Key Changes in Treasury's Final Regulations for the 45X Advanced Manufacturing Production Credit
On October 24, 2024, the Department of Treasury and the Internal Revenue Service (IRS) issued final regulations for the Advanced Manufacturing Production Credit (§45X).
On October 24, 2024, the Department of Treasury and the Internal Revenue Service (IRS) issued final regulations for the Advanced Manufacturing Production Credit (§45X). The final regulations were published in the Federal Register on October 28, 2024 and are largely consistent with the proposed regulations issued on December 15, 2023.
Noted below are key changes as well as clarifying guidance that were issued in the final regulations. Jump to a section:
Distinguishing "minor assembly"
The final regulations replace each instance of "mere assembly" with "minor assembly" to clarify what activities meet the substantial transformation threshold required to qualify for §45X tax credits.
The guidance recognizes that certain eligible components such as a solar module or a battery module are produced primarily by assembling other components. In these cases, the assembly required to achieve production of the ultimate eligible component (solar module or battery module) should not generally be viewed as disqualifying “minor assembly.”
Furthermore, eligible components that have completed substantial transformation, are considered “produced by the taxpayer,” and have been produced and sold to a third-party, in which only “minor assembly” remains, does not disqualify the original party from claiming the §45X credit. As a result, the ensuing third-party who performs the “minor assembly” would not be eligible to claim the credit.
Production costs expanded for critical minerals and electrode active materials
The final guidance is intended to recognize the value of material costs while addressing concerns regarding multiple-crediting and unintended incentives. The proposed regulations did not specifically allow direct material costs, indirect material costs, or any costs related to the extraction or acquisition of raw materials to be considered as production costs. However, the Treasury Department and the IRS, after consultation with the Department of Energy, have reconsidered the proposed exclusion of all material costs based on comments received and revised the regulations to include extraction costs for raw materials sourced in the U.S. or its territories if incurred by the taxpayer claiming the credit.
Additionally, if a taxpayer acquires extracted raw material as a direct (or indirect) material cost, the material costs may be included as production costs consistent with the rules provided under section 263A regardless of whether the extracted material is domestic or foreign-sourced.
Furthermore, any inclusion of direct and indirect material costs may be included if certain conditions are met, but only if they are not for materials that are already an eligible component at the time of purchase (e.g., applicable critical mineral or electrode active material), and as such, an additional credit cannot be claimed on costs relating to the acquisition and use of other eligible components.
See also "Additional substantiation requirements for critical minerals and electrode active materials."
Additional substantiation requirements for critical minerals and electrode active materials
In order to include direct or indirect materials costs as production costs when calculating a §45X credit for the production and sale of critical minerals or electrode active materials, a taxpayer must include certifications from each supplier, as an attachment to the tax return, and maintain specific books, records, and documentation to substantiate the credit.
The certifications must include the supplier’s employer identification number, be signed under penalties of perjury, and state that the supplier is not claiming a §45X credit for the materials purchased, nor is the supplier aware of any prior supplier claiming a §45X credit in the chain of production for the materials.
The books, records, and documentation requirements include, whether prepared by the taxpayer or (ideally) a third-party:
- An analysis of any constituent elements, materials, or subcomponents that concludes the material did not meet the definition of an eligible component (for example, an applicable critical mineral or electrode active material) at the time of acquisition by the taxpayer
- A list of all direct and indirect material costs and the amount of such costs that were included within the taxpayer’s total production cost for each applicable critical mineral
- A document related to the taxpayer’s production activities with respect to the direct and indirect material costs that establishes the materials were used in the production of the applicable critical mineral
Failure to provide this documentation with the return filing, or failure to provide an “available upon request” statement, would constitute a failure to substantiate the tax credit claim.
Definition of produced by the taxpayer
The final regulations expanded the definition of “produced by the taxpayer” to confirm that taxpayers may produce eligible components using recycled materials (secondary production). The updated definition now reads, “Primary production involves producing an eligible component using non-recycled materials while secondary production involves producing an eligible component using recycled materials.”
Clarification on §45X vs §48C facility
The final regulations simplified the definition of a §45X facility, replacing the term “production unit” with “independently functioning tangible property” that is used and necessary for the eligible component to be considered produced by the taxpayer, regardless of physical location. Accordingly, tangible property used to produce a subcomponent which is later integrated, incorporated, or assembled into a distinct and final eligible component may not be part of the section 45X facility.
This clarification allows the use of subcomponents manufactured at a separate §48C facility without tainting the ability to qualify for a §45X credit, as long as the subcomponent is not part of the determination that the taxpayer is the producer of the eligible component.
The final regulations also added a specific rule to address §48C taints in a contract manufacturing arrangement - the tangible property determination for a 45X facility would apply to either party in the transaction, regardless of which party to the contract manufacturing arrangement is claiming the credit.
Effective date
December 27, 2024
Applicability dates
As noted in § 1.45X–1(j), §1.45X–2(f), §1.45X–3(g), and §1.45X–4(d), these final regulations apply to eligible components for which production is completed and sales occur after December 31, 2022, and during taxable years ending on or after October 28, 2024.
Taxpayers may choose to apply these regulations to eligible components for which production is completed and sales occur after December 31, 2022, and during taxable years ending before October 28, 2024, provided that taxpayers follow these regulations in their entirety and in a consistent manner.
Additionally, §5.05(2) of Notice 2023–18 and §3 of Notice 2023–44, which relate to the interaction between §45X and §48C, are superseded for eligible components for which production is completed and sales occur after October 28, 2024.
Appendix 1 — Additional technology-specific changes
Clarification on tandem cells
The final regulations addressed commenters concerns regarding disparate treatment between different types of tandem cells and the resulting capacity and credit amount. The Treasury Department and IRS agreed with commentators, and to prevent potentially incentivizing the development of certain tandem technology, added additional text for cells that are either mechanically stacked or using interconnected layers: “Where that cell is sold to a customer who will use it as the bottom cell in a tandem module, its capacity should be measured with the customer’s intended top cell placed between the bottom cell and the one-sun light source.”
Definition of "polymeric backsheet"
The final regulations clarify that the definition is limited to a sheet on the back of solar modules composed, at least in part, of a polymer, that acts as an electric insulator and protects the inner components of such module from the surrounding environment. This added definition for "polymeric" excludes most glass backsheets because they are typically not composed of a polymer, but of soda-lime glass.
Solar grade polysilicon measurement standards
The final rules added that satisfaction of the minimum purity requirement will be determined in accordance with the standards provided in SEMI Specification PV17-1012 Category 1. This standard also provides additional clarification by including guidance to distinguish between material and immaterial impurities.
Determining credits from related offshore wind vessels
§1.45X-3(c)(4)(ii) was revised to include the application of Federal income tax principles to determine inclusions and exclusions for the sales price used to calculate the §45X credit for offshore wind vessels.
Additional standards allowed to certify rated capacity of completed wind turbines
The final regulations revise proposed §1.45X-3(c)(6) to add both AWEA 9.1-2009 and ANSI/ACP 101-1-2021 as acceptable wind turbine certification standards.
Clarification to DC optimized microinverter systems
§1.45X-3(d)(5)(iv)(B) requires that the inverter and DC optimizer in the DC optimized inverter system to be produced and sold as a combined end product. The Treasury Department and the IRS retained this rule while also clarifying that the inverter and the DC optimizer do not need to be physically packaged together at sale, and the inverter and DC optimizer do not need to be fully interconnected and assembled at the time of sale.
No separate credit is created solely for a DC optimizer, and no changes were made to the number of inverter units used to compute the available credit amount, as these changes are beyond the authority of the Treasury Department and IRS.
Battery cell energy density requirements refer to volumetric energy density
When determining if a battery cell has an energy density of not less than 100 watt-hours per liter, the final regulations clarify that energy density is referring to volumetric energy density in §1.45X-3(e)(3)(i)(B) (e.g., as opposed to gravimetric, mass-based, energy density).
Clarification on modules using battery cells
Many commenters expressed concerns regarding the proposed regulations which would not have permitted a credit for the production of a module that is not the end-use configuration. Other commenters acknowledged that the proposed regulations could create confusion as the definition of battery module could potentially include items that are referred to in the industry as “battery packs.”
To address this confusion, §1.45X-3(e)(4)(i)(A) of the final regulations:
- Redefine an end-use configuration as “the product that ultimately serves a specified end use combines cells into a module such that any subsequent manufacturing is done to the module rather than to the cells individually”
- Clarify that “where multiple points in a supply chain may be eligible under this section, the first module produced and sold that meets the requirements of this section and the kilowatt-hour requirement in paragraph (e)(4)(i) of this section will be the only module eligible”
Clarification on modules not using battery cells for thermal and thermochemical battery technology
Taxpayers producing thermal and thermochemical battery modules with no battery cells must convert the energy storage to a kilowatt-hour basis, provide both the methodology and testing regarding this conversion, and maintain this testing as part of its books and records.
Additionally, the kilowatt-hour conversion cannot exceed the direct conversion of the total nameplate capacity of the thermal battery module to kilowatt-hours (the capacity that is sold to the consumer), and the taxpayer claiming the §45X credit must use the same methodology consistently, subject to any updated standard of the same methodology and testing, for all battery modules (with or without cells) sold in the taxpayer’s trade or business. The final regulations incorporate these clarifications in §1.45X-3(e)(4)(ii).
Additional guidance forthcoming for aluminum
As noted in the Summary of Comments and Explanation of Revisions, a number of comments were received regarding additional clarification for the definition of aluminum, and the Treasury Department and the IRS have determined that additional consideration is necessary prior to finalizing proposed §1.45X-(b)(1) with respect to this definition.
Appendix 2 — Additional contract manufacturing and relation person election changes
Additional critical minerals use case for contract manufacturing
The final regulations also added an additional contract manufacturing example to demonstrate a way to structure and claim a tax credit on initial extracting and refining activities that do not meet the minimum purity levels required for an eligible component until the initial materials are later purchased, completed, and sold.
Anti-abuse rule measured at point of sale for Related Person Election
The final regulations added a clarification regarding defects with regard to a related person election. If an eligible component is not defective at the time of sale, defects arising after the point of sale may occur in the ordinary course of a business and do not generally raise the improper claim concerns regarding defective components.
Appendix 3 — Select items upheld in final regulations
Confirmation of the scope for domestic production and use
The final regulations adopted the proposed rules that require eligible components to be produced within the United States, whereas constituent elements, materials, and subcomponents used in the production of the eligible components are not subject to a domestic production requirement.
In addition, the eligible components do not ultimately have to be used in the United States for §45X eligibility.
Production efforts required to stack or claim additional credits for integral components that are also eligible components
The final regulations upheld the temporary regulations perspective that a taxpayer must produce (rather than merely purchase or acquire) an eligible component that it then integrates, incorporates, or assembles into another eligible component that is then sold to an unrelated person in order to claim credits on both components.
No additional credits for defective units that are subsequently replaced
A commenter proposed that eligible components that were used to replace defective units pursuant to a contractual obligation do not appear to violate proposed anti-abuse provisions. However, the final regulations confirmed the replacement of a defective unit does not represent a new sale to an unrelated person, and §45X does not incentivize the production of two eligible components related to a single sales transaction.
Rejection to expand eligible components and applicable critical minerals
Commenters requested to expand the list of eligible components and applicable critical minerals, but the Treasury Department and the IRS declined, citing the lack of statutory authority to expand the list.
Rejection of proposed safe harbor for contract manufacturing arrangements
The Treasury Department and the IRS declined a commenter’s request to establish a safe harbor for contract manufacturing agreements in place before the applicability date of the proposed regulations.
However, a taxpayer may still elect to apply the special rule (§1.45X-1(c)(3)(iii)), which allows the parties of a contract manufacturing arrangement to agree on which party to the contract will claim the credit.
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Drawing on over $10B of verified transactions, our report takes a deep dive on the Section 48 investment tax credit, Section 45 production tax credit, and Section 45X advanced manufacturing production credit. We also examine emerging market trends and deal dynamics.
Transferable tax credit pricing has increased in the latter half of 2024, particularly for large, "clean" ITCs
The increase in pricing reflects a seasonal supply-demand imbalance caused by the following:
- Corporate taxpayers have a firm and clear estimate of their 2024 tax liability, and many new tax credit buyers have stepped into the market. They are now scrambling to find credits to offset that liability
- The supply of 2024 credits, particularly large credit volumes, have dwindled given the amount of transaction activity throughout the year
We expect pricing for 2024 credits to remain inflated through the end of the year and into 2025. This intra year supply-demand imbalance was also observed in 2023.
While pricing has increased across all credit types, the most marked increase has been with large, straightforward ITC projects. For most of the year, these opportunities traded in the $0.92 to $0.93 range, but as of Q3 we are seeing buyers bid $0.94 or even $0.95. The spread between ITCs and production credits (§45 PTCs and §45X AMPCs) has narrowed considerably.
Sellers have started marketing high quality 2025 tax credit opportunities and are actively seeking buyer commitments. We believe that buyers that are willing to shop now for 2025 credits will be able to access a wide range of credit opportunities, with less competition.
We have also observed sellers running competitive RFP processes, and are receiving multiple bids – in some cases, upwards of ten qualified bids. Examples of projects that have received multiple bids with high valuations:
- $130M solar ITC from an investment grade seller, exempt from prevailing wage requirements
- $150M solar and storage ITC from a reputable seller with a very strong balance sheet. No step-up in cost basis and exempt from PWA requirements
Corporate buyers should develop their 2025 tax credit acquisition strategy now to avoid the late-year credit frenzy
Reunion is seeing an increasing number of high quality sellers marketing their 2025 projects now and placing tight deadlines on accepting bids. Even though pricing may not be optimal due to a lower number of buyers ready to look at 2025 credits, these sellers want to put a tax credit purchase agreement in place so they can obtain a bridge loan against their tax credit commitments.
Buyers who are able to commit to 2025 credits now will get access to a wider selection of project opportunities, and potentially better pricing, as only a subset of buyers have enough visibility into 2025 tax liabilities to be able to commit early. They’ll also avoid “chasing credits” in the latter-half of 2025.
Buyers who are able to execute tax credit transfer agreements now have a significant advantage
For buyers with uncertainty around their tax liability, one option is to initially target a purchase volume that is significantly lower (e.g., 50%) than projected tax liability. The buyer can purchase additional tranches of credits later in 2025 as their tax position becomes more clear. (We previously discussed the strategy of topping up on credits.) Purchasing tranches of credits to “top up” also carry the benefit of less competition for smaller credits, resulting in potentially better pricing.
Buyers who are willing to go slightly out of pocket will also be in an advantageous position
A majority of corporate tax credit buyers do not want to go “out of pocket” to acquire clean energy tax credits, preferring to align tax credit purchases with their quarterly estimated tax payments. Typically, the internal approval process for a cost savings effort (e.g., paying a clean energy developer $95M in lieu of paying $100M to the IRS, at approximately the same time) is easier than requesting an out-of-pocket investment to buy credits that generate tax savings in the future.
Buyers who are willing to go slightly “out of pocket” — for example, willingness to pay for an ITC in Q1, Q2, or even Q3 — will enjoy a less competition, and a larger discount to compensate for timing of payment. These out-of-pocket investments can present attractive economics to buyers, with IRRs over 20%.
We can see this in a sample $100M ITC purchase from a project that will be placed in service in Q1 2024. Let’s assume a buyer and seller execute a tax credit transfer agreement in Q4 2024 (11/15/2024) for a utility-scale solar project that is expected to be placed in service in Q1 2024 (3/15/2024). If the buyer agrees to pay for the credits as soon as the project is placed in service, they could reasonably expect to pay $0.93, as they will essentially be “pre-paying” their taxes in Q1 and will get the benefit of the tax offset during their quarterly estimated tax payment dates.
Even though the buyer goes out of pocket in this scenario, the investment generates an attractive 20.3% IRR and $7.0M tax savings.
Consider smaller projects for better economics
Buyers and sellers want as few counterparties as possible. If a buyer has a $160M tax credit appetite, they want to find one project as close to a $160M as possible.
Focusing on a single, large transaction, however, can present challenging economics because as we noted, there are many large taxpayers that all want to find a large, straightforward transaction.
Simply moving from a single transaction of $100M to three transactions of $30M can meaningfully improve deal economics without necessarily adding undue risk or complexity. Through Q3 2024, for example, smaller 45X AMPCs deals priced approximately a cent below larger 45X AMPCs deals.
Set expectations with internal stakeholders on pricing dynamics for 2024 credits
Companies looking to pursue sizable 2024 ITC opportunities should expect credits to trade at a premium. Buyers should set expectations to bid $0.94, $0.95, or even slightly higher to win the most coveted opportunities.
Additional 2024 credit opportunities will arise as the year draws to a close, and we also predict that additional opportunities will arise shortly after January 1. What we observed last year is that a number of tax credit sellers were not sure if their ITCs would be placed in service in the current year or the subsequent year, so they waited until they had certainty on the tax credit year (i.e., after January 1) to market their credits. That said, we predict that a large number of tax credit buyers will continue to compete over these 2024 credits, particularly for larger opportunities.
Companies should start evaluating 2025 clean energy tax credit investments now
Corporations who are comfortable with their 2025 tax liability and are willing to go a bit out of pocket should begin shifting their attention to 2025. Q4 2024 is a good time to lock in some of the most attractive 2025 deals, particularly for larger ITC, PTC, and AMPC opportunities.
Our transactions team would be happy to assemble indicative cashflow scenarios. Contact us today.
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Executive summary
Over the past 12 months, the rate of growth in the transferable tax credit market has continually surprised industry observers and participants.
Reunion has analyzed how large the transferable tax credit market could be on an annual basis, as well as the size of various monetization strategies – tax equity, direct pay, retention, and transfer.
We estimate that the total size of the transferable tax credit market in 2024 will range from $45B to $50B, which will be broken into four key monetization strategies:
- Transfer: $21B to $24B
- Tax equity: $21B to $23B
- Retain: $1.8B to $2.4B
- Direct pay: $0.8B to $1.0B
Over a nine-year period, Reunion estimates the total volume of clean energy tax credits to steadily climb, surpassing $90B in 2030.
Of the annual total, we expect approximately 50% to 60% to be monetized through transferability.
We ran our estimate through 2032 for two reasons. Under the §45X credit, manufactured components are subject to a four-year phase-down beginning in 2030 (75%, 50%, 25%, 0%). Therefore, manufactured components will no longer be eligible for the §45X after 2032. Also, 2032 is the first potential "applicable year" for the four-year phase-out of the §45Y PTC and §48E ITC.
Jump to a section
- Total transfer market: How many clean energy tax credits will be transfer in 2024?
- Tax equity: How many clean energy tax credits that are eligible for transferability will be monetized through traditional tax equity in 2024?
- Direct pay: How many clean energy tax credits that are eligible for transferability will be monetized through direct pay in 2024?
- Retain: How many clean energy tax credits that are eligible for transferability will be monetized directly by the developer, manufacturer, or refiner in 2024?
- Transfer: How many clean energy tax credits will be transferred in 2024?
- Stranded: How many clean energy tax credits will not be monetized in 2024?
- Looking ahead: How many clean energy tax credits will be eligible for transfer through 2032? Of these, how many will be transferred?
TOTAL TRANSFER MARKET: $45B - $50B
How many clean energy tax credits will be eligible for transfer in 2024?
To estimate the total size of the market for transferable tax credits in 2024, we reviewed several existing estimates by industry observers:
- Congressional Budget Office
- Credit Suisse
- Evercore ISI
- Goldman Sachs
- University of Pennsylvania, Penn Wharton Budget Model
Our analysis identified two key trends:
- A significant increase in estimates following the passage of the IRA: Before August 2022, estimates of the volume of tax credits that would be generated following the passage of the IRA were clustered below $20B. After the IRA became law, estimates markedly increased
- Clustering between $45B and $50B: More recent estimates have fallen between $45B and $50B
$19B | University of Pennsylvania, Penn Wharton Budget Model (July 2022)
Shortly before the passage of the IRA, the University of Pennsylvania's Penn Wharton Budget Model (PWBM) provided a preliminary estimate of the budgetary effects of the legislation from 2022 through 2031.
The report pegged the ten-year cost of the IRA's "climate and energy" provisions at $369B and the 2024 cost at $35.7B. Importantly, PWBM's climate and energy bucket includes several sets of provisions:
- Tax rebates and credits to lower energy costs for households
- Tax credits, research, loans, and grants to increase domestic manufacturing capacity for wind turbines, solar panels, batteries, and other essential components of clean energy production and storage
- Tax credits to reduce carbon emissions
- Programs to reduce the environmental impact of agriculture
- A new fee on methane emissions
To isolate transferable tax credits, we can pull percentages for the various climate and energy provisions from an updated PWBM analysis (which we'll discuss in further detail):
The resulting cost of transferable tax credits for 2024, then, is 54% of $35.7B, or $19.2B. If we apply the same percentage to the ten-year window, we arrive at a total cost of $198.3B for transferable tax credits.
$11B | Congressional Budget Office (August 2022)
In an August 2022 report, the Congressional Budget Office (CBO) estimated the annualized budgetary effects of the Inflation Reduction Act (IRA) from 2022 to 2031. The report covers the entirety of the IRA, although transferable tax credits are broken out by their IRA section. IRA section 13101, for example, extends the §45 PTC.
The CBO estimates the ten-year budgetary impacts of transferable tax credits at $209.8B, $10.5B of which is in 2024.
$20B | University of Pennsylvania, Penn Wharton Budget Model (August 2022)
Once the Senate had passed the IRA, PWBM updated their July 2022 estimated budgetary effects of the IRA. The analysis, from August 2022, resulted in a slight uptick in cost across the board.
To estimate the size of the transferable tax credit market, we have to again scale the "climate and energy" provisions by 54%. The result is $20.0B for 2024 and $206.8B for 2022 through 2031.
$49B | Credit Suisse (November 2022)
Credit Suisse produced one of several analyses that argued initial estimates of the size of the IRA were low – perhaps as much as 3x too low:
"Climate spending will likely be significantly higher than the headline estimate. Roughly two-thirds of the baseline spending is allocated to provisions where the potential federal credit/incentive is uncapped. Our assessment of potential demand for clean electricity production tax credits (PTC) and investment tax credits (ITC), carbon capture, clean hydrogen, and renewable/battery manufacturing credits shows federal spending could reach >3x the cost estimates assigned for these key provisions. The advanced manufacturing provision alone could cost US$250 billion given the credits across solar, wind, and battery supply chains."
Credit Suisse estimated the ten-year cost of transferable tax credits at $528B and the 2024 cost at $49B.
Wood Mackenzie similarly argued that the long-term cost of the IRA would greatly surpass initial estimates. However, Wood Mackenzie focused their analysis on ITCs and PTCs from solar, wind, and storage, so we omitted it from our review.
$33B | Goldman Sachs (March 2023)
Goldman Sachs published an in-depth analysis of the costs and benefits of the IRA and, like Credit Suisse, concluded that early estimates were drastically low. Goldman Sachs estimated the IRA will cost the U.S. government $1.2T by 2032, with some incentives continuing into 2040.
To arrive at an estimate for the 2024 tax credit market, we should remove EVs and buildings from Goldman's estimate because these credits apply largely to individuals and will not be transferred. In exhibit 18, Goldman Sachs estimates that EV- and biofuel-related IRA programs will cost the U.S. government $393B and $43B, respectively.
If we apply this ratio – 90.1% EVs, 9.9% biofuels – to the combined 2024 estimate for “EVs and biofuels,” we remove approximately $9B of cost from 2024, resulting in an annual total of approximately $35B. Buildings further reduce this estimate by approximately $2B, resulting in an 2024 cost of approximately $33B.
Although Goldman Sachs did not publish a year-by-year estimate for transferable tax credits, they assembled a chart of annual IRA spending:
$48B | University of Pennsylvania, Penn Wharton Budget Model (April 2023)
Shortly after the Goldman Sachs report, PWBM released a third estimate of the budgetary effects of the IRA. Importantly, GWBM relied heavily on the Goldman Sachs report: "In preparing these updated estimates, PWBM consulted with private sector experts to understand the likely growth in utilization by climate and energy provision. We are especially grateful to the energy team at Goldman Sachs who helped break down each area and further aided our efforts to produce a budget score against the pre-IRA baseline."
PWBM estimated the total cost of the IRA's energy and climate provisions from 2023 through 2032 – a new ten-year window – at $1.0B. If we isolate transferable tax credits, we arrive at a total of $561B.
We can allocate the $561B total over the ten-year window, assuming a similar annual allocation percentage from PWBM's earlier estimates. Under this assumption, we get $48.3B for 2024.
$47B | Evercore ISI (April 2024)
“Drawing on projections from the U.S. Treasury,” Evercore ISI estimated that the “total addressable market of potentially transferable energy tax credits is $47 billion in 2024.” Evercore notes that “not all these credits will ultimately be transferred” – a key detail we'll explore below.
Viewing the estimates through time
When viewed through time, the eight estimates we've examined exhibit two trends:
- A significant increase in estimates following the passage of the IRA: Before August 2022, estimates of the volume of tax credits that would be generated following the passage of the IRA were clustered below $20B. After the IRA became law, estimates markedly increased
- Clustering between $45B and $50B: More recent estimates have tended to fall in the high $40B range
TAX EQUITY: $21B - $23B
How many clean energy tax credits that are eligible for transferability will be monetized through traditional tax equity in 2024?
With the passage of the IRA, clean energy tax credits can be monetized through transferability, traditional tax equity, or "hybrid" structures involving some mix of both. To properly size the transferability market, then, we need to remove "pure play" tax equity.
Although precise tax equity transaction volumes are not publicly available, Norton Rose Fulbright provides reliable snapshots in their annual cost of capital webinar. In the 2024 cost of capital webinar, for example, Jack Cargas of Bank of America and Rubiao Song of JPMorgan estimated the 2023 tax equity market at $20B to $22B:
- Jack Cargas, Bank of America: "We estimate that the volume was $20 to $21 billion [in 2023], roughly in the same ballpark as the year before."
- Rubiao Song, JPMorgan: "We saw a slight uptick in tax equity volume in 2023 compared to 2022. We put the traditional tax equity at $21 to $22 billion in 2023."
We can create a ten-year series by reviewing the transcripts from prior years – 2023, 2022, 2021, etc.
When estimating 2024 tax equity volumes, Rubiao Song said, "If the economy remains strong, we could see tax equity volume growing by single-to-low double digits."
Despite uncertainty around the potential impacts of Basel III requirements on tax equity investments, Reunion estimates that $21B to $23B of tax credits will be monetized through traditional tax equity in 2024.
Importantly, the amount of tax equity investment is not directly representative of tax credit generation, as some amount of investment is associated with benefits of depreciation and the rights to future project cash flows. However, for purposes of this simplified analysis, we have ignored this distinction and will address it in future discussions.
DIRECT PAY: $0.8B - $1.0B
How many clean energy tax credits that are eligible for transferability will be monetized through direct pay in 2024?
Of the approximately $47B in 2024 tax credits that are eligible for transfer, some will be monetized through direct pay. As Evercore notes in their report, "For a subset of credits" – 45X, 45Q, and 45V – "companies may take advantage of a time-limited provision through which they can receive the credit as a direct payment from the [IRS] after filing their tax returns."
Evercore goes on to emphasize that, "Figures on project registrations released by the U.S. Treasury suggest that even in cases where the seller would have the option for 'direct pay' after filing tax returns, the vast majority are still opting for transfer."
As the Treasury stated, "More than 98% of...facilities or projects are pursuing transferability."
Based on Reunion's 2024 transactions data, which covers nearly $5B in verified transactions, Reunion estimates $0.8B to $1.0B in 2024 tax credits will be monetized through direct pay in 2024. (We can perform a simple check on our estimate by scaling our $47B total market value by 98%, which results in $0.94B.)
RETAIN: $1.8B - $2.4B
How many clean energy tax credits that are eligible for transferability will be monetized directly by the developer, manufacturer, or refiner in 2024?
Based on SEC filings from large, publicly traded utilities, Reunion estimates that 4% to 5% of 2024 tax credits will be retained by developers, manufacturers, and refiners to offset their own tax liability. They will not, in other words, transfer all of their IRA tax credits.
In their 2023 10-K, for example, Duke Energy states, "...due to its existing tax attributes and projected tax credits to be generated related to the IRA, Duke Energy does not expect to be a significant federal cash taxpayer until around 2030."
Reunion's estimates that $1.8B to $2.4B of clean energy tax credits will be retained by their originator.
TRANSFER: $21B - $24B
How many clean energy tax credits will ultimately be transferred in 2024?
In the simplest sense, tax credit transfers become the "plug" in our equation: [total tax credit market] = [tax equity] + [direct pay] + [retention] + [transfer].
Recognizing that we have provided estimated ranges for each value, we can create a "high" and "low" case resulting in an estimated transfer market range of $21B to $24B.
"STRANDED" CREDITS
How many clean energy tax credits will fail to be monetized, irrespective of strategy?
Although we've focused our anaylsis on accretive monetization strategies, it's worth noting the existence of a fifth bucket: "stranded" credits. These are credits that are generated but, for whatever reason, not monetized through tax equity, transferability, direct pay, or retention.
Reunion has seen stranded credits first-hand with smaller developers who were unable to successfully transfer 2023 credits with values in the low hundreds of thousands. We also assume some stranded credits will emerge from developers in financial distress.
We believe stranded credits constitute a de minimis and hard-to-estimate segment of the transferability market and have excluded them from our analysis.
LOOKING AHEAD
How many clean energy tax credits will be eligible for transfer through the early 2030s? Of these, how many will be transferred?
We expect the overall tax credit market to grow by an average of 10% to 15% per year, peaking in 2030. The highest percentage of this growth will occur in transferability (versus other monetization strategies). We estimate that the total tax credit market will approach $700B through 2032, over $350B of which will be monetized through transferability.
We ran our estimate through 2032 for two reasons. Under the §45X credit, manufactured components are subject to a four-year phase-down beginning in 2030 (75%, 50%, 25%, 0%). Therefore, manufactured components will no longer be eligible for the §45X after 2032. Also, 2032 is the first potential "applicable year" for the four-year phase-out of the §45Y PTC and §48E ITC.
Further updates to come
Reunion will update and refine this analysis as we facilitate more transactions and further data comes to market. If your team has data to share on an anonymized basis, we would welcome the opportunity to connect.
Reunion recently surpassed $1.5B in clean energy tax credit sales in 2024. Our transactions have spanned solar, wind, battery storage, fuel cells, biomass, and advanced manufacturing components.
Our team works directly with dozens of Fortune 500 tax credit buyers and leading clean energy companies, and we have observed several emerging trends in 2024.
Speed of execution is a critical factor in winning deals
An increasing number of deals are competitive bidding situations. Buyers should have a clear sense from relevant stakeholders — e.g., CFO, legal, board of directors — on what deal terms are acceptable and what specific approvals are required prior to starting the negotiation process, as delays can be the difference between winning and losing a deal.
We have seen several companies proactively establish investment thresholds that allow them to move quickly for the right credit.
Very large credits carry premium pricing
There has been increased interest in tax credit purchases from major corporations that pay $500M to $1B or more in annual taxes, resulting in more competition for large credit opportunities.
These opportunities tend to trade at a premium — upwards of $0.01 to $0.02, depending on the credit type.
Buyers are increasingly interested in ITCs
Many buyers were reluctant to pay for ITCs early in the year because doing so required them to “pre-pay” their taxes. Buyers, consequently, willing to purchase ITCs in Q1 or Q2 were rewarded with deeper discounts.
Now that we are in Q3 and payments for ITCs will not occur until later in the year, buyer interest has increased.
Pricing on ITCs, PTCs, and AMPCs trended upward in Q3
Buyers, particularly ones that have bid and lost on tax credit opportunities, want to make sure that they lock in credits in time to offset Q3 and/or Q4 estimated tax payments.
There is a price ceiling on ITC transactions
ITCs are still expected to trade at a wider discount compared to production credits. Although sellers often ask for mid-$0.90s pricing for ITCs, buyers typically push back since lower-risk PTCs or AMPCs would be available at similar pricing.
Scope and coverage of insurance is a focus of deal negotiation
Initially, tax credit buyers demanded tax credit insurance to cover 100% or more of the tax credit value. We are seeing more flexibility in structures, whereby insurance may not cover the full tax credit amount due to presence of other risk mitigants such as portfolio diversification, creditworthy seller indemnities or parent guaranties.
Buyer fee reimbursement becoming standard
Over the past few months, virtually every transaction we’ve executed has included a capped fee reimbursement for the buyer. The size of the reimbursement is largely dependent on the deal size.
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