PTC? And are those the projects that may move first to the line in terms of credits that are going to be brought to the market for sale?

Andy Moon: That's a fascinating insight. I'll comment on the tax equity hybrid model. We are strong believers that many tax equity partnerships will look to transfer credits just given the fundamental shortage of tax equity. It's much harder to get tax equity done than it was even six months ago. We've talked to a number of banks that are fully committed for all of 2024. We strongly believe that partnerships will look to transfer credits to make room for more investments.

Adam Kobos: I would agree with that. I think it's now common, maybe universal, in tax credit or tax equity deals that we're working on to provide that functionality for the partners to sell down their tax credits. For the big tax equity investors, that's  part of what they're going to do. They're going to want that flexibility. That hybrid structure is attractive because they're monetizing depreciation as well, and that's one of the things that can get lost in a pure tax credit transfer deal. But, in addition to that hybrid tax equity structure, we're seeing a lot of interest among sponsors to figure out ways to step up the basis. Even if they're not going to go down the road of a traditional tax equity structure, there are "cash equity investors" out there offering products by which they'd invest alongside the sponsor in a partnership. The sponsor would develop a project, and its development affiliate would sell to this joint venture between another affiliate of the sponsor and this outside investor. If structured in the right way, you can affect a basis step up, have that new partnership, and sell the tax credit deal. Those deals get a little bit complicated, and at the end of it, people are asking the question, "Well, why didn't we just do tax equity?" But, if you get over that, I think we're going to see those structures as well.

Andy Moon: Adam, that's a bit of what I was getting at. We've also heard of those structures and know a couple of funds that are interested in taking minority stakes in these types of projects. From a legal standpoint, there are a couple of questions there. One is, if you sell, what percentage of the stake do you need to sell to a third party? Is 20% sufficient? And, second, if the minority investor is taking a preferred equity return, will that be respected by the IRS as a true equity investment, or does that look too much like debt?

Adam Kobos: Without commenting specifically on numbers, those are exactly the right questions. In structuring these transactions, we've taken the view that you can analyze them by principles that operate in the context of tax equity. That debt-versus-equity question, that runs right through tax equity investments. What is the size of the investment? How significant a component does it have to be? That runs through the tax equity financing structure as well. Some of those partnership questions that we'll work through on the investor side as we're structuring deals, they're going to migrate over to those cash equity deals as well. But not to tip my hand too much, the partnership flip revenue procedures provide some thoughts as to what maybe that residual interest ought to be and [define] some of the upfront economics or parameters you've got to live by. Those might help inform some of the structuring questions. But we're seeing a big variety of structures in the market trying to address this cash equity question and, Andy, structured with the concerns you have in mind.

Question 15: Where will we see basis step-ups in the next few years?

Andy Moon: Absolutely. Let me end on a fun and, perhaps, controversial question. We're seeing Bank of America and JPMorgan capping step-ups at 15-20%. I think some insurers are still willing to insure step-ups a bit higher than this. Looking to the crystal ball, where do you think step-up shake out? In two years, will there be step-ups in the 20% range? Greater than 30%?

Adam Kobos: That's a good question. You are right that there are segments of the market that put caps on step-ups. In the deals that we see, we see a wide range of step-ups, ranging anywhere from 15-20%, 40%, and north of 40%. And tax practitioners, I think, have different views about this. I am, from a methodology perspective, biased to the income approach. I'm not a valuation expert. But the appraisers are thoughtful and conclude as to a higher step-up, there are some projects that are just worth more than other projects. From a tax lawyer perspective, I'm okay going above that. From a risk management perspective, investors and buyers have to decide how high they want to go and do they want to fall outside of the herd. That's a more complicated, nuanced question, and you see buyers and investors going different ways there. Brian, I can't wait to hear what you have to say on this.

Brian Murphy: I agree with everything Adam said. As a tax practitioner, that 15-20% that we've lived with now has no real substantive technical merit. Adam's spot on that there should be a perfect correlation to the risk and complexity of development of a project to what should be earned by the developer who took that risk. To say it's 15-20% is somewhat arbitrary. From a tax technical perspective, being able to have projects with the right fact patterns that go well north [of 15-20%] makes all the sense in the world. I do think from an insurance and a buyer perspective - and tax equity has, I think, contributed to this comfort - that being within 15-20% gives you a little security moving to the middle of the pack and not being on the edges. I think there's going to be continued preference for more historically comfortable ranges in the development fee that are in that window or south. That bothers me from a purist perspective because I think there are projects that are probably claiming that may not warrant 15-20% but feel comfortable in that window. And there are projects that probably took tremendous risk and time to develop that weren't more than that, that are constraining themselves to be acceptable to counterparties in the market.

Andy Moon: Brian and Adam, this has been an awesome conversation. Thank you so much for joining today. As everybody can hear, there's a lot of activity in the market. Q4 is going to be exciting. We hope to work with you both. Thanks again for appearing on the show today.

Brian Murphy: Looking forward to it. Thanks for having us, Andy.

Adam Kobos: Thank you, Andy.