The “One, Big, Beautiful Bill” and the implications for corporate taxpayers and the clean energy industry

Key features of the IRA's 11 transferable tax credits

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

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

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Jump to a credit

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

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

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§45Y PTC - Clean electricity production credit

Funding mechanism: Production tax credit

Technology grouping: Electricity

IRA Section: 13701

New or existing: New

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

U.S. Code: 26 U.S. Code §45Y

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

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

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

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

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

Inflation adjustment: Subject to an annual inflation adjustment

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

Recapture: Not applicable

Rates

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

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

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

Funding mechanism: Investment tax credit

Technology grouping: Electricity

IRA Section: 13702

New or existing: New

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

U.S. Code: 26 U.S. Code §48E

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

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

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

Stackability and limitations:

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

Inflation adjustment: None

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

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

Rates

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

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

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Introduction

Over the past year, we have talked to scores of potential buyers about the benefits and risks of acquiring transferable tax credits. Many measure their economic benefit in terms of the discount of the credit – i.e., how much they are willing to pay for a $1 reduction in their federal tax liability.

While important, the discount represents a single dimension to evaluate economic return. Payment terms for credits, as well as the potential impact on estimated taxes, are also key considerations.

In this article, we explore several hypothetical scenarios to understand how transaction timing impacts other key metrics, including internal rate of return (IRR) and return on investment (ROI).

Transaction scenarios under different payment terms

Let’s consider a transaction in which a corporate taxpayer, ABC Corp., is acquiring $100 of tax credits for a notional price of $90, reflecting a 10% discount. ABC is a C-Corporation, with estimated tax payments due on the fifteenth of April, June, September, and December. Its tax filing deadline is April 15 of the following year, but ABC makes an election to extend the date of its filing (and, for this example, we assume it files on September 15).

For purposes of this simplified analysis, we will assume that ABC does not calculate estimated taxes on an installment method but instead calculates estimated taxes based on equal quarterly payments.

Scenario 1: Sign and close at end of year, no estimated payment reduction

ABC identifies a tax credit opportunity in Q4 of their fiscal year and enters into a tax credit transfer agreement (TCTA) on December 31, 2024. ABC closes on the credit purchase simultaneous with the execution of the agreement and pays $90 on the same date.

Given the date of the purchase, ABC is unable to benefit from the reduction of estimated taxes throughout the year. Assuming it files its final tax return in September 2025, ABC receives a $100 benefit at that time through a reduction of its annual federal tax liability.¹ The internal rate of return on this purchase would be 16%, and the ROI 11%.

Scenario 2: Sign and close at beginning of year, four quarters estimated payment reduction

ABC identifies a tax credit opportunity early in the year and enters into a TCTA on January 31, 2024. As in scenario 1, it closes and pays for the credits simultaneous with the execution of the TCTA. (This would typically occur if a credit were generated early in the tax year; for instance, if a solar project was placed in service in January 2024.)

ABC is able to reduce its four quarterly estimated payments by $25, reflecting an overall anticipated reduction of its federal tax liability of $100. The IRR impact of this transaction is 23%, while the ROI remains 11%.

Scenario 3: Sign and close mid-year, three quarters estimated payment reduction

Let’s assume that ABC identifies a tax credit opportunity and executes a TCTA on June 15, 2024. As in the previous scenarios, it closes and makes payment on the same date. In this scenario, ABC would have a cash outflow of $90 but realize an economic benefit of $50, as it would reduce its Q2 estimated tax payment by half of the tax credit purchased (reflecting the $25 of savings for each of Q1 and Q2). The net effect of its purchase on June 15 would be a $40 outflow.

In the next two quarterly payment dates, ABC would reduce its estimated tax payments by $25 each, producing an IRR of 82% and an ROI of 11%. (We realize that as the duration of an investment shortens, IRR becomes less meaningful as a metric.)

Scenario 4: Sign early year, close end of year, four quarters estimated payment reduction

In the transferability guidance released in June 2023, the IRS stated that a “transferee taxpayer [i.e., a tax credit purchaser] may also take into account a specified credit portion that it has purchased, or intends to purchase, when calculating its estimated tax payments…” (emphasis added). This is a favorable provision, as we’ll demonstrate in scenarios 4a and 4b.

Let’s assume that ABC identifies a tax credit opportunity early in 2024. It is a solar project that is expected to be placed in service in December 2024. ABC enters into a TCTA with the project owner in January 2024, but closing of the purchase and sale is conditional on the completion of the project. Therefore, the TCTA represents a binding, forward commitment to purchase credits from the project, but no payment is made until later in the year.

Given that the IRS guidance allows for ABC to reduce its estimated tax payments for credits it intends to purchase, and an executed TCTA is clear evidence for such intention, ABC would be able to reduce its four quarterly estimated tax payments by $25 and pay for the tax credits in December 2024 when the project is completed.

Once again, the ROI of the transaction remains at 11% (see Scenario 4a).²

In addition to reducing the buyer’s federal tax liability, this transaction has the benefit of generating working capital. Assuming the quarterly tax savings earn a conservative annualized return of 5%, the ROI of the transaction increases to 13% (see Scenario 4b).²

Keep potential scheduling delays in mind for ITC transfers

Keep in mind, project delays are a key risk for a buyer to evaluate in ITC transfer transactions when a project is anticipated to be completed late in the year. For example, if ABC reduced its quarterly tax payments throughout 2024, but the project in question was delayed into 2025, ABC would either need to find replacement 2024 credits from a different project or be subject to underpayment penalties.

We touched on this risk in an earlier blog post.

IRR and ROI metrics represent post-tax returns for the buyer

In another favorable provision, the IRS affirmed that the buyer does not have gross income with respect to the discount of a purchased credit. Therefore, the IRR and ROI metrics discussed in this paper represent post-tax returns (the exception being the interest on working capital in Scenario 4b, which would be taxable).

To the extent that a corporate taxpayer is viewing tax credit purchases as an alternative to traditional treasury investments, it should keep in mind the post-tax nature of the return metrics.

How Reunion can help

Reunion operates a managed tax credit marketplace and provides close transactional support with a keen eye to risk identification and management. With over 40 years of combined tax credit transaction experience, Reunion’s leadership team guides buyers, sellers, and their advisors through every phase of the transferability process.

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Footnotes

¹For this analysis, we will assume that ABC receives the benefit of the credit upon filing of its tax return. In reality, this may depend on other factors, including if and when ABC receives a cash refund for overpayments.

²IRR is not a meaningful metric in this scenario as inflows of cash precede any outflows.

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

General structure

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.

Commercial terms

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.

Post-closing covenants

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.

Indemnification

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.

Guarantee agreement

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.

Termination

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.

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Footnotes

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.

Tradable tax credits are becoming a hot commodity in the renewable energy industry.

A new breed of climate tech startup is emerging to take advantage of provisions in the U.S.’s Inflation Reduction Act that for the first time allow clean-energy tax credits to be bought and sold. That trading will unlock tens of billions of dollars in previously inaccessible financing for solar, wind, and battery farms, in particular projects whose scale falls between an individual household and a huge installation.

Those projects, which often went unbuilt due to a lack of financing, could dramatically speed up progress toward the Biden administration’s goal to fully decarbonize the electricity grid by 2035. The provisions also present a new method for all kinds of companies to get a break on their taxes in a way that looks good on their sustainability marketing.

Tim’s view

Over the last 20 years, tax headaches have hampered the rollout of renewable energy in the U.S. at least as much as technology glitches, supply chain bottlenecks, or competition from fossil fuels. But the IRA changes the game by allowing project developers to sell their tax credits without the hassle and expense of a frequently used type of financing known as tax equity. That reform is one of the law’s biggest, if least heralded, victories.

The market for renewables tax-equity deals is about $15-20 billion annually. That number is unlikely to grow, especially with a recession looming. If project developers can sell their tax credits in a relatively painless way to any corporate taxpayer, it will at least double the amount of financing available, said Eric Rubinstein, chief investment officer at Leyline Renewable Capital, a North Carolina-based clean energy investment firm. That would keep tax financing on pace with projected demand.

Say you’re a company that develops midsize solar farms and has interest in a project from a rural farming town. You predict the tax credits the project will qualify for once built. Then you look for a buyer: any company from Google to a grocery store chain. You sell the credits at a discount — lawyers I spoke to said the ranges being negotiated for the first IRA-enabled credit sales are 85-95 cents per dollar. You get cash to do the project, the middleman takes a fee, and the buyer gets a discounted tax break and an opportunity to tell everyone they’re supporting clean energy that might not have been built otherwise.

That’s where the startups come in. Reunion Infrastructure and Basis Climate were both launched after the IRA passed, raising an undisclosed amount of venture capital seed funding this year. Both were founded by veterans of the renewable energy finance industry, with a similar business model: To act as a marketplace connecting sellers and buyers of tax credits. Both startups are developing insurance programs in case the project doesn’t actually get built, and lawyers said more government guidance is needed to ensure tax credit buyers don’t wind up on the hook or under audit if projects don’t materialize.

The upshot is that the pool of possible financiers grows from a handful of big banks to anyone with a corporate tax bill, and a lot more clean energy gets built.

Know More

Renewable energy projects in the U.S. can tap one of two tax credits. Prior to the IRA, many project development companies were unable to use these credits directly, either because they didn’t have enough taxable income to make full use of them, or because they needed cash upfront to actually get the project built. Instead, they typically sought a tax equity deal, in which a bank or other financier puts up cash, becoming a partial owner of the project, and allowing the financier to count the credits against its own taxes.

There are two problems with these deals. One, they’re notoriously tedious and require teams of accountants and lawyers — the term “brain damage” gets used a lot to describe them. Two, there’s simply not enough tax equity financing available to cover all the projects out there. Where there is, it tends to get eaten up by the biggest projects, like an offshore wind farm that costs hundreds of millions of dollars. Smaller projects — solar on the roof of a commercial warehouse or in a field next to a university — weren’t worth it. The investor-owned utilities that operate most of the nation’s coal-fired power plants have also been held back in switching to renewables in part because their regulatory structure prevents them from entering tax equity deals. The IRA’s transferability reforms should go a long way toward solving these problems.

Room for Disagreement

The market for tax credit trading is certain to grow quickly, Rubinstein said, drawing in the traditional big accounting firms that most companies are more accustomed to dealing with. “I’m skeptical that startups will be able to unseat the incumbents,” he said. And if the Internal Revenue Service does open the door for individuals to buy tax credits, as it is considering, the startups will also face competition from filing services like TurboTax.

The View From Texas

Transferability isn’t the only tax innovation in the IRA. The new law also extends tax breaks beyond wind and solar to a range of other technologies including batteries, nuclear, geothermal, and hydrogen. The first investment in utility-scale batteries made possible by IRA tax credits was announced this week, for a 200-megawatt pair of batteries in Mission, Texas.

Notable

• The IRA’s plethora of grants, loans, and tax breaks have turned the U.S. into the world’s most attractive investment destination for renewables, the Financial Times reported, with $90 billion in new investment announced since the law passed. The U.S. is on track for $114 billion per year in clean energy investment by 2031.

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 info@reunioninfra.com.

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.

Video chapters

• 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?

Transcript

Introductions

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 info@reunioninfra.com. We have some great interviews lined up and will look forward to seeing you on the next video episode. Thank you.