Navigating December Rush and Three-Year Carryback - The Complex World of Transferability
Tax equity, the December 31st deadline, and the "game changer" that is transferability.
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. 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 info@reunioninfra.com.
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Footnotes:
[1] IRC §39 is the code section that governs carrybacks.
[2] 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.
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Transferable tax credits are a powerful tool for profitable companies looking to manage their federal tax liability. When buying transferable tax credits, however, companies must consider their tax year-end in conjunction with that of the seller in order to claim the credits correctly and to the greatest extent possible.
IRC §6418(d) dictates tax credit purchase timing between buyers and sellers
Internal Revenue Code §6418(d) explains the specific rule relating to the relationship between a buyer’s (transferee taxpayer) and seller’s (eligible taxpayer) tax year-ends.
"In the case of any credit (or portion thereof) with respect to which an election is made under subsection (a), such credit shall be taken into account in the first taxable year of the transferee taxpayer ending with, or after, the taxable year of the eligible taxpayer with respect to which the credit was determined."
Corporate taxpayers will face one of three scenarios when engaging tax credit sellers
Scenario 1: Buyer and seller both have a calendar year-end
For transactions where both the buyer and seller have a 12/31 tax year-end date, the credits simply apply to the tax year in which they were generated.
Scenario 2: Buyer's tax year ends before that of the seller
For a transaction where the buyer tax year ends before that of the seller – for example, the buyer has a 9/30 tax year, and the seller has a 12/31 tax year – any credits generated in the same calendar year are pushed into the next tax year for the buyer.
Scenario 3: Buyer's tax year ends after that of the seller
Lastly, for a transaction where the seller's tax year ends before that of the buyer, credits generated prior to the end of the seller tax year will apply to the current calendar year, but credits generated after the end of the seller tax year will push into the next calendar year.
Most eligible corporate taxpayers are calendar-year filers
There are approximately 600 publicly traded companies in the U.S. with a trailing 12-month income tax liability over $100M (as of May 2024).
Of these companies, 78% are calendar-year filers, while another 8.0% close out their fiscal year in February or September.
If we increase the threshold to $500M of trailing 12-month income tax liability, the numbers remain consistent: 78.2% of companies are calendar-year filers.
Find credits that complement your company's tax year-end
To find clean energy tax credits that complement your company's tax year-end, please contact Reunion's transactions team. In addition to providing access to our tax credit marketplace, we can curate a list of projects that most closely align with your needs.
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.
Jump to a credit
To jump directly to a credit, click a link below:
- §45 PTC – Electricity produced from certain renewable sources
- §45Y PTC – Clean electricity production credit (technology-neutral PTC)
- §48 ITC – Energy credit
- §48E ITC – Clean electricity investment credit (technology-neutral ITC)
- §30C ITC – Alternative fuel vehicle refueling property credit
- §45U PTC – Zero-emission nuclear power production credit
- §45Q PTC – Credit for carbon oxide sequestration
- §45Z PTC – Clean fuel production tax credit
- §45V PTC – Clean hydrogen production tax credit
- §48C ITC – Advanced energy project credit
- §45X PTC – Advanced manufacturing production credit
§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
§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.
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.
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