The Inflation Reduction Act gives taxpayers two options for monetizing the Internal Revenue Code's energy-related tax credits—a "direct pay" election and the ability to sell credits to third parties for cash. These options will give developers more flexibility to finance renewable energy and carbon reduction projects and may reduce or eliminate the need for these projects to rely on traditional tax equity.

In this White Paper, we consider structuring opportunities in light of these changes.

U.S. federal income tax law incentivizes investment in renewable energy and related technology in two ways. First, there are tax credits to encourage use of, or investment in, renewable technologies and carbon reduction projects. Second, taxpayers may claim accelerated depreciation for most property used in renewable energy projects. The problem is that traditional sponsors develop these projects using special purpose vehicles that typically do not have enough U.S. federal income tax liability to benefit from these credits or depreciation deductions. Thus, sponsors commonly bring in "tax equity" investors to partner with these special purpose vehicles—that is, investors like banks or other large companies that predictably generate taxable income and can monetize these benefits by reducing their U.S. federal income tax liability.

Tax equity deals are highly structured in order to achieve the parties' tax and economic objectives. In most cases, this means navigating complicated partnership tax rules that allow tax equity investors and developers to allocate tax credits and depreciation between themselves, in ways that do not immediately correspond to allocations of cash flow. This complexity makes tax equity deals costly to implement. Additionally, traditional tax equity deals generally result in unfavorable accounting treatment (above-the-line hit to earnings) that has historically dissuaded many potential investors, such as public companies.

This all may be about to change for two reasons. First, the Inflation Reduction Act of 2022, signed into law by President Biden on August 16, 2022 (the "Act") not only expands the universe of technologies eligible for energy tax credits but also generally provides for energy credits to become fully refundable for tax-exempt entities (known as "direct pay") and for taxpayers to have the ability to sell energy credits to unrelated parties for cash (with no unfavorable accounting treatment (above the line hit to earnings) to buyers). Second, the increasing number of operating companies with net zero goals that are developing their own renewable energy and carbon reduction projects may have sufficient tax capacity to enable them to both utilize accelerated depreciation for themselves and either utilize or transfer tax credits to third parties (or both).

In this White Paper, we discuss certain structuring considerations and opportunities for monetizing renewable energy tax benefits in light of these changes.


Direct Pay

Beginning this year, tax-exempt entities, including state and local governments, are now generally able to elect for direct pay (a payment directly from the IRS, or a "refund") of the major energy-related credits, including investment tax credits and production tax credits.1 The usual rules that prevent tax-exempt entities from claiming investment tax credits will not apply for this purpose.2 Additionally, taxpayers that are not tax-exempt entities will be allowed to elect direct pay of carbon oxide sequestration credits, advanced manufacturing production credits and clean hydrogen production credits generally for a five-year period. However, such taxpayers may not make such elections for any taxable years beginning after December 31, 2032.

A direct pay election must be made no later than the due date (including extensions) for the tax return for the taxable year for which election is made, with special rules to apply in the case of governmental entities that do not file tax returns.

If a facility or property is held by a partnership or S corporation, the direct pay election must be made directly by the partnership or S corporation and not the partners or shareholders. Treasury will pay such electing partnership or S corporation the refund directly, with such refund treated as tax-exempt income for purposes of section 705 and section 1366 of the Internal Revenue Code.

If the IRS determines that a taxpayer claimed a refund in excess of the amounts to which it was entitled, the electing taxpayer could be required to repay the excessive refund, potentially with penalties.

Transfer of Energy Credits

Taxpayers that are not tax-exempt entities may elect to transfer energy tax credits to unrelated third parties for cash.3 As a result of this election, the buyer of the energy credits is treated as the taxpayer with respect to such credits for purposes of the Internal Revenue Code. The seller of the energy credits may elect to transfer all or only a portion of its energy credits to the buyer. Any payments received in exchange for the transfer of energy credits are excluded from the taxable income of the seller, and any amounts paid by the buyer to obtain transferred energy credits may not be deducted from the taxable income of the buyer.

A seller makes a transfer election on a year-by-year basis. The election must be made no later than the due date (including extensions) for the tax return for the taxable year for which the credit is determined. Once a seller makes an election to transfer an energy credit to a buyer, the buyer may not make a second election to transfer the energy credit to another buyer.

A taxpayer may not sell energy credits that it has carried back or carried forward. However, a buyer does not appear to be prohibited from carrying back or forward any energy credits it has purchased.

If a facility or property is held by a partnership or S corporation, the transfer election must be made directly by the partnership or S corporation and not the partners or shareholders. Any amounts received as consideration will be treated as taxexempt income for purposes of section 705 and section 1366 of the Internal Revenue Code.

If the IRS determines that a taxpayer transferred credits in excess of the amounts that it was entitled to transfer, the buyer could be required to repay the excessive transferred credits, potentially with penalties.

In the case of an investment tax credit, the seller generally must reduce the tax basis of the relevant property by 50% of the amount of the transferred credit (or 100% of the transferred credit in the case of the qualifying advanced energy project credit). In addition, the seller must provide notice of any recapture of investment tax credits to the buyer, and the buyer must provide notice of the recapture amount to the seller.


The appeal of the new provisions is their simplicity. A developer no longer needs tax equity to monetize energy tax credits. In light of the Act, the developer now has two basic options

First, the developer can wait to sell energy credits (or make a direct pay election, if available) following the taxable year in which they arise, in connection with filing its tax return for such taxable year. At that time, the developer will know with certainty the amount of the energy credits. We expect the market to establish a price for energy credits, taking into account, on the one hand, the risk a buyer may be denied the credit, and on the other, any non-monetary benefits, such as improving the buyer's sustainability profile, if applicable. Importantly, this wait-and-sell approach may create a timing issue for developers, such as traditional sponsors, who need cash to develop these projects. This means the developer will need financing to bridge receipt of the credits. A developer may mitigate the risks of market volatility and facilitate the obtaining of financing by executing an agreement with a buyer to purchase credits to be generated in the future at an agreed-upon fixed price, which would provide an assured revenue stream upon which lenders could extend a loan.

We expect this to be an attractive option for certain projects. For example, a developer may agree to sell an entire stream of production tax credits to a buyer, possibly up to an agreed cap, or enter into a take-or-pay contract, where the buyer agrees to buy a certain amount of credits for a fixed price or else pay a penalty. In either case, there are additional potential structures that could be implemented to enable an intermediary or broker to facilitate the sale and purchase of credits between a seller and a buyer (as further discussed below).

Second, the developer could sell energy credits to a buyer before development of the project, with the consideration paid upfront on a prepaid basis. In this case, we would expect the developer to receive a further discounted price for the credits to reflect the time value of money. We would also expect that potential buyers would want to negotiate protective protections in the sale contract, including potential collateral and other credit support due to the enhanced credit risk for the buyer arising from the prepayment to the seller and covenants similar to what might be found under loan arrangements, and conduct meaningful due diligence.

But while the new direct pay and transfer provisions offer simplicity, developers may wonder whether they might get more value from traditional tax equity. The Act provides only for direct pay and transferability of energy credits, and does not provide similar provisions for accelerated depreciation. Additionally, in the context of a traditional tax equity deal for the investment tax credit, the tax basis establishing the amount of the credit typically gets stepped up to fair market value. If a developer constructs a project and does not sell it to a tax equity structure, the basis will not be stepped-up, such that the amount of the credit may be smaller

These limitations, however, should not significantly handicap the appeal of direct pay or transfer elections for energy credits as compared to traditional tax equity. The lack of a step-up is only relevant to an investment tax credit, and not a production tax credit, which is available now for many of the same technologies. Additionally, the size of the step-up hinges on fair market value, which is an area ripe for audit by the IRS. Further, although depreciation cannot be sold, some developers will have sufficient income from operations to utilize depreciation deductions (just not both depreciation and credits). This may be particularly true for the increasing number of operating companies with net zero goals that are developing their own renewable energy and carbon reduction projects and that have a certain amount of tax capacity.

Additionally, while some tax equity investors currently are able to extract value from accelerated depreciation, significant strings are attached. Tax accounting for partnerships requires the partnership to keep capital accounts for each partner, tracking capital contributions and distributions to and from the partners as well as book income or loss allocated to the partners. In a typical tax equity transaction, the tax equity investors' capital accounts are exhausted before the vast majority of the depreciation can be allocated to them, such that significant amounts of depreciation must be reallocated to the developer. A tax equity investor may address this problem by agreeing to a deficit restoration obligation (whereby the investor commits to contribute capital in the amount of any capital account deficit if the partnership liquidates), but few investors are willing and able to do so. And, even with a deficit restoration obligation, a tax equity investor usually has taxable gain on exit, which offsets prior allocations of depreciation, such that any tax benefit from allocations of depreciation is a pure timing difference. Accordingly, the lack of ability to transfer depreciation may not be a significant obstacle for getting deals done under the Act's new provisions.


As mentioned above, the benefit of the credit transfer election depends on whether and to what extent there develops a market for transferable tax credits. By including credit transfer provisions in the Act, it appears Congress expected, or at least hoped, that there would be a robust market. Nevertheless, there are several notable limitations on the use of transferred credits that potential buyers will need to consider, including limitations generally applicable to credits under the Internal Revenue Code.

Limitation on Use of General Business Credits

Section 38(c) of the Internal Revenue Code imposes a basic limit on the ability of a taxpayer to claim a general business credit, including the energy credits under the Act. Generally, a taxpayer not subject to an alternative minimum tax may claim a credit only against the first $25,000 of tax liability and 75% of any remaining tax liability. For example, if a taxpayer's net tax liability is $100,000, the taxpayer may claim general business credits of only $81,250 ($25,000 plus 75% of $75,000). If a taxpayer is subject to an alternative minimum tax, section 38(c) generally prohibits the taxpayer from applying general business credits against the alternative minimum tax liability. Fortunately, the Act amended section 38(c) so that energy credits can generally be used to offset up to approximately 75% of the new 15% corporate book minimum tax, which is effective for tax years beginning after December 31, 2022. This means that very large corporations that are expected to be subject to the 15% corporate book minimum tax could be keen buyers of energy credits.

Passive Activity Limitations

Section 469 of the Internal Revenue Code prohibits certain taxpayers from claiming tax credits, including energy credits, arising from "passive activities" against tax liabilities arising from other activities. A "passive activity" is any activity that involves the conduct of any trade or business and in which the taxpayer does not materially participate. Individuals and closely held corporations are subject to the passive activity limitations.

The application of these rules to energy credits transferred to a buyer under the Act is unclear. We expect Treasury and the IRS to weigh in on the issue soon. If the rules apply to such credits, the universe of potential buyers of energy credits will likely be limited to non-closely held corporations.

Cash Purchase Requirement

The Act requires the consideration for an energy credit "to be paid in cash." The full meaning of this requirement is unclear. For example, suppose a buyer agrees to buy $1 million of energy credits from a developer, to be transferred to the buyer five years in the future, at a purchase price of $800,000. The discount of $200,000 may reflect several considerations, such as the risk that the project does not perform. It may also reflect the value to the developer using the cash for the fiveyear period. Is such value consideration that is not "paid in cash"? The Act is unclear, but we note that one benefit from this arrangement is that the buyer appears to enjoy a tax-free return on its initial investment, even though the investment resembles a loan in some respects.

Unrelated Buyer Requirement

The Act requires that the buyer not be related to the seller within the meaning of section 267(b) or section 707(b)(1) of the Internal Revenue Code, which generally requires a morethan-50% ownership interest, by value, to find that parties are related. Accordingly, certain shareholders or partners in a developer may not be able to buy energy credits from the developer. This limitation also seems to prohibit hybrid tax equity structures where a buyer would also acquire a significant equity interest in the developer (perhaps to claim depreciation deductions).


In any deal in which a developer adopts a wait-and-see approach for electing direct pay or transfer of energy credits, there will be a need for interim financing to provide the developer the cash necessary to construct the project. We would expect that this interim debt financing could be collateralized by and possibly mandatorily prepayable by the credit stream. While the Act does not contemplate a mechanism for pledging energy credits, we expect that parties may get to the ame place contractually (for example, with powers of attorney or requiring cash received in respect of credit monetization transactions to be deposited directly in blocked accounts controlled by lenders).

Developers taking advantage of debt financing could take interest deductions, subject to limitations on deductibility of interest expense. Any interest deductions disallowed under section 163(j) of the Internal Revenue Code could be carried forward indefinitely to future (operating) years.


A potential buyer of energy credits may be concerned that it might not have sufficient tax liability to absorb the credits, even if it has historically generated positive taxable income. While it appears a buyer can carry forward transferred credits, there is a time-value-of-money cost to doing so. The Act does not permit a buyer to resell transferred credits. These concerns might put downward pressure on the purchase price.

Given these concerns, brokers or other intermediaries could aid in developing an efficient market. While the Act does not permit a buyer to make an election to resell transferred credits to another transferee, we think the Act does not prohibit similar contractual arrangements, as long as the credits are not statutorily transferred (on a form filed with the Internal Revenue Service) more than once. For example, suppose a broker or other intermediary, such as a bank or other institution, has a relatively predictable stream of positive taxable income. This intermediary could agree to buy credits from developers at backstopped prices and, at the same time, search for potential investors in the market. Investors could agree to buy credits on an as-needed basis for a given taxable year, based on their taxable income for that year (or the three prior years, due to the carryback rules). If the intermediary successfully brokers a transaction, the intermediary would instruct the developer to assign the credits to the third-party investor (and not the intermediary). If the intermediary fails to broker a transaction, it would buy the credits at the backstopped price and apply them against its own tax liability (or carry them forward or back)

These market participants could also take a role in negotiating favorable contract terms on behalf of investors and vetting potential projects, giving investors comfort that they are protected in the event of audit or credit recapture.


Transferable tax credits stand to offer buyers a more favorable accounting result than traditional tax equity arrangements. Under U.S. accounting principles, a tax equity structure using a partnership could, of course, reduce the tax equity investor's income tax expense as a result of credits allocated from the partnership. However, from an accounting perspective, this after-tax benefit comes at a significant pre-tax cost. The investor's capital account in the partnership would be reduced upon receipt of the tax credits, and the investor would report a corresponding pre-tax book loss. These book losses, combined with other non-tax expenses, such as depreciation, could seriously reduce a tax equity investor's pre-tax income. The resulting negative hit to earnings ratios often dissuaded would-be investors from participating in tax equity projects that would have generated positive economic returns.

By contrast, when a buyer purchases a tax credit under the Act, no pre-tax expenses or losses occur. The buyer has no partnership interest to impair and does not own any depreciable property associated with the underlying energy project. The buyer's income statement should see no pre-tax changes. The income statement effects of the purchased tax credit (and of any discount on the purchase) would be limited to after-tax items. This avoids the accounting distortion that would often scare public companies away from investing in traditional tax equity arrangements.


It is possible that a brokered tax credit sale could be considered subject to the Commodity Exchange Act ("CEA"), the primary statute governing derivatives transactions, intermediaries, and markets. This includes potential characterization of such transactions as swaps. A swap is a type of transaction regulated by the Commodity Futures Trading Commission ("CFTC").

Treatment as a swap may trigger certain requirements for the counterparties and agents involved in those transactions, including transaction-specific requirements (e.g., real-time reporting and swap data reporting) and entity registration requirements (e.g., registration with the CFTC as a commodity trading advisor, introducing broker, or swap dealer).

If a brokered tax credit sale is a spot transaction or forward transaction, it would not be subject to the CFTC's regulatory scheme (though it would remain subject to CFTC anti-fraud and anti-manipulation authority). A spot transaction is generally understood to require delivery of the underlying commodity (in this case, the tax credits) for cash consideration on a prompt basis that varies by commodity. If a sale transaction has a delivery timeframe longer than a spot transaction, however, it may be possible for it to be characterized as a forward transaction and excluded from the "swap" definition based on that and other factors. Also, if a sale transaction involves margin, leverage, or other financing, additional analysis of the transaction may be required, including as to the status of the counterparties as eligible contract participants and/or commercial market participants.

Analysis of these transactions and their treatment under the CEA and CFTC regulations will be highly fact dependent. Like other aspects of the Act, these issues will require careful consideration given the potential CFTC requirements that could apply if brokered tax credit sales are deemed to be swaps, and evaluation of potential approaches to structuring transactions to mitigate these concerns.


As described in this White Paper, there are a number of considerations—tax, accounting, regulatory, and legal—for developers of energy projects, potential buyers of tax credits, financial brokers and intermediaries, and others that must be taken into account in designing effective tax credit monetization transactions under the Act. Nevertheless, the new energy credit sale provisions offer inviting alternatives to traditional tax equity that may broaden the universe of interested investors in renewable energy and carbon reduction projects going forward.


1. See I.R.C. § 6417(b). The list also includes the alternative fuel vehicle refueling property credit under section 30C, the new zero-emission nuclear power production credit under section 45U, the new clean hydrogen production credit under section 45V, the new qualified commercial vehicles credit under section 45W, the new advanced manufacturing production credit under section 45X, the new clean electricity production credit under section 45Y, the new clean fuel production credit under section 45Z, the qualifying advanced energy project credit under section 48C, and the new clean electricity investment credit under section 48E. Generally, we refer to the credits under sections 45, 45Q, 45U, 45V, 45W, and 45X as "production tax credits"; the credits under sections 48, 48C, 48E, and, in the case of the direct pay election, 30C as "investment tax credits"; and all such credits collectively as "energy credits." All references to "section" or "I.R.C. §" herein refer to provisions of the Internal Revenue Code of 1986, as amended.

2. See I.R.C. § 50(b)(3), (4)(A).

3. See I.R.C. § 6418. The credits eligible for this election are the same as are eligible for the direct pay election, with the exception of the qualified commercial vehicles credit.

The content of this article is intended to provide a general guide to the subject matter. Specialist advice should be sought about your specific circumstances.