Comprehensive guide to buying and selling clean energy tax credits

Reunion's transferable tax credit handbook has become the seminal resource in the market. Over 4,000 buyers, sellers, and professional advisors have downloaded our handbook since we launched it in October 2023.

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Executive summary

The Inflation Reduction Act of 2022 (IRA) was a landmark piece of legislation intended to accelerate the United States’ transition to cleaner energy sources. As part of this legislation, Congress significantly expanded energy-related federal income tax credits and introduced transferable tax credits, which can be freely sold to third parties.

The intent of transferable credits is to reduce the cost and complexity of financing clean energy projects. Prior to the IRA, a handful of large financial institutions were responsible for most clean energy financing. Congress recognized that participation from a broader pool of investors was needed to achieve our clean energy goals, and corporate finance teams will play a central role through the purchase of transferable tax credits.

Transferable tax credits are fulfilling their promise. The first major transactions closed shortly after the Department of the Treasury’s proposed regulations in June 2023, and the market has rapidly accelerated since. Final transferability regulations, released in April 2024, have set the stage for hundreds of billions of dollars of clean energy investments over the next decade.

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Background

What are transferable tax credits?

The IRA greatly expanded energy-related federal income tax credits and added §6418 to the Internal Revenue Code (IRC), which allows “eligible taxpayers” to elect to transfer (i.e., sell) certain tax credits to unrelated taxpayers for cash.

Eligible taxpayers can elect to transfer all or a portion of an eligible credit, and the tax credit buyer is treated as the taxpayer with respect to such credit (or such portion thereof). The buyer is allowed to claim the transferred tax credits on its tax returns, while also assuming some risk in the event of a recapture event or a challenge by the IRS on the qualification of the transferred tax credit.

Tax credits can be transferred for tax years starting after December 31, 2022. The cash payments are excluded from the tax credit seller’s gross income and are not deductible by the buyer. In addition, the buyer does not record any gross income or gain for federal tax purposes, even if the buyer has purchased the tax credit at a discount from face value.

Tax credits under the following U.S. tax code sections can be transferred: §45, §45Y, §48, §48E, §45Q, §45V, §45U, §45Z, §45X, §48C, and §30C. Appendix A provides an overview of key features of each credit, including period of availability and project eligibility.

What are the benefits of transferable tax credits?

Tax credits have been the primary mechanism for the U.S.federal government to provide subsidies to clean energy projects such as wind and solar. However, most manufacturers and developers of clean energy projects lack sufficient tax liabilities to take full advantage of tax credits generated by their projects. Prior to the IRA, only an owner of the clean energy project could utilize the tax credits. This led to the creation of certain leasing and tax equity structures, such as the partnership flip, whereby a third-party investor entered a partnership with the clean energy developer to co-own a project and was allocated a share of project cash and most tax benefits.

Tax equity structures are complex to set up and cumbersome to manage. As a result, the supply of tax equity has been dominated by a small number of large financial institutions: JP Morgan and Bank of America have accounted for more than 50%of tax equity investment in recent years.

A tax credit can be transferred in a simpler process that is meant to incentivize a broader pool of capital to invest in clean energy projects. Rather than having to make a multi-year investment into a clean energy project through a complex lease and/or legal partnership, a tax credit purchaser can simply buy a transferable credit that directly offsets federal tax liabilities. The benefits of transferable tax credits versus tax equity are summarized below.

Simplified structure and lower cost

Transferability negates the need for complex tax equity structures, which require a tax credit seller to negotiate and enter into a partnership or leasing arrangement. The combined legal, due diligence, and accounting costs can exceed $1 million for a single tax equity transaction.

In contrast, buyers and sellers of tax credits use a straightforward tax credit transfer agreement (TCTA) to memorialize the terms and conditions of a tax credit sale. The purchase is effectuated by making a transfer election on an original tax return filed no later than the due date(including extensions) for the original return for the tax year in which the credit is determined.

Less ongoing management

For tax equity investors, who are often co-owners of a project, a typical deal requires extensive ongoing asset management and financial reporting. At minimum, the investor must monitor project performance, conduct complex GAAP accounting analysis, which may include consolidation/variable interest entity assessments and hypothetical liquidation at book value (HLBV) accounting, prepare or collect K-1 and other tax forms , and ensure receipt of timely payments  (e.g.,preferred payments in a partnership flip structure).

More favorable reporting

Traditional tax equity has complex GAAP accounting treatment, which can increase volatility of earnings reporting for publicly traded companies. The accounting complexity, as well as risk of tax equity’s impact on reported earnings, has made tax equity a non-starter for many publicly traded companies. In contrast, a transferred tax credit has a more straightforward accounting treatment.

Narrower set of risks, primarily related to disallowance or recapture of credit by the IRS

A tax equity investor is investing true equity into a project, meaning their returns may be impacted if a project has lower performance than what was underwritten – for instance, if a wind turbine doesn’t produce as much power as originally estimated. In a tax credit transfer, the buyer is not directly subject to asset performance risk; the primary risk is a disallowance or recapture of the tax credit by the IRS.

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The 11 transferable tax credits

11 types of clean energy tax credits are transferable, and they fall under the following U.S. tax code sections.

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Technical credit considerations

Who can sell transferable tax credits?

Eligible credits can be transferred by taxpayers – including individuals, C-corporations, trusts, estates, partnerships, and S-corporations – beginning on January 1, 2023.

Tax-exempt entities, including municipal and rural electric co-ops, state and local governments, and tribal entities, are not able to transfer credits but can use the elective pay election under §6417.

For property held by a partnership, the transfer is made at the partnership level. However, each partner may direct the partnership to sell its respective share of credits without affecting any other partner’s allocation of credits.

Who can buy transferable tax credits?

The credit must be transferred to an unrelated taxpayer.Related parties are defined in the IRC under §267(b) and §707(b)(1). The credit can be transferred in whole or in part (e.g., credits from a single project can be sold to multiple buyers).

Partnerships may purchase credits from unrelated taxpayers. Such credits are allocated to its partners and treated as nondeductible expenditures and reduce each partner’s capital account and tax basis in its partnership interests.

Tax treatment

For the seller

The purchase price of the tax credits is not included in the gross income of the seller. If a partnership is the owner of the credit property, the tax credits are sold by the partnership, and the amount of cash consideration received by the seller is treated as tax exempt income. This tax-exempt income is allocated to the partners in the same proportionate manner that the original credit would have been allocated.

For the buyer

The purchase price of the tax credits is not deductible by the buyer, and buyers do not recognize gross income on the discount portion of the credit. For example, a buyer that purchases $100M of tax credits for $95M in cash is not subject to federal tax on the $5M reduction in taxes payable to the IRS.

Other restrictions

Cash only consideration

Buyers must purchase transferable credits with cash – U.S. dollars, check, cashier’s check, money order, wire transfer, ACH transfer, or other bank transfer of immediately available funds. A disguised consideration, such as a buyer receiving a discount on services from the seller from whom they are purchasing credits, could cause the transfer election to be disallowed.

Prohibition against resale

Credits may only be transferred once. Once a buyer has purchased tax credits, they cannot resell them. If a buyer is unable to fully utilize the tax credits they purchased in a given year, they can carry the unused credits back three years and forward for up to 22 years.

While a tax credit seller who is an S corporation is subject to the no additional transfer rule, an allocation of a transferred specified credit portion to a direct or indirect shareholder of an S corporation is not a transfer for purposes of §6418.

No progress expenditures

Investment credits that are realized as progress expenditures may not be transferred.

Lessees may not transfer credits

To the extent that a lessee claims a credit pursuant to a lease passthrough structure, the lessee may not subsequently transfer the credit. However, lessors in a sale-leaseback transaction may elect to transfer the credits to a third party.

At-risk rules

Tax credit sellers that are individuals or closely held C-corporations (or partnerships or S-corporations whose partners or shareholders include such taxpayers) are subject to the at-risk rules of §49. The rules apply an at-risk calculation to determine the amount of tax credits that the taxpayer is allowed to realize, based on each partner’s or shareholder’s amount of nonqualified nonrecourse financing related to the credit property. To the extent that such at-risk rules apply, the amount of credit that a seller can claim and transfer may be limited.

There are a few exceptions to the at-risk rules that make the basis reductions pursuant to §49 rare in energy transactions. Primarily, the at-risk rules do not apply where there is“qualified commercial financing”, where the taxpayer does not acquire the property from a related party, the financing does not cover more than 80% of the cost of the property, and the lender is a commercial lender or a lender through a federal, state, or local government program. Nonetheless, buyers should ensure that sellers are not subject to the at-risk rules as part of their diligence.

Passive activity loss rules

Generally, individuals, estates, trusts, closely heldC-corporations, and personal service corporations are subject to passive activity loss rules under §469. The passive activity loss rules require any taxpayers subject to such rules to only apply tax credits to passive income, and not active income, such as wage income, or portfolio income, such as capital gains or dividends.

There are, however, certain exceptions in place for closely held C-corporations as outlined in §469(e)(2)(A). Closely held C-corporations should consult with tax counsel on their ability to use tax credits to offset net active income.

Excessive credit transfers

If a credit transfer is deemed by the IRS to constitute an “excessive credit transfer,” the purchaser of the credit would be liable for an increase in tax by the amount of the excessive credit transfer plus a penalty of 20% of such amount. The penalty would not be applied to the extent the excessive credit transfer is due to “reasonable cause.”

As discussed in the commentary for §1.6418–5(a)(4), reasonable cause is generally determined, on a case-by-case basis, by the extent of efforts taken to confirm, for the applicable taxable year, that the eligible taxpayer has the specified credit portion to transfer.

Whether an eligible taxpayer has the specified credit portion to transfer includes the confirmation that:

• The amount of specified credit portion transferred does not exceed the amount of the eligible credit determined with respect to the eligible credit property
• The specified credit has not been transferred to any other taxpayer. Relying solely on an eligible taxpayer’s representations is not sufficient for purposes of demonstrating reasonable cause.
  

Circumstances that indicate reasonable cause include:

• Review of the eligible taxpayer’s records with respect to the determination of the eligible credit (including documentation evidencing eligibility for bonus credit amounts)
• Reasonable reliance on third party expert reports
• Reasonable reliance on representations from the eligible taxpayer that the total specified credit portion transferred does not exceed the total eligible credit determined with respect to the eligible credit property for the taxable year
• Review of audited financial statements

§1.6418–5(a)(4) also refers to §1.6664-4 for additional discussion on reasonable cause, including specific examples such as: “Reasonable cause and good faith ordinarily is not indicated by the mere fact that there is an appraisal of the value of property. Other factors to consider include the methodology and assumptions underlying the appraisal, the appraised value, the relationship between appraised value and purchase price, the circumstances under which the appraisal was obtained, and the appraiser’s relationship to the taxpayer or to the activity in which the property is used.”

Because the tax credit buyer is directly liable for excessive credit transfers, and not the tax credit seller, it is important for purchasers to perform due diligence, negotiate seller indemnifications carefully, and consider other risk mitigants including tax credit insurance.

Required minimum documentation

A statement or representation must be made in the transfer election statement that the tax credit seller has provided the “required minimum documentation” to the tax credit buyer. Required minimum documentation differs from the reasonable cause standard for excessive credit transfers, and is discussed in §1.6418–2(b)(5)(iv).

The minimum documentation threshold is intended to establish a baseline of information necessary to validate an eligible taxpayer’s claim to an eligible credit. Tax credit buyers will often require additional documentation to substantiate the credit and to gain comfort that they will be able to provide the necessary documentation in the event of an IRS challenge.

Required minimum documentation includes:

• Information that validates the existence of the eligible credit property, which could include evidence prepared by a third party (such as a county board or other governmental entity, a utility, or an insurance provider)
• If applicable, documentation substantiating that the eligible taxpayer has satisfied the requirements to include any bonus credit amounts (as defined in §1.6418–1(c)(3)) in the eligible credit that was part of the transferred specified credit portion
• Evidence of the eligible taxpayer’s qualifying costs in the case of a transfer of an eligible credit that is part of the investment credit or the amount of qualifying production activities and sales amounts, as relevant, in the case of a transfer of an eligible credit that is a production credit

Carrybacks and carryforwards

§39(a)(4) generally allows a three-year carryback period in the case of any applicable credit (as defined in §6417(b)). However, this is not straightforward to utilize.

Take the example of a tax credit buyer seeking tax credits from a clean energy project for the 2023 tax year. The project falls behind on construction and is placed in service on 1/1/2024. This results in tax credits for the 2024 tax year; however, these credits cannot easily be applied to the originally desired tax year of 2023.

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.

Practically speaking, carrying back credits would require a buyer to amend one or more of its prior year returns, which could lead to complexities such as increased audit risk, or review from the Joint Committee on Taxation.

Taxpayers may carry applicable IRA tax credits forward up to 22 years.

Buyers and sellers with different tax years

The year that a buyer recognizes transferable tax credits depends on both the buyer and seller tax year. Pursuant to §6418(d), “a [tax credit buyer] takes the transferred eligible credit into account in its first tax year ending with, or after, the eligible taxpayer’s tax year with respect to which the transferred eligible credit was determined.” Corporate taxpayers will face one of three scenarios when engaging tax credit sellers.

Buyer and seller both have a calendar year-end

For transactions in which 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.

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Buyer's tax year ends before that of the seller

For a transaction in which 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.

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Buyer's tax year ends after that of the seller

Lastly, for a transaction in which 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.

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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. 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.

The approximately 20% of corporations who are not December filers may be somewhat disadvantaged when sourcing credits. A tax credit buyer who has a September fiscal year end, for example, would effectively need to source credits placed in service in 2024 (assuming a seller with a calendar tax year) for their 2025 return. This timing disconnect presents timing of payments challenges for both the tax credit seller and the tax credit buyer.

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Transfer mechanics

To effectuate a valid credit transfer, the buyer and seller must both complete several key steps.

Negotiate tax credit transfer agreement

First, the buyer and seller should enter into a contractual agreement to transfer the credits. A summary of a typical tax credit transfer agreement is provided in Section 11. This agreement is a private agreement between the buyer and seller and is not a public document that would be filed with the IRS.

Fulfill IRS pre-filing registration

The seller of the credit needs to fulfill the pre-filing registration requirements with the IRS, which is done electronically through an IRS pre-filing registration tool, and receive a registration number for each eligible credit property.

As part of this registration process, the seller will include information about the transferor taxpayer and the credit property, including addresses and coordinates, supporting documentation relating to the construction or acquisition of the credit property, beginning of construction date, and placed in service date. Such registration must be accompanied by a penalties of perjury statement, signed by a person with personal knowledge of the relevant facts and who is authorized to bind the registrant.

Complete relevant source credit forms and IRS Form 3800

The tax credit seller must complete the relevant source credit form and IRS Form 3800, General Business Credit (or its successor). A schedule must also be attached to the Form 3800, showing the amount of eligible credit transferred for each eligible credit property.

Below are links to available source credit forms for transferable tax credits; for example, Form 7207, Advanced Manufacturing Production Credit, is required if making a transfer election for a §45X credit. Some forms, like 7213, are in draft as of August 2024:

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Execute transfer election statement

A transfer election statement is a written document that memorializes the transfer of a specified credit portion between a tax credit buyer and seller. The tax credit seller and tax credit buyer must each attach a transfer election statement to their respective return. There is not a specific form, but the document must be labeled as a “transfer election statement” and be signed under penalties of perjury by an individual with authority to legally bind the tax credit seller. The statement must also include the written consent of an individual with authority to legally bind the tax credit buyer.

As stated in §6418, information that must be in the transfer election statement includes:

• Name, address, and taxpayer identification number of the tax credit seller and the tax credit buyer. If either the tax credit seller or the tax credit buyer is a member of a consolidated group (as defined in §1.1502–1), then only include information for the group member that is the tax credit seller or the tax credit buyer (if different from the return filer)

• A statement that provides the necessary information and amounts to allow the tax credit buyer to take into account the specified credit portion with respect to the eligible credit property, including:
  • A description of the eligible credit (for example, advanced manufacturing production credit for a §45X transfer election), the total amount of the credit determined with respect to the eligible credit property, and the amount of the specified credit portion
  • The taxable year of the tax credit seller and the first taxable year in which the specified credit portion will be taken into account by the tax credit buyer
  • The amount(s) of the cash consideration and date(s) on which paid by the tax credit buyer
  • The registration number related to the eligible credit property

• Attestation that the tax credit seller (or any member of its consolidated group) is not related to the tax credit buyer (or any member of its consolidated group) within the meaning of §267(b) or 707(b)(1))

• A statement or representation from the tax credit seller that it has or will comply with all requirements of §6418, the §6418 regulations, and the provisions of the Code applicable to the eligible credit, including, for example, any requirements for bonus credit amounts described in §1.6418–1(c)(3) (if applicable)

• A statement or representation from the tax credit seller and the tax credit buyer acknowledging the notification of recapture requirements under §6418(g)(3) and the §6418 regulations (if applicable)

• A statement or representation from the tax credit seller that the tax credit seller has provided the required minimum documentation (as described in paragraph (b)(5)(iv) of this section) to the tax credit buyer

The transfer election statement must be attached to both the tax credit buyer and the tax credit seller’s respective tax returns. Once filed by either party, the transfer election statement becomes irrevocable.

Beginning of construction

Within the statutes and relevant guidance governing clean energy tax credits, there are many references to a project’s beginning of construction (BoC) date, such as energy community qualification and the exemption from prevailing wage and apprenticeship requirements.

Relevant IRS notices

Over a series of notices beginning in 2013, the IRS has established the standards for determining the date that a project began construction.

These notices remain the applicable standards for any references to BoC as it relates to the IRA tax credits and associated guidance.

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Methodologies for establishing a project’s BoC date

A taxpayer need only meet one of two methodologies to establish the BoC date:

• Physical Work Test: A taxpayer establishes BoC by starting physical work of a significant nature (within the meaning of section 5 of Notice 2013-29) and thereafter maintaining a continuous program of construction (the “Continuous Construction Test”). Physical work of a significant nature may include both on-site and off-site physical work, performed by either the taxpayer or by another party under a biding written contract. Some examples of on-site physical work of a wind facility include the beginning of the excavation for the foundation, the setting of anchor bolts into the ground, or the pouring of the concrete pads of the foundation. For off-site physical work, manufacture of components must be done pursuant to a binding written contract, with such components not held in a manufacturer’s inventory. One of the most common ways to satisfy the off-site physical work test is physical work on a custom-designed transformer that steps up the voltage of electricity

• Five Percent Test: A taxpayer establishes BoC by paying or incurring (within the meaning of §1.461-1(a)(1) or (2)) five percent or more the cost of the facility, and thereafter making continuous efforts towards completion of the facility (the "Continuous Efforts Test"). Only costs included in the depreciable basis of tangible personal property and other tangible property integral to the facility are taken into account to determine if the Five Percent Test has been met

Given that both methods require continuous progress toward completion once construction has begun via either the Continuous Construction Test or the Continuous Efforts Test (collectively, the “Continuity Requirement”), the IRS also provide a safe harbor (the “Continuity Safe Harbor”) pursuant to which the Continuity Requirement is deemed to be satisfied if a taxpayer places a project in service by the end of a calendar year that is no more than four calendar years after the calendar year during which construction began. Notice 2021-41 extended the four- year window to six years for projects where construction began in 2016, 2017, 2018, or 2019, and to five years for projects where construction began in 2020.

This section is intended to provide a cursory summary of the BoC regulations. Such regulations are extensive and depending on the facts and circumstances, the analysis surrounding a project’s BoC date may be complex. As such, BoC analysis is often supported by memorandum of counsel or other professional advisors.

Corporate alternative minimum tax (CAMT)

Created by the IRA, the corporate alternative minimum tax (CAMT) seeks to place a 15% “floor” under corporate taxpayers to raise revenues and require companies with lower effective tax rates to bring their rates up to a uniform level.

The legislative language behind CAMT is designed to require profitable corporations to pay at least some federal income tax, regardless of the deductions and credits they may claim under the regular tax system. The law also intends to reduce the gap between the book income and taxable income of corporations, which has been a source of public criticism and scrutiny.

CAMT applies to large corporations – other than an S-corporation, regulated investment company, or real estate investment trust – who report more than $1 billion in profits to shareholders on their financial statements. 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. AFSI diverges from taxable income, sometimes significantly; as a result, corporations with an effective tax rate that exceeds 15% may still be subject to CAMT liability.

One of the most important adjustments for the CAMT is the allowance of general business tax credits to reduce tax liability back below the 15% threshold. General business tax credits, which include §45 PTCs, §45X AMPCs and §48 ITCs, can be used to offset up to 75% of a corporation's net income tax. In conclusion, corporations facing CAMT can purchase transfer tax credits to offset tax liabilities even below the 15% minimum tax threshold imposed through CAMT.

OECD Pillar Two

OECD Pillar Two is a legal framework designed to combat tax avoidance by establishing a global minimum tax rate of 15%. Pillar Two is meant to ensure that large multinational enterprises (MNEs) pay their fair share of taxes in all the jurisdictions in which they operate.

Over 140 countries have agreed to the Pillar Two framework, but formal adoption requires each country to enact rules through local legislation. As of July 2024, 36 jurisdictions – including South Korea, Canada, New Zealand and most European Union countries – have implemented or will implement the global minimum tax taking effect in 2024.45 The Biden administration agreed to Pillar Two, but the U.S. has not yet ratified it, which will require Congress to agree to add Pillar Two to the U.S. tax code. It is unclear if this will happen, given strong opposition from Republicans in Congress.

Pillar Two applies to MNEs with annual revenues above €750 million. It is a "top-up tax", which is levied when the MNE's effective tax rate (ETR) falls below 15% in any jurisdiction that has adopted Pillar Two in which the MNE operates. The right to tax income can be levied through each of the following mechanisms, in order:

• Qualified domestic minimum top-up tax (QDMTT): The jurisdiction in which the undertaxed entity is located has the first right to collect the top-up tax. There is a strong incentive to collect taxes locally, otherwise taxes can be collected by other entities (see below)
• Income Inclusion Rule (IIR): If the source country does not impose a top-up tax, the home country of the parent company can collect the tax. For example, the German government can collect top-up tax on the German parent of a U.S. subsidiary, if the ETR of the U.S. entity fell below 15%
• Undertaxed Payments Rule (UTPR): If neither of the above two taxes apply, then countries in which other constituent entities (such as subsidiaries and branches) are located can collect the tax by denying deductions for those constituent entities. No countries have yet assessed the UTPR, and the OECD's latest guidance delayed implementation of the UTPR until 2026 in many jurisdictions

OECD guidance from July 2023 clarified that IRA tax credits will receive the same favorable treatment as refundable tax credits, even though IRA tax credits were no explicitly designated as refundable credits. Tax credits are treated as nonmarketable credits from the buyer’s perspective, and marketable credits from the seller’s perspective.

For the buyer, the numerator of the effective tax rate (ETR) calculation is only reduced by the discount amount of the credit. For example, if a buyer purchases $1 of tax credits for $0.95, then the numerator of the ETR calculation is reduced by only $0.05. This alleviated concerns that the purchase of IRA tax credits would have a more significant impact on the ETR calculation for purposes of Pillar Two taxation.

For the seller, the proceeds from the sale of tax credits are treated as additional income, rather than a reduction of taxes. For example, if a seller sells $1 of tax credits for $0.95, then the denominator of the ETR calculation is increased by $0.95.

For the seller, this tax treatment holds whether or not the tax credits are sold to a third party.

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§48 ITCs: Eligibility, rates, risks, and due diligence

Eligibility and dates

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Rates

PWA

Assuming prevailing wage and apprenticeship requirements are met, the §48 ITC is worth 30% of a project’s qualified basis.

Energy community

Projects that qualify for the energy community bonus receive:

• 2% ITC value increase if PWA requirements are not met
• 10% ITC value increase if PWA requirements are met

Assuming a project meets PWA requirements, for example, the energy community bonus results in an ITC value worth 40% of a project’s qualified basis.

Domestic content

Projects that qualify for the domestic content bonus receive:

• 2% ITC value increase if PWA requirements are not met
• 10% ITC value increase if PWA requirements are met

Assuming a project meets PWA requirements, for example, the domestic content bonus results in an ITC value worth 40% of a project’s qualified basis.

Low-income community

Projects that qualify for the low-income community bonus receive an additional 10% or 20%. The bonus is limited to projects of 5 MW or less and is an allocated credit, meaning tax credit sellers must apply for the bonus and receive an allocation.

Risks

Qualification

Buyers will need to ensure that tax credits qualify for the §48 ITC and will be respected in full by the IRS. Key areas of qualification include validation that the underlying project qualifies as energy property (as defined in §48), the proper cost basis is used, and the project was placed in service in the appropriate tax year.

The IRS may challenge the cost basis of the energy property. If the cost basis is determined to be a lower amount, this will also reduce the ITC amount, resulting in an excessive credit transfer to the tax credit buyer.

Recapture

Investment tax credits under §48 are subject to the recapture provisions of §50, which states that, “if, during any taxable year, investment credit property is disposed of, or otherwise ceases to be investment credit property with respect to the taxpayer” then the credit will be recaptured. The ITC carries a five-year compliance period, in which the potential amount of credit that can be recaptured starts at 100% for the first year and steps down 20% per year.

Practically speaking, recapture can occur in the following scenarios:

• The property ceases to be a qualified energy facility
• There is a change in ownership of the property

The first scenario, in which a property ceases to be a qualified energy facility, occurs when an asset is destroyed and not rebuilt and placed back in service, abandoned, or starts selling something other than electricity derived from the qualified generation asset.

The second scenario, in which there is a change in ownership, can occur if the project owner transfers its ownership of the facility during the compliance period, or if a lender forecloses on its collateral interest in the facility (or in the equity of any intermediate holding company between the facility and the tax credit seller52) due to a borrower default. When a lender has such collateral interests, a forbearance agreement can be negotiated with the lender to mitigate this risk. We recommend that project owners that may be considering future tax credit transfers should negotiate forbearance agreements with their lenders when raising project or corporate financing, or otherwise structure debt such that a foreclosure does not trigger a recapture of tax credits.

Despite having no direct governance rights over a project, a purchaser of tax credits is required to pay any recapture amounts, except in one scenario. A change in upstream ownership of a partnership or S-corporation does not cause recapture for the buyer of the credit, instead triggering recapture to the shareholder or partner who sold their interests. Since tax credit sellers are often structured as partnerships, some with many different equity owners, subjecting tax credit buyers to the risk of upstream changes of control that inadvertently cause recapture would be a difficult risk to manage.

Protecting against recapture is an important focus of due diligence, transaction documents, seller covenants and indemnities, and tax credit insurance.

Due diligence

§48 ITCs generally carry a larger discount compared to §45 PTCs and §45X AMPCs because due diligence is more complex, and credits are subject to risk of §50 recapture. Buyers should ensure that the project qualifies as energy property (as defined in IRC §48), the proper cost basis is used, and the project was placed in service in the appropriate tax year. Buyers should also ensure that risk mitigants are in place to avoid common recapture scenarios.

In this section, we focus on due diligence related to qualification, structure, and recapture of §48 ITCs. Other points of due diligence include compliance with prevailing wage and apprenticeship requirements (or claimed exemption thereof), and the ability to claim bonus credit adders.

Qualification: cost basis and basis step-ups

The buyer first will need to confirm that that tax credits are generated from qualified energy property, as defined in IRC §48.

Buyers will also need to review detailed documentation to substantiate the project’s cost basis. A cost segregation analysis from a reputed third-party accounting firm is typically used to validate the cost basis for energy property eligible for the ITC.

If a project has a step-up in the cost basis, the buyer will want to:

• Diligence the transaction that effectuates the step-up
• Analyze the stepped-up valuation (with specific focus on the amount of step up relative to the cost basis of the project prior to such step-up

Transaction structure for basis step-up

In some transactions, a tax credit seller will seek to increase, or “step up,” the cost basis to a fair market value that exceeds the original cost basis. A stepped-up cost basis drives a larger tax credit amount, as the ITC is calculated as a percent of the project’s cost basis.

Project developers have long sold project companies to tax equity partnerships to achieve a step-up in cost basis. With tax credit transfers, there are several structures that sellers can employ to achieve a step-up in cost basis.

The most common structure is to sell the project company to a partnership, which is composed of the project sponsor and a third party that owns a certain percentage of the partnership. Many private equity funds and other investors have emerged with “preferred equity” vehicles that will serve as the third-party investor in a partnership.

When a project company is sold into a partnership, the partnership will become the seller of the tax credits. Buyers should validate that the seller is an eligible transferor, and that the seller’s underlying legal structure will be respected by the IRS. It may be appropriate for tax counsel to opine on the validity of the structure as part of due diligence.

Valuation for basis step-up

In addition, the buyer should request an appraisal performed by a qualified thirdparty appraisal firm to substantiate the project’s fair market value. An appraisal is often done in conjunction with a cost segregation report, and typically is only required if the seller has stepped up the cost basis of the project. Several large tax equity investors have capped the level step-up they are willing to entertain, and Reunion generally believes that larger step-ups will be subject to increased scrutiny by the IRS. Therefore, we suggest careful due diligence on projects with larger basis step-ups, and we suggest that buyers retain due diligence documentation to avoid the 20% excessive credit transfer penalty in the event of an IRS challenge.

Recapture: continuation as a qualified facility

The IRS may recapture the credit if a property ceases to be a qualified energy facility. This can happen if any of the following occurs:

• The facility is destroyed or abandoned, and not rebuilt and placed back in service
• The facility starts selling something other than electricity derived from the qualified generation asset

To protect against these risks, buyers should take steps to ensure the project remains in operation as energy property during the recapture period. This includes receiving evidence from the seller that the project has:

• Sufficient property and casualty (P&C) insurance coverage: Sufficient insurance coverage allows the project to be placed back in service in the event of weather, vandalism, or other property damage that causes the project to temporarily stop operations
• Adequate site control: Owners and successors of the land or building where the project is sited cannot have the right to terminate the lease or other agreement or otherwise eject the project from the property‍
• Adequate interconnection rights: A project much have the necessary interconnection rights to allow it to deliver electricity to the grid

The seller should also demonstrate that they have alternatives in the event of counterparty default. Buyers should assess whether the project has other options (including selling on a merchant basis into a wholesale electricity market) if the primary offtaker is unable to take and pay for the electricity the project produces.

Recapture: no change in ownership

The IRS may recapture the credit if the project owner transfers ownership of the facility within the five-year period of the project being placed in service. To protect this risk, buyers should receive from the seller:

• Detailed information about the project’s ownership structure
• Confirmation that financing parties do not have collateral interests that could cause recapture in the event of a default.
  • Debt can be structured in a way (e.g., through an internal partnership or back-leverage structure) such that the lender will not foreclose on the project in the event of a default. §6418 regulations stated that a change in upstream ownership of a project owned by a partnership or an S-corporation does not cause recapture for the buyer of the credit, instead triggering recapture to the shareholder or partner who sold their interests
  • If project-level debt is present, a forbearance agreement can sometimes be negotiated such that lenders agree not to foreclose on project assets or undertake any other actions that would cause a recapture

Placed-in-service date

The placed-in-service date determines the tax year to which the tax credit applies. If a project’s anticipated placed-in-service date was 2025, but it was later found that the project was placed in service in 2026, then the buyer must treat the credits as having been generated in the 2026 tax year. This is particularly important to diligence at the end of the seller’s tax year, when ambiguity around the exact placed-in-service date can result in tax credits slipping to the subsequent tax year.

To make a determination of when a project is placed in service, there is a five-factor test generally considered by the IRS and various courts. None of the five factors are controlling:

• The procurement of required licenses and permits
• The passage of control of the facility to the ultimate taxpayer
• The completion of critical tests
• The commencement of regular operations
• The synchronization of the facility into a power grid for generating electricity to produce income (if applicable)

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§45 PTCs: Eligibility, rates, risks, and due diligence

Eligibility and dates

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Rates

The IRS updates §45 PTC rates on an annual basis, generally in Q2. Rates are determined using an inflation adjustment factor (IAF) and published in the Federal Register. The inflation adjustment factor for 2024 is 1.9499.

Although uncommon, published PTC rates are subject to change. In 2022, the IRS issued a correction to the inflation adjustment factor, revising it from 1.8012 to 1.7593. This change to the IAF resulted in a change to the §45 PTC rate as well.

PWA

The §45 PTC has two different rates depending on when a project was placed in service.

Placed in service before January 1, 2022

Projects placed in service before January 1, 2022 are not subject to PWA requirements, and the PTC calculation is [1.5 cents] x [inflation adjustment factor] rounded to the nearest 0.1 cents.

The 2024 rate is $29.00 per MWh for wind, closed-loop biomass, and geothermal; and $15.00 per MWh for open-loop biomass, landfill gas, trash, qualified hydropower, and marine and hydrokinetic renewable energy.

Placed in service after December 31, 2021

For projects placed in service after December 31, 2021, the PTC rate calculation is [0.3 cents] x [inflation adjustment factor] rounded to the nearest 0.05 cents. For projects meeting PWA requirements, this product is multiplied by five.

The 2024 rate, assuming prevailing wage and apprenticeship compliance, is $30.00 per MWh for wind, closed-loop biomass, geothermal and solar; and $15.00 per MWh for open-loop biomass, landfill gas, trash, qualified hydropower, and marine and hydrokinetic renewable energy.

For qualified hydropower and marine and hydrokinetic renewable energy facilities placed in service after 12/31/2022, the 2024 is $15.00 per MWh, assuming prevailing wage and apprenticeship compliance.

Energy community

Projects that qualify for the energy community bonus receive:

• 2% PTC value increase if PWA requirements are not met
• 10% PTC value increase if PWA requirements are met

Domestic content

Projects that qualify for the domestic content bonus receive:

• 2% PTC value increase if PWA requirements are not met
• 10% PTC value increase if PWA requirements are met

Assuming a project meets PWA requirements, for example, the domestic content bonus results in an PTC value worth 40% of a project’s qualified basis.

Reduced PTC rates for wind facilities that began construction in certain years

The IRA restored the full PTC rate for wind facilities that were placed in service after December 31, 2021. Prior to the enactment of the law, wind facilities claiming the §45 PTC that were placed in service before January 1, 2022 were subject to reduced PTC rates under §45(b)(5), based on when construction began:

• Before January 1, 2017: Eligible for 100% of PTC
• January 1, 2017 – December 31, 2017: Eligible for 80% of PTC
• January 1, 2018 – December 31, 2018: Eligible for 60% of PTC
• January 1, 2019 – December 31, 2019: Eligible for 40% of PTC
• January 1, 2020 – December 31, 2021: Eligible for 60% of PTC

Eligible taxpayers can elect to transfer credits from wind facilities that were placed in service prior to January 1, 2022. However, validating the beginning of construction for such facilities is imperative to determine the PTC rate that is applicable to such project.

Risks

To qualify for a §45 PTC, a project needs to generate electricity from a qualified energy resource during the ten-year period beginning on the date the facility was placed in service and be sold to an unrelated person during the taxable year.

Because the PTC is tied to production, the primary risk associated with PTCs is accurate production accounting. This risk is considered easily manageable because production is quantifiable and readily verified. A tax credit buyer will expect to see a production report from the associated asset’s revenue-grade meter to qualify the associated PTCs and verification of the sale of such electricity to a third party. This report can be also verified by the project's offtaker or system operator (such as MISO, ERCOT, or PJM), who is taking delivery of the project output.

PTCs from projects placed in service prior to 2023 can still be transferred under §6418, as long as the credits were generated during a tax year beginning after December 31, 2022.

Unlike ITCs, §45 PTCs are not subject to recapture risk. A buyer of PTCs should ensure that the facility it is purchasing credits from does not have a placed-inservice date more than ten years prior.

Facilities that have undergone a repower – where a project owner takes an operating project and upgrades the equipment – may be treated as newly placed in service and qualify for another ten years of PTCs. However, the fair market value of the used property must not be more than 20% of the facility’s total value. Transactions involving repowers often involve a third-party appraisal to determine the fair market value of used property.

Due diligence

The PTC is based on the amount of electricity the qualifying project produces once it is placed in service. Buyers should receive from the seller:

• Evidence that the project has been placed in service and has not been in operation for more than ten years
• If the project has been repowered or upgraded, evidence of the fair market value of the used equipment and the cost of the new equipment
• A production report from the project’s revenue-grade meter or other thirdparty substantiation (such as settlement statements from the grid operator)
• Confirmation of the electricity purchase by an unrelated third party

Buyers should also understand the circumstances under which the project may generate less electricity than anticipated – for example, curtailment – because that reduces the amount of PTCs generated.

To mitigate this risk, sellers typically elect to use conservative production estimates when entering into an agreement to sell PTCs. In some scenarios, buyers may negotiate liquidated damages to the extent that the volume of credits generated is significantly lower than projected. Nonetheless, buyers typically purchase PTCs as they are generated, in arrears, so cash is not exchanged until after a credit is generated.

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§45X AMPCs: Eligibility, rates, risks, and due diligence

Eligibility and dates

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Rates

§45X rates are specific to particular clean energy components and critical minerals.

Risks

Qualification

While §45X AMPCs are not subject to PWA requirements and do not carry the same recapture risks as §48 ITCs, they do carry additional qualification risks that are absent from other power generation-related tax credits such as the §45 PTC.

Components may be required to meet certain administrative or technological specifications to qualify as an eligible component that gives rise to a tax credit.

Due diligence

Buyers should conduct due diligence on several core aspects of §45X tax credit qualification, in particular the following five key diligence points:

• Confirm correct credit amount and technical qualification: §45X provides a list of eligible components, their associated AMPC amount, and any design parameters / capacity limits that are required to qualify for credits. The production of eligible components must be completed in 2023 or later, and the tax year where credits may be claimed is driven by the year in which the sale is completed. Buyers may choose to engage an independent engineer to perform a site visit and confirm technical specifications as well as compliance with any design or capacity requirements under §45X
• Ensure components were produced by a taxpayer: The credit is awarded only to the taxpayer who conducted the “substantial transformation” in a trade or business of the taxpayer. The regulations differentiate between “substantial transformation” versus “mere assembly,” in which the former is required to claim a credit. Parties to a contract manufacturing arrangement may choose who claims the credit through a signed agreement prior to the completion of eligible components. Buyers should review any contract manufacturing arrangements relating to the eligible components‍
• Validate domestic production: Only eligible components produced in the U.S. and its territories are eligible for a tax credit. Elements, subcomponents, and materials used in the product of an eligible component are not subject to the domestic requirement. Diligence around the location of the §45X facility may be addressed with the evidence of facility ownership and/or site visit
• ‍Confirm no §48C investment tax credits: Facilities that claim §48C investment tax credits are only eligible for AMPCs if the assembly line for §45X eligible components operates independently from the §48C assembly line or factory. This diligence typically requires an understanding of when the facility began operations as well as direct inquiry around sources of funds (namely §48C tax credits). In some cases, a review of prior tax returns and/or publicly named §48C awards may corroborate any direct inquiries
• ‍Validate third-party sale for productive purposes: §45X tax credits are only generated upon the sale of eligible components to a third party. Diligence may include obtaining relevant, audited sales and cost information, or a review of major revenue contracts and supporting sales documentation. Additionally, a sale to an affiliate would not generate a tax credit until subsequent resale by the affiliate to a third party unless an annual Related Person election pursuant to §45X(a)(3)(B) is made with the IRS to treat an affiliate as a third party for purposes of determining §45X tax credits. In the event there is a Related Person election, the election should be reviewed to confirm all required disclosures are properly included. Buyers should also confirm that sales do not run afoul of anti-abuse considerations

Relationship to the §48C qualifying advanced energy project credit

Certain advanced manufacturers may elect the §45X AMPC or the §48C qualifying advanced energy project credit, though they cannot claim the §45X credit for products manufactured at a facility for which they claimed a §48C credit. There are instances, however, when vertically integrated manufacturers may qualify for both credits. For example, if a company manufactures a component from equipment for which it claimed a §48C credit, and then uses that component to produce §45X components using other equipment, the company may be eligible to claim both credits.

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Due diligence considerations common to §48 ITCs, §45 PTCs, and §45X AMPCs

As noted under each of the three most common tax credits, different tax credits present different risks, mitigants, and due diligence considerations. There are, however, several due diligence considerations that are common to the §48, §45, and §45X tax credits.

Corporate structure

Buyers should understand the corporate structure of the seller and identify and diligence any disregarded entities between the project company and the seller. Doing so will ensure proper chain of title of tax credits to the seller and enable evaluation of any transactions that may be disregarded for tax purposes.

To the extent the seller is a partnership or an S-corporation whose partners or shareholders may be individuals or closely held corporations, the at-risk rules of §49 may reduce the amount of eligible credit available. At a high level, these rules require credits to be reduced by any non-recourse financing (although there is an exemption for qualified commercial financing that covers many typical project financings). Commonly reviewed corporate documentation includes:

• Articles of organization, operating agreements, and corporate by-laws
• Organization chart
• Taxpayer identification number
• Certificate of good standing
• Lien and litigation searches

Financial strength

While buyers do not have direct governance rights over the underlying project from which they are purchasing credits, they bear the risk of tax credit recapture or disallowance. As a result, sellers will generally indemnify the buyer against losses due to recapture or disallowance.

The value of this indemnification depends on the seller’s creditworthiness and financial condition. Large sellers with strong balance sheets will be able to satisfy their indemnification obligations. By contrast, smaller or less well-capitalized sellers may have difficulty compensating buyers in the event of a recapture or disallowance.

Understanding the scope of an indemnification requires the buyer to understand the financial strength and any existing indemnification obligations of the seller, and any relevant parent organization(s) that may be providing credit support.

Pre-filing registration

The buyer should review IRS pre-filing documentation and registration number(s) provided by the seller The parties should consider that the IRS has indicated that it may take up to 120 days to process registration number applications. While it is common for transfer transactions to close with the registration numbers pending, taxpayers should note that a fully executed transfer election statement (including the registration number) is required to be filed as part of both the buyer and seller’s final tax return filing. Not having a registration number by the final filing date may invalidate the transfer.

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Prevailing wage and apprenticeship requirements

The IRA aims to create a robust market for well-paying clean energy jobs. To achieve this goal, the IRA significantly increases the tax benefits for projects that meet prevailing wage and apprenticeship (PWA) requirements.

Projects that comply with PWA requirements generally receive a tax credit that is five times greater than the base rate. Of the 11 tax credits eligible for transfer, only the §45X credit is not subject to PWA requirements.

The IRS and Treasury published final PWA regulations on June 18, 2024, and they go into effect on August 26, 2024. Alongside the final regulations, the IRS published a fact sheet and updated their PWA FAQs.

Prevailing wage rules

Overview of prevailing wage

Prevailing wage rules require that laborers and mechanics that are employed by the project developer, or by construction contractors or subcontractors working on the project, are paid a minimum prevailing wage specified by the U.S. Department of Labor (DOL). Prevailing wages must be paid during the construction of a facility or property, and during alteration or repair of a facility or property for a certain number of years after the project is placed in service.

Prevailing wages apply not only to laborers and mechanics at the site of construction, but also to secondary sites where a significant portion of the construction, alteration, or repair of the facility occurs, provided that the secondary site either was established specifically for, or dedicated exclusively for a specific period of time to, the relevant project. Secondary sites include any adjacent or virtually adjacent dedicated support sites, such as job headquarters, tool yards, batch plants or borrow pits.

Workers do not have to be paid prevailing wages for basic maintenance work, which is “routinely scheduled and continuous or recurring.” Examples of basic maintenance are regular inspections of the facility, regular cleaning and janitorial work, regular replacement of materials with limited lifespans such as filters and light bulbs, and the calibration of any equipment.

When to start paying prevailing wages

Prevailing wages must be paid from the time at which construction, alteration, or repair begins; the definition of construction, alteration, or repair is expansive and includes all types of work done on a particular building or work site, as defined in 29 CFR 5.2. This aligns with the Davis-Bacon Act (DBA) administered by the DOL, rather than the physical work and 5% tests the IRS has used to determine when construction starts for tax purposes. For example, prevailing wages must be paid during certain demolition or removal activities, which would not be considered the start of physical work on the project for purposes of qualifying for tax benefits.

Determining the prevailing wage rate

Prevailing wage rates are published on the SAM website. The appropriate job type, location, and time period must be selected in order to comply with prevailing wage requirements. Occasionally, the job type and/or location is not published. In this case, the taxpayer can contact the DOL at IRAprevailingwage@dol.gov to request a wage determination. The department will try to respond to wage determination requests within 30 days.

The prevailing wage rates that must be paid are locked in at the time the contract for the construction, alteration, or repair of the facility is executed by the project developer and the contractor. This is consistent with the timing of wage determinations in Davis-Bacon compliant projects. If a project developer enters into a contract for alteration or repair work over an indefinite period of time that is not tied to the completion of any specific work, the applicable prevailing wage rates must be updated on an annual basis on the anniversary date of such contract.

If the project developer executes separate contracts with more than one prime contractor, then for each such contract, the applicable prevailing wage rates are determined at the time the contract is executed with each prime contractor. The prevailing wage rates apply to all subcontractors under each prime contractor. Prevailing wage rates must be reset to current wage rates if the contract is later amended to add substantially to the scope of work or extend the contract period.

If work on a project straddles locations with different wage rates, then the project developer should pay the wages for each location based on where the work is done. Offshore wind projects should use the prevailing wages for the closest location on shore.

Apprenticeship rules

The IRA’s apprenticeship rules fall into three main categories.

Labor hours requirement

The apprenticeship rules require a certain percentage of labor hours during construction, alteration, or repair for a project prior to the facility being placed in service to be performed by a qualified apprentice. The minimum percentage of hours that must be performed by qualified apprentices is:

• 12.5% for projects that began construction after December 31, 2022 and before January 1, 2024
• 15.0% for projects that begin construction after December 31, 2023

Hours worked by foremen, superintendents, owners, or persons employed in a bona fide executive, administrative, or professional capacity are excluded from the labor hours calculation.

Ratio requirement

The labor hours requirement is subject to any applicable requirements for apprenticeship-to-journeyman ratios of the DOL or applicable state apprenticeship agencies. Apprenticeship ratios can be set by a DOL- or state-approved registered apprenticeship program and vary from one program to the next.

Participation requirement

Any contractor, subcontractor, or taxpayer who employs four or more mechanics or laborers on the project must employ one or more qualified apprentice. The workers, however, do not have to be employed at the same time.

Duration of PWA requirements

The duration of the PWA compliance requirement depends on the credit. The IRS clarified in the final regulations that apprentices are not required for work after a project is placed in service; therefore, compliance during the post-construction period applies only to prevailing wages.

As previously noted, §45X advanced manufacturing production credits are not subject to PWA requirements.

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Records and documentation

If PWA requirements are not fulfilled, tax credit buyers that were expecting the full tax credit amount could face a credit disallowance and be subject to underpayment penalties. However, when PWA compliance is well-documented, a careful due diligence process can help buyers get comfortable that the tax credits are properly accounted for.

Prevailing wage records

PWA documentation must include “payroll records for each laborer and mechanic (including each qualified apprentice) employed by the taxpayer, contractor, or subcontractor employed in the construction, alteration, or repair of the qualified facility.”

The guidance also lists further information that the taxpayer “may include” in their records for prevailing wage compliance:

• Identifying information for each laborer and mechanic who worked on the construction, alteration, or repair of the qualified facility, including the name, the last four digits of a social security or tax identification number, address, telephone number, and email address
• The location and type of construction of the qualified facility
• The labor classification(s) the taxpayer applied to each laborer and mechanic for determining the prevailing wage rate and documentation supporting the applicable classification, including the applicable wage determination and copies of executed contracts for construction, alteration, or repair of the qualified facility with any contractor or subcontractor
• The hourly rate(s) of wages paid (including rates of contributions or costs for bona fide fringe benefits or cash equivalents thereof) for each applicable labor classification
• Records to support any contribution irrevocably made on behalf of a laborer or mechanic to a trustee or other third person pursuant to a bona fide fringe benefit program, and the rate of costs that were reasonably anticipated in providing bona fide fringe benefits to laborers and mechanics pursuant to an enforceable commitment to carry out a plan or program described in 40 U.S.C. 3141(2)(B), including records demonstrating that the enforceable commitment was provided in writing to the laborers and mechanics affected
• The total number of hours worked by each laborer and mechanic per pay period
• The total wages paid for each pay period (including identifying any deductions from wages)
• Records to support wages paid to any qualified apprentices at less than the applicable prevailing wage rates, including records reflecting an individual’s participation in a registered apprenticeship program and the applicable wage rates and apprentice-to-journeyworker ratios prescribed by the registered apprenticeship program
• The amount and timing of any correction and penalty payments and documentation reflecting the calculation of the correction and penalty payments, including records to demonstrate eligibility for the penalty waiver in §1.45-7(c)(6)
• Records to document any failures to pay prevailing wages and the actions taken to prevent, mitigate, or remedy the failure (for example, records demonstrating that the taxpayer (or an independent third party engaged by the taxpayer) regularly reviewed payroll practices, included requirements to pay prevailing wages in contracts with contractors, and posted prevailing wage rates in a prominent place on the job site)
• Records related to any complaints received by the taxpayer, contractor, or subcontractor that the taxpayer, contractor, or subcontractor was paying wages less than the applicable prevailing wage rate for work performed by laborers and mechanics with respect to the qualified facility

Apprenticeship records

For apprentices, the developer should capture:

• Any written requests for the employment of apprentices from registered apprenticeship programs, including any contacts with the DOL’s Office of Apprenticeship or a state apprenticeship agency regarding requests for apprentices from registered apprenticeship programs
• Any agreements entered into with registered apprenticeship programs with respect to the construction, alteration, or repair of the facility
• Documents reflecting the standards and requirements of any registered apprenticeship program, including the applicable ratio requirement prescribed by each registered apprenticeship program from which taxpayers, contractors, or subcontractors employ apprentices
• The total number of labor hours worked with respect to the construction, alteration, or repair of the qualified facility, including and identifying hours worked by each qualified apprentice
• Records reflecting the daily ratio of apprentices to journeyworkers
• Records demonstrating compliance with the Good Faith Effort Exception in §1.45-8(f)(1) (including requests for qualified apprentices, correspondence with registered apprenticeship programs, and denials of requests)
• The amount and timing of any penalty payments and documentation reflecting the calculation of the penalty payments
• Records to document any failures to satisfy the apprenticeship requirements under §45(b)(8) and §1.45-8 and the actions taken to prevent, mitigate, or remedy the failure
• Records related to any complaints received by the taxpayer, contractor, or subcontractor that the taxpayer, contractor, or subcontractor was not satisfying the apprenticeship requirements

Annual prevailing wage compliance report

For §48 ITCs, tax credit sellers must submit an annual prevailing wage compliance report to the IRS during the five-year recapture period. The report should adequately document the payment of prevailing wages with respect to any alteration or repairs of the project.

Tax credit sellers submit the report to the IRS with their tax returns. To ensure compliance with the reporting requirement, tax credit buyers should receive confirmation of the seller’s annual submission.

Compliance

The IRS encourages tax credit sellers to take the following actions to ensure ongoing compliance:

• Regularly reviewing payroll records
• Ensuring any contracts entered into with contractors require that the contractors and their subcontractors adhere to prevailing wage and apprenticeship requirements
• Regularly reviewing compliance with the prevailing wage and apprenticeship requirements (including the proper worker classifications of laborers and mechanics, the applicable prevailing wage rates, and the percentage of labor hours performed by qualified apprentices)
• Posting information about paying prevailing wages in a prominent and accessible location, or otherwise providing written notice regarding the payment of prevailing wage rates
• Establishing procedures for individuals to report suspected failures to comply with the prevailing wage and apprenticeship requirements without retaliation or adverse action
• Investigating reports of suspected failures to comply with the prevailing wage and apprenticeship requirements
• Contacting the DOL’s Office of Apprenticeship or relevant state apprenticeship agency for assistance in locating registered apprenticeship programs

Exceptions

Beginning of construction

Projects that began construction before Jan. 29, 2023, are exempt from the prevailing wage and apprenticeship rules, except for credits under §48C and §45Z.

For the avoidance of doubt, the beginning of construction test to determine exemption from prevailing wage and apprenticeship requirements is a different test than determining when construction, alteration, or repair of a project began for purposes of starting compliance with prevailing wage rates.

One megawatt

Projects under §45 and §48 (and their replacements under §45Y and §48E) are exempt from PWA if the maximum net output is less than one megawatt (as measured in alternating current) or the capacity of electrical or equivalent thermal storage is less than one megawatt. The net output will be determined by “nameplate capacity,” defined as the maximum output on a steady-state basis during continuous operation under standard conditions.

In the case of thermal equipment, like geothermal heat pumps and solar process heating, a developer must use the equivalent of 3.4 million British thermal units per hour (mmBTU/hour) to determine maximum capacity. For hydrogen storage and clean hydrogen production facilities, 3.4 mmBTU/hour is equivalent to 10,500 standard cubic feet per hour. Finally, for qualified biogas, developers can convert 3.4 mmBTU/hour into a maximum net volume flow rate of 10,500 standard cubic feet/hour, after converting the gas output into a maximum net volume flow using the appropriate high heat value conversion factors found in an EPA table.

Electrochromic glass, fiber-optic solar, and microgrid controllers are not eligible for the one-megawatt exception because they do not generate electricity nor thermal energy.

Remedies

Prevailing wages

If a developer does not meet the PWA requirements, the tax credit does not automatically get reduced to the base rate. A developer can cure any deficiencies and will be deemed to satisfy the PWA requirements if, within 180 days from when the IRS makes a final determination (which occurs on the date the IRS sends a notice to the developer stating that the developer has failed to satisfy the PWA requirements), they:

• Pay back-wages with interest: Pay the affected laborers or mechanics the difference between what they were paid and the amount they were required to have been paid (multiplied by three for intentional disregard), plus interest at the federal short-term rate (as defined in §6621) plus 6%; and
• Pay a penalty: Pay a penalty to the IRS of $5,000 ($10,000 for intentional disregard) for each laborer or mechanic who was not paid at the prevailing wage rate in the year. This penalty applies to each calendar year of the project. If, for example, a laborer is not paid the correct prevailing wage in two calendar years, the penalty is $10,000

The taxpayer can waive the penalty if they make a corrective payment with interest by the last day of the first month after the calendar quarter in which the wage shortfall occurred, and either of two conditions is true:

1. The worker was not paid less than the prevailing wage for more than 10% of all pay periods of the calendar year during which the worker was employed on the project
2. The shortfall in payment was not greater than 5% of what the worker should have been paid during the year

The penalty is waived if the laborer or mechanic was employed under a “qualifying project labor agreement” and if any correction payment owed to the laborer or mechanic is paid on or before a return is filed claiming an increased credit amount. A qualifying project labor agreement must meet six requirements, which can be found at 26 CFR §1.45-7(c)(6)(ii).

To avoid increased penalties due to intentional disregard, the taxpayer should undertake a quarterly (or more frequent) review of wages paid to mechanics and laborers to ensure that wages not less than the applicable prevailing wage rate were paid.

Apprenticeships

To cure a failure to meet the apprenticeship requirements, a developer must pay a penalty of $50 multiplied by the total labor hours for which the apprenticeship requirements were not met. The amount of the penalty with respect to the apprenticeship requirements is also increased to $500 per labor hour if the IRS determines the failure was due to intentional disregard.

Good-faith exception

The apprenticeship requirement can be satisfied if the developer made a good faith effort to comply. The developer must have requested qualified apprentices from a registered apprenticeship program and either:

• The request was denied for reasons other than the developer’s refusal to comply with the program’s standards and requirements
• The apprenticeship program failed to respond within five business days of receiving a request

To satisfy the good faith effort exception, the developer must make a written request to at least one registered apprenticeship program that has a geographic area of operation that includes the location of the facility, or that can reasonably be expected to provide apprentices to the location of the facility; trains apprentices in the occupation(s) needed by the developer performing construction, alteration, or repair with respect to the facility; and has a usual and customary business practice of entering into agreements with employers for the placement of apprentices in the occupation for which they are training, pursuant to its standards and requirements.

An apprenticeship request must be made at least 45 days before the qualified apprentice is requested to begin work on the facility, so that registered apprenticeship programs have adequate time to plan for the anticipated need. Subsequent requests to the same registered apprenticeship program must be made no later than 14 days before qualified apprentices are requested to begin work on the facility.

If there is no apprentice program that covers the project location, trains apprentices in the occupations needed and supplies apprentices to employers, then the project is deemed to have made a good-faith effort without the need to file a request for apprentices. In this case, however, developers should contact the DOL and/or a state agency to help find apprentices.

A request for a qualified apprentice lasts for 365 days (or 366 during a leap year). Developers must submit a subsequent request within the 365-day (or 366-day) window to continue to satisfy the good-faith exception. The annual duration also applies if a developer is not able to locate a registered apprenticeship program with an area of operation that includes the location of the facility.

The good faith effort exception is limited to the request for apprentices made by the developer, including the number of apprentice hours for which the request for apprentices has been made to a registered apprenticeship program.

The good faith effort exception only applies to the specific portion of the request for apprentices that was not responded to or was denied. If a request was not responded to or was denied, the developer must submit an additional request(s) to a registered apprenticeship program after 120 days to continue to be eligible for the good faith effort exception.

Due diligence

Under the IRS regulations, it is the seller’s obligation to maintain and preserve sufficient records demonstrating compliance with PWA requirements. But the liability for non-compliance is on the buyer in the form of an excessive credit transfer.

If the tax credit claims to be exempt from PWA requirements, the tax credit buyer should substantiate exemption under one of two scenarios:

• Beginning of construction exemption: Validate and substantiate that construction began prior to January 29, 2023
• One megawatt exemption: Validate the size of eligible project through audit of relevant contracts

If the tax credit requires compliance with PWA requirements, the tax credit buyer should validate that proper documentation was collected by the seller. At a minimum, the IRS requires “payroll records for each laborer and mechanic (including each qualified apprentice) employed by the taxpayer, contractor, or subcontractor.” The IRS also lists several other items the taxpayer may include in  compliance, including nine related to wages and five related to apprentices; the list is available at 26 CFR §1.45-12(c) and (d).

Tax credit buyers should ensure sellers have properly collected, maintained, and reviewed payroll records to ensure that prevailing wages were paid and sufficient apprentice labor was utilized. Tax credit sellers often engage third parties to provide additional analysis with respect to PWA compliance. Furthermore, buyers should also review the covenants, representations and warranties in contracts with the primary EPC (and potentially with their subcontractors) to validate that all parties have agreed to comply with PWA requirements.

In the case of the §48 ITC, the seller should also provide any information the IRS requires during the recapture period.

Guidance

• November 30, 2022: IRS Notice 2022-61, Prevailing Wage and Apprenticeship Initial Guidance Under §45(b)(6)(B)(ii) and Other Substantially Similar Provisions
• August 30, 2023: Notice of Proposed Rulemaking, Increased Credit or Deduction Amounts for Satisfying Certain Prevailing Wage and Registered Apprenticeship Requirements
• November 17, 2023: Notice of Proposed Rulemaking, Definition of Energy Property and Rules Applicable to the [§48] Energy Credit
• June 24, 2024: Final regulations, Increased Amounts of Credit or Deduction for Satisfying Certain Prevailing Wage and Registered Apprenticeship Requirements

Resources

• The IRS maintains a prevailing wage and apprenticeship requirements FAQ
• The Department of Labor determines and maintains prevailing wages
• To request a wage determination, developers can email iraprevailingwage@dol.gov with project and labor information
• Apprenticeship.gov provides resources for finding qualified apprentices

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Bonus credits

The IRA created three bonus credits, or “adders,” for which projects can qualify:

• Energy community bonus
• Domestic content bonus
• Low-income community bonus

Each bonus has specific eligibility requirements that a project must meet. Tax credit buyers will bear some additional risk when assuming these bonus credits, as qualification for these adders is subject to IRS scrutiny and audit.

Bonus credits are not treated differently from base credits for the purpose of transferability. Treasury guidance released in June 2023 specified that all transferable credits must be sold as “vertical slices” and be pari passu to one another, as opposed to “horizontally” bifurcating bonus credits from base credits.

Energy community

Eligibility

To qualify for the energy community bonus, a project must be in at least one of three energy community types:

• Brownfield
• Statistical area
• Coal closure

If a clean energy project is in two energy communities – a brownfield site within a coal closure, for instance – the bonus remains 10%.

Timing

For projects that claim an investment tax credit under §48 and §48E, eligibility for the energy community bonus credit is determined on the date that the project is placed in service and is not tested again.

For projects (including repowers) that claim a production tax credit under §45 and §45Y, eligibility for the energy community bonus credit must be determined every year during the ten-year PTC period. For such credits, a qualified facility is treated as located in an energy community during a taxable year if it is located in an energy community during any part of the taxable year.

However, to the extent that a taxpayer begins construction on a project after December 31, 2022 in a location that is in an energy community on the date the project begins construction, then the location will continue to be considered an energy community for the full duration of the PTC credit period (for §45 and §45Y) or on the placed in service date (for §48 and §48E).

Projects that generate §45 PTCs that were placed in service before December 31, 2022 are not eligible for the energy community bonus, even if the project happens to be located in an energy community and is within its ten-year period of credit generation. The December 31, 2022 date is set in the IRA itself (H.R.5376).

Nameplate capacity test

A project qualifies for the energy community bonus if at least half (50%) of its nameplate capacity is in an energy community. According to the IRS, nameplate capacity is the DC capacity that a project is capable of producing on a steady-state basis during continuous operation under standard conditions.

Footprint test

If a clean energy facility does not have a nameplate capacity, it can qualify for the energy community bonus under the “footprint test.” If 50% or more of the project’s square footage is located in an energy community, then the project qualifies for the bonus. The percentage is determined by dividing the square footage of the project that is located in the energy community by the total square footage of the project.

Brownfield

A brownfield site as defined in certain subparagraphs of the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA): “…real property, the expansion, redevelopment, or reuse of which may be complicated by the presence or potential presence of a hazardous substance, pollutant, or contaminant."

Three types of sites qualify as a brownfield under a safe harbor:

• Existing brownfield: Brownfields that are already tracked by a federal, state, territorial, or federally recognized Indian tribal brownfields program. Many states, like Idaho and New York, have their own brownfields programs with supporting maps. A valid brownfield site could be tracked by a state program but not a federal program, and vice versa
• Phase II assessment: A Phase II Assessment has been completed with respect to the site and such Phase II Assessment confirms the presence on the site of a hazardous substance as defined under 42 U.S.C. § 9601(14), or a pollutant or contaminant as defined under 42 U.S.C. § 9601(33)
• Phase 1 assessment (for projects with a nameplate capacity of not greater than 5 MWac): A Phase I Assessment has been completed with respect to the site and such Phase I Assessment identifies the presence or potential presence on the site of a hazardous substance, or a pollutant or contaminant

Statistical area

A "metropolitan statistical area" (MSA) or "non-metropolitan statistical area" (non-MSA) that has (or had at any time after 2009):

• 0.17% or greater direct employment or 25% or greater local tax revenues related to the extraction, processing, transport, or storage of coal, oil, or natural gas; and
• Has an unemployment rate or above the national average unemployment rate for the previous year

The statistical area category is determined annually, based on the prior year's unemployment rate. As the IRS FAQs state, "Because an MSA's or non-MSA's status as an energy community depends on its unemployment rate for the previous year, an MSA or non-MSA that qualifies as an energy community in one period might not qualify as an energy community in a later period if its unemployment rate for the previous year falls below the national average."

Coal closure

A census tract (or directly adjoining census tract):

• In which a coal mine has closed after 1999; or
• In which a coal-fired electric generating unit has been retired after 2009

Due diligence considerations

The energy community bonus is relatively straightforward to substantiate. A developer should provide documentation that crosswalks their project’s location with at least one of the three energy community categories. Buyers will want to keep the 50% rule in mind when comparing locations.

For §48 and §48E ITCs, eligibility for the energy community bonus credit is determined on the date that the project is placed in service. For §45 and §45Y PTCs, eligibility for the energy community bonus credit must be determined every year during the ten-year PTC period, although the IRS created a safe harbor for projects with beginning of construction dates on or after January 1, 2023.

Nameplate capacity attribution rule

The most recent IRS guidance, Notice 2024-30, broadened eligibility for the energy community bonus through two key changes:

• Expansion of the "nameplate capacity attribution rule"
• Inclusion of two additional NAICS codes for determining the fossil fuel employment rate for a statistical area category

The "nameplate capacity attribution rule" pertains to projects with offshore generation – namely, offshore wind – that have a nameplate capacity but are not located within a census tract, an MSA, or a non-MSA. The rule allows developers to allocate their offshore nameplate capacity onshore for purposes of qualifying for the energy community bonus.

Prior to Notice 2024-30, the attribution rule generally allowed offshore wind projects to qualify for the energy community bonus if their power-conditioning equipment closest to the point of interconnection was in an energy community.

Notice 2024-30 expanded the nameplate capacity attribution rule to include not only power-conditioning equipment, but also supervisory control and data acquisition (SCADA) equipment.

SCADA equipment must be owned by the developer and located in an "energy community project port." To qualify as an energy community project port, a port must:

• Be used "either full or part-time to facilitate maritime operations necessary for the installation or operation and maintenance" of the project
• Have a "significant long-term relationship" with the project, meaning the developer owns or leases all or part of the port for a minimum term of ten years
• Be the location at which staff employed by, or working as independent contractors for, the project are based and perform functions essential to the project's operations. Essential functions include "management of marine operations, inventory and handling of spare parts and consumables, and berthing and dispatch of operation and maintenance vessels and associated crews and technicians"

Annual updates

According to Notice 2023-29, "The Treasury Department and the IRS intend to update the listing of the Statistical Area Category based on Fossil Fuel Employment annually. These updates generally will be issued annually in May."

Guidance

• October 5, 2022: IRS Notice 2022-51, Request for Comments on Prevailing Wage, Apprenticeship, Domestic Content, and Energy Communities Requirements under the Inflation Reduction Act of 2022
• April 4, 2023: IRS Notice 2023-29, Energy Community Bonus Credit Amounts under the Inflation Reduction Act of 2022; Appendix A; Appendix B; Appendix C
• April 7, 2023: IRS Notice 2023-45, Energy Community Bonus Credit Amounts Under the Inflation Reduction Act of 2022
• June 15, 2023: IRS Notice 2023-47, Energy Community Bonus Credit Amounts or Rates, Annual Statistical Area Category Update and Coal Closure Category Update; Appendix 1; Appendix 2; Appendix 3
• March 22, 2024: IRS Notice 2024-30, Energy Community Bonus Credit Amounts Under the Inflation Reduction Act of 2022; Appendix 1; Appendix 2
• June 9, 2024: IRS Notice 2024-48, Energy Community Bonus Credit Amounts or Rates: Annual Statistical Area Category Update and Coal Closure Category Update; Appendix 1; Appendix 2

Resources

• The Department of Energy (DOE) maintains an energy community map
• The National Energy Technology Laboratory (NETL) maintains an energy community interagency website, which has a robust FAQ page
• The Environmental Protection Agency (EPA) maintains a cleanups in my community map, which shows federally recognized brownfields
• The IRS maintains an FAQ

Reunion analysis and commentary

The energy community bonus credit is widely applied and generally uncontroversial from an underwriting standpoint, given that the credit is location-based and easily verified with GIS-mapping. Many projects benefit from the energy community, as large swaths of the U.S. are in energy communities, including much of Appalachia, Texas, Nevada, and the Rocky Mountains.

Domestic content

Eligibility

To incentivize the development of domestic clean energy production and manufacturing, the IRA includes a domestic content bonus. The domestic content adder is applicable to the §45, §45Y, §48, and §48E credits.

To qualify, a project must meet two overarching requirements:

• Steel and iron: 100% of all structural steel or iron products used must be produced in the U.S.
• Manufactured products: A minimum percentage of the total costs of manufactured products (including components) must be mined, produced, or manufactured in the U.S. Direct labor costs of incorporating a manufactured product into a project, such as installation costs, are not applicable

The minimum percentage of manufactured products is set to increase annually:

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Within Notice 2023-38, the IRS provided a categorization of applicable project components as “steel/iron” or “manufactured product.”

The domestic manufacturing percentage calculation (“Adjusted Percentage Rule”) requires developers to divide the cost of the manufactured products or components made in the U.S. by the entire cost of all the U.S. and foreign manufactured products used to build the project.

Collecting and validating data to input into the calculation is complex, however. Interim IRS guidance requires analyzing the origin of parts and materials that the U.S. manufacturer used to make the product. Developers and their manufacturers and suppliers, therefore, will have to work closely together to validate the calculation. Manufacturers will need to disclose far more information about their supply chains and cost structures than has been customary.

Safe harbor

To minimize the complexities associated with collecting and validating cost data from manufacturers, the IRS created a “new elective cost safe harbor” in IRS Notice 2024-41 for purposes of calculating the domestic content percentage. A list of safe harbor technologies is in Appendix E: Domestic content safe harbor technologies.

The new elective safe harbor allows developers to determine their project’s domestic content percentage by aggregating fixed, IRS-determined percentages from an "exclusive and exhaustive" list of manufactured components and subcomponents instead of relying on the manufacturer to disclose their actual direct costs. Critically, the safe harbor does not exempt tax credit sellers from the domestic content requirements set forth in Notice 2023-38.

No partial reliance on safe harbor

If a developer chooses to use the elective safe harbor, they must do so for the entire project. Therefore, developers who use the elective safe harbor must disregard any manufactured products or manufactured product components not listed in Table 1 of Notice 2024-41.

Elective safe harbor certification

If a developer uses the elective safe harbor to qualify for the domestic content bonus, they must submit a certification to the IRS alongside Form 8835 (for PTCs) or Form 3468 (for ITCs) in the first taxable year in which they report a domestic content credit amount for their project.

Although the IRS has not prescribed a specific format, section 5 of IRS Notice 2023-38 provides a list of information that must be included:

• Project type
• Tax credit
• Placed-in-service date
• Location/coordinates
• Total amounts of bonus credit claimed

Substantiation

Developers who claim the domestic content bonus credit must meet general recordkeeping requirements under §6001 to substantiate that they have met all the adder requirements.

Due diligence considerations

Prior to the elective cost safe harbor, application of the domestic content bonus credit was minimal. This was partly driven by the complexity of validating proper qualification of the bonus. Sellers would need to collect sensitive cost information from their suppliers (which is practically infeasible in many cases), which the would, in turn, provide to buyers for due diligence purposes.

With the elective safe harbor, domestic content due diligence becomes simpler (though the adder will likely remain the most complex of the three to diligence). Buyers will want to validate the developer’s safe harbor calculations, collect documentation confirming the sourcing of components and sub-components included in the calculations, and view the developer’s safe harbor certification. In many cases, a legal memorandum may be prepared by seller counsel to analyze and confirm compliance with domestic content requirements.

Guidance

• May 12, 2023: IRS Notice 2023-38, Domestic Content Bonus Credit Guidance under §45, §45Y, §48, and §48E
• May 16, 2024: IRS Notice 2024-41, Domestic Content Bonus Credit Amounts under the Inflation Reduction Act of 2022: Expansion of Applicable Projects for Safe Harbor in Notice 2023-38 and New Elective Safe Harbor to Determine Cost Percentages for Adjusted Percentage Rule
• Final guidance: Expected 2024

Resources

• Table 1 – New Elective Safe Harbor, IRS Notice 2024-41

Reunion analysis and commentary

The preliminary guidance released in May 2023 created a complicated test for project owners to meet the domestic content requirement. Specifically, it requires owners to obtain the cost to manufacture subcomponents that were made outside of the United States. The practical ability to readily obtain this information from foreign suppliers will be challenging.

The latest guidance, released in May 2024, provides a valuable work-around: instead of relying on manufacturers to provide cost data, developers can apply a safe harbor. This change should unlock the domestic content bonus, and Reunion expects broader adoption over time.

Low-income community

Eligibility

The low-income bonus is designed to incentivize investment in communities that have historically been left behind. Specifically, the credit promotes wind, solar, and associated energy storage investments in low-income communities, on Indian land, as part of affordable housing developments, and benefitting low-income households.

The low-income bonus is an allocated and capped credit, and 2024 capacity limitations are presented below. Projects in the first two categories receive a 10% bonus credit value, while projects in the third and fourth categories receive a 20% bonus credit value. All low-income projects must be less than 5 MWac in size.

For 2024, at least 50% of the capacity of each category will be reserved for projects meeting certain ownership and/or geographic selection criteria, which we detail below.

Beginning in 2025, the low-income community bonus credit will be available under §48E(h). Guidance is forthcoming.

Allocations

The DOE maintains a low-income communities program capacity dashboard, which displays the available capacity for each category. As of this version, the DOE had not yet published 2024 capacity.

In 2023, 324.785 MW of capacity remained unallocated under the environmental justice solar and wind capacity limitation.

How to apply

Since the low-income bonus is an allocated bonus, developers must apply for and receive an allocation from the IRS. Developers who receive an allocation will receive an award letter from the IRS with their allocation amount.

The IRS makes it clear that a developer “may receive an allocation less than its [applied for] nameplate capacity.” The allocation, not the project’s capacity, determines the credit value.

There is an application starting date for each program year and applications submitted within 30 days of the start date will be treated as submitted on the same date and at the same time.

If any category or sub-category is oversubscribed during the initial 30-day period, the IRS will make awards based on a randomized lottery. Following the initial 30-day period, any leftover capacity will be awarded on a first-come, first-served basis. Applicants may only submit one application per facility, per program year.

The IRS will make allocations with certain ownership and location priorities in mind:

• Ownership: Priority will be given to (1) projects owned directly or indirectly by Indian tribes; (2) consumer or purchasing cooperatives with controlling members who are workers or from low-income households; (3) tax-exempt charities and religious organizations; and (4) state and local governments, and U.S. territories, Indian tribes, and rural electrical cooperatives
• Location: Priority will be given to (1) persistent poverty counties, where 20% of residents have experienced high rates of poverty of the last 30 years; and (2) and census tracts designated as “disadvantaged” in the Climate and Economic Justice Screening Tool (CEJST)

The following chart, provided by the DOE, outlines the high-level application process, including key activities once a project has been placed in service.

Restrictions

Once a developer has an allocation, they have four years to place the project in service, and they cannot change the location of the project. Extensions to the fouryear deadline are not permitted. Developers cannot place a project in service before receiving an allocation.

Once a tax credit seller has placed a project in service – but prior to filing tax forms to claim the credit – they must update their DOE online application and provide supporting documentation. (The scope of documentation depends on the allocation category.) Once a tax credit seller has updated their application with placed in service information, they must make several attestations, including confirming that there has been no material ownership and/or changes from the application, and submit the update for review.

If the facility size is larger than the allocated capacity (but still below 5 MWac), the 10 or 20 percentage point increase will be reduced by a reduction factor. If the facility size is lower than the allocated capacity (but by no more than the greater of 2kW or 25% of the allocated capacity), the percentage award is maintained. Larger reductions will result in disqualification.

The DOE can ask for further information during their review, which tax credit sellers provide through the application portal. Tax credit sellers have 12 business days to respond to requests for additional information.

Disqualification

A facility may become disqualified and lose its allocation if, prior to being placed in service, one or more of the following occur:

• Facility size is larger than the allocated capacity and now above 5 MWac
• Facility size is lower than the allocated capacity by more than the greater of 2kW or 25% of the allocated capacity
• The location where the facility will be placed in service changes
• The net output of the facility increases such that it exceeds the less than 5MW AC output limitation provided in §48(e)(2)(A)(ii) or the nameplate capacity decreases by the greater of 2 kW or 25 percent of the Capacity Limitation awarded in the allocation (AC for a wind facility; DC for a solar facility)
• The facility cannot satisfy the financial benefits requirements for allocation categories 3 of 4
• The facility that received the capacity limitation allocation is not placed in service within four years after the date the applicant was notified of the allocation of capacity limitation to the facility
• The facility received a capacity limitation allocation based, in part, on meeting the ownership criteria and ownership of the facility changes prior to the facility being placed in service, unless the original applicant transfers the facility to an entity treated as a partnership for federal income tax purposes and retains at least a one percent interest (either directly or indirectly) in each material item of partnership income, gain, loss, deduction, and credit of such partnership and is a managing member or general partner (or similar title) under State law of the partnership (or directly owns 100 percent of the equity interests in the managing member or general partner) at all times during the existence of the partnership

Successor-in-interest charges

Developers may apply to transfer an allocation of environmental justice solar and wind capacity when there is a sale or transfer of an underlying facility. If the original allocation was based, in part, on meeting certain ownership criteria, a change in ownership can result in disqualification.

A tax credit seller may only apply for an allocation transfer when all three of the following conditions are valid:

• A sale or transfer of a facility from one taxpayer to another has taxpayer occurred
• The original owner has already applied for and been awarded an allocation for the applicable project
• The original owner has not already placed the project in service

Once the IRS approves an ownership change, the successive owner is responsible for filing all placed-in-service documentation.

Due diligence considerations

To qualify for the bonus, a developer must have an allocation award letter as well as confirmation that the project was placed in service within a statutorily set four-year period. To validate that the project was properly placed in service, the developer must provide documentation and make attestations in the DOE low-income community application portal.

The documentation requirements vary by category:

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If the project was subject to a successor-in-interest change, buyers should validate that the successor placed the project in service and that the ownership change did not run afoul of any ownership-based allocation criteria.

Guidance

• February 13, 2023: Notice 2023-17, Initial Guidance Establishing Program to Allocate Environmental Justice Solar and Wind Capacity Limitation Under §48(e)
• May 31, 2023: Notice of Proposed Rulemaking, Additional Guidance on Low-Income Communities Bonus Credit Program
• August 10, 2023: Final Regulations, Additional Guidance on Low-Income Communities Bonus Credit Program
• August 10, 2023: Revenue Procedure 2023-27
• March 29, 2024: Revenue Procedure 2024-19

Resources

• The Department of Energy (DOE) maintains a low-income communities bonus credit program website and application portal
• Applicant checklist
• Applicant user guide (2024 program year)
• Successor-in-interest allocation transfer request guide
• Category 1 eligibility map with CEJST and persistent poverty county screens
• Category 3 eligible covered housing programs‍
• Category 4 household income limits

Reunion analysis and commentary

In 2023, the IRS and DOE adjusted the category allotments within the low-income bonus credit to drive full allocation. Further, the IRS and DOE carried over unallocated environmental justice and wind capacity from 2023 to 2024:

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Tax credit pricing

Transferable tax credits are priced at a discount to face value ($1.00) to incentivize the buyer to purchase credits.

Most tax credit buyers are sensitive to incurring “above the line” expenses, and will typically expect the seller to pay for the following transaction-related costs:

• Intermediary fee: in many transactions, an intermediary such a Reunion arranges the transaction and provides due diligence and transactional support
• Tax credit insurance: For transactions in which the seller cannot provide a sufficiently strong indemnification, buyers may require tax credit insurance. The price of insurance varies, but typically costs two to three cents per $1.00 of tax credit

Tax credit buyers often will retain third-party legal counsel and, in certain cases, will retain an accounting or advisory firm to perform additional due diligence. Buyers are increasingly requesting a capped level of reimbursement from the seller for all or a portion of these professional services expenses. Whether the seller provides reimbursement, and to what level, is the subject of negotiation.

Pricing with tax credit buyers is typically discussed as the price that the buyer pays for the credit. For example, a tax credit buyer that purchases $100M in credits at a quoted price of $0.95 generally expects that they will achieve $5M in savings. The price typically assumes that the seller will pay for the intermediary fee, tax credit insurance (if applicable), and potentially a capped level of reimbursement for professional service fees.

The price that the buyer pays is sometimes referred to as the gross price, and the price that the seller ultimately receives is sometimes referred to as the net price.

Latest pricing for §48 ITCs, §45 PTCs, and §45X AMPCs

Reunion publishes pricing on a quarterly basis in our market intelligence report.

Other considerations

Speed of transaction execution is also a key factor in pricing. Buyers that provide a strong early offer to a seller may be able to circumvent a longer sales process and get advantageous pricing as a result.

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Cashflow considerations

Selecting the most appropriate credit

Among corporate taxpayers, Reunion has generally seen tax credit buyers in one of two camps:

• Maximize the dollar amount of tax savings
• Minimize risk, complexity, and optimize timing of payment to avoid “out of pocket” investment compared to what buyer would have paid the IRS

The first group tends to focus on §48 ITCs. The second group generally focuses on §45 PTCs and §45X AMPCs, which do not carry risk of §50 recapture and can be purchased quarterly in arrears (typically structured such that the buyer pays concurrently or shortly after each quarterly estimated tax payment date, based on credits generated to date).

ITCs can also be structured to minimize the impact on cashflows, which we discuss below; for example, portfolios of ITCs can be paid for quarterly in arrears.

Maximizing the dollar amount of tax savings

Buyers who are primarily interested in maximizing the dollar amount of tax savings associated with a tax credit purchase focus on the level of discount, rather than on timing of payment, or complexity of transaction.

Generally, these buyers find ITCs most appealing because of their deeper median discounts of 7.0% to 9.0%. As noted in Section 9.1, Overview of tax credit pricing, buyers can achieve a relatively larger discount on ITCs by paying in full earlier in the year, making forward commitments for future tax years, and pursuing more complex or riskier transactions.

Optimizing timing of payment to avoid “out of pocket” investment

Treasury’s final regulations made clear that corporate taxpayers can offset their quarterly estimated tax payments using tax credits they intend to purchase, opening the door for tax credit buyers to realize most or all the benefit of a tax credit prior to paying the tax credit seller.

An increasing number of corporate tax directors and treasurers are focused on these types of opportunities, which do not require the buyers to go “out of pocket” to invest in a tax credit. Instead, the buyer pays a clean energy company a discounted amount compared to what they would have paid the IRS. The payment is concurrent with, or in some cases even after, their scheduled tax payment date and is based on actual tax credits generated to date.

We have identified four primary scenarios in which buyers can realize tax benefits prior to cash outlay. In the following examples, we assume the buyer is a corporation that pays $200M each year in federal tax and is looking to purchase $50 to $100M in tax credits.

Purchase §45 PTCs or §45X AMPCs and pay quarterly in arrears

Production-based tax credits including §45 PTCs and §45X AMPCs are typically paid quarterly in arrears.

As an example, a tax credit buyer commits to purchasing $100M in tax credits in Q1, which allows the buyer to offset $25M in tax payments each quarter. This example assumes that credits are generated evenly throughout the year, and therefore the buyer pays the tax credit seller $23.75M on each estimated tax payment date, instead of paying the IRS $25M. This results in a $1.25M net benefit each quarter, without any out-of-pocket investment.

Note that if the buyer commits to purchase $100M in a later quarter, there is a similarly strong benefit. For example, if the buyer commits to purchasing credits in Q2 instead of Q1, the buyer can offset $50M in tax payments in Q2, and $25M in both Q3 and Q4.

Purchase a §48 ITC portfolio and pay quarterly in arrears

A portfolio of ITCs can be structured similarly to the previous example, in which the buyer pays quarterly in arrears (and is therefore able to utilize the full tax benefit prior to cash outlay).

In this example, the seller has a portfolio of rooftop solar projects that will be placed in service throughout the year, generating a total of $100M in tax credits. The seller is offering an 8% discount for the credits. The buyer commits to the tax credit purchase in Q1 and reduces their estimated tax payments by $25M each quarter.

The buyer will pay for the actual credits generated at the end of each preceding quarter. In this example, we assume that $20M in credits are generated in Q1 and Q2, while $30M is generated in Q3 and Q4. As a result, a relatively lower volume of credits needs to be paid for in Q1 and Q2 (while the reduction in estimated tax payments remains fixed at $25M each quarter), resulting in a strong net benefit in Q1 and Q2. Overall, the buyer saves $8M in taxes over the course of the year, without any out-of-pocket investment.

There is a risk that the seller does not generate as many credits as anticipated in a given tax year; if so, liquidated damages or a make-whole provision can be negotiated, which obligates the seller to make the buyer whole for any difference between what they agreed to pay for the credits and what they would have to reasonably pay for any replacement credits. In the event of a shortfall of credits, Reunion will also work with the buyer to source replacement credits.

Commit to a §48 ITC purchase early in the year, but pay late in the year

In this scenario, a buyer commits to purchasing ITCs that a developer will generate later in the year. While the IRS was clear that buyers can offset quarterly tax payments with tax credits they intend to purchase, it is up to buyers and their legal and tax advisors to decide what documentation is needed to establish intent.

Assume that the buyer and seller execute a tax credit transfer agreement in Q1, and the buyer uses this as a basis to start offsetting quarterly estimated tax payments. If the project is placed in service around or after the Q3 estimated tax payment date, the buyer will be able to offset taxes in Q1, Q2, and Q3 before having to pay the seller for the credits (see example below). This will free up $25M of additional cash each quarter for other corporate purposes, with the understanding that a lump sum will need to be paid to the tax credit seller later.

Sellers typically prefer to receive payment as soon as the credits are generated, but it is possible to negotiate a delayed payment date. For example, if the payment date can be delayed to on or after the Q4 estimated payment date, the buyer will be able to take the full benefit of the tax credit before any cash outlay. This strategy also applies if the buyer commits to the ITC in Q2 or Q3 and does not have to pay for the credit until later in the year.

Structure 3 carries the risk that the project is not placed in service in 2024 tax year, which would require the buyer to source replacement credits. It is possible for the buyers to negotiate liquidated damages or a make-whole provision, if credits are not delivered as promised.

Buy tax credits to “top up” at the end of the year, resulting in a lower Q4 or final tax payment

The final scenario is a variation of structure 3. A company purchases tax credits at the end of the year, once they have a more concrete understanding of their total annual tax liability, and delays payment until their Q4 or final tax payment date.

Assume the buyer has paid $150M in taxes through the first three quarters and has $50M due in taxes in Q4. The buyer can fully offset their remaining taxes due by committing to purchase $50M in credits in Q4. In this example, the buyer receives an 8% discount, paying $46M for the credits and achieving tax savings of $4M. The buyer can achieve the full benefit of the credit prior to cash outlay by arranging to pay the seller of the tax credit on or after the Q4 estimated tax payment date.

The same logic applies to credits purchased in time for the final tax filing (e.g., on April 15 for the prior tax year, for a calendar year filer). If a buyer has $20M in remaining payments due at final tax filing, they could offset the entire tax payment through purchase of a tax credit. Assuming they could identify and purchase a tax credit with an 8% discount, they would pay $18.4M to a tax credit seller, achieving $1.6M in tax savings. It is worth noting that if the buyer procures more than they end up owing in their final tax payment, the overpayment can be applied to the first estimated tax payment of the following year.

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Tax credit transfer agreements

General structure

A tax credit transfer agreement (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 in which 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 in which 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 that the buyer, seller, and project meet certain conditions before closing.

Commercial terms

Pricing is the obvious commercial term that the transacting parties must negotiate. Price 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 (typically annual caps, but occasionally quarterly caps as well)
• 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. For example, if a project is placed in service in January 2025 rather than December 2024, the tax credit is generated for the 2025 tax year, which may carry a different value to the buyer compared to a credit for the 2024 tax year
• Payment terms: To the extent that a buyer desires to pay the seller in a manner that is not immediately after all closing conditions have been met, the TCTA should specify these payment terms; buyers will often want to align payment of credits no earlier than their estimated tax payment dates
• Transaction costs: Often, buyers will include a provision for sellers to pay for a buyer’s third-party transactional costs; these amounts are typically capped at a negotiated amount

Representations and warranties

At a basic level, the seller will represent that it owns the credit property, the credit project is qualified to generate transferable tax credits, they are eligible to claim and transfer the credits from the credit property, 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, that 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

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 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 (depending on the timing of the transaction and pre-filing registration process, this is often a post-closing covenant, with the form of such transfer election statements agreed upon in the transfer agreement)
• 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 when 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 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 from the IRS 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 [tax credit buyer’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 period, 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 can 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.

Typically, tax contest language in the TCTA reflects this risk-sharing agreement. In an audit by the IRS against the buyer, the buyer controls 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. Often the buyer contractually agrees to not settle or resolve any dispute with the IRS without the seller’s consent. Specific control and participation rights 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.

Guarantor

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 turn owned by a partnership, the seller of the tax credit is the partnership, as opposed to the project company, as that project company is a disregarded entity for tax purposes.

Given that the tax credit seller may be a company of limited financial wherewithal, a guarantor is needed to backstop the indemnity obligations of the seller. The guarantor is typically the parent company of the developer. 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 five-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

The requirement for tax credit insurance is a negotiated item and will be included as a condition precedent in the TCTA to the extent agreed to by the parties. While the insurer typically does not have contractual privity to the TCTA, it typically will review the TCTA as part of its underwriting and due diligence.

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.

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Indemnification

While buyers do not have direct governance rights with respect to the underlying project, they bear the risk of tax credit recapture or disallowance. As a result, one important risk mitigant is for the seller to indemnify the buyer against losses it may incur because of the recapture or disallowance of the credit.

Tax credit seller indemnification is typically broad, covering the buyer’s loss, reduction, recapture, or disallowance of any transferred credit as well as any interest and penalties (including any excess credit transfer penalties) payable to the IRS. Actions by the buyer that cause a loss are typically excluded, including the failure of the buyer to properly claim or be eligible to claim the transferred credit and the buyer’s lack of federal income tax liability to utilize the credit.

In many 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.

The value of this indemnification depends on the seller’s creditworthiness and financial condition, including existing indemnification obligations. To address this risk, buyers may require:

• A parent guarantee to backstop the seller’s obligations. If the buyer is buying the credit from a joint venture or special purpose entity owned by the project developer and a tax equity investor (as is the case in a hybrid tax transfer transaction), the parties must determine the entity that will provide this guarantee
• Tax credit insurance

In cases where tax credit insurance is procured, the indemnity can be structured in multiple ways. The seller indemnity can serve as a backstop whereby tax credit insurance will pay out first in the event of a loss, and the seller’s indemnity will make the buyer whole in case the tax credit insurance does not sufficiently cover the buyer’s loss. Alternatively, the seller may only agree to indemnify against losses that are specifically excluded by insurance. In this case, risks covered by the insurance policy will only be protected by insurance and not by the seller indemnity.

There is often a complex interplay among a seller indemnity, parent guarantee, and tax credit insurance. For example, if tax credit insurance is being procured, a seller may not be willing to provide a parent guarantee. These provisions are negotiated on a deal-by-deal basis, as some sellers procure tax credit insurance as a primary means of protecting their or their parent’s balance sheet by reducing contingent liabilities from a tax credit sale.

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Tax credit insurance

Buyers may also require tax credit insurance to ensure that they are protected in the event of an IRS recapture or disallowance of credits, and the seller does not adequately compensate the buyer. Some buyers require all transactions to carry tax credit insurance, while others only ask for tax credit insurance if the creditworthiness of the seller or guarantor is insufficient. Buyer and seller typically agree upfront on whether insurance will be procured, and the cost is typically $0.02 to $0.03 per $1.00 of tax credit.

Tax credit insurance is readily available. A pool of investment-grade insurance carriers has long insured qualification, recapture, and structure risks for tax equity financings. However, tax credit insurance can be difficult to procure or prohibitively expensive for small transaction sizes (e.g., under $3 to $5 million in transaction volume with a single sponsor) due to minimum premium requirements and fixed underwriting costs. To make insuring smaller projects more cost effective, some developers have bundled multiple smaller projects in a single tax insurance policy to benefit from economies of scale. However, it is not always possible to obtain a tax insurance policy for a portfolio of projects that will be placed in service over several months (or multiple years), which would complicate the underwriting process.

Tax credit insurance has played a significant role in the adoption of the transferability of tax credits, particularly in ITCs transactions. Typical risks covered by tax credit insurance (“Covered Tax Positions”) in a §48 credit transaction include the following:

• Eligibility of seller to claim and transfer the credit
• Placed in service date
• Bonus credit eligibility
• Compliance with prevailing wage and apprenticeship requirements
• Beginning of construction date
• Credits have not been, nor will be, subject to recapture
• Eligible cost basis of energy property (including the basis attributable to step-up transactions)

To the extent insurance is procured for other credits, Covered Tax Positions would include risks specific to that credit. For example, in a §45X transaction, a Covered Tax Position would include that the component that was produced at a particular facility is an “eligible component”, as defined in §45X, and was sold to a third party as required by §45X during a particular tax year.

Tax credit insurance policies typically have standard exclusions, including:

• Inconsistent filing positions
• Settlement with tax authority without consent of the insurer
• Material misrepresentations or inaccuracies
• Prospective changes in tax law
• Amendments from or failure to comply with relevant documents, including the tax credit transfer agreement
• Recapture caused by actions of the insured (including voluntary transfer of interests in the project in the case of §48 ITCs)

Losses arising from Covered Tax Positions include additional tax, penalties, interest, tax gross up, and contests costs, up to the policy limit of liability (although most policies include a small retention amount for contest costs only). Given that the higher limit of liability will have a higher premium, the policy limit is a negotiated amount between the tax credit seller and buyer.

Not all risks need to be covered in each transaction, so parties will need to agree on the covered tax provisions and understand the specific exclusions to each policy. For example, a buyer may want protection primarily on the stepped-up portion of credits in a §48 ITC transaction, requiring a smaller policy limit. Alternatively, a buyer might forgo tax credit insurance in certain PTC transactions in which the placed-inservice date is clear and there is little ambiguity about the eligibility of the credits being transferred.

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Tax equity

Prior to the passage of the IRA, tax equity was the only means of monetizing renewable energy tax credits for most project developers that lacked the tax liability to absorb the credits. The tax equity market has plateaued at approximately $18-20 billion in size as of 2022, the year the IRA was passed. However, the volume of tax credits generated, and hence the need for tax credit investors, is expected to grow dramatically post-IRA. Estimates from Credit Suisse suggest that the annual volume of tax credits will reach $80 billion or more by 2032.

There is now a fundamental shortage of tax equity, and transferability aims to help fill the large gap between the supply of tax equity and demand for tax credits. Below are some observations on where tax equity is headed, and how tax credit transfers will interact with the existing tax equity market.

Tax equity in the post-IRA era

Much has been written about the cost, complexity, and constraints of tax equity. That said, there are three principal benefits of tax equity in the post-IRA market.

Monetization of depreciation

In any tax equity transaction, the sponsor expects to get value from monetization of the ITC as well as accelerated depreciation. Generally, however, most near-term depreciation is allocated to the tax equity partner, so the sponsor is not able to absorb any material tax losses during the early years of the partnership. This is an important and sometimes under-appreciated point, especially in the context of step-ups and phantom income.

Flexibility for changes of control

With tax equity, a developer can divest its interest in a project without a material negative financial impact resulting from ITC recapture, because a developer typically owns only 1% of the project’s profits interest during the five-year ITC recapture period. This is important because many developers are owned by private equity or infrastructure funds, and some sponsors may plan to sell their interest within five years. Tax equity was not designed to create liquidity for project sponsors, but it has become a meaningful mechanism to support such secondary sales.

Step up to fair market value

When a project is sold by a developer to a tax equity partnership prior to mechanical completion, the purchase price is typically determined by a third-party appraiser who values the project above the developer’s cost to build. This step up allows the developer to apply the project’s ITC percentage – 30%, for instance – on a higher cost basis. For the project developer, this step up in basis does create a taxable event; if a developer builds a project for $100 and sells it to a tax equity partnership for a 30% step up to $130, the $30 of gain is taxable income.

Most tax equity deals will take on hybrid structures

We expect most tax equity deals to take on hybrid structures, whereby tax credits are sold out of tax equity partnerships. Tax equity investors will retain a portion of tax credits generated from the project and sell some or all of the remainder.

A tax equity investor’s investment appetite is limited by both its total corporate tax liability as well as the amount that has been allocated internally to renewable energy transactions. In our discussions with tax equity investors, virtually all of them have indicated that they intend to use transferability to enable a larger volume of tax equity transactions across more projects and more clients.

Reunion analysis and commentary

Tax equity has been a major source of financing for clean energy for the past 15 years and will remain an important financing tool for the foreseeable future. Tax credit transfers will increasingly be included as part of tax equity deals due to the shortage of tax equity relative to the number of tax credits being generated. In addition, standalone tax credit transfer deals that bypass tax equity all together with emerge as a new financing option, with applicability across a variety of technologies and developer profiles.

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