Essential Insights on Treasury's Transferability Guidelines

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

Canary Media thanks KORE Power for its support of our special coverage of the Inflation Reduction Act’s first year.

The Inflation Reduction Act has unleashed what could be a trillion-dollar flood of tax credits for U.S. clean energy and decarbonization investments over the next decade.

To capture as much of the value of these tax credits as possible — and, in turn, build as much new clean energy as possible — project developers need to partner with companies and financial institutions in what’s called a tax-equity market. Thanks to three decades of tax-credit-focused clean energy policy, this is a well-established ecosystem; it’s become the financial engine that makes solar, wind and battery subsidies work in the U.S.

But here’s the problem: The volume of tax credits introduced by the climate law is unlike anything these tax-equity marketplaces have ever dealt with — and without serious changes, these new credits would almost certainly overwhelm this key market.

A provision of the climate law known as ​“transferability” aims to solve this. The rules for how it works are as complicated as major new federal tax-credit policies tend to be, but the concept is relatively simple. For decades, financiers have had to become co-owners of the clean energy projects they invest in in order to claim the associated tax credits. In contrast, the new deal structure introduced in the Inflation Reduction Act allows investors to buy those credits on an open market, drastically lowering barriers to entry and potentially unleashing a torrent of new project funding worth billions.

“This will truly transform the way clean energy projects are financed,” said Andy Moon, CEO and co-founder of Reunion Infrastructure, one of a number of startups that have launched to facilitate and support the emerging market for tax-credit transfers. ​“It’s hard to overstate. This will be a huge deal.”

Many clean energy projects aren’t financially feasible without the help of tax credits, but the amount of money a project developer can receive from those credits is limited by the size of its tax bill — and most developers don’t pay nearly enough in taxes to make use of those credits. Today’s tax-equity markets help solve this: Clean-energy project developers partner with big banks and financial institutions with massive tax bills that are looking to reduce how much they owe to the federal government. In turn, these deep-pocketed partners return some of that value to the project developers in the form of cash payments.

That allows project developers to maximize the value of the credits and build far more clean energy projects much faster than would be possible if developers relied on their own tax liability alone.

At its peak prior to the new law, the U.S. tax-credit investment market processed about $20 billion in clean-energy projects per year. Under the Inflation Reduction Act, that annual figure is expected to be at least two to three times larger, according to multiple analyses. And with the supply of clean energy tax credits uncapped by the federal government and restricted only by the volume of creditworthy projects, the eventual demand could grow even further.

To incentivize project developers to build out clean energy as quickly as the climate crisis demands, the tax-equity market also needs to rapidly expand its capacity. That’s where transferability will play a vital role — and big banks, new startups, renewable energy developers and armies of lawyers and consultants are all rushing to put it into practice.

One of these advisory firms, Reunion Infrastructure, is benefiting mightily from the flood of interest in tax-credit transfers. In July, the startup announced it had amassed more than $1 billion in credits from ​“high-quality solar, wind, battery storage, and biogas projects” that are ready to be snapped up by corporate buyers. By mid-August, the total had doubled to $2 billion, according to CEO Andy Moon.

The pace of deals is likely to pick up even further in the wake of the U.S. Treasury Department issuing guidance in June on transferability and another option for streamlining tax-credit transactions, known as direct pay.

“There have been deals literally waiting on the sidelines to be implemented once the structure was in place,” said Allison Nyholm, vice president of government affairs at the American Council on Renewable Energy, a trade group representing clean energy companies and customers. An ACOREsurvey of clean-energy developers and investors in June indicated that more than 80 percent of them intended to use transferability or direct pay in their investments over the next three years.

This week, Bank of America unveiled details of the first tax-credit transfer deal to be made public, an agreement to buy $580 million in wind energy tax credits from a $1.5 billion wind farm being built by clean power developer Invenergy. ​“We’re creating a market where you can have more players around the table all participating in the clean-energy transition,” Karen Fang, Bank of America’s global head of sustainable finance, told TheWall Street Journal.

But Patrick Worrall, vice president of the asset marketplace at clean energy marketplace provider LevelTen Energy, warned that ​“the only way that the IRA can fulfill its promise is if there are many more parties who jump into the tax investment game.” That’s because the relatively small pool of large financial institutions that now do tax-equity deals don’t have the investment appetite or capacity to finance nearly as many projects as the Inflation Reduction Act’s expanded tax credits can support.

Transferability makes such expansion possible — but it doesn’t guarantee it. ​“There’s nothing there if these parties don’t start coming to the market and making these investments,” Worrall said. ​“This was all set up by the federal government to enable these corporations to enable this transition.”

From tax equity to transferability: A sea change in how clean energy is financed

Why can’t today’s tax-equity markets handle the coming wave of clean energy tax credits initiated by the Inflation Reduction Act? Simply put, the traditional way of doing things is just too complicated and expensive to meet the scale and scope of investments coming, Moon said.

Moon and his co-founder at Reunion Infrastructure, Billy Lee, both come from the tax-equity investment world, starting together at solar development pioneer SunEdison and then working separately at large banks and private equity firms. ​“We’ve pitched tax equity [deals] to corporates for 15 years — and they very rarely do it,” Moon said. ​“It’s very complex.”

At the core of that complexity is the long-standing rule that allowed only the project owner to claim tax credits associated with the project. The government structured the rules that way to ensure that the benefits of the tax credits would go to an entity with a vested interest in ensuring the project was actually built and operated properly.

But it also complicated the process of using tax credits to build clean energy projects. Project developers and deep-pocketed tax-equity investors used complex transaction structures, such as partnership flips and sale-leasebacks, to make the investor the owner of the project for as long as it would take for them to be eligible to claim the tax credit. After that, they would ​“flip” ownership back to the developer for the remainder of the project’s lifespan.

These labyrinthine partnerships can take millions of dollars in legal and administrative costs to put together, and because of their inherent complexity, there is little opportunity to streamline or standardize based on past efforts and make future deals simpler or cheaper, Moon said. They also force investors into the position of owning a clean energy project for years at a time, exposing them to risks that very few companies are willing to take on.

That’s why the pool of tax-equity investors is as small as it is, LevelTen’s Worrall said. ​“Over 50 percent of it is JPMorgan and Bank of America,” with about 40 other institutions rounding out the market, he said. And because these deals are so complex and risky, these investors have little appetite or capacity to expand how much new business they can take on — ​“they’re investing regularly, and they’re full.”

These conditions have led to a ​“huge supply-demand imbalance for tax equity,” Moon said. ​“Projects that could previously get tax equity are in the last six months struggling — there just isn’t enough. And if you don’t get tax equity, you can’t build a project.”

Another problem with the status quo is that tax-equity investors tend to only target deals of $100 million and up. That has forced developers of smaller-scale projects like community solar to sell to project aggregators that bundle numerous smaller projects together into high-dollar portfolios valuable enough to attract the interest of banks.

The IRA’s new transferability option upends this landscape entirely, Moon said. ​“Now there’s an option for those developers to build the projects and sell the credits themselves.”

Would-be buyers of tax credits also have a much simpler road ahead under the new transferability option, Worrall said. ​“There’s no longer a partnership investment with a ton of due diligence upfront and a ton of maintenance over the lifetime of the investment. You’re talking about a simple transfer: corporate tax credits for cash.” These deals also have much simpler accounting requirements, he added.

Some projects making use of the new tax-transfer deal structure have already started to be put together. Moon said that participants in his company’s marketplace include developers of smaller-scale projects that would struggle to get the attention of traditional tax-equity investors.

Crux Climate is another recently launched startup that provides software and services to manage this new breed of tax-credit transfer transactions. CEO Alfred Johnson said Crux has ​“gotten past the term-sheet stage,” which precedes the writing of a binding contract, on its first deal with a smaller clean-energy project developer and an unnamed corporate tax-credit buyer that’s new to the tax-equity market.

While tax-credit transferability opens the door to smaller developers and inexperienced corporate investors, it could also be an option for those already active in the existing tax-equity markets, Moon added. ​“Large and very experienced developers are talking about how this will be part of the portfolio. All the banks and tax-equity investors are looking at how to integrate transferability,” with financiers including Bank of Americareporting deals in progress.

That’s a good thing, because the growth needed to expand the pool of investment capital flowing into clean energy projects that must be built at an unprecedented pace and scale to combat climate change is immense, Johnson said.

“We need to move from a world where there are 40 or 50 credible” financial institutions investing in the market and processing about $20billion in traditional tax-equity deals per year, to one capable of processing about “$85 billion in credits per year” by 2031, as per a Credit Suisse forecast of the market spurred by the Inflation Reduction Act, Johnson said. That $85 billion figure would be roughly equivalent to 20 percent of all corporate taxes paid in the U.S. last year, representing an unprecedented level of commitment from corporate America to a form of investment that barely exists today.

Hurdles to clear to make a market: Recapture and insurance

A lot of industry watchers say the new tax-credit transfer deal structure will make things simpler, but it won’t exactly make them easy. That’s why companies like Reunion Infrastructure, Crux Climate and others have sprung into being.

The first challenge is ​“finding the big corporations and making them comfortable with it,” said Ben Ullman, founder and CEO of transferability marketplace startup Common Forge. That leaves it up to companies like his to ​“find a way to standardize this for corporations” so it’s as simple and painless as possible for the tax departments of the companies being courted as buyers of clean energy tax credits, he said.

One way to make the new tax-credit transfer deals more appealing to skittish corporate buyers is by reducing their risk exposure as much as possible, according to Ullman. ​“The key to that is the buyer protections” that dealmakers must structure to protect companies from the risks they take on when they purchase large amounts of tax credits, he said. ​“No corporation looking to buy a tax credit is going to start on a big deal process” without a clear understanding of the risks and how to protect themselves against them.

Right now, the biggest risk lies in what’s called ​“recapture,” Ullman said, referring to the Internal Revenue Service’s right to reclaim the tax credits from failed, sold or otherwise ineligible clean energy projects. Many clean-energy tax credits, including those for solar power projects, are pegged to the value of investment into a project in the year it begins operating. These credits can then be used to offset a buyer’s tax liability in the following year.

But what if that project ends up going bankrupt and shutting down, or is destroyed by extreme weather, or is sold to another party, or otherwise fails to meet the rules that allowed it to claim the tax credit in the first place? If that worst-case scenario occurs, the IRS can claw back the value of those tax credits.

When the project owner is the same entity using the tax credits to offset their tax bill, that’s a fairly straightforward process. But any third party looking to buy those tax credits and retain their value over time will need to find a way to protect themselves.

That’s what makes the risk of ​“recapture a headache” for would-be corporate tax-credit buyers, Ullman said. ​“The company has to defend itself to the IRS and to pay the IRS — and they could either pay out of pocket when that happens or buy an insurance product and pay that premium over time.” That’s why Common Forge and other players in this market are building insurance into their standard transaction structures, he said.

The good news is that there are already established ways to mitigate this risk. ​“Recapture insurance and qualification insurance is a mature market — all the big carriers and brokers carry that insurance,” Moon said. ​“We’re working closely with them.”

In fact, Ullman noted, ​“Insurers are all quite excited by the market opportunity.” And because insurance rates tend to decline when there’s a bigger pool of stuff to insure, that’s another argument in favor of encouraging standardization across deal terms in the burgeoning tax-credit transfer market, he added.

Building markets that work at scale — and that sellers and buyers can trust

Crux CEO Johnson believes that another key to successful standardization will be the availability of reliable technology to connect clean-energy developers selling credits with potential buyers. His company is focusing on providing its software to the big banks and financial institutions that are already the key players in the traditional tax-equity market, he said.

Clean-energy developers need software ​“to easily list…their credits for sale” to the widest audience possible and ​“to distribute the credits at the highest net price” they can hope to secure, Johnson said. Buyers need to be able to ​“find projects that meet their desired characteristics” and access project data they need to do their due diligence, and they need this information both before making a decision to buy and afterward, in case ​“the IRS comes knocking.” And companies like Crux are needed ​“in the middle” to ​“distribute these credits and make markets,” he said.

Ullman warned that this new market is not going to develop overnight. ​“The first thing — the existential thing — is getting buyer interest,” he said. ​“You have to do a bunch of transactions this year, show that buyers can engage with minimal overhead time internally, show a bunch of savings, and show it didn’t blow up at the end.”

Eventually, a healthy market will be able to sort tax credits from project developers with weaker or stronger underlying financial underpinnings and price them accordingly, Johnson said. It will also be broad-based enough to ride out disruptions that dogged the traditional tax-equity investment markets during the recessions of 2008–2009 and 2020–2021, when big tax-equity investors were making less money and thus had smaller tax bills, and had largely stopped looking for tax credits as a result.

A vibrant tax-credit transfer market could also create a new way for climate-conscious companies to invest in decarbonization, Worrall noted. For clean energy to grow at the rate needed to reach the Biden administration’s carbon-cutting commitments under the Paris Agreement, ​“these corporate taxpayers need to step up to support this federal policy,” he said.

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

-Andy Moon

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

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

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Top 10 Takeaways

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

Full Transcript

Introductions

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

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

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

Elizabeth Crouse (Perkins Coie): Tony?

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

Treasury released proposed regulations on June 14

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

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

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

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

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

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

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

Who is a good buyer of tax credits?

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

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

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

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

Tony Grappone (Novogradac): Great point.

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

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

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

Guidance provides clarity around recapture risk

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

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

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

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

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

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

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

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

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

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

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

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

Andy Moon (Reunion): Yeah, for sure.

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

Andy Moon (Reunion): Yeah, for sure.

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

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

Elizabeth Crouse (Perkins Coie): Okay.

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

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

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

Buyer due diligence comes to the fore

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Base tax credits cannot be separated from tax credit adders

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

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

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

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

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

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

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

Buyers can apply tax credits against quarterly estimated tax liabilities

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

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

Tony Grappone (Novogradac): I love that.

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

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

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

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

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

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

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

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

Tony Grappone (Novogradac): I agree with you.

Basis step up revisited

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

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

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

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

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

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

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

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

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

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

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

Tony Grappone (Novogradac): Great point.

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

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

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

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

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

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

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

Andy Moon (Reunion): Great point.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Elizabeth Crouse (Perkins Coie): Yeah.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Current tax credit market pricing

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Contact us

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