Understanding transferable tax credit carrybacks

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.

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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

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Our values

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Come join us

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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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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."

Listen on Spotify or Apple

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

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

Watch Video

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.

Takeaways

• The low-income community bonus is an allocated – that is, capped – credit, and we believe it will be fully utilized
• Developers must apply for an allocation through the Department of Energy. All applications received within the initial 30 days will be treated as received at the same time
• There are 21 business days in the 30-day window. The last day coincides with the expiration of the federal government’s current continuing resolution
• Allocation amounts can different from applied-for amounts

Overview of the low-income community bonus

The low-income bonus is designed to incentivize investment in communities that have historically been left behind. Specifically, the credit promotes wind, solar, and associated energy storage investments in low-income communities, on Indian land, as part of affordable housing developments, or benefitting low-income households.

The low-income bonus is an allocated credit. For 2023, the bonus is subject to an 1,800 MW annual capacity limitation, which is further allocated across four categories:

1. Located in a low-income community: 700 MW
2. Located on Indian land: 200 MW
3. Qualified Low-Income Residential Project: 200 MW
4. Qualified Low-Income Economic Benefit Project: 700 MW

Projects in the first two categories receive a 10% bonus credit value, while projects in the third and fourth categories receive a 20% bonus credit value. All low-income projects must be less than 5 MWac in size.

For 2023, the 700 MW in category one will be further subdivided: 560 MW will be reserved for residential rooftop solar and other “behind-the-meter” (BTM) facilities, and 140 MW will be reserved for “front-of-the-meter” (FTM) facilities.

The bonus is available for §48 and §48E credits

The low-income bonus is only applicable to §48 and §48E investment tax credits. The latter credit, the technology-neutral ITC, is available to projects placed in service in 2025 or later, so it’s possible that many developers will generate §48E ITCs.

How to apply

Since the low-income bonus is an allocated bonus, developers must apply for and receive an allocation from the IRS. (The DOE administers the application process, but the IRS ultimately makes allocation decisions.)

The DOE has published a  checklist for applicants in each category.

If any category or sub-category is oversubscribed during the initial 30-day period, the IRS will make awards based on a randomized lottery. Following the initial 30-day period, any leftover capacity will be awarded on a first-come, first-served basis. Applicants may only submit one application per facility, per program year.

The IRS will make allocations with certain ownership and location priorities in mind:

• Ownership: Priority will be given to (1) projects owned directly or indirectly by Indian tribes; (2) consumer or purchasing cooperatives with controlling members who are workers or from low-income households; (3) tax-exempt charities and religious organizations; and (4) state and local governments, and U.S. territories, Indian tribes, and rural electrical cooperatives
• Location: Priority will be given to (1) persistent poverty counties, where 20% of residents have experienced high rates of poverty of the last 30 years; and (2) and census tracts designated as “disadvantaged” in the Climate and Economic Justice Screening Tool (CEJST)

Once a developer has an allocation, they will have four years to complete the project and place it in service.

When to apply

All applications received within the first 30 days will be treated as received at the same time

The allocation portal opened on Thursday, October 19th at 9:00am ET. Applications submitted within 30 days of this date will be treated as submitted on the same date and at the same time.

Submit applications before November 17th, when the federal government’s current continuing resolution expires

The 30th day of the application window falls on Friday, November 17th. Developers should strive to submit their applications before this day because the federal government’s current, 45-day continuing resolution expires at the end of it.

Allocation amounts may differ from application amounts

Developers who receive an allocation will receive an award letter from the IRS with their allocation amount. Notably, the IRS makes it clear that a developer “may receive an allocation less than its [applied for] nameplate capacity.”

The allocation, not the project’s capacity, determines the credit value.

Reunion expects the IRS to fully allocate the credit

The IRS and DOE have stated that they can adjust the category allotments within the low-income bonus credit to ensure full allocation. Therefore, we expect the low-income bonus to be fully utilized every year – likely within the 30-day, all-applications-are-equal window.

The IRS and DOE have released extensive guidance and detailed resources for applicants

Guidance

• Initial guidance (February 13, 2023): Notice 2023-17, Initial Guidance Establishing Program to Allocate Environmental Justice Solar and Wind Capacity Limitation Under §48(e)
• Proposed regulations (May 31, 2023): Notice of Proposed Rulemaking, Additional Guidance on Low-Income Communities Bonus Credit Program
• Final regulations (August 10, 2023): Final Regulations, Additional Guidance on Low-Income Communities Bonus Credit Program
• Revenue procedure (August 10, 2023): Revenue Procedure 2023-27

Resources

• The Department of Energy (DOE) maintains a low-income communities bonus credit program website
• Applicant checklist
• Category 1 eligibility map with CEJST and persistent poverty county screens
• Category 3 eligible covered housing programs
• Category 4 household income limits

As the leading marketplace for clean energy tax credits, Reunion has been approached by many non-profit organizations to help them monetize clean energy credits, primarily from distributed solar projects. Unfortunately, non-profits are not able to transfer tax credits to third parties.

But non-profits have an alternative. The elective pay provision, sometimes called direct pay, allows “applicable entities,” including tax-exempt entities, to benefit from IRA clean energy tax credits even though they are not traditional taxpayers. This provision allows non-profits to receive refund payments directly from the IRS for the amount of eligible credits claimed.

Unlike transferable tax credits, where credits are purchased at a discount to their face value, applicable entities are entitled to receive the full amount of the credits from the IRS.

In order to qualify for elective pay, an applicable entity needs to pre-register its project with the IRS and receive a registration number. The direct payment election is made on Form 990-T, and the amount of credit would be treated as a payment of tax, which would be refundable, absent any other tax liability.

The elective payment provisions of the IRA are codified in IRC §6417. The internal revenue code (IRC) defines six applicable entities that are eligible for elective pay:

• 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

Most nonprofits, including 501(c)(3) and 501(d) entities, fall into the first category.

12 credits are available for elective pay:

• §48: Energy Credit
• §48E: Clean Electricity Investment Credit
• §45: Renewable Electricity Production Credit
• §45Y: Clean Electricity Production Credit
• §45W: Commercial Clean Vehicle Credit
• §45U: Zero-emission Nuclear Power Production Credit
• §45X: Advanced Manufacturing Production Credit
• §45V: Clean Hydrogen Production Credit
• §45Z: Clean Fuel Production Credit
• §45Q: Carbon Oxide Sequestration Credit
• §30C: Credit for Alternative Fuel Vehicle Refueling/Recharging Property
• §48C: Qualifying Advanced Energy Project Credit

Hello,

The market for transferable tax credits has gained momentum heading into Q4, as many buyers want to get their first deals done in the 2023 tax year. We expect the volume of deals to increase substantially as we reach the end of the year.

Exploring the latest market developments with EY and Troutman Pepper

In the latest edition of 10 Questions With Reunion, Brian Murphy of EY, Adam Kobos of Troutman Pepper, and our CEO, Andy Moon, discuss what they are seeing in transferable tax credit transactions.

The wide-ranging discussion covers topics of interest to tax credit buyers including pricing, using credits to offset estimated tax payments, timing of the IRS portal, and how to mitigate project risks.

Watch the full episode here.

See you at TEI on October 22-25 in NYC

Reunion is headed to New York on October 22-25 to attend the Tax Executives Institute (TEI) Annual Conference. Reunion CEO Andy Moon will be speaking on a panel about tax credit transfers. If you’d like to meet and discuss tax credit transfers while we are in New York, please schedule a meeting with us.

Best of luck to everyone closing out the quarter!

Team Reunion

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.