If the Democrats manage to end their in-fighting and pass the Build Back Better Act (BBB), it appears likely to include an option to elect cash in the form of a tax refund in lieu of tax credits. This option is known as “direct pay.” Some in the in the renewable energy industry view it as a panacea for the challenges of the tax equity market. The optimism of some may be based on less than a full understanding of what the direct pay process would be.
Direct pay could end up being more than just an alternative to the tax equity market for sponsors that are more interested in electrical engineering than financial engineering. The BBB also expands tax credits for offshore wind projects, stand-alone storage, carbon capture projects and other activities related to addressing climate change. Given the potential size of the offshore wind and carbon capture market, they could require much of the tax appetite currently available in the tax equity market. That expansion of the demand for tax credits could leave many sponsors that have previously successfully tapped the tax equity market with no choice but to opt for direct pay.
What is direct pay?
Direct pay is a legislative proposal whereby tax credits for newly constructed wind, solar and other renewable energy projects as wells as carbon capture tax credits would be treated as a payment of tax. If the taxpayer, taking into account the deemed tax payment for the credits, had “overpaid” its taxes it could elect a cash refund from the IRS.
What about accelerated depreciation?
Some renewable energy developers assume that if the a refund is available for renewable energy tax credits that a refund would also be available for accelerated depreciation. However, the proposed direct pay rules do not include any payment for depreciation. It varies by transaction and investor, but in a tax equity transaction the tax equity investor often to some extent makes a larger capital contribution to reflect the accelerated depreciation benefit it will be allocated. Unless the sponsor finds an investor to partner with that will monetize the depreciation, a direct pay election sponsor will effectively mean foregoing raising cash from monetizing the depreciation benefit.
To whom is the cash paid?
The cash refund for the tax credits is paid to the entity that is the taxpayer. Accordingly, it can only be paid to an entity taxed as a partnership or corporation or to an individual, estate or certain trusts. Despite being pass-through taxpayers, partnerships and s-corporations would be able to make the election and receive the refund at the entity level, rather than the refund being paid to their partners or s-corporation shareholders.
Non-profit organizations, state and local governments, Indian tribes, Alaska Native Corporations and the Tennessee Valley authority would be able to make the refund election and receive the refunds themselves. Oddly, despite including such entities in the direct pay regime, the BBB would not relax the rules that make projects leased to such non-taxpayers ineligible for the actual investment tax credit (ITC) and accelerated depreciation and create issues related to ITC and accelerated and depreciation for partnerships that have such non-taxpayers as partners.
In the commercial solar segment of the market, it is common for non-profit and governmental organizations to enter into power purchase agreements, characterized as service contracts for income tax purposes, to procure solar power. They use this approach because they cannot use the ITC or accelerated deprecation themselves and a lease to them would disqualify the project in the lessor’s hands for such tax benefits. Solar providers may find that direct pay means non-profit and governmental organizations have less need for their power purchase agreements.
When is the cash paid?
If the BBB is enacted, the direct pay election is available for projects placed in service after December 31, 2021, but no one should expect a direct payment in 2022.
A typical tax equity structure for ITC eligible projects (e.g., solar) has the tax equity investor making its capital contribution 20 percent at “mechanical completion” (i.e., before placement in service) and 80 percent at “substantial completion” (i.e., when the project is regularly dispatching power and has passed performance testing, which is generally considered to be after placement in service). For wind, the typical structure has the tax equity investor contributing 75 percent of its capital at substantial completion, or there about, and 25 percent in “paygo” payments that are made after the project has generated certain agreed levels of energy (i.e., production tax credits (PTCs)).
The cash for the tax credits under direct pay would be received almost a year later than tax equity investors now typically make the bulk of their contribution. Under direct pay, in the best case scenario, the project has to be placed in service; the taxable year has to end; the taxpayer has to file its tax return (which sponsors will think they will do in early January, but it will inevitably slip due to needing information from other sources (e.g., IRS Form 1099 reporting for the project’s bank account, which is not due until February 1st) and busy accountants) requesting the refund; and, then the IRS has to process the “refund,” which will likely take a couple of weeks at best. For instance, if a project is placed in service in March 2022, the sponsor and its accountants could work at breakneck speed and file the tax return in April 2023, and the refund could possibly be received in June 2023.
No direct payment election for the first 270 days after enactment
The proposed legislation provides that no direct pay election may be made for 270 days following enactment. For instance, if congressional Democrats manage to stop squabbling and pass the BBB on November 15, 2021 and President Biden signs it on November 16, 2021, the earliest any project owner year could hypothetically make a direct pay election is August 13, 2022. This 270 days rule seems designed to ensure that even if project owners get creative with adopting fiscal years for their taxable years (e.g., place a project in service on January 15, 2022 and have it owned by a newly formed c-corporation with January 31st fiscal year for financial statement purposes (and accordingly the same for its taxable year)), that the IRS has time to craft the rules and tax forms that will be necessary to implement the program.
A registration process for a tax refund?
Tax credits are claimed on IRS Form 3800 which is all of three pages. Those in the renewables industry that are most excited about direct pay may be thinking the direct pay process will be Form 3800 with an accompanying statement that the taxpayer is electing the refund. However, the proposed legislation provides that the IRS “may require such information or registration as … necessary or appropriate for purposes of preventing duplication, fraud, improper payment or excessive payments.” It is not clear yet what the “registration” process could be, and the IRS could opt to not require registration (but that seems unlikely). Further, based on the 270-day grace period discussed above, Congress appears to be expecting the IRS to build a robust process.
If a project owner elects direct pay for the ITC, the ITC is based on a project’s eligible tax basis. Eligible basis involves applying tax regulations that have not been updated since the 1980s to amounts incurred in what in some instances are transactions that involve significant complexity. Hence, there is some subjectivity to it. The 1603 cash grant program under which during the Obama administration the Treasury paid cash in lieu of tax credits followed the same ITC rules and was fraught with disagreement between Treasury and project owners.
Under the 1603 cash grant program, the Treasury sought to rely on independent accountants to police the amounts claimed as eligible basis, by requiring requests for payments of at least $1 million to include “independent accountants’ examination opinion” while payments of less than $1 million but more than $150,000 were “required to provide a report of agreed opinion procedures by an independent accountant.”
The Treasury ended up finding that its views of eligible basis often differed from that of project owners and their accountants. This difference in views resulted in Treasury paying many project owners less than they had requested. Such “haircuts” led to more than 50 law suits being filed in the US Court of Federal Claims by aggrieved project owners. Two of those cases have resulted in appellate opinions, one of those two is pending a trial on remand, a number of case are pending their original trial, and several cases are stayed to allow the parties to see how the cases ahead of them in queue play out.
In the 1603 cash grant disputes, the Treasury typically requested cost segregation reports, appraisal reports and documentation of construction costs. If the IRS draws on this experience of its parent agency, it may require comparable documentation either to register a project for a direct payment election or to make the election on a tax return for an ITC.
The IRS could opt to require less for documentation for PTC and carbon capture tax credit refunds as those tax credits are based on easily measurable metrics. For the PTC, the measure is the kilowatt hours of electricity generated and sold to third parties during the taxable year, while for the carbon capture tax credit the measure is the tons of carbon captured during the taxable year.
Under current law, wind projects can opt for the PTC or the ITC, but solar projects may only claim the ITC; the BBB would allow solar projects to opt for the PTC. Such a PTC election would avoid 1603-esque disputes about eligible basis; however, opting for the PTC means receiving the benefit over ten years as the PTC is $25 a megawatt hour for electricity generated and sold to third parties for ten years. Sponsors that are accustomed to the bulk of tax credit benefit in the first year may not be prepared to have their benefit stream spread out over ten years.
Banks may be able to help with the issue of the PTC being a ten year tax credit stream by lending against anticipated direct payments. Given all of the “ESG” money looking to be put to work, the interest rate on such loans may not result in too much of a diminishment in the proceeds available for the project.
I want my ITC
What if a sponsor prefers an ITC refund in the first year to waiting around for ten years of PTC refunds or determines that the ITC will be a greater amount than the stream of PTCs? The ITC is 30 percent of the eligible basis. In the ordinary course, the eligible basis is the cost to construct the project (e.g., payments to equipment suppliers and the construction contractor). However, project economics often depend on a larger ITC. A portion of the basis can be stepped-up to fair market value by selling a partnership interest to an investor, but the step-up is only on the percentage of the project that correlates to the percentage purchased by the investor.
To fully step-up the basis to fair market value, requires either a sale of the project for fair market value or a payment of a “development fee” for the difference between cost and fair market value. The market trend, although not universal practice, has been a fair market value sale.
Transactions between members of the same consolidated group or disregarded entities with a common regarded parent would not increase the ITC eligible basis. Transactions between two partnerships or a partnership and a corporation do increase the ITC eligible basis and are more robust if some of the purchase price or developer fee is funded by a third-party investor that will own at least a minority stake in the project with the sponsor holding the majority stake. Accordingly, that introduces the need to identify and negotiate with a third-party investor, which will entail some of the transaction costs and friction present in tax equity transactions that sponsors are hoping to avoid. A sponsor may then just opt for a customary tax equity transaction, monetize the depreciation and receive the capital sooner and avoid the rigmarole of requesting a refund under a process that the IRS needs nine months to craft the rules and tax forms for. The question is whether such a sponsor will be able to find a tax equity investor with available tax appetite given the expansion of tax credits for offshore wind and carbon capture proposed in the BBB.
Labor and US content requirements
Projects that “begin construction” in 2024 and are over one megawatt would be subject to a ten percent reduction in the direct payment, if they do not pay prevailing wages for construction and operations and maintenance, use apprentices and satisfy minimum US content requirements. The direct pay reduction for such a failure ratchets up to 15 percent if the production begins in 2025 and would go to zero if the production begins in 2026 or later. There would be exceptions if the US content is not available or would add more than 25 percent to the cost of the project or if there are not apprenticeship programs available. For projects over one megawatt starting in 2024, avoiding these headaches would be another reason that sponsors may prefer to stick with tax equity.
Sponsors may find themselves electing direct pay, even if they have a track record of tapping the tax equity market, due to the tremendous demand for tax equity the BBB will trigger by expanding various types of tax credits. The IRS will have nine months to build a process for direct pay. That process must have guardrails to prevent abuse, but for direct pay to serve its intended purpose it must work better than the section 1603 cash grant program did at the end of its life when “haircuts” in the amount paid and delays made it unusable for many sponsors.
 See House Rules Comm., 117th Cong., Text of H.R. 5736, Build Back Better Act (Comm. Print. 117-18, Nov. 3, 2021). Direct pay would be provided for in new Internal Revenue Code section 6417, the text of which starts on page 1370 of the PDF version.
 S-corporations are unlikely to be the owners of clean energy projects because their shareholders may only be United States citizens, residents, certain estates and certain non-profits. Further, s-corporations can only have one class of stock. See I.R.C. § 1361.
 See I.R.C. §§ 50(b)(3), 168(g)(3) and 470.
 See I.R.C. § 168(h)(6).
 See I.R.C. 7701(e).
 See I.R.C. §§ 50(b)(3), 168(g)(3) and 470
 This timing is motivated by the fact that the ITC arises when the project is placed in service and a transfer after the credit arises triggers recapture of the credit. I.R.C. §§ 48(a)(1), 50(a). Thus, the tax equity investor wants to be sure that it is a partner having made a material investment before placement in service, and mechanical completion is safely achieved before placement in service. There is no renewable energy guidance addressing this issue, but the 20 percent / 80 percent parameter is based on a guidance for historic tax credit deals. See Rev. Proc. 2014-12, § 5, Ex. 1.
 The PTC is based on production over a ten year period starting on the placed in service. I.R.C. § 45(a)(2)(A)(ii). Accordingly, for instance, if the tax equity investor invests a month after placement in service, the only consequence is that the tax equity investor is entitled to 99 percent of the PTC for 119 months, rather than 120 months. The 75 percent / 25 percent paygo rule is the rule for “contingent” consideration in the wind safe harbor. Rev. Proc. 2007-65, § 4.04. For carbon capture credits, the IRS allows 50 percent paygo. Rev. Proc. 2020-12, § 4.04.
 See Treas. Reg. § 1.441-1T(b)(2). Such a fiscal year would not be available to a s-corporation or most partnerships.
U.S. Treasury, Payments for Specified Energy Property in Lieu of Tax Credits, Independent Account Requirements (Sept. 24, 2009), available at https://home.treasury.gov/system/files/216/accountant-certification.pdf.
 Alta Wind Lessor C v. United States, 897 F.3d 1365 (Fed. Cir. 2018); California Ridge Wind Energy v. United States, 959 F.3d 1345 (Fed. Cir. 2020).
 See Rev. Rul. 99-5 (situation 1).
 See, e.g., California Ridge Wind Energy v. United States, 959 F.3d 1345 (Fed. Cir. 2020); https://www.projectfinance.law/publications/2020/may/california-ridge-developer-fees-struck-down-again/.
 Treas. Reg. § 1.1502-3(a)(2).