Understanding transferable tax credit carrybacks and carryforwards

Reunion recently released our Q3 Market Monitor update, including forward-looking pricing estimates through Q4 of this year. 

Overall, our data highlights two seemingly divergent trends: (1) softened demand for 2025 tax credits alongside (2) increased market maturity and liquidity.

To better understand this dynamic, this note examines six key trends from our data:

• Pricing: 2025 tax credit prices have declined compared to 2024 levels, primarily due to the OBBBA
• Market dynamics: Sections 45U and 45Z are becoming increasingly popular production credits
• Transaction timing: 10% of 2024 tax credit transfers closed in Q3 2025
• Prevailing wage and apprenticeship (“PWA”): Credits that are PWA exempt because of beginning of construction (“BoC”) exemption are vanishingly rare
• FEOC: FEOC will become a key purchase consideration, with upward pricing for credits with low FEOC risk
• Credit adders: Adoption of bonus credit adders continues to expand for ITCs, but remains muted for PTCs

Pricing

2025 tax credit prices have declined compared to 2024 levels

Across virtually all credit types and deal sizes, 2025 pricing declined relative to 2024 levels. This trend has been particularly pronounced in Q3 and Q4. In 2024, prices rose from Q3 to Q4 as buyers competed for increasingly limited supply. In 2025, the trend reversed, with pricing generally softening over the same period.

Investment-grade (“IG”) supply continues to command a premium – ITCs from IG sellers, for example, continued to trade one to three cents above these median levels in late 2025.

*Section 48 ITC pricing is exclusive of residential solar and biogas. Reunion maintains separate pricing series for these technologies.

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The following chart compares estimated Q4 2025 to actual Q4 2024 data. This year’s Q4 data is based on deals closed through November and terms sheets executed through the publication date of this note.

*Section 48 ITC pricing is exclusive of residential solar and biogas. Reunion maintains separate pricing series for these technologies.

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Residential, or “resi,” solar experienced marked price declines throughout 2025 as well. (Reunion maintains separate pricing series for ITCs from resi solar and biogas. We do not include resi and biogas deals in our market-wide Section 48 ITC pricing above.) Looking across 2024 and 2025 vintages, median prices fell from $0.928 in Q3 2024 to an estimated $0.88 in Q4 2025.

When understanding resi prices, it's important to recall that buyers and sellers often negotiate the limit of liability ("LOL") on resi tax credit insurance policies, which flows through to headline pricing. A major resi solar developer, for example, offered a further discount of two cents for an LOL of 40% versus 100%.

While “headline” declines in prices have been modest on a percentage basis, the flow through to cash tax savings has been significant

A corporate taxpayer who purchased a $50M tranche of Section 48 ITCs Q3 2024 and am equivalent $50M tranche of Section 48 ITCs  in Q3 2025 would have benefited from an additional $500,000 in cash tax savings – a 14.3% increase.  

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Tax credit pricing declines in 2025 have largely been driven by impacts of the OBBBA

In the months leading up to the Bill’s passage on July 4, the tax credit market slowed as buyers hesitated to make meaningful commitments without clarity on the final legislation. Many feared that 2025 tax credits might be retroactively repealed and chose to wait for assurance that existing credits would be respected before proceeding with transactions.

The Bill provided clarity that both current- and future-year tax credits will be respected, but the OBBBA itself had a significant downward impact on corporate tax liabilities. Dozens of corporations that were expecting $50M or $100M+ in tax liability no longer had the appetite to purchase 2025 credits. 

Today, many companies are still working to understand how OBBBA will affect their final 2025 tax liability – and have delayed purchasing credits as a result.

We expect lingering OBBBA-related impacts on 2026 tax liabilities. As of the publication of this note, Reunion is conducting our year-end tax credit buyer survey, and early feedback suggests that corporations are anticipating reduced 2026 tax liabilities of 10% to 30% against an assumed “non-OBBBA” baseline. Varying degrees of impact tend to cluster in sectors that are particularly sensitive to tax law changes. We’ll publish our year-end buyer report in early 2026.

Although 2026 aggregate demand may be down compared to this non-OBBBA baseline, we are seeing a significant number of taxpayers moving early on 2026 credits. These taxpayers generally fall into two camps:

• Strategic: Companies proactively seeking investments over $50M
• Opportunistic: Companies seeking investments with outsized discounts

We will incorporate pricing for 2026 tax credits in our Q1 2026 Market Monitor release.

Market dynamics

Section 45U nuclear and Section 45Z clean fuels are becoming increasingly popular production credits

In the second half of 2024, a handful of Reunion’s corporate clients explicitly prioritized Section 45U zero-emission nuclear power production credits (“ZENPPCs”). However, the majority of production credit-focused buyers focused on Section 45 PTCs.

As we approach the end of 2025, we have observed that many production credit-focused companies now view 45U ZENPPCs and 45 PTCs with roughly equivalent interest. From a pricing perspective, 45U nuclear credits are among the most stable.

A similar pattern is emerging around Section 45Z clean fuel production credits (“CFPCs”). An increasing number of corporate buyers are actively targeting 45Z credits due to two key factors:

• Risk/return: Section 45Z clean fuel credits are trading in the high $0.80s to low $0.90s, depending largely on the purchase size, presence of tax credit insurance, and the seller’s financial strength. Although this pricing generally aligns with Section 48 ITCs, Section 45Z CFPCs are not subject to recapture. 
• General business credit (“GBC”) ordering: Tax credit carrybacks have become more popular, and an effective carryback strategy must account for the credit-ordering rules reflected in IRS Form 3800. Compared to Section 48 ITCs, Section 45Z CFPCs are more advantageous for a carryback from a credit ordering perspective.

To reflect this growing interest, we are now publishing pricing series for both 45U and 45Z credits. Our 45U pricing goes back to 2024, while 45Z begins in 2025 (when the credit first became available). 

Although demand for 45Z credits is growing, prices have moderated slightly throughout 2025. We believe this reflects supply dynamics: since the 45Z credit only became available this year, a preponderance of sellers entered the market in the latter half of this year, generally offering full-year tranches of 2025 credits.

Looking ahead to 2026, we expect, and have already begun to see, 45Z deals structured around quarterly payments, akin to many Section 45 PTC transactions. Strips should become increasingly common, too.

The Treasury and the IRS have not yet issued final guidance for either of these credits, though this has not been a gating factor for most buyers. 45Z, in fact, is among the credits that received favorable treatment under the OBBBA.

10% of 2024 tax credit transfers closed in Q3 2025

Nearly 10% of all transfers involving 2024 credits took place in Q3 2025 – concentrated heavily in September and the first half of October, just ahead of the extended filing deadlines for both partnerships and C-corporations, respectively. This is measured by notional deal volume.

For many buyers, these “before-the-buzzer” transactions were structured around a carryback strategy, allowing them to request a refund simultaneously with the filing of their 2024 return.

‍Other deals were driven by the desire to fully utilize remaining tax capacity under the 75% statutory credit offset cap.

Regardless of the buyer’s underlying motivation, sellers generally benefited from premium pricing. Section 45X transactions for the 2024 vintage, for example, traded at the top of their range in Q3 2025 – "Following Q3" for the 2024 trend line – for both large and small deals.

PWA

Credits that are PWA exempt because of beginning of construction (BoC) dates are vanishingly rare

In the early days of the transfer market, buyers often sought tax credits that were exempt from prevailing wage and apprenticeship (PWA) requirements in an effort to avoid an incremental due diligence burden. Projects that either began construction before January 29, 2023 or have a capacity of less than 1 megawatt are generally exempt from PWA rules. 

In 2023, nearly all available credits on Reunion’s platform fit that profile: by credit value, 95% of Section 48 ITCs and 100% of Section 45 PTCs were PWA-exempt due to BoC timing. Fast-forward to the 2026 credit vintage, and the landscape has essentially reversed.

Projects with a capacity under 1 MW, such as residential solar, remain exempt from PWA requirements, as do certain other credit types (e.g., 45X credits).

Only 1% of 2026 Section 48 ITCs and 29% of Section 45 PTCs remain PWA-exempt due to BoC timing.

The 29% exemption figure for 2026 Section 45 PTCs may give buyers an overly optimistic impression. Much of this volume is already committed through multi-year strips or tied up by existing buyers holding rights of first refusal. As a result, PWA-exempt PTCs that are broadly available may carry a pricing premium and clear the market quickly.

FEOC

FEOC is becoming a key purchase consideration, resulting in premium pricing for credits with low FEOC risk

In 2024, buyers specifically requested credits that were exempt from PWA requirements. We are starting to see a similar trend emerging with respect to Foreign Entity of Concern (FEOC); buyers are prioritizing “legacy” Section 48 ITCs and Section 45 PTCs that qualify as FEOC-exempt. We expect legacy credits to trade at a premium price compared to similar credits (e.g., 48E and 45Y) that require compliance with FEOC rules.

We expect demand for increasingly scarce "legacy,” FEOC-exempt Section 48 and Section 45 tax credits to drive pricing higher. 

Credit adders

Adoption of bonus credit adders continues to expand for ITCs, but remains muted for PTCs

Section 48 ITCs and Section 45 PTCs can qualify for various “bonus” credit adders that increase a project’s effective credit value. 

Since 2023, average ITC credit amount above the 30% baseline (assuming PWA compliance), have risen from 4.4% to 9.5%, indicating that most developers are now effectively incorporating at least one credit adder.

From a buyer’s perspective, Section 48-eligible projects without a bonus credit adder have become relatively scarce.

Section 45 PTCs, by contrast, show a different pattern. Average PTC rates above the base credit amount have remained relatively flat from 1.1% in 2023 to 1.8% in 2026. This stability is expected, however, because many Section 45 PTCs originate from projects that pre-date the Inflation Reduction Act’s introduction of bonus credit adders.

Access Reunion's Q3 Update to Market Monitor

Explore the latest pricing trends, transaction data, and market dynamics shaping the transferable tax credit market.

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The Inflation Reduction Act (IRA) aims to create a robust market for well-paying clean energy jobs. To achieve this goal, the IRA significantly increases the tax benefits for projects that meet Prevailing Wage and Apprenticeship (PWA) requirements. The IRA introduced transferable tax credits, codified under §6418 of the Internal Revenue Code (IRC), allowing "eligible taxpayers" to sell certain energy tax credits to unrelated third parties for cash. Transferability intends to broaden the pool of investors participating in clean energy financing by simplifying complex structures like traditional tax equity arrangements.

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 credit is not subject to PWA requirements.

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

For more information about Reunion’s PWA compliance product, please contact us here.

Prevailing wage rules

Overview of prevailing wage

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

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

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

When to start paying prevailing wages

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

Determining the prevailing wage rate

Prevailing wage rates are published on the SAM website. The appropriate job type, location, and wage determination must be selected to comply with prevailing wage requirements. Occasionally, a job type for a given location will not be published. In this case, the taxpayer must contact the DOL at IRAprevailingwage@dol.gov to request a wage determination for the unlisted job type. The request to the DOL must include specific pieces of information such as form SF-1444, project name and location, contractor name, contract number (if applicable), name and description of the job classification needed, proposed wage rate and fringe benefits, the duties performed by workers in the proposed classification, explanation of why no current classification in the wage determination matches these duties, and an agreement or disagreement of the contracting officer and contractor with the proposed rate. The department has indicated that it will try to respond to wage determination requests within 30 days. For more information, please consult our PWA Help Center.

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

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

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

Reunion PWA automatically scrapes the SAM website for all wage determinations across all states and counties regularly. Reunion makes this data available and searchable via Reunion PWA so that developers and contractors can easily select the appropriate wage determinations for their projects.

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Apprenticeship rules

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

Labor hours requirement

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

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

Hours worked by foremen, superintendents, owners, or persons employed in a bona fide executive, administrative, or professional capacity are excluded from the labor hours calculation, unless these persons devote more than 20% of their time during a workweek to manual or physical labor. In this case, the hours worked must be included in the denominator (total labor hours) of the apprentice labor hours calculation.

Ratio requirement

Any apprentices performing work on a project are subject to the applicable apprentice-to-journeyworker ratio as prescribed by the associated registered apprenticeship program. Apprentice-to-journeyworker ratios must be met daily and vary depending on the applicable apprentice program’s requirements.

Participation requirement

Any contractor, subcontractor, or taxpayer who employs four or more mechanics or laborers on the project must employ one or more qualified apprentices. The journeyworkers and apprentices, however, do not have to be employed at the same time, provided that the applicable apprentice-to-journeyworker ratio as prescribed by the associated apprenticeship program is met on days when the apprentice is working.

Duration of PWA requirements

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

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

Impact of PWA Compliance on Tax Credits

Overview

The Prevailing Wage and Apprenticeship (PWA) requirements are a critical component of the Inflation Reduction Act of 2022 (IRA), and compliance with these rules has a direct and substantial financial impact on the value of most clean energy tax credits.

PWA compliance determines whether a project qualifies for an enhanced, significantly larger tax credit amount, which is generally five times greater than the base tax credit rate.

Financial Impact: The 5x Multiplier

For most transferable tax credits, meeting the PWA requirements results in a credit rate that is five times higher than the base rate.

The IRS updates §45 and §45Y PTC rates on an annual basis, generally in Q2. Rates are determined using an inflation adjustment factor (IAF) and published in the Federal Register. The inflation adjustment factor for 2025 is 1.9971. Specific examples of this financial enhancement include:

• Investment Tax Credits (§48 and §48E ITCs):
  
  • If PWA requirements are met (or exempted from), the credit is 30% of a project’s qualified basis.
  • If PWA requirements are not met, the credit is reduced to the base rate of 6% of the qualified basis.
  • Furthermore, achieving PWA compliance is necessary to receive the full value of certain bonus credits. For example, the Energy Community bonus or Domestic Content bonus is typically 10% of the qualified basis if PWA requirements are met, but only 2% if they are not met.
• Production Tax Credits (§45 and §45Y PTCs):
  
  • 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 base rate and PWA rate (after rounding) are $6 and $30 per MWh of qualifying electricity produced and sold, respectively.
  • For projects placed in service after December 31, 2021, the §45 PTC rate calculation is $3 per MWh of qualifying energy, multiplied by the inflation adjustment factor, and rounded to the nearest $0.50. For projects meeting PWA requirements, this product is multiplied by five. There is no separate PWA rate of $15 per MWh of qualifying energy for these projects, and as such, the resulting rate for PWA-compliant projects may have small differences from the PWA rates discussed above, as was the case in 2024. The same technology-specific rate adjustments apply for open-loop biomass, small irrigation power, landfill gas, and trash facilities, so the resulting rate is reduced by one-half. There is no phaseout adjustment for wind projects placed in service after December 31, 2021. The 2025 rate, assuming prevailing wage and apprenticeship compliance, is $30.00 per MWh for wind, closed-loop biomass, geothermal, and solar; and $15.00 per MWh for open-loop biomass, landfill gas, trash, qualified hydropower, and marine and hydrokinetic renewable energy. For qualified hydropower and marine and hydrokinetic renewable energy facilities placed in service after December 31, 2022, the 2024 rate is $15.00 per MWh, assuming prevailing wage and apprenticeship compliance.
  • Similar to the ITC case, the Energy Community bonus and Domestic Content bonus add a 10% increase to the applicable rate (Base or PWA-compliant).

Impact on Risk and Due Diligence

For tax credit purchasers, PWA compliance is a major risk factor. If the requirements are not met and the project claimed the enhanced rate, the credit amount can be dramatically reduced (e.g., from 30% to 6% for an ITC), resulting in an "excessive credit transfer". The buyer is liable for this excessive credit amount plus a 20% penalty.

Therefore, PWA compliance heavily influences the due diligence process for transferable tax credit transactions:

• Buyers must ensure sellers maintain extensive records, including payroll records for all laborers and mechanics (including apprentices).
• Documentation must substantiate proper labor classifications, applicable wage rates, and comprehensive apprenticeship records (requests, hours worked, ratios).
• For §48 ITCs, the seller must provide an annual prevailing wage compliance report during the five-year recapture period.
• Buyers should validate if a seller claims an exception, such as verifying the BoC date or the project's output capacity.
• Due to the complexity, Reunion offers a PWA compliance software product to reduce the time and expense of complying with PWA requirements and generate a standardized report for due diligence purposes.

Records and documentation

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

Prevailing wage records

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

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

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

Apprenticeship records

For apprentices, the developer should capture:

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

Annual prevailing wage compliance report

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

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

Compliance

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

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

Exceptions

Beginning of construction

Projects that began construction before Jan. 29, 2023, are exempt from the prevailing wage and apprenticeship rules, except for credits under §48C and §45Z. To learn more, please refer to the Beginning of construction section. 

For the avoidance of doubt, the beginning of the construction test to determine exemption from prevailing wage and apprenticeship requirements is a different test than determining when construction, alteration, or repair of a project began for purposes of starting compliance with prevailing wage rates (as discussed in the When to start paging prevailing wages section).

One megawatt

Projects under §45 and §48 (and their replacements under §45Y and §48E) are exempt from PWA if the maximum net output is less than one megawatt (as measured in alternating current) or the capacity of electrical or equivalent thermal storage is less than one megawatt. The net output will be determined by “nameplate capacity,” defined in 40 CFR 96.202, as the maximum output on a steady-state basis during continuous operation under standard conditions when not restricted by seasonal or other deratings. 

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

Electrochromic glass, fiber-optic solar, and microgrid controllers are not eligible for the one-megawatt exception because they do not generate electricity or thermal energy.

Remedies

Prevailing wages 

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

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

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

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

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

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

Apprentices

Apprenticeship cures are unique to the failure that occurred. To cure a failure of a particular requirement, the following processes apply:

• Apprentice labor hours requirement: Any shortfall in apprentice labor hours is calculated (see Labor hours requirement section above and reclassification of apprentices to journeyworkers in the Apprentice ratio requirement below) and multiplied by $50 (or $500 for intentional disregard) to determine the amount of cure payment owed.
• Apprentice ratio requirement: The required apprentice-to-journeyworker ratio is calculated daily (see Ratio requirement section above), and apprentices in excess of the ratio are required to be paid a journeyworker wage. Labor hours from apprentices in excess of the ratio are also accounted for as journeyworker labor hours in the apprentice labor hours requirement above. Any shortfall in prevailing wage payments resulting from this reclassification of apprentices to journeyworkers must be remedied to maintain compliance. 
• Apprentice participation hours requirement: If the participation requirement is not met (see Participation requirement section above), the shortfall in participation hours is the total labor hours divided by the number of laborers or mechanics (for the laborers or mechanics that failed to meet the participation requirement). This shortfall in participation hours is then multiplied by $50 (or $500 for intentional disregard) to determine the amount of cure payment owed.

Good-faith effort exception

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

• The request was denied for reasons other than the developer’s refusal to comply with the program’s standards and requirements
• The apprenticeship program failed to respond within five business days of receiving a request
• The apprentice program provided apprentices, but there were fewer than requested

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

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

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

A good-faith effort exception can be applied as an exemption from a portion of the apprentice labor hours requirement for a period of 365 days (or 366 during a leap year). The good faith effort exception excuses a developer or contractor from the amount of labor hours that were requested from the applicable apprentice program by applying the requested block of labor hours towards the numerator (apprentice labor hours) of the apprentice labor hours calculation. Developers or contractors must submit a subsequent request within the 365-day (or 366-day) window to continue to satisfy the good-faith exception for an additional block of apprentice labor hours. The annual duration also applies if a developer or contractor is not able to locate a registered apprenticeship program with an area of operation that includes the location of the facility.

Due diligence 

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

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

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

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

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

In the case of the §48 ITC, the seller should also provide an annual compliance report to the IRS during the recapture period.

Guidance and resources

Guidance

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

Resources

• The IRS maintains a prevailing wage and apprenticeship requirements FAQ
• The Department of Labor determines and maintains prevailing wages
• To request a wage determination, developers can email iraprevailingwage@dol.gov with project and labor information
• Apprenticeship.gov provides resources for finding qualified apprentices
• Reunion maintains a Reunion PWA Help Center for Reunion PWA customers that includes information about various regulations and instructions for submitting information to the DOL

 Frequently Asked Questions about Prevailing Wage & Apprenticeship

1. How can developers structure contracts to ensure continuous compliance with prevailing wage requirements across multi-phase projects?
   
   1. Ensure that contracts with EPCs (or primary contractors) contain provisions obligating the EPC and all subcontractors to abide by prevailing wage and apprenticeship requirements. Additionally, ensure that the EPC is obligated to provide certified payroll records and other relevant information to the developer (or a third party) such that PWA compliance can be certified.
2. What mechanisms exist to verify and document apprenticeship utilization to satisfy the IRA’s PWA requirements?
   
   1. Developers (and contractors) should ensure that apprentices are hired from a registered apprentice program (listed on apprenticeship.gov) and that all apprentices have a certificate of registration with the applicable apprenticeship program. 
3. How do project timelines and change orders affect prevailing wage determinations?
   
   1. Wage determinations are “locked in” on the execution date of the construction contract with the EPC for a facility. However, wage determinations must be updated in one of the following situations: 
      
      1. A new contract for alterations or repairs is executed after the facility is placed in service. In this case, use the wage determinations that are in effect when that alteration/repair contract is signed.
      2. There is a material contract change to the initial EPC contract. If the EPC contract is amended to substantially add scope or extend the contract period, wage determinations must be reset to the then-current modifications.
      3. Indefinite-term contracts are not tied to specific work. In this case, wage determinations must be reset each new contract year.
4. What are the financial and tax credit implications of partial non-compliance with PWA provisions?
   
   1. For the purposes of determining compliance with the PWA requirements for the eligibility of the 5X rate multiplier, there is no partial compliance. Either a project is PWA compliant or it is not. That said, there are cure methods for any shortfall with respect to the PWA compliance requirements, such that projects are able to remedy issues and maintain compliance even if mistakes are uncovered later.
5. How can digital compliance systems or third-party verification tools be integrated to simplify PWA tracking and reporting?
   
   1. Reunion recommends establishing a PWA tracking method at least two months before the beginning of project construction. This ensures that all contractors are aware of their responsibilities with respect to PWA and reporting. The benefit of ensuring tracking is in place before construction is that all parties maintain real-time visibility into a project’s compliance status and are able to get ahead of any underpayments or non-compliant issues before penalties are incurred.
6. How are apprentices hired in rural areas or with specialized trades where registered programs may not exist or provide apprentices in the applicable trade?
   
   1. If there is no registered apprentice program that both supplies apprentices in the project location and trains apprentices in the occupations needed, then the project is deemed to have made a good-faith effort with the need to file a request for apprentices. However, the US Department of Labor or a state apprentice agency must be contacted in such cases for help finding apprentices in order to claim the good-faith effort exception.

With Brent Schoradt from Clean Energy Counsel, LLP and Kathryn McEvilly from Baker Botts

Mastering the complexities of Prevailing Wage and Apprenticeship (PWA) requirements is essential to protecting the full value of a project's tax credits. The financial stakes are significant, and reporting errors can put full tax credit values at risk, jeopardizing financing and project viability. ‍

Recording: The 10 most common prevailing wage and apprenticeship compliance questions

Questions Covered:

Question 1: Supplemental Wage Determinations (06:25)

In what situations should supplemental wage determinations be requested, and once you get a response from the DOL, what should you do with the s supplemental wage determination?

Summary: If a project requires a trade or occupation not listed in the applicable wage determination for the state and county where a project is being constructed, contractors must request an additional wage determination (SF-1444 conformance request). Once the DOL responds to the conformance request, contractors should ensure that laborers performing work under this supplemental wage determination are paid according to the prescribed rates.

Question 2: Delayed Supplemental Wage Determinations (09:04)

What happens if you don't receive a supplemental wage determination before the start of construction?

Summary: If construction starts before the DOL has responded to a conformance request, there is relief to avoid penalties in the case where the initially requested rate was less than the rate in the DOL's final determination: you must pay back wages (the difference between what was paid and the rate defined in the supplemental wage determination) within 30 days of receiving confirmation of the supplemental wage determination from the DOL. As long as these back wages are paid within 30 days of receipt of confirmation from the DOL, you do not have to pay interest along with the back wages.

Question 3: Changes in Supplemental Wage Determinations (11:24)

What happens if your conformance request response comes back from the DOL, and they tell you that you need to pay more than the rate that you indicated in your request?

Summary: If the final supplementary wage determination rate is higher than the rate that you had initially requested, you must pay the difference (back wages) within 30 days. Failure to pay these back wages within the 30-day window subjects the taxpayer to normal cure provisions, including interest and the $5,000 per laborer per year penalty.

Question 4: Exemption from PWA Compliance (14:13)

Are certain activities exempt from PWA compliance, and specifically, what activities are exempt during the alteration and repair period?

Summary: Exemptions exist for projects under 1 MW or those that began construction before January 29, 2023. While regular maintenance is exempt, activities like site clearing and preliminary work are considered "construction" under the Davis-Bacon Act (DBA) definition referenced by PWA, making them subject to PWA compliance.

Question 5: Apprenticeship Requirements (18:52)

How can developers be confident in satisfying the apprentice participation, ratio, labor hours, good faith effort requirements?

Summary: Developers should track compliance against the three apprenticeship requirements: Participation (at least one apprentice must be hired per contractor with four or more laborers performing work on the project), Ratio (daily tracking of the apprentice-to-jouneyworker ratio to ensure that this ratio is compliant with the prescribed ratio of the associated apprenticeship program), and Labor Hours (15% of total labor hours must be worked by apprentices for projects that began construction in 2024 or later).

The Good Faith Effort exception is met if a proper request for apprentices is submitted in writing and denied or not responded to within five business days. Additionally, the Good Faith Effort exception may be claimed if no apprentice program covers the project location, trains apprentices in the occupations needed, and supplies apprentices to employers. In this case, the US Department of Labor or state apprentice agency must be contacted to help find apprentices. The Good Faith Effort exception excuses a contractor from the apprentice participation requirement and from a portion of required apprentice labor hours, depending on how many apprentice hours were requested.

Question 6: Job Sites Across Multiple Counties (34:10)

How should I handle PWA compliance for a single site that spans two different counties?

Summary: You must comply with the prevailing wage and apprenticeship requirements of each county individually. Recommended approaches include paying the higher wage rate across both counties or requesting a single supplemental wage determination applicable to the entire job site.

Question 7: Feedback from Tax Credit Buyers and Insurers (36:20)

What are the most common items that tax credit buyers and insurers find are missing in PWA compliance reports?

Summary: The most common issue is a lack of data from subcontractors, often because the project sponsor lacks direct contractual privity with them. This logistical difficulty leads to incomplete or delayed compliance reports.

Question 8: Making Back Payments (39:23)

If a laborer is underpaid, how long do I have to pay them back? Are there any penalties associated with the underpayment? And how can I make sure that my subcontractors are aware of any wage deficiencies and that they remedy them in a timely manner?

Summary: Underpayments must be corrected by paying back wages plus interest (short-term federal rate + 6%). The penalty of $5,000 per laborer per year is waived if the deficiency is identified and corrected by the end of the month following the calendar quarter in which the underpayment occurred. The Reunion platform provides automated notifications to contractors when underpayments or other non-compliance are identified. This ensures that contractors are made aware of any back pay requirements in a timely manner.

Question 9: Demonstrating Intent to Pay Penalties (47:36)

If I have PWA penalties due and intend to pay them with my tax return, how should I document this intent for purposes of demonstrating my project's PWA compliance?

Summary: To satisfy tax credit investors/buyers, documentation often includes a letter of intent to pay the penalty with a developer's tax return. In some cases, a cash escrow account may be set up to ensure the availability of funds for the penalty payment.

Question 10: Definition of a Qualified Facility Under Section 48E (50:28)

If my project is pursuing Section 48E tax credits, do I need to track PWA compliance on a more granular level than on the project as a whole to comply with the definition of a qualified facility under Section 48E?

Summary: Unlike older credits, Section 48E technically requires establishing PWA compliance (including the 15% apprentice labor hour requirement) at the level of the qualified facility (e.g., an individual inverter block for solar). Because this granular tracking is commercially infeasible, the market is currently revolving around using a reasonable allocation method to establish compliance at the qualified facility level.

Timestamps:

• ‍00:00-01:14 - Welcome and Technical/Administrative Notes
• ‍01:14-04:33 - Panelist and Moderator Introductions
• ‍04:33-06:25 - Reunion Company Overview & PWA Platform
• ‍06:25-11:24 - Supplemental Wage Determinations
• ‍11:24-14:13 - Penalties and Curing Wage Deficiencies
• ‍14:13-18:31 - Exemptions from PWA Compliance
• ‍18:31-23:41 - Apprenticeship Requirements Deep Dive
• ‍23:41-34:10 - Tracking Apprenticeship Compliance & Risk Management
• ‍34:10-37:01 - Compliance for Multi-County Job Sites & Missing Data
• ‍37:01-47:36 - The Role of Tax Credit Buyers/Insurers & Penalty Details
• ‍47:36-55:32 - Documentation and Section 48E Qualified Facility Issues
• ‍55:32- 01:00:45 - Final Audience Q&A and Closing Remarks

‍

With Brandon Hill from CliftonLarsonAllen, Debbie Harrison from McDermott Will & Schulte, and Mark Christy from Orrick, Herrington & Sutcliffe

Clean energy transferable tax credits have created new opportunities for taxpayers to participate in the clean energy transition while offsetting tax liability, but understanding the mechanics of carrybacks and carryforwards is essential to capturing their full benefit.

‍Recording: Navigating Carrybacks and Carryforwards in Clean Energy Tax Credit Transactions

Insights from the conversation:

1. Carrybacks Create a Four-Year Tax Liability Window

The ability to carry a clean energy tax credit back 3 years and carry forward 22 years is the core mechanism. For a corporate buyer, this potentially aggregates four years of tax liability (the current year plus the three carryback years), making a carryback a great fit for any taxpayers with a trailing federal tax liability. Some examples of strong profiles for a carryback strategy include tax payers with a large, one-time event in a recent tax year or relatively smaller taxpayers looking to aggregate up to four years of liability to make a larger tax credit purchase. The carryback must first be applied to the current tax year, and then carried back to the earliest possible year first, with each year thereafter sequentially. Each tax year is subject to the statutory cap (75% of federal tax liability).

2. Cash Flow is the Primary Strategic Concern

One potential challenge of a carryback is the mismatch between the date the buyer pays for the credit and the date the refund is received from the IRS. Since a carryback claim is effectively filed simultaneously with the current year's tax return (which may be several months after year-end for corporates), there may be a notable lag. To alleviate this burden, tax credit buyers frequently negotiate delayed / split payment structures (or possibly lower upfront purchase prices) with tax credit sellers to improve the overall return on investment.

3. IRS Refund Timing is Variable (But Pays Interest)

Once the carryback claim is filed, the refund processing time is variable. The IRS publishes processing statuses online, which suggest an approximate 90-day timeline to process carryback claims. Notably, the IRS will pay interest on carryback refund claims that have been outstanding for more than 45 days. Subject to a given taxpayer’s internal cost of capital, some buyers have found interest payments to be accretive to the overall transaction ROI. Carryback refund claims under $5 million are not subject to Joint Committee on Taxation (JCT) review, which may also lead to faster processing.

4. Credit Ordering Rules Matter (Form 3800)

Taxpayers who have other general business credits (e.g., low-income housing, work opportunity, etc.) should be mindful of the instructions established in the Form 3800 General Business Credit (”GBC”) ordering rules. These rules dictate the order by which certain GBCs (including energy tax credits) must be applied against the current year's tax liability, and can have downstream impacts on carryback or carryforward mechanics.

Conversation overview:

• Welcome, Introductions, and Agenda Overview
• Mechanics of Carrybacks and Carryforwards: Rules, Caps, and Filing Forms (1139/1120X)
• Documentation, Negotiating Payment Timing, and Managing Cash Flow for Refunds
• Practical Considerations: IRS Refund Timing, Interest Payments, JCT Review, and Audit Risk
• Buyer Profile, Strategy, and Credit Ordering Rules for Carryback Optimization
• Market Update: Supply, Pricing Trends, and Emerging Credits (45Z Clean Fuel and 45U/45Y Nuclear)
• Audience Q&A and Final Closing Remarks

Defining the beginning of the construction date for a renewable energy project has historically been a thorny task for developers with respect to tax credits qualification. 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 PFE/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”).  

Physical work of a significant nature 

A taxpayer can establish BoC by starting physical work of a significant nature (within the meaning of section 4 of Notice 2013-29) and thereafter maintaining a continuous program of construction (“Continuous Construction”). Physical work may occur on-site or off-site, performed by either the taxpayer or by another party under a binding written contract. On-site physical work does not include preliminary activities such as planning and design, obtaining permits and licenses, or performing surveys, studies, test drilling, site clearing, or excavation for the purpose of recontouring land (as distinguished from excavation for footings and foundations).

For a wind facility, some examples of on-site physical work include the beginning of the excavation for the foundation, the setting of anchor bolts into the ground, or the pouring of the concrete pads of the foundation. For off-site physical work, the manufacture of components must be done pursuant to a binding written contract, with such components not held in a manufacturer’s inventory. 

One of the most common ways to satisfy physical work of a significant nature through off-site means is through physical work on a custom-designed transformer that adjusts the voltage of electricity generated by a project for purposes of transmission and distribution. 

Five percent safe harbor 

Alternatively, a taxpayer can establish BoC through the Five Percent Safe Harbor by paying or incurring (within the meaning of §1.461-1(a)(1) and (2)) five percent or more of the total cost of the facility and thereafter making continuous efforts towards completion of the facility (“Continuous Efforts”). Only costs properly included in the depreciable basis of the facility are taken into account to determine whether the Five Percent Safe Harbor has been met; the total cost of the facility does not include the cost of land or any property not integral to the facility. 

Continuity safe harbor 

Given that both physical work of a significant nature and the Five Percent Safe Harbor require continuous progress toward completion once construction has begun via either Continuous Construction or Continuous Efforts (collectively, the “Continuity Requirement”), the IRS also provides a safe harbor (the “Continuity Safe Harbor”) pursuant to which the Continuity Requirement is deemed to be satisfied if a taxpayer places a project in service by the end of a calendar year that is no more than four calendar years after the calendar year during which construction began. For example, a project that begins construction in early 2026 will have until the end of 2030 to be placed in service. Notice 2021-41 extended the four-year window to six years for projects where construction began in 2016, 2017, 2018, or 2019, and to five years for projects where construction began in 2020. 

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

Under the OBBBA, solar and wind projects are subject to an early phasedown in tax credits; projects seeking §45Y or §48E credits must be placed in service before January 1, 2028, unless the projects started construction before July 5, 2026. As a result, solar and wind developers have been racing to establish BoC in order to secure additional time to complete projects. In connection with the OBBBA, President Trump issued Executive Order 14315, directing the Treasury to issue new and revised beginning of construction guidance within 45 days of the order. 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 the beginning of construction. These projects can no longer utilize the Five Percent Safe Harbor and must also maintain a continuous program of construction, which can be satisfied through the existing Continuity Safe Harbor if the project is placed in service by the end of a calendar year that is no more than four calendar years after the calendar year during which construction began. 

One notable language change in the physical work requirement is that under the previous Notice 2013-29, a taxpayer could establish the beginning of construction by “starting” physical work of a significant nature, whereas the new Notice 2025-42 requires that the work be “performed.”  

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 that were in place before Notice 2025-42, and therefore can continue to use the Five Percent Safe Harbor: 

• Projects that can establish BoC (using the old BoC rules) before September 2, 2025. 

• Solar projects with a maximum net output of 1.5 MW or less. This capacity is generally measured at each inverter, though facilities will need to aggregate their output if they (i) are owned by the same taxpayer, (ii) are placed in service within the same year, and (iii) use the same point of interconnection. 

The BoC guidance in Notice 2025-42 only pertains to tax credit qualification for wind and solar projects under §45Y and §48E; PFE/FEOC guidance (which is expected to include BoC provisions) is still being drafted by Treasury. 

Guidance 

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

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

Frequently Asked Questions about the Beginning of Construction

1. How is “Beginning of Construction” defined across different IRA tax credit sections, and what documentation substantiates compliance?
   
   1. Beginning of Construction (“BoC”) is established either by performing physical work of a significant nature or by meeting the Five Percent Safe Harbor (incurring ≥5% of total facility costs). The BoC definition is consistent across IRA tax credit types. Documentation to demonstrate BoC may include construction logs, invoices, contracts, images of site construction, or satellite imagery proving physical work.
2. How do delays, redesigns, or partial project transfers affect the original BOC date and credit eligibility?
   
   1. The original BoC date generally remains valid if the taxpayer maintains Continuous Construction or Continuous Efforts, or qualifies under the Continuity Safe Harbor (usually 4 years to place in service). Transfers or redesigns may risk eligibility if they disrupt continuity or materially change project scope.
3. What strategies can developers use to establish BoC early, in order to lock in eligibility before regulatory or incentive changes?
   
   1. Developers can begin physical work (e.g., foundation excavation, transformer manufacturing) or incur ≥5% of total costs under a binding written contract before a cutoff date. These actions “lock in” eligibility under current credit rules and rates.
4. How do off-site manufacturing or preliminary activities (like grading or engineering) factor into BoC determinations?
   
   1. Offsite manufacturing counts towards the establishment of BoC only if performed under a binding contract for project-specific components that are not held in inventory. Preliminary activities (e.g., planning, grading, surveys, permit work) do not qualify as Begining of Construction.
5. How should developers coordinate BoC documentation across multiple EPCs or component suppliers for audit readiness?
   
   1. Developers should maintain centralized records of binding contracts, invoices, manufacturing milestones, and delivery logs from all EPCs and suppliers. Consistent date tracking and certification statements ensure defensible audit evidence of BoC and continuity.
6. How does BoC interact with prevailing wage/apprenticeship and domestic content rules for determining applicable credit multipliers?
   
   1. The BoC date determines whether a project is subject to or exempt from enhanced credit requirements under the IRA.
      
      1. Prevailing Wage & Apprenticeship (PWA):
         
         1. Projects that began construction before January 29, 2023, are exempt from PWA and automatically receive the 5X multiplier on the base credit rate. Projects starting on or after that date must meet PWA labor and apprenticeship rules to qualify for the higher rate.
      2. Domestic Content & PFE/FEOC:
7. The BoC date “locks in” which Treasury guidance applies to domestic content thresholds (preliminary or final guidance) and could govern future PFE/FEOC sourcing restrictions once guidance is provided by Treasury in 2026.In short, BoC is the regulatory timestamp that fixes which labor and sourcing rules apply to a project’s credit eligibility and credit rate multiplier.

Key takeaways

Carrybacks create a four-year tax liability window

The ability to carry a clean energy tax credit back 3 years and carry forward 22 years is the core mechanism. For a corporate buyer, this potentially aggregates four years of tax liability (the current year plus the three carryback years), making a carryback a great fit for any tax payers with a trailing federal tax liability. Some examples of strong profiles for a carryback strategy include tax payers with a large, one-time event in a recent tax year or relatively smaller taxpayers looking to aggregate up to four years of liability to make a larger tax credit purchase. The carryback must first be applied to the current tax year, and then carried back to the earliest possible year first, with each year thereafter sequentially. Each tax year is subject to the statutory cap (75% of federal tax liability)

Cash flow is the primary strategic concern

‍One potential challenge of a carryback is the mismatch between the date the buyer pays for the credit and the date it receives the refund from the IRS. Since a carryback claim is effectively filed  simultaneously with the current year's tax return (which may be several months after year-end for corporates), there may be a notable lag. To alleviate this burden, tax credit buyers frequently negotiate delayed / split payment structures (or possibly lower upfront purchase prices) with tax credit sellers to improve the overall return on investment

IRS refund timing is variable (but pays interest)

‍Once the carryback claim is filed, the refund processing time is variable. The IRS publishes processing statuses online which suggest an approx. 90 day timeline to process carryback claims. Of note, the IRS will pay interest on carryback refund claims outstanding longer than 45 days. Subject to a given taxpayer’s internal cost of capital, some buyers have found interest payments to be accretive to the overall transaction ROI. Carryback refund claims under $5 million are not subject to Joint Committee on Taxation (JCT) review, which may also lead to faster processing.

Credit ordering rules in IRS Form 3800 are key

Taxpayers who have other general business credits (e.g., low-income housing, work opportunity, etc.) should be mindful of the instructions established in the Form 3800 General Business Credit (”GBC”) ordering rules. These rules dictate the order by which certain GBCs (including energy tax credits) must be applied against the current year's tax liability, which can have downstream impacts on carryback or carryforward mechanics

Introduction

The Treasury’s final transferability regulations allow corporations to carry transferable tax credits back up to three years, with the ability to offset up to 75% of prior-year tax liabilities. Companies may also carry credits forward up to 22 years.

Although carrybacks and carryforwards have been available for clean energy tax credits since the introduction of transferability under the Inflation Reduction Act (IRA), it's been only in the past six months that Reunion has seen a meaningful increase in companies exploring and modeling these strategies – with a particular interest in carrybacks.

In our view, this emerging interest in carrybacks reflects market maturity, as both experienced and first-time buyers seek to maximize the value and flexibility of their tax credit investments. By leveraging carrybacks, purchasers can expand the total credit volume under consideration, unlocking more favorable deal terms and better overall returns.

How does a tax credit carryback work?

Tax credit buyers can carry credits back three years, and then apply credits forward to subsequent years. A company who purchases 2025 tax credits for a carryback, for instance, would first have to max out their 2025 capacity and then apply any unused amount to 2022, then 2023, and then to 2024. For each year, the company would apply credits up to the statutory cap (75% of total tax liability) before moving on to subsequent years. Buyers do not have the discretion to pick and choose which years to apply carryback credits.

It’s worth reiterating that a company may only carry back credits after they have exhausted their ability to apply those credits to the tax year of the credits. In other words, a company may only carry back 2025 credits once they have hit the 75% statutory cap for 2025. 

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

Assume a taxpayer purchases $75 million of 2025 tax credits and is expected to have a gross tax liability of $100 million from 2022 through 2028. The tax credit deduction would follow the below structure:

What types of companies should consider a carryback?

A carryback generally makes sense for companies who have a significant tax liability across one or more of their three prior tax years. A common use case is a sizable tax event, like a strategic divestiture, within the three-year carryback window.

This holds true for public and private companies, both of whom Reunion has supported in carryback transactions.

When and how do you apply for a carryback refund request?

If a company is requesting a carryback refund via IRS Form 1139, Corporate Application for Tentative Refund, the tax team would typically submit Form 1139 at the same time as, but not in the same package with, their income tax return for the year of the credits they purchased for a carryback. 

From Instructions for Form 1139:

• “When to File: Generally, the corporation must file Form 1139 within 12 months of the end of the tax year in which an NOL, net capital loss, unused credit, or claim of right adjustment arose. The corporation must file its income tax return for the tax year no later than the date it files Form 1139.
• Where to File: File Form 1139 with the Internal Revenue Service Center where the corporation files its income tax return. Do not file Form 1139 with the corporation's income tax return.”

Because a company effectively files their refund request at the same time as their income tax return, they will have a concrete understanding of how many credits are unused from the current tax year. 

How long should it take to process a carryback refund request?

The IRS has 90 days to process a Form 1139 carryback refund request 

The Instructions for Form 1139 states, “The IRS will process this application within 90 days of the later of:

• The date the corporation files the complete application, or
• The last day of the month that includes the due date (including extensions) for filing the corporation's income tax return for the year in which the loss or credit arose (or, for a claim of right adjustment, the date of the overpayment under section 1341(b)(1))”

Importantly, receiving a refund doesn't validate the application. The IRS may later assess penalties and interest for overvalued property, negligence, rule disregard, or substantial income tax understatement if deductions or credits are found incorrect.

Current refund processing times are around 90 days

The IRS publishes processing statuses for various tax forms online. As of the publication date of this note (October 2025), the IRS is processing Form 1139s from June 2025 – that is, generally within the prescribed 90-day window.

Reunion accessed the IRS processing status webpage on October 29. The footer stated that the page was last reviewed or updated on October 24.

Some companies are assuming more than 90 days for modeling purposes

Reunion has supported several corporate tax leaders who are baking additional time into their carryback modeling assumptions. These are generally larger C corporations who are requesting refunds over $5 million, which are subject to another level of review through the Joint Committee on Taxation (JCT).

Most of these companies consider 90 days their best-case scenario and anticipate that a refund could take longer – perhaps six to nine months.

The IRS pays interest on refunds that take longer than 45 days

It's worth bearing in mind that the IRS pays interest on refund requests that take longer than 45 calendar days (from the point at which the IRS deems the application complete).

For companies with relatively low costs of capital, the interest paid by the IRS may, in fact, be accretive to the overall transaction ROI.

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What types of credits are most suitable for a carryback?

Tax credits with wider discounts generally work well

All transferable tax credits, irrespective of discount, can be suitable for a carryback as long as they are “applicable credits.” We included an exhaustive list below. 

Generally speaking, however, due to the time-value-of-money implications of the refund process, tax credits with wider discounts are most suitable for a carryback. Section 48 ITCs and Section 45Z CFPCs, which tend to trade in the low $0.90s, are commonly used for carrybacks.

Delayed payments and delayed transactions can also make the economic case for a carryback

A buyer can achieve a comparable time-value-of-money benefit by negotaiting delayed payment with the seller. Reunion supported a publicly traded buyer, for instance, who purchased 2025 Section 45 PTCs for a carryback from a seller who was willing to accept payment in June 2026.

Along the same lines, a buyer can simply wait to purchase tax credits until their tax filing date is closer. Reunion supported over a dozen 2024 tax credit transfers in September 2025 alone, and many of these transactions involved a carryback allocation. It's worth recalling, however, that tax credit prices generally rise as tax filing dates approach.

Keep in mind your company's other general business credits

Taxpayers who have other general business credits ("GBC") – for example, R&D and low-income housing – should be mindful of the ordering rules established in Instructions for IRS Form 3800. These rules dictate the order by which GBCs (including energy tax credits) must be applied against the current year's tax liability, which can have downstream impacts on carryback or carryforward mechanics.

Several of Reunion's banking clients who have LIHTC exposure prioritize Section 45Z CFPCs over Section 48 ITCs because of the general business credit ordering rules: investment credits (including "energy credits" claimed on IRS Form 3468) are used before low-income housing credits.

"Applicable credits" that are eligible for a carryback

The following transferable tax credits are “applicable credits” that are eligible for carrybacks (per Section 39(a)(4) and Section 6417(b)):

• Section 48 ITCs
• Section 48E ITCs
• Section 45 PTCs attributable to qualified facilities which are originally placed in service after December 31, 2022
• Section 45Y PTCs
• Section 45X advanced manufacturing production credits
• Section 45U zero-emission nuclear power production credits
• Section 45Z clean fuel production credits
• Section 48C qualifying advanced energy project credits
• Section 45V clean hydrogen production credits attributable to qualified facilities which are originally placed in service after December 31, 2012
• Section 45Q carbon oxide sequestration credits attributable to carbon capture equipment which is originally placed in service after December 31, 2022
• Section 30C alternative fuel vehicle refueling property credits which, pursuant to subsection (d)(1) of such section, are treated as a credit listed in Section 38(b)

Watch Reunion's webinar on tax credit carrybacks and carryforwards

Reunion hosted a webinar, The Role of Carrybacks & Carryforwards in Clean Energy Tax Credit Transactions, on November 12. Our Head of Commercial Strategy, Alessio De Falcis, led a panel of tax and legal experts from CLA, Orrick, and McDermott to explored how carryback and carryforward provisions work and what they mean for corporate tax credit purchasers. 

The panel discussed:

• How carryback and carryforward provisions apply to transferred credits under the IRA
• Key considerations for timing, documentation, and compliance
• How purchasers can plan for credit utilization across multiple tax years
• IRS guidance updates and emerging best practices from prior filing cycles
• Practical insights from recent transactions

We published a recording and transcript of the webinar.

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The One Big Beautiful Bill Act (OBBBA) added new “Prohibited Foreign Entity (PFE)” restrictions, primarily intended to prevent Chinese companies from benefiting from tax credits, and to reduce reliance on China for clean energy technology. PFE 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. 

PFE restrictions are broadly divided into two sets of rules: 

1. Taxpayer level restrictions: taxpayers claiming §48E, §45Y, §45X, §45U, §45Z, and §45Q tax credits may not be a prohibited foreign entity (PFE), and the tax credit may not be transferred to a PFE (see Taxpayer level FEOC restrictions below). For §48E, §45Y, §45X credits, taxpayers may not give “effective control” to a specified foreign entity (SFE) through a binding contract or licensing agreement (see Effective control FEOC restrictions below)
2. Project level restrictions: taxpayers claiming §48E, §45Y, and §45X tax credits may not receive “material assistance” from a PFE through the use of manufactured products or eligible components (see Material assistance FEOC restrictions below).

PFE 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 PFE 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 entity-level restrictions beginning in the taxpayer’s first taxable year after enactment of the OBBBA).

Buyers will need to perform careful due diligence to ensure PFE compliance.  

Taxpayer-level restrictions 

Prohibited foreign entities (PFEs), which can be either a specified foreign entity (SFE) or a foreign-influenced entity (FIE), are not allowed to claim the following tax credit types: §45Y, §48E, §45X, §45Q, §45U, and §45Z

For §45Y, §48E, §45X, and §45Q, both SFEs and FIEs cannot claim credits starting the tax year beginning after July 4, 2025.

For §45U and §45Z, the prohibition on SFEs starts the tax year beginning after July 4, 2025. The prohibition on FIEs starts the second tax year beginning after July 4, 2025. 

Specified foreign entities

Per §7701(a)(51)(B), an SFE is defined to be one of the following:

• A “foreign entity of concern” as defined in the William M. (Mac) Thornberry National Defense Authorization Act (NDAA) for Fiscal Year 2021. Entities meeting this criteria include foreign terrorist organizations, entities owned by the Chinese, Russian, North Korean, or Iranian government (the “Covered Nations” as defined in §4872(f)(2) of title 10, United States Code), and entities that could be a threat to national security
• A Chinese military company as defined in §1260H of the William M. (Mac) Thornberry National Defense Authorization Act for Fiscal Year 2021
• An entity manufacturing products that benefits from Uyghur forced labor in Xinjiang in China, per §2(d)(2)(B) of Public Law 117-78
• An entity included on the OFAC list that could pose a threat to national security per §154(b) of the National Defense Authorization Act for Fiscal Year 2024
• A “foreign-controlled entity” (FCE) as defined per §7701(a)(51)(C) as an entity that is 50% or more owned by one of the following:
  
  • A government of one of the Covered Nations
  • An agency of one of the governments of a Covered Nation
  • A citizen or national from a Covered Nation (if not also a citizen, national, or green card holder of the United States) 
  • A company with its primary place of business in a Covered Nation

Foreign-influenced entity

As defined in §7701(a)(51)(D), an FIE is an entity where an SFE has “influence” in at least one of the following ways:

• An entity where the SFE has “direct authority” to appoint a “covered officer” (such as a board member, CEO, CFO, COO, general counsel, or senior vice president, defined in §7701(a)(51)(F))
• An entity that is 25% or more owned by an SFE
• An entity that is 40% or more owned by multiple SFEs
• An entity with 15% or more debt held by at least one SFE when issued
• An entity with “effective control” through contractual payments, as defined in the next section

Effective control restrictions

The OBBBA adds additional restrictions to entities that make “applicable payments” to an SFE during the taxable year through a binding contract or licensing agreement, therefore giving “effective control” (as defined in §7701(a)(51)(D)(ii)) over either the project, manufactured products, or eligible components as it relates to the claimed tax credits of §45Y, §48E, or §45X.  The IRS will provide additional guidance to aid developers in identifying an instance of effective control. In the meantime, entities should avoid giving potential SFEs the unrestricted contractual right to: 

• Determine the quantity or timing of production of an eligible component (for §45X)
• Determine the amount or timing of activities related to the production or storage of electricity (for §45Y or §48E)
• Determine which entity may purchase or use the eligible components or critical minerals
• Determine which entity may purchase or use the electricity
• Restrict access to data critical to production or storage of energy, or to the factory, mine, or mineral processing facility, to the personnel or agents of such contractual counterparty, or
• On an exclusive basis, maintain, repair, or operate any plant or equipment which is necessary to the production of eligible components or electricity

Effective control can also be triggered if a taxpayer enters into a licensing agreement with an SFE after the OBBBA date of enactment that gives the SFE a significant role. Entities should avoid giving potential SFEs the contractual right to:

• Specify or otherwise direct one or more sources of components, subcomponents, or applicable critical minerals to be used in an electricity or energy storage project, or in the production of an eligible component
• Direct the operation of an electricity or energy storage project, or a facility that produces eligible components or critical minerals
• Limit the taxpayer's utilization of intellectual property related to the operation of an electricity or energy storage project, or in the production of an eligible component
• Receive royalties for more than 10 years
• Require the taxpayer to enter an agreement for the provision of services for a duration longer than 2 years

In addition, manufacturers and mineral producers entering into licensing arrangements should have the “technical data, information, and know-how necessary to enable the licensee to produce the eligible component” without needing further involvement from the counterparty or other specified foreign entity. 

A bona fide purchase or sale of intellectual property is not subject to these restrictions. However, arrangements where the “ownership of intellectual property reverts to the contractual counterparty after a period of time” shall not be considered a bona fide purchase or sale.

Recapture for §48E ITCs

In §50(a)(4), the recapture risk for ITCs is extended to ten years if there is any “applicable payment” sent to an SFE, and therefore allowing that entity to have effective control. If any payment is made to an SFE in the ten years after the qualified facility is placed in service, then the entirety of the credit is clawed back. This provision applies to taxpayers who claim a credit for any taxable year beginning after July 4, 2027 (e.g., 2028 and beyond for calendar year filers). This may have the impact of shifting more developers towards claiming a §45Y credit over §48E, if they have the option to do so.

Risk of public companies becoming PFEs

Public companies are largely exempt from being considered an SFE (per §7701(a)(51)(E)), except in the instance where the company is traded on a market in a Covered Nation. Additionally, they are at risk of being considered an FIE if an SFE has the authority to appoint a board member or executive officer. Public companies are also at risk of giving “effective control” to an SFE through a contractual payment or licensing agreement. 

Transferred credits to SFEs

The OBBBA amended §6418(g) to prohibit the transfer of a §48E, §45Y, §45X, §45Q, §45U, or §45Z credit to an SFE. Therefore, tax credit transfer transactions involving these credits also need to diligence the purchaser. 

Determination

Entities are tested to determine if they qualify as SFEs and FIEs on the last day of the tax year for which the applicable credit is claimed (see §7701(a)(51)(A)(ii)). 

The only exception is the first taxable year after July 4, 2025, where the test takes place on the first day of the taxable year. Said another way, all entities will be tested on January 1, 2026, for the 2026 tax year, assuming they have a calendar fiscal year end.

Material assistance restrictions 

The OBBBA restricts developers’ ability to claim §45Y, §45X, and §48E credits if they receive “material assistance” from a “prohibited foreign entity” as defined in §7701(a)(52). Material assistance is represented as a percentage of the total direct costs that meet the compliance threshold (for the avoidance of doubt, these are costs that are NOT affiliated with a PFE). For §48E ITCs and §45Y PTCs, the costs analyzed are the labor and material costs of the manufactured products and their components used in qualified facilities. For §45X AMPCs, the costs are the direct material costs of eligible components and critical materials. 

In the case of §45Y and §48E credits, projects that begin construction for tax purposes before January 1, 2026, do not need to comply with material assistance requirements. The OBBBA codified that the beginning of construction rules in IRS Notices 2013-29 and 2018-59 (as well as any subsequently issued guidance clarifying, modifying, or updating either Notice), as in effect on January 1, 2025, apply to FEOC requirements. On August 15, 2025, the Treasury issued Notice 2025-42 modifying the BoC rules for wind and solar tax credit eligibility; however, the document reiterates in Footnote 3 that, “The guidance in this notice is not intended to address the beginning of construction rules for those foreign entity restrictions. The Treasury Department and the IRS are currently drafting additional guidance as is necessary and appropriate to implement those restrictions, as enacted by the OBBBA.”  

Material assistance for tech-neutral credits (§45Y and §48E)

§7701(a)(52)(A)(i) provides guidance on how to meet the “threshold percentage for qualified facilities and energy storage,” as defined based on the following cost ratio for the manufactured products involved:

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Total Manufactured Products Costs are the total direct costs for all “manufactured products (including components) which are incorporated into the qualified facility or energy storage technology upon completion of construction." Examples of manufactured products are solar modules and batteries that are produced in a factory, versus on-site construction materials.

Manufactured Products Costs Without Prohibited Foreign Entities are the total direct costs of manufactured products (including components) that are NOT “mined, produced, or manufactured by a prohibited foreign entity” (§7701(a)(52)(D)(i)(II)).

The “threshold percentage for qualified facilities and energy storage technology”, as defined in the above formula, must meet the requirements in the table below, depending on the year when the qualified facility or energy storage technology begins construction.

Threshold percentage requirements (§45Y and §48E)

Per §7701(a)(52)(B), the following threshold percentages apply for qualified facilities and storage technology claiming §45Y PTCs and §48E ITCs:

Material assistance for eligible components (§45X AMPCs)

For eligible components and critical minerals, §7701(a)(52)(A)(ii) provides guidance on how to meet the “threshold percentage for eligible components,” as defined based on the following cost ratio for the eligible components involved:

Total Eligible Components Costs are the direct material costs paid or incurred for production of the eligible components.

Eligible Components Costs Without Prohibited Foreign Entities is defined to be the direct material costs paid or incurred for production of the eligible components that are NOT “mined, produced, or manufactured by a prohibited foreign entity” per §7701(a)(52)(D)(ii)(II).

The “threshold percentage”, as defined by the above formula, must meet the requirements in the table below, depending on the year in which the component is sold.

Threshold percentage requirements (§45X AMPCs)

Per §7701(a)(52)(B), the following “threshold percentages” apply for eligible components or critical minerals claiming §45X AMPCs. Note that for applicable critical minerals, the “threshold percentages” will be updated by December 31, 2027, and the OBBB provides Treasury with the discretion to increase these amounts to consider several subjective factors, including domestic availability and processing capacity, supply chain constraints, and national security concerns. 

Documentation

Safe Harbor Tables

Per §7701(a)(52)(D)(iii), the IRS is expected to publish tables no later than December 31, 2026, to improve the ease of the calculation of the “threshold percentages” and provide all rules regarding material assistance (for §45Y, §48E, and §45X). 

Until these tables are published, taxpayers can use existing domestic content tables from Notice 2025-08, issued in January 2025, and included in Appendix D. The domestic content tables only apply to solar, onshore wind, and battery storage projects. Other project types will need to use the actual material and labor costs that developers paid (note: this contrasts with the domestic content calculations, which require supplier costs).

Certificates

Project developers and manufacturers will ask equipment suppliers to provide certificates confirming whether products were manufactured by PFEs, and whether there are any PFEs in the supply chain. The certificate should confirm the payment amount charged to the taxpayer for non-PFE goods (see §7701(a)(52)(D)(iii)). Certificates should be retained by both the taxpayer and supplier for six years and include the following:

• EIN Number of the supplier 
• Any foreign identification number
• Signatures from suppliers
• Statement about the relationship to a PFE, if applicable, for all Manufactured Products Costs or Eligible Components Costs

Material assistance exclusions

In the instance where the Manufactured Products Costs are derived from binding contracts and purchase orders entered into before June 16, 2025, the costs are excluded from the material assistance determination assuming the project begins construction by July 31, 2025, and is placed in service by December 31, 2029 (or by December 31, 2027 for solar or wind projects) (see §7701(a)(52)(D)(iv)). Similarly, for Eligible Components Costs, any costs incurred pursuant to binding contracts and purchase orders entered into before June 16, 2025, will also be excluded for eligible components sold by December 31, 2029.

Material assistance penalties

The IRS can challenge the material assistance determination anytime in the six years after the tax return is filed for a qualified facility, energy storage technology, eligible component, or critical mineral (see §6501(o)), and there are significant penalties if an inaccuracy is discovered. The penalties are calculated based on the understatement of income tax that occurred from the inaccurately claimed tax credit. The following penalties hold:

• Penalty to taxpayer: Per §6662(a), the penalty is 20% of the reduction in the tax basis that benefited from the tax credit if the taxpayer’s underpayment exceeds 1% of what they should have paid or $5,000, whichever is greater. Per §6662(d)(1)(B), if the taxpayer is a corporation, the penalty applies if the taxpayer’s underpayment exceeds 1% of what they should have paid or $10 million, whichever is less.
• Penalty to equipment supplier: Per §6695B, in the instances where a certificate (as described above and in §7701(a)(52)(D)(iii)) is inaccurate, the supplier of that certificate is subject to a penalty that is the greater of 10% of the understatement of the taxpayer’s tax basis, or $5,000. This penalty is only relevant if the understatement is greater than the lesser of 5% of the tax on the tax return or $100,000. Certificates provided before January 1, 2026, are exempt from this penalty.

Practical steps to maintaining compliance

To maintain compliance with PFE restrictions, Reunion recommends an ongoing audit of supply chain entities or potential tax credit purchasers and ongoing attention to contractual language in binding contracts or licensing agreements that could potentially provide “effective control” to a counterparty. 

PFE restrictions are evolving and will likely gain additional clarity with the publishing of Treasury regulations in 2026. As such, Reunion recommends working with a knowledgeable third party to ensure ongoing compliance with PFE restrictions as well as maintaining records demonstrating PFE compliance for at least six years.

High-level compliance checklist

The following items are overall suggestions of evidence to maintain for proving PFE compliance in an ongoing manner. These items are not exhaustive and, given the dynamic nature of PFE restrictions, should not be considered a comprehensive list.

Taxpayer-level SFE requirements

Maintain the following evidence to verify that the taxpayer itself is not an SFE.

• Documentation of ownership structure listing all entities with direct ownership of the taxpayer entity
• Certificates of formation/incorporation for all entities within the ownership structure
• Exchange listing documentation (for publicly traded entities)

Taxpayer-level FIE requirements

Maintain the following evidence to verify that the taxpayer itself is not an FIE.

• Documentation of ownership structure listing all entities with direct ownership of the taxpayer entity
• Certificates of formation/incorporation for all entities within the ownership structure
• Complete list of debt holders showing total debt amounts
• Documentation showing any SFE “direct authority” to appoint a “covered officer”

Effective control requirements

Maintain the following evidence to verify that over the previous tax year, an SFE did not hold “effective control”, as defined in §7701(a)(51)(D)(ii), over key aspects of the production of eligible components, energy generation in a qualified facility, or energy storage which are not included in the measures of control through authority, ownership, or debt.

• Operations, Maintenance, or Asset Management Agreements: including long-term service, performance, or dispatch authority terms
• Supply, Procurement, or Manufacturing Agreements: for equipment, components, or critical minerals, especially those specifying approved vendors or sourcing restrictions
• Power Purchase, Offtake, or Energy Storage Agreements: governing generation schedules, dispatch, or output allocation
• Licensing or Technology Agreements: covering intellectual property, software, or SCADA systems used in production or operation
• Construction or EPC Contracts: where counterparties retain operational authority, site access, or equipment control rights
• Joint Venture, Development, or Shareholder Agreements: involving shared governance, veto, or consent rights
• Financing, Lease, or Royalty Agreements: imposing operational conditions, long-term payments, or extended obligations
• Data Access or Remote Operations Agreements: granting privileged access to system controls or operational data
• Consulting, Technical Service, or Training Agreements: that create long-term dependence or ongoing foreign involvement

Material assistance requirements

Maintain the following evidence to verify that the labor and material costs of manufactured products and their components (§48E and §45Y) or the direct material costs of eligible components and critical materials (§45X)  used in a qualified facility exceeded the statutory thresholds for total costs not paid to a PFE  as defined in §7701(a)(52) of the U.S. Code.

Supply chain mapping

• Documentation listing all suppliers and sub-suppliers of Covered Items for each qualified facility, including entity names, addresses, and countries of formation/operation
• Bills of materials, purchase orders, and invoices identifying all Covered Items and their source entities
• Payment records and proof of transaction completion
• Agreements with contractors, subcontractors, and suppliers
• Confirmation of physical receipt or completion of services for the Covered Items

Supply chain mapping

• Documentation listing all suppliers and sub-suppliers of Covered Items for each qualified facility, including entity names, addresses, and countries of formation/operation
• Bills of materials, purchase orders, and invoices identifying all Covered Items and their source entities
• Payment records and proof of transaction completion
• Agreements with contractors, subcontractors, and suppliers
• Confirmation of physical receipt or completion of services for the Covered Items

48E recapture requirements

Maintain the following evidence to verify that no “applicable payments” to an SFE have been made that would entitle the SFE to exercise “effective control” (as defined in §7701(a)(51)(D)(i)(II)), during the ten-year period after the facility has been placed in service.

• Operations, Maintenance, or Asset Management Agreements: including long-term service, performance, or dispatch authority terms
• Supply, Procurement, or Manufacturing Agreements: for equipment, components, or critical minerals, especially those specifying approved vendors or sourcing restrictions
• Power Purchase, Offtake, or Energy Storage Agreements: governing generation schedules, dispatch, or output allocation
• Licensing or Technology Agreements: covering intellectual property, software, or SCADA systems used in production or operation
• Construction or EPC Contracts: where counterparties retain operational authority, site access, or equipment control rights
• Joint Venture, Development, or Shareholder Agreements: involving shared governance, veto, or consent rights
• Financing, Lease, or Royalty Agreements: imposing operational conditions, long-term payments, or extended obligations
• Data Access or Remote Operations Agreements: granting privileged access to system controls or operational data
• Consulting, Technical Service, or Training Agreements: that create long-term dependence or ongoing foreign involvement

Guidance and resources

Guidance

• July 4, 2025: One Big Beautiful Bill Act, Chapter 5.

Resources

The OBBBA passed on July 4, 2025, and federal resources are still being updated with amended sections. 

President Trump issued a July 7, 2025, Executive Order signaling that further guidance may be released as soon as 45 days after the enactment of the bill, and Notice 2025-42 denoted that guidance relating to FEOC restrictions is still forthcoming. The IRS will also release guidance on identifying PFEs no later than December 31, 2026 (see §7701(a)(51)(D)(iii)). 

Frequently Asked Questions about Prohibited Foreign Entities

1. How do PFE restrictions most impact eligibility for clean energy tax credits and financing?
   
   1. PFE restrictions, as introduced by the OBBBA, prohibit Prohibited Foreign Entities (PFEs) from claiming §45Y, §48E, §45X, §45Q, §45U, and §45Z tax credits. Additionally, tax credits may not be transferred to a PFE.
2. What supply chain tracing methodologies are being accepted to demonstrate compliant sourcing of critical minerals and components?
   
   1. Taxpayers will need to verify which entities in their supply chains are considered PFEs and ultimately comply with the statutory supply thresholds specified by the IRS and Treasury. Per §7701(a)(52)(D)(iii) of the U.S. Code, the IRS is expected to publish tables no later than December 31, 2026, to improve the ease of the calculation of the “threshold percentages” and provide all rules regarding material assistance (for §45Y, §48E, and §45X). Until these tables are published, taxpayers can use existing domestic content tables from Notice 2025-08, issued in January 2025. The domestic content tables only apply to solar, onshore wind, and battery storage projects. Other project types will need to use the actual material and labor costs that developers paid (note: this contrasts with the domestic content calculations, which require supplier costs)
3. How can developers assess PFE risk exposure during early procurement planning for battery, solar, or wind projects?
   
   1. Developers should work with a knowledgeable third party during the procurement phases of a project to ensure that the required percentage of components is sourced from non-PFEs. There are a number of technology and service vendors in the space that are able to assist developers with this assessment. 
4. What due diligence frameworks or certifications are recognized to prove PFE compliance?
   
   1. Given that the PFE requirements introduced by the OBBBA are so new, as of this writing, there are no widely accepted comprehensive formats for demonstrating PFE compliance. That said, §7701(a)(52)(D)(iii) of the U.S. Code provides some guidance on the information that should be included in supplier PFE certifications. Until Treasury guidance is released in 2026, Reunion recommends working with a knowledgeable third-party to gather and document PFE compliance in an ongoing fashion. 
5. How might evolving geopolitical designations of SFEs affect long-term asset compliance for operational projects?
   
   1. The recapture provisions surrounding §48E tax credits with respect to PFE compliance specify that any “applicable payment” as defined in §7701(a)(51)(D)(i)(II) of the U.S. Code, to an SFE that provides the SFE with “effective control” during the ten years after a facility has been placed in service, could result in the recapture of the entire tax credit. Given this risk, it will be important to clarify if evolving SFE designations need to be taken into account when tracking any “applicable payments” to potential SFEs during the recapture period.
6. How can joint ventures or partnerships with foreign investors navigate FEOC limitations without jeopardizing credit eligibility?
   
   1. Developers should work with a third party with expertise in PFE compliance when navigating credit eligibility in a situation where foreign investors are involved. Developers should ensure documentation of any internal investigations into foreign investors' PFE status, as well as document foreign investors’ corporate formation documents, while ensuring that the investors are not SFE.

The rush to close out 2024 tax credits is finally coming to an end, with the October 15 tax filing deadline approaching. Read on for highlights on what the Reunion team has been seeing in the tax credit market, along with recent deal highlights.

What we’re seeing in the market:

More buyers are looking to delay payments for 2025 credits until 2026

• Due to the OBBBA, some corporations overpaid their estimated quarterly taxes relative to what they will end up owing for 2025. Therefore, they prefer delaying payments for tax credits until 2026, because they do not anticipate realizing the benefit of the credits until April 15, 2026
• We have observed more buyers looking to pursue carrybacks to offset prior year taxes; carryback buyers typically seek delayed payment terms, given uncertainty around when they will receive tax refunds from the IRS
• In general, we have seen an increasing share of transactions occurring well into the following calendar year, and expect this seasonal trend to continue. For example, Reunion closed approximately 15 transactions for the 2024 tax year, totaling over $550M in credit volume, in the weeks leading up to October 15, 2025

Sellers are showing flexibility in pricing for investment-grade buyers that are willing to forward commit to ITCs that will be generated in 2026 or 2027

• Sellers are unable to get high advance rates from lenders for tax credit transfer bridge loans without a committed buyer. The net advance rate is typically <70% of the face value of the tax credits
• Sellers are showing flexibility in pricing to secure commitments from investment-grade buyers to purchase credits generated in 2026 or 2027
• Reunion has also partnered with a major financial institution to offer forward ITC and 45X commitments for 2026 or 2027 credits with at least $50M in volume; please contact us for pricing and further details

Buyers are demanding §45U credits, and pricing remains high

• A number of large Reunion clients are focused specifically on identifying §45U credits, which are production-based credits generated by nuclear power facilities. Buyers are drawn to the relatively straightforward diligence process, lack of §50 recapture risk, and the current administration’s general support of nuclear power
• Spot 2025 pricing for credits remains elevated due to the fairly small universe of §45U credit sellers; as with other credits, buyers willing to enter into a multi-year agreement can achieve a 1 to 2.5 cent discount on pricing, depending on the length of commitment

Highlights from Recently Closed Transactions

Project Wind River

$150M+ in §45U nuclear credits transacted on a very short closing timeline due to high demand

‍Credit type: §45U
Overview: Reunion brought two highly motivated, publicly traded companies together to transact on §45U nuclear credits, going from a signed term sheet to closing in two weeks.
Highlights: Looming deadlines meant both buyer and seller needed to lean on legal and advisory resources, including Reunion, to negotiate terms and move quickly through due diligence and approvals.

Project Ginkgo

$75M+ in §48 credits from battery storage project with deferred payment schedule

Credit type: §48
Overview: Reunion worked with a repeat client to sell tax credits from a battery storage project to a publicly-traded buyer.
Highlights:The purchaser was able to offer a premium price in exchange for deferred payment, which was attractive given the seller’s access to low-cost capital. Resulting payment will take place over a year after the project was placed in service.

Reunion's Compliance Software

Tracking Prevailing Wage and Apprenticeship compliance for a large solar developer

‍Credit type: §48E
Overview: Reunion is under contract with a major solar developer to manage PWA compliance for their entire 2025-2026 portfolio. Reunion's report is a key piece of documentation for the developer's tax equity partner, which is a leading bank.
Highlights: The tax equity partner will receive frequent and thorough PWA updates via Reunion's software throughout the construction and O&M phases. It was critical for the tax equity partner to gain comfort with Reunion's PWA compliance process prior to closing the transaction.

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Economics

What do transferable tax credits typically cost?

Tax credits generally range in price from $0.90 to $0.96. These prices are “all in,” meaning that the cost of tax credit insurance and any broker or intermediary cost is typically borne by the seller. The seller will also typically reimburse buyers for a capped amount of third party legal and diligence fees.

§48 investment tax credits from large, reputable sellers have historically traded in the $0.93 to $0.95 range. In late 2024 and early 2025, we observed sizable ($75M+) credits from investment-grade sellers for the 2024 tax year trading in the $0.95 range. Factors that impact pricing include:

• Financial strength of seller: Buyers pay a premium when seller has a strong balance sheet or investment-grade credit rating
• Credit type: There is more buyer demand for large utility scale projects versus distributed portfolios. Additionally, advanced manufacturing, solar, wind, storage and nuclear have more demand than renewable natural gas or carbon capture technologies
• Volume of opportunity: Buyers pay a premium for larger opportunities ($75M to $100M+). Very small opportunities (<$10 or $15M) have a larger discount due to relatively low absolute savings amount
• Payment terms and timing: Buyers pay a premium for delayed payment terms. Pricing also tends to increase the later a transaction occurs, as project supply dwindles and more last-minute buyers come into the market. Conversely, pricing tends to decrease for forward commitments, especially for those with longer time horizons into future tax years 

Leading project developers often have lofty expectations on the pricing they expect to receive on their credits, and as a result there is often a robust back and forth before settling on a price.

Who pays for tax credit insurance?

Sellers typically purchase tax credit insurance, with the buyer listed as an “additional insured” on the policy. Buyers occasionally elect to purchase tax credit insurance instead of the seller, but this scenario is far less common.

Who pays for legal and diligence fees?

To minimize “above-the-line” expenses, buyers typically negotiate for sellers to pay a capped reimbursement amount for documented third party legal and / or diligence fees. The reimbursement is generally an absolute dollar amount (versus a percentage of the credit amount), and generally increases based on the complexity of the transaction. For example, a portfolio with many projects is likely to have a larger expense reimbursement compared to a single utility-scale asset.

Is the benefit — the difference between the face value of the credits and the purchase price — taxable?

The benefit is not subject to federal tax. While many states have rolling conformity to federal taxation rules, we recommend checking with your tax advisor on state-level taxation issues.

Markets

What other corporations are active in purchasing transferable tax credits?

Although public disclosures are very rare, Fortune 500 companies from nearly every sector are actively purchasing clean energy credits. Examples of publicly disclosed transactions include: 

• Visa: $870M tax credit purchase from First Solar
• Fiserv: $700M tax credit purchase from First Solar
• MarketAxess: $16M tax credit purchase from Broadwind

What is a typical tax credit purchase amount?

Reunion maintains a database that monitors over $25B of tax credit transactions. We observe that a majority of transactions are in the $15M to $200M range, though we have worked on multiple individual transactions in the $1 billion range.

Corporate taxpayers can offset up to 75% of their federal tax liability with general business credits, which include transferable tax credits. According to a 2024 Reunion survey, 85% of surveyed tax credit buyers plan to offset at least 50% of their tax liability using transferable tax credits.

Risks

What are the primary risks associated with purchasing a tax credit?

§48 ITCs are subject to several primary areas of risk, which buyers should thoroughly diligence:

• Qualification: Validate that the underlying project qualifies as energy property, the proper cost basis is used, and the project was placed in service in the appropriate tax year. If applicable, validate qualification for bonus credit adders such as energy community and domestic content. If applicable, the buyer should also validate that the project complies with Prevailing Wage and Apprenticeship requirements (for projects above 1 MW that began construction on or after January 29, 2023) and Foreign Entity of Concern restrictions (see below for more commentary on FEOC).
• Structure: Validate that seller is an eligible transferor, and that the seller’s underlying legal structure will be respected by the IRS.
• Recapture: ITCs 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. Practically speaking, recapture can occur in the following scenarios: (1) the property ceases to be a qualified energy facility or (2) there is a change in ownership of the property.
• Counterparty: 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. Additionally, buyers should understand the financial strength of the seller and, by extension, the “value” of the seller’s indemnity and / or guaranty

How do I ensure that the tax credits apply to the appropriate tax year?

The placed in service (PIS) date determines the tax year to which the credits can be applied. A project that is placed in service in 2026, for instance, generates ITCs that can be applied to a company’s 2026 tax liability (for calendar-year filers). As part of due diligence, the buyer should review documentation substantiating when the project was placed in service; the IRS employs a five-factor test to determine when a project is PIS for tax purposes.

There is a risk that a PIS date “slips” into a subsequent tax year, and the buyer is unable to apply the credits to a given tax year as planned. To mitigate this risk, buyers will often negotiate a two-tiered pricing approach, in which the price per credit is reduced if the credits slip from one year to the following (we have seen this discount commonly range from 1.5 to 3 cents).

Have other tax credit buyers been subject to audit activity?

There are many tax credit buyers that are in the Compliance Assurance Process (CAP) program; CAP buyers assume that the IRS will audit their tax credit purchase activity at some point. These buyers typically prioritize ensuring that they have all necessary documentation prepared in advance, in the event of an IRS information document request (IDR). 

Reunion has worked with several companies in the CAP program that have satisfactorily responded to audit activity, including responding to IDRs.

We have not yet heard of buyers outside the CAP program subject to audit activity from tax credit transfers, but we do expect that it will happen.

Describe how the process works if the IRS does challenge a credit?

Tax proceedings are one of the heavily negotiated points in a tax credit transfer agreement (TCTA).

If the IRS performs an audit of the tax credit buyer and determines that the credits are excessive or invalid, the buyer will typically request an appeal with the IRS Independent Office of Appeals.

If the IRS Independent Office of Appeals upholds the decision, the buyer or the tax credit insurer may choose to proceed to litigation, typically in U.S. District Court or in U.S. Tax Court. The obligation to proceed to litigation, and how far to take the litigation (instead of triggering an indemnity payment from the seller) is a point of negotiation between buyers and sellers. 

Tax credit insurers typically will include the right to litigate as part of the terms and conditions of the tax credit insurance policy, as the insurer will want the opportunity to litigate before needing to pay out a claim.

If there is a successful challenge or disallowance of the credit by the IRS, will I be made whole? 

In case there is a loss event, a well-negotiated Tax Credit Purchase Agreement will ensure that the buyer will be made whole through the indemnity and / or tax credit insurance. The protections are designed to cover all potential losses, including penalties, interest, taxes, contest costs, and fees.

What are common negotiation points related to tax credit insurance?

One common point of negotiation between buyers and sellers is defining the scope of the tax credit insurance policy, and ensuring that the buyer is comfortable with the covered tax positions as well as any potential exclusions to the policy. 

The other primary point is to define the limit of liability on the policy, to ensure that the buyer will be fully covered in the event of a loss. Buyers sometimes agree to a lower limit of liability in exchange for better pricing on the credit, or in cases where they see other factors that reduce risk on the transaction (e.g., strong seller balance sheet).

Legislative

Under what conditions are credits subject to new OBBBA provisions, such as foreign entity of concern (FEOC)?

Projects that began construction before the end of 2024 have the option to qualify for §48 credits rather than §48E credits. §48 credits are not subject to FEOC restrictions.

§48E credits that begin construction before the end of 2025 are not subject to the FEOC material assistance restrictions, which limit the amount manufactured products that can originate from restricted countries (China, Iran, North Korea, and Russia).

What happens if there’s another change in law between when execution of a tax credit transfer agreement, and funding of the transaction?

The tax credit transfer is not officially consummated until the transfer election statement is filed when the buyer and seller file their tax returns. Buyers typically negotiate TCTAs to include “no change in law” as a condition precedent (CP) to funding. Therefore, if there is a significant change in law between signing the TCTA but before funding, the buyer would have the option to walk away from the transaction.