Introduction: Why buying tax credits is preferred by many corporate taxpayers
By allowing corporate taxpayers to purchase tax credits from renewable energy projects through the Inflation Reduction Act, Congress created a streamlined incentive to allow companies to put their tax payments to work financing the energy transition.
At the heart of this program, referred to as “transferability” or “transferable tax credits,” is a simple concept. Instead of requiring a partnership to allocate credits to a corporate taxpayer, that taxpayer can now use a tax credit transfer agreement (TCTA) to simply buy the credits from the generating source. By using a TCTA to purchase tax credits, corporations no longer must use complicated partnership structures that may generate negative accounting results.
For tax, treasury, and corporate finance professionals, this is a welcome development. In order to identify and manage all the risks of a tax credit transaction, a thorough understanding of the purchase documents is critical – starting with the TCTA itself.
In its simplest form, the TCTA is the contract that legally obligates a buyer to buy and a seller to sell the transferable tax credits generated from one or more projects. This article covers the key commercial and legal terms of the TCTA, as well as the allocation of risk between the parties.
Key components of a tax credit transfer agreement
A TCTA can be structured in two ways, principally depending on whether tax credits have already been generated. Spot transactions may use a simultaneous sign and close structure or a sign and subsequent close structure, while forward transactions will generally use a sign and subsequent close structure.
For transactions where a project has already generated tax credits and all closing conditions precedent will be achieved upon signing, a TCTA should be structured for a simultaneous sign and close. In this structure, payment happens upon execution of the contract.
For transactions where transferable tax credits will be generated in the future or where credits have been generated but have conditions that have not yet been fulfilled – for instance, a cost segregation is outstanding – the TCTA can be structured for sign and subsequent close. In either case, a sign and subsequent close ensures the buyer, seller, and project meet certain conditions before closing.
Pricing is the obvious commercial term that the transacting parties must negotiate. It is typically reflected as a price per $1.00 of tax credit. However, there are other commercial terms that need to be considered – ideally, early in the negotiation process – and reflected in the TCTA, including:
- Maximum credits acquired: A buyer will often put a cap on the amount of credits it acquires.
- Percent of credits acquired: If there is more than one purchaser of credits from a specific project, the TCTA may specify the pro rata amount of credits allocated to a particular buyer.
- Different pricing for different credit years: To the extent a buyer is acquiring credits from multiple credit years, or there is uncertainty as to the tax year in which a credit may be generated, the parties may negotiate pricing specific to each credit year. (We wrote about the rush to get projects placed in service in December here).
- Payment terms: To the extent that a buyer desires to pay the seller that is not immediately after all closing conditions have been met, the TCTA should specify these payment terms.
- Transaction costs: To the extent that each party does not bear its own legal and transaction costs (which we think makes the most sense), the parties should agree upon cost sharing.
Representations and warranties
At a basic level, the seller will represent that it owns the project, the project is qualified to generate transferable tax credits, they are eligible to claim and transfer the credits from the project, and such tax credits have not been previously sold, carried back or carried forward.
The seller will also need to make representations around the project itself – for instance, the project has been placed in service as of the closing date (for §48 ITCs); that the electricity was generated and sold to a third party (for §45 PTCs); whether the project qualifies for any bonus credit adders (energy community, domestic content, or low income); and whether the project has complied with or is exempt from prevailing wage and apprenticeship requirements.
There are also customary and non-controversial representations that both parties typically make, including around legal organization, due authorization, enforceability, no litigation, and no material adverse effect.
Pre-closing covenants and conditions
Pre-closing covenants govern the conduct of the parties between signing and closing. Pre-closing covenants are generally non-controversial, representing best practices to ensure that the seller does not do anything to impair the value of the credits and continues to advance the project in a commercially reasonable way. If any material changes do occur, a seller should be obligated to inform the buyer promptly.
Closing conditions precedent
Both the buyer and seller will need to meet conditions precedent (CPs) that are required to obligate the other party to close on the transaction, although most CPs in TCTAs are obligations of the seller.
The closing conditions validate that the credits have been generated and can be transferred as contractually envisioned; furthermore, they stipulate the specific deliverables that the buyer and seller must furnish prior to closing. Some common CPs include the following:
- Restatement of representations and warranties: This “bring down” confirms that all of the previous representations made by both parties remain accurate.
- Evidence that the project has been placed in service for tax purposes by a certain date.
- Completion of a pre-filing registration with the IRS along with a transfer election statement.
- Procurement of tax credit insurance (if agreed to by the parties).
- Evidence that the project has complied with the prevailing wage requirements and the project qualifies for any bonus credits available.
- For §48 ITCs, provision due diligence reports, including a cost segregation analysis and appraisal by agreed upon consultants. An appraisal is not required in many transactions but is typically warranted where there is a fair market value step-up transaction.
- For §45 PTCs, evidence that the electricity has been generated and sold to a third party; if the PTCs were subject to a wind repower, a report that establishes the 80/20 test has been met.
- No changes of tax law.
The buyer, importantly, is confirming within the closing conditions that they have conducted a thorough due diligence process. Demonstration of a thorough due diligence process can help buyers avoid a 20% “excessive credit” penalty in the event of a disallowance.
The IRS transferability guidance includes a “reasonable cause” provision that can absolve buyers of the 20% penalty (but not their pro-rata share of the excessive credit itself). The most important factor to establish reasonable cause is “the extent of the transferee taxpayer’s efforts to determine” that the credit transferred was appropriate. Specific examples provided by the IRS that establish reasonable cause include review of seller’s records, reliance on third party expert reports, and reliance on seller representations.
Although transferability does not require a buyer and seller to enter into an equity partnership, both parties still have legal obligations to one another for a period of time following the transaction. The post-closing covenants detail these obligations and ensure ongoing compliance and cooperation.
Most importantly, the post-closing covenants require the parties to file their tax returns and properly reflect the tax credit transfer. This includes attaching the transfer statement with registration numbers to both the seller and buyer’s tax returns.
For §48 ITCs, recapture risk allocation is addressed in the post-closing covenants. The seller agrees to not take any action that would lead to recapture (such as sale or abandonment of the project) and, failing that, to notify the buyer if there has been a recapture event. Both parties agree to take any actions required of them if recapture occurs. Furthermore, during the recapture period1, the seller is required to meet the prevailing wage and apprenticeship requirements for any alterations or repairs on the project (although this requirement does not apply to routine operations and maintenance). To the extent the IRS determines that the seller violated wage and apprenticeship requirements, the seller has the ability to remediate such violations within 180 days of identification of such failure through cure payments. The requirement to make such cure payments should be a specific covenant in the TCTA.
In any tax credit transaction, whether a tax equity transaction or a tax credit transfer, the risk of loss often manifests itself in the form of an IRS audit. Given that a buyer has received the benefit of a tax credit, the IRS generally looks to the buyer if it challenges the amount of credit that was claimed. However, the buyer has an indemnification from the seller (and potentially tax credit insurance), so the seller will want visibility into any future tax proceedings that relate to the transferred credits.
Proceedings with the IRS can be governed in one of two ways. First, the buyer can control any proceedings with the IRS, with the right of the seller to be informed of the progress of the proceedings and the right to participate in such proceedings. Alternatively, the seller can control any proceedings with the IRS, with the buyer having participation rights. Control and participation rights should be negotiated between the parties as a commercial matter.
A TCTA should include a broad indemnity that shifts most risks (and their associated costs) from the buyer to the seller. In a tax credit transfer transaction relating to a §48 ITC, the primary risks to which a buyer is subject are qualification and recapture.
- Qualification risk: Pertains to whether the tax credits will be allowed in full by the IRS. Disallowance could result from several factors, including challenges to the qualified tax basis of the asset, the date the asset was placed in service, prevailing wage and apprenticeship labor, and the claim of bonus credit adders.
- Recapture risk: Occurs if the asset no longer remains energy property owned by the seller during the recapture period. This can occur in numerous circumstances, most notably if there is a default on a loan that results in a foreclosure2, or a sale of the energy property by the seller3. However, there are other instances that can cause recapture, such as a casualty event where the asset is not or cannot be rebuilt or a loss of site control where the project loses its ability to remain commercially operational. While these scenarios are remote, buyers should nonetheless remain aware that they exist.
There are fewer risks in a §45 PTC transaction. Generally, though, for any TCTA, the seller should expect to indemnify the buyer for any credit losses (other than from losses that were a direct result of a buyer action).
Unlike a traditional tax equity partnership, the buyer of tax credits has no control or governance rights over the project and, therefore, should not expect to assume the risk associated with credit losses.
In most cases, indemnity payments made by a seller to a buyer will be taxable transactions. Therefore, indemnity provisions will include a tax gross-up to ensure the buyer is able to cover any losses on an after-tax basis. Also, it is typical that a seller will indemnify for interest and penalties that may be assessed against the buyer.
As is common in purchase and sale transactions, indemnification will include breaches of representations, warranties, and covenants. As discussed previously, post-closing covenants are important for tax credit transfer transactions, given that the filing of both parties’ tax returns is required for the legal transfer of the credit from seller to buyer.
The transferor of a tax credit is the first regarded entity that owns the project generating the credit. For instance, if a project is owned by a single member LLC project company (which is a very common structure for energy projects), which is in turned owned by a partnership, the transferor of the tax credit is the partnership, as opposed to the project company, as that project company is a disregarded entity.
Given that the transferor may be a company of limited financial wherewithal, a guarantor is needed to backstop the indemnity obligations of the transferor. The guarantor is typically the parent company of the developer. In order to evaluate the creditworthiness of the guarantor, a buyer will want financial statements – preferably audited – of the guarantor. A buyer should undertake a credit analysis to understand the likelihood of repayment by the guarantor, should a recapture or disallowance condition occur. This analysis should take into consideration that the IRS can recapture tax credits over a 5-year period, with the amount of potential recapture stepping down by 20% each year. In determining the duration of the guarantee, the buyer should also consider the IRS audit statute of limitations, which typically runs three years.
Tax credit insurance
To the extent that the creditworthiness of the transferor and guarantor is insufficient for the buyer, tax credit insurance may be required. Whether tax credit insurance is required is typically negotiated up front, as the insurance premium is meaningful and will reduce the seller’s net economics.
Tax credit insurance can cover qualification, recapture, and structure4 risk. Not all risks need to be covered in each transaction, so all parties will need to agree on the covered tax provisions and understand the specific exclusions to each coverage.
To bind an insurance policy, the transacting parties must prepare a comprehensive due diligence package to submit to insurance providers. Once the submission is made, it usually takes several weeks to bind a policy. Parties should consider the insurance timeline during the TCTA negotiating process.
The insurer typically does not have contractual privity to the TCTA.
For any TCTA that is structured with a non-simultaneous signing and close, a termination provision is included that would provide an outside date to complete the transaction. Some typical reasons for termination would be if a project is delayed beyond a certain date, or if the project was not placed in service in a particular tax year.
How Reunion helps
Our founding team has been at the forefront of renewable energy tax credit financing and innovation for the last twenty years. With our marketplace of over $2 billion of near-term transferable tax credits, we can help identify tax credit opportunities that meet the needs of corporate tax teams. Additionally, we will guide buyers through transactions in a detailed and comprehensive manner, with a focus on properly identifying and managing risk.
To learn more about how we can help your company, please contact us.
1 The recapture period is the first five years from the date the project is placed in service.
2 A buyer may require a seller to negotiate a forbearance agreement with its lenders, where lenders agree to “forbear” against a direct foreclosure on the asset that would cause an ITC recapture.
3 A change in the upstream ownership of a partnership or S-corp does not cause recapture for the buyer of the credit, although this may trigger recapture to the shareholder or partner who sold their interests.
4 Whether the IRS will respect the transaction and the eligibility of the transferor to sell and the transferee to purchase the credits.
Welcome to 10 Questions with Reunion
At Reunion, we are fortunate to occupy a unique position in the clean energy financing market. Sitting at the confluence of buyers, sellers, and external advisors, we receive questions and observations from every corner of the industry. To share our vantage point, we are launching a video series, 10 Questions with Reunion, in which we will field questions, share emerging insights, and engage with a range of experts.
We hope you'll join us and ask questions of your own. Stay tuned to Reunion's LinkedIn page for further episodes and market analysis. If you have a question for our team, please send it to firstname.lastname@example.org.
Episode 01 takeaways
- "Rumored" credit prices from $0.95 to $0.98 are not representative of the broader market. Transactions pricing in the mid- to high-90s are not representative of the broader transferability market. Deals with relatively high pricing reflect non-standard features, like extended payment terms.
- Plain vanilla 2023 spot ITCs with scale are pricing in the $0.90 to $0.92 range net to the developer. Potentially a hair higher or lower.
- 2023 spot PTCs are pricing around $0.93 to $0.94 net to the developer. Generally, PTCs present less risk than ITCs, so they trade at less of a discount than ITCs.
- Do not assume the conventional wisdom that credit prices will rise with time. Credit pricing is a function of supply and demand. We see a major increase in available credits in 2024 and beyond. The key question is whether credit demand increases at a similar rate.
- The further in advance a tax credit is purchased, the greater the discount. There is a real price for forward commitments. A 2024 credit purchased in 2023, for instance, will carry a greater discount than a 2023 spot credit.
- Medium- to large-size corporate buyers and sophisticated finance groups have been early market entrants. Among corporate buyers, many had considered tax equity but decided it was too complex. Now, with transferability, they're re-engaging.
- Traditional tax equity has been increasingly harder to access. Supply of traditional tax equity has remained constant, while demand for it has grown rapidly. New demand is originating both from new developers and also new credit types.
- Transferability will play a role in most tax equity deals going forward. Traditional tax equity is dominated by a few large banks, and they have a finite tax equity appetite. Layering transferability onto tax equity deals enables large banks to support more clients and more projects.
- The June transferability guidance suggested that the IRS would further scrutinize step-ups. Looking ahead, we could see a market-wide standard for step-ups around 15% to 20% emerge because of limits set by insurance companies. Already, some large banks have implemented similar caps in tax equity deals.
- Due diligence for transferability should be simpler and more standardized than due diligence for tax equity. Unlike tax equity, buying transferable tax credits is not making an equity investment, which minimizes the scope of due diligence.
- Applying tax credits to quarterly tax payments could result in effective IRRs in the teens or higher. The June guidance allows taxpayers to offset their quarterly tax estimated payments with tax credits that they intend to acquire. If a company is paying $0.92 or $0.93 for a tax credit, their effective IRR could be in the teens or higher.
- 0:00 - Introduction and overview of Reunion
- 0:55 - Question 1: There have been rumors of transactions at 95, 96, or even 98 cents on the dollar. Are these numbers real?
- 2:28 - Question 2: How should we think about pricing a Section 48 investment tax credit (ITC)?
- 4:20 - Question 3: How does pricing compare for a Section 45 production tax credit (PTC)?
- 6:46 - Question 4: How should we think about pricing on forward commitments?
- 8:01 - Question 5: What kind of buyers are approaching the transferability market?
- 9:02 - Question 6: Has it become harder for developers to access traditional tax equity?
- 10:50 - Question 7: How will transferability play a role in tax equity deals?
- 12:46 - Question 8: How are market participants thinking about the IRS potentially scrutinizing basis step-ups?
- 13:59 - Question 9: How will due diligence for transferability compare to due diligence for tax equity?
- 15:43 - Question 10: How do buyers think about the return on investment when buying a tax credit?
Andy Moon: Good afternoon. My name is Andy Moon. I'm Co-Founder and CEO of Reunion, a marketplace that facilitates the purchase and sale of clean energy tax credits from solar, wind, battery storage, and other projects. We currently have over $2 billion in near-term tax credits from leading clean energy developers on our platform. Reunion works closely with corporate finance teams to identify high-quality projects and ensure a low-risk transaction. Together with my colleagues, Billy Lee and Kevin Haley, we have over 40 years of experience financing clean energy projects. Today, we'll be answering ten of the most common questions we get about tax credit transfers. Let's dive in.
Question 1: There have been rumors of transactions at 95, 96, or even 98 cents on the dollar. Are these numbers real?
Andy Moon: There have been rumors of transactions at 95, 96, or even 98 cents. Some project developers say they are holding out for prices in that ballpark. Billy, are these numbers real?
Billy Lee: Thanks, Andy. To answer it quickly, no, we don't think these transactions are really representative and reflect other non-standard features like extended payment terms. For example, we heard of an outlier where a buyer is acquiring 2023 credits but is not required to pay for them until close to the tax filing date in late 2024. In another example, an institution is selling late-year credits along with an investment-grade corporate guarantee to provide additional wrap.
Kevin Haley: Exactly, Billy. I would say that payment terms are a good example of something that's both very important and, in this early market, a little bit under appreciated in terms of price drivers, especially in a high interest rate environment that we're all dealing with today. A seller obviously wants to get paid as quickly as possible once the project's been completed, but the buyer is incentivized to try to come to some agreement to extend those payments when possible. Over time, I think we'll have to see a normalization around payment terms. The later that the payment is delayed, buyers should expect that it'll come with a penalty on the discount and they'll end up paying a slightly smaller discount.
Question 2: How should we think about pricing a Section 48 investment tax credit (ITC)?
Andy Moon: There's a few different types of credits. Why don't we go one at a time. How should I think about pricing on a Section 48 investment tax credit?
Billy Lee: Sure. Let's assume a plain vanilla deal. What I mean by that is 2023 tax year, a well-capitalized sponsor with deep experience, no tax credit insurance required, no material fair market value (FMV) step-up, a project that has scale – say, $20 million of credits or higher – and proven technology such as solar or battery storage. For these credits, we are seeing pricing net to the developer in the 90 to the 92 cent range. Maybe a hair higher or maybe a hair lower.
Andy Moon: I'll add we are seeing a wider discount in a few different scenarios. One is project size. These early deals require a fixed amount of transaction cost and learning just to get the deal done. I think buyers do want a wider discount to motivate them to take on a small project. Second, there's technologies such as biogas that have a smaller pool of buyers compared to solar or battery storage. These deals do carry a slightly larger discount. I think, similarly, there's new technologies that have tax credits for the first time, such as hydrogen or CCS, and they have less buyer demand. I think we'll have to see where the pricing shakes out. One other point is that projects that have unusual risk or complexity do carry a larger discount. Some examples are very large step-ups in the cost basis, or if a project has large indebtedness, that will also impact buyer demand. One final item I'll mention is that if a tax credit buyer requires insurance on a project, that will result in some additional cost in the 2-3% range, which results in a lower final price to the project developer.
Question 3: How does pricing compare for a Section 45 production tax credit (PTC)?
Andy Moon: Kevin, how does pricing compare on a Section 45 production tax credit?
Kevin Haley: I think for the PTC, particularly for 2023 spot credits, there's less risk than an ITC, and we would expect the discount to be lower, and that's what we're observing in the market today. Risk is lower on the PTC because generally there's no recapture risk, and the PTC credit amount is determined by the amount of electricity generated, which is easy to verify, and then it's multiplied by a fixed price per kilowatt PTC credit amount. We're typically seeing PTCs coming off of wind projects in 2023, trade in the 93 to 94 cent range net to the developer, and we would expect solar PTCs to trade in that similar range. Now, the one area where I think there could be a wider discount on PTCs is for other technologies that have lower buyer demand, like you mentioned, Andy. We're starting to see some of the early 45X and 45Q credits. These do carry a small amount of recapture risk on the 45Q side, and that could translate into a slightly better price for the buyer.
Billy Lee: I would interject here. It may seem obvious to most people, but the price of any commodity, including tax credits, is directly related to supply and demand. And there's a conventional wisdom that's been reiterated many times in a number of articles that pricing for tax credits will increase as the buyers become more active. But it's important to note that this assumes a static supply of credits, which will almost certainly not be true. Remember that there is a development cycle for these projects. Most 2023 credits are from projects that were originally developed pre-IRA, so they weren't assuming transferability. The IRA, by all measures, has supercharged clean energy development, and the vast majority of these credits will start to be generated in 2024 and beyond. We have a unique vantage point in the marketplace, and it is very plausible at this point in time that the supply of credits will continue to outstrip demand, which will almost certainly impact pricing on a macro level. The million dollar question is whether the tax credit buyer demand increases at the same rate as a supply of tax credits.
Question 4: How should we think about pricing on forward commitments?
Andy Moon: Developers are looking for forward commitments. In other words, they want a buyer to commit to buying credits now, even though the project may not be placed in service until 2024 or 2025. The reason, of course, is they want to be able to take that commitment, go to a bank, and get a bridge loan. Billy, can you talk more about pricing in this scenario?
Billy Lee: Sure. There's a real cost to the buyer for agreeing to commit early. Even though the money doesn't change hands until the credit is generated, it's a legally binding obligation. That has a cost. Right now, the supply of buyers willing to commit in advance is limited. Currently, most buyers are still very focused on 2023 spot tax credits. In order to get a bridge loan against a commitment, the buyer must be creditworthy. We expect this requirement to relax over time. We believe that lenders will start underwriting and lending against tax credits without a buyer commitment, but that's in the future – not really right now. So, in general, there will be a further discount on 2024 credits and even a larger discount on 2025 credits. The further in advance a commitment gets, the larger the discount.
Question 5: What kind of buyers are approaching the transferability market?
Andy Moon: Kevin, you've been spending a lot of time with buyers. What buyers are you seeing come to the table?
Kevin Haley: Thanks, Andy. It's been really interesting so far, especially because it's such an early market. We only just got Treasury guidance in June. I would say that our early buyers are typically the medium- to large-sized corporation that pays federal income tax. Our earliest adopters have really been coming out of the more sophisticated finance groups, many of whom have previously looked at tax equity investments into wind or solar. Some of them pursued those; others decided tax equity wasn't for them, and now they're coming back for transferability. But I think this is rapidly changing. We have deals in flight right now with a variety of large corporates in manufacturing, specialty finance, retail, insurance, and healthcare. It's really a diverse range across different sectors.
Andy Moon: I think Treasury guidance on June 14th really gave a lot of confidence to tax directors on how the transfer program would work.
Question 6: Has it become harder for developers to access traditional tax equity?
Andy Moon: Switching gears to tax equity, Billy, you've had a hand in many of the earliest tax equity transactions and have watched the market grow over the last 15-plus years. We keep hearing that the tax equity market has changed a lot in the last six months, and it's actually really hard to get tax equity than it was before. Is this true?
Billy Lee: Yes. This is near universal feedback that we're hearing from developers. Again, it's just reflective of supply and demand. There is a lot more demand for tax equity than there is supply. We're hearing of experienced developers with unique and long-standing tax equity experience saying they're struggling to get tax equity on 100-, 200-megawatt contracted utility-scale projects that previously would have been easy to get a tax equity deal. Tax equity has never been a layup, but the market dynamics really have changed. For example, we've already talked to a large bank that said that their tax equity appetite for 2024 has already been committed.
Kevin Haley: Billy, you touched on this earlier with supply and demand dynamics. There's a lot of new first-time credits coming online – 45Q, 45X, 45Z. There's a nuclear PTC. These are all competing for those same tax equity dollars. The demand for credits has increased significantly since the IRA, but the supply of tax equity capital has not really moved much further north of the $20 billion-a-year historical market size that we've seen in the past, and we don't expect that to change dramatically in the near future.
Question 7: How will transferability play a role in tax equity deals?
Andy Moon: That's a great point. And due to this shortage in tax equity, it's now becoming clear that transferability is going to play a role in many tax equity deals moving forward. Can you describe how this will work?
Billy Lee: Sure. I'll even go so far as to say that we think that transferability will start to play a role in the majority of tax equity deals. And this is based on conversations with many of the banks that are involved in tax equity. For example, a bank's ability to invest is limited by not only their total corporate tax liability, but also the amount that they've allocated internally to renewable energy transactions. One option is for the bank to sell some of the credits from a tax equity investment to a third party, which then frees up more space to serve more clients and more projects. In some ways, we think that there will be more corporate buyers who will be particularly interested in buying credits from a tax equity partnership for two main reasons. One, the tax credit buyers can rely on a bank's significant and detailed underwriting and due diligence. Secondly, and really interestingly, if there's a disallowance or reduction in the value of the tax credits, the IRS will first go after the retained credits before they go after transferred credits. So long as the tax equity partner keeps some credits, that's built-in risk mitigation because it provides a first loss mechanism to a tax credit buyer. That said, everything comes with a price and, in an efficient and perfect market, we would expect credits that are sold out of tax equity partnerships to carry a smaller discount than ones that are sold from a standalone tax credit transfer deal.
Question 8: How are market participants thinking about the IRS potentially scrutinizing basis step-ups?
Andy Moon: Switching gears to step-ups, we've heard some chatter that the IRS may start scrutinizing step-ups and that 50% to 100% basis step-ups are a thing of the past. Billy, what do you think about this?
Billy Lee: One surprise back in the guidance was that lease pass-through structures are not going to be allowed to transfer credits. This was the one structure that explicitly allowed for stepping basis up to fair market value. We read this as a potential sign that there will be more scrutiny from the IRS on step-ups. Large banks like JPMorgan and Bank of America have started limiting step-ups to 15% to 20% as an institutional rule. If we start to see more challenges from the IRS on large step-ups, we think the insurance market may go a similar route. And this could create a market standard that establishes what a maximum step-up percentage should be. So in general, overall, yes, we do think there's increased risk both for transfers as well as traditional tax equity deals that have large basis step-ups. The developers should just be aware of this when planning their projects.
Question 9: How will due diligence for transferability compare to due diligence for tax equity?
Andy Moon: Question for you, Kevin. Is the due diligence process in a transfer deal going to be as cumbersome and difficult as tax equity? What does it look like?
Kevin Haley: I think it's a really interesting question, and we certainly hope that transferability will eliminate some of the complexity and some of the hurdles that tax equity investors had to go through on diligence really for two main reasons. One is that a tax equity deal is just that. It's an equity investment into a project. And with that equity stake, a tax credit investor needs to go to a deep level of diligence to ensure the project will perform as planned. The second reason is that tax equity also involves the structuring of a legal partnership between the seller or the project developer behind the credits and, of course, the tax equity investor themselves. These partnerships are oftentimes quite expensive to set up, running into the million dollar or higher range. They come along with substantial legal and accounting complexities. When we've pitched tax equity to corporations over the years, that's oftentimes been a roadblock to their ability to participate. So, yes, Andy, I would say we want to do our best to not fully replicate the diligence exercise behind tax equity when we think about transfer deals.
Andy Moon: I will add that it is important to note that, especially in the early days, transfer deals do have complexity, and this is where Reunion steps in and actively shepherds deals forward. Our team has to help buyers navigate the project identification and due diligence process, and we really ensure that contracts are properly set up and risk mitigation is in place, such as tax credit insurance.
Question 10: How do buyers think about the return on investment when buying a tax credit?
Andy Moon: Final question for today. How do buyers think about the return on investment when buying a tax credit?
Kevin Haley: I think it's been interesting so far. We've seen a number of motivations and metrics that tend to be case-specific to each buyer. One example, we have some large buyers that really are volume-driven. In the early transactions, they're targeting larger projects, even if they are seeing the slightly narrower discount on those deals. But we have other buyers that are very much yield-focused. For them, they want to take on projects that are maybe a little bit more complex. If that will get them a discount of 10%, maybe a little bit higher, that's a trade that they're willing to make.
Billy Lee: Other investors just really care about time value of money. One important point in the June guidance is that taxpayers can offset their quarterly tax estimated payments with tax credits that they acquire or intend to acquire. That's an important three words there. So even if they are paying 92 or 93 cents for a dollar of tax credit, the effective IRR could be in the teens or potentially much higher, to the extent that they're reducing their estimated tax credits during the year and actually acquiring the tax credits late in the year or even in the following year.
Andy Moon: Thanks, Billy. There you have it, ten questions with the Reunion team. Thank you so much for listening today. We're excited about the level of interest in transferable tax credits and will be posting regular analysis on our LinkedIn page.
Questions of your own?
If you have questions you'd like us to answer, please send us an email at email@example.com. We have some great interviews lined up and will look forward to seeing you on the next video episode. Thank you.
Andy Moon, Co-Founder and CEO of Reunion, joined Shannon Holzer, Joey Lange, and Matt Donath of Edison Energy for an hour-long panel, "Powering Progress: An Overview of Policy Trends Shaping the North American Renewable Energy Landscape," on August 22, 2023. The panel provided a transferability overview, market update, and several policy insights, and concluded with audience Q&A.
Video recording and slides
Transcript of Andy's presentation
Overview of Reunion
Andy Moon: I'll start with a very brief introduction on Reunion. We're a marketplace that facilitates the purchase and sale of tax credits from clean energy projects. We currently have over $2 billion in near-term credits from leading clean energy developers available on our platform. We work closely with corporate finance teams to identify high quality projects and ensure a low-risk transaction. Our company was formed in the wake of the IRA, but our team has spent over 40 years in clean energy finance. We have a lot of experience both in tax equity as well as private finance.
Transferable tax credits will transform the way clean energy projects are financed
Andy Moon: When the Inflation Reduction Act passed, we saw a large opportunity in the transferability clause because financing has always been a major challenge for clean energy product developers. Transferability provides a much simpler and more streamlined structure, and tax credits from many technologies can now be transferred. In addition to solar, wind, and battery storage; now biogas, nuclear, manufacturing, and hydrogen projects can be transferred. There's a whole slew of tax credits that are available to be transferred. Historically, tax credit monetization has been dominated by tax equity, which is controlled by a handful of large banks. So, a major goal of transferability is to broaden the pool of investors that are investing in the energy transition. Any corporation that pays US federal tax can now be an investor in clean energy projects.
Corporations are paying attention to clean energy tax credits, given the volume of tax credits and the length of the program
Andy Moon: There's a lot of momentum that we're feeling right now from CFOs and tax teams from companies because the opportunity is large. The chart is from CohnReznick, which shows that the demand for tax credit monetization will reach $70, $80, or $90 billion annually in just a few years.
Andy Moon: And tax credit supply is hovering around the $20 billion range. There's just really a lot of demand for additional investors to come support clean energy projects. The other item is that, as many people here know, ITCs and other incentive programs have been extended piecemeal on a three- or five-year basis. And the Inflation Reduction Act is a long-term program. At the earliest, it will go to 2034. But many observers believe that because tax credits are uncapped until certain emission targets are reached, this program could last 20 or 30 plus years.
Treasury guidance from June 2023 provided certainty to transact
Andy Moon: As Shannon mentioned – just to highlight how new this market is – Treasury released guidance on June 14th, and that is really unlocked a lot of interest from corporate buyers. I think there was always the fear that potentially guidance would come with some unwelcomes surprises, but that certainly was not the case. Transferability, the mechanism, was explained quite clearly over a 108 pages. I think the biggest win is just having a clear sense of the mechanism by which how tax credits can be transferred. There were also some important economic clarifications to the positive side. So one is that tax credits that are purchased can be used to offset quarterly estimated tax payments, which greatly improves the return profile of the investment. And Treasury also clarified that if you buy a tax credit at a discount, so say you buy one dollar tax credit for 92 cents, that eight-cent discount is not taxable. We can go over any questions about the mechanisms in the Q&A, but just in brief – the way it works is the seller of the credit will be required to pre-register their project on an IRS platform and get a pre-registration number. Both the buyer and the seller need to attach a transfer election form when they file their tax reasons.
Purchasing credits is a simple process that drives tangible benefits
Andy Moon: I'll quickly go through a simple example for how a tax credit transfer will work. So if a corporation has, say, $50 million in tax liabilities, they could purchase tax credits from a clean energy developer or through a platform such as Reunion at a discount. And this discount is typically in the 7% to 10% range, but it really depends on a number of factors. So, assume that they pay $45 million in cash, they would then be able to offset $50 million of their federal tax liabilities. And given that the tax credit can now be used to offset quarterly tax payments, this is a big boon for IRR-driven investors, because that means that the effective IRR will be quite compelling.
Buyers face several manageable risks, which can be mitigated through due diligence, seller indemnity, and insurance
Andy Moon: I'll talk a little bit about the risks to be aware of when investing in a tax credit. In general, buyers do need to conduct due diligence on these projects to mitigate the risk that a tax credit is challenged by the IRS. That said, the diligence checklist is much narrower than a tax equity investment because you are just buying a tax credit. You are not making a true equity investment into the project. There are specific categories of diligence that need to be checked. In some instances, you are ensuring the project was actually constructed and connected to the grid, ensuring that the cost basis of the project is properly calculated in the case of an investment tax credit, and really ensuring that some of the bonus credit adders have properly been incorporated.
Beyond due diligence, sellers generally sign a broad indemnity, promising that if the tax credit is recaptured or reduced for any reason, the buyer will be made whole. However, if the buyer needs assurance that if the IRS successfully challenges the tax credit and the seller does not make good on their indemnity, tax credit and insurance is also available to ensure that the buyer doesn't realize a loss. In the future, we also think that diversification of projects will also be an important mitigator of risk.
Observations on current and future market
Andy Moon: Everybody wants to know about price, so I'll give some general observations on what we're seeing in the market. In 2023, which we're already at the end of August, I'd say buyers are very focused on a narrow set of projects. They tend to look for projects that are from very experienced developers that have financial strength behind them. They look for projects, generally with scale, that have proven technologies such as solar, wind and battery storage. And these are generally trading in a fairly narrow band. We're seeing these 2023 credits trade in the $0.90 to $0.92 range to the developer after all expenses.
Now, of course, there are a number of factors that can further impact the price for 2023 projects. One is product size. So, if the project size is small – say, a $5 to $10 million transaction – we're seeing buyers want a larger discount for those small projects just because this is a new asset class and there's a lot of diligence and new education that's required to do a project. So a lower price is required to motivate buyers to the table. Technology – I think there's a smaller pool of buyers for newer technologies. So, even biogas carries a bit of a larger discount, and it remains to be seen where pricing will settle for new technologies such as hydrogen or carbon capture. And then project risk is another piece. Projects that have items like large step-up in cost basis or that have large debt attached to the project can also carry a larger discount.
Production tax credits that are traded spot. 2023 spot credits trade at a narrower discount because there is not the risk of recapture or reduction in credits because those credits are typically sold after they're generated. For 2024 and beyond, conventional wisdom has been that prices on credits will eventually narrow and the discount will narrow over time. However, we are seeing that there's going to be massive influx of credits in 2024 and beyond. We have many projects such as nuclear, solar, and wind, and all these other credit categories that will be competing for the same tax credit buyers. I think the impact on price in 2024 and beyond really does remain to be seen.
We're seeing a lot of developers that have projects that will be constructed in late 2024 or in 2025 who are looking for a commitment from a buyer today to buy the credits when the project is completed. These forward commitments do generally carry a larger discount. The reason why a developer wants the forward commitment is because they want to be able to take that piece of paper to a bank and get a bridge loan against a forward commitment to buy credits in the future. So, that's another example of where buyers can achieve a larger discount and a higher return is by committing to a forward commitment in advance.
Reunion's digital platform has $2B+ in near-term tax credits from leading clean energy developers
Andy Moon: As I mentioned, Reunion launched our digital platform last month. We already have over $2 billion in near-term credits available for transaction with leading clean energy developers. We work very closely with tax credit buyers to really ensure a low risk and streamlined transaction process. If this sounds of interest, we love to talk and answer questions. We do realize that this is new for many people. And so a lot of our job today is really to answer questions and really make sure that buyers and sellers both understand exactly how the process works and feel comfortable with these transactions.
Reunion launches clean energy tax credit marketplace, which now has over $2 billion in tax credits available for sale
In July, we announced Reunion’s digital marketplace, with over $1 billion in near-term tax credits from clean energy projects such as wind, solar, battery storage, and biogas. Since then, the supply of tax credits on our platform has grown to over $2 billion!
Watch our marketplace announcement to learn more.
If you are a corporate buyer looking to purchase tax credits, please sign up to get access to the platform and take a look at our project portfolio. In addition to the largest inventory of marketable tax credits, we provide transactional support with deal structuring, insurance, and due diligence. Early tax credit transfer transactions are novel and complex, and we are here to answer your questions.
For project developers, please contact us to add your projects to our marketplace. All projects are listed in a way that protects the confidentiality of the sponsor, the project, and project counterparties. There is no obligation or exclusivity to listing a project. A seller portal will be released shortly that will allow you to easily add, edit, or remove projects from the marketplace.
Follow us on LinkedIn to stay up to date on our latest insights
Our founding team has a combined 40+ years of experience in clean energy finance, and we are sharing real-time market observations via our website and our LinkedIn page. Recent highlights:
- Billy Lee, Co-Founder and President, notes that tax equity is becoming relatively more scarce, and predicts transferability will become a component of most tax equity deals going forward (link)
- Kevin Haley, Head of Tax Credit Capital, wrote a popular article on how transferable tax credits help corporations navigate Corporate Alternative Minimum Tax (link)
- Our founding story: while Reunion launched in 2023, we have laid the groundwork for this company over many years (link)
Recent appearances at industry events
Andy Moon, Co-Founder and CEO, appeared on a panel discussion with Perkins Coie and Novogradac to do a deep dive into Treasury's guidance on tax credit transfers.
Andy Moon appeared on a panel with JP Morgan, Marathon Capital, and others in June at the Norton Rose Energy Finance conference; please keep an eye out for the August Project Finance newswire for a transcript.
Looking forward to the rest of the year
The Treasury Department released Proposed Regulations for tax credit transfers on June 14, and the clean energy industry breathed a collective sigh of relief. Uncertainty around the timing and the contents of Treasury guidance has been a hindrance to moving tax credit deals forward. Treasury clearly laid out the mechanism for tax credit transfers, and confirmed several important economic points (e.g., tax credits purchased at a discount will not be subject to tax on the discounted amount; tax credits can be used to offset estimated quarterly tax payments).
Reunion has been pleased with the uptick in activity from both buyers and sellers since June 14. Please let us know if we can help your organization purchase or sell a tax credit, or if we can collaborate on furthering the market for clean energy tax credits.
Have a great rest of the summer!
Over the past six months building Reunion, we have interacted with hundreds of market participants – developers, tax equity providers, lenders, syndicators, accountants, and lawyers. We have been excited to see the discussion evolve from binary debates about transferability versus tax equity, into more nuanced conversations about the future of renewable energy financing. In this piece, we reflect on several themes emerging from our conversations:
- Tax equity will continue to play a valuable role in a post-IRA world
- Tax equity is becoming scarcer on a relative basis
- Most tax equity deals will take on hybrid structures, involving components of tax credit transfer
- The sale of investment tax credits from hybrid tax equity deals should, in theory, command a slight premium
- “Standalone” tax credit transfers can close the tax equity supply gap
Tax equity will play a valuable role in the post-IRA world
Much has been written about the cost, complexity, and constraints of tax equity, so we won’t rehash those issues here. Instead, we’ll explore the three principal benefits of tax equity in the post-IRA market.
Monetization of depreciation
In any tax equity transaction, the sponsor expects to get value from monetization of the investment tax credit (ITC) as well as accelerated depreciation. Generally, however, the vast majority of near-term depreciation is allocated to the tax equity partner, so the sponsor is not able to absorb any material tax losses during the early years of the partnership. This is an important and sometimes under-appreciated point, especially in the context of step ups and phantom income (see below).
Flexibility for changes of control
With tax equity, a developer can divest its interest in a project without a material negative financial impact resulting from ITC recapture, because a developer typically owns only 1% of the project’s profits interest during the five-year ITC recapture period. This is important because many developers are owned by private equity or infrastructure funds, and some sponsors may plan to sell their interest within five years. Tax equity was not designed to create liquidity for project sponsors, but it has become a meaningful mechanism to support such secondary sales.
Step up for fair market value
When a project is sold by a developer to a tax equity partnership prior to mechanical completion, the purchase price is typically determined by a third-party appraiser who values the project above the developer’s cost to build. This step up allows the developer to apply the project’s ITC percentage – 30%, for instance – on a higher cost basis. Without detailing the appropriate sizing and risks of FMV step ups, we’ll simply emphasize their substantial value.
However, market participants often overlook that basis step ups create phantom income. If, for example, a developer builds a project for $100 and sells it to a tax equity partnership for a 30% step up to $130, the $30 of gain is taxable income. While the developer benefits from the additional ITC value generated from that incremental $30 – $9 for a project with 30% ITCs – they (or their partners) will realize a tax burden on that gain. Further, almost no depreciation from the project is available to reduce that burden since it has been allocated to the tax equity partner.
If individual partners in the developer live in high-tax states – California, New Jersey, and New York, for instance – those individuals may realize a marginal tax that exceeds the ITC and depreciation benefit from this step up.
Tax equity is becoming scarcer on a relative basis
In our conversations with developers, we’ve noted a near universal theme: tax equity has gotten materially harder to raise since the passage of the IRA, even for sponsors that have significant tax equity experience with large, contracted projects. The reason is simple – supply and demand.
Static supply of tax equity
The supply of existing tax equity is not expected to rise materially beyond the oft-quoted $18-20 billion of the previous several years. Many of the incumbent tax equity suppliers do not expect to budget major increases in the amount of tax liability allocated to tax equity, and we do not expect the arrival of major new entrants who can move the needle, especially given that transferable tax credits are a far simpler alternative.
Increasing demand for tax equity
The developer community, on the other hand, is generating more tax credits and this pace is accelerating. Projects that had not qualified for tax credits before the IRA – storage, biogas, nuclear, carbon capture, manufacturing, hydrogen, etc. – are now generating tax credits. What’s more, the relative number of credits per project is increasing. A solar project can now reasonably generate ITCs worth 40% or even 50%, as opposed to 22% pre-IRA.
Increasing bifurcation between the tax equity “haves” and “have-nots”
The largest sponsors with the deepest tax equity relationships may find themselves in an advantageous market position over the near-term, with the ability to close transactions with the best terms relative to their competitors. The majority of sponsors, however, will find capital raising process more competitive, challenging, and protracted.
Most tax equity deals will take on hybrid structures, involving components of tax credit transfer
A tax equity investor’s investment appetite is limited by both its total corporate tax liability as well as the amount that has been allocated internally to renewable energy transactions. In our discussions with tax equity investors, virtually all of them have indicated that they intend to use transferability as a “release valve” to spread their tax liability across existing clients who have more projects and more credits.
Investors will continue to underwrite tax equity deals but may retain only a portion of the credits generated from the project and sell off the remainder. This trend carries implications for sponsors.
The amount of credit that the tax equity investor will be able to sell will emerge as a significant point of negotiation
The value of an ITC that is sold (at a discount to a third party) is going to be less than the value of an ITC that is retained. Either (or both) the sponsor, or the tax equity investor, will need to absorb this economic hit. Given the scarcity of tax equity today, it seems unlikely that tax equity will bear the brunt of the discount of transferred ITCs.
Tax equity will become more complicated and expensive
Finally, expect tax equity to become more complicated and expensive. Introducing tax credit transfers to tax equity deals brings a new layer of complexity and deal documentation. This will increase the tax equity barrier to entry.
ITCs from hybrid tax equity deals – those “release valve” credits – should, in theory, command a slight premium
Large, institutional buyers of tax credits may prefer to buy credits from tax equity partnerships for three reasons:
- They can rely on the underwriting diligence of experienced investors
- Most financing in tax equity transactions is back leverage, meaning a borrower default would not result in a foreclosure, causing tax credit recapture
- In the event of an IRS challenge of eligible basis, the IRS will first assess any disallowance to retained credits before assessing them against credits sold to third parties. Said differently, the tax equity partnership takes the first loss (up to the amount of credits it did not sell) for any credit reduction by the IRS
Assuming the tax equity partnership retains a significant portion of credits, tax credit buyers are in a safer position, particularly where there are aggressive step ups or bonus credit adders.
“Standalone” tax credit transfers can close the tax equity supply gap
Luckily there is also the option for a standalone tax credit transfer, which bypasses tax equity altogether. While much simpler and less cumbersome than tax equity, such transactions are still complex and nuanced, and require careful diligence and risk allocation. In a forthcoming article, we will explore a few common transaction structures relating to standalone tax credit transfers and analyze both the merits and pitfalls of each.
Tax equity has been a major source of financing for clean energy for the past 15 years and will remain an important financing tool for the foreseeable future. Tax credit transfers will increasingly be included as part of tax equity deals due to the shortage of tax equity relative to the number of tax credits being generated. In addition, standalone tax credit transfer deals that bypass tax equity all together with emerge as a new financing option, with applicability across a variety of technologies and developer profiles. Reunion is excited to play a role in the rapidly evolving clean energy finance market, working closely with tax credit buyers, project developers, and other ecosystem participants.
If you’d like to learn more about what we do or collaborate on a project, please reach out to firstname.lastname@example.org.
“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, 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 email@example.com.
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.
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.
Reunion is excited to play a part in accelerating the clean energy transaction. To learn more, please reach out to us at firstname.lastname@example.org.
SAN FRANCISCO, CA — Today, Reunion launched its digital marketplace for clean energy tax credits, with over $1 billion of transferable tax credits available to immediately transact. Reunion has engaged with more than 200 clean energy developers to identify high quality solar, wind, battery storage, and biogas projects.
Reunion’s marketplace connects clean energy projects with corporations seeking to invest in federal tax credits at an attractive, risk-adjusted return. Reunion provides project origination, due diligence, insurance, and transaction support services to facilitate the purchase and sale of transferable tax credits, as enabled by the Inflation Reduction Act of 2022.
“Corporations play a key role in financing the clean energy transition and our marketplace will give tax credit buyers the confidence to transact,” said Andy Moon, CEO of Reunion. “Our team has spent most of our careers working in renewable energy tax equity and project finance, and we believe that properly structuring the purchase and sale of these credits in a diligent, yet scalable approach can unlock billions of dollars for critical clean energy projects.”
Reunion is working with dozens of projects to sell tax credits between $2M - $100M+ to qualified taxpayers. Reunion’s cohort of buyers represent corporate taxpayers in manufacturing, financial services, retail, technology, banking, and more.
“We are pleased to work with some of the most well-known and reputable project developers in the renewable energy business,” said Billy Lee, President of Reunion. “The early days of this market are all about building trust with the buyer and seller communities. The quality of projects we’ve assembled on our marketplace, along with our deep expertise in structuring tax credit transactions, will go a long way toward making that happen.”
Reunion raised corporate funding in early 2023, led by Segue Sustainable Infrastructure. David Riester, Managing Partner at Segue, commented on Reunion’s launch, saying “We backed Reunion because they have the right people and approach to help shepherd the energy transition into this new ‘season’ of project financing brought forth by tax credit transferability. There’s no more experienced team positioned to accelerate the flow of capital into these clean energy projects.”
Corporate tax credit buyers can register for early access to Reunion’s marketplace at www.reunioninfra.com.
Reunion officially opened its doors in December 2022, but my co-founder Billy Lee and I have laid the groundwork for this company over the last 15+ years of our respective careers.
Here’s the story of how we gained the confidence and the conviction to go all in and start Reunion.
Part 1: How Reunion’s founding team came together
Billy and I first met in late 2008 when I joined SunEdison, a leading solar development company. Billy had been one of the first employees at the company, and had already spearheaded some of the earliest solar transactions in the market. We quickly closed our first transaction together in 2009, when we sold a portfolio of solar energy projects in New Jersey to a first-time solar energy investor. Believe it or not, this was a very novel concept at the time!
We developed mutual respect while working together; Billy led a dozen-person project finance team that completed many of the earliest solar tax equity deals, with major banks such as Wells Fargo and JPMorgan. My team was successful in convincing the first US private equity firm to invest in a portfolio of solar energy projects, and brought many first-time investors to solar energy including bond and infrastructure investors.
Every solar financing was challenging back then, so we bonded over the many ways we had to use tenacity and creativity to get deals across the finish line.
Part 2: Achieving "founder-market fit"
After our work together in solar finance, we both started our own solar companies; Billy built out a solar tax equity financing company and partnered with investors such as D.E. Shaw. He later started a greenfield development company that developed utility-scale solar projects across the US. I started SunFarmer, a Y Combinator-backed solar energy company focused on developing countries that led the installation of 1,500+ solar energy projects in South Asia.
Billy and I joined forces in the summer of 2022 with the goal of starting a new company that would have a meaningful impact on climate. We quickly picked up a consulting contract from a California utility, while investigating several climate-related business ideas.
We kept coming back to the realization that we have a unique competitive advantage in renewable energy finance. Investors talk about "founder-market fit" - the unique insights and skills a team has to tackle a market opportunity. Billy and I have spent years driving real innovation in renewable energy financing by bringing new investors to the table and structuring first-of-a-kind deals. We have deep expertise, a strong track record, and vast networks in the space. In a way, we have spent our entire careers preparing for the launch of Reunion.
Part 3: A unique market opportunity
When the Inflation Reduction Act passed in August 2022, we immediately knew that the provision on “transferability of tax credits” would transform the way that renewable energy is financed. After years financing projects the traditional way (“tax equity financing”), we knew how painful the process often was for both renewable energy developers, and also for investors.
We spent our entire professional careers trying to make renewable energy financing more efficient and scalable, but there was one critical, insurmountable hurdle that we could not change - the US tax code. But with the passage of the IRA, tax credits became freely tradable for the first time - for tax nerds like us, we knew this would be massively disruptive (and no, we aren’t exaggerating!)
The market for transferable tax credits is also enormous; analysts expect upwards of $75B of clean energy tax credits generated per year by 2027 (see chart below), but the existing tax equity market only supplies roughly $20B in tax credit volume each year. Platforms such as Reunion will be needed to facilitate the transfer of large volumes of renewable energy tax credits.
Segue Sustainable Infrastructure has been at the forefront of the discussion on transferable tax credits, and they led a seed round in Reunion in December 2022, along with a dozen leading entrepreneurs and CEOs.
The future is bright; Reunion is growing
I listened to hundreds of business plans in my previous work as an early stage startup investor. While there are no rules to achieving startup success, several patterns emerged in teams I met with that ultimately were the most successful:
- Co-founders previously worked together on hard problems: The ideal co-founder brings relevant skills, similar goals and risk tolerance, and must be somebody you work well with. Not easy to find! As a result, it’s common for successful co-founder teams to have previous experience working together
- The team is uniquely positioned to solve the problem (“founder-market fit”): while some founders can pick a new market and just figure it out, it’s more likely that founders with a deep understanding or insight about their market find success
- Ripe market opportunity: The market has to be large, and growing in some interesting way that has not yet been exploited. Marc Andreesen says that when it comes to startup success, “market matters most”... even more than the product or team.
I am lucky to say that Reunion checks all three of these boxes. I have a long working history with my co-founder, who happened to be looking to get back into entrepreneurship at the same time I was. We picked a market that we know uniquely well, and it just so happened that a legislative change opened a huge new market opportunity.
Now is an exciting time to join Reunion at the ground floor; we have an incredible opportunity in front of us, and we are experiencing strong demand from both project developers and tax credit buyers. We are hiring for high-impact roles across marketing, business development, and project finance; please reach us with applications or referrals at email@example.com.
The new corporate alternative minimum tax (CAMT) is nothing if not complex. Created by the Inflation Reduction Act (IRA), the CAMT seeks to place a 15% “floor” under corporate taxpayers in order to raise revenues and force certain companies to bring their tax rate up to a uniform level. The number of companies affected is still unknown; the Joint Committee on Taxation estimated 150, but one estimate from KPMG exceeded 300 companies.
Implementation of the CAMT will take some time, as the specifics of the law are developed through IRS guidance and as corporate taxpayers calculate their exposure. In fact, the IRS has already granted penalty relief to companies who have not made estimated tax payments related to the new CAMT. But this relief is, of course, temporary and most companies affected by the CAMT will quickly start to look for viable ways to manage their exposure.
Fortunately, we already know that companies facing the CAMT may still utilize general business tax credits to reduce this tax liability back below the 15% threshold. And while the IRA created this burden, the IRA also created a possible solution in “transferable” clean energy tax credits that can be obtained with a simple purchase and sale agreement.
As tax teams figure out the CAMT and potential solutions, transferable tax credits are worth some analysis.
In creating the CAMT, Congress is attempting to do at least two things. First, the CAMT is designed to ensure that profitable corporations pay at least some federal income tax, regardless of the deductions and credits they may claim under the regular tax system. Second, the CAMT is also intended to reduce the gap between the book income and taxable income of corporations, which has been a source of public criticism and scrutiny.
The CAMT applies to large corporations (other than an S-corp, regulated investment company, or real estate investment trust) that report more than $1 billion in profits to shareholders on their financial statements. The CAMT imposes a 15% minimum tax on the adjusted financial statement income (AFSI) of these corporations, which is their income before taxes as reported on their financial statements, with certain adjustments.
KPMG points out that, “Because AFSI diverges in significant ways from taxable income, corporations with a higher than 15 percent effective tax rate cannot assume they have no CAMT liability.” This also means that corporations which are already paying above a 15% effective tax rate may still be subject to CAMT liability.
For example, here is a hypothetical review of what the CAMT’s impact could have been in 2021, from researchers at the University of North Carolina.
Transferable tax credits as a solution
One of the most important adjustments for the CAMT is the allowance of certain tax credits to reduce the CAMT liability–up to 75% of the combined regular and minimum tax. These credits include the same clean energy tax credits–Section 45 production tax credits and Section 48 investment tax credits, among others–that are enhanced by the IRA.
Practically speaking, this means that corporates facing CAMT liabilities can procure renewable energy tax credits via tax equity partnerships or the simpler “transferability” purchase and sale process to reduce any cash tax burden created or extended by the CAMT.
In addition, once companies are designated as “in-scope” for CAMT–meaning the minimum tax is applicable–that status is “hard to shake, even if income falls below the $1 billion threshold in future years,” per KPMG. So unless future guidance changes this fact, companies facing the CAMT may feel more comfortable structuring multi-year tax credit purchases.
Novogradac suggests that on balance, this will drive greater appetite for tax credits: “The IRA created a 15% minimum tax on corporate book earnings, which could boost demand for tax credits since some public companies will have larger income tax bills due to the corporate minimum tax and may seek to offset a portion of that tax liability with federal income tax credits.”
In a separate article, however, Novogradac also flags some potential challenges for CAMT-affected companies exploring the tax equity route (as opposed to transferability, for example):
- “...partnerships would be required to report to their partners the allocable share of the partnership’s AFSI. This will likely mean that accountants for those partnerships will need to perform a new analysis that includes certain adjustments, such as for accelerated tax depreciation, to calculate each partner’s share of the partnership’s AFSI as defined by the new law…
- This language also appears to require the corporation to record the flow-through AFSI income and/or losses of the partnership to determine its own AFSI. For tax credit investments that are recorded using the proportional amortization method or other similar methods that account for income or losses “below the line,” this adjustment for investments in partnerships appears to require that income or loss be recorded “above the line” for purposes of determining the corporation’s AFSI.”
Given the preexisting complexities around tax equity investing, transferability appears to be a best-of-both-worlds solution for companies facing CAMT liability. By purchasing renewable energy tax credits, any of the companies in this camp can easily reduce their tax burden without introducing new layers of accounting complexity.
For a high-level overview of transferability, see our article published here.
Next steps for CAMT and transferability
The Treasury Department released transferability guidance in mid-June, 2023 to clarify the rules behind how these credits are bought, sold, and utilized. There were no major surprises and the guidance was generally friendly to credit buyers. Several key points of clarification include:
- Application to quarterly payments – Treasury formally blessed the application of credits to estimated quarterly payments. While this practice was common for tax equity investors already, receiving formal approval only helps streamline the application of transferable tax credits.
- Credit value is not taxable income – Treasury clarified that the value of the credit to the buyer–that is, the difference between a discounted price paid for the credit and the full dollar of tax savings–is not considered taxable income to the credit buyer.
- Recapture risk to the buyer is partially limited – The risk of credit recapture due to a change in project ownership sits with the developer, not the buyer. The buyer is still responsible for other types of recapture risk, but can secure protection against that with indemnification and insurance.
More clarity around CAMT will undoubtedly develop as companies calculate their exposure and Treasury offers additional guidance. But transferable tax credits will continue to be an attractive solution.
On June 14th, the US Treasury released guidance on the tax credit transferability mechanisms established by last year’s Inflation Reduction Act. This highly anticipated announcement provides proposed regulations for credit transfers under Section 6418. In this article, we will share initial insights and takeaways from the guidelines, and share thoughts on their effect on clean energy financing moving forward.
The overall industry reception to this week’s guidance appears positive, as it has largely followed expectations that market participants were anticipating. The guidance provided three key things to enable more investment into renewable energy projects:
- Certainty that corporate taxpayers can utilize the credits as intended, as well as clear guidelines that will allow transactions to move forward.
- A clear delineation of the risks and who will be responsible for them.
- A relatively low-burden process for registering, transferring, and claiming the credits.
Takeaways from Treasury guidance were largely positive
1. Clarity on transfer mechanics
Sellers electronically pre-register with the IRS, receiving a project identification number associated with each tax credit eligible property. Sellers and buyers must file a transfer election statement, which includes the registration number and is attached to the seller's and buyer's tax returns.
The transferee and transferor may file their returns in any order, as long as the transferee return is for the taxable year in which the eligible credit is taken into account under the rules of section 6418.
The IRS has released an FAQ with more details on the transfer process.
2. Narrows risk to buyer on tax credit recapture
As expected, recapture risk sit with the buyer; however, the risk to the buyer is narrowed through the following clauses:
- The Proposed Credit Transfer Rules expressly permit indemnification relating to recapture of the buyer by the seller
- A change in upstream ownership of a partnership or S corp does not cause recapture for the buyer of the credit, although this would trigger recapture to the shareholder or partner who sold their interests.
This is one of the most positive outcomes of the proposed regulations. Developers are often structured as partnerships, some with many different equity owners. Subjecting tax credit buyers to the risk of upstream changes of control that inadvertently cause recapture is a difficult risk to manage, and would likely not be covered by tax credit insurance. Additionally, sponsors may opt to continue using some form of backleverage (where a partner in the partnership that owns a project is the borrower, as opposed to the partnership itself), instead of negotiating forbearance agreements from lenders.
Unfortunately this does not change the risk profile to a developer, and they will still need to think carefully about structuring deals to avoid recapture.
3. Proceeds to buyer are tax-exempt
Another large positive for prospective buyers is that income made from a purchase of a tax credit is non-taxable. If a buyer pays $45M in cash for a $50M credit, they would not be taxed on the $5M proceeds. This is also beneficial for sellers, as it should create a market equilibrium that is closer to the true cost of the credit, and help them extract more value from their sales.
4. Supports activities of partnerships and intermediaries
The guidance confirms that partnerships or S corps may qualify as eligible taxpayers or transferee taxpayers. This opens up additional transaction structures, and seems to enable syndication mechanisms similar to those in existing tax equity transactions.
Guidance also confirmed that intermediaries can support transactions without violating the rule against second transfers, which is helpful clarification that should allow third party financial institutions and platforms, such as Reunion, to assist with facilitating transactions.
5. Credits can be purchased in advance
As expected, advanced purchases of eligible credits are permitted, as long as the cash payments are made within the specified period. In an industry that deals with a long timeframe and complex, large-scale projects, this is a welcome clarification that should narrow the timing gap, and allow sellers additional opportunity to find short-term financing from lenders and investors.
6. Credits can be factored into estimated taxes
In accordance with advanced purchases, buyers will be able to think ahead by tax planning credit acquisitions. “A transferee taxpayer may also take into account a specified credit portion that it has purchased, or intends to purchase, when calculating its estimated tax payments, though the transferee taxpayer remains liable for any additions to tax in accordance with sections 6654 and 6655 to the extent the transferee taxpayer has an underpayment of estimated tax.”
This is particularly meaningful, as a tax credit purchaser can calculate estimated tax payments in anticipation of future purchases of tax credits. From a time value of money standpoint, this accretes value to the purchaser in the context of forward purchases of tax credits.
7. Flexibility on 20% excess transfer fee
There is a 20% fee for excess credit transfer, but this “does not apply if the transferee taxpayer demonstrates to the satisfaction of the Secretary that the excessive credit transfer resulted from reasonable cause.” The guidance provided specific examples of what constitutes reasonable cause, and generally reflects standard due diligence efforts that Reunion would facilitate with respect to transactions on our platform.
8. Timeline for opening of registration portal
Lastly, the guidance confirms that the portal for registering and filing elections should open in late 2023. This should not be limiting, as most market participants expect that deals agreed upon in pre-registration will be able to be filed normally once registration opens later this year. The formal filings on the portal will provide for greater market transparency, and ensure that the same credits are not transacted twice.
Several takeaways from Treasury guidance were less positive
9. Lessees in lease pass through transactions are not allowed to transfer credits
This is one of the biggest surprises of the guidance, as most market participants had been expecting that such transfer would be allowed, and a number of transactions have closed based on this assumption. Given that a lessor is explicitly allowed to pass through an ITC at FMV (as opposed to cost), this could be the first indication that the IRS will be heavily scrutinizing transactions that step up basis.
In general, basis step up is a topic that is controversial, important, complicated and subject to interpretation. Most importantly, challenges to qualified basis are the most likely meaningful risk that a tax credit transferee assumes. We will be doing a deeper dive in this area in the near future; stay tuned.
10. Base and bonus credits must be sold in vertical slices
A seller has flexibility on the amount of credits they would like to sell, and can sell credits from one facility to multiple buyers. However, base and bonus credits cannot be sold separately; each buyer must receive a “vertical” tranche that includes a pro rata portion of base and bonus credits.
Said differently, all tax credit purchasers buying tax credits from a particular project are buying the same credit; if there is a reduction of credit, all purchasers will suffer a pro rata reduction. Sponsors were hoping to be able to sell different tranches of credits, at different pricing and risk profiles. While it is possible to synthetically allocate risk amongst a set of credit purchasers through contractual means, it remains unclear whether this will emerge as a common practice.
11. Passive loss rules continue to apply
While the guidance proposes that active/passive rules are expected to apply, they are requesting further comments. For the time being, we believe that it will remain challenging for individuals to participate in tax credit sales, other than to offset passive income.
Treasury Guidance was widely applauded by the clean energy industry for providing clarity on how project developers and investors can take advantage of transferable tax credits, a key financing tool of the Inflation Reduction Act. One goal of the IRA is to attract wider participation in clean energy financing through tax credits; Treasury guidance has provided the clarity that corporate investors will need to move forward with clean energy tax credit purchases. According to Treasury Secretary Janet Yellen, “More clean energy projects will be built quickly and affordably, and more communities will benefit from the growth of the clean energy economy."
Reunion is excited to play a part in accelerating the clean energy transaction. To learn more, please reach out to us at firstname.lastname@example.org.
Corporates are now one of the most prolific forces on the planet for meaningful climate action. Who saw that coming 10 years ago!? A leading benchmark group, Science Based Targets initiative (SBTi), now counts nearly 5,000 companies taking action, with 2,600+ companies setting formal science-based targets and 1,800 companies with net zero goals.
A key decarbonization activity has been to offset electricity-related emissions (also known as “Scope 2” emissions) by purchasing electricity from renewable energy generation–often via a corporate power purchase agreement, or PPA.
While PPAs have been a great tool to drive new renewables build-out, not every corporate has the financial strength, risk appetite, or ability to sign up for long-term PPA contracts, which typically run for 10 to 20 years. Fortunately, following the passage of the Inflation Reduction Act (IRA), sustainability leaders now have even more ways to tackle their Scope 2 emissions targets.
Tax credits – why do they matter?
A central feature of the IRA was the expanded tax credit regime. Now, renewable energy and sustainable infrastructure projects can qualify for 10+ years of tax credits which can be monetized as part of the project financing process.
These tax credits have drawn a lot of attention for driving top line growth projections for renewables. For example, Wood Mackenzie estimates that solar, wind, and battery storage alone could produce as much as $90B of tax credits per year:
As the chart below shows, the IRA tax credit incentives will help drive significant deployment of new wind, solar and other sustainable technologies. .
Less attention has been paid to where this capital comes from. Because the vast majority of clean energy funding in the IRA came in the form of tax credits, the unspoken assumption is that corporate taxpayers will simply monetize these credits for project developers as they did with pre-IRA tax credits. But going from a tax credit market that was traditionally in the $18B-$20B range pre-IRA to one that is 2-3x larger or more post-IRA will necessitate a large number of new corporate taxpayers to enter the market and trade tax capacity in the form of cash for tax credits.
What does this have to do with corporate sustainability?
As corporates look for energy-related sustainability tools beyond the PPA, investing capital directly into projects via tax equity or its new post-IRA cousin, transferability, is an appealing option. Some companies like Starbucks, Facebook, and Nestlé, have invested in tax credits with great effect already.
With the IRA’s new transferability provision, the process is more straightforward than tax equity; companies with tax liability (which they have to pay anyway), can instead purchase tax credits at a discount. For example, paying $0.90 for $1.00 of tax credits on $50M of tax liability would net an immediate $5M savings.
Investing in transferable tax credits has a sustainability story, and it drives meaningful clean energy impact. But there’s a catch–the investment activity of monetizing tax credits on behalf of a specific renewable energy project doesn’t “count” towards Scope 2 emissions reduction targets. The corporate, despite putting tens or hundreds of millions of dollars into a project, would also need to buy the energy attribute certificates (EACs) or renewable energy certificates (RECs) to make a formal “green” claim.
Fortunately for sustainability leaders, the savings generated by purchasing tax credits–$5M in our example above–could be redirected to offset the cost of REC procurement. This approach helps bring sustainability activity more directly into alignment with the financial incentives of the business.
“From a CFO’s perspective, an interesting feature of the green-energy credits is a provision in the law that makes the credits transferable one time”
Deloitte, “For CFOs, the full impact of the Inflation Reduction Act is still coming into focus”
Corporate sustainability leaders can be internal champions for tax credit purchases
Corporate sustainability leaders should champion tax credit purchases inside their company for three reasons:
- It drives real impact – as noted above, tax credit monetization is a real, measurable, and impactful way to put steel-in-the-ground. Without tax credit financing, projects don’t get built. Any company putting $20M, $50M or $100M+ of tax capacity to work financing projects is directly accelerating the energy transition.
- It fills an enormous funding gap for clean energy – also noted above is the gap between today’s tax credit investment market (~$20B annually) and the very near future of ~$60 to $90B in annual demand for tax credits. . Only taxpaying corporates can effectively monetize these credits to enable projects. Without them, the promises of the IRA and much of the decarbonization effort falls short.
- It provides an economic benefit for action on sustainability – unlike RECs and PPAs which are often a net cost to the corporation, tax credits are a net benefit, saving 7-10% annually on tax liabilities that the company is already responsible for. These savings can be reinvested in REC purchases or other activities to secure the desired environmental attributes.
Conclusion – sustainability teams can “do well and do good” with tax credits
Given the deep necessity of more corporates putting their tax liability to work in monetizing tax credits for renewable energy project developers, sustainability teams are a natural place to start for leading this effort.
The alignment of doing well, by improving the bottom line via tax savings, and doing good, by sending already spoken for capital directly into renewable energy projects, should have any sustainability leader excited to pick up the phone and call their corporate finance team to get started.
Anyone who has developed solar projects knows about the “December rush” – all hands on deck to get projects built and interconnected, hounding utilities for inspections and PTO letters, coordinating last minute signature pages up until COB on New Year’s Eve – all because tax equity investors generally allocate tax capacity on an annual, tax year basis. If tax equity commits to fund a project in a certain year, it wants to make sure it gets the expected tax benefits from that project in that tax year. Accordingly, there is significant pressure for developers not to miss the 12/31 deadline, and often there are significant financial penalties if they do – hence, the December rush that many developers and financiers know well. (For years, my peers and I never took vacation until January 1st.)
Transferability is appropriately labeled a “game changer.” Having worked in project finance and tax equity for nearly 20 years, I knew that the ability for clean energy tax credits to be freely bought and sold would be transformative and disruptive. So much so, that soon after the passage of the Inflation Reduction Act, I dropped everything and launched Reunion with my longtime colleague and renewable energy veteran, Andy Moon.
Lately, I’ve heard some people mention that transferability gives developers the “gift of time” and will alleviate the massive pressure to place projects in service by the end of year. Unfortunately, transferability, while transformative, is not a panacea for all challenges.
What is the gift of time?
In a typical tax equity partnership transaction, a tax equity partner must fund 20% of its investment by mechanical completion. Time is not a developer’s friend; as a project approaches COD, the need to close tax equity becomes more and more urgent (and a developer’s leverage in tax equity negotiations diminishes). With the IRA, this urgency becomes less pronounced, because the developer always has a fall back option to sell tax credits.
With transferable tax credits, Section 6418 of the Internal Revenue Code (IRC) indicates that the seller of the credit has until the filing date of its tax returns (as extended) to sell the credits. Therefore, the owner of a project that is being placed in service on 12/31/2023 can sell the associated 2023 tax credits up until 9/15/2024 (the extended filing date for partnerships). If the project is placed in service on 1/1/24, it generates a 2024 credit but that credit can be sold up until 9/15/2025.
This certainly gives developers more flexibility on when to sell the credit. However, what hasn’t changed is that tax credits (specifically, the IRC §48 investment tax credit which applies to solar, storage and other technologies) are generated when the project is placed in service. So a project placed in service on 12/31/2023 will generate a 2023 tax credit, whereas a project placed in service on 1/1/2024 will generate a 2024 credit. This is true whether or not the tax credit is transferred or allocated to a partner in a traditional tax equity partnership.
So a tax credit buyer who has agreed to buy a 2023 credit from a project developer to reduce its 2023 tax liability will not be obligated to close the purchase if the project slips to 2024 (unless of course, this has been contemplated in the deal documents and priced accordingly).
The IRA does include a three-year carryback provision, but it’s not straightforward to utilize
At first blush, the three-year carryback seems like an incredible tool to unlock significant tax liability and add flexibility. However, actually utilizing the carryback is cumbersome in practice; it is not as simple as just carrying the credit back to the prior year.
In the example above, a developer misses the year end deadline and places a project in service on 1/1/2024. It sells the 2024 credits to a buyer who wishes to apply those credits against 2023 liability. Unfortunately, the buyer must first apply those credits against its 2024 liability (which they cannot actually do until filing its 2024 tax return in 2025). Only to the extent that there are unused credits after application against 2024 liability can the buyer carryback the credits. But it must first carryback the credits to the earliest possible date applicable, or 2021; any unused credits would then be applied to 2022; then finally to 2023. Buyers do not have the discretion to pick and choose which years to apply carryback credits.1
Practically speaking, carrying back credits would require a buyer to amend one or more of its prior year returns, which has its own complexities (Joint Committee review, increased audit risk, etc.). The juice may not be worth the squeeze.2
Reunion is committed to sharing transparently both the benefits and risks of transferable tax credits, based on our years of experience structuring renewable energy finance transactions. Transferability will unlock billions of dollars in additional renewable energy financing, by attracting new investors to the space with a simplified and low-risk investment process. However, tax credit buyers will continue to need to ensure that the developers they work with are able to deliver tax credits within the desired tax year. Reunion can help both tax credit buyers and sellers navigate this challenge.
If you'd like to learn more about how Reunion can help you buy or sell the highest quality clean energy tax credits, please reach out to email@example.com.
 IRC §39 is the code section that governs carrybacks.
 Anecdotally, many people don’t realize that the pre-IRA §48 credit had a one-year carryback feature, and not surprisingly, was rarely employed in prior tax equity deals.
The Inflation Reduction Act of 2022 (IRA) was a sweeping bill with many implications for the energy transition–particularly the financing of new projects. In the IRA, Congress specifically sought to incentivize private sector investment into the energy transition. One of the most prominent ways they did this was through tax credits, to incentivize corporate taxpayers to redirect capital into the clean energy and sustainable technology industry.
A recent assessment of the IRA from Boston Consulting Group (BCG) and Breakthrough Energy puts a fine point on the value of tax credits in switching to low carbon energy, by demonstrating the impact of tax credits on levelized cost of energy (LCOE).
Per BCG’s analysis, tax credits from the IRA and other major energy-related legislation can drive between 20% and 60% reductions in LCOE across six technology types. But a low LCOE and actual steel-in-the-ground are not the same thing. To physically deploy these less expensive technologies, project developers will require many billions of dollars of project finance capital.
Bloomberg illustrates just how significant the demand for investment dollars may be over the next 25-30 years. This demand is a powerful function of government policies, decarbonization goals of Fortune 500 companies that increasingly extend down into global supply chains, and the aforementioned plummeting LCOE that allows low carbon energy technologies to displace incumbent coal, gas and oil-based power generation. That’s a very difficult demand-pull force to derail once it gets going.
The opportunity and challenge of tax credits for project finance
So where will all this capital come from? In the U.S. the IRA’s tax credit regime significantly enhances project capital stacks with upwards of $500 billion of tax credits over the next 10-20 years, depending on various estimates and factors. Here’s one such estimate from Credit Suisse, which projects $576B in tax credits over a 10-year period.
The IRA also enhanced the value of tax credits on a project-by-project basis. For example, developers can now monetize up to 70% of a solar project’s costs with the addition of bonus credits. Project developers typically are not able to absorb the tax benefits from their projects, and traditionally would tap into a $15B-20B tax equity market to finance the tax credit portion of any given project. With the enhancements from the IRA, the renewable energy sector could require up to 3.5x market growth by 2030 and possibly ~5x growth by 2049 according to demand projections by Wood Mackenzie. And that doesn’t even include fuels, CCUS, hydrogen, manufacturing or any of the other tax credits created by the IRA. That's a lot of external tax appetite being put to work that did not previously participate in this market.
Monetizing tax credits for project development will be one of the primary barriers to clean energy deployment, particularly in the initial years following the IRA legislation as corporate tax groups are educated on the opportunity to redirect their tax payments into renewable energy tax credit investments.
Recruiting capital into sustainable technology tax credits with transferability
Following the IRA, the question developers now face is how quickly and to what extent they'll be able to monetize these benefits as they execute on their development pipeline.
Tax credit-related capital has traditionally come from large banks such as JP Morgan Chase, Bank of America, Wells Fargo, and US Bank; a handful of banks account for the majority of tax equity investment capital in recent years.
The IRA legislation seeks to broaden this pool of capital to meet the anticipated demand represented above in the WoodMac chart. To do this, they created a transaction mechanism called Transferability which allows project developers to monetize their credits with a simple purchase-and-sale agreement, rather than the traditional equity partnership investment structure.
Here is a detailed description of transferability.
Transferability as a promising solution
Transferability isn't intended to replace traditional tax equity; instead, it gives corporate tax and treasury teams an alternative pathway to:
- Easily secure tax benefits to offset their federal income tax liability, and
- Participate in financing new, renewable energy and sustainability infrastructure that aligns with their corporate ESG goals
The value proposition for corporate taxpayers is simple: redirect your tax payments into clean energy projects and receive a discount on your federal tax liability. The reality is a little more complicated – tax credit purchases do carry some risks and reporting requirements, so partnering with third parties on transactions can often streamline the process. But earning an estimated 8%-10% discount on federal tax with controllable risks will be an attractive proposition to corporate taxpayers who may have chosen not to pursue traditional tax equity investments.
If the IRA is successful in its goal to scale more established technologies while kickstarting newer technologies like hydrogen and CCUS, a deep market for transferable tax credits could develop by 2030 with wider pricing spreads and creative structures used to pull more capital in from corporate taxpayers.
In conclusion, while it’s early days in the post-IRA renewable energy project finance market, the outlook is bright for both sustainable technology growth broadly speaking and for transferable tax credits sales specifically.
Reunion Infrastructure is leading the market on transferability as a service by packaging market expertise with core services needed to execute rapid, de-risked, and repeatable transferable tax credit transactions. Through its marketplace platform, Reunion provides:
- Access to a best-in-class range of project and tax credit types
- The ability to bundle different project or credit types into risk-adjusted portfolios
- Comprehensive due diligence and legal documentation to project buyers
- Access to tax credit insurance products
- Reporting services to ensure credit transactions are properly recorded
To learn more about Reunion, please contact Kevin Haley at firstname.lastname@example.org.
The Inflation Reduction Act of 2022 (IRA) delivered a plethora of benefits to renewable energy project developers, including billions of dollars in tax credits and newly created flexibility to transfer tax credits or capture direct pay.
But these benefits come with strings attached, and it’s important for any clean energy project developer to understand the rules before diving into new projects. These strings are divided into two groups – “carrots” and “sticks” that the federal government is using to guide developers to meet certain conditions. Starting with the “sticks,” here is a brief overview of the eligibility rules for renewable energy Production Tax Credits (PTC) and Investment Tax Credits (ITC):
How should developers think about these rules?
The simplest way to approach the wage and apprenticeship rules is to treat them as necessary prerequisites to project development. Without following these rules, developers will only capture a 6% ITC or 0.52 cent/kWh and leave significant value on the table.
Developers who fail to meet wage and apprenticeship standards may “cure” their shortcomings by repaying shortfalls plus interest, or certain fees/penalties. If the developer was determined to have intentionally failed to meet these standards, the penalty amounts increase significantly.
Fortunately for developers, the Department of Labor already publishes wage determinations and rates, and will be adding to that list as this program takes effect. Likewise, there has been increasing interest in apprenticeship programs across the country. New programs like the Real World Academy in New Jersey and the Sustainability Hub in Illinois are springing up and the Solar Energy Industries Association (SEIA) has a number of resources to support developers.
How do these prerequisites differ from adders?
So-called “adders” are the second important part of the tax credit regime created by the IRA. Serving as the “carrot” for developers, adders are true incentives for development under certain conditions. Here is a brief overview of the adders specific to the Production Tax Credit (PTC) and Investment Tax Credit (ITC):
How should developers think about adders?
Adders can be a valuable way to capture additional PTCs or ITCs for any given project. Importantly, however, developers should be thorough in their diligence of eligibility. Many tax equity investors won’t fund adders until full IRS guidance has been issued, and will expect to see diligence documents proving the project’s qualifications.
Some groups are already publishing helpful maps to illustrate where certain adders may be available, such as energy communities and low-income communities. Here is one example from S&P Global.
But once IRS guidance is in-hand and developers can confidently assess their project locations and domestic content, the adders under the IRA can deliver even more tax equity or transfer tax credit capital to projects.
Where do we go from here?
The Department of Treasury and the IRS are continuing to release guidance related to the IRA. In tandem, the project developer industry is collaborating with each other and industry groups like SEIA to identify best practices and optimize for maximum development value. Over the course of 2023, expect to receive more clarity on the formal obligations under the IRA, and the informal best practices across the renewable energy industry.
Reunion Infrastructure is working with 50+ developers to source transfer tax credits for banks, insurance companies, and corporates with tax appetite in 2023 and 2024 or beyond. Whether you are a developer or taxpayer looking for credits, please reach out at email@example.com.
The Inflation Reduction Act of 2022 (IRA) enables the purchase and sale of certain federal tax credits through a process referred to as transferability. Using a simple purchase contract, corporate tax departments can realize savings of up to 10% on their federal income tax burden by acquiring transferable tax credits at a discount from domestic clean energy projects such as wind, solar, and battery storage. Transferability was created in part to help minimize the complexity associated with traditional tax equity investing. By reducing the barrier to entry for corporate taxpayers to access these credits, the IRA seeks to incentivize more capital flowing into the sustainable energy economy.
How we got here
The IRA has been called the largest piece of climate legislation ever enacted. The backbone of the climate and energy spending in the bill is more than $230 billion of tax credits for clean energy projects, carbon capture and sequestration projects, electric vehicle charging equipment, and sustainable technology manufacturing. A small number of corporate taxpayers have traditionally helped project developers monetize these tax credits through a process called tax equity financing. This process is complex and requires a team of lawyers, accountants, and appraisers to help establish complicated partnership structures.As a result, the majority of capital that flowed into the $15B-$20B pre-IRA tax equity market was historically provided by a handful of large banks. Given the limitations on these banks’ tax appetite, something would need to change in order to attract capital for the IRA’s 10x or greater tax credit regime. To solve this challenge, Congress created a new monetization mechanism called transferability or transferable tax credits. Now, post-IRA, any company with federal income tax liability may use a standardized purchase and sale agreement to buy tax credits at a discounted rate, allowing them to earn a savings on their tax bill while also financing new sustainable infrastructure.
What corporate tax groups and sustainability teams need to know
By exchanging cash for transferable tax credits, a corporation could, for example, spend $45M for $50M of tax savings, realizing a $5M savings compared with paying their normal federal income tax liability.There are nine types of tax credits (across 11 sections of the tax code) now available for transferability. Companies can buy transferable credits from different technologies and project types. More established technologies are likely to be viewed as lower risk, whereas newer technologies may offer more attractive pricing.
Across these nine types of tax credits, several of them are categorized as “production tax credits” (PTCs) or “investment tax credits” (ITCs). This terminology refers to how the credit is generated–either as the item in question is produced (e.g. kilowatt hours of renewable energy) or as capital is invested in the associated project (e.g. a percentage of the cost of a solar farm). Tax groups will want to make strategic decisions about sourcing PTCs vs. ITCs or both, in order to secure streams of tax credits over time in the case of PTCs or one-off purchases in the case of ITCs. Intermediaries can help in structuring the procurement of these credits.
Timing and process
Some specifics of the transfer process are awaiting clarification from the Treasury department, but there are some things we already know from section 6418 of the U.S. tax code:
- Credits can be elected for transfer up to the time the seller files their tax return (Example: a credit generated in CY2023 can be transferred to a buyer until April 15, 2024 or October 15, 2024 for extended corporate filers)
- Credits can only be transferred in exchange for cash to an unrelated party
- Cash paid by the buyer is nondeductible
- Credits may only be transferred one time; resale of the credits is not allowed
- Buyers may carry back the credits up to three years, and carry forward the credits up to 22 years
The transactions themselves will be completed with a customized but relatively simple purchase and sale-style agreement. These should be constructed by experienced tax attorneys to ensure adequate protections for buyers and sellers, but are ultimately less complex than traditional tax equity partnership structures.
Transferable tax credits carry lower risk, in certain cases, versus traditional tax equity partnerships. For ITCs, a tax credit buyer is not concerned with the ongoing performance of the project beyond low-probability recapture events. And even for PTCs, the primary performance risk is related to the produced credit volume and not financial performance. The projects and developers associated with these credits should be vetted and underwritten to ensure credits are delivered as expected. For buyers of transferable credits, this review process can add certainty to reduce disallowance or recapture risk. Typically, buyers can also secure indemnifications from sellers to protect themselves in the event of recapture events. Transferable credits can also be insured against recapture, providing a backstop to indemnification.
Transferability represents a new pathway to access well-understood tax benefits for corporate taxpayers. By participating in the transferable tax credit market, companies can “do well and do good” by supporting renewable energy infrastructure and reduce their tax liability. Partnering with seasoned clean energy finance experts can help reduce risk and ensure a smooth, replicable transition process. For more information or to explore live project opportunities, please reach out to firstname.lastname@example.org.