With the pandemic taking precedence over a large part of tax policy over the past two years, there have been many other significant developments in the tax arena that impact our Section. Below is discussion of the major points of interest.
On November 19, 2021, the U.S. House of Representatives passed the Build Back Better Act (“BBBA”), which contains its legislative recommendations relating to infrastructure financing, green energy, social safety net, and prescription drugs, among others. The bill subsequently moved to the U.S. Senate. Because the Democrats in the U.S. Senate do not possess the required supermajority (i.e., 60 members) required to pass the BBBA, the legislation is being considered using a budget reconciliation process which requires a simple majority in the U.S. Senate to pass and cannot be filibustered. The budget reconciliation process comes with strict rules about what can be contained in the legislation and how it impacts the budget. Procedural rules prevent provisions that have no budgetary effects and titles that increase deficits outside the budget window. Thus, any taxpayer favorable provisions must be offset by revenue raising provisions over a 10-year period.
In late December of 2021, the legislation stalled in the U.S. Senate, largely because it did not have the support of moderate Democratic senators, notably, Senator Joe Manchin of West Virginia. The Biden administration has vowed to continue working with U.S. Congress to pass legislation that contains as many of the aforementioned priorities as is possible, but it is likely that any legislation that passes will be a smaller bill. That said, there is growing consensus that the legislation will retain most, if not all of the framework around green energy. If the green energy proposals are passed, it will significantly revamp the Internal Revenue Code of 1986, as amended, to extend and expand on various tax credits, including the production tax credit (“PTC”) and investment tax credit (“ITC”).
Under current law, covered technologies for the PTC include:
The PTC for most of the technologies either expired or were further phased down as of December 31, 2021. The BBBA would extend and expand these PTCs, as well as create additional PTCs for several new technologies, including hydrogen and nuclear.
Hydrogen PTC: The BBBA proposes a PTC of $0.60/kilogram with respect to hydrogen produced through a process that results in a lifecycle greenhouse gas emission rate of less than 0.45 kilograms of CO2 per kilogram of hydrogen (so-called “green hydrogen”). The value of the PTC is reduced as CO2 emissions from production increase (no PTC is allowed for emissions greater than 6 kilograms of CO2 per kilogram of hydrogen - so-called “blue hydrogen”). The credit values are indexed for inflation.
For this purpose, the term “lifecycle greenhouse gas emissions” has the same meaning given to the term under the Clean Air Act. In addition, the term “lifecycle greenhouse gas emissions” only includes emissions through the point of production (well-to-gate), as determined under the most recent Greenhouse gases, Regulated Emissions, and Energy use in Transportation model (commonly referred to as the “GREET model”) developed by Argonne National Laboratory, or a successor model (as determined by the Treasury Secretary).
If the BBBA is passed, the hydrogen PTC would be available for hydrogen produced after 2021 (regardless of when a qualified facility was placed in service) and is available only for the first 10 years of production after the facility is placed in service. No credit is allowed if the taxpayer claims the carbon capture PTC with respect to the facility or begins construction of the facility after 2028. A taxpayer can elect a 30% ITC in lieu of the PTC.
Nuclear PTC: The bill also proposes a new PTC for existing nuclear power plants. The PTC would be measured at 0.3 cents per kilowatt-hour credit for electricity produced at a qualified nuclear power facility and sold to an unrelated person. The credit is reduced as the sales price of electricity increases. Under the credit reduction formula, the credit is reduced (but not below zero) by 80 percent of the excess of the gross receipts (excluding certain federal, state and local zero-emissions grants) from any electricity produced and sold by such facility over the product of 0.5 cents times the amount of electricity sold during the taxable year. The 0.3 cent credit amount and 0.5 cent amounts used in the credit reduction formula are both adjusted for inflation using 2022 as the base year.
If passed, the nuclear PTC would provide a significant incentive to owners of nuclear power plants, and would be demonstrate the growing recognition that nuclear power is a critical component to the long-term decarbonization strategy of the US’ power supply.
Under current law, covered technologies for the ITC include:
The ITC for most of these technologies is set to expire at the end of 2023. For solar, the ITCs available is subject to a phase-out of 26% through 2022, 22% for 2023 and 10% for 2024 and thereafter.
The BBBA would extend and expand these ITCs, as well as create additional ITCs for several new technologies, including energy storage technology, linear generators, microgrid controllers, dynamic / electrochromic glass and convertible biogas property.
In addition, the BBBA would create a new 30% ITC for investments in qualifying electric transmission property, which is electric transmission lines or related transmission property capable of transmitting at least 275 kilovolts with a capacity of not less than 500 megawatts. The proposal does not apply to projects with cost allocation or that have begun construction.
The BBBA green framework uses a two-tiered incentive system with a “base rate” and a “bonus rate.” The base rate would be equal to 20% of the bonus rate and the bonus rate would generally be an increased rate for projects that meet certain prevailing wage and apprenticeship requirements mentioned below, as well as a domestic content requirement. For example, if these requirements are met, a claimant of a nuclear PTC would be eligible to claim a tax credit at a bonus rate of 1.5 cents per kilowatt-hour credit compared to the base rate of 0.3 cents per kilowatt-hour.
To meet the “prevailing wage” requirement, the taxpayer would have to ensure that any laborers and mechanics employed by contractors and subcontractors were paid prevailing wages during the construction of such project and, in some cases, for the alteration and repair of such project, and for a defined period of five years after the project is placed into service.
To meet the “apprenticeship” requirement, the taxpayer would have to ensure that no fewer than the applicable percentage of total labor hours were performed by qualified apprentices. The applicable percentage for purposes of this requirement would be 10% for projects for which construction begins in 2022. This rate would be increased to 12.5% for 2023 and 15% for 2024 and thereafter. This provision would require that each contractor and subcontractor who employs four or more individuals to perform construction on an applicable project would have to employ at least one qualified apprentice to perform such work.
To meet the “domestic content” requirement, the taxpayer would have to ensure that such facility was composed of steel, iron or products manufactured in the United States. For purposes of these requirements, steel and iron that are not part of a manufactured product (other than manufacturing products that are primarily steel or iron) would have to be 100% produced in the United States. Manufactured products would be deemed to have been manufactured in the United States if not less than the adjusted percentage of the total cost of the components and subcomponents across the project was attributable to components which are mined, produced or manufactured in the United States.
In addition, the BBBA continues a unique feature known as the Direct Pay Program. Under this program, for projects placed in service in 2022, this new provision allows a taxpayer election of a tax refund payment for 100% of the value of the ITC or PTC. For facilities that begin construction in 2024 and thereafter, the amount of payment will be decreased for projects that do not meet domestic content requirements. Those projects can only claim 90% of the value if it begins construction in 2024, 85% if it begins construction in 2025 and 0% if the begin construction in 2026 and thereafter.
The Direct Pay Program would allow entities with little or no tax liability to monetize these credits currently. If passed, it could also have an impact on the tax equity market, as taxpayers with limitations on their ability to utilize tax credits would have less of a need to partner with unrelated entities to monetize such credits.
The total breakdown of the BBBA green energy framework is depicted below:
Over the course of the federal legislative session of 2021, much discussion emanated from Washington regarding increasing the rates of corporate income taxes. However, certain tax increases are already occurring. While the proposed BBBA, around which much of this corporate tax increase discussion occurred, did not emerge as enacted legislation, it is prudent for tax advisors to consider the substance of the BBBA’s provisions as near-term prospects.
For corporate taxpayers in the capital-intensive infrastructure industries, one significant increase may be coming into effect. For many years, the Code has included in Section 163(j) certain limitations on the deductibility of interest expense paid to related persons. These rules were substantially tightened in the Tax Cut and Jobs Act of 2017 (the “TCJA”), subject to limited exception for regulated rate payers, from application only to related party interest into a general limitation of interest expense deductions. But a significant further tightening phased in under such legislation just went into effect for taxable years beginning on or after January 1, 2022.
The pre-2022 rules provided that in general, interest deductions could not exceed 30% of adjusted taxable income. For years prior to 2022, adjusted taxable income was calculated by adding back the deduction for depreciation, amortization or depletion, essentially making the income base very similar the “EBITDA” (earnings before interest, tax, depreciation and amortization or generally cash flow) used in lending and business acquisition to determine liquidity and value. Adding these expenses back to taxable income greatly expands the base on which the 30% limitation is imposed. For 2022, however, the adjusted taxable income will no longer permit this add back essentially changing from EBITDA to EBIT. So, the interest limitation will become substantially more restrictive. These rules are made inapplicable to rate regulated electricity, water, gas and steam pipeline companies.
Worthy of note are the further tightening measures that were included in the BBBA. The BBBA proposed a new Section 163(n) to the Code, restricting the interest deduction of foreign controlled U.S. corporations to their proportionate share of the worldwide group’s interest expense allocated on an EBITDA basis.
Another significant change of the TCJA was to reduce the corporate income tax rate from 35% to 21%, justified as being more similar to average rates of our trading partners. While some tax analysts have observed that the prior business pattern of corporate inversions (U.S. corporations migrating their base of operation to lower rate countries such as Ireland) immediately stopped following this major change in tax rate incentives, others have complained that the rates are too low. The Biden administration had been proposing that corporate rates rise to 27% or higher to provide a source of funding for other welfare provisions in the BBBA.
Due to the narrow majority the Democrats hold in the U.S. Senate, Democratic Senator Kyrsten Sinema of Arizona was able to block this general rate increase by her objection alone. However, the BBBA as it passed the U.S. House of Representatives added as a substitute an Alternative Minimum Tax (“AMT”). This new AMT however was not like the corporate AMT that was repealed in the TCJA. The old AMT was calculated using the tax accounting concepts in the Code to determine what tax benefits were being excessively used or abused. The BBBA would impose a 15% AMT on the book income that corporations use to report their financial results to shareholders, lenders and other constituents. The AMT would apply to corporations with more than $1 billion of financial statement income. Importantly, the accounting and realization rules for financial accounting differ significantly from the Code. These conceptual differences are major, e.g., who is considered to be the owner of an asset, what obligations are treated as interest bearing indebtedness and what cash flows might be treated as deposits versus realized income. The utilization of a book-income based AMT also changes an important incentive for the preparation of fair financial statements. While uncertain, one would hope that major corporations would not begin to plan to reduce book income in order to lower tax expense.
If elements of the BBBA emerge in smaller legislative proposals during 2022 and beyond, it is possible that some of these corporate rate increases will be incorporated as a funding source. We also note that Senator Joe Manchin of West Virginia, who was another strong opponent to the BBBA, recently stated that he remained open to considering raising corporate rates back to 25%. Even without new federal programs, the recent increases in the federal debt to 130% of our gross domestic product will require more revenue to service the national debt as interest rates rise back to historic norms. That will put continuing pressure on the corporate income tax rate.
Taxpayers who perform qualified research and development may be able to claim tax credits associated with those expenses on either an original return or a claim for refund. The Internal Revenue Service (“IRS”) issued Chief Counsel Memorandum 20214101F (the “Memorandum”) on October 15, 2021, providing new guidance for refund claims for Section 41 research credits. The Memorandum applies to claims for refund filed after January 10, 2022, and identifies the following items a taxpayer needs to provide the IRS to constitute a valid claim:
The Memorandum also states, “A taxpayer must provide a declaration signed under the penalties of perjury verifying that the facts provided are accurate. In most cases, the signature on IRS Forms 1040X or 1120X serves this function. Additionally, a taxpayer should provide the facts in a written statement rather than through the production of documents. However, if a taxpayer provides documents, including a credit study, the taxpayer must specify the exact page(s) that supports a specific fact. A mere volume of documents will not suffice to meet a taxpayer’s obligation”.
To be considered a valid refund claim filed with the IRS, it must meet the specificity requirement of Treas. Reg. §301.6402-2. This means “[t]he claim must set forth in detail each ground upon which a credit or refund is claimed and facts sufficient to apprise the Commissioner of the exact basis thereof.” Taxpayers generally will attach to a refund claim a written explanation setting forth the grounds for the relief. Then the IRS may decide if additional information is needed and if so, an audit may be initiated. The Memorandum significantly expands upon what is meant by the specificity requirement as it relates to Section 41 research credit refund claims, something the IRS has not done for any other type of refund claim and something that garnering significant attention from the tax community.
The Memorandum directs IRS personnel to reject Section 41 research credit refund claims that do not satisfy the new requirements. However, the IRS has implemented a one-year grace period until January 9, 2023, whereby taxpayers will be notified if their refund claim is deficient and will be granted a 45-day grace period to perfect the claim. Failure to perfect a claim within the 45-day period will result in the claim being rejected, meaning the taxpayer has not filed a valid administrative refund claim.
In order for taxpayers to be afforded the opportunity to initiate a suit for refund in the courts, a taxpayer must wait six months after filing with the IRS their initial administrative refund claim under Section 7422 of the Code. Therefore, taxpayers must carefully monitor their statute of limitations under Section 6511 of the Code when filing a refund claim with the IRS, because a rejection of the claim by the IRS after a statute of limitation expired could negatively affect a taxpayer’s ability to file suit in order to claim Section 41 credits.
The new memorandum will likely result in increased cost of compliance for any taxpayer submitting a Section 41 refund claim going forward. There is also a potential that the memorandum will have a chilling effect on taxpayers in that they decide not to file a refund claim due to the increased burden. It is likely that part of the IRS rationale in creating such a high threshold in submitting Section 41 refund claims is to better manage resources given the high volume of claims they have received. They may also be leveraging recent court rulings that have gone against taxpayers. Regardless, there will be added challenges, complexities, and burdens faced by taxpayers to sustain research credit claims.
The IRS has indicated the requirements in the Memorandum apply only to Section 41 research credit refund claims and not research credits claimed on original returns. Taxpayers claiming Section 41 research credits on original returns should be aware however that the IRS may request the same information on audit regarding business components and the associated qualified research activities. The IRS has also issued limited frequently asked questions (FAQ’s) which address some questions that taxpayers have raised since the release of the Memorandum. Of note, the IRS has indicated statistical sampling is still acceptable for Section 41 research credit refund claims, although a taxpayer is still required to provide the four requested items surrounding business components listed in the Memorandum.
It should be noted the Memorandum is non-precedential because the IRS did not follow the formal notice and comment period for issuing guidance and therefore is merely advisory to IRS field personnel. Additionally, the new claim specificity requirements set forth in the Memorandum appear to contradict the recent holding in Premier Tech, Inc. v. United States, No. 2:20-CV-890-TS-CMR, 2021 WL 2982064 (D. Utah July 15, 2021). Several commenters have stated in letters to the IRS that taxpayers would be better served by having the IRS issue proposed regulations. However, until further guidance is received from the IRS, or the underlying legal issues are addressed in new court opinions, taxpayers should attempt to closely align any research claims being filed to the new requirements in the Memorandum.
The current economy is a global economy with large multinational enterprises (“MNEs”) earning income throughout the world. In many cases, a company can earn income from customers in a particular jurisdiction without the company having a physical presence in the jurisdiction. The result is income earned from a buyer or consumer for use of a product or service in the jurisdiction without that jurisdiction imposing a tax. In certain instances, the tax laws of individual countries have not kept up with the current manner in which business is conducted. In other situations, countries have structured their tax laws in a manner designed to encourage investment in that country through incentive laden tax systems. For example, certain countries have preferential tax regimes that exempt global income, tax income at a low rate or provide other tax incentives such as accelerated deductions or exemptions, designed to encourage a multi-national business to have nexus with the particular country. The OECD has been working for years to help mitigate the potential for tax avoidance associated with differing tax regimes and the so-called “race to the bottom” that has driven down corporate tax rates throughout the world.
In October of 2021, 136 of the 140 OECD countries agreed to a new framework for a global tax regime designed to minimize potential abuses (the “Framework”). The Framework includes Pillar One, pursuant to which the overall profit of certain very large MNEs will be allocated among jurisdictions, with a focus on where sales arise, and Pillar Two, which provides for a global minimum tax rate of 15%.
Pillar One’s main goal is to ensure a fair allocation of tax amount taxing authorities with respect to profits of a MNE with business in different countries. The Pillar One principals will initially apply to MNEs with global revenue above €20 billion and a profit margin above 10%. At its core, Pillar One would reallocate profit to jurisdictions based on where sales arise, without regard to the seller’s physical presence in the jurisdiction. Of critical importance to Pillar One is designing rules that most appropriately compute the amount that will be subject to tax by a jurisdiction where goods or services are provided or customers are located. The principals of Pillar One are intended to be implemented through a convention agreed to by the adopting jurisdictions as well as implementing legislation in each adopting jurisdiction.
Pillar Two provides for a global minimum tax rate of 15%. The minimum tax would apply to MNEs with annual revenue over €750 million. On December 20, 2021, the OECD published model rules to assist in the implementation of the global minimum tax. The rules are intended to serve as a roadmap for participating jurisdictions that choose to adopt them. As a general matter the minimum tax would give the country where the parent entity of a MNE is located the right to impose a top-up tax on income that is otherwise taxed at a rate below 15%. If the jurisdiction where the parent is located does not impose the top-up tax, other jurisdictions where the MNE does business will have a right to collect the top-up amount.
The OECD goal is for the Pillar One and Pillar Two principals to be implemented by 2023. That timeline is thought of as quite ambitious given the complexity associated with the two main principals and extensive rules required to implement the principals, and the fact that different jurisdictions will need to enact legislation to implement the standards. Nonetheless, the agreement in October 2021 by such a significant number of countries that together represent the overwhelming majority of the world’s economy, including a number of countries that previously benefited from incentive laden tax regimes, shows traction where there previously wasn’t.
The Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (“CERCLA”) was enacted, in part, to create a hazardous substance cleanup program. To generate revenue for what was commonly referred as the “Superfund,” CERCLA sought to impose a tax on sales of taxable chemicals and on sales or uses of imported taxable substances that use one or more taxable chemicals in their manufacture or production. These excise taxes would fill the Superfund, which would then fund the cleanup of hazardous waste sites. The Superfund chemical taxes previously in effect expired on December 31, 1995.
The Infrastructure Investment and Jobs Act (the “IIJ Act”) was signed into law on November 15, 2021 and revived two environmental excise taxes after their termination twenty-five years ago - the “Chemicals Superfund Tax” and the “Hazardous Substances Tax.” The Chemicals Superfund Tax and the Hazardous Substances Tax will take effect on July 1, 2022 and be effective until January 1, 2032. The United States Congressional Joint Committee on Taxation estimated that these proposals would increase revenues by approximately $14.5 billion over a 10-year period.
The Chemicals Superfund Tax is an excise tax on the sale or use by the manufacturer, producer, or importer of 42 specified feedstock chemicals. The tax applies to both feedstock chemicals manufactured or produced in the United States, and those imported into the United States for consumption, use, or warehousing. The highest tax rate applies to certain petrochemicals to the extent they are not used or sold for a qualified fuel use: acetylene, benzene, butane, butylene, butadiene, ethylene, naphthalene, propylene, toluene and xylene. The tax rate varies by chemical from $0.44 to $9.74 per ton, which is twice the previously enacted rates.
Numerous exceptions and special rules apply to the Chemicals Superfund Tax, including those for methane or butane used as a fuel, certain substances used in the production of fertilizer or animal feed, substances used in the production of motor fuel, and substances having a transitory presence during refining and certain intermediate hydrocarbon streams, among others. As taxpayers determine whether the Chemicals Superfund Tax applies to their business operations, it is important to consider the full list of available exceptions.
The Hazardous Substances Tax is imposed on certain hazardous substances sold or used by an importer. The importer is the party entering a taxable substance into the United States for consumption, use, or warehousing. The effect of the Hazardous Substances Tax is that importers of substances containing chemicals covered by the Chemicals Superfund Tax also pay an excise tax.
The Hazardous Substances Tax is imposed at the rate that would have been applicable to the taxable chemicals used to produce the taxable substances, as if the taxable substance had been produced in the United States. In the alternative, the tax is imposed at a rate of 10 percent of the appraised value of the substance if the importer failed to furnish sufficient information to the Secretary of the Treasury to determine the amount of the tax. Exemptions may apply for hazardous substances sold for use or used as fuel, in the production of fertilizer, or in the production of animal feed. As noted above, it is important that taxpayers consider the full list of available exceptions that may apply to their business.
A third excise tax is proposed to be reinstated in the BBBA reconciliation bill (the “Petroleum Superfund Tax”) at a rate of 16.4 cents per barrel on (1) crude oil received at a U.S. refinery; (2) imported petroleum products entered into the United States for consumption, use, or warehousing and (3) any domestically produced crude oil that is used (other than on the premises where produced for extracting oil or natural gas) in or exported from the United States if, before such use or exportation, no taxes were imposed on the crude oil.
The Petroleum Superfund Tax would apply to the operator of the U.S. refinery, the person importing the product for consumption, use, or warehousing or the person using or exporting the crude. Notably, the statutory definition of crude oil would include crude oil condensates and natural gasoline. Similarly, the definition of petroleum product would include crude oil but is silent with respect to other products. The Petroleum Superfund Tax would be indexed for inflation beginning in calendar year 2023.
In conclusion, companies need to consider the impact to their business of the reinstated Superfund Taxes related to chemicals and hazardous materials. It is anticipated the Internal Revenue Service will issue specific guidance on these new taxes in advance of their effective date of July 1, 2022.
The IRS has recently issued several private letter rulings dealing with normalization questions surrounding depreciation and ITCs involving a utility entering into a partnership with a tax equity investor to own wind or solar assets for investment. These were the first of a kind ruling on the normalization issues surrounding these transactions (described below). This allows utilities significantly more flexibility in ownership of renewable assets than had been available in the past.
Utilities have generally procured renewable energy by either constructing or acquiring generation property or by purchasing the power generated from the projects pursuant to power purchase agreements (“PPAs”). Utilities with loss or credit carryforwards, including due to years of bonus depreciation deductions, have tended to shift to use of PPAs. Historically, utilities have not emphasized ownership of renewable assets because the relative amount of power purchased pursuant to PPAs was small in relation to the overall power generated by the utilities, especially if the renewable energy was a supplement to existing generation portfolios and not a replacement for other generation facilities owned by the utilities and included in rate base. Given the incentives related to renewable assets, renewable generation assets are generally attractive economically as a generation resource. Utilities have been exploring structures to include their investments in renewables in their rate base. If approved by the relevant public service commission, the solar partnership interest owned by the utility will be included in the utility’s rate base. The solar assets owned by the UTE Structure (defined below) are not included in rate base; it is the utility’s investment in the solar partnership that is included in rate base.
The utility/tax equity partnership structure (“UTE Structure”) allows the utility to efficiently monetize the tax attributes provided to wind and solar generation assets. Pursuant to the UTE Structure, the utility and tax equity contribute assets and/or cash to a solar partnership and the solar partnership uses the cash to purchase a renewable energy facility. Pursuant to the partnership agreement for a typical solar facility, tax equity generally receives 99 percent of the taxable income or loss and ITCs and approximately 20 to 30 percent of the cash flow and the utility receives one percent of the taxable income or loss and ITC and approximately 70 to 80 percent of the cash flow. The UTE Structure is compliant with a safe harbor issued by the IRS in Rev. Proc. 2007-65, discussed in more detail below.
Pursuant to the UTE Structure, the utility will contribute part of the purchase price and tax equity will contribute the rest of the purchase price of the solar facility. The tax equity investment reflects the value of the losses, including depreciation, ITC and cash flow expected to be allocated to it. This is the same arrangement that independent power producers (IPPs) employ when they cannot use the ITC and depreciation efficiently and cannot reflect these tax benefits in the price of power until they are utilized.
The normalization rules were enacted to encourage utility investment in assets eligible for accelerated depreciation and the ITC. The normalization rules are applicable to public utility property. If a utility owns public utility property, the normalization rules require that the tax benefit of the ITC and accelerated depreciation benefits may not be passed through to ratepayers any quicker than ratably over the regulatory life of the asset used for ratemaking purposes.
Depreciable property is categorized as public utility property if it satisfies three requirements: (i) the property must be used in a trade or business to furnish or sell electricity, (ii) the rates for the sale of electricity must be regulated by a federal or state agency or public utility commission, and (iii) the regulated rates must be established on a rate of return or cost of service basis (not a market basis).
The UTE Structure does not cause a normalization violation when analyzed from the perspectives of the solar partnership, the utility or the overall transaction. The solar partnership is selling energy to the market or to the utility at market rates and not based upon cost of service ratemaking. Because the solar partnership is selling energy at market rates (not rate of return or cost of service rates), the solar assets are not public utility property and are not subject to the normalization rules.
The UTE Structure generally satisfies the requirements required by Rev. Proc. 2007-65 (although this safe harbor is for a wind tax equity projects, this safe harbor is routinely applied to solar tax equity projects). This guidance provides if the UTE Structure meets the safe harbor requirements, the partnership is treated as a “partnership,” the partners are treated as “partners” for federal income tax purposes and the form of the structure is respected for federal income tax purposes.
In the partnership context, the determination of whether property is public utility property is generally made at the partnership level as long as the partnership is treated as a partnership and subject to the general rules of Subchapter K. Regulations under former Section 167(l) of the Code required the determination to be made at the partner level if a Section 761 election to be excluded from partnership treatment could be made.
The solar partnership cannot elect out of Subchapter K under Section 761 of the Code. First, the partners do not co-own the property, but rather the solar partnership owns the solar assets. Second, the solar partnership sells all of the electricity generated by the solar assets rather than the partners separately arranging for independent sales of their proportionate amount of the electricity generated. Finally, the partners are not able to determine partnership income without the use of the partnership rules. Therefore, the determination of public utility property must be made at the partnership level. Additionally, the solar partnership in a UTE Structure is typically incorporated as a limited liability company, which is not an unincorporated organization. Thus, the solar partnership is not eligible to elect out of Subchapter K and the determination of whether the solar assets are public utility property is made at the partnership level. These rules, taken together, make it clear that the renewable assets held in the UTE Structure are not public utility property and therefore not subject to the normalization rules.
On December 21, 2017, the TCJA was signed into law. Since its passing, taxpayers have worked through substantial changes and additions to the overall tax regime in the United States including changes to the foreign tax credit regime, Section 163(j) interest expense deduction and Section 172 net operating losses. Many of the changes to the Code were effective immediately for federal income tax purposes, however, there are provisions which were scheduled to take effect or sunset nearly four years after the TCJA was signed. One of these more surprising changes relates to Section 174 of the Code, research and experimental (“R&E”) expenditures.
The accounting method options available under Section 174 of the Code went immediately unchanged after the TCJA was signed into law. For the periods before the TCJA was enacted through tax years beginning prior to January 1, 2022, taxpayers had the ability to immediately expense R&E expenditures that were paid or incurred during the taxable year in connection with a trade or business. Conversely, taxpayers could elect to treat R&E expenditures as a deferred expense, with the cost amortized over a period of no less than 60 months. Furthermore, taxpayers could also elect to amortize over 10 years expenditures otherwise allowable as a deduction under Section 174(a) of the Code. Finally, Section 174 expenditures which were neither treated as expenses nor deferred and amortized under Section 174, were required to be charged to a capital account.
Effective for tax years beginning after December 31, 2021, the R&E expenditures must be capitalized and amortized ratably over a five-year period for research conducted in the United States, and 15 years for research conducted outside of the United States beginning with the midpoint of the tax year in which the specified R&E expenditures were paid or incurred. This rule is applied on a cutoff basis to specified R&E expenditures paid or incurred in tax years beginning after December 31, 2021. Additionally, the change to Section 174 of the Code is being treated as a change in the taxpayer’s method of accounting initiated by the taxpayer and with the consent of the Treasury Secretary. However, there is presently uncertainty around the procedural mechanisms that will be used to effectuate the change in accounting method (e.g., use of a Form 3115, Application for Change in Accounting Method).
As taxpayers move into tax year 2022, the changes to Section 174 of the Code will be significant to consider as federal taxable income is calculated. It is also important to note, that from a state income tax perspective, conformity to changes made to federal income tax provisions is dependent on the version of the Code a state’s tax statute references when determining state taxable income. For instance, California and Texas conform to versions of the Code in effect before December 21, 2017. As a result, pre-TCJA Section 174 would be in effect for California and Texas state income tax purposes, thereby allowing for R&E expenses to be deducted as incurred. On the other hand, a state like Wisconsin has adopted many of the recent changes to the Code, but has specifically decoupled from the Section 174 changes in the TCJA. Therefore, Wisconsin would allow for R&E expenses to be deducted as incurred.
In conclusion, the changes to Section 174 of the Code may come as a surprise to many taxpayers. The differences in how states conform to the Code may create differences between Section 174 deduction amounts included in federal taxable income and state taxable income. Given these additional complexities, there is hope that any new tax legislation introduced in 2022 will contain a provision pushing back the effective date or eliminating mandatory Section 174 capitalization.
One of the noteworthy provisions contained in the TCJA was the revision to the amount of business interest expense taxpayers could deduct under Section 163(j) of the Code. Section 163(j) provides that the amount of a taxpayer’s deductible business interest expense cannot exceed the sum of: the taxpayer’s business interest income, 30% of the taxpayer’s adjusted taxable income (“ATI”), and the taxpayer’s floor plan financing interest. On March 27, 2020 the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) was enacted. The CARES Act allowed corporate taxpayers for 2019 and 2020 tax years only, to use 50%, instead of 30%, of ATI in their Section 163(j)-limitation calculation. For partnerships, this enhanced limitation only applied for 2020 tax year. Other changes included allowing taxpayers to substitute 2019 ATI into their tax year 2020 calculations and automatically permitting 50% of a partnership’s 2019 excess business interest expense as a deduction during 2020 tax year only.
While the CARES Act forced taxpayers to account for changes to the already complicated Section 163(j) rules introduced under the TCJA, it did not amend the components taxpayers used to calculate ATI. Specifically, ATI equaled a taxpayer’s taxable income computed without regard (i) any item of income, gain, deduction, or loss that is not properly allocable to a trade or business, (ii) business interest or business interest income, (iii) the amount of any net operating loss deduction, (iv) the 20% deduction for certain passthrough income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion. Therefore, for the 2022 tax year, taxpayers need to be aware that ATI amounts may be lower than in previous years because of amounts relating to depreciation, amortization, and depletion now being accounted for in the calculation. The impact here is that as ATI decreases, so does the amount of allowable interest expense under Section 163(j) of the Code.
For state income tax purposes, how a particular state conforms to the Code is an important threshold question to answer first. For example, if a state conforms to a version of the Code in effect before December 21, 2017 or has specifically decoupled from the provisions of Section 163(j) of the Code, then a taxpayer is likely not subject to the limitations discussed above. However, if a state conforms to the Code either on a rolling basis or on a fixed date on or after December 21, 2017, then the amount of available business interest expense considered in state taxable income is likely to be limited utilizing the new ATI calculation parameters for the 2022 tax year.
If a state does conform to the provisions of Section 163(j) of the Code, additional considerations are needed due to the differences in filing methods between the federal and state levels. The federal limitation is considered on a consolidated basis, which is often based on the consolidated group. At the state level, filing group compositions can often differ from the federal consolidated group. As a result, states often require the filing group to redetermine taxable income as if the group filing within that state filed a consolidated return for federal income tax purposes. Therefore, while a state may conform to the provisions of Section 163(j) of the Code, the determination of any applicable interest expense limitation may need to be done with a different group of corporations than what was contemplated at the federal level.
Furthermore, many states conform differently to the Code depending on if the taxpayer is a corporate or partnership entity. Connecticut, New Jersey, and Pennsylvania are three examples of states where the conformity rules differ depending on the entity type of the taxpayer. The consistent changes to the federal Section 163(j) rules over the last couple of years, coupled with the inconsistent conformity approaches at the state level, highlights the importance for taxpayers to pay close attention to the way business interest expense deductions and limitations are computed in the 2022 tax year.
Chair B. Benjamin Haas, Vice Chairs include Martha Groves Pugh, David Hardy, Russell Kestenbaum, and Glenn Todd. Thank you for contributions from Andrew Granek from McDermott Will & Emery; Suraj Punjabi and Christian Ehehalt from Constellation; and Lawrence Joseph, Jessica Slean, Julie Capel, Taylor Cortright and Brad Wilhelmson from KPMG.
