A review of how tax year-end affects transferability for buyers and sellers.
A review of how tax year-end affects transferability for buyers and sellers.
Head of Tax Credit Capital
Transferable tax credits are a useful tool for profitable companies looking to manage their tax position. 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.
Internal Revenue Code §6418(d) explains the specific rule relating to this relationship between buyer’s and seller’s tax year end. Reunion produced a one-pager that goes into detail on this rule and gives example scenarios for when either a buyer or a seller has a non-calendar tax year-end.
Download Timing of Transferable Tax Credit Purchases
To learn more, download our one-pager to explore several tax-year scenarios.
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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.
Download our transferability economic model
To learn more, corporate taxpayers can download our transferability economic model and align it with their company's fact pattern.
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.
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
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.
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 an overview of transferability, download our transferable tax credit handbook.
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.
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 firstname.lastname@example.org.
 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.