Transferable Tax Credits Comprehensive Guide 2026

Introduction

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. In 2025, about 8.5% of U.S. publicly traded companies disclosed tax credit purchases in corporate filings, roughly double the volume compared to 2024. Taking additional market data into account, including non-disclosed purchases, Reunion estimates that 16% to 18% of Fortune 1000 companies now have experience purchasing transferable tax credits.

The One Big Beautiful Bill Act of 2025 (OBBBA) amended the eligibility requirements and reduced the availability of many of these tax credits. Notably, for the most common tax credits, wind and solar projects under §48E and §45Y and wind components under §45X are subject to earlier tax credit phasedowns. Also, §48E, §45Y, §45X, §45U, §45Z, and §45Q tax credits are subject to new Foreign Entity of Concern (FEOC) restrictions. The OBBBA has already started impacting the wind and solar industry, and FEOC compliance has started adding a new layer of complexity as restrictions have come into force in 2026.

That said, many technologies such as battery storage, geothermal, nuclear, and advanced manufacturing will benefit from tax credit support for at least 5-10 years, and there is a strong pipeline of wind and solar projects in advanced stages of project development that will be eligible for tax credits as they are placed in service in the coming years. Tax credit transfers were not restricted in the OBBBA except that tax credits subject to FEOC rules cannot be sold to specified foreign entities (SFEs), which will not cause a significant impact.

The tax credit market has continued its momentum in 2026, with more transaction activity in the first half of 2026 compared to the first half of prior years. We expect transaction activity to continue to grow in the second half of 2026, as buyers gain clarity on their tax liability for the year. While the OBBBA has reduced tax liability for many corporate taxpayers, impacting their ability to purchase credits, we are also observing new buyers enter the market to manage their tax liabilities. The clean energy industry has been resilient across many policy changes, and we have no reason to believe that this time will be different.

Scope

This guide is primarily focused on federal tax issues and is for informational purposes only. Readers should not construe this content document or related materials as legal, tax, investment, financial, or other advice. All content in this handbook is information of a general nature and does not address the circumstances of any individual or entity.

Version 4.2 and Recent Updates

This Comprehensive Guide is a shortened version of the Transferable Tax Credit Handbook Version 4.2, which was updated in July 2026. We have updated the following content to incorporate relevant changes, though further guidance will continue to emerge.

Version 4.0 of the Reunion Transferable Tax Credit Handbook was published following the enactment of the OBBBA on July 4, 2025. 

Major changes introduced by the OBBBA include:

• Accelerated phase-down of tech-neutral (§45Y and §48E) tax credits for solar and wind
• Accelerated phase-down of advanced manufacturing production credits (§45X) credits for wind components
• Termination of the clean hydrogen production credit (§45V) for projects beginning construction after December 31, 2027
• Several tax credits were expanded or extended, including §40A credits for small agri-biodiesel producers, §45X credits for metallurgical coal producers, and §45Z credits for clean fuel producers
• Rates were adjusted for §45Z and §45Q credits for parity across types
• For §45X integrated components (where a primary eligible component is sold to an affiliate to produce a secondary eligible component), both need to be produced in the same factory and 65% of the direct material costs for the primary components must be US-made
• New FEOC restrictions for §48E, §45Y, §45X, §45U, §45Z, and §45Q credits
• Transferability is preserved, though tax credit purchasers for most credits other than legacy §45 and §48 credits cannot be specified foreign entities
• Elimination of the permanent 10% minimum ITC under §48
• Although not a transferable credit, the §25D credit for homeowners for solar, geothermal heat pumps, and batteries was eliminated for equipment placed in service after December 31, 2025
• Addition of a nuclear energy community adder to §45Y for facilities in communities that are, or previously were, employed to advance nuclear power

The OBBBA introduced several tax policies, notably bonus depreciation and R&E expensing, that will reduce the tax liability of many prospective tax credit buyers. This in turn will impact the volume of credits that these buyers can purchase. The major corporate tax changes include:

• 100% bonus depreciation: introduces option to claim 100% bonus depreciation for qualified property acquired after January 19, 2025. Bonus depreciation is also available for manufacturing and production facilities that meet certain criteria
• Full expensing of domestic research and experimental (R&E) expenditures: §174A allows full expensing of domestically sourced R&E expenditures for taxable years beginning after December 31, 2024. Foreign sourced expenditures must be capitalized and amortized over a 15-year period
• §163(j) business interest adjustment: restores the Earnings Before Interest, Taxes, Depreciation, and Amortization-based (EBITDA) calculation of adjusted taxable income for purposes of the 30% cap on business interest deduction for taxable years beginning after December 31, 2024
• Base erosion and anti-abuse tax (BEAT): increases BEAT rate from 10% to 10.5%, rather than to the previously scheduled 12.5% rate for taxable years beginning after December 31, 2025. Also allows add-back of general business credits under §38 for BEAT purposes, which had previously been scheduled to sunset (see Base erosion and anti-abuse tax section for more details)

Version 4.1 provided an incremental update to incorporate Notice 2025-42 that was published August 15, 2025 as a response to President Trump’s Executive Order 14315, directing the Treasury to issue new and revised beginning of construction guidance within 45 days of the order.

Version 4.2 provides further updates, including to incorporate Notice 2026-15 guidance on FEOC and proposed regulations for §45Z published on February 4, 2026. We have updated the document to incorporate other relevant changes as of the date of publication, though further guidance will continue to emerge.

Overview

Under §6418 of the Internal Revenue Code (IRC) (first introduced in the IRA), “eligible taxpayers” are allowed to elect to transfer (i.e., sell) certain tax credits to unrelated taxpayers for cash.

What are transferable tax credits?

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: §30C, §40A, §45, §45Q, §45U, §45V, §45X, §45Y, §45Z, §48, §48C, and §48E.

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: two major banks 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 transaction costs

Transferability negates the need for complex tax equity structures, which require a tax credit seller to negotiate and enter 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.

The 12 transferable credits

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Technical credit considerations

Who can sell 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 details on elective pay, download the full handbook.

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 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

§48 investment 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.

Passive activity loss rules

Generally, individuals, estates, trusts, closely held C-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.

Foreign entity of concern restrictions

The OBBBA introduced restrictions such that the tax credits cannot be claimed by a “prohibited foreign entity” (PFE), as defined in §7701(a)(51)(A), and cannot be transferred to a “specified foreign entity” (SFE), as defined in §7701(a)(51)(B), for many transferable tax credits starting in 2026. Therefore, the buyer cannot qualify as an SFE and the seller cannot qualify as a PFE. See the Foreign entity of concern section for more details.

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 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 that the eligible taxpayer has the specified credit portion to transfer. Relying solely on an eligible taxpayer’s representations is not sufficient for purposes of demonstrating reasonable cause. For a full list of circumstances that indicate reasonable cause, download the full handbook.

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. 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. For a full description of required minimum documentation, download the full handbook.

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. Carrying back credits requires 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. However, the carryforward is 22 years from the three-year carryback, meaning a taxpayer may effectively carry unused tax credits forward 20 years from their current tax year.

For a detailed example of how carryback sequencing works in practice, including the order of application across prior tax years, download the full handbook.

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

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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, 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

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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. The approximately 20% of corporations who are not December filers may be somewhat disadvantaged when sourcing credits, as there can be a timing disconnect between when credits are generated and when the buyer’s tax year ends.

Transfer mechanics

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

Step 1 — Negotiate tax credit transfer agreement

First, the buyer and seller should enter into a contractual agreement to transfer the credits. See the Tax credit transfer agreements section for a summary of typical negotiated terms.

Step 2 — 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.

• A tax credit seller can only submit one pre-filing registration for a given tax year. Therefore, they must apply for registration numbers for all their credits in a single filing.
• If a tax credit seller needs additional registration numbers for different facilities or properties, they must wait until the most recent pre-filing registration submission is processed by the IRS and returned.
• A tax credit seller will need one registration number per eligible credit property/facility.
• A registration number is only valid for a single tax year, so the tax credit seller will need to apply for new registration numbers each year for projects that generate credits in more than one year -- §45 PTCs, for example.

Step 3 — 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. For links to available source credit forms for each transferable tax credit, download the full handbook.

Step 4 — 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. 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. For a full list of required content in the transfer election statement, download the full handbook.

Beginning of construction

A project's beginning of construction (BoC) date is widely referenced in the statutes and related Treasury guidance governing clean energy tax credits. Notably, the BoC date determines:

• Eligibility of the project for certain tax credits / bonus credits
• Exemption from prevailing wage and apprenticeship requirements
• Exemption from FEOC restrictions

Historically, the two ways to establish BoC are by starting physical work of a significant nature, or by proving spend-to-date exceeds 5% of the total project costs (the "Five Percent Safe Harbor"). For a full guide to BoC requirements, including changes to BoC for solar and wind projects under §45Y and §48E under Notice 2025-42, visit our Comprehensive Guide to Beginning of Construction Requirements. For additional detail, download the full handbook.

Changes to BoC for solar and wind projects under §45Y and §48E

Under the OBBBA, solar and wind projects seeking §45Y or §48E credits must be placed in service before January 1, 2028, unless the projects started construction before July 5, 2026. On August 15, 2025, the Treasury updated guidance (via Notice 2025-42) for purposes of determining whether a wind or solar project has started construction under §45Y or §48E.

Under Notice 2025-42, solar projects with a maximum net output of greater than 1.5 megawatts and all wind projects must perform physical work of a significant nature to establish beginning of construction. Such projects can no longer utilize the Five Percent Safe Harbor. Other than re-stating that “there is no fixed minimum amount of work or monetary or percentage threshold required,” Treasury did not draw clear lines on what is required to meet the standard of performing physical work of a significant nature. Financing and insurance markets will need to determine where they are comfortable drawing the lines.

Certain projects can continue to use the old BoC rules, including projects that were able to establish BoC before September 2, 2025, and solar projects with a maximum net output of 1.5 MW or less.

The BoC guidance in Notice 2025-42 only pertains to tax credit qualification for wind and solar projects under §45Y and §48E. Further guidance on FEOC BoC provisions is still being drafted by Treasury.

Corporate alternative minimum tax (CAMT)

Created by the IRA, the corporate alternative minimum tax (CAMT) seeks to place a 15% “floor” under corporate taxpayers. CAMT applies to corporations exclusive of S-corporations, regulated investment companies, and real estate investment trusts, that have an adjusted financial statement income (AFSI) greater than $1 billion (for corporations with a U.S. parent) or $100 million (for U.S. corporations that are subsidiaries of a multinational group with a foreign parent that has an AFSI greater than $1 billion) over any consecutive three-year period.

CAMT is determined by calculating a minimum tax equal to 15% of the 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 on taxable income that exceeds 15% may still be subject to CAMT liability.

The calculation of AFSI includes several adjustments to a corporation’s financial statement income. However, those adjustments do not include any reductions in relation to general business tax credits, including the §45 PTCs, §48 ITCs, §45X AMPCs, and any other energy tax credits.

On September 13, 2024, after a series of interim guidance, the IRS published proposed regulations for the CAMT, including rules related to the calculation of AFSI. The supplementary background to the proposed regulations explains that these rules are generally intended to be consistent with tax treatment of transferred credits under §6418. Under the proposed regulations, income received by the seller as payment for transferred energy tax credits, which is typically not included in the gross income of the seller, is also not included in the calculation of the seller’s AFSI. For a tax credit buyer, any amounts paid by the buyer to the seller for the transferred credits are disregarded for purposes of calculating AFSI (in other words, cash payments for credits do not reduce AFSI). At the same time, AFSI is also adjusted to disregard any increase in a tax credit buyer’s financial statement income resulting from utilizing the credits, such as in a case where a tax credit buyer pays less than the face value of the credits (in other words, receiving a discount on the face value of the credits is not treated as income and does not increase AFSI). The proposed regulations also note that AFSI is adjusted to disregard any decrease in a taxpayer’s financial statement income resulting from increased taxes owed due to recapture of a tax credit.

As a result of the above rules, tax credit buyers potentially subject to the CAMT must evaluate the extent to which energy tax credits can offset their tax liability. Since such credits reduce a corporation’s regular tax liability but do not reduce AFSI and the corporation’s CAMT minimum, purchasing tax credits could trigger the CAMT to apply and may not reduce a buyer’s tax liability by an amount equivalent to the face value of the credits.

On February 18, 2026, the IRS released additional CAMT guidance that allowed for additional taxpayer favorable adjustments to AFSI. At the same time, Treasury and the IRS announced their intent to “re-propose” the entire CAMT framework. There is no timeline for forthcoming guidance. For more detail on CAMT credit carryforwards and their interaction with BEAT, download the full handbook.

OECD Pillar Two

OECD Pillar Two is a legal framework designed to combat tax avoidance by establishing a global minimum tax rate of 15% for large multinational enterprises (MNEs) with annual revenues above €750 million. Over 140 countries have agreed to the framework, though formal adoption requires local legislation.

Upon taking office on January 20, 2025, President Trump issued an Executive Order directing Treasury to notify the OECD that any commitments made under the Biden administration with respect to OECD Pillar Two will no longer have effect within the U.S. absent an act of Congress. On January 5, 2026, Treasury announced that it had reached a “side-by-side” agreement with 145 countries in the OECD/G20 Inclusive Framework to exempt U.S. headquartered companies from Pillar Two and ensure U.S. companies remain subject only to U.S. global minimum taxes. As of January 5, 2026, the U.S. was the only country formally identified by the OECD as meeting the criteria for the safe harbor, effectively making companies with an ultimate parent in the U.S. exempt from Pillar Two rules.

Earlier OECD guidance from July 2023 clarified that IRA tax credits will receive the same favorable treatment as refundable tax credits. Tax credits are treated as non-marketable 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. For the seller, the proceeds from the sale of tax credits are treated as additional income, rather than a reduction of taxes.

For a full breakdown of the three Pillar Two collection mechanisms (QDMTT, IIR, and UTPR) and how each operates, download the full handbook.

Base erosion and anti-abuse tax (BEAT)

Created under the 2017 Tax Cuts and Jobs Act, the base erosion and anti-abuse tax (BEAT) is intended to prevent large multinational corporations from eroding their U.S. tax base by shifting profits to affiliates in foreign jurisdictions. BEAT applies to corporations with average annual gross receipts of at least $500 million over the prior three years and where at least 3% (or 2% for taxpayers in affiliated groups including banks and registered securities dealers) of total tax deductions come from payments to foreign affiliates.

BEAT functions as a minimum tax: if a corporation’s adjusted tax liability is less than its BEAT minimum, the corporation must pay a top-up tax equal to the difference. The BEAT minimum is calculated by adding back deductions due to payments to foreign affiliates to the corporation’s regular taxable income and applying a 10.5% BEAT tax rate. The OBBBA made this rate permanent for tax years beginning after December 31, 2025.

However, under the current statute, only certain energy tax credits, namely legacy §45 and legacy §48 credits, can be added back when calculating adjusted tax liability. These credits are therefore treated favorably under BEAT and are of higher value to buyers facing BEAT than other energy credits, such as those under §45Y, §48E, §45Q, and §45Z, which cannot be added back. 

For the full adjusted tax liability calculation under BEAT, including the 80% credit add-back formula, download the full handbook. 

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The most common credits: eligibility, risks, and due diligence

§48 and §48E ITCs

Eligibility and dates (§48)

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Eligibility and dates (§48E)

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Rates

Assuming Prevailing Wage and Apprenticeship requirements are met, the §48 and §48E ITCs are worth 30% of a project’s qualified basis. Otherwise, the credit is reduced to 6%. Projects qualifying for the energy community or domestic content bonus each receive an additional 10% of qualified basis (or 2% without PWA). The bonus adders can be stacked, meaning that a project that meets PWA requirements and qualifies for both adders would have an ITC value worth 50% of a project’s qualified basis. Projects qualifying for the low-income community bonus receive an additional 10% or 20% of the project’s qualified basis; the bonus is limited to projects of 5 MW or less and is an allocated credit.

For a full breakdown of ITC values under all stacked bonus adder combinations, download the full handbook.

Risks

Qualification

Buyers will need to ensure that tax credits qualify for the §48 or §48E 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) or a qualified facility or energy storage technology (as defined in §48E), the proper cost basis is used, the project was placed in service in the appropriate tax year, and that FEOC restrictions are considered (if applicable).

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 and §48E are subject to the recapture provisions of §50. 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. Recapture can occur if the property ceases to be a qualified energy facility or if there is a change in ownership of the property. 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. For full details on recapture scenarios, download the full handbook.

At-risk rules of §49

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 §48 ITCs 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).

Foreign entity of concern

For §48E tax credits, strict rules around FEOC were added in the OBBBA. There is also a ten-year recapture period for §48E investment tax credits if some of these rules are not adhered to accurately. For the avoidance of doubt, §48 tax credits are exempt from this provision. See the Foreign entity of concern section for further details.

Due diligence

§48 and §48E ITCs generally carry a larger discount compared to §45 or §45Y 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 §48) or a qualified facility or energy storage technology (as defined in §48E), 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.

For the full recapture due diligence checklist, including specific seller documentation requirements for P&C insurance, site control, interconnection rights, and lender forbearance, download the full handbook.

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, or a qualified facility or energy storage technology as defined in §48E.

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 additionally want to diligence the transaction that effectuates the step-up and analyze the stepped-up valuation. An appraisal from a qualified third-party firm is typically required to substantiate fair market value. Reunion generally believes that larger step-ups will be subject to increased scrutiny by the IRS. For full detail on basis step-up structures, download the full handbook.

Recapture: continuation as a qualified facility

The IRS may recapture the credit if a property ceases to be a qualified energy facility during the first five years of operation. To protect against this risk, buyers should ensure the seller has sufficient property and casualty insurance coverage, adequate site control, and adequate interconnection rights. The seller should also demonstrate that they have alternatives in the event of primary offtaker default.

Recapture: 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 detailed information about the project’s ownership structure, and confirmation that financing parties do not have collateral interests that could cause recapture in the event of a default. If project-level debt is present, a forbearance agreement is often negotiated such that lenders agree not to foreclose on project assets or undertake any other actions during the first five years of operation that would cause a recapture.

Recapture: FEOC restrictions (beginning in 2028)

Added in the OBBBA, the IRS may recapture §48E credits any time in the ten years after the qualified facility is placed in service if the taxpayer makes certain payments to a specified foreign entity as further detailed in the Foreign entity of concern section. Only qualified facilities placed in service during and after 2028 are subject to FEOC 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. For a description of the five-factor test used to determine placed-in-service date, download the full handbook.

§45 and §45Y PTCs

Eligibility and dates (§45)

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Eligibility and dates (§45Y)

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One important distinction between §45 and §45Y: in the case of §45 credits, the taxpayer must own the qualified facility and sell the electricity produced there to an unrelated person. For §45Y credits, the taxpayer must either (i) own the facility and sell the electricity produced there to an unrelated person; or (i) own the facility, (ii) equip the facility with a metering device that is owned and operated by an unrelated person and (iii) sell, consume or store the electricity. There is not a requirement to sell electricity to claim §45Y credits, as long as the metering device is owned and operated by an unrelated person.

Rates

The IRS updates §45 and §45Y PTC rates on an annual basis, generally in Q2. Rates are determined using an inflation adjustment factor and published in the Federal Register. The inflation adjustment factor for §45Y for 2025 is 1.9971. The inflation adjustment factor for §45 for 2026 is 2.0570.

The §45Y PTC has one base rate, irrespective of when a qualifying project is placed in service. The base rate is $3 per megawatt-hour (MWh) of qualifying electricity produced and sold. With PWA compliance (or exemption), the rate increases to $15 per MWh. There is also an annual, calendar year inflation adjustment for the rates, in which the rates are multiplied by the inflation adjustment factor described above and rounded. The $3 base rate is rounded to the nearest multiple of $0.50, and the $15 PWA rate is rounded to the nearest multiple of $1. As such, using the 2025 inflation adjustment factor of 1.9971, the 2025 §45Y base rate and PWA rate (after rounding) is $6 and $30 per MWh of qualifying electricity produced and sold, respectively.

The §45 PTC has two different rates depending on whether a project was placed in service before January 1, 2022, or not. Projects qualifying for the energy community or domestic content bonus each receive a 10% PTC value increase if PWA requirements are met. Wind facilities placed in service before January 1, 2022 may be subject to reduced PTC rates depending on when construction began. For full details on all of the above, download the full handbook.

Risks

Qualification

To qualify for a §45 or §45Y 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 sell such electricity to an unrelated person during the taxable year.

Because PTCs are 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.

PTCs from projects placed in service prior to 2023 can still be transferred under §6418 if the credits were generated during a tax year beginning after December 31, 2022. Unlike ITCs, §45 and §45Y PTCs are not subject to recapture risk. Facilities that have undergone a repower may be treated as newly placed in service and qualify for another ten years of PTCs, provided the fair market value of the used property does not exceed 20% of the facility’s total value.

Foreign entity of concern

For §45Y PTCs, strict rules around FEOC were added in the OBBBA. For the avoidance of doubt, legacy §45 tax credits are exempt from this provision. See Foreign entity of concern section for further details.

Due diligence

The PTC is based on the amount of electricity the qualifying project produces and sells to a third-party 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 third-party 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.

For more detail on production risk mitigation strategies including conservative estimate structures, liquidated damages provisions, and make-whole arrangements, download the full handbook.

§45X AMPCs

Eligibility and dates

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For credit rates by component type, download the full handbook.

Risks

Qualification

While §45X AMPCs are not subject to PWA requirements and do not carry the same recapture risks as §48 and §48E ITCs, they do carry additional qualification risks that are absent from other power generation-related tax credits such as the §45 and §45Y PTCs. Components may be required to meet certain administrative or technological specifications to qualify as an eligible component that gives rise to a tax credit.

Foreign Entity of Concern

For §45X tax credits, strict rules around foreign entities of concern are required for any taxpayer to claim the credit for tax years beginning January 1, 2026. See the Foreign entity of concern section for further details.

Due diligence

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

• Confirm correct credit amount and technical qualification: The production of eligible components must be completed in 2023 or later. The tax year where credits may be claimed is driven by the year in which the sale is completed. §45X provides a list of eligible components, their associated AMPC amount, and any design parameters / capacity limits that are required to qualify for credits.
• 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. Parties to a contract manufacturing arrangement may choose who claims the credit through a signed agreement prior to the completion of eligible components.
• Validate domestic production: Only eligible components produced in the U.S. and its territories are eligible for a tax credit.
• 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.
• Validate third-party sale for productive purposes: §45X tax credits are only generated upon the sale of eligible components to a third party. In an instance where an eligible component is sold to an affiliate to produce another eligible component, these “integrated components” may still qualify given (a) both components are produced in the same factory, (b) the secondary component is sold to an unrelated person, and (c) at least 65% of the direct material costs to produce the secondary components are attributable to primary components mined, produced or manufactured in the United States.
• Comply with FEOC restrictions: See Foreign entity of concern section.

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.

§45U PTCs

Eligibility and dates

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Rates

The IRS updates §45U PTC rates on an annual basis, generally in Q2. The inflation adjustment factor for 2025 is 1.0242, producing a 2025 base rate of $3 per MWh. The base rate is then further reduced by a “reduction amount,” which is calculated based on “gross receipts” earned by the project during the taxable year. The adjusted PTC rate is multiplied by five if the project complies with prevailing wage (PW) requirements during alteration or repair of the project. For the full reduction amount formula and calculation methodology, download the full handbook.

Risks

Qualification

To qualify for a §45U PTC, a project owner needs to generate electricity from a qualified nuclear power facility in the United States and sell such electricity to an unrelated person during the taxable year. Because PTCs are tied to production, the primary risk is accurate production accounting. Unlike ITCs, §45U PTCs are not subject to recapture risk. A buyer of §45U PTCs should ensure that the facility was placed in service prior to August 16, 2022 and has a reactor design that was approved by the U.S. Nuclear Regulatory Commission on or before December 31, 1993.

Foreign entity of concern

For §45U PTCs, strict rules around FEOC were added in the OBBBA. See Foreign entity of concern section for further details.

Due diligence

The §45U PTC is based on the amount of electricity the qualifying nuclear project produces and sells to a third-party, reduced by the reduction amount calculated based on gross receipts. Buyers should receive from the seller:

• Evidence that the project was placed in service prior to August 16, 2022 and has a reactor design that was approved by the U.S. Nuclear Regulatory Commission (NRC) on or before December 31, 1993
• A production report from the project's revenue-grade meter or other third-party substantiation (such as settlement statements from the grid operator)
• Confirmation of the electricity purchase by an unrelated third party
• Verification of any other revenues received by the facility that would be included in the calculation of gross receipts

Buyers should also ensure that any other revenues received by the facility that would qualify as gross receipts are disclosed by the seller and verified, as these revenues can reduce the amount of the §45U PTCs. For full details on §45U due diligence considerations, download the full handbook.

§45Z PTCs

Eligibility and dates

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Rates

The §45Z credit is calculated as the product of the applicable amount per gallon (or gallon equivalent) of transportation fuel and the emissions factor of such fuel. For fuel produced in 2025, the applicable amount is $0.20/gallon for non-aviation fuel and $0.35/gallon for aviation fuel. For fuel produced in 2026-2029, the applicable amount is $0.20/gallon for both. With PWA compliance, the applicable amount increases by a factor of five. Using the 2025 inflation adjustment factor of 1.0611, the 2025 §45Z applicable amount for fuel produced by a facility that complies with PWA requirements is $1.06/gallon for non-aviation fuel and $1.86/gallon for aviation fuel. For full detail on the emissions factor calculation and GREET/CORSIA methodology, download the full handbook.

Risks

Qualification

To qualify for a §45Z PTC, a taxpayer must be registered as a producer of clean fuel under §4101 at the time of production. The fuel must be suitable for use as a fuel in a highway vehicle or aircraft. However, actual use as a fuel in a highway vehicle or aircraft is not required. Fuel produced after December 31, 2025, must be exclusively derived from a feedstock that was produced or grown in the United States, Mexico, or Canada.

The §45Z PTC is generated upon a “qualified sale,” in which the fuel is sold by the taxpayer to an unrelated person for use in the production of a fuel mixture, in a trade or business, or at retail. Sales of fuel to intermediaries or resellers constitute qualified sales.

The credit has anti-stacking provisions: a facility claiming the §45Z credit cannot also claim a credit under §45V or §45Q in the same taxable year. A §48(a)(15) election permanently disqualifies the facility from claiming the §45Z credit in the election year and all subsequent years.

Foreign entity of concern

For §45Z PTCs, strict rules around FEOC were added in the OBBBA. See Foreign entity of concern section for further details.

Due diligence

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

• Confirm producer registration: A taxpayer must be registered as a producer of clean fuel under §4101 at the time of production. Evidence of IRS approval confirming the effective date of registration and the registration number is recommended.
• Feedstock: Fuel produced after December 31, 2025, must be exclusively derived from a feedstock that was produced or grown in the United States, Mexico, or Canada.
• Suitable for use: A fuel must be suitable for use as a fuel in a highway vehicle or aircraft. The fuel must also meet any required ASTM or SAE specifications.
• Emissions rate: A third-party consultant is typically engaged to verify that the emissions rate has been calculated correctly under the 45ZCF-GREET model or the CORSIA methodologies.
• Qualified sale: The fuel must be sold in a qualified sale as defined under the Code and the proposed regulations.
• Anti-stacking: A taxpayer must confirm no tax credits will be claimed with respect to the facility under §45V, §45Q, or §48(a)(15) for any applicable year in which the owner of the facility claims the §45Z credit.

For full details on §45Z due diligence considerations, download the full handbook.

Due diligence considerations for all common credits

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

For the full corporate structure diligence checklist and guidance on pre-filing registration timing risk, download the full handbook.

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. Commonly reviewed corporate documentation includes articles of organization, operating agreements, corporate by-laws, organization charts, taxpayer identification numbers, certificates of good standing, and 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.

Pre-filing registration

The buyer should review IRS pre-filing documentation and registration number(s) provided by the seller. 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. 

Prevailing wage and apprenticeship requirements

The IRA aims to create a robust market for well-paying 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 12 tax credits eligible for transfer, only the §45X and §40A credits are not subject to PWA requirements (note §45U credits are subject to prevailing wage, but not apprenticeship requirements).

The IRS and Treasury published final PWA regulations on June 18, 2024 which went into effect on August 26, 2024. For a full guide to PWA compliance, visit our Comprehensive Guide to Complying with Prevailing Wage and Apprenticeship Requirements. For additional detail, download the full handbook.

Foreign entity of concern

The OBBBA added new "Foreign Entities of Concern (FEOC)" restrictions, primarily intended to prevent Chinese companies from benefitting from tax credits, and to reduce reliance on China for clean energy technology. FEOC restrictions apply to entities connected to China, Russia, North Korea, and Iran, and prohibit them from claiming §48E, §45Y, §45X, §45U, §45Z, and §45Q tax credits, either directly or indirectly.

FEOC restrictions are broadly divided into two sets of rules:

1. Taxpayer-level restrictions: the taxpayer claiming §48E, §45Y, §45X, §45U, §45Z, and §45Q tax credits may not be a specified foreign entity (SFE) or foreign-influenced entity (FIE), and the tax credit may not be transferred to a SFE or FIE, depending on the applicable credit type and tax year. For §48E, §45Y, §45X credits, taxpayers may not give "effective control" to a specified foreign entity (SFE) through a binding contract or licensing agreement.
2. Project-level restrictions: the taxpayer claiming §48E, §45Y, and §45X tax credits may not receive "material assistance" from a prohibited foreign entity (PFE) through use of manufactured products or eligible components.

FEOC restrictions take effect in tax years beginning after the OBBBA date of enactment: July 4, 2025. Projects claiming legacy §45 or §48 credits are not subject to any of the FEOC restrictions. §45Y and §48E projects that start construction for tax purposes before January 1, 2026 are not subject to project-level material assistance requirements (but are subject to the taxpayer-level restrictions beginning in the taxpayer's first taxable year after enactment of the OBBBA).

Buyers, sellers, and suppliers will need to perform careful due diligence to ensure FEOC compliance. For a full guide to FEOC compliance, visit our Comprehensive Guide to Prohibited Foreign Entities for Clean Energy Tax Credits. For additional detail, download the full handbook.

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 bonus credit

Eligibility

To qualify for the energy community bonus as a project claiming investment and production tax credits under the §45, §45Y, §48, and §48E, 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%.

The OBBBA adds an energy community bonus for §45Y nuclear facilities that are located in metropolitan statistical areas that are, or have previously been, nuclear communities (see Nuclear facility section below).

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. 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.

Nameplate capacity and footprint tests

A project qualifies for the energy community bonus if at least half (50%) of its nameplate capacity is in an energy community. If a clean energy facility does not have a nameplate capacity, it can qualify under the “footprint test” if 50% or more of the project’s square footage is located in an energy community.

Brownfield

A brownfield site is 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 (as defined in CERCLA). Three types of sites qualify as a brownfield under a safe harbor: existing brownfields tracked by a federal, state, or tribal brownfields program; sites where a Phase II assessment confirms the presence of a hazardous substance; and, for projects not greater than 5 MWac, sites where a Phase I assessment identifies the presence or potential presence of a hazardous substance. For full detail on each brownfield type, download the full handbook.

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 an unemployment rate at or above the national average unemployment rate for the previous year. The statistical area category is determined annually.

For the full text of the statistical area eligibility criteria and annual re-testing mechanism, download the full handbook.

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.

Nuclear facility

As added in the OBBBA, a new 10% energy community bonus is available for advanced nuclear facilities, or any nuclear facility that the Nuclear Regulatory Commission (NRC) has authorized to construct and issued a site-specific construction permit or combined license, claiming §45Y tax credits that are situated in a metropolitan statistical area where at least 0.17% of the community is (or has been at some time since December 31, 2009) employed directly by the advancement of nuclear activity.

Due diligence considerations

The energy community bonus is relatively straightforward to substantiate (other than qualification as a brownfield which can be more subjective). A developer should provide documentation that crosswalks their project’s location with at least one of the three energy community categories. The IRS created a safe harbor such that if the project is in an energy community as of the beginning of construction date, the location will continue to be considered an energy community for the duration of the credit period.

Nameplate capacity attribution rule

Notice 2024-30 expanded the nameplate capacity attribution rule to help offshore wind projects qualify for the energy community bonus. The rule allows developers to allocate offshore nameplate capacity onshore for purposes of qualifying for the energy community bonus, and was expanded to include not only power-conditioning equipment but also supervisory control and data acquisition (SCADA) equipment located in an “energy community project port.” For full detail on port qualification requirements, download the full handbook.

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
• April 4, 2023: IRS Notice 2023-29
• April 7, 2023: IRS Notice 2023-45
• June 15, 2023: IRS Notice 2023-47
• March 22, 2024: IRS Notice 2024-30
• June 9, 2024: IRS Notice 2024-48
• June 23, 2025: IRS Notice 2025-31
• July 4, 2025: One Big Beautiful Bill Act, Chapter 5.

Resources

• The Department of Energy (DOE) maintains an energy community map
• The Environmental Protection Agency (EPA) maintains a cleanups in my community map, which shows federally recognized brownfields
• The IRS maintains an FAQ

Domestic content bonus credit

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 dependent on when the project begins construction, as amended in the OBBBA and effective on or after June 16, 2025:

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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 safe harbor” in IRS Notice 2024-41 for purposes of calculating the domestic content percentage. The new elective safe harbor allows developers to elect 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. IRS Notice 2025-08 modified Notice 2024-41 to adjust the percentages in the “First Updated Elective Safe Harbor.”

Note, 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.

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. For the full list of required certification information and recordkeeping requirements, download the full handbook.

Due diligence considerations

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
• May 16, 2024: IRS Notice 2024-41
• January 16, 2025: IRS Notice 2025-08

Low-income community bonus credit

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 2026 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.

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For program years starting in 2025, the low-income community bonus credit is available for §48E credits under §48E(h). Revenue Procedure 2025-11 outlines the process to apply for the low-income community bonus credit under §48E for 2025 and subsequent program years.

How to apply and key restrictions

Since the low-income bonus is an allocated bonus, developers must apply for and receive an allocation from the IRS. Applications submitted within 30 days of the program start date will be treated as submitted on the same date. At the beginning of the application period, 50% of the total capacity allocation in a given category or subcategory is reserved for facilities meeting certain ownership criteria (e.g., Indian tribal enterprises, Alaska Native Corporations, certain tax-exempt entities) or geographic criteria (persistent poverty counties or CEJST-designated tracts).

Once a developer has an allocation, they have four years to place the project in service and cannot change the project’s location. Developers cannot place a project in service before receiving an allocation. Extensions to the four-year deadline are not permitted. For full details on the application process, restrictions, disqualification conditions, successor-in-interest changes, and documentation requirements, download the full handbook.

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. For full documentation requirements, download the full handbook.

Guidance

• September 3, 2024: Notice of Proposed Rulemaking
• January 13, 2025: Final Regulations
• January 8, 2025: Revenue Procedure 2025-11

Resources

• The Department of Energy (DOE) maintains a clean electricity low-income communities bonus credit amount program website and application portal
• Applicant checklist
• Applicant user guide (program years starting in 2025)
• Successor-in-interest allocation transfer request guide
• Category 1 eligibility map with CEJST and persistent poverty county screens 

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Pricing and cashflow timing

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 arranges the transaction. Certain intermediaries such as Reunion also provide 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 and has risen in the past year, but typically costs three to five cents per $1.00 of tax credit
• Legal and/or third-party due diligence fee: 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 almost universally request a capped level of reimbursement from the seller for all or a portion of these professional services expenses.

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

Latest tax credit pricing

For an up-to-date view of pricing, please visit Reunion’s Market Monitor, a comprehensive pricing and markets dashboard. We also have an overview on pricing in our Transferable Tax Credit Handbook.

Key pricing factors

Through 2025 and into 2026, Reunion has observed credits trading in relatively narrow pricing bands by credit and counterparty. Several factors drive both the pricing bands, and where pricing falls within a given price band:

Risk and complexity

The more risk a project carries, the higher the discount. ITCs tend to be more complex than PTCs due to cost basis risk and recapture risk, and therefore tend to trade at a larger discount. Long-standing technologies such as wind, solar, and battery storage have the largest pool of buyers and tend to carry smaller discounts compared to less mature technologies.

Project size

Smaller tax credit amounts – for example, below $5 or $10M – may offer a larger discount to face value due to the need for the buyer to achieve sufficient savings. Larger projects often trade at a smaller discount, given demand from buyers that want to buy a large volume of credits from one seller.

Forward and multi-year commitments

Most tax credit buyers are looking to buy credits for the current tax year. Buyers that are willing to commit to credits for the subsequent tax year, or that are willing to commit to multi-year streams of credits can often get a larger discount.

Premiums for efficient transactions

Speed of transaction execution is also a key factor in pricing. Buyers that provide a strong early offer to a seller (or that happen to catch a seller when they are up against a tight deadline to sell credits) may be able to circumvent a competitive process and get advantageous pricing as a result.

Cashflow timing

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

• Maximize the dollar amount of tax savings
• Minimize risk and complexity by 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. Corporate taxpayers can offset their quarterly estimated tax payments using tax credits they intend to purchase. 

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. 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 with fewer competing buyers.

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. For detailed worked examples with specific dollar amounts illustrating each cashflow structure, download the full handbook.

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

Production-based tax credits are typically paid quarterly in arrears. A buyer commits to purchasing credits in advance, reduces their quarterly estimated tax payments accordingly, and pays the seller a discounted amount on each estimated tax payment date. This structure creates a positive cash flow with no upfront cost.

Purchase a §48 ITC portfolio and pay quarterly in arrears

A portfolio of investment tax credits can be structured similarly, paid quarterly in arrears as credits are generated throughout the year. Since credit generation may be uneven throughout the year, this can result in the buyer reducing their tax payments by a larger amount than they are paying out in the early quarters, creating a strong cash flow benefit.

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

A buyer can commit to purchasing ITCs that a developer will generate later in the year and use the commitment to offset quarterly estimated tax payments before any cash is disbursed to the seller. This structure carries the risk that the project may not be placed in service in the anticipated tax year, requiring the buyer to find replacement credits. Buyers can mitigate this risk by negotiating liquidated damages with the seller.

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

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. This allows them to fully offset their remaining taxes due with a single discounted payment to the seller.

For detailed worked examples with specific dollar amounts illustrating each cashflow structure, download the full handbook.

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.

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, the parties may negotiate pricing specific to each credit year
• Under-delivery liquidated damages: To the extent the seller does not generate a minimum amount of credits to sell to the buyer during a tax year, the parties may negotiate certain liquidated damages to compensate the buyer
• 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
• 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; 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.

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. The closing conditions validate that the credits have been generated and can be transferred as contractually envisioned. 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. For the full list of common closing conditions, download the full handbook.

Covenants

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.

Post-closing covenants

Post-closing covenants require the parties to file their tax returns and properly reflect the tax credit transfer. For §48 and §48E ITCs, the seller agrees to not take any action that would lead to recapture and to notify the buyer if there has been a recapture event. During the recapture period, the seller is required to meet the prevailing wage and apprenticeship requirements for any alterations or repairs on the project.

In any tax credit transaction, the risk of loss often manifests itself in the form of an IRS audit. Typically, tax contest language in the TCTA reflects a risk-sharing agreement: the buyer controls any proceedings with the IRS, with the right of the seller to be informed and the right to participate. Often the buyer contractually agrees to not settle or resolve any dispute with the IRS without the seller’s consent.

Indemnification

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 payable to the IRS.

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. Key commercial negotiations include whether the indemnity is capped and whether it is triggered on a no-fault or breach-based basis.

The value of this indemnification depends on the seller’s creditworthiness and financial condition. To address this risk, buyers may require a parent guarantee to backstop the seller’s obligations or tax credit insurance. In cases where tax credit insurance is procured, the indemnity is often structured 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.

Guarantor

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 (audited if available) 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.

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. Buyer and seller typically agree upfront on whether insurance will be procured, and the cost is typically $0.03 to $0.05 per $1.00 of tax credit. This is an increase from the $0.02 to $0.03 price range we saw in 2024 and early 2025.

Tax credit insurance is readily available. 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.

Typical risks covered by tax credit insurance (“Covered Tax Positions”) in a §48 credit transaction include 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, and eligible cost basis of energy property (including the basis attributable to step-up transactions). For the full list of standard covered positions and exclusions, download the full handbook.

Termination

For any TCTA that is structured with a non-simultaneous signing and close, a termination provision is often 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.

Working with Reunion

Who we are

Reunion works with leading corporations to identify and purchase high-quality tax credits from clean energy projects. Our team supports every step of the transaction, with a focus on due diligence and risk management.

Reunion was founded in 2022 following the passage of the IRA and is now the leading platform for clean energy tax credits and compliance. Since 2024, we have led more than $8 billion in transactions, including several of the industry’s largest and most complex transfers and multiple deals above $1 billion in volume.

In early 2025, we also launched a Prevailing Wage and Apprenticeship Compliance software product, which significantly reduces the time and expense of complying with PWA requirements and generates a standardized report for due diligence purposes. In 2026, we are launching a similar product to address Foreign Entity of Concern compliance.

Fortune 500 corporations and leading energy companies partner with Reunion for four reasons:

Access to a walled garden of vetted credits

Reunion canvasses the market widely to source the highest-quality, highest-value credits. Our track record with a broad network of sellers gives buyers access to off-market opportunities they may not find elsewhere.

Securing ideal tax credits

Reunion curates credit opportunities that fit each buyer’s specialized needs for pricing, timing, and risk. We help buyers understand market dynamics and win favorable terms, drawing on our proprietary database of tax credit transactions and our team’s extensive transaction experience.

Hands-on deal guidance

Reunion quarterbacks the deal, providing skilled mediation through a transparent negotiation process. We deliver a comprehensive diligence memo, an offering used by Fortune 100 tax teams for internal approvals, within 10 days of term sheet execution so that key issues surface early.

In-depth risk management

Reunion examines deal structure and transaction documents closely to manage risk and secure favorable contractual terms. We prepare detailed, organized documentation to defend the credit in the event of an IRS audit.

The process from the buyers’ perspective

Although every transaction is unique, Reunion generally supports buyers across the full acquisition lifecycle through the Reunion Transaction Process (RTP). The RTP has been tested across more than $8 billion in transactions and drives term sheets to close with an average timeline of 45 days, with a success rate above 95%.

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Step 1: Understand buyer requirements

Key deliverable(s): NDA, investment presentation/parameters

Reunion begins by understanding each buyer’s specifications for pricing, timing, risk, and credit type. Reunion often helps prepare a presentation for internal stakeholders or investment committees, covering pricing, payment timing, due diligence, and risk mitigation.

Step 2: Curate opportunities

Key deliverable(s): Tax credit recommendations

Once a buyer has internal buy-in, Reunion curates opportunities that match its risk, pricing, and timing preferences, typically presenting three to six at a time with a clear explanation of how each meets the buyer’s goals.

Step 3: Sign term sheet

Key deliverable(s): Term sheet

Reunion assists in formally expressing interest through a term sheet, driving alignment on terms including price, payment timing, fee reimbursement, tax proceedings, indemnification, and tax credit insurance. An executed term sheet begins an exclusivity period, typically 30 to 45 days.

Step 4: Perform upfront diligence

Key deliverable(s): Due diligence memo

Shortly after executing a term sheet (typically within 10 days), Reunion delivers an initial diligence memo so the buyer understands potential risks early, before spending significant time and expense. A sample of Reunion’s diligence checklist is available on our website (§45 checklist, §45X checklist, §48 checklist).

Step 5: Collect supporting documentation

Key deliverable(s): Data room

In parallel, Reunion works closely with the seller to assemble and organize a thorough due diligence data room. This often takes several iterations to ensure the documentation satisfies the buyer and gives confidence in the event of a future IRS challenge.

Step 6: Negotiate final contracts

Key deliverable(s): Tax credit transfer agreement, tax credit insurance policy

Reunion regularly takes transactions from term sheet to close in under 45 days. Through skilled mediation and extensive transaction experience, we focus buyers and sellers on the most important areas of negotiation, bringing market data to establish what terms are market.

In deals involving tax credit insurance, Reunion helps the buyer understand coverage and validates that the policy is properly sized in the event of a claim.

Step 7: Post-closing

Key deliverable(s): Ongoing reminders (e.g., tax filing requirements and deadlines)

Reunion stays in close contact with buyer and seller after closing, ensuring post-closing covenants are completed and providing reminders for relevant IRS filings. Reunion also helps the buyer stay current with market trends and provides early access to new deals coming to market.

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This guide will be updated periodically to reflect new versions of the Reunion Transferable Tax Credit Handbook; readers are encouraged to download the latest version of the handbook for the most current guidance.