Six Tax Credit Takeaways from Analyzing 6,000 Public Company Filings

The market for clean energy tax credit transfers has accelerated rapidly in 2024, as corporate tax and treasury leaders see a significant new opportunity to reduce tax liabilities and increase corporate cash availability.

A complete transferable clean energy tax credit transaction, from identifying the opportunity to closing the deal, can be summarized in seven key steps.

Step 1: Build your company's internal business case

Duration: Varies by company.

Goals and activities

How Reunion helps

Through an introductory call, Reunion's transactions team can equip your company with insights on eligibility, appropriateness, market dynamics, and risk. We can also help your team prepare a business case/investment committee memo and provide supporting materials. For larger organizations, Reunion has organized tax credit "workshops," which we have found are particularly effective for aligning multiple functional teams.

Key resources

• Transferable tax credit handbook
• How early investors are approaching clean energy tax credits
• Sample business case or investment committee memo (by request)

Step 2: Identify and formally express interest in projects

Duration: One to three weeks.

Goals and activities

How Reunion helps

Reunion takes a "push" and "pull" approach when helping companies find projects that most align with their needs. On the "push" front, we curate a list of tax credit opportunities based on the criteria we identified in step one and share it with your team. For many companies, we do this on a rolling basis as new projects join our platform. On the "pull" front, we provide your team with access to our managed tax credit marketplace, where we have over $7B (and growing) in near-term tax credits available.

Once your team has the right project(s) in mind, Reunion will populate our form term sheet on your company's behalf. We'll levarage our market intelligence to ensure your proposal is competitive and assist you in negotiating key terms, like timing of payment, indemnification, and tax credit insurance.

Key resources

• Tax credit marketplace
• Transferable tax credit transactions tracker
• Unlocking the economic benefits of tax credits before payment
• Sample term sheet (by request)

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Step 3: Conduct Reunion-led preliminary due diligence

Duration: One to two weeks.

Goals and activities

How Reunion helps

Reunion conducts a preliminary screen to identify any major issues up front ("fatal flaw" due diligence analysis). From that point, we consult with your team to assess risks and recommend appropriate mitigation strategies. Importantly, this step ensures alignment of incentives: we do not want to move a transaction forward unless there is a high probability of success.

We also provide validated market intelligence to compare your proposed transaction to the risk/reward profile of similar tax credit opportunities in the market.

Key resources

• Buying and selling clean energy tax credits
• What should corporations expect to pay for clean energy tax credits?
• Due diligence checklist (by request)

Step 4: Conduct comprehensive due diligence

Duration: Two to six weeks. The precise duration depends largely on the number and relatively complexity of projects in the transaction.

Goals and activities

How Reunion helps

Reunion spearheads the due diligence process by:

• Reviewing documents provided by the Seller, and requesting any missing or incomplete information
• Creating and organizing a data room, ensuring that due diligence documentation meets Reunion's checklist of required documentation
• Reunion will produce a summary due diligence memorandum summarizing our findings and highlighting any areas of concern
• If you are working with additional diligence advisors, Reunion will work closely with advisors to organize and accelerate their review process, reducing costs

Key resources

• Due diligence checklist (by request)

Step 5: Procure tax credit insurance (if needed)

Duration: This step is optional and runs in parallel to step 4.

Goals and activities

How Reunion helps

Reunion can help companies decide if insurance is an appropriate risk mitigation tool for their transaction. If we collectively determine that tax credit insurance makes sense, we can advise on insurance offerings, including the scope of coverage – e.g., structure, qualification, recapture, PWA, bonus credit adders – and where gaps might exist.

We can also help you validate that the insurance policy is appropriately sized and includes penalties and tax gross-up and contest costs.

Key resources

• Tax credit insurance helps power up credit transfers

Step 6: Sign tax credit transfer agreement

Duration: This step runs in parallel to step 4.

Goals and activities

How Reunion helps

Reunion streamlines the negotiation process for buyers and sellers by providing a template legal document and helping parties focus on the most pertinent deal topics.

Key resources

• Common terms and negotiation strategies for tax credit transfer agreements

Step 7: Post-transaction support

Duration: Ongoing duration depending on credit type.

Goals and activities

How Reunion helps

Our transactions team will issue both parties reminders about filing requirements and deadlines, including tax forms and compliance. In subsequent tax years/quarters, Reunion will provide early acccess to new deals.

Key resources

Get started

Reunion’s team of clean energy and tax credit experts are here to support you through the entire process of buying and conducting due diligence on  IRA tax credits. We draw on our deep expertise to help you navigate tax credit transactions, and our marketplace features the widest pool of tax credit opportunities available in the industry.

Our key differentiators include:

• Widest pool of high quality tax credits: We curate opportunities from our $10B+ marketplace, featuring technologies and projects ranging from under $3M to $300m+
• Extensive educational materials: We offer an extensive resource library featuring content on financial, legal, and market-related topics pertaining to IRA tax credits
• Hands-on due diligence: We support buyers throughout the transaction process, ensuring that the due diligence is performed at high quality and that risks are minimized upfront, saving you time and expense
• Industry-leading transaction team: Reunion has facilitated more than $2 billion in tax credit transfers in 2024. Our transaction team consists of industry veterans, with experience raising $5+ billion in clean energy project financing `with partners such as US Bank, JP Morgan, Wells Fargo, Bank of America, Key Bank, PNC, Nord/LB, D.E. Shaw, First Reserve, and over a dozen Fortune 500 companies
• Market intelligence tools: Available upon request, we offer proprietary insights on tax credit pricing and data on key trends

Overview

For corporate taxpayers who are considering purchasing tax credits in 2024, please join Reunion's transactions team – with 50+ years of combined experience in tax credits – for a 60-minute workshop to walk through a sample tax credit transfer.

The webinar will equip tax and treasury teams with the information and resources they need to efficiently pursue a tax credit transaction.

Topics

The interactive workshop will include three 15-minute modules and five minutes of Q&A per module.

Speakers

Reunion's CEO, Andy Moon, and President, Billy Lee, will co-host the webinar. Over the course of their careers in clean energy financing, Andy and Billy have executed over $2B in transactions across a range of technologies.

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On April 25, the Treasury and IRS published final regulations for the Inflation Reduction Act’s tax credit transfer mechanism. The IRS also published a press release and updated their transferability FAQs.

The final regulations carried few surprises – other than, perhaps, arriving earlier than some market participants predicted – and preserved the status quo set by the June 2023 guidance.

At Reunion, we welcomed this "non-event" and the clarity it provided, and wanted to highlight several key consistencies.

Highlights from the final regulations

Individuals, trusts, estates, and closely held C corporations remain largely on the sidelines

Despite “many comments” calling for a change, widely held C corporations will remain the primary buyers of transferable tax credits. While this decision will likely decrease overall liquidity in the tax credit market, it will also limit the potential for fraud and abuse.

Passive activity rules generally limit individuals, trusts, estates, and closely held C corporations to applying transferable tax credits to passive income – not active income. The final regulations did not adjust this stance. (However, a potential exception exists for certain closely held C corporations, which allows them to offset active income with tax credits.)

Deprecation cannot be transferred

The IRS did not change its stance on depreciation. As the FAQ states, “Only a taxpayer that has an ownership interest in the project may claim tax depreciation. Transferability does not allow depreciation benefits to be transferred.”

Bonus credits cannot be sold separately

The IRA created three bonus, or adder, credits, which can increase the value of a clean energy project’s tax credits:

• Energy communities
• Low-income communities
• Domestic content

The Treasury’s June guidance stated that bonus credits cannot be sold separately from a project’s other credits. A developer cannot, in other words, sell its base credits to one company and its bonus credits – perhaps at a different price per credit – to another company.

Instead, all credits must be sold as “vertical slices” and be pari passu to one another. In practice, if a single project has multiple buyers for its credits, all buyers have the same risk exposure.

April’s regulations did not change the Treasury’s position. 

The "intends to purchase" provision remains unchanged

Tax credit buyers can still "take into account a specified credit portion that it has purchased, or intends to purchase, to calculate its estimated tax payments." Of course, buyers remain liable for any underpayments.

The regulations clarified that the "intends to purchase" language "illustrates that all the requirements of proposed §1.6418-2(b) do not have to be met for a transferee taxpayer to take the expected eligible credit into account in its estimated tax calculations."

Generators of §45X, §45V, and §45Q credits can make facility-specific elections for transferability or direct pay

An advanced manufacturer’s decision to use transferability or direct pay to monetize their §45X tax credits need not be binary. If a manufacturer has multiple facilities, they can make the transferability-or-direct-pay decision at the facility level. If a manufacturer only has one facility, however, their decision is binary.

The same optionality holds true for the §45V PTC for clean hydrogen and §45Q PTC carbon capture, although the timing of the election varies by credit:

• §45V PTC: The direct pay/transfer election is made during the taxable year the qualified clean hydrogen production facility is placed in service
• §45Q PTC: The direct pay/transfer election is made during the taxable year the “single process train” is placed in service 
• §45X AMPC: The direct pay/transfer election is made during the taxable year in which eligible components are produced

Importantly, because the §45X election is made during the taxable year in which an eligible component is produced, production facilities that predated the IRS may be eligible for the credit.

Advanced cash payments for multi-year PTCs are not permitted – but borrowing against expected future tax credit payments is permitted

Although “upfront payments for PTCs determined in future taxable years are standard in tax equity transactions,” the final regulations stated that transferred PTCs must be paid for in cash one year at a time. This holds true for ten- and 12-year PTCs. 

Permitting advanced payments would “raise several complex legal and administrative issues, such as whether an excessive credit transfer has occurred or if the eligible taxpayer has gross income if prepaid eligible credits were not transferred in a later tax year."

On an encouraging note, the final regulations specifically state that “there is no prohibition on either a transferee taxpayer” – that is, a tax credit buyer – “or another third-party loaning funds to an eligible taxpayer, including loans secured by an eligible credit purchase and sale agreement.” 

Intermediaries can serve as brokers but not dealers

The final regulations, unsurprisingly, left unaltered the assumed role of tax credit intermediaries (like Reunion) in the transferability market. Intermediaries can serve as brokers and facilitators in tax credit transfers, helping to match and advise buyers and sellers. 

Intermediaries cannot, however, serve as dealers, effectively taking ownership of a tax credit with the intent of transferring/selling it again. 

“Required minimum documentation” remains the same

The final regulations acknowledge calls for an increase to the amount of required minimum documentation that an eligible taxpayer must provide to a transferee taxpayer to make a valid transfer. 

Nonetheless, the Treasury and IRS left the required minimum unchanged. Perhaps as a nod to the validity of increasing the required minimum, the final regulations remind market participants that, “...while the required minimum documentation requirements are the same for all taxpayers, any particular agreement between an eligible taxpayer and transferee taxpayer may go beyond the required minimum documentation based on the arrangement of the parties. The proposed regulations allowed sufficient flexibility for market participants to determine if more information is necessary in a particular transaction, while balancing the burden of producing the required minimum documentation required to make a transfer election.”

The final regulations also remind market participants that "§6418(g)(2)(B) specifically places a due diligence responsibility on the transferee taxpayer."

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Improvements likely coming to the pre-registration portal

The IRS opened the tax credit pre-registration portal in December to significant fanfare. But, as with any brand-new IT system, there have been calls for improvement.

While the IRS would not commit to set application review times, it left the door open to "continue to review the efficiency of the registration portal, including functionality responses from the public, to determine whether changes should be implemented or whether additional guidance or publications should be issued."

Plenty more guidance to come in the next 20-ish business days

In Norton Rose Fulbright’s annual Cost of Capital call, the panelists aptly brought attention to the Congressional Review Act, which “is a tool Congress can use to overturn certain federal agency actions.”

With respect to the Inflation Reduction Act, an incoming Congress (backed by a Trump administration) could use the CRA to unwind IRA regulations that were issued within 60 legislative days of the previous Congress.  

Although the exact date for the beginning of the 60-day window remains to be seen, it’s potentially in late May or early June. This gives the Treasury and IRS a little over 20 business days to issue a backlog of IRA-related guidance and regulations. 

The IRS 2023-2024 Priority Guidance Plan details what guidance the IRS is prioritizing through the end of the plan year, which is June 30, 2024.

Discuss the regulations with Reunion

Please contact Reunion's transactions team to understand how these final regulations could impact your organization's plans to purchase clean energy tax credits.

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The IRA created a new clean energy tax credit, the §45X AMPC

The Inflation Reduction Act of 2022 introduced a new class of production tax credit — the §45X advanced manufacturing production credit (AMPC). The credit is for eligible components produced and sold after December 31, 2022 and is transferable under §6418.

The §45X tax credit is generated via the production and sale of:

• Sustainable energy components: Five categories of eligible sustainable energy components including solar modules, battery cells, or wind blades, nacelles, or towers
• Critical minerals: 50 applicable critical minerals that attain a specified purity level

A list of eligible components, critical minerals, and related tax credit amounts is included below.

§45X transfers have taken off since the IRS issued guidance in December 2023

In December 2023, the Department of the Treasury released proposed regulations on §45X tax credits, which opened the door for transactions to begin.

Notably, Fiserv (NYSE: FI) agreed to purchase $700M in §45X tax credits from First Solar (NASDAQ: FSLR) at a price of $0.96 per dollar of credit, resulting in $28M of tax savings for the 2023 tax year. The public announcement of a large-scale transaction has led to significant interest from corporate buyers in §45X tax credits.

Key characteristics of §45X AMPCs

Generated over time

§45X AMCPs are generated on a rolling basis from the (i) production and sale of eligible components or the (ii) conversion of critical minerals to a specific purity level. As we'll discuss below, this opens the door for buyers to negotiate quarterly or monthly payment terms.

No recapture risk or prevailing wage and apprenticeship requirement

There is no recapture or prevailing wage and apprenticeship (PWA) provision, reducing risk associated with §45X tax credits.

Eligible for direct pay or transfer

As with §45Q and §45V credits, generators of §45X credits may elect to be treated as an “applicable entity” for the limited purpose of making an elective payment election, also known as direct pay.

Careful consideration should take place before electing in or out of direct pay for §45X credits. The election is rigid in that there are no partial elections:

• The election applies to all eligible credits from the applicable facility, and
• The election applies to the entire taxable year for which the election was made and all subsequent taxable years ending before January 1, 2033

Additionally, an electing taxpayer may file an irrevocable election to revoke the elective payment, but the revocation applies to the entire taxable year in which the election to revoke takes place and all subsequent taxable years remaining before January 1, 2033.

In short, AMPC generators may elect to take five years of direct pay with the IRS or transfer the credits to another taxpayer, and the ability to do both is significantly limited.

Commercial guidelines for buyers of transferred §45X tax credits

Sellers

Sellers of §45X tax credits range from large, multinational companies to smaller, domestic producers. Tax credit buyers may require sellers to procure tax credit insurance if there is uncertainty around their longevity and/or ability to cover indemnities relating to the sale of credits.

"Unaffiliated third party" buyers

In order to generate AMPCs from the production and sale of eligible components, buyers of manufactured components must be unaffiliated third parties unless a related party election has been made under §45X(a)(3)(B).

All sales must be for “productive purposes” and not solely to claim the §45X tax credit.

Pricing

In Q1 2024, median pricing to buyers ranged from $0.91 to $0.95 for single-year 45X credits. The relatively high pricing reflects the lower risk profile of AMPCs compared to investment tax credits (ITCs).

Drivers of larger price discounts include smaller transaction sizes, less established sellers, and forward contracts for credits that have not yet been generated.

Payment terms

AMPCs are sold in arrears of generation. Unless the AMPCs are sold in a single closing, most sellers will accept quarterly or monthly payment terms, allowing buyers to recognize the value of the credit before issuing payment to sellers.

Due diligence checklist for §45X tax credits

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

Buyers and their advisors should conduct due diligence on several core aspects of §45X tax credit qualification to avoid a situation where credits are improperly accounted for and subsequently disqualified — a risk that flows through to the buyer in a transferability transaction. To guide this process and mitigate potential risks, refer to the 45X Due Diligence Checklist.

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Eligible components and related §45X tax credit amounts

The table below shows the eligible components that qualify for §45X credits as well as the amount of tax credit.

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Subject to a four-year phase-out (except for critical minerals)

With the exception of critical minerals, the amount of credit begins phasing out for sales occurring after December 31, 2029. As a result, the amount of tax credit is 75% for components sold during calendar year 2030, 50% for components sold during calendar year 2031, 25% for components sold during calendar year 2032, and 0% thereafter.

Learn more

Reunion is actively transferring §45X tax credits from a variety of clean energy manufacturers. To learn more about sourcing, diligencing, and purchasing §45X AMPCs, please contact Reunion's experienced transactions team.

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Reunion is excited to host quarterly “office hours” for clean energy developers who would like to learn more about our marketplace and get a pulse on the overall transferability market.

Hosted on a quarterly basis

We will generally hold office hours on a quarterly basis and open registration one or two months in advance.

Designed for clean energy developers and manufacturers

Our office hours are designed for clean energy developers and manufacturers who have transferred, or are planning to transfer, IRA tax credits over the next 12 months. Developers need not have projects in Reunion's marketplace to participate.

Co-hosted by Reunion's founders

Reunion's founders, Billy Lee and Andy Moon, will co-host the hour-long sessions.

Billy and Andy pioneered solar financing structures with tax equity and private equity investors, leading some of the first solar transactions with institutions such as US Bank, JP Morgan, Wells Fargo, Bank of America, Key Bank, PNC, Nord/LB, D.E. Shaw, and First Reserve.

Questions welcome!

We want our office hours to be interactive, so please bring any questions you have, whether related to current market conditions, pricing, or commercial terms.

You're welcome to ask questions beforehand.

The latest energy community guidance, which meaningfully expanded the number of qualifying areas, placed the 10% adder back in the spotlight for the transferable tax credit marketplace. At the same time, Reunion has observed a marked increase in the number of projects in our marketplace claiming the energy community bonus.

While our transferable tax credit handbook goes deep on energy communities, we wanted to share a comprehensive (and refreshed) look at the adder.

Our guide begins with the basics, so we invite you to jump ahead.

• Background and scope
• Credit and project eligibility
• Diligence
• Guidance
• Annual updates to areas qualifying as energy communities
• Resources

Background And Scope

The Inflation Reduction Act created three bonus credits, or "adders"

The Inflation Reduction Act (IRA) created three "bonus" credits that can increase the value of a clean energy project's transferable tax credits:

• Domestic content: 10% bonus
• Energy community: 10% bonus
• Low-income community: 10% or 20% bonus

The energy community adder provides a 10% bonus credit

The energy community bonus provides a 10% increase to a project's credit value if the underlying project is located in an energy community (and meets prevailing wage and apprenticeship requirements).

A utility-scale solar project, for instance, that meets PWA requirements would receive tax credits worth 30% of its eligible cost basis. If the same project is located in an energy community, it would receive tax credits worth 40% of its eligible basis.

The IRA defines three types of energy communities

To qualify for the energy community bonus, a project must be located in at least one of three energy community "categories."

Category 1: Brownfield

‍A brownfield site is defined in 42 U.S.C. § 9601(39)(A) as "real property, the expansion, redevelopment, or reuse of which may be complicated by the presence or potential presence of a hazardous substance, pollutant, or contaminant" (as defined under 42 U.S.C. § 9601), and includes certain "mine-scarred land" (as defined in 42 U.S.C. § 9601(39)(D)(ii)(III)). A Brownfield site does not include the categories of property described in 42 U.S.C. § 9601(39)(B).

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

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

Category 2: Coal closure

A census tract (or directly adjoining census tract): 

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

Category 3: Statistical area

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

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

The scope of "direct employment" is determined by ten NAICS codes.

No double bonus for multiple energy communities

If a clean energy project is located in two energy communities – a brownfield site within a coal community, for instance – the bonus remains 10%. Developers cannot double up.

Bonus credits cannot be sold in stand-alone tranches

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

Credit And Project Eligibility

Four IRA credits are eligible for the energy community bonus

The IRA created 11 transferable tax credits, four of which are eligible for the energy community bonus:

• §45 PTC: Electricity produced from certain renewable resources
• §45Y PTC: Clean electricity production credit
• §48 ITC: Energy credit
• §48E ITC: Clean electricity investment credit

§48 and §48E ITC eligibility determined on placed-in-service date

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

Because eligibility is determined on a PIS date that is subject to potential delays, developers should think carefully about how to incorporate the statistical area category into their financial assumptions.

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

§45 and §45Y PTC eligibility determined annually with a beginning-of-construction safe harbor

For projects that claim a production tax credit under §45 or §45Y, eligibility for the energy community bonus credit must be determined every year during the ten-year PTC period. Theoretically, a wind project could qualify one year under the statistical area category but not qualify the following year because of a change in employment rates.

However, the IRS created a safe harbor for PTC projects with beginning-of-construction dates on or after January 1, 2023. If the project owner determines that the project is eligible for the energy community bonus credit on the date construction is considered to have started for tax purposes, then the project will qualify for the bonus credit for the entire ten-year PTC period and is not tested again.

For insights on how the Energy Community Bonus Credit impacts a real-world transaction, refer to our Section 45 PTC transfer case study, which examines implications and lessons learned.

"Legacy" §45 PTCs are not eligible for energy community bonus

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

The December 31, 2022 date is set in the IRA itself (H.R.5376).

50% of a project's nameplate capacity (or square footage) must be in an energy community

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

For battery storage projects, at least half (50%) of the storage capacity, as measured in megawatt hours, should be in an energy community.

Lastly, for projects that do not generate nor store energy, like biogas, the 50% threshold is measured on a square footage basis.

Diligence

When performing due diligence on the energy community bonus, it's helpful to approach the process based on the credit type and energy community category.

Credit type

ITCs

‍Tax credit buyers should request documentation that demonstrates when and where the project was placed in service. Then, buyers and their advisors should crosswalk that location to an appropriate energy community siting resource, like one of the IRS's appendices. (We provide links to these appendices in the guidance section of this post.)

When validating a project's location, it's important to keep the "50%" rule in mind.

PTCs

Due diligencing the energy community bonus for PTCs is effectively the same as ITCs, although buyers will want to validate when and where the project began construction (versus when and where the project was placed in service). Once again, it's important to keep the "50%" rule in mind.

Energy community category

As far as each category is concerned, the statistical area and coal closure categories are relatively straightforward from a due diligence standpoint: the IRS has published lists of areas that qualify for each. The brownfield category, however, may present a slightly more nuanced due diligence process.

Statistical area

It's important to recall that the statistical area category changes every year, based on the prior year's unemployment rate. As we'll discuss below, the IRS is obligated to publish updates to this category every year, generally in May.

Coal closure

Unlike the statistical area category, the coal closure category cannot shrink – that is, once an area qualifies as a coal closure, it remains as such for the duration of the energy community bonus.

However, the coal closure category can expand, and we fully expect it to do so. According to a 2022 analysis by the Energy Information Agency (EIA), nearly a quarter of the operating U.S. coal-fired fleet is scheduled to retire by 2029. Every closure will add more census tracts to the list of areas eligible for the energy community bonus.

Brownfield

The IRS has not published – and, as far as we know, has no plans to publish – a consolidated list of areas that qualify as brownfields for purposes of the energy community bonus. In fact, the DOE energy community map doesn't even include federally-recognized brownfield sites. (The EPA, however, maintains a list of federally-recognized brownfields in its cleanups in my community map.)

We doubt the IRS or any federal agency will publish a definitive list of brownfields. There are simply too many moving parts across federal, state, local, and tribal brownfields programs.

So, an opinion from an environmental attorney may be warranted, and the scope of the opinion will vary based on which of the three brownfields safe harbors a project is claiming.

Guidance

Latest guidance expands the number of areas that are eligible for the energy community bonus

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

• Expansion of the "nameplate capacity attribution rule"
• Inclusion of two additional NAICS codes – which are in our list above – for determining the fossil fuel employment rate for a statistical area category

Expansion of the nameplate capacity attribution rule

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

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

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

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

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

Inclusion of two additional NAICS codes

Notice 2024-30 added two additional NAICS codes for determining the fossil fuel employment rate for a statistical area category:

• 2212: Natural gas distribution
• 23712: Oil and gas and pipeline and related structures construction

These NAICS codes cover workers in local gas distribution companies and construction workers on oil and gas pipelines.

According to Norton Rose Fulbright, "The biggest additions to the list of potentially eligible counties are in six Midwestern states: Minnesota (57), Missouri (57), Illinois (28), North Dakota (23), Wisconsin (23) and Indiana (20)."

The IRS has released five pieces of energy community guidance, with regulations to come soon

Energy community regulations should arrive by June 30, 2024

As Notice 2024-30 notes, proposed regulations are forthcoming. Until then, "taxpayers may rely on the rules described in sections 3 through 6 of Notice 2023-29, as previously clarified by Notice 2023-45 and modified by section 3 [of] this notice, for taxable years ending after April 4, 2023."

Based on the Q2 update to the IRS 2023-2024 Priority Guidance Plan, energy community regulations should arrive before the end of the current "plan year," which concludes on June 30, 2024.

Where to find the latest guidance

The IRS and Treasury maintain lists of IRA-related guidance, including guidance specific to the energy community adder. Although the lists generally overlap, there may be differences based on when each website was last updated.

• IRS list of IRA guidance
• Treasury list of IRA guidance

Below is a close look at all the guidance that's been released through March 2024.

Notice 2022-51: Request for Comments on Prevailing Wage, Apprenticeship, Domestic Content, and Energy Communities Requirements under the Inflation Reduction Act of 2022

• Date: October 5, 2022
• News release: IRS 
• Companion documents: N/A

Notice 2023-29: Energy Community Bonus Credit Amounts under the Inflation Reduction Act of 2022

• Date: April 4, 2023
• News release: IRS 
• Companion documents: Appendix A, Appendix B, Appendix C

‍Notice 2023-45: Energy Community Bonus Credit Amounts under the Inflation Reduction Act of 2022

• Date: June 15, 2023
• News release: IRS 
• Companion documents: N/A‍

Notice 2023-47: Energy Community Bonus Credit Amounts or Rates (Annual Statistical Area Category Update and Coal Closure Category Update)

• Date: June 15, 2023
• News release: IRS 
• Companion documents: Appendix 1, Appendix 2, Appendix 3

‍Notice 2024-30: Energy Community Bonus Credit Amounts under the Inflation Reduction Act of 2022

• Date: March 22, 2024
• News release: IRS 
• Companion documents: Appendix 1, Appendix 2

Annual Updates To Areas Qualifying As Energy Communities

Expect energy community eligibility updates every May, beginning in 2024

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

The first update should arrive in May 2024 – that is, next month.

Resources from administering federal agencies

DOE, EPA, and IRS have provided energy community eligibility and project siting resources

U.S. federal agencies who are responsible for administering or managing parts of the energy community bonus credit have published several key resources that are valuable to buyers, sellers, and their advisors:

• Department of Energy (DOE): Energy community map
• IRS: Frequently asked questions
• DOE National Energy Technology Laboratory (NETL): Frequently asked questions
• Environmental Protection Agency (EPA): RE-powering America's land initiative
• EPA: Cleanups in my community
• Interagency working group: Energy community tax credit bonus

Learn More

To learn more, you can download our 100-page transferable tax credit handbook or start a conversation with our transactions team.

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Read by over 2,000 members of the transferable tax credit market

Since launching in October 2023, Reunion's handbook has been read by over 2,000 members of the transferable tax credit market, including hundreds of attorneys, accountants, and other strategic advisors.

"Your handbook was fabulous. I encouraged my entire team to download it."
-Fortune 500 Director of Tax

Preview what's inside

Before downloading our comprehensive guide to buying and selling clean energy tax credits, we hope you'll take a peak inside.

Download the complete, 100-page handbook

Once you have downloaded our handbook, we will email you whenever we release an update.

Reprinted from the Novogradac Journal of Tax Credits

January 2024 – Volume XV – Issue I

Corporate income tax revenue was $425B in 2022, suggesting that if IRA tax credits reach $100B annually, monetizing these credits will require over 20% of annual corporate federal income tax to redirect into clean energy projects. Attracting new sources of tax-related capital into the market remains one of the major hurdles facing the renewable energy sector.  

Congress attempted to lower the barriers to entry for attracting tax credit capital by introducing transferability – a transaction mechanism that allows for the purchase and sale of credits, rather than the more complex tax equity partnership structure.

So far, this solution appears to be attractive to corporate taxpayers. In 2023, the range of buyers interested in IRA tax credits has grown beyond the traditional appetite from banks, insurance companies, and some specialized financial services firms. This trend is explored further in Buyers Perspective on Transferable Tax Credits in 2025, which outlines how market dynamics are evolving and what buyers should consider moving forward.

IRA credits bring significant optionality to tax credit buyers

There are many different types of tax credits from which to choose.  For example, there are two credit types – Internal Revenue Code (IRC) Section 48 investment tax credits (ITC) or IRC Section 45 production tax credits (PTC) – and 11 sub-credits spanning electricity generating technology, low carbon fuels, carbon capture and sequestration, and advanced manufacturing.

There is also a range of pricing discounts available that reflect the risk profile of a specific project. Buyers now have far more optionality around the attributes of the credits they are buying, and the transaction process itself. 

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Buyers can also choose from two different tax credit structures – a single-year ITC or a ten-year stream of PTCs. Single-year ITCs apply to the tax year in which the project was placed in service. This gives tax teams the ability to buy credits year-by-year to offset fluctuating or unpredictable tax liabilities. PTCs are generated alongside the physical output of the project (e.g., electricity, sequestered carbon, manufacturing components, etc.). This allows tax credit buyers to contract for either a spot purchase – i.e., the credits from a single period of output (usually one year) – or a forward commitment to a stream of credits. For taxpayers with a predictable amount of tax over a multiyear period, committing to a forward PTC, or “strip,” purchase can improve the economics of the transaction versus a single-year purchase.

In the current market, spot PTC purchases offer the smallest discount to face value, since they carry less risk compared to ITCs which have a recapture provision, whereas PTCs do not. Single-year ITCs typically offer the median discount and PTC strips offer the largest discount. 

Optionality also comes in the form of purchase timing. There are two considerations here – first, most transferable credits are not paid for until a project is placed in service. This approach gives buyers the ability to require key conditions precedent to be met before funding and greatly reduces construction risk to the buyer while isolating the buyer’s exposure to pure tax credit-related risks. Second, buyers can still contract for credits prior to payment. Treasury guidance released in June 2023 formally allowed taxpayers to apply their “intent to purchase” credits to quarterly estimated payment, creating an opportunity to save on quarterly payments prior to laying out cash for a tax credit purchase.

Structuring purchases or payments around quarterly estimated payment days can deliver the best internal rate of return and cash management value. Contracting early in the year can often help buyers secure the best economics, even for credits that aren’t generated until later in the year. Ultimately, buyers should consider the timing of credit purchases as an additional benefit of transferability and plan accordingly for their own tax position.

Transferable IRA credits carry discrete, manageable risks

For early investors in IRA tax credits, risk mitigation should be the primary focus of a transaction process. In general, IRA credits carry the same risks as investing in pre-IRA wind or solar PTCs or ITCs. When investors buy these credits using transferability, however, they eliminate the structure risk associated with tax equity partnerships. This results in cleaner transactions, where buyers need to primarily focus on de-risking the credit itself, rather than the operating profile of the underlying asset.

For a transferable tax credit purchase, buyers must focus on two core risks:

• Qualification: Was the tax credit properly claimed?
• Recapture: Applicable only to Section 48 ITCs and Section 45Q PTCs (not applicable to other PTCs)

A Section 48 ITC is calculated on the cost basis of the energy property placed in service during the tax year. The IRS may challenge the cost basis of the energy property, and if this amount is ultimately reduced, the amount of ITCs from the project will be reduced as well, resulting in an excessive credit transfer tax to the transferee. Buyers will want to review detailed documentation that records the project’s cost basis, verified by a reputable third party accounting or legal firm. In addition, prevailing wage and apprenticeship requirements and any bonus credit adders will need to be verified.

To qualify for a Section 45 PTC, a project needs to generate electricity from a qualified energy resource during the ten-year period beginning on the date the facility was placed in service. Because the PTC is tied to production, the primary risk associated with PTCs is accurate production accounting. This risk is considered easily manageable because production is quantifiable and readily verified.

For a detailed look at how production tracking and verification play out in real transactions, see our Section 45 PTC transfer case study that highlights best practices and common pitfalls.

Recapture on a Section 48 ITC requires that (1) the property remains a qualified energy facility for five years, and (2) there is no change in ownership of the property for five years. In practice, there are three key risks that can be investigated with respect to recapture:

• Proper site control: ensure that the energy project will not be forced from the property by a current or new landlord, triggering a recapture
• Adequate property and casualty insurance: ensure that there is sufficient coverage such that the energy property will be rebuilt in the event of a casualty event
• Mitigate risk of recapture due to debt foreclosure: ensure that lender has agreed to forbearance agreement, or debt is structured in a way that does not trigger recapture in the event of a default

In addition, the seller will need to contractually assure the buyer that there will not be a change in ownership during the five-year recapture period, which the indemnity agreement will help ensure. 

To protect against these risks, buyers will negotiate indemnifications from the seller, and may seek tax credit insurance as a backstop to protect the value of the credits. Working with experienced transaction partners familiar with renewable energy tax credits can ensure that risks have been properly diligenced and risk mitigation is in place in the event of a challenge from the IRS.

Common points of negotiation in tax credit transfer agreement

Unlike a tax equity investment where control rights are an inherent part of the negotiated partnership structure between a project developer and tax credit investor, transferable tax credits sold via a purchase-and-sale agreement don’t carry the same level of ongoing rights for a buyer. This means that buyers should identify the key points of negotiation they will want to include in a tax credit transfer agreement (TCTA). 

Some common points of negotiation beyond price include:

• Timing of payments
• Audit participation rights
• Scope of buyer indemnification 
• Tax credit insurance and who bears the associated costs
• Representations and warranties, and pre-close/post-close conditions precedent 

Several of these are closely related to risk management and warrant additional explanation – namely, the scope of buyer indemnification and tax credit insurance. 

Buyers will typically secure a broad indemnity that shifts most risks (and their associated costs) from the buyer to the seller. In a tax credit transfer transaction relating to a Section 48 ITC, the primary risks to which a buyer is subject are qualification and recapture. The price of the credit can vary depending on the strength of this indemnity – if a creditworthy guarantor or very large balance sheet (in comparison to the size of the credit) is providing the indemnity, tax credit insurance may not be required. 

For instances where a buyer does want tax credit insurance, this cost is typically paid by the seller or the price of the credit is adjusted accordingly when the buyer is procuring insurance directly. Tax credit insurance can be a double-trigger policy that backstops the seller indemnity. So, if the seller fails to perform on the contractual obligations around a recapture or disallowance event, for example, the insurance policy steps in to make the buyer whole. Tax credit insurance is usually quite comprehensive and costs several pennies per dollar of credit. 

Conclusion: discrete, manageable risks

The IRA created an attractive tax credit regime for corporate taxpayers to participate in the energy transition while managing their own federal tax liability over an extended period. While these credits are not certificated in the same manner as some state tax credits, they do bear the benefit of being transferable – vastly lowering the barrier to participation when compared with legacy tax equity investments. 

The risks to these credits are not zero, but they are discrete and manageable through due diligence, seller indemnification, and products like tax credit insurance. Buyers can generally find ways to substantially de-risk these credits while still preserving sufficient value.

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Introduction

In episode 6, Reunion's CEO, Andy Moon, chats with Craig Smith of Wiley Rein to understand how buyers and sellers of transferable tax credits can borrow lessons-learned from the Davis-Bacon Act when navigating the IRA's prevailing wage requirements. The episode includes Craig's view on the November 2023 §48 ITC guidance, which included key PWA updates.

In Craig's view, it's important for transacting parties to strike the right balance between information and enforcement.

Guest: Craig Smith, Wiley Rein. Craig Smith is a partner at Washington, DC-based Wiley Rein. Craig has dedicated a significant portion of his practice to the Davis-Bacon Act, which has several key parallels to the prevailing wage and apprenticeship requirements in the Inflation Reduction Act.

Listen on Spotify or Apple: 10 Questions with Reunion is now available as a podcast on Spotify and Apple.

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Chapters

• 0:00 – Introductions
• 1:47 – Question 1: What are the PWA requirements for the purposes of IRA tax credits?
• 2:33 – Question 2: Are there substantive differences between the PWA requirements under the IRA and the Davis-Bacon Act?
• 3:29 – Question 3: How will the recent major updates to the Davis-Bacon Act – the first in almost 40 years – impact buyers of IRA tax credits?
• 5:27 – Question 4: What's the process for complying with DOL requirements?
• 7:46 – Question 5: How does a developer ensure they are using the correct timing of a wage determination?
• 8:55 – Question 6: How are developers documenting PWA?
• 10:09 – Question 7: How are buyers mitigating the risk of deviations from PWA requirements? How deep should they go with diligence?
• 11:42 – Question 8: What should developers keep their eyes on with respect to documenting PWA?
• 13:09 – Question 9: What is the role of consultants when it comes to documenting PWA compliance?
• 16:02 – Question 10: Under the Davis-Bacon Act, has it been common for a contractor to require subcontractors to submit certified payroll?
• 17:04 – Question 11: How does the PWA "cure period" work?
• 20:54 – Question 12: What is the after-the-fact process for locating and properly compensating a worker who was underpaid?
• 23:05 – Question 13: Any parting wisdom?
• 24:08 – Question 14: What has been the role, if any, of insurance when prevailing wages were not paid under the Davis-Bacon Act?
• 25:45 – Question 15: What should the clean energy market know about the November 2023 PWA guidance?
• 26:44 – Question 16: What can you tell us about the annual PWA reporting requirement during the recapture period?
• 27:25 – Question 17: The November Section 48 ITC guidance did not reference to the use of apprentices during the recapture period. Any insights on whether apprentices are a requirement for the alteration and repair period?
• 28:32 – Question 18: Any closing comments?

Transcript

Introductions

Andy Moon: Hello and welcome to another episode of 10 Questions with Reunion. My name is Andy Moon, and I'm the co-founder and CEO of Reunion, the leading marketplace for clean energy tax credits. We work closely with corporate finance teams to purchase high quality tax credits from solar, wind, and other clean energy projects.

Today's guest is Craig Smith, a partner at the law firm Wiley Rein in Washington, D.C. Craig has significant experience in prevailing wage issues for federal contractors. 

We are excited to have you on the show, Craig. Can you start by sharing a brief introduction on you and your practice?

Craig Smith: Thanks so much, Andy. Delighted to be here. It feels just like just yesterday I got thrown into the world of federal prevailing wage requirements with the American Recovery and Reinvestment Act of 2009, which many people may remember pumped billions of dollars into the economy through grants and other agreements.

My practice has expanded to other types of prevailing wage requirements, which we're going to talk about today, in both the federal contracting space and other vehicles ever since. 

Andy Moon: This is a hot topic for many clean energy developers. For many of the current projects selling IRA tax credits in 2023, they tend to be exempt from prevailing wage and apprenticeship requirements, otherwise known as PWA, because construction on these projects started prior to January 29th, 2023. But PWA compliance is becoming a big topic for 2024 projects, which requires diligence.

Question 1: What are the PWA requirements for the purposes of IRA tax credits?

Andy Moon: Craig, will you summarize PWA requirements for the purposes of IRA tax credits?

Craig Smith: Sure. I think the key term to keep in mind is “Davis-Bacon Act,” which is what all this is based on. It's a nearly hundred-year-old law that directly imposes requirements to pay certain wages and fringe benefits to the laborers and mechanics – which are general terms – who work on federal construction projects.

That requirement has expanded to all sorts of other projects over the years, but the key points are the same: In a given area, you must pay certain wages and fringes to certain classes of workers over the lifespan of the project.

Question 2: Are there substantive differences between the PWA requirements under the IRA and the Davis-Bacon Act?‍

Andy Moon: Are there substantive differences between the PWA requirements under the IRA and the prevailing Davis-Bacon wage requirements?

Craig Smith: It's a bit like if my son were to come to me and say, “Dad, you don't have to pay me an allowance, but every week you have to give me $5 for not doing anything.”

I've been hearing this argument that you just have to pay wages in accordance with the Davis-Bacon Act – you don't have to comply with the Davis-Bacon Act. For most folks, there's no real trade space between those two.

For a lawyer like me, who's thinking about enforcement and working with companies directly, there are some differences in the administration, record-keeping, and other obligations.

And the implementation has, so far, recognized these differences. By and large, though, if you're  thinking about what you need to make sure that people are getting paid, I don't see too much difference.

Question 3: How will the recent major updates to the Davis-Bacon Act – the first in almost 40 years – impact buyers of IRA tax credits?

Andy Moon: That’s very helpful. On that note, the first substantive updates in almost 40 years to Davis-Bacon and related acts became effective recently. Were there any major changes? If so, how will this impact buyers of IRA tax credits?

Craig Smith: There are two that should draw the [clean energy] market’s attention, both of which will take some time to be more salient and will require attention and diligence.

One is that DOL has reverted to a prior method of calculating the prevailing wage. They have certain methodologies where they ask, “Are most people in an area making a single wage rate?” For the last 40 years, if the answer was no, DOL just took a weighted average.

DOL has reinserted in that methodology a 30% threshold – a big plurality, if you will. Where I think you're going to see that make a difference is in geographic areas where there's a fair amount of union labor, but not a majority. At some point in the next few years – perhaps next year, perhaps in five years – the wage rate for iron workers or electricians pops up to reflect that change. Not a today change or a tomorrow change, but something developers need to account for.

The other change is that the site of the work that's covered – who's in the area where you must pay the wages – is steadily expanding. As modular construction continues to grow, the Department of Labor is focused on getting the same kinds of work covered at these secondary sites of work.  

It's going take a little while to see how these [site] changes play out in practice. If you are – to use an easy expression – delivering the windows for the building, [historically] that's just supply. I think when you start assembling things offsite, it's going to get more complicated and require more attention.

Question 4: What's the process for complying with DOL requirements?

Andy Moon: Let’s go into some practical details. Let’s say you’re a developer and trying to make sure you get the correct labor calculation. How should you think about the geography of work, and what’s the process for ensuring that you're complying with DOL requirements? 

Craig Smith: Geography is the easiest place to start because wages are set first by geographic area under the Davis-Bacon Act. Counties are the most common dividing line. For example, you'll see a given county is in wage determination 12345, along with three or four other counties. (There are some projects that, of course, cover multiple counties or other geographic areas. But let's save that for the 201 interview. For now, you can just think about one county.)

Then you must understand what kind of work is being done, because there are four Davis-Bacon wage determination types. They're fairly self-explanatory – building, highway, residential, and heavy. Of course, at the edges, it can get tricky. But DOL has provided some guidance that solar and wind projects should use heavy.  

When you click through the website where these are published, www.sam.gov, you'd start with heavy. Then, you look at who's going to do the work. DOL has recognized we don't have a labor category for installer of solar panels or fabricators of wind turbines. So, really distilling – do we have electricians? Do we have iron workers? What are the trades involved? From there you go down, and it'll have a wage rate and a fringe benefit rate.

A key factor to bear in mind is fringes can be paid as part of a cash wage. A developer doesn’t have to run out and sign everyone up for a 401(k) and a health plan. Instead, the dollars they’re spending per worker per hour must match up with what's in that wage determination. 

Question 5: How does a developer ensure they are using the correct timing of a wage determination?

Andy Moon: Another common question is the timing of the work. You mentioned that the prevailing wage for ironworkers might increase. How does the developer ensure that they are using the correct timing of the wage determination?

Craig Smith: The lodestar is when construction of the facility begins or the other work where the installation work is being done.There are cases at the edges, but for getting familiar with the concept, a developer should think about when they are going to start swinging hammers or digging shovels.

What's important to realize is you'll be able to go online and see the wage determination today. The challenge, then, is you'll already have the contracts, you might have already bought long-lead items, you already have pricing – the project is going to be well-advanced.  

Therefore, understanding the mechanism to confirm you have the right wage determination and if there are any changes [will be important]. That process exists for a federal construction contractor who, say, gets a contract from the General Services Administration to construct a building. It's a little painful, but everyone knows what it is. Under the IRA, [the process is less defined]. It’ll be important to have a plan if that situation arises. 

Question 6: How are developers documenting PWA?

Andy Moon: How are developers currently documenting this PWA?

Craig Smith: There's a wide range of ways to do it. Let me give you some context from Davis-Bacon, which has been around for a long time.

Some companies do it in a manual way, perhaps in Excel. They have an admin who keys all [the information] in. Some have automated systems. Others rely on payroll and plan to extract the data (although I'd say make sure you can do that before you try it).

As you get further and further down the subcontracting chain – and this is important to realize – some companies are flatly unaware of [the requirements]. A partner of mine and I were on a project some years ago, for example, and we were talking with a third- or fourth-tier subcontractor who had never heard of the Davis-Bacon Act.

This is critical for a taxpayer [who is buying tax credits] to know because they are one step further removed from a prime contractor or general contractor.

Question 7: How are buyers mitigating the risk of deviations from PWA requirements? How deep should they go with diligence?

Andy Moon: Because the taxpayer is the one that's on the hook for deviations from the PWA, how are buyers mitigating risk? Are there situations where they can rely on the representations from the EPC or construction company? How deep does the buyer need to go on the diligence side?

Craig Smith: People get into this business because they have some appetite for taking risks and investing. I think buyers need to think carefully about their appetite for risk and the information available to them.  

A compliance lawyer would say you must have detailed documentation of every hour worked by every person on this project. You must have contact information. You must know what's going on week by week because that's the gold-plated way to make sure you're handling compliance. But, as your investors and buyers probably know, you pay for that.  

So, the question is, what's your risk tolerance? A certification may be effective if it's a company you know is familiar with Davis-Bacon or it's a tax credit seller who's using a contractor you know is sophisticated.

I think it’s the right blend of information and enforcement that's going to work with me where the investment still makes sense.

Question 8: What should developers keep their eyes on with respect to documenting PWA?

Andy Moon: We’ve heard that contemporaneous documentation is one of the key elements in ensuring that documentation is sufficient. What are some other points that you would advise developers to keep an eye on as they are documenting PWA?

Craig Smith: Let me give you a variation of that contemporaneous documentation item, which is you've got to make sure everyone knows that this requirement applies. How would someone who's just there to install solar panels know? So, the first consideration is making sure everybody knows what we're supposed to be doing in terms of wages.

Then, you want to understand how these [construction] companies are tracking payroll. What [information] are they accumulating? Maybe [the developer] is not getting the information on a real-time basis, but they should understand the [payroll] process, so they can go back and reconstruct it.

You don’t want to hear, “We had some electricians who came in and paid their guys in cash, and they've all disappeared to the wind.” You don’t want to end up $5 per hour short on a multimillion-dollar tax credit and be unable to find the workers.

Question 9: What is the role of consultants when it comes to documenting PWA compliance?

Andy Moon: I understand what you say when some developers are tracking this manually with spreadsheets, while others are using their certified payroll. What is the role of consultants when they are involved in ensuring that PWA documentation is happening?

Craig Smith: Let me talk about that certified payroll term for just a second, because that may be new to a lot of folks. Under the Davis-Bacon Act itself (and some of the “related acts” that impose the requirements), every week a contractor and subcontractor who are covered has to prepare what's called a “certified payroll,” which lists out all the Davis-Bacon covered workers, their hours by day, how much they got paid, and someone certifies under the Federal False Statements Act that Davis-Bacon wages and fringes have been paid. You can think of that, again, as a gold standard.

But [certified payroll] is not required under the IRA. That's clear. However, the government will tell you it’s a really good idea.

So, when understanding what kind of information you might get, you might see some companies give you certified payrolls, or maybe they use the certified payroll form. Viewers can see the PDF online by searching WH-347. Some companies are sending PDF after PDF. Other companies have moved ahead in how they handle it.

With that context in mind, consultants can help on a few fronts. They can help you wrangle all the information because you might be learning this on the fly. If it's a more construction-oriented consultant, they can help you assess if the labor categories that a contractor has chosen are realistic. Are these workers, for instance, really journeyman ironworkers?

You could also have consultants who help with automating the process of consolidating unstructured data. They could take whatever [data] they get from the general contractor – who's just going to roll up everything from the subs – and put it into a single, clean report. You could, for enough of these projects, have a consultant who builds a light website that handles this.

There is a range of services out there that someone could build, depending on their familiarity with the Davis-Bacon Act. Perhaps they are just technically proficient and can help you automate a workflow. 

Question 10: Under the Davis-Bacon Act, has it been common for a contractor to require subcontractors to submit certified payroll?

Andy Moon: Going back to certified payroll, has it been common under the Davis-Bacon Act for a contractor to require subcontractors to submit certified payroll?

Craig Smith: It’s a contractual requirement, so there's no getting around it. Think of a reverse cascade: payrolls are supposed to make their way to the contracting or the grant-making agency.

If you have a contractor who is familiar with the federal space, they may be the simplest pathway because they already have a workflow for it. Others might say, “We do [certified payroll] for federal projects, but we are not doing them for your project.”

Certified payroll gives you a frame of reference for the type of information you’ll want to have for in-process monitoring and if there are questions five years later when the IRS comes calling to reconstruct what happened.

Question 11: How does the PWA "cure period" work?

Andy Moon: One item that's been talked about a lot in the context of IRA credits is the cure period. If a taxpayer or a developer is determined that workers were not paid prevailing wage, the tax credit is not automatically repealed. There is a chance for the prevailing wage failure to be cured by paying the worker the difference in wages plus an underpayment rate plus an additional $5,000 for each worker that was underpaid. Can you comment a bit on the cure period and, practically, how would it work?

Craig Smith: My comments are generally about how poorly thought out this is. Let me try, however, to help folks think about how to approach the cure mechanism. I’ll contrast it with a regular Davis-Bacon project where, even with the most compliance-oriented companies, people get underpaid. This is hard. So, I want people to understand that this is going to be really hard because you don't have some of the infrastructure from federal projects.

Typically, under Davis-Bacon, the Department of Labor would determine that, let’s say, some workers were paid wages from an outdated version of a wage determination. You would owe them all $2 an hour more for some number of hours, and you would remit the funds. Then, if you can’t find the workers – and this is also true in the services space – you can pay the money over to DOL, and they will try to find the workers.

So, there are two principal differences for any type of cure. One, the proposed guidance is written as though the [buyer] is paying [the cure]. Although the tax credit investor is technically responsible – I think everyone understands that – they don’t have an employer and/or independent contractor relationship [with the workers].

Some companies, especially if they’re publicly traded, have internal controls. It'd be a nightmare for them to pay the workers because they’re not their employees.

I hope that, as the [PWA] rules get finalized by the Internal Revenue Service, this will get fixed. (The comment period is open). If not, taxpayers may need to think about how they’re potentially going to be paying people.  

The second principal difference is the mechanism for paying workers you can't find. It's one thing in the middle of a project to realize there's been a mistake, and you're able to arrange for a back payment. It’s another thing when the project is over – perhaps there's a challenge to the tax credit years later. In this case, you’re trying to find the workers.

So far, all the IRS has said is in their proposed rulemaking is, “Look to state law for how you would pay these people.” I find that deeply unsatisfying, and I hope that gets resolved by the time anyone has these issues.  

The good news, as you mentioned, is we're just now starting to see projects come online that are subject to these requirements. It's going to be some time before we're trying to do after-the-fact fixes.

Right now, projects should have mechanisms in place for validating in-process compliance. They should be able to handle shortfalls in the ordinary course of back pay, whether it's on a paycheck or a special payment. It's going to be a lot easier to catch these [shortfalls] in the moment. 

Question 12: What is the after-the-fact process for locating and properly compensating a worker who was underpaid?

Andy Moon: If there was an underpayment on prevailing wage, I assume the first course of action would be for the developer to make the buyer whole because the developer has a fulsome indemnity. The developer would have a strong incentive to play a role in curing the underpayment of wages.

If that is not able to happen, I thought you had mentioned that the penalty can be paid to the DOL, which will make their best effort to locate the folks who were underpaid. Can you talk through those mechanics? 

Craig Smith: That's how we work in the ordinary course of a Davis-Bacon project. [With the IRA], we don't have that mechanism. Instead, let's say I'm a developer or an investor, I have an uncooperative general contractor, and I don’t have legal recourse. In this case, it’s important to know where the project is located and to engage local counsel who’s familiar with construction projects in that jurisdiction.

This won't be the first time that workers are discovered to be owed money after the fact [in that jurisdiction]. So, for the time being, the best advice we have is look to state law, just like the proposed rules from the IRS say to do. It's not a satisfying solution, but it's the best one that we have. 

The other point to consider is that, although they’re on opposite sides of the bargain, the developer (the seller of the credits) and the buyer have aligned interests. They both want to ensure everyone’s getting paid the correct rate. As you move further from that core transaction under the IRA, however, people have other things to do in life. So, you ultimately need to make sure that everyone is rowing in the same direction.

Question 13: Any parting wisdom?

Andy Moon: Craig, you've been in this space for along time. Is there anything that I could have asked or anything that we missed in this discussion today about prevailing wage?

Craig Smith: I want to reemphasize that companies who spend a lot of money to get this right still run into difficulties. So, [developers should] want to understand PWA requirements from a practical perspective.  

Before they start trying to quantify the risk and model it out, they should think about the right balance of information and enforcement. Some companies might look at this and determine they prefer a strong [with] liquidated damages. Others may want to be more proactive based on their comfort and understanding. But if you just look at this as, “Make sure people get paid the right wages and fringes,” that should take care of itself.  

I have a career in this field for a reason. It's because it's hard to do, even for those who work hard to get it right.

Question 14: What has been the role, if any, of insurance when prevailing wages were not paid under the Davis-Bacon Act?

Andy Moon: That's good feedback, Craig. I'd like to bring up a final item. Tax credit insurance is one area that buyers are using to mitigate risk on these projects. And tax credit insurance does cover qualification of the credit, which would include verification of prevailing wage and apprenticeship requirements.  

How have you seen this play out in Davis-Bacon projects where it’s been determined that prevailing wage was not paid. Has there been insurance available and, if so, how has it mechanically worked?

Craig Smith: It's a too early to see how it's playing out because we're less than a year in. I think this is a question for this time next year when we’ll see how [insurance] is getting bought and sold and if we’re running into these kinds of issues.

If nothing else, we'll have had our first tax filing season, and you can pay someone prevailing wages right away if there's a shortfall. The $5,000 or greater penalty wouldn't be due until tax day, so there is a time lag before we start seeing what's the reality on the ground. 

Andy Moon: Thanks so much, Craig, for coming on the show today. It's great to learn from your experience of working on federal contracting issues and certainly hope to work with you in the future.

Craig Smith: Thanks so much, Andy. This was a blast. Really appreciate it.

Question 15: What should the clean energy market know about the November 2023 PWA guidance?

Andy Moon: Hi, Craig. Happy new year – great to see you again.

Craig Smith: Great to be back.

Andy Moon: The IRS issued an update to Section 48 ITC guidance in November 2023, and it included some updates to the prevailing wage and apprenticeship guidance. We would love for you to give an overview to our audience on what they should know about the PWA.

Craig Smith: When we recorded questions 1 through 14, I said there were a lot of PWA pieces and processes that still had to be defined. Without going into too much granularity, the latest guidance brought some of those pieces together – in particular, around reporting and record-keeping.

There are some pieces, however, that may take more time. For example, we don't know how, in practice, the IRS is going to handle the returns that will include these tax credits. How the IRS will handle disputes is also an open question.

But it still felt like things are starting to come together.

Question 16: What can you tell us about the annual PWA reporting requirement during the recapture period?

Andy Moon: Is there anything in particular that buyers and sellers should be aware of? For example, there was a specific requirement for an annual PWA compliance report to the IRS. What does that look like?

Craig Smith: It's similar to an aggregated report of wages. Perhaps not surprisingly, the November update drew a parallel between the reporting requirements during the construction phase with the reporting requirements during the alteration and repair phase – that is, the recapture period – of a qualifying facility.

Question 17: The November Section 48 ITC guidance did not reference to the use of apprentices during the recapture period. Any insights on whether apprentices are a requirement for the alteration and repair period?

Andy Moon: On the topic of the five-year recapture period, the November guidance did not have any references to the use of apprentices during this period. Any insights on whether apprentices are a requirement for the alteration and repair period on 48 ITCs?

Craig Smith: One of the things that I do as a lawyer is go back to the start with the source text. And I'd say that is an area that isn't as crisply written in the IRA as some of the others when it comes to prevailing wage and apprentices.

For companies that are looking to be in this market, they should be focused on a final answer from the iRS in the Federal Register. And then any challenges to that, one way or the other, will take time to play out.

I think the most important thing to say is, "If we want to be risk averse, we should probably plan for apprentices." If that's not the direction you're going in, then you should have a plan ready if apprentices are part of the ultimate outcome. Within that plan, allocating risks and responsibilities will be an important discussion point.

Question 18: Any closing comments?

Andy Moon: Anything I haven't asked that I should have?

Craig Smith: I think it's important to pay attention to the Department of Labor, which recently published substantially updated Davis-Bacon rules. The market should follow these in-the-field developments.

Said differently, we don't want to over-focus on the IRS. We should keep an eye on Davis-Bacon rules and keep in mind that that there are changes afoot, even if they might feel like they're not quite as forefront as record-keeping or reporting.

Andy Moon: Thanks so much, Craig.

Craig Smith: Thanks for welcoming me back, Andy.