Reunion's Market Monitor Q2 2025 Report

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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Listen on Spotify or Apple

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.

On January 19, the IRS released key guidance for the §30C alternative fuel vehicle refueling property credit. The guidance included two appendices that identify eligible census tracts depending on a project's placed-in-service date. Alongside the guidance, the IRS issued a press release and an FAQ.

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Takeaways

1. The Inflation Reduction Act extended and meaningfully modified the §30C ITC 
2. 99% of U.S. territory is included in eligible census tracts
3. Eligible locations will vary depending on when a project is placed in service
4. DOE published a mapping tool that shows eligible areas with placed-in-service filter
5. Ambiguity around definition of "single item" with respect to credit qualification remains a gating factor
6. Further guidance is coming

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TAKEAWAY 1

The Inflation Reduction Act extended and meaningfully modified the §30C ITC 

The §30C ITC existed prior to the Inflation Reduction Act (IRA), and the guidance reminds us of the ways in which the IRA modified the credit.

Added prevailing wage and apprenticeship requirements

‍The §30C is subject to the IRA's prevailing wage and apprenticeship (PWA) requirements. If a developer meets PWA requirements, the §30C credit value increases from 6% to 30% of eligible costs. Considering the economics, virtually all developers will meet PWA requirements.

Increased credit maximum

‍The IRA increased the maximum credit value that an eligible property can receive. For businesses, the cap is $100,000 per "item of property."

Modified eligibility scope

‍The IRA modified the scope of the §30C ITC "so that it no longer applies per location and instead applies per single item." Notably, although the guidance provides several definitions, it does not define what constitutes a "single item." We'll comment on this below.

Narrowed applicability to non-urban areas, low-income communities, and, with this guidance, U.S. territories

The IRA requires a §30C-eligible property to be placed in service in an eligible census tract – that is, any population census tract that is a low-income community, a non-urban area, or a U.S. territory.

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TAKEAWAY 2

99% of U.S. territory is included in eligible census tracts

According to the guidance, three broad areas are eligible for the credit:

• Non-urban areas: For purposes of the §30C credit, the IRS defines a non-urban area as "any population census tract in which at least 10 percent of the census blocks are not designated as urban areas.” Many market participants have been referring to non-urban areas as "rural areas."
• Low-Income communities: The IRA defined a qualifying census tract as one described in Section 45D(e), which defines a low-income community for purposes of the new markets tax credit (NMTC). The guidance, however, notes that NMTC data was recently updated and provides a transition rule under which developers can rely on designations using the older or more recent data.
• U.S. territories: The guidance allows refueling properties located in U.S. territories to qualify for the credit. However, the property must be owned by a U.S. citizen, U.S. corporation, or a U.S. territory corporation. (Inhabited U.S. territories are American Samoa, Guam, the Northern Mariana Islands, Puerto Rico, and the U.S. Virgin Islands.)

According to the Electrification Coalition, an industry group, the areas in which eligible property can be installed "will include approximately 99% of U.S. land territory and 62% of the population."

This is particularly good news for expanding electric vehicle adoption because, without the §30C tax credit, installing EV charging infrastructure can be prohibitively expensive in rural areas where there are fewer vehicles in the first place.

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TAKEAWAY 3

Eligibility of a census tract depends on when a project is placed in service

The guidance also provided two appendices that list qualified census tracts depending on when a project is placed in service (PIS):

• PIS after 12/31/22 and before 1/1/25: Appendix A or Appendix B
• PIS after 12/31/24 and before 1/1/30: Appendix B

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TAKEAWAY 4

DOE published a mapping tool to streamline siting analyses

To strengthen implementation efforts, Argonne National Laboratory within the Department of Energy (DOE)  published a §30C Tax Credit Eligibility Locator mapping tool and an FAQ.

To help developers select the appropriate census tract for their project's placed-in-service date, Argonne accompanied the map with a decision tree.

The mapping tool, however, is for informational purposes only and "may not be relied upon by taxpayers to substantiate a tax return position and will not be used by the IRS for examination purposes."

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TAKEAWAY 5

Ambiguity around definition of "single item" with respect to credit qualification remains a gating factor

The guidance did not fully clarify what equipment constitutes a "single item" with respect to credit qualification. As Canary Media notes, electric vehicle "charging sites also have a lot of 'shared equipment' such as power conduits, switchgear, transformers and enclosures," and there are "still questions of whether [the credit] will cover just the charger, or additional factors to installation like upgrading power infrastructure."

The definitional ambiguity presents financial challenges for developers who want to transfer their tax credits because they don't yet know what their credits will be worth.

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TAKEAWAY 6

Proposed regulations still to come from the IRS and Treasury

Fortunately, the guidance states that further guidance is forthcoming. Reunion believes this additional guidance will likely address the definition of a "single item," given the gating nature of its ambiguity.

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In December 2023, the IRS issued Notice 2024-9, which details how "applicable entities" can satisfy the Inflation Reduction Act's domestic content requirements when using elective pay (which is often called "direct pay"). In particular, projects beginning construction on or after January 1, 2024 may have the value of their tax credit reduced if domestic content requirements are not met.

The IRS refers to the time-based credit reductions as the "statutory elective payment phaseouts."

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Applicable credits

The required use of domestic content under elective pay applies to the following credits:

• §45: Electricity produced from certain renewable sources
• §45Y: Clean electricity production credit (technology-neutral PTC)
• §48: Energy credit
• §48E: Clean electricity investment credit (technology-neutral ITC)

Details for each credit can be found in our overview of IRA tax credits.

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Applicable entities

Applicable entities subject to the statutory elective payment phaseouts include:

• Organizations exempt from income tax
• Any state or political subdivision thereof
• The Tennessee Valley Authority
• An Indian tribal government
• Rural energy cooperatives
• Alaska Native corporations

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Credit reduction

The percentage of credit available to an applicable entity making a direct pay election is determined by multiplying the credit value by an "applicable percentage." Applicable percentages are as follows:

• 100%: Project meets domestic content requirements and/or has a net output of less than one megawatt (alternating current)
• 90%: Project begins construction on or after January 1, 2024 and doesn't meet either of the "100%" requirements
• 85%: Project begins construction on or after January 1, 2025 and doesn't meet either of the "100%" requirements
• 0%: Project begins construction on or after January 1, 2026 and doesn't meet either of the "100%" requirements

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Exceptions

The IRS provided two exceptions to the domestic content requirement. If either exception applies, the applicable percentage is 100%.

• ‍Increased cost exception: The inclusion of steel, iron, or manufactured products that are produced in the U.S. increases the project's overall costs of construction by more than 25%‍
• Non-availability exception: The relevant steel, iron, or manufactured products are not produced in the U.S. in sufficient and reasonably available quantities or of satisfactory quality

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Attestation

Applicable entities can claim one of the above exceptions from the phaseout by attaching an attestation to the relevant tax form claiming the credit – form 8835 or form 3468.

The attestation must:

• Be signed by an individual with the power to bind the applicable entity in federal tax matters
• Be made under the penalties of perjury
• State that the entity has reviewed the requirements for each exception and has made a good faith determination that one or both apply

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Q1 2024 Newsletter

January 22, 2024

Welcome to the new year and our Q1 2024 newsletter.

The transferable tax credit market is accelerating quickly, and so is Reunion. We have several updates we'd love to share you — from a first-of-its-kind tax credit transfer, to news of our marketplace crossing $4 billion in tax credit opportunities.

Tax credit transfers will drive a significant increase in clean energy deployment in 2024, and we look forward to keeping you up to date!

Andy Moon, CEO

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An innovative tax credit transfer for commercial rooftop solar

Reunion celebrated the new year by facilitating an innovative tax credit transfer from a portfolio of commercial rooftop solar installations. The transaction represents the promise of transferability: enabling clean energy projects that have historically struggled to attract financing.

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Major updates to our transferable tax credit handbook

We recently unveiled version 2.0 of our 100-page transferable tax credit handbook, after receiving fantastic feedback from the market on our initial release.

Our latest edition includes an overview of the IRA's 11 transferable tax credits as well as comments on the latest Treasury guidance.

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Read our 2023-2024 pricing review and outlook

In January, our team published our inaugural pricing review and outlook, based on our transactional experience and hundreds of conversations with tax credit buyers and sellers. In the article, we share pricing observations from 2023 and predictions for 2024.

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Our marketplace now features over $4B in tax credits

Our marketplace has grown rapidly since our launch in June 2023. We now have over $4B of tax credits available across solar, wind, battery storage, advanced manufacturing, and other clean energy technologies.

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Reunion is hiring

Our team continues to grow! We have several open positions available and would love your help finding great folks.

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Stay tuned on LinkedIn

You can catch our latest insights and news on LinkedIn. We hope you’ll follow us and join the conversation.

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2023, the first full year of the Inflation Reduction Act, is officially behind us. As year-end approached, transactions closed in lockstep with the release of further IRS guidance and other market-enabling milestones.

With the turn of the calendar, we wanted to share our 2023 pricing observations and 2024 pricing predictions.

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Overview of tax credit transfer pricing

Transferable tax credits are sold at a discount per $1.00 of credit, and the discount is the primary incentive for a buyer to enter into a tax credit transaction. A corporation, for example, buying credits for $0.90 would pay $90M in cash in exchange for $100M in tax credits. The company would realize $10M of savings, which is not treated as gross income and, therefore, not subject to taxes.

The net price the seller receives for the credit is typically the buyer’s purchase price less the cost of tax credit insurance and transaction fees (e.g., fees paid to a platform or facilitator such as Reunion).

Looking back on 2023 pricing

The market for transferable tax credits remains nascent, as transactions started in earnest following Treasury guidance on June 14, 2023. We have found that offers (and closed transactions) for 2023 tax-year credits are within fairly narrow pricing bands based on risk/complexity.

Across these pricing bands, projects with more scale have tended to drive smaller discounts.

§45 production tax credits (PTCs)

§45 PTCs are the simplest transaction to execute, as the credit is straightforward to validate. Buyers commonly review production reports and related documents to confirm that electricity was produced from an eligible project type and sold to an unrelated third party. Importantly, §45 PTCs do not carry recapture risk. 

Current-year PTCs have been trading in the $0.94 to $0.95 range. Buyers who have committed to paying for PTCs that will be generated in future tax years have received larger discounts.

For a deeper understanding of how pricing dynamics and forward commitments affect transaction structures, refer to our Section 45 PTC transfer case study, which explores a real-world transaction and deal specifics.

§48 investment tax credits (ITCs)

§48 ITCs carry more complexity. The buyer will need to validate the cost basis used to calculate the ITC as well as the tax year that the project was placed in service:

• Cost basis: If the cost basis has not been properly calculated, the credit can be subject to disallowance by the IRS
• Placed-in-service date: The project must be placed in service in the desired tax year; if a project is placed into service in a later-than-expected tax year, the tax credits can be carried back up to three years but the process is not straightforward

§48 ITCs are subject to recapture rules, which require that (1) the property remains a qualified energy facility for five years, and (2) there is no change in ownership for five years. If these conditions are not met, the IRS will recapture the unvested portion of the ITC (the ITC vests equally over a five-year period). 

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2023 summary pricing

The discount is only one financial metric. Many buyers are also interested in timing of cash flows

While the discount is often the first question that we receive about tax credit pricing, it is not the only metric to evaluate the financial return of a tax credit transfer.

The timing of cash flows from a tax credit transfer is also important to buyers. Treasury’s June 2023 guidance clearly states that a “transferee taxpayer [i.e., a tax credit purchaser] may also take into account a specified credit portion that it has purchased, or intends to purchase, when calculating its estimated tax payments.”

Below are several examples of how timing of a tax credit purchase can impact returns (assuming buyers purchase credits for $0.90):

Finally, buyers commonly request to delay payments for a tax credit transfer to line up with their quarterly estimated tax payments. This is a key negotiation point, as sellers prefer to get paid as soon as possible after credits are generated.

Going forward, we expect delayed payment terms to result in a smaller headline discount for the buyer, since the seller will want to be compensated for their cost of capital.

In September 2023, we wrote a detailed discussion on buyer returns and also made a returns calculator available for download.

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Looking forward to 2024 pricing

As we consider macro-level tax credit pricing in 2024, two major themes come to mind: increased credit supply and market bifurcation. The former is an emerging trend, while the latter extends from 2023.

Increased tax credit supply

Early analysts predicted that discounts would shrink as the market matures. We do not believe this is a foregone conclusion.

There is a significant increase in supply of clean energy tax credits for the 2024 tax year; Reunion’s digital platform already lists over $3 billion in tax credit opportunities for the 2024 tax year. This increased volume of tax credits looking for buyers will put downward pressure on pricing, at least until buyer demand grows commensurately.

In contrast, the supply of 2023 tax year credits was constrained, with a relatively small number of projects for buyers to invest in.

Continued market bifurcation

Heading into 2024, we believe that the market will bifurcate: certain credits will demand premium pricing while other credits (e.g., uninsured ITCs without an indemnity from a creditworthy guarantor) will need to offer a deep discount and/or novel ways to mitigate risk.

Common project types that will garner premium pricing include:

• §45 PTCs from solar and wind with an indemnity from a creditworthy guarantor or tax credit insurance. Certain §45X credits from advanced manufacturers will trade at a premium, if the size of the credit is significant and the seller provides a creditworthy guarantee or tax credit insurance
• §48 ITCs from sizable solar or battery projects (larger transaction sizes will demand a premium price), with an indemnity from a creditworthy guarantor or tax credit insurance
• §48 ITCs from solar or battery projects sold out of tax equity partnerships with experienced sponsors and tax equity investors

2024 summary market drivers

Overall, our view is that risk/complexity and scale will be the two main drivers of pricing. Projects that present buyers with lower risk and greater scale will, ultimately, enjoy higher pricing.

How Reunion helps

The Reunion team is available to meet with buyers looking to purchase 2023 or 2024 tax-year credits, and is also available to answer questions for those looking to learn more about the rapidly growing tax credit transfer market.

Please find us on LinkedIn or email us at info@reunioninfra.com.

Introduction

In episode 5 of 10 Questions with Reunion, our president, Billy Lee, sits down with David Kinzel of Marsh to discuss tax credit investor default insurance. Marsh designed this innovative and evolving insurance solution as a "credit enhancement" for buyers of transferable tax credits who are considering forward purchase commitments.

As David notes, tax credit investor default insurance has the potential to meaningfully "expand the universe of buyers well beyond what it is today and add more liquidity to the transferability market."

Listen on Spotify or Apple

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

Guest: David Kinzel, Structured Credit & Political Risk Insurance Consultant, Marsh

David Kinzel is a Vice President in Marsh's Structured Credit and Political Risk group. Marsh is the largest insurance broker in the world.

Takeways

• Credit insurance expands the universe of potential buyers of transferable tax credits. By providing a credit enhancement to would-be transferable tax credit buyers, credit insurance allows more companies to buy tax credits on a forward basis. According to a Marsh analysis, over 1,400 companies could be eligible.
• Credit insurance is relatively new with respect to transferability. Insurers are beginning to explore credit insurance for transferable tax credit transactions, which should expand the scope of eligible deals.
• Underwriting is evolving but relatively straightforward. Underwriters will consider the financial strength of the buyer, the experience and reputation of the developer, the duration of the commitment, and the experience of advisors involved in the transaction.
• A credit insurance policy has three parties: the developer, the buyer, and the lender. The developer would be the insured, the buyer would be the insured counter-party, and the lender would be the "loss payee," or the party who would have rights to the policy proceeds in the event of a valid claim. The lender generally provides a bridge or construction loan to the developer.
• Many privately held companies would be insurable. Companies without publicly rated debt, including privately held companies, would be eligible for tax credit insurance.
• In the event of default on the forward contract, the insurer could become the purchaser of the credits. If the tax credit buyer doesn't perform on the forward commitment, the credits haven't been transferred. Therefore, the insurer could purchase the credits as part of their recovery.
• Coverage will usually cost less if an insurer has more recovery options. Insurers look for multiple pathways to being made whole, and the more pathways they have lowers the risk of the deal.
• ‍A good starting point for the cost of credit insurance is an annualized 1% of the commitment amount. Pricing would likely go down for higher credit qualities and shorter durations. Pricing would likely go up for more challenging credits and longer durations.

Video

Video Chapters

• 0:00 - Introductions
• 2:05 - Question 1: How can credit risk insurance be applied to tax credit transfer transactions?
• 4:43 - Questions 2 and 3: How deep is the tax credit investor default insurance market today? How deep could the market become?
• 6:00 - Question 4: What would underwriting and due diligence look like for investor default insurance?
• 8:21 - Questions 5 and 6: Could any tax credit buyer be insured? Why would a tax credit buyer need a credit enhancement?
• 11:01 - Question 7: How would a tax credit investor default insurance policy be structured?
• 12:26 - Question 8: How could an insurer "step into the shoes" – that is, become the purchaser of the credits – of a buyer in the event of an insurance claim?
• 14:27 - Question 9: Theoretically, will coverage cost less if insurers have more recovery options?
• 15:06 - Question 10: How much does this insurance cost today? How much do you think this insurance will cost over time?

Transcript

Introductions

Billy Lee: Hello, and thank you for joining 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 David Kinzel, Vice President of Structured Credit and Political Risk at Marsh. I'm excited to speak with you, David, because risk management – that is, the comprehensive identification and proper allocation of risk – is core to the tax credit marketplace. Innovations around risk management are critical to growing this market.

Let's get into it. David, for starters, can you tell us who you are, what you do, and where this webinar finds you today?

David Kinzel: Thanks, Billy. I appreciate you having me here today. I am part of Marsh's Credit Specialties Division. For those who don't know, Marsh is the largest insurance broker in the world but has teams who are specialized in niches within the insurance world – mine being credit and political risks. I've been working in the world of credit risk for over 15 years and have a lot of experience in political risk (but that's an interesting topic for another day).

Billy Lee: David, where are you calling in from?

David Kinzel: I'm based out of Denver, Colorado.

Billy Lee: Excellent. Insurance in the context of tax credit transferability usually focuses on tax credit insurance, where an insurer is covering the risk that a tax credit is disallowed or recaptured by the IRS. With transferable tax credits, this insurance is important because, generally, buyers bear this risk, and sellers often do not have the balance sheet wherewithal to stand behind their indemnities.

Question 1: How can credit risk insurance be applied to tax credit transfer transactions?

Billy Lee: You and I had an interesting discussion the other day about how credit risk insurance could also be applied to tax credit transfer transactions, specifically in the context of forward commitments. Can you provide some detail here?

David Kinzel: Yes, we had an interesting dialog. And, to be clear, credit insurance is different from what our talented tax credit insurance team does. Our team is focused on more of a credit enhancement for the tax credit buyer.

We can take a step back to get a little bit more context. Credit insurance covers the default of a financial obligation. The market has been around for years but has been evolving over the past decade or so. Recently, we've been looking into more complex transactions beyond short-term trade receivables. We've been looking at insuring the default of a project finance loan and we've been looking at insuring offtake agreements. (Under a power purchase agreement, there's credit risk as well.) It's a creative and evolving segment of the insurance world.  

When we look at transferability, we're thinking of credit enhancement for the tax credit buyer who makes a forward purchase commitment. We're effectively insuring the financial commitment of the tax credit buyer. From our understanding and our discussions, it seems like lenders – whether it be bridge lenders or construction lenders – have a binary view of the credit risk of the tax credit buyer. They say, "If that tax credit buyer is investment grade, we can fund the project. If they're not, then you need to find a new tax credit buyer."

So, we see credit insurance as an opportunity to open up the universe of eligible tax credit buyers.

Billy Lee: When a developer is seeking a forward commitment to sell their tax credits to a buyer – that is, they are starting construction on a project that's going to take two years, they want a buyer to be there in two years to buy the credits, but they want to contract now – the creditworthiness of that buyer is important because, typically, a developer is entering into that contract to finance that bridge loan. When we have buyers who may not be as creditworthy, then your product could come in handy.

David Kinzel: That's exactly right. Perfectly said.

Question 2: How deep is the tax credit investor default insurance market today?

Billy Lee: How deep is this market? Maybe it's not deep today, but how deep do you think it can become?

David Kinzel: As you said, Billy, it's a new market. It's evolving as we go, so it's hard to give concrete numbers. But we, Marsh, are building out this market. There's a lot of insurer interest. A lot of insurers have expressed interest in diving into this market. And, once they understand more about insuring these risks, I think there's going to be a short-term and a long-term approach.

When we say short-term, insurers are probably going to have more appetite for vanilla transactions. We're thinking ITCs because of the shorter duration of the risk that they would be taking on. We're thinking there could be anywhere up to $100 million per transaction. So, $100 million of tax credits or commitments could be insurable, which, from my understanding, should cover the majority of the transactions that are going on today or in the near future.

Question 3: How deep could the market become?

David Kinzel:  When we look to the longer term, there's going to be a lot more appetite for more complex transactions. PTCs could become eligible, given their longer term nature of credit risk.

Question 4: What would underwriting and due diligence look like for investor default insurance?

Billy Lee: What would the underwriting for a credit transaction of this type look like? What would the diligence be? I imagine it would be much different than your typical tax credit insurance.

David Kinzel: It's evolving. Initially, we think that underwriters are going to take a conservative and traditional view of the risk.They're going to dive into the credit risk of the tax credit buyer by looking at audited financials. How creditworthy are they to make this investment? Is there anything coming up that could impact their ability to make that investment when the time comes and the tax credits are available? Ultimately, that's going to be the first layer underwriters are going to look at. You have to pass that test.

Then, once they drill deeper, they're going to look at the developer. Does the developer have a good reputation? Are they reliable?

Underwriters are going to look at the duration of the forward commitment. A six-month commitment is going to be different from a 24-month commitment. So, duration – from the time the tax credit transfer agreement is signed to the time that the tax credits are transferred – will be part of the analysis.

Many people want to know, "Are insurers going to dig into the underlying contracts? Are they going to want to see all these contracts and get into the details?" The answer is no. However, they're going to want to see portions of the tax credit transfer agreement. It's important to clarify that they're insuring the default of a legally enforceable obligation. If, for some reason, there's a situation where one of the tax credit buyers says, "We found a way to back out of this commitment because of one of the clauses within the agreement," the insurers aren't looking to provide protection for a bad contract. It's important to just make that clarification and distinction.

It's also important to say the underwriters are probably going to look at what advisors are involved in these transactions. If there are advisors like you, Billy, who have a lot of experience in structuring these transactions and getting clean documents together, that's going to give them comfort as well.

Questions 5 and 6: Could any tax credit buyer be insured? Why would a tax credit buyer need a credit enhancement?

Billy Lee: You mentioned something interesting about insurers analyzing audited financials and credit. I guess the question is, could any tax credit buyer be considered an insured? And, if a potential buyer has to have some minimum level of credit, does that defeat the purpose of insurers? If you have credit already, why do you need a credit enhancement?

David Kinzel: Those are really good questions. Not every tax credit buyer would be considered insurable. But I don't believe that defeats the purpose of the insurance, and I'll explain why. In the short-term, we expect the insurer's appetite is going to be for more S&P BB risks. So, one notch below investment grade is probably where there's going to be the most appetite. This is also good for privately held companies – companies without publicly rated debt. That is something that the credit insurance market is comfortable with. Looking at financials and backing into an implied rating is something they're doing on a regular basis; that's not going to be a problem.

Where we get excited is we've done some analysis of S&P data and looked at the universe of all the rated entities in the United States. If you look at who is investment grade, there's approximately 1,200 investment grade issuers in the United States. That says the potential universe of companies that can invest in tax credits on a forward commitment is around 1,200 – a big number. But what could we do differently? If we go down the credit curve and say BB entities are eligible, maybe even B entities, that adds another estimated 1,400 entities.

On top of that, if we look at privately held entities that don't have public debt, or if we look at U.S. subsidiaries of a foreign parent where the parent may be investment grade but doesn't want to give a parental guarantee – there are many situations where this could come into play. We see credit insurance as an opportunity to expand the universe of potential buyers well beyond what it is today and add more liquidity into the market.

Billy Lee: Those are interesting numbers. Right off the bat, we're doubling the potential universe of buyers. That's great. We need more of that type of thinking and creativity.

Question 7: How would a tax credit investor default insurance policy be structured?

Billy Lee: How would a policy like this be structured, from a mechanical standpoint?

David Kinzel: I'll keep it simple. There will be three parties involved. First, you would have the developer, and they would be the insured on the policy. They're going to be who purchases the policy.

The second party would be the insured counter-party, or the tax credit buyer. That's the party that could trigger a claim by defaulting on the legally enforceable obligation that we talked about.

Third would be the lender. The lender would be what's called a "lost payee." They'd be named on the policy and, if there was a claim paid, they would have rights to the proceeds, giving them that comfort of why the policy is there in the first place. The claim could be triggered by a number of different things – for example, you could have a 12-month forward commitment and the tax credit buyer files insolvency on month six. A second scenario could be where the tax credits are transferred and there's some agreement to pay after the transfer event; if there are payment terms like that, that would trigger a claim as well. Really, any situation in which the tax credit buyer defaults on the contract that we're wrapping in insurance, that's where claims would be triggered, and that's how it would be structured from a general level.

Question 8: How could an insurer "step into the shoes" – that is, become the purchaser of the credits – of a buyer in the event of an insurance claim?

Billy Lee: We also spent some time talking about how an insurer could step into the shoes of a buyer in the event of a claim, which I think is really interesting. Could you explain this arrangement? Also, would an insurer need to have privity to the purchase and sale agreement? Would it become a three-way tax transfer agreement?

David Kinzel: It's interesting. We've talked a lot about the underwriting process and how it works based on credit quality. But another important factor that the insurance market takes into account is the potential for recoveries. Once an insurance company pays a claim, it's not like they sit there and say, "We made a bad decision. Let's move on to the next one." They are going to be going back and looking for recoveries in any way that they can to minimize their loss. That's part of their process, and there are three ways they can go through it. First, they would go after the tax credit buyer under their breach of that legally enforceable obligation to commit the capital.

If the insurer isn't successful there, they'd have the expectation that the developer would help them find a new buyer for the tax credits. The third step is the interesting thing that we talked about: there could be a situation where the insurer may say, "We paid a claim, but our recoveries could be in the form of a tax credit" – that is, finding a way to say the tax credits have not been transferred to the original tax credit buyer. Since there's not a buyer anymore because they defaulted on that contract, could the insurance company step in take those tax credits for themselves? This is something we're exploring and talking about, and it seems possible.

Question 9: Theoretically, will coverage cost less if insurers have more recovery options?

Billy Lee: Right. If you give insurers more backup options to ultimately recover, the more willing they will be to extend that coverage, and perhaps the coverage will cost less theoretically, correct?

David Kinzel: Exactly. That could impact the cost and how far down the credit curve we can go. There's a lot of implications as the market develops. If the insurers get good experience and get comfortable, it could really open up the universe of who would be eligible to be insured as a tax credit buyer.

Question 10: How much does this insurance cost today? How much do you think this insurance will cost over time?

Billy Lee: Great. The immediate follow-up question and my last question is the million dollar question: How much does this insurance cost today? Obviously, there's probably been very few data points, but how much do you think this coverage will cost over time? Will it go down as more of these policies are written?

David Kinzel: The market's developing. I think there is going to be quite a bit of variation based on the risk with all those underwriting factors that we talked about. But we know the market really well. We've been in this market for a long time. I think a good starting point is around an annualized 1% on the commitment amount that's going to be insured. And that could go down as we see better credit quality, more comfort from insurers. I would expect that to go down for the higher credit qualities and the shorter duration risk. Whereas if we look at going down the credit curve to more challenging credits and longer durations, then it could be above that 1% annualized threshold. But that's a good base estimate if people are looking to explore this at a high level.

Billy Lee: David, this has been a great conversation. I love connecting with thought leaders and innovators, particularly around risk management. Thank you for your time. Thank you for tuning into 10 Questions. We'll see you next time.

In early December, the IRS launched a webpage for its pre-filing registration tool. As of this post, the actual tool is "unavailable to the public."

However, developers who want a head-start can review the portal's user guide to get a clear sense of what to expect – including the IRS's recommended 120-day review timeline.

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Reunion's key takeaways from the pre-registration portal user guide

• Takeaway 1: The IRS pre-registration portal is not yet open, but the user guide discloses the portal's data and documentation requirements
• Takeaway 2: The IRS does not issue a registration number until the review is complete, and the IRS recommends at least 120 days for review
• Takeaway 3: Projects must be placed in service before submitting a registration‍
• Takeaway 4: For every credit, the portal requires standardized information about the registrant‍
• Takeaway 5: The portal includes credit-specific requirements, including a "non-exhaustive" list of documents. (Navigate directly to a credit's requirements: §30C, §45, §45Q, §45U, §45V, §45X, §45Y, §45Z, §48, §48C, §48E)‍
• Takeaway 6: Developers will need a registration number for each facility/property‍
• Takeaway 7: A registration number does not mean a registrant qualifies for a credit of any specific amount

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TAKEAWAY 1

The IRS pre-registration portal is not yet open, but the user guide discloses the portal's data and documentation requirements

In early December, the IRS launched a webpage for its pre-filing registration tool. As of this post (December 18, 2023), however, the actual tool is "currently unavailable to the public."

Although the portal is not yet live, developers can get a preview of the tool's look, feel, and workflow through the Pre-Filing Registration Tool User Guide and Instructions.

The 69-page guide includes step-by-step instructions for registering each facility/property, including a bulk upload functionality – complete with a spreadsheet template – for the §30C, §45, and §48 credits. (The template is not yet available.)

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TAKEAWAY 2

The IRS does not issue a registration number until the review is complete, and the IRS recommends at least 120 days for review

The IRS does not issue registration numbers until the application has been reviewed and marked as "Returned - Closed." The registration field will go from "pending" to an alpha-numeric string.

The guide counsels registrants to submit their pre-filing registration at least 120 days prior to when they plan to file their tax return. 120 days "should allow time for IRS review, and for the taxpayer to respond if the IRS requires additional information before issuing the registration numbers."

Importantly, 120 days is the IRS's current recommendation, suggesting this timeline could vary. Developers should prudently assume 120 days is the minimum.

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TAKEAWAY 3

Projects must be placed in service before submitting a registration

The guide states, "Before a facility/property can be registered to make a transfer election...that property or facility must have been placed in service no later than the date the registration is submitted." However, nothing prevents a registrant from getting a head-start on a draft submission.

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TAKEAWAY 4

For every credit, the portal requires information about the registrant and allows for "additional information, if any"

All registrations must provide the following "general information" about the registrant:

• Tax period of the election
• EIN
• Name associated with EIN (as it appears on tax return)
• Parent of consolidated group?
• Registrant type (C corporation, sole proprietorship, etc.)
• Address
• Bank account information (account number, routing number)
• Type(s) of prior-year return(s) filed (Form 1120, Form 1040, etc.)

The portal also allows for "additional information, if any" as unformatted text. This field is optional but allows for the collection of "any additional information the registrant may wish to provide to identify a specific property or facility." In general, registrants should consider this field an opportunity to address any potential questions about their submission. Registrants should remove as much uncertainty in their application as possible.

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TAKEAWAY 5

The portal includes credit-specific requirements, including a "non-exhaustive" list of documentation

Depending on the type of credit a developer is registering, the portal will ask for specific data – the date construction began, for example – and a "non-exhaustive" list of supporting documentation.

According to the guide, "Supporting documents will usually be relatively short documents, such as permits, title documents, [and] sales documents (showing the name of the registrant, date of purchase, and identifying information such as serial numbers)." On several occasions, the user guide states, "Do not attach detailed project plans or contractual agreements."

The guide does not list requirements for credits that are pending:

• §45Y – Clean electricity production credit: Applies to facilities placed in service after 12/31/2024
• §45Z – Clean fuel production credit: Applies to transportation fuel produced after 12/31/2024
• §48E – Clean electricity investment credit: Applies to facilities placed in service after 12/31/2024

Scroll to a credit: §30C | §45 | §45Q | §45U | §45V | §45X | §45Y | §45Z | §48 | §48C | §48E

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TAKEAWAY 6

Developers will need a registration number for each facility/property

Developers will need a separate registration number for each facility/property, depending "on how the credits must be computed and reported on the source credit form and Form 3800."

The source forms for each credit are as follows:

Transferable tax credit source form links

Here are links to available source credit forms for transferable tax credits. Some forms, like 7213, are in draft as of this post (December 11, 2023): 

1. §30C (Alternative fuel refueling property credit) – Form 8911
2. §45 (Renewable electricity production credit) – Form 8835
3. §45Q (Carbon oxide sequestration credit) – Form 8933‍
4. §45U (Zero emission nuclear power production credit) – Form 7213. As of December 2023, this form is draft
5. §45V (Clean hydrogen production credit) – Form 7210. As of December 2023, this form is draft
6. §45Z (Clean fuel production credit) – Form 8835. As of December 2023, this form is pending a future revision
7. §45X (Advanced manufacturing production credit) – Form 7207
8. §45Y (Clean electricity production credit) – Form 7211. As of December 2023, this form is pending
9. §48 (Energy credit) – Form 3468
10. §48C (Qualifying advanced energy project credit) – Form 3468‍
11. §48E (Clean electricity investment credit) – Form 3468. As of December 2023, this credit will involve a future form revision

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TAKEAWAY 7

A registration number does not mean a registrant qualifies for a credit of any specific amount

The guide reminds registrants that the portal demonstrates an "intent to monetize" a credit. A registration number, in other words, "does not mean that the registrant has been determined to qualify for a credit of any specific amount."

To monetize a credit, a developer must meet other requirements to make a valid election, including:

• Reporting the credit on the applicable source credit form (see list above)
• Completing Form 3800
• Fully executed transfer election statement
• Attaching these forms to a timely-filed tax return

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QUESTIONS

Interested in learning more?

To learn more about the pre-registration portal or the IRA tax credit market it supports, please contact Reunion.

At Reunion, we believe that setting a strong company culture from the start is a critical part of building a high-performing company. Our founding team worked together to define company values that influence our everyday work; from how we screen and hire new employees, to how we collaborate and develop our product offering.

Our mission has remained constant. Our team members are motivated by our mission to make a meaningful difference in the fight against climate change. We believe that our team is uniquely positioned to increase deployment of renewable energy through our deep experience in financing.

We have five core company values. Every quarter, we re-visit our company values and ask whether these values remain relevant to how we work. This always spurs insightful and honest reflections on where we are succeeding and where we can improve. Sometimes, it leads us to adjust our company values to better reflect what is truly important.

Our mission

Reunion’s mission is to accelerate investment into renewable energy projects by simplifying the project financing process.

Our values

Communicate empathetically and directly

• We communicate openly and directly, even in disagreement
• We are kind and assume our teammates, customers, and partners have the best intentions

How can we go faster?

• We make firm and fast decisions, particularly on decisions that can be reversed
• We ship fast and adjust course based on data and feedback

How can we do it better?

• We run experiments that we can measure and are open to changing our minds when presented with data
• We keep an “enterprise-level” bar for excellence

Everybody is a leader and an owner

• Anybody can own an initiative and make it a reality
• If we commit to a project, we aim to follow through to finish

Continuous growth

• We strive to keep learning and improving, both as a company and as individuals
• Feedback is a gift; we embrace opportunities to grow

Come join us

Defining and refining our company values has helped us clarify who we want to be as a company. We have developed a high-performance culture, and we have surprised ourselves at times with our pace of execution despite having a small (but mighty) team. I should also emphasize that, although it’s not an official company value, we also have fun! 🙂

We believe that hiring and motivating the best people will be core to achieving our climate mission. If our mission and values resonate with you, we are always looking for talented people to join us – check out our open roles.

Key features of the IRA's 11 transferable tax credits

The Inflation Reduction Act (IRA) created 11 transferable tax credits to promote investment into clean energy. This article summarizes key features of each transferable credit including technology, duration, period of availability, and rates. Depending on the credit, we included three rates:

• Base: Rate assuming prevailing wage and apprenticeship requirements are not met.
• Full: Rate assuming prevailing wage and apprenticeship requirements are met. The full rate is five times higher than the base rate.
• Bonus: Additional rates assuming bonus credits – energy community, domestic content, low-income community – are met.

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Jump to a credit

To jump directly to a credit, click a link below:

1. §45 PTC – Electricity produced from certain renewable sources
2. §45Y PTC – Clean electricity production credit (technology-neutral PTC)
3. §48 ITC – Energy credit
4. §48E ITC – Clean electricity investment credit (technology-neutral ITC)
5. §30C ITC – Alternative fuel vehicle refueling property credit
6. §45U PTC – Zero-emission nuclear power production credit
7. §45Q PTC – Credit for carbon oxide sequestration
8. §45Z PTC – Clean fuel production tax credit
9. §45V PTC – Clean hydrogen production tax credit
10. §48C ITC – Advanced energy project credit
11. §45X PTC – Advanced manufacturing production credit

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§45Y PTC - Clean electricity production credit

Funding mechanism: Production tax credit

Technology grouping: Electricity

IRA Section: 13701

New or existing: New

Eligibility: Technology-neutral tax credit for production of clean electricity. The §45Y PTC is for facilities generating electricity for which the greenhouse gas emissions rate is not greater than zero

U.S. Code: 26 U.S. Code §45Y

Duration: 10 years from the date the project is placed in service

Period of availability: Projects placed in service beginning in 2025 are eligible for the credit.

The credit is subject to a four-year phase-out (100%, 75%, 50%, 0%) for projects that begin construction in the first calendar year after the ”applicable year,” which is the later of (1) 2032 or (2) the calendar year in which the IRS determines that the annual greenhouse gas emissions from the production of electricity in the U.S. are equal to or less than 25% of the annual greenhouse gas emissions from the production of electricity in the U.S. in 2022.

Below is an example phase-out schedule, assuming the "applicable year" is 2032. An eligible project that begins construction in 2035 and meets PWA requirements will generate §45Y PTCs worth $13.75 per MWh when it is placed in service.

Stackability and limitations: Cannot be stacked with §48E or §45Q

Inflation adjustment: Subject to an annual inflation adjustment

Elective pay (direct pay): Only available to tax-exempt entities

Recapture: Not applicable

Rates

• Base rate: $5.50 per MWh (as increased by annual inflation adjustment factor from 2023)
• Full rate: $27.50 per MWh (as increased by annual inflation adjustment factor from 2023)
• Energy Community: 10%
• Domestic Content: 10%

Guidance: Further guidance pending. The credit is included in the IRS 2023-2024 Priority Guidance Plan

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§48E ITC - Clean electricity investment credit (technology-neutral ITC)

Funding mechanism: Investment tax credit

Technology grouping: Electricity

IRA Section: 13702

New or existing: New

Eligibility: Technology-neutral tax credit for investment in facilities generating electricity for which the greenhouse gas emissions rate is not greater than zero

U.S. Code: 26 U.S. Code §48E

Period of availability: Projects placed in service beginning in 2025 are eligible for the credit.

The credit is subject to a four-year phase-out (100%, 75%, 50%, 0%) for projects that begin construction in the first calendar year after the ”applicable year,” which is the later of (1) 2032 or (2) the calendar year in which the IRS determines that the annual greenhouse gas emissions from the production of electricity in the U.S. are equal to or less than 25% of the annual greenhouse gas emissions from the production of electricity in the U.S. in 2022.

Below is an example phase-out schedule, assuming the "applicable year" is 2032. An eligible project that begins construction in 2034 and meets PWA requirements will generate a §48E ITC worth 22.5% of the project’s qualified investment when it is placed in service

Stackability and limitations:

• Cannot be stacked with §48, §45, §45Y, §48C, §45Q
• Subject to recapture per §50

Inflation adjustment: None

Elective pay (direct pay): Only available to tax-exempt entities

Recapture: Subject to five-year recapture period beginning on placed-in-service date. Recapture amount decreases by 20% per year

Rates

• Base rate: 6%
• Full rate: 30%
• Energy Community: 10%
• Domestic Content: 10%
• Low-Income: 10% if located in low-income community or on Indian land. 20% if part of qualified low-income residential building project or qualified low-income economic benefit project. Limited to projects less than 5 MW

Guidance: Further guidance pending. The credit is included in the IRS 2023-2024 Priority Guidance Plan

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