2018 and Onward: The Impact of Tax Reform on the Renewable Energy Market
How much of an impact have President Trump's tax reforms had on the US wind industry, and what does it mean for investors? Guest bloggers David Burton, Jeffery Davis and Anne Levin-Nussbaum take an in-depth look.
How much of an impact have President Trump's tax reforms had on the US wind industry, and what does it mean for investors? Guest bloggers David Burton, Jeffrey Davis and Anne Levin-Nussbaum take an in-depth look. This article first appeared in Pratt’s Energy Law Report March 2018.
On December 22, 2017, President Trump signed into law the bill known as the “Tax Cuts and Jobs Act” (the “Tax Act” or “Tax Reform”) (1.) This article describes the Tax Act provisions of interest to the renewable energy industry, along with some of the possible implications of tax reform on the industry.
There were multiple provisions in the House’s tax reform proposals that were specific threats to the economics of the renewable energy industry. Fortunately, for the industry, none of those provisions survived the legislative process. Nonetheless, the reduction of the federal corporate income tax rate from 35 to 21 percent reduces the amount of tax equity that can be raised for renewable energy projects. Further, the renewable energy industry is wrestling with the implications of the base erosion anti-abuse tax (“BEAT”) on certain multinational tax equity investors.
However, the implications of BEAT are not as severe as they would have been under the Senate’s proposal because Tax Reform allows affected multinational corporations to generally benefit from 80 percent of their renewable energy tax credits for purposes of calculating BEAT through the end of 2025 (as explained below). However, that benefit ends starting in 2026, when affected taxpayers are no longer be able to benefit from any tax credits for purposes of calculating the BEAT, if any. The benefit is also muted by the expanded reach of the Tax Act to corporations that make three percent of their deductible payments to foreign affiliates, which is an increase from the four percent threshold under the Senate bill.
For banks, the BEAT provisions apply if payments to foreign affiliates are two percent of deductible payments. On the positive side, the Tax Act repeals the corporate alternative minimum tax (“AMT”), which is necessary to avoid the loss of certain production tax credits (“PTCs”), which were an AMT “preference” when generated by projects after their fourth year of operation. In addition, the Tax Act allows immediate expensing for newly acquired equipment. Notably, the Tax Act follows the House bill in permitting 100 percent expensing of newly acquired “used” property.
CORPORATE TAX RATE AND AMT
The Tax Act reduces the corporate tax rate to a flat 21 percent, replacing the previous graduated rate structure capped at 35 percent for income that exceeds $10 million. This 21 percent rate is incrementally beneficial for operating projects that are beyond their depreciation period. For new projects, the lower rate reduces the amount of tax equity a project can raise; however, the uncertainty of Tax Reform was hampering the market more than the reduced tax rate is expected to. One straightforward implication of the 21 percent corporate tax rate is there will be significantly less “tax appetite” than there was with a 35 percent tax rate. Fortunately, the largest tax equity investors appear to have significant tax appetite, notwithstanding this reduction.
The Tax Act provides an additional first-year expensing of qualified property at 100 percent. This is also referred to as 100 percent bonus depreciation. This provision is temporary in nature and starts to ratchet down in 2023 and is eliminated completely in 2027. Transmission projects are provided an extra year with respect to each phase-out deadline. Notably, the Tax Act also eliminates the “original use” requirement to qualify for 100 percent bonus depreciation, which means “used” property can be fully expensed in the first year if the taxpayer has not used the property before. This will provide opportunities for acquiring operating projects, including repowered projects.
To prevent abuses, used property acquired from certain related parties is not eligible for expensing. The anti-abuse rule could be a challenge for wind tax equity transactions in which the parties desire to benefit from expensing if the investor has not made its investment in the partnership on or prior to when the project is placed in service (i.e., when the project has essentially become operational), which would require the investor to take construction risk.
Some partners in partnerships owning projects eligible for expensing will face challenges in fully realizing the benefit of the 100 percent deduction. The expensing provision does not treat partnerships differently than other taxpayers; however, the ability of partners in a partnership to claim deductions is limited by such factors as the partner’s “outside” basis and the capital account rules. Those factors may make it difficult for partners to use the expensing deduction without causing other issues. A partnership that is in its first year of doing business can elect out of expensing and claim 50 percent bonus depreciation (2).
Further, all taxpayers can opt for “MACRS” depreciation (e.g., five-year double declining balance for wind and solar property) or the alternative depreciation system (e.g., 12-year straight-line for wind and solar property).
The BEAT provisions were first introduced in the Senate bill and aroused wide concern in the renewable energy sector. The BEAT provisions target earning stripping transactions between domestic corporations and related parties in foreign jurisdictions. The BEAT is a tax (at a phased-in rate discussed below) on the excess of an applicable corporation’s (I) taxable income determined after making certain BEAT-required adjustments, over (II) its “adjusted” regular tax liability (“ARTL”), which is its regular tax liability reduced by all tax credits other than, through the end of 2025, certain favored tax credits. The favored credits are (A) research and development tax credits and (B) up to a maximum of 80 percent of the sum of the low-income housing tax credits and the renewable energy tax credits. This favored treatment of the low-income housing and renewable energy tax credits was in response to concerns raised by those industries.
However, the favored treatment is at best a partial mitigant to the impact of the BEAT on the value of those tax credits and the associated investments. The ability to exclude the renewable energy credits from the ARTL calculation ends in 2026. In particular for PTCs, this could be a deterrent given the 10-year stream of those credits. Further, the Tax Act did not change the BEAT provisions in the Senate bill to distinguish between PTCs and investment tax credits (“ITCs”) earned with respect to projects that have already been placed in service or for which construction has begun. Thus, BEAT could affect monetization of tax credits mid-stream. It could also affect renewable energy credits earned with respect to projects in which tax equity is currently invested. Another issue is that the Tax Act expanded the reach of the BEAT, because the threshold for being subject to the tax is lower than under the Senate version.
Under the Senate version, corporations that make payments to their foreign affiliates equal to four percent of their deductible payments are subject to the BEAT regime. Under the Tax Act, the threshold is three percent and two percent for banks. Confounding the problem is that these companies will not know in advance whether the BEAT will apply, and this uncertainty could cause susceptible tax equity to leave the market. The Tax Act provides a phase-in for the final BEAT rate.
Under the phase-in, the BEAT is five percent for tax years beginning in 2018, 10 percent for tax years beginning between 2019 and 2025, and 12.5 percent thereafter. In the case of banks and securities dealers, the general BEAT rate is increased by one percentage point such that their BEAT rate is six percent for taxable year 2018, 11 percent for taxable years 2019 through 2025 and 13.5 percent thereafter. The higher BEAT rate also applies to corporations and other entities that are members of the same affiliated group of a bank or securities dealer. The higher rate for the specified financial institutions was the “pay for” for allowing the specified financial institutions to exclude payments with respect to derivatives to their foreign affiliates from BEAT. BEAT is a challenge for both PTC and ITC transactions.
However, it is a more significant challenge for PTC transactions due to the fact the PTC benefit is a 10-year stream, while the ITC is all in the first year. Thus, in a PTC transaction, the tax equity investor must predict whether BEAT might apply to it for 10 years in the future, whereas the applicability of BEAT is a one-year concern in an ITC transaction. Wind projects have the option of electing the ITC in lieu of the PTC. The combined effect of BEAT and the availability of 100 percent expensing may cause some wind projects to elect the ITC to attract a larger pool of tax-motivated investors. This would be because a lease structure is the most efficient means for monetizing the benefit of 100 percent expensing and PTCs are not available to the lessor in a lease structure, whereas the lessor is able to claim the ITC.
However, electing the ITC has a cost, as today’s highly efficient wind turbines often cause the present value of a land-based project’s projected PTC stream to exceed the ITC. Therefore, it would appear the ITC election would only be made if it resulted in a significantly larger pool of tax-motivated investors being prepared to bid competitively.
TECHNICAL TERMINATION OF PARTNERSHIPS
The Tax Act repeals section 708(b)(1)(B) of the tax code, which caused a partnership to be deemed to terminate (a so-called “technical termination”) when there is a sale or exchange of 50 percent or more of the total interest in the partnership’s capital and profits during a 12-month period. In the case of such a deemed termination, the terminating partnership was deemed to transfers its assets and liabilities to a new partnership, and the terminating partnership was deemed to distribute interests in the new partnership to the purchasing partner and other partners of the terminating partnership.
One result of the termination was that the recovery period for depreciating the partnership’s assets was restarted. There is a special bonus depreciation rule that provides that the “new” partnership is the entity entitled to claim the deduction for bonus depreciation for property placed in service during the year of the technical termination. The technical termination rule, combined with this bonus depreciation rule, enabled tax equity investors in wind projects to avoid construction risk and still receive bonus depreciation by waiting until after a project was up and running smoothly to acquire an interest in the terminating partnership.
The resulting “new” partnership could claim bonus depreciation, even though the “old” partnership had placed the project in service. Thus, tax equity investors were able to invest in operating wind projects, qualify for bonus depreciation and only lose a few weeks of the 10-year PTC stream. With the 100 percent expensing provisions in the Tax Act, such structuring is not necessary, as “used” property qualifies for expensing so long as the wind project is newly acquired by the taxpayer and the acquisition is not subject to the anti-abuse rules regarding related-party acquisitions (which may still present issues in the case of tax equity partnerships).
Note that the Tax Act does not alter the ITC prohibition with respect to used equipment, so ITC investors will still need to invest at or before the placed-in-service date or execute a sale-leaseback within three months thereof. The repeal also simplifies transfers of interests in tax equity partnerships, which were often restricted by provisions in the partnership operating agreement prohibiting transfers that would result in a technical termination of the partnership. Without the need for this constraint, it is now possible to remove one of the most complex aspects of partnership transfers.
PREPAID POWER PURCHASE AGREEMENTS
The Tax Act eliminates the tax deferral benefit of a prepaid power purchase agreement (“PPA”). Under a prepaid PPA, the offtaker (or residential customer) prepays some or all of the projected cost of the power to be delivered during the term of the PPA. Prior market practice was that the seller of the power (in many transactions, a tax equity partnership) defers the income recognition until the power is actually delivered.
The Tax Act requires sellers to report prepayments for goods and services in the year received or the year following receipt of the payment.3 If the seller of the power is a partnership, the acceleration of the recognition of the prepayment for tax purposes would create more taxable income for the partnership and may increase the ability of the partners to use the 100 percent expensing deduction without causing a deficit capital account problem.
It should be noted that the Tax Act does not make prepaid PPAs impermissible; it merely denies power sellers the timing benefits of income deferral for tax purposes. If the transaction economics are acceptable to the power seller without the tax deferral, parties may opt to continue to include the prepayment feature, as some offtakers find it to be an economically attractive means to deploy their available cash.
The Tax Act limits deductions for net interest expense (i.e., interest expense in excess of interest income) to 30 percent of an adjusted income amount that is calculated using a tax version of “EBITDA” (through the end of 2021, and thereafter switching to a tax version of the more restrictive “EBIT”). Interest that is disallowed as a result of the application of this limitation can be carried forward to future tax years indefinitely. In the case of partnerships, the limitation is applied at the partnership level.
As a result, it applies to each partner regardless of whether the partner has sufficient interest income to otherwise avoid application of the limitation. The limitation only applies to taxpayers with over $25,000,000 in average annual gross receipts for a three-year prior period, unless the taxpayer is a partnership that meets an expansive and highly technical definition of “tax shelter.” (4) The typical tax equity partnership appears to be a “tax shelter” under this definition that, if so considered, would be subject to the interest limitation rules notwithstanding that it has less than $25,000,000 in annual gross receipts.
This concern regarding the application of the interest limitation rules to tax equity partnerships may negatively impact tax equity investors’ willingness to change their existing views regarding the impermissibility of having debt secured by the project. Some tax equity investors are starting to entertain the idea of permitting debt at the project level as that may permit them to benefit from a greater portion of the 100 percent expensing deduction on their tax returns in the project’s first year. Such greater use of the depreciation deductions arises in levered deals due to the application of favorable rules for non-recourse debt under the partnership “outside basis” rules.
The interest deduction limitation is an aspect of Tax Reform some bankers may not be focusing on given that banks generally have more overall interest income than interest expense and, therefore, are not subject to the limitation.
However, the analysis is different when a bank invests in a partnership because the limitation, to the extent applicable, applies at the partnership level (i.e., the bank’s interest income from its general operations would not factor into the equation). Thus, tax equity desks may be surprised by the application of the limitation to levered tax equity partnerships.
It remains to be seen if the detriment of the deferral of the interest deduction due to this 30 percent limitation will be enough to make the use of debt secured by the project unattractive for tax-economic reasons. This would be in addition to the commercial considerations that have made project-level debt a disfavored feature in recent years and caused the market to embrace back-leverage (i.e., debt secured only by the sponsor’s interest in the partnership).
These questions, resulting from Tax Reform, regarding the optimal use of debt and many others will be hashed out in coming weeks as financial models are run and transaction documents are negotiated. Fortunately, the Tax Act was a far less painful blow to the U.S. renewable energy industry than it could have been, and the industry has the experience necessary to optimize transactions under the new tax regime.
David K. Burton, a partner at Mayer Brown LLP and a member of the Tax Transactions & Consulting practice, leads the firm’s Renewable Energy group in New York. He advises clients on U.S. tax matters, with a particular emphasis on project finance and energy transactions. Jeffrey G. Davis, a partner in the firm’s Tax Transactions & Consulting group in Washington, D.C., is a co-head of the firm’s Renewable Energy group, with a focus on project finance and energy transactions. He advises corporations, financial institutions, and private equity funds on U.S. tax matters. Anne S. Levin-Nussbaum is counsel in the firm’s New York office and a member of the Tax Transactions & Consulting practice advising clients on U.S. tax matters, with a particular focus in the renewable energy finance area. The authors may be reached at firstname.lastname@example.org, jeffrey.davis@ mayerbrown.com, and alevin-nussbaum@mayerbrown. com, respectively.
1 Pub. L. 115-97, 131 Stat. 2054 (2017). (The final text of the enacted bill is available at https://www.congress. gov/115/bills/hr1/BILLS-115hr1enr.pdf.)
2 The Conference Committee Report provides: “A transition rule provides that, for a taxpayer’s first taxable year ending after September 27, 2017, the taxpayer may elect to apply a 50-percent allowance instead of the 100-percent allowance.”
3 I.R.C. § 451(c).
4 I.R.C. § 163(j)(3). Under Section 163(j)(3), the minimum $25,000,000 in average annual gross receipts requirement does not apply to a “tax shelter prohibited from using the cash receipts and disbursements method of accounting under section 448(a)(3).” For that purpose, the following are considered tax shelters: (i) any “syndicate” within the meaning of section 1256(e)(3)(B), (ii) any “tax shelter” within the meaning of section 6662(d)(2)(C)(ii), and (iii) any enterprise (other than a C-corporation) if interests in the enterprise were offered for sale at any time in an offering required to be registered with any federal or state securities regulator. I.R.C. §§ 448(d)(3), 461(i)(3). The definition of a “syndicate” would include a partnership where in any taxable year more than 35 percent of the losses are allocated to partners that do not actively participate in management. I.R.C. §§1256(e)(3), 461(j)(4). Therefore, arguably a tax equity partnership with a 99 percent loss allocation to a passive tax equity investor could be a syndicate. Further, a tax equity partnership could potentially be a “tax shelter” as defined in section 6662(d)(2)(C)(ii), as it may have “a principal purpose of . . . the avoidance of federal income tax.” If it were a tax shelter under either definition, it would be subject to the interest limitation rules regardless of its size.