As shared in the last several IRIS reports, on August 16, 2022, US President Joe Biden signed the Inflation Reduction Act of 2022 (the IRA) into law, which includes $369 billion in energy and climate spending. The IRA includes several new and expanded sources of government support for the development of a domestic clean energy industry and for the gradual transition to a more sustainable energy economy.
Major provisions of the IRA of interest to the energy industry include an extension and expansion of existing investment and production tax credits for renewable energy; a mechanism to sell tax credits for renewable energy; a production tax credit for existing nuclear plants; newly created hydrogen tax credits and many more incentives. The IRA also implements a new alternative income tax on corporations and creates an excise tax on corporate stock buybacks.
Please refer to the sections below for further details on the major provisions of the IRA, including, where applicable, updates on regulatory guidance by the IRS and Treasury.
The IRA introduces a new 15% corporate alternative minimum tax (Corporate AMT) on the “adjusted financial statement income” (AFSI) of certain “applicable corporations” (generally corporations reporting at least $1 billion average adjusted pre-tax net income on their consolidated financial statements) for tax years beginning after December 31, 2022. The Joint Committee on Taxation (JCT) has estimated that this provision would raise approximately $222.25 billion over the 10-year budget window.
Under the new law, a company’s Corporate AMT is equal to the amount by which the tentative minimum tax (15% of AFSI reduced by AMT foreign tax credits) exceeds the company’s regular tax for the year (including any Base Erosion and Anti-Abuse Tax (BEAT) liability, but before the consideration of general business credits).
In general, the Corporate AMT applies to an “applicable corporation”—defined as any corporation that is not an S corporation, a regulated investment company, or a real estate investment trust, that meets the “average annual adjusted financial statement income test” (Income Test) in one or more tax years ending after December 31, 2021, but prior to the tax year at issue.
In general, the Income Test would be met for a tax year if the average annual AFSI of a corporation in the three tax years ending with the tax year at issue exceeded $1 billion (subject to certain adjustments for newly formed corporations, predecessor corporations, and short tax years). Once a corporation is an applicable corporation, it remains an applicable corporation for all future years, subject to certain limited exceptions. The new law explicitly provides that financial statement net operating losses are not to be taken into account for purposes of the Income Test.
AFSI generally starts with the net income or loss of the taxpayer as reported on its applicable financial statement with certain modifications, including an addback for certain federal and foreign taxes and the ability to use tax depreciation instead of book depreciation. An applicable financial statement includes a corporation’s Form 10-K filed with the SEC, certain audited financial statements, and certain other similar financial statements filed with a federal agency. Companies may claim a credit against regular tax in future years for Corporate AMT previously paid, but the credit cannot reduce that future year’s tax liability below the computed minimum tax for that year.
The IRA amends section 38, the general business credit (GBC) to take into account the Corporate AMT. The IRA limits the availability of GBCs to $25,000 plus 75% of a taxpayer’s net income tax that exceeds $25,000. This generally follows the pre-enactment law paradigm for the ability to use GBCs. For this purpose, net income tax means the sum of regular tax liability and the AMT, reduced by credits allowed under Subpart A and B of Part IV of the Code (credits against tax). Section 901 foreign tax credits are included among the taxes allowed under Subpart B.
On December 27, 2022, Treasury and the IRS issued Notice 2023-7, which provides interim guidance to taxpayers (until regulations are issued) to assist in determining their status as applicable corporations subject to the AMT and in computing applicable financial statement income. Taxpayers may rely on the Notice pending the issuance of proposed regulations.
The Notice provides clarity on tax-free corporate reorganizations, mergers, acquisitions, and divisions which allow such transactions to be excluded from financial statement income, unless there is cash (boot) paid in connection with the transaction. Additionally, the Notice provides several examples of corporate reorganizations when companies join or leave a group and how taxpayers should be computing AFSI for purposes of the applicable corporation test and the three-year test period. Generally, a taxpayer may utilize a reasonable method in performing such AFSI calculations for the new or departing member of the group. Taxpayers do not need to include any cash received, whether through direct pay credits or transferred credits sold to other taxpayers, in AFSI.
The Notice also clarified that a corporation does not need to include in AFSI its share of partnership income if it is a partner in the partnership. The treatment of tax depreciation was also included in the Notice and allows taxpayers to utilize current year tax deprecation (including COGS depreciation) rather than book depreciation. The Notice, however, did not provide any true-up provisions for taxpayers that may have taken accelerated depreciation in prior years and in CAMT years no longer have tax depreciation for that asset. Lastly, the Notice provides relief for taxpayers that may be emerging from bankruptcy, by allowing them to not recognize such debt discharge in income for purposes of AFSI.
The IRS still needs to issue additional guidance on CAMT, primarily for international taxpayers and taxpayers that have mark-to-market financial statement income.
The IRA introduces a new 1% excise tax on corporate stock buybacks starting January 1, 2023. Generally, any domestic corporation which is publicly traded on a national securities exchange will be subject to the new buyback excise tax. A stock buyback or repurchase is defined as a redemption of the corporation stock for cash or property (defined in section 317(b)) and any other economically similar transaction. The excise tax is calculated based on the fair market value of stock repurchased less any stock issued during the year, measured at fair market value; therefore companies should consider the timing of both stock buybacks and issuances. The excise tax also applies to preferred shares issued in connection with publicly traded stock. A few exceptions to the new 1% excise tax include tax-free reorganizations, stock repurchases which then transfer the shares to an employee-sponsored retirement plan or similar plan, and any repurchase where the total value of such transactions does not exceed $1 million in a single tax year.
On December 27, 2022, Treasury and the IRS issued Notice 2023-2, which provides interim guidance to taxpayers (until regulations are issued) on how the new 1% excise tax on stock-buybacks will be imposed and administered. Taxpayers may rely on the Notice pending the issuance of proposed regulations. Further, Treasury issued Announcement 2023-18, which informed taxpayers that they are not required to report or pay the excise tax until the publication of forthcoming regulations. Treasury also said taxpayers would not be subject to any failure to pay penalties for the excise tax prior to the forthcoming regulations. For calendar year taxpayers with years ending December 31, 2023, the filing and payment of the 1% excise tax will not be required until the publication of the forthcoming regulations. There is currently a draft Form 7208 that is expected to be used to report the excise tax and be part of the larger Form 720 Quarterly Excise Tax filing.
The Notice clarifies that, for purposes of the stock repurchase excise tax, a repurchase means solely a redemption under Section 317(b) of the Code (with several exceptions discussed below) or an “economically similar transaction.” For example, the Notice stated that neither of the following types of redemptions would be considered a “repurchase” for purposes of the excise tax:
The following transactions are considered to be economically similar transactions to a repurchase:
Additionally, complete liquidations under Sections 331 and 332 and divisive transactions under Section 355 (other than split-offs) are not considered to be economically similar transactions to a repurchase.
Finally, the Notice also provides for timing and valuation guidance on the repurchased stock. Generally, stock is treated as repurchased at the time at which ownership of the stock transfers to the covered corporation or to the applicable acquiror. The fair market value of the stock is determined by the market price of the stock on the date it is repurchased. If the repurchased stock is traded on an established securities market, the market price must be determined by consistently applying one of four specified methods (daily volume-weighted average price, closing price, average of high and low prices, or trading price at the time of repurchase) to all repurchases throughout the covered corporation's taxable year. If the repurchased stock is not traded on an established securities market, the market price is determined under certain Section 409A principles.
The IRA extended and modified the current Production Tax Credit (PTC) for wind and certain other renewable facilities that are placed in service after 2021 and begin construction before 2025. The IRA also allows for a PTC for solar facilities placed in service after 2021 and begin construction before 2025. The extended credit will apply utilizing a base credit of 0.55 cents/kilowatt-hour (kWh) and a bonus credit of five times that amount or 2.75 cents per kWh if the new prevailing wage and apprenticeship requirements are met (PWA, as described in greater detail below). Additional bonus credits are available if the qualified facilities meet the domestic content requirements or if the project is located in an energy community or low-income community. Projects that begin construction prior to 60 days after the date the government issues guidance on the PWA requirements will be treated as eligible for the bonus rate even if those requirements are not satisfied.
The IRA also extended the Investment Tax Credit (ITC) for qualified energy projects including solar projects. The base credit under the extension is 6% of the basis of qualified energy property and the credit is increased to 30% for projects that satisfy the PWA requirements. Bonus credits are also available for the ITC if domestic content requirements are met or if the project is located in an energy community or low-income community. Additionally, the IRA has a new ITC for standalone energy storage. Energy storage technology is property (other than property primarily used in the transportation of goods or individuals and not for the production of electricity) which receives, stores, and delivers energy for conversion to electricity (or, in the case of hydrogen storage, to store energy), and has a capacity of not less than 5 kilowatt hours.
Moreover, on November 17, 2023, the IRS and Treasury issued proposed regulations, updating rules for the ITC under Section 48 (48 Proposed Regulations). Because regulatory guidance on claiming the ITC has not been revisited since 1987, the 48 Proposed Regulations are significant and largely reflect changes in the energy industry, including technological advances, over the past several decades.
In addition to updating the definition of “energy property” under § 1.48-9 to reflect amendments to Section 48, the 48 Proposed Regulations would adopt a function-oriented approach to describe types of components that are considered energy property. The 48 Proposed Regulations outline two ways property can be classified as energy property: if (1) components of property are functionally interdependent, or (2) the property is an integral part of energy property.
Generally, components of property are functionally interdependent if the placing in service of one component is dependent upon the placing in service of other such components in order to generate or store electricity, thermal energy, or hydrogen or otherwise perform its intended function. As such, energy property, subject to certain exceptions, includes all components necessary for generating or storing electricity or thermal energy up to, but not including, the transmission, distribution, or usage stage.
Property used directly in the intended function of the energy property and essential to the completeness of the intended function is also considered part of the energy property. For example, power conditioning and transfer equipment (and the respective components and parts related to the functioning of those components) are considered energy property because they are integral parts of an energy property. However, roads primarily for access to the site or roads used primarily for employee or visitor vehicles are not integral parts of an energy property. Certain types of intangible property, such as power purchase agreements, renewable energy certificates, goodwill, and going concern value, are not energy property, because they are neither functionally interdependent nor an integral part of energy property.
The distinction between the property being “functionally interdependent” or an “integral part” is particularly important in the context of offshore wind projects. While the preamble to the 48 Proposed Regulations specifies that power conditioning and transfer equipment are not functionally interdependent components, such equipment is considered an integral part of energy property. Even though power conditioning and transfer equipment are not functionally interdependent, they qualify as energy property because they are integral parts of an energy property.
After 2024, taxpayers will be able to take advantage of the PTC under section 45Y or the ITC under Section 48E for a power facility with any technology, so long as the facility’s greenhouse gas emissions rates are at or below zero. For this purpose, the greenhouse gas emissions rate means the amount of greenhouse gases emitted into the atmosphere by a facility in the production of electricity, expressed as grams of CO2e per kWh. In the case of a facility that produces electricity through combustion or gasification, the greenhouse gas emissions rate for such facility must be equal to the net rate of greenhouse gases emitted into the atmosphere by such facility, taking into account lifecycle greenhouse gas emissions as described under the Clean Air Act. Similar rules regarding PWA requirements will be applicable.
As mentioned above, the IRA also introduced for the first time the concept of a “base” and “bonus” credit amount, whereby taxpayers who comply with the “prevailing wage and apprenticeship” requirements will increase their base credit by a factor of five. In order to satisfy the requirements, any laborers employed by the taxpayer or any contractor or subcontractor in the construction of a qualified facility, and with respect to any taxable year during the “relevant period,” in the alteration or repair of such facility, must be paid wages that are not less than the prevailing wages for the construction, alteration, or repair of a similar character in the location in which such facility is located as most recently determined by the Department of Labor. For this purpose, the relevant period is the 10-year PTC period (12 years for Section 45Q carbon sequestration credits) or the five-year recapture period for the ITC. In order to satisfy the apprenticeship requirements, taxpayers must ensure that (i) the applicable percentage of the total labor hours of the construction, alteration, or repair of the qualified facility is performed by qualified apprentices (15% for facilities that begin construction after January 1, 2024), (ii) certain Department of Labor (or applicable state agency) apprentice-to-journeyworker ratios are met (e.g., two journeyworkers for each apprentice), and (iii) every taxpayer, contractor, or subcontractor that employs four or more individuals to perform construction, alteration, or repair of the qualified facility employs at least one apprentice.
The PWA requirements apply to all IRA credits, and are a new concept in the tax law. Given the financial import of the 5x multiplier, taxpayers have been eagerly awaiting regulatory guidance on implementing these new concepts.
On November 30, 2022, the IRS issued Notice 2022-61. The Notice features two important aspects of IRS guidance. The first aspect of the Notice describes which projects are exempt from complying with the PWA requirements. Projects that begin construction on or before January 29, 2023, need not comply with the requirements to receive the full value of the tax credit subsidies. The Notice defines beginning of construction by reference to a set of earlier IRS rules that have been published over the past decade. Those rules liberally permit projects to be treated as under construction when some amount of physical work has commenced either at the project site or by a manufacturer of certain critical project components. Project owners can also incur 5% or more of the project’s cost as a means of establishing that their project is under construction for purposes of those rules (safe harbor rule).
The second aspect of the Notice fills in some important details about how to apply these rules, largely incorporating the well-established principles of the Davis-Bacon Act. The Davis-Bacon Act was enacted by Congress in 1931 and directs the Department of Labor to determine prevailing wage rates for most contractors and subcontractors performing on federally funded or assisted contracts for the construction, alteration, or repair of public works projects. The Department of Labor has issued numerous pieces of guidance interpreting the Davis-Bacon Act, including defining concepts such as “construction, alteration or repair” and “laborer or mechanic.” Nevertheless, the Notice leaves open a number of important questions that will need to be addressed in supplemental guidance, including the definitions of a contractor and subcontractor.
Finally, on a matter of practical importance, the Notice requires a taxpayer, along with any contractors and subcontractors, to maintain books of account and records of work performed in sufficient form to establish that the taxpayer, its contractors, and subcontractors have satisfied the PWA requirements with respect to the facility.
Further, on August 30, 2023, the IRS and Treasury published proposed Treasury regulations (PWA Regulations) providing expansive guidance on the prevailing wage and apprenticeship requirements that taxpayers must satisfy to receive the full credit amount available under the IRA. Taxpayers are permitted to rely on the PWA Regulations with respect to a facility on which construction began on or after January 29, 2023, but before final regulations are published.
The PWA Regulations provided much needed clarity on the following issues:
Consistent with the statutory text of Section 48, the 48 Proposed Regulations would similarly incorporate the PWA requirements of Section 45 in order for taxpayers to receive the full credit amount that was available before the IRA was enacted. Additionally, the 48 Proposed Regulations provide further guidance on the One-Megawatt Exception (as defined below) and the recapture rules.
The PWA requirements are inapplicable only if construction of a facility began before January 29, 2023, or the project has a maximum net output of less than one megawatt of electrical or thermal energy (One-Megawatt Exception). The 48 Proposed Regulations detail how to determine a project’s maximum net output to ascertain whether the One-Megawatt Exception applies and provide the maximum output for electrical generating units, energy storage technologies, thermal energy producing properties, qualified biogas property, and specified clean hydrogen production facilities. The preamble to the 48 Proposed Regulations specifies that electrochromic glass property, fiber-optic solar, and microgrid controllers are ineligible for the One-Megawatt Exception because they do not generate electricity or thermal energy.
The increased credit amount claimed by a taxpayer who failed to satisfy the PWA requirements is subject to recapture such that the taxpayer would only be entitled to the base amount of 6% instead of the full 30% credit amount. The recapture amount also includes an annual ramp-down of 20% of the recapture amount. However, taxpayers can still use the correction and penalty procedures of PWA to avoid recapture. The 48 Proposed Regulations clarify that the 5-year recapture period for the Section 48 tax credit begins on the day an energy project is placed in service.
In the event of a recapture after a tax credit has been transferred pursuant to Section 6418, the transferor must notify the transferee of the recapture event, but the transferee taxpayer is responsible for any amount of tax increase. The 48 Proposed Regulations would also introduce a new annual information reporting requirement to verify compliance with the PWA requirements after the close of each recapture year. The preamble to the 48 Proposed Regulations provides that the IRS expects taxpayers to fulfill the annual compliance reporting obligation when filing their income tax or other annual returns following the close of each recapture year.
In addition to the increase in the base credit amount for satisfying the PWA requirements, energy projects can receive several bonus tax credits, such as the Domestic Content Bonus Credit, Energy Communities Bonus Credit, and Low-Income Communities Bonus Credit.
The Domestic Content Bonus applies to qualified facilities under Section 45 or Section 45Y, energy projects under Section 48, and qualified facilities and energy storage technologies under Section 48E. The Domestic Content Bonus provides for up to an additional 10% increase in tax credit for certain qualified facilities or energy projects (together, Applicable Projects).
To qualify for the credit, a taxpayer must certify to the Secretary of the Treasury that any steel, iron, or manufactured product that is a component of an Applicable Project was produced in the United States by meeting the domestic content requirements described below. Applicable Projects are eligible for a 2% to 10% bonus credit depending on whether the Applicable Project also satisfies (or is deemed to satisfy) the PWA requirements. Generally, to qualify for the Domestic Content Bonus, the following must be satisfied:
The domestic content requirements are to be interpreted consistent with the Federal Transit Authority’s “Buy America” requirements under 49 CFR Section 661.
On May 12, 2023, Treasury and IRS released Notice 2023-38 for the Domestic Content Bonus, which provided the following critical definitions for previously undefined terms:
In addition to defining critical terms, Notice 2023-38 clarified that a manufactured product, which includes components not actually manufactured in the United States, may still be deemed to be manufactured in the United States if a certain percentage of all manufactured product APCs for an Applicable Project are US-based costs.
Generally, the Manufactured Products Requirement is met if all APCs that are Manufactured Products are produced in the United States. A Manufactured Product is produced in the United States (a US Manufactured Product) if:
However, a Manufactured Product in an Applicable Project can be deemed to be produced in the United States if the domestic costs associated with the manufacturing process of all Manufactured Product APCs for that Applicable Project (the Domestic Cost Percentage) is greater than or equal to the required domestic content percentage that applies to that Applicable Project. Notice 2023-38 provides that the Domestic Cost Percentage is determined by dividing the cost of domestic manufactured products and components—which includes both domestically manufactured APCs and domestically produced Manufactured Product Components—by the total cost of all APCs that are manufactured products (regardless of origin). Such costs include production costs for US Manufactured Products and acquisition costs of domestically produced US Manufactured Product Components. Nevertheless, they do not include production costs for non-US Manufactured Products and costs to incorporate APCs in the Applicable Project.
Certain APCs that are found in utility-scale solar PV systems, on- and off-shore wind facilities, and battery energy storage technologies, on the other hand, are automatically categorized as a steel or iron APC or a manufactured product APC.
Notice 2023-38 also makes clear that the domestic content requirements are not concerned with subcomponents, which eases the burden of taxpayers trying to determine if they qualify for the bonus credit. For instance, the Steel or Iron Requirement does not apply to steel or iron used in subcomponents of Manufactured Product Components, which includes without limitation nuts, bolts, screws, or similar items that are made primarily of steel or iron but are not structural in function. Similarly, whether a Manufactured Product is produced in the United States is determined based only on the location of the manufacturing processes for the Manufactured Product and the Manufactured Product Components, and not for any subcomponents.
Lastly, Notice 2023-38 provides that an Applicable Project may qualify as originally placed in service even though it contains some used property, provided that the fair market value of the used property is less than 20% of the Applicable Project’s total value (80/20 Rule). In other words, 80% or more of the Applicable Project’s value must be new property. If the Applicable Project meets the 80/20 Rule, it is eligible for the Domestic Content Bonus if the new property meets the domestic content requirements outlined above.
The Energy Community Bonus provides a 10% multiplier to a project’s PTC value and a potential 10% adder to the ITC rate if the project is located in an “energy community” and satisfies the PWA requirements. If the PWA requirements are not met, the bonus is limited to 2% of the base PTC or ITC.
On April 4, 2023, the IRS released Notice 2023-29 outlining the rules for claiming the Energy Community Bonus under Sections 45, 45Y, 48 and 48E. Energy communities include:
1. Brownfields sites defined under 42 U.S.C. § 9601(39)(A), which are real property, the expansion, redevelopment or reuse of which may be complicated by the presence or potential presence of a hazardous substance, pollutant or contaminant and certain mine-scarred land (with significant exclusions). Safe harbor categories include brownfield sites that are:
a. already viewed as a brownfield site under federal, state, territorial or federally recognized Indian tribal programs based on potential pollution;
b. a Phase II environmental site assessment concluding that a hazardous substance, pollutant or contaminant is present; or
c. an ASTM E1527 Phase I Environmental Site Assessment has been completed with respect to the site for projects with a nameplate capacity less than 5MW (AC);
2. Statistical areas where at least 0.17% direct employment or at least 25% of the local tax base is dependent on extracting, processing, transporting or storing fossil fuels, and higher than average unemployment for the previous year and
3. Coal closure areas where a coal mine or coal-fired facility was closed after 1999 or coal-fired generating unit was retired after 2009.
All of these categories are subject to changes over time; therefore, a project may be included or excluded based on the year of determination. In other words, projects claiming a PTC must be “located in” an energy community. Whether a project is located in an energy community is determined separately for each taxable year of the project’s 10-year credit period. As for projects claiming an ITC, they need to be “placed in service” in an energy community to qualify for the bonus credit amounts. In both cases, the geographic qualifier is determined by whether 50% or more of a facility’s generating output or storage capacity is located in the appropriate area (Nameplate Capacity Test), and if that cannot be measured, the determination shifts to whether 50% or more of the facility’s square footage is in the appropriate area (the Footprint Test).
Given that the categories of energy communities are subject to change over time, the IRS anticipated the difficulty of this moving target for developing projects with multi-year build times and created a special beginning of construction rule. This rule states that if a taxpayer begins construction of a project on or after January 1, 2023, in a location that is an energy community as of the beginning of construction date, then, with respect to that project, the location will continue to be considered an energy community for the duration of the 10-year credit period for Sections 45 and 45Y or on the placed-in-service date for Sections 48 and 48E. Notice 2018-59 provides guidance for determining when construction begins.
Notice 2023-29 was also released with three appendices. Appendix A contains delineations of the statistical areas, Appendix B lists statistical areas with significant direct employment in the relevant fossil fuel industries, and Appendix C lists census tracts in the coal mine and plant closure categories. Notice 2023-47 was also released afterwards to provide appendices, which contain information that taxpayers may use to determine whether they meet certain requirements under the Statistical Area category or the Coal Closure Category. Along with the appendices, Treasury and IRS have collaborated with the Interagency Working Group on Energy Communities to create a mapping tool to easily identify eligible energy communities.
The Low-Income Communities Bonus provides a 10 or 20 percentage point increase to the ITC for specifically qualified solar and wind energy facilities with a maximum net output of less than five megawatts (measured in alternate current).
On August 10, 2023, the Treasury and IRS issued the final regulations concerning the application of the Low-Income Communities Bonus, which became effective on October 16, 2023.
To receive the Low-Income Communities Bonus, a portion of the annual environmental justice solar and wind capacity limitation (Capacity Limitation) is allocated to the applicable project. The available Capacity Limitation for allocation for 2024 is set at 1.8 gigawatts of direct current capacity.
Moreover, the qualified wind or solar facility must have a maximum net output of less than five megawatts and fall within one of the four categories to be eligible for the Low-Income Communities Bonus:
1. Category 1: These facilities can receive an increase of 10 percentage points, limited to a 700-megawatt Capacity Limitation, for eligible property that is located in a low-income community. Low-income Community includes any population census tract that has:
a. A poverty rate of 20% or greater; or
b. Either of the following:
i. A median family income that does not exceed 80% of the statewide median family income if the census tract is not located in a metropolitan area; or
ii. A median family income that does not exceed 80% of the greater of statewide median family income or the metropolitan area’s median family income if the census tract is located in a metropolitan area.
2. Category 2: These facilities can receive an increase of 10 percentage points, limited to a 200-megawatt Capacity Limitation, for eligible property that is located on Indian Land as defined in Section 2601(2) of the Energy Policy Act of 1992. This includes any land that is:
a. Located within the boundaries of an American Indian reservation, pueblo, or rancheria;
b. Held in trust by (or held by the United States for the benefit of) an American Indian tribe or individual, or a dependent American Indian community;
c. Owned by an American Indian tribe and was conveyed to an Alaska Native Corporation (ANC) (or was conveyed to an ANC in exchange for such land);
d. Located in a census tract in which the majority of residents are Alaska Natives; or
e. Located in a census tract in which the majority of residents are enrolled members of a federally recognized tribe or village.
3. Category 3: These facilities are entitled to an increase of 20 percentage points, limited to a 200-megawatt Capacity Limitation, for eligible property that is part of a qualified low-income residential building project. A qualified low-income residential building project includes a:
a. A residential building which participates in a covered housing program as defined in Section 41411(a) of the Violence Against Women’s Act of 1994
b. Multifamily housing program under the U.S. Department of Agriculture’s Rural Housing Service
c. Housing program administered by a Tribally designated housing entity (as described in section 4 of the Native American Housing Assistance and Self-Determination Act of 1996)
d. Other affordable housing programs as the Secretary of State may provide.
4. Category 4: These facilities are entitled to an increase of 20 percentage points, limited to a 700-megawatt Capacity Limitation, for eligible property that is part of a qualified low-income economic benefit project. A facility will be treated as part of a qualified low-income economic benefit project if at least 50% of the financial benefits of the electricity produced by such facility are provided to households with income of less than 200% of the poverty line (as defined in section 36B(d)(3)(A) of the Code) applicable to a family of the size involved, or less than 80% of area median gross income (as determined under section 142(d)(2)(B) of the Code).
The IRA created new Sections 6417 (Direct Pay) and 6418 (Transferability). Section 6417 allows for Direct Pay for the first five years of the project, meaning a taxpayer can receive cash from the Treasury for the value of the credit. Alternatively, Section 6418 allows for energy credits to be transferred for cash to a third party in a nontaxable transaction to the seller. The transfer of credits allows a producer of clean energy who may not have the ability to utilize credits, to nonetheless monetize the credit through the sale, potentially eliminating the need for a traditional tax equity structure.
Under Section 6417, “applicable entities” (AEs), such as states, local governments, nonprofits, tribal entities, Alaska Native Corporations, the Tennessee Valley Authority, rural electric cooperatives, and US territories (and their political subdivisions), can receive direct payment from the IRS for the excess taxes they have paid or are deemed to have paid. In other words, this election makes the applicable tax credits “refundable.” The eligible tax credits for AEs under Section 6417 include:
Meanwhile, “electing entities” (EEs) are taxpayers that are not AEs who may elect direct pay for tax credits under Sections 45Q, 45V, and 45X for the first five years of production. While EEs do not need to make the election each year, a new registration number is required annually. EEs can elect to transfer the credits under Section 6418 in later years when the five-year direct pay election is not in effect.
On June 14, 2023, the IRS and Treasury issued proposed regulations on Direct Pay and temporary regulations on Transferability (DP&T Regulations). The DP&T regulations address several issues:
On March 5, 2024, the IRS and Treasury released the final regulations on Direct Pay (6417 Final Regulations). The 6417 Final Regulations clarified certain technical and procedural questions related to the “no excess benefit rule” that arose from the proposed regulations on Section 6417. For instance, when entities receive grants, forgivable loans, and similar financial aid for developing or acquiring properties eligible under various Investment Tax Credit provisions, these financial amounts are incorporated into the property’s basis for calculating the tax credit. However, when the restricted tax-exempt amount, combined with the tax credit, exceeds the cost of the investment-related credit property, the amount of the credit is reduced to be equal to the amount of that cost.
Generally, such eligible entities must own the underlying credit property and conduct the activities giving rise to the credit. However, the 6417 Final Regulations provide a special exception for the Advanced Manufacturing Production Tax Credits under Section 45X. Generally under Section 45X, the applicable credit property is the facility in which eligible components are produced. Under the exception in the 6417 Final Regulations, the AE or EE is the taxpayer to which the Section 45X credit is determined, even though the producer of eligible components may not own the facility. However, further interaction between Treasury regulations proposed under Section 45X and the 6417 Final Regulations on direct pay presents some related ambiguity. Section 45X typically assigns the credit to the component manufacturer by default but also permits a contracting party to claim the credit if there is a written agreement to that effect. This arrangement suggests that the contracting party, once designated as the recipient of the Section 45X credit via such an agreement, becomes eligible to make a direct pay election.
The 6417 Final Regulations also prohibit making a direct pay election for credits that are transferred to an AE or EE, a practice known as “chaining”. More specifically, chaining involves the transfer or sale of tax credits under Section 6418 to an AE or ET, which then would make a direct pay election. The proposed regulations on direct pay explicitly indicated that chaining would be challenging to monitor and administer and could be prone to fraud. As chaining has been a topic of debate since the IRA was passed, the preamble to the 6417 Final Regulations states that Treasury will continue to evaluate whether chaining should be permitted in limited circumstances.
Furthermore, in general, to receive the direct payment of tax credits, the AE or EE must satisfy the pre-filing registration requirements, which include completing an online pre-filing process through an IRS electronic portal. Treasury and the IRS declined to specify any timeframes for processing pre-registration submissions or tax returns related to direct pay elections. The lack of defined processing timelines by Treasury and the IRS introduces uncertainty, yet the preamble of the 6417 Final Regulations stated that AEs will be subject to standard examination procedures akin to regular taxpayers (e.g., the procedures laid out in Publication 5884, Inflation Reduction Act (IRA) and CHIPS Act of 2022 (CHIPS) Pre-Filing Registration Tool User Guide and Instructions). The ambiguity surrounding the scope of prefiling registration review and whether taxpayers can appeal any denials of registration numbers also leaves room for interpretation and necessitates careful navigation by entities opting for direct pay elections.
The 6417 Final Regulations apply to taxable years ending on or after March 11, 2024, and will also become effective on Mary 10, 2024. Taxpayers may choose to apply the 6417 Final Regulations to earlier years so long as they adhere to the rules in their entirety.
The IRA introduces a new tax credit specifically for hydrogen production. Starting in 2023 and running 10 years for projects placed in service prior to January 1, 2033, the new Section 45V credit allows for a PTC or an ITC. The base amount of the PTC is $0.60 cents/kg of clean hydrogen produced, adjusted annually for inflation, and can be increased to $3/kg if PWA requirements are met.
In order to qualify for the maximum amount of the PTC, the underlying source producing the hydrogen generally needs to come from green hydrogen and the project needs to be located in the United States. The hydrogen can be produced and available for sale or for use in the ordinary course of the taxpayer’s trade or business. Alternatively, a taxpayer can claim an ITC with a base rate of 6% of the eligible costs, which can be increased to 30% if the PWA requirements are met. Similar rules apply to the ITC, in that the credit can qualify for either direct pay or be transferred. Below is a chart summarizing the qualifications of the Section 45V hydrogen credit based upon CO2E emissions and corresponding credit:
| CO2E emissions equivalent per kg hydrogen | PTC Base Rate | Bonus Rate | ITC Base Rate | Bonus Rate |
| Less than .45 kg | $.60/kg | $3 | 6% | 30% |
| Between .45 kg and 1.5 kg | $.20/kg | $1 | 2% | 10% |
| Between 1.5 kg and 2.5 kg | $.15/kg | $0.75 | 1.50% | 7.50% |
| Between 2.5 kg and 4 kg | $.12/kg | $0.60 | 1.20% | 6% |
To satisfy the new PWA requirements (see above) for the bonus credit rates, a taxpayer must ensure that laborers and mechanics (and subcontractors) involved in the construction or repair of the project are paid prevailing wages for that region, as defined and published by the Department of Labor. Additionally, there needs to be an apprentice program for the project, meaning a certain number of the total labor hours on a project need to be filled by qualified apprentices, which again coincide with ratios published by the Department of Labor by geographic region and job type. Similar penalties listed under the PWA requirements will be imposed and opportunities to cure will be available. The domestic content requirement refers to the sourcing of the materials for the hydrogen project, but generally requires the steel and iron to be sourced in the U.S. and a minimum percentage of manufactured products must come from the U.S. A taxpayer claiming a Section 45V hydrogen credit can also claim a credit under Section 45U for existing nuclear plants but cannot claim a carbon capture credit under Section 45Q.
On December 22, 2023, the Treasury released the highly anticipated proposed regulations relating to Section 45V (45V Proposed Regulations).
The 45V Proposed Regulations define key terms, such as “lifecycle greenhouse gas emissions,” “qualified clean hydrogen,” “provisional emissions rates,” and “qualified clean hydrogen production facility.” Treasury proposed rules for:
The rules would include designation of the applicable Greenhouse gases, Regulated Emissions, and Energy use in Transportation (GREET) Model. These rules, if adopted, would greatly inform the feedstock eligibility criteria for qualifying clean hydrogen, and likely will have a dramatic impact on the development at-scale of the hydrogen value chain in the United States. Treasury is seeking further comments on many topics that will inform the final regulations.
Under the IRA, the calculation of lifecycle GHG emissions will include all upstream emissions from “well-to-gate” (i.e., through the point of production). The preamble of the 45V Proposed Regulations provides that this would include all emissions associated with feedstock growth, gathering, extraction, processing, and delivery to the qualified facility. Emissions associated with the hydrogen production process, such as electricity used by the hydrogen production facility and any capture and sequestration of carbon dioxide generated by the hydrogen production facility, would also be included.
The IRA deferred to Treasury on whether to rely on the GREET Model or alternatively, adopt a “successor” model to calculate lifecycle GHG emissions. Treasury has opted to adopt a successor GREET Model and proposes using the 45VH2-GREET Model developed by Argonne National Laboratory, which has been purpose-built for the hydrogen credit.
The 45VH2-GREET Model includes various hydrogen production pathways. As of the publication date of the 45V Proposed Regulations, the 45VH2-GREET Model includes:
For taxpayers using production pathways or hydrogen production technologies that are not included in the 45VH2-GREET Model, the 45V Proposed Regulations permit those taxpayers to petition the Secretary of Treasury for a provisional emissions rate (PER) that would be analogous to the lifecycle GHG emissions rate calculated using the 45VH2-GREET Model. Such PER would only be allowed as long as the production pathway was not included in the annual 45VH2-GREET Model.
To confirm that the electricity used in hydrogen production is sourced from renewable or zero-emission sources, taxpayers may use Energy Attribute Certificates (EACs), including Renewable Energy Certificates (RECs) and other zero-emission attribute certificates, such as those associated with nuclear power generation. The 45V Proposed Regulations impose three new criteria for EACs to qualify for purposes of the hydrogen credit, sometimes indicated as the “three pillars”:
An existing facility originally placed in service before January 1, 2023, and not producing qualified clean hydrogen before modification, will be considered newly placed in service on the date the property required for modification is placed in service. This applies only if the modification aims to enable the production of qualified clean hydrogen and does not include mere changes of fuel inputs such as a switch from conventional natural gas feedstock to renewable natural gas. Retrofits of existing facilities may also establish a new in-service date if the fair market value of the used property is not more than 20% of the retrofitted facility’s total value.
The preamble of the 45V Proposed Regulations provides some criteria for producing hydrogen from biogas, including landfill gas, under specific conditions. Treasury and the IRS plan to finalize regulations that would include additional methods for hydrogen production using renewable natural gas and fugitive methane sources, such as coal mine and coal bed methane.
A new zero-emission clean nuclear power production credit is created under section 45U for electricity generation using nuclear energy at a qualified nuclear power facility and sold to an unrelated third party over the 10-year period after 2023 and through 2032. Qualified nuclear power facilities must be placed in service before the date of enactment of this section and do not include an advanced nuclear power facility defined under section 45J(d)(1).
The base PTC amount is 0.3 cents/kWh of electricity produced and sold (subject to an inflation adjustment), which exceeds the reduction amount for the taxable year. The associated bonus PTC is multiplied by five or 1.5 cents/kWh if certain wage requirements are met. The 5x multiplier for the 45U credit does not include an apprenticeship requirement that is present for many of the other renewable energy credits.
The 45U credit is reduced as the sale price of such electricity increases. The credit for any taxable year is reduced by 16% of the excess gross receipts from any electricity produced and sold by the qualified nuclear power facility over the product of 2.5 cents multiplied by the amount of electricity sold during the year. Therefore, facilities with receipts of less than 2.5 cents/kWh or $25/MWh would be eligible for the full credit amount. The reduction amount for any taxable year is the lesser of (1) the PTC amount multiplied by the electricity generated and sold, or (2) the amount equal to 16% of the excess gross receipts from any electricity sold over 2.5 cents (subject to inflation) multiplied by the amount of electricity sold.
The gross receipts shall include any amount received by a taxpayer during the taxable year with respect to the qualified nuclear power facility from a zero-emission credit program, except if the full amount of the credit calculated is used to reduce payments from such zero-emission credit program. Zero-emission credit program means any payments with respect to a qualified nuclear power facility as a result of any federal, state, or local government program for (in whole or in part) the zero-emission, zero-carbon, or air quality attributes of any portion of electricity produced by such facility. For purposes of determining the amount received during such taxable year, the taxpayer shall take into account any reductions required under such program.
Like the other credits included in the IRA, nuclear PTCs generated under Section 45U are eligible to be transferred. Therefore, in lieu of using the tax credits to offset their own tax liability, taxpayers that own nuclear assets that generate PTCs may elect to sell the PTCs to unrelated parties. The proceeds from such transfers are nontaxable to the taxpayer that generated the PTC.
Due to the significance of the reduction amount in the PTC calculation and its incorporation of the term “gross receipts,” significant open questions remain on how this term will be defined for purposes of computing the reduction amount. In an attempt to seek clarity, the industry is currently working together to solicit administrative guidance from Treasury and the Internal Revenue Service on how to define “gross receipts.”
Treasury has yet to issue any guidance on the 45U nuclear PTC and it is likely that guidance will not be forthcoming until the second half of 2024.
With the Code receiving yet another set of legislative changes, after the Tax Cuts and Jobs Act in 2017 (TCJA) and the Coronavirus Aid, Relief, and Economic Security Act in 2020, how states incorporate the Act into their own tax laws is an important issue taxpayers must consider when determining the full impact of the Act on their business operations.
States generally incorporate the Code into their own tax laws through two main methodologies, “rolling conformity” and “static conformity.” States that utilize “rolling conformity” adopt the Code as amended and do not need the state legislature to act for new provisions of the Code to be incorporated into the states’ tax laws. Conversely, states that utilize “static conformity” adopt the Code as of a specific date. Here, the state legislature must act to advance the conformity date for any new provisions of the Code to be incorporated into the state’s tax laws. It should be noted that a small number of states utilize neither rolling conformity nor static conformity, but rather conform to only specific provisions of the Code or adopt changes to the Code only if certain conditions are met such as revenue impact.
As discussed above, the IRA introduces a new 15% Corporate AMT on the adjusted financial statement income of certain large corporations for tax years beginning after December 31, 2022. In those states that impose a Corporate AMT, the majority do not calculate tax due based on a corresponding alternative minimum tax liability determined at the federal level. In these instances, the corporate AMT provisions are not likely to have a significant state tax impact. On the other hand, if the state liability is tied to the liability determined at the federal level, state conformity to the Code will be important in calculating alternative minimum tax liabilities.
For example, Alaska imposes an alternative minimum tax at a rate of 18% of the applicable federal alternative minimum tax. Alaska utilizes rolling conformity to the Code. As a result, Alaska’s alternative minimum tax liability beginning in tax years after December 31, 2022 is likely based on the corporate AMT of the Act. Another state that imposes an alternative minimum tax that references the federal alternative minimum tax provisions is California. California utilizes static conformity and conforms to the Code as of January 1, 2015. Therefore, the Corporate AMT provisions would not be incorporated for California purposes unless state legislative action is taken.
For multistate taxpayers, the previous examples of Alaska and California highlight the importance of considering state conformity to the Code. After the IRA was passed, the Joint Committee of Taxation estimated the Corporate AMT would raise approximately $222.25 billion over the 10-year budget window. Mechanisms to generate additional state revenues, especially considering revenue shortfalls caused by the health pandemic over the last couple of years, are a shared goal across state legislatures. Taxpayers should continue to monitor state responses to the IRA such as changes to conformity to the Code or the enactment of state-specific legislation that may seek to drive additional state tax funding.
For tax years beginning after 2022, the IRA provides that a taxpayer may elect to transfer the PTC and/or ITC to an unrelated taxpayer for a cash payment and exclude such sale proceeds from gross income. The transferability election must be made annually and separately with respect to each facility. Transferability has never been available for federal tax credits, and it remains to be seen how the market for the tax credits and the associated tax credit sale transactions develop.
From a state perspective, the starting point for determining state taxable income is federal taxable income. Under the IRA, proceeds from the sale of federal energy credits would not be included in the state taxable income starting point – assuming the state conforms to the current version of the Code. In states that have static conformity to the Code as of a date prior to August 16, 2022, or if a state decouples from Section 6418, a situation arises where the proceeds from the transfer of PTC or ITC credits may create state taxable income, while being excluded from federal taxable income. Additional consideration should be given to the tax status of the entity selling the federal credits. States can utilize different conformity methodologies to the Code depending on the entity type. For instance, in Pennsylvania, for corporate income tax purposes, Pennsylvania is a rolling conformity state, and would therefore require a state specific modification to decouple from the determination of federal taxable income. For personal income tax purposes, however, Pennsylvania does not conform to the Code, but rather selectively conforms to certain provisions of the Code. This highlights the possibility that there can be differences in the treatment of the same item impacting taxable income (i.e. proceeds from credit transfers, 163(j), etc.) between different entity types, even though each entity may be reporting activity to the same state.
Furthermore, if a state should require the proceeds be included in the taxpayer’s state taxable income base, then consideration should also be given as to how those proceeds should be represented in the taxpayer’s state apportionment formula. The sale of credits is likely not considered the sale of tangible personal property, and therefore, taxpayers will need to pay special attention to the state rules that control how to properly source the sale of intangible assets.
Aside from an income tax perspective, some states impose a tax on gross receipts—which may not necessarily be tied to taxable income. A state gross receipts tax that is based on commercial activity in the state could include the revenue generated from the sale of federal ITCs and/or PTCs since those transfers would have resulted in proceeds received by the selling entity. While those proceeds are excluded from the determination of federal taxable income, those same proceeds may not be excluded from a gross receipts tax base at the state level. In these states, further examination is required to determine whether gross receipts received from the sale of PTCs and/or ITCs would be subject to a state gross receipts tax—even though the taxable income generated from that sale may be exempt from an income tax perspective.
The transferability of federal energy credits will impact the project finance landscape by changing the way developers and their financial partners can share the economic benefit of the incentives. If taxpayers have plans on generating new ITC or PTC credits with the intent to sell those credits, additional consideration should be given on where a project is placed and how that state conforms to the IRA. This will help to avoid any surprises where income excluded from tax at the federal level may be subject to tax at the state level.
On a related point, taxpayers should also analyze whether state specific credits are available based on the type of project being commenced in the state. With the IRA generating a lot of attention of the credits available at the federal level, state credits can provide additional tax benefits that taxpayers can take advantage of.
If taxpayers claim an ITC, the basis of property must be reduced by 50% of the credit amount. While not a new provision of the IRA, it is important to remember how state depreciable basis interacts with the basis utilized for federal depreciation purposes. In most cases, state depreciable basis will reference the depreciable basis utilized at the federal level. For instance, New York provides that “Depreciable basis is the cost or other basis reduced by the part of the basis you elected to amortize or expense under Section 179, and any federal investment credit subtracted when computing the federal unadjusted basis of the asset.” Given the mechanics of determining depreciable basis in New York, any reduction in basis at the federal level relating to ITC credits awarded is likely to also reduce the New York asset basis.
Conversely, South Carolina explicitly decouples from Sections 22 through 54, relating to tax credits. In the computation of South Carolina taxable income, if for federal income tax purposes a taxpayer claims a credit which requires a reduction of basis to Section 38 property under Section 50(c), the taxpayer may deduct the amount of the basis reduction for South Carolina income tax purposes by the amount of the basis reduction in the tax year in which basis is reduced for federal income tax purposes. In this specific instance, South Carolina would not recognize the basis adjustment to the assets placed in service that were subject to a federal ITC because South Carolina does not adopt Section 48 or Section 50. On the South Carolina income tax return, the taxpayer would report a modification to taxable income, equal to the amount of the basis reduction computed for federal income tax purposes. At the same time, the statutes provide that for South Carolina depreciation purposes, the taxpayer would also get the benefit of the full cost basis of the assets – creating a double benefit.
As taxpayers generate federal tax credits that require adjustments to property basis, a review of the state conformity provisions to the Code and state modifications is important. This review will help ensure the proper basis is utilized in determining state depreciation expense deductions and any required state modifications are properly reported.
There has been a bipartisan tax bill introduced in early 2024 that was negotiated between Ron Wyden in the Senate and Jason Smith in the House of Representatives. The Tax Relief for American Families and Workers Act of 2024 was passed by the House on January 31, 2024, and contains both business and individual provisions. It is currently residing in the Senate Finance Committee, but no final decision as of this publication has been announced by Senate Majority Leader Schumer as to when the bill may be brought to the floor or if it will undergo any amendments in the Senate Finance Committee.
There are three primary business provisions in the bill, and each of these changes operates to extend certain provisions of the TCJA. The first is to extend 100% bonus depreciation for qualified property placed in service from 2023 through 2025. Under current law as passed by the TCJA, bonus depreciation began phasing down in 20% increments in 2023, so this provision would effectively delay the implementation date of the phasedown. The second provision is to reverse the Section 174 requirement to amortize research and development expenses, so that taxpayers could fully deduct Section 174 expenses incurred from 2022 through 2025. The last provision aims to keep the earnings before interest, taxes, depreciation, and amortization calculation of adjusted taxable income, concerning the business interest limitation deduction, through 2025, rather than limiting the deduction to the earnings before interest and taxes.
