Energy Tax Credits for a New World Part VII: Low-Income Communities Bonus Credits

What is the Low-Income Communities Bonus Credit?

The Low-Income Communities Bonus Credit available through the Inflation Reduction Act of 2022 (IRA)[1] is designed to increase the siting of, and access to renewable energy facilities in low-income communities, encourage new market participants, and provide social and economic benefits to individuals and communities that have been historically overburdened with pollution, adverse health or environmental effects, and marginalized from economic opportunities.[2]

The Low-Income Communities Bonus Credit supports “a transformative set of investments designed to create jobs, lower costs for American families, and spur an economic revitalization in communities that have historically been left behind.”[3] With the Low-Income Communities Bonus Credit the U.S. government is helping to “lower energy costs and provide breathing room for hard-working families, invest in good-paying clean energy jobs in low-income communities, and support small business growth.”[4]

The Low-Income Communities Bonus Credit is an investment tax credit (ITC) available for certain clean energy investments in low-income communities, on Indian lands, with certain affordable housing developments, and for certain projects benefiting low-income households.[5] It is an ITC for certain clean energy investments in a “Qualified Solar or Wind Facility,” that is, a facility with a net output of less than five megawatts. Unlike most of the other tax credits we have looked at in this Q&A with Andie series, there is a competitive bidding application process. Projects must receive a “Capacity Limitation Allocation Amount” to receive these credits.

What are the eligibility categories for the Low-Income Communities Bonus Credit?

There are four project eligibility criteria to qualify for the Low-Income Communities Bonus Credit:

  1. It is located in a “low-income community” (Category 1)
  2. It is located on “tribal Indian land” (Category 2)
  3. It is installed on certain federal housing projects that are qualified low-income residential building facilities (Category 3)
  4. It serves low-income households as a “qualified low-income economic project” (Category 4)

These eligibility categories are discussed in what follows.

Which tax credits do Low-Income Communities Bonus Credits apply to?

The Low-income Communities Bonus Credit is an additional bonus credit available for ITC-eligible credits at Internal Revenue Code (Code) Section 48, Energy Property ITC, and Section 48E, Clean Energy ITC (CEITC). Section 48 applies to an “eligible facility” (that is, a qualified solar or wind energy facility) for which construction begins before 2025; while the CEITC applies to construction in qualifying clean electricity generating facilities and energy storage technologies that are placed in service after December 31, 2024.[6] The base credit may be increased by 10 percent (for a project located in a low-income community or on Indian land) or by 20 percent (for a qualified low-income residential building project or a qualified low-income economic benefit project).[7]

Because the Section 48 credit expires at the end of 2024 and the Section 48E (CEIT) becomes effective January 1, 2025, we will need to look at Section 48 separately from Section 48E (CEITC) when we address the allocation procedures.

How is the Low-Income Communities Bonus Credit calculated?

The Low-Income Communities Bonus Credit is one of the few IRA energy tax credits that requires an application process and the granting of a “capacity limitation allocation amount.” For allocations in 2023 and 2024, the Section 48(e) ITC provides an increased tax credit for an eligible facility that is part of a “qualified solar or wind energy facility” and that receives a capacity limitation allocation amount. For allocations in 2025 and thereafter, the Section 48E (CEITC) credit applies to a broader group of facilities than those covered under Section 48(e).[8] For both Section 48 and 48E (CEITC), the base credit amount is six percent of a qualified investment (that is, the tax basis of the energy property), and that amount can be increased by 10- or 20-percentage points with the Low-Income Communities Bonus Credit, depending on whether the project meets certain eligibility category requirements.[9] The 10 percent credit is available for an eligible facility in a low-income community or on Indian land, while the 20 percent credit is available for a “qualified low-income residential building project” or a “qualified low-income economic benefit project.”

What is a qualified solar or wind facility?

A Qualified Solar or Wind Facility is an eligible facility if it meets three requirements.[10] First, it generates electricity solely from a wind facility, solar energy property, or small wind energy property. Second, it has a maximum net output of less than five megawatts as measured in alternating current. And third, it is described in at least one of the four Low-Income Communities Bonus Credit project categories.[11]

Because the eligible facility must have a maximum net output of less than five megawatts as measured in alternating current, can applicants divide larger projects into smaller ones to meet the five megawatts requirements?

No. The Treasury has issued Final Regulations on Low-Income Communities Bonus Credit (Final Low-Income Communities Regulations),[12] effective August 15, 2023. The Final Low-Income Communities Regulations provide that the capacity limitation allocation amounts will be made on a “single project factors test.”[13] This is intended to prevent applicants from artificially dividing larger projects into multiple facilities in an attempt to circumvent the requirement for the maximum net output.[14]

When can a Qualified Solar or Wind Facility be placed in service?

A project cannot be placed in service until after it receives the capacity allocation.[15] This is because the Treasury holds that “requiring projects to be placed in service after allocation provides the best way to promote the increase of, and access to, renewable energy facilities that would not be completed in the absence of the program.”[16] This is not viewed as an impediment because Section 48(e)(4)(E)(i) provides a “lengthy window of four years to place a facility in service following an Allocation of Capacity Limitation.”[17] Section 48E (CEITC) also provides a four-year window to place the facility in service.[18]

Definitions

What is a Category 1 low-income community for purposes of the Low-Income Communities Bonus Credit?

A Category 1 low-income community is a community that is located in a census area where the poverty rate is at least 20 percent or more, or the median family income is 80 percent or less than the median family income in the state where the community is located.[19] If the census tract is in a metropolitan area, the median family income cannot be more than 80 percent of the statewide median family income or the metropolitan area’s median family income.

The poverty rate for an eligible Category 1 low-income census tract is generally based on the threshold for low-income communities set by the New Markets Tax Credit (NMTC) Program, as noted in the Treasury Regulations. The NMTC updates its eligibility data every five years based on poverty estimates from the American Community Survey (ACS). New eligibility tables and maps for the NMTC program were released on September 1, 2023, which use underlying ACS estimates from 2016 to 2020.[20] The next NMTC update will include ACS estimates from 2021 to 2025, at which point applicants will have a period of one year following the date that the 2021-2025 NMTC is released to use the 2016-2020 NMTC dataset.[21]

How is Category 2 tribal Indian land defined?

Category 2 Tribal Indian land is land of “any Indian tribe, band, nation, or other organized group or community that is recognized as eligible for the special programs and services provided by the United States to tribes (Indians) because of their status.”[22] To qualify as Indian land, the property must meet the definition of Section 2601(2) of the Energy Policy Act of 1992, which is defined as, “Indian reservations; public domain Indian allotments; former Indian reservations in Oklahoma; land held by incorporated Native groups, regional corporations, and village corporations under the provisions of the Alaska Native Claims Settlement Act[23]; and dependent Indian communities within the borders of the United States whether within the original or subsequently acquired territory thereof, and whether within or without the limits of a State.”[24]

The Energy Policy Act of 1992 was amended by the Energy Act of 2020 to include in the definition of land occupied by a majority of Alaskan Native Tribe members.[25]

How is a Category 3 qualified low-income residential building project defined?

A Category 3 qualified low-income residential building project is a federally subsidized residential building facility “installed on the same parcel or on an adjacent parcel of land that has a residential rental building that participates in an affordable housing program, and the financial benefits of the electricity produced by such facilities are allocated equitably among the occupants of the dwelling units or the building.”[26] Projects must be part of a “qualified program”: one among various federal housing assistance programs as are set out in the Treasury Regulations. For state programs to qualify to receive the 20 percent bonus credit, they must be part of a qualified federal program. To remain a qualified low-income residential building facility, a project must maintain its participation in a covered housing program for the entire five-year tax credit recapture period.

How does a Category 4 qualified low-income economic benefit project assist low-income households?

A qualified low-income economic benefit project is one where at least 50 percent of the financial benefits of the electricity produced are provided to households with income of less than 200 percent of the poverty line, or 80 percent of the area’s median gross income.[27] The financial benefits of a low-income economic project benefiting low-income households can only be delivered in utility bills savings. “Other means such as gift cards, direct payments, or checks are not permissible. Financial benefits for these facilities must be tied to a utility bill of a qualifying household. The Treasury Department and the IRS may consider other methods of determining Category 4 financial benefits in future years.”[28]

Allocation Process

How is the annual Capacity Limitation allocated across the four facility categories?

The annual Capacity Limitation amount is divided across each facility category as is set out in each program year. For the 2023 and 2024 Program Years, for example, we have IRS Notices setting out the Allocation Process. The Applicable Bonus Credit is available at Section 48. For the calendar year 2025 and succeeding years, the applicable bonus credit is available at Section 48E (CEITC). On September 3, 2024, the Treasury issued Proposed Regulations addressing Section 48E (CEITC) (Proposed 48E Allocation Regulations).[29]

For the 2024 Program Year, for example, the annual Capacity Limitation is divided across each facility category “plus any carried over unallocated Capacity Limitation from the 2023 Program Year.”[30]

 Does the Low-Income Communities Bonus Credit have a competitive bidding application?

Yes. The Low-Income Communities Bonus Credit has a competitive bidding application process that applies to each of the four eligibility categories. An annual allocation of up to 1.8 gigawatts (GWs) is available, in the aggregate, to the four categories of qualified solar or wind facilities with a maximum output of less than five megawatts.[32]

How does competitive bidding work?

Since it was introduced for the 2023 program year, competitive bidding has been very successful. The Low-Income Communities Bonus Credit program is extremely popular. The 2023 program—the first year of the competitive bidding process—was significantly over-subscribed with more than 46,000 applications submitted. Applications were for qualified facilities representing 8 GWs of capacity, although only 1.8 GWs of capacity were available for allocation.[33]

For purposes of the Section 48E Low-Income Communities Bonus Credit, we have the Proposed Section 48E Regulations to turn to as to how the competitive bidding process works. The Treasury has provided notice of a public hearing on the Proposed Regulations for October 17, 2024.

What government guidance do we have on the annual Capacity Limitation allocation process for Section 48?

For purposes of the Section 48 Low-Income Communities Bonus Credit, we have the Final Low-Income Communities Regulations. In addition, the IRS has issued revenue procedures and a Notice:

  • Rev. Proc. 2023-27[34] and Rev. Proc. 2024-19[35] provide information and guidance for the 2023 and the 2024 allocations. These revenue procedures both address the reservation of capacity limitations, allocation selection, and application procedures.
  • IRS Notice 2023-17,[36] sets out initial guidance on establishing the program to allocate the environmental justice solar and wind capacity limitation under Section 48(e).

What does the 2024 allocation program look like?

The 2024 capacity limitation allocation opened in May of 2024, with 1.8 GWs of capacity being allocated across the four eligible facility type categories.[37]

Are there any additional selection criteria for 2024?

Yes. For 2024, the Treasury has imposed what it refers to as “additional selection criteria” (ASC) for the 1.8 GWs allocation. The 2024 ASC requires at least 50 percent of the 1.8 GWs to be allocated to applications that meet specified ASC ownership and geographic criteria.

The 2024 ASC ownership criteria is based on applicants that qualify as one of the following: Tribal enterprises, Alaska Native Corporations, renewable energy cooperatives, qualified renewable energy companies, qualified tax-exempt entities,[38] Indian tribal governments, and any corporation described in Section 501(c)(12) that furnishes electricity to persons in rural areas.

The 2024 geographic criteria is based on the facility being located in a persistent poverty county or disadvantaged community as identified by the Climate and Economic Justice Screening Tool.[39] The screening tool is at an official U.S. government website, with an interactive map of census tracts that are “overburdened and underserved” and that are “highlighted as being disadvantaged.[40] For these purposes, Alaska Native Villages are considered to be disadvantaged communities.[41] The datasets used in the Screening Tool’s eight “indicators of burdens” are “climate change, energy, health, housing, legacy pollution, transportation, water and wastewater, and workforce development.”[42]

Where do we look for 2025 allocations and beyond?

The selection criteria for 2025 and beyond is addressed in the Proposed Section 48E Regulations.

Application Process

How are applications reviewed and Capacity Limitations allocated?

The Treasury and the IRS have partnered with the DOE to administer the program. The DOE’s “Office of Economic Impact and Diversity administers the program application portal and reviews applications, with the DOE making “recommendations to the IRS” based on the eligibility of the facility.[43] The Treasury and the IRS can adjust the allocations of Capacity in future years “for categories that are oversubscribed or have excess capacity.”[44] “At least 50% of the capacity within each category will be reserved for projects that meet certain ownership and/or geographic selection criteria. The ownership and geographic selection criteria can be found in §1.48(e)-1(h)(2).”[45]

How does an applicant apply for the Low-Income Communities Bonus Credit Program?

A taxpayer seeking to claim the credit must submit an application to the DOE for an allocation of capacity. The DOE allows one application per project. To begin their process, an applicant must create a login.gov account and register using the “Log In” button located at a DOE’s portal page, https://eco.energy.gov/ejbonus/s/. Before registering, applicants are encouraged to read the handy dandy “DOE Applicant User Guide”[46] available at the same web portal address. Applications are submitted through DOE’s online “Low-Income Communities Bonus Credit Program Applicant Portal” accessible at the same URL. The portal’s applicant checklist sets out rigorous documentation and attestation requirements to demonstrate that ownership requirements are being met.

How does an applicant support its allocation of capacity for its Low-Income Communities Bonus Credit application?

An applicant must submit information for each proposed facility allocation, including the “applicable category, ownership, location, facility size/capacity, whether the applicant or facility meet additional selection criteria, and other information.”[47] In addition, the applicant must complete a series of attestations and must upload to the online portal certain documentation in order to demonstrate project maturity.”[48] An allocation must be received by the taxpayer before an eligible facility can be placed in service.[49]

How are applications considered?

“There will be a 30-day period at the start of each program year where applications will be accepted for each category. Applications received within this 30-day period will all be treated as being received on the same day and time. Once the 30-day period is over, the DOE will accept applications on a rolling basis and recommend applicants to the IRS until the entire capacity limitation within the applicable category is diminished.”[50] In addition, once applications are submitted, “the DOE will review the applications and recommend projects eligible for the bonus to the IRS. The IRS will then award the applicant with an allocation of the capacity limitation or reject the application. The DOE will stop reviewing applications once the entire capacity limitation is awarded. Applicants can reapply for the bonus credit in the next program year if they remain eligible.”[51]

What happens if a facility is not placed in service within the four-year deadline?

A facility can be disqualified after it receives an allocation if the facility is not placed in service within the deadline set in Section 48(e)(4)(E) of four years after the date of allocation. “[P]roviding any type of alternative forms of completion within the four year window apart from ‘placed-in-service’ is inconsistent with the statute and not allowed.”[52]

Can a credit recipient face a recapture event?

Yes. Recapture of the benefit of any increased credit due to Section 48E is provided in Section 48(e)(5). The Treasury noted that “Under the recapture provisions of Section 48(e)(5), Congress provided that the period and percentage of such recapture must be determined under rules similar to the rules of Section 50(a). Section 50(a) generally provides that this is a five year period with differing applicable percentages depending on when the property ceases to qualify. Therefore, under Section 48(e)(5), stricter restrictions related to recapture should not be imposed.”[53]

The final regulations clarify that “any event that results in recapture under Section 50(a) will also result in recapture of the benefit of the section 48(e) Increase. The exception to the application of recapture provided in § 1.48(e)-1(n)(2) does not apply in the case of a recapture event under Section 50(a).”[54] This same recapture possibility applies to Section 48E (CEITC) credit recipients.


The firm extends gratitude to Nicholas C. Mowbray for his comments and exceptional assistance in the preparation of this article.


[1] The Inflation Reduction Act of 2022, Pub. L. No. 117-169, 136 Stat. 1818 (2022) (IRA), August 16, 2022.

[2] “Inflation Reduction Act Guide for Local Governments and Other Tax-Exempt Entities; Solar and Storage Projects,” p. 17, New York State, January 2024, available at https://www.nyserda.ny.gov/-/media/Project/Nyserda/Files/Programs/Clean-Energy-Siting/Inflation-Reduction-Act-Guide-for-Solar-and-Storage-Projects.pdf.

[3] “Low-Income Communities Bonus Credit Program,” Department of Energy (DOE), Office of Energy Justice and Equity, available at https://www.energy.gov/justice/low-income-communities-bonus-credit-program.

[4] “U.S. Department of the Treasury, IRS Release Final Rules and Guidance on Investing in America Program to Spur Clean Energy Investments in Underserved Communities,” Press Release, U.S. Treasury, August 10, 2023, available at https://home.treasury.gov/news/press-releases/jy1688.

[5] “Low-Income Communities Bonus Credit,” IRS, available at https://www.irs.gov/credits-deductions/low-income-communities-bonus-credit.

[6] For a discussion of Sections 48 and 48E (CEITC), see Part II of this series: Production Tax Credits and Investment Tax Credits: The Old and The New.

[7] § 48(e).

[8] § 48E(h). “Elective pay and transferability frequently asked questions: Elective pay,” IRS, Overview, Q15, available at https://www.irs.gov/credits-deductions/elective-pay-and-transferability-frequently-asked-questions-elective-pay#q15.

[9] § 48(e)(1).

[10] Section 48(e)(2)(A) and the Treasury Regulations.

[11] Section 48(e)(2)(A)(iii).

[12] 88 FR 55506, “Additional Guidance on Low-Income Communities Bonus Credit Program,” U.S. Treasury, August 15, 2023, available at https://www.federalregister.gov/documents/2023/08/15/2023-17078/additional-guidance-on-low-income-communities-bonus-credit-program.

[13] Ibid.

[14] Ibid, Preamble, Definition of Qualified Solar or Wind Facility.

[15] 88 FR 55506, August 15, 2023.

[16] Ibid.

[17] Ibid.

[18] Ibid.

[19] “Inflation Reduction Act Guide for Local Governments and Other Tax-Exempt Entities; Solar and Storage Projects,” p. 18, New York State, January 2024.

[20] “Frequently Asked Questions, 48(e) Low-Income Communities Bonus Credit Program,” Q47.

[21] Ibid.

[22] Ibid.

[23] 43 U.S.C. § 1601 et seq.

[24] 106 Stat. 3113; 25 U.S.C. § 3501.

[25] The Energy Act of 2020, Section 8013, As Amended Through Pub. L. 117-286, Enacted December 27, 2022. See also “Energy Act of 2020, Section-by-Section,” Section 8013. Indian Energy, available at https://www.energy.senate.gov/services/files/32B4E9F4-F13A-44F6-A0CA-E10B3392D47A.

[26] “Inflation Reduction Act Guide for Local Governments and Other Tax-Exempt Entities; Solar and Storage Projects,” p. 18, New York State, January 2024.

[27] Ibid.

[28] FAQ#53.

[29] 89 Fed. Reg. 71193 (Sept. 3, 2024).

[30] “Low-Income Communities Bonus Credit Program,” DOE, Office of Energy Justice and Equity, available at https://www.energy.gov/justice/low-income-communities-bonus-credit-program. Also see https://www.energy.gov/sites/default/files/2024-05/48e%20Slides%20for%20PY24%20Applicant%20Webinar.pdf and refer to Rev. Proc. 2024-19 (IRS) and Treasury Regulations § 1.48(e)–1 for the full definitions and requirements of each program category.

[31] Such as rooftop solar.

[32] “U.S. Department of the Treasury, IRS Release 2024 Guidance for Second Year of Program to Spur Clean Energy Investments in Underserved Communities, As Part of Investing in America Agenda,” Press Release, U.S Treasury, March 29, 2024. Proposed Section 48E (CEITC) Regulations.

[33] “The Low-Income Communities Bonus Credit Program: Categories and How to Apply,” Morgan Mahaffey, EisnerAmper, May 29, 2024, available at https://www.eisneramper.com/insights/real-estate/low-income-communities-bonus-credit-program-0524/

[34] Rev. Proc. 2023-27, IRS, August 10, 2023, corrected by Announcement 2023-28, September 11, 2023.

[35] Rev. Proc. 2024-19, IRS, March 29, 2024.

[36] Notice 2023-17, IRS, February 13, 2023.

[37] Treas. Reg. §1.48(e)-1 defines the four categories of facilities for Low-Income Communities Bonus Credit.

[38] Including Sections 501(c)(3) and 501(d) entities.

[39] The screening tool is available at https://screeningtool.geoplatform.gov/en/#3/33.47/-97.5.

[40] Ibid.

[41] Ibid.

[42] Climate and Economic Justice Screening Tool, Frequently Asked Questions, available at https://screeningtool.geoplatform.gov/en/frequently-asked-questions#3/31.77/-95.39.

[43] Ibid.

[44] “IRS releases Guidance on Low-Income Communities Bonus Credit Program, Inflation Reduction Act,” Forvis Mazars, LLP, August 15, 2023, available at https://www.forvismazars.us/forsights/2023/08/irs-releases-guidance-on-low-income-communities-bonus-credit-program.

[45] Ibid. See also, § 1.48(e)-1(h)(2), the Reservations of Capacity Limitation allocation for facilities that meet certain additional selection criteria is available at https://www.law.cornell.edu/cfr/text/26/1.48(e)-1.

[46] “Applicant User Guide,” DOE, available at https://www.energy.gov/sites/default/files/2024-05/2024%20DOE%2048%28e%29%20Applicant%20User%20Guide.pdf.

[47] “Low-Income Communities Bonus Credit Program,” DOE, Office of Energy Justice and Equity, available at https://www.energy.gov/justice/low-income-communities-bonus-credit-program.

[48] Ibid.

[49] “Low-Income Communities Bonus Credit,” IRS, available at https://www.irs.gov/credits-deductions/low-income-communities-bonus-credit.

[50] “IRS releases Guidance on Low-Income Communities Bonus Credit Program, Inflation Reduction Act,” Forvis Mazars, LLP, August 15, 2023.

[51] Ibid.

[52] 88 Fed. Reg. 55537.

[53] 88 Fed. Reg. 55538.

[54] 88 Fed. Reg. 55538.

Read Part IPart IIPart IIIPart IVPart V, and Part VI here.

by: Andie Kramer of ASKramer Law

For more news on Energy Tax Credits, visit the NLR Environmental Energy Resources section.

Energy Tax Credits for a New World Part I: Overview of Energy Tax Credits under the IRA

Signed into law on August 16, 2022, the Inflation Reduction Act (IRA) is the most significant long-term commitment made by the U.S. government to encourage and support a clean energy future. The IRA works through the Internal Revenue Code (Code) in ways that fundamentally change the landscape on how clean energy tax credits and incentives are designed, awarded, and monetized.

The regulation, taxation, and financing of energy projects has been an integral aspect of my law practice for decades. These are exciting times now, as the structuring of energy tax credits under the IRA expands on a number of themes that I first covered in an energy and environmental project finance book I coauthored for Oxford University Press back in 2010. Then, as now, my perspective is shaped by my work for clients in the traditional and emerging clean energy sectors.

Why launch a series now about the energy tax credits that were extended, modified, or introduced by the IRA?

  • Many of the IRA energy credits run until 2032, so project developers still have ample opportunity to get their projects underway while credits remain available.
  • The Treasury and the IRS have yet to provide us with many important details on IRA implementation, with much of the guidance having been provided in Notices and proposed Treasury Regulations. But while the details are being ironed out, taxpayers still need to move forward with their projects, and tax returns need preparation. As project owners and funders continue to seek assistance, it remains critical to remain vigilant and stay on top of the large number of new developments.
  • Two important technology-specific credits expire at the end of 2024. They will be replaced in 2025 by two technology-neutral credits. The technology-neutral credits do not expire until 2032, or until certain greenhouse gas emissions (GHG) are reduced to specific levels set out in the Code (most likely, later).
  • Projects that seek to qualify for IRA energy tax credits and which begin construction in and after 2025 will need to meet statutory requirements not required for earlier projects.

Developers and investors would be well advised to consider the tax consequences to their energy projects during the second half of 2024, which I look at as a transition period.

In this Q&A with AndieEnergy Tax Credits For A New World, I aim to provide an overview of the IRA as it relates to many important energy credits. I will take deep dives into some of the requirements and mechanics of some of these credits, and I will look at the ways in which these credits can be monetized.

Through Summer and Fall 2024, Readers can look forward to reading this extended occasional series presented in the following parts:

Part I: Overview of Energy Tax Credits under the IRA

Part II: Production Tax Credits and Investment Tax Credits: The Old and The New

Part III: Overview of Bonus Credits

Part IV: Prevailing Wage and Apprenticeship Bonus Credits

Part V: Domestic Content Bonus Credits

Part VI: Energy Community Bonus Credits

Part VII: Low-Income Communities Bonus Credits

Part VIII: Monetizing Energy Tax Credits

Part XI: Changes to Traditional Tax Equity Financing

The IRA’s tax benefits are enormous. As a result, when a “qualifying energy project” is properly structured and timed, it can receive tax credits that reduce certain related costs by more than 50 percent.

As I launch this series, I would like to extend my gratitude to Nicholas C. Mowbray for his comments and exceptional assistance.

Part I: Overview of Energy Tax Credits under the IRA

“Dozens of countries are widening the gap between their economic growth and their greenhouse gas emissions. . . . If these trends continue, global emissions may actually start to decline,” observed Umair Irfan writing for Vox.[1]

What is the importance of the Inflation Reduction Act (IRA) to energy tax credits?

The IRA has strengthened the United States’ long-term commitment toward a clean energy economy. It is the most ambitious U.S. effort to date to incentivize the development of renewable energy technologies[2] that can help to reduce greenhouse gas (GHG) emissions. The IRA targets the enormous capital expenditures needed to create, commercialize, and broadly make available renewable energy technologies. The IRA’s goal is to lay out a path toward a net-zero GHG economy by 2050.[3]

How does the IRA affect energy project funding?

The IRA has brought about major changes in the ways in which energy projects are structured and funded. It provides for loans, grants, financial and technical assistance, rebates, and energy tax credits. About $400 billion has been allocated for clean energy innovation, technology, and manufacturing. Of this funding, about $260 billion applies to the extension and modification of existing tax credits and the introduction of new ones. In fact, more than 70 percent of the IRA’s benefits are delivered through tax incentives. Now, more than 20 tax credits allow for monetization that supports clean energy generation, develops related manufacturing capacity, incentivizes the increased use of clean vehicles and energy sources, and increases carbon capture programs.[4]

How does the IRA target GHG emission?

The IRA uses funding and financial incentives to support research, development, and commercialization of low- and zero-GHG emission technologies. It also seeks to steer project developers to locate their projects in “energy communities” or “low-income communities”; to pay prevailing wages and encourage the training of registered apprentices; and to increase the use of domestic content components in project-related manufacturing and construction processes.

Have the IRA initiatives been effective?

Initial IRA success stories are very positive, but we have a long way to go. In 2023, “more solar panels were installed in China […] than the US has installed in its entire history. More electric vehicles were sold worldwide than ever.”[5] As the United States seeks to become a global leader in decarbonization and to compete with other major economies like China, the IRA is creating “new opportunities for workers […] and lower costs for America’s families.”[6]

Congress also seeks to ensure that monies provided by the IRA strengthen domestic supply chains and ensure the nation’s energy security in its transportation modes. The IRA is boosting domestic manufacturing for critical renewable energy components, while partially funding the construction of renewable energy projects through its rigorous domestic sourcing requirements.

In 2023 the American Council on Renewable Energy found that, “One of the most notable impacts of the IRA is how quickly it helped to onshore new advanced green manufacturing. More than 83 new or expanded wind, solar, and battery manufacturing facilities have been announced since August 2022, including 52 plants for solar production, 17 for utility-scale wind production, and 14 for production of utility-scale battery storage.”[7]

Notwithstanding some initial successes, two years after passage of the IRA, there are some serious concerns that some of the credits are unworkable, and that the IRA’s domestic sourcing requirements have fallen short of expectations.[8]

Is it possible that the IRA could be dismantled by future Administrations?

Yes. It is possible. Perhaps, a better question might be should the IRA be dismantled? Is it in our best interests to shut down the onward innovation of a thriving high-growth, high-benefit fledgling U.S. industry segment, substantially underwritten by the government, and made available to the residents of a leading market economy?

What makes the IRA different from prior environmental and climate efforts?

The IRA is fundamentally different from the carrot-and-stick approaches of many prior U.S. environmental and climate laws. It has an incentives-based focus: it does not rely on traditional regulation and enforcement to achieve its desired outcomes. It proactively seeks to encourage long-term commercial investments to decarbonize transportation, manufacturing, and construction. The IRA is popular among early adopters. Kimberly Clausing, the Eric M. Zolt Chair in Tax Law and Policy at the UCLA School of Law, noted in a 2023 interview, “There’s a lot of things to like about these tax credits […] they’re broad, they’re longer lived than prior tax credits, and they don’t phase out as quickly. They’re more flexible than prior tax credits. They’re more transferable and refundable, and that enables them to be ultimately more effective.”[9]

The IRA’s long-term focus on tax credits, financial incentives, and monetization may offer prospective project developers a degree of certainty in their planning; persuade investors to commit to clean energy undertakings; and broaden the pool of capital available to do so. So far, the facts speak for themselves: in the first year after the IRA’s enactment, 280 clean energy projects were announced across 44 states, representing $282 billion of investment.[10]

What deference will be given to Treasury Regulations addressing the IRA provisions?

Since passage of the IRA, the Treasury and the IRS have been carefully moving through the details of its rollout.[11] At the date of this writing, many critical questions remain unanswered. In addition, for many decades, the Treasury and the IRS have enjoyed broad latitude on the administration of the laws. But the legal landscape might be changing. On June 28, 2024, in Loper Bright Enterprises v. Raimondo, the U.S. Supreme Court effectively overturned the so-called Chevron doctrineChevron is a 40-year-old Supreme Court case that afforded federal agencies a degree of deference in the reasonable interpretation of a statute that fell within their areas of expertise.[12] As a result, many questions will be raised about many laws, along with the frameworks for their roll out and enforcement. Although the Treasury and the IRS will be able to claim broad expertise in some areas of the tax law, it is likely that there will be disputes and litigation over the deference to be given to climate-related tax regulations.[13]

What is the starting point for the IRA’s focus on tax credits?

Let’s take a walk down memory lane. Federal income tax credits for wind and solar energy were first enacted in The Energy Tax Act of 1978.[14] They were structured as refundable 10 percent tax credits for energy property and equipment that produced electricity using wind and solar sources. Later, The Windfall Profit Tax Act of 1980 extended the expiration through 1985, increased the credit to 15 percent, and removed a taxpayer’s ability to get a tax refund based on the value of the credit.[15] The Tax Reform Act of 1986 reduced solar energy credits from 15 percent to 10 percent and extended them through December 31, 1988. Further energy credit extensions for solar property were enacted between 1988 and 1991.

With The Energy Policy Act of 1992,[16] Congress made solar energy credits “permanent” and named them “investment tax credits” (ITCs). The same legislation also enacted the “renewable electricity production tax credit,” or the PTC. When the PTC expired in 1999, it was subsequently extended and expanded to include additional energy technologies.

The Energy Policy Act of 2005 increased the ITC for solar energy from 10 percent to 30 percent, and it extended the credit to additional types of energy property.[17] It did not, however, extend the PTC for solar and refined coal facilities. This meant that from 2005 until enactment of the IRA, the PTC was not available for electricity that was produced from solar energy.

Does the IRA move away from technology-specific tax credits?

Yes. Before the IRA, the PTC at Section 45 and the ITC at Section 48 were the two principal energy tax credits. They were enacted to encourage the development of U.S. wind farms and solar arrays. Both the PTC and the ITC included technology-specific statutory provisions that had been amended over the years to include additional technologies identified by Congress.

The IRA modified and extended both the Section 45 PTC and the Section 48 ITC through the end of 2024 at which point they will be replaced by the next generation of technology-neutral credits: the Section 45Y Clean Electricity Production Tax Credits (CEPTC) and the Section 48E Clean Electricity ITC (CEITC).[18] The rest of the energy tax credits that the IRA modified or introduced took effect for projects beginning on or after January 1, 2023, with most of those credits expiring on December 31, 2032.

In the next part of this series, we will take a look at the production tax credit (PTC), the investment tax credit (ITC), and their progeny. Many of the IRA tax credits are modifications or expansions of the PTC and the ITC. It is an important next step to consider the underlying framework of the old credits and the new.


The firm extends gratitude to Nicholas C. Mowbray for his comments and exceptional assistance in the preparation of this article.


[1] “We Might Be Closer to Changing Course on Climate Change Than We Realized,” Umair Irfan, Vox, April 25, 2024.

[2] Ibid.

[3] The Inflation Reduction Act of 2022, Pub. L. No. 117-169, 136 Stat. 1818 (2022) (IRA), August 16, 2022.

[4] Treasury, Inflation Reduction Act, https://home.treasury.gov/policy-issues/inflation-reduction-act#:~:text=The Inflation Reduction Act, enhanced, for clean energy and manufacturing. See also, “Elective Pay Overview,”
IRS Pub. 5817 (Rev. 4-2024) Number 941211. https://www.irs.gov/pub/irs-pdf/p5817.pdf

[5] “We Might Be Closer to Changing Course on Climate Change Than We Realized,” Umair Irfan, Vox, April 25, 2024.

[6] “Inflation Reduction Act Tax Credit,” U.S. Department of Labor, Inflation Reduction Act Tax Credit | U.S. Department of Labor (dol.gov), accessed August 15, 2024.

[7] “Celebrating One Year of Progress: The Inflation Reduction Act’s Impact on Renewable Energy and the American Economy,” Greg Wetstone, American Council on Renewable Energy, August 14, 2023.

[8] Press release, www.manchin.senate.gov, June 4, 2024.

[9]  “Why the Inflation Reduction Act Can’t Be Repealed,” Evan George, Legal Planet, April 17, 2023.

[10] “The US Inflation Reduction Act is Driving Clean-Energy Investment One Year In,” Marco Willner,

Sebastiaan Reinders and Aviral Utkarsh, Goldman Sachs, October 31, 2023.

[11] “Here’s What the Court’s Chevron Ruling Could Mean in Everyday Terms,” By Coral Davenport et al., The New York Times, June 28, 2024.

[12] “The Supreme Court’s Elimination Of The Chevron Doctrine Will Undermine Corporate Accountability,” Michael Posner, Forbes, July 8, 2024.

[13] “Tax Pros Discuss Impact of Loper Bright on IRS Regs,” Tim Shaw, Thomas Reuters, July 29, 2024,
“The Supreme Court’s decision […] may have ripple effects on Treasury and IRS rulemaking, though to what extent remains unclear, tax professionals say.”

[14] Pub. L. No. 95-618, 92 Stat. 3174 (1978).

[15] Pub. L. No. 96-223, 94 Stat. 229 (1980).

[16] Pub. L. No. 102-486, 106 Stat. 2776 (1992); H.R. 776, 102nd Congress (1991̵–1992).

[17] Pub. L. No. 109-58, 119 Stat. 594 (2005). I will discuss the term “energy property” in a future article.

[18] The PTC, ITC, CEPTC, and CEITC are discussed in Part V: Domestic Content Bonus Credits of this series.

by: Andie Kramer of ASKramer Law

For more news on Energy Tax Credits under the IRA, visit the NLR Tax section.

DOE Ramping Up General Service Lamp Enforcement

Largely out of public view, the U.S. Department of Energy (DOE) has been ramping up enforcement of its “backstop” efficiency standard and sales prohibition regarding general service lamps, including incandescent bulbs. After a period of enforcement discretion (previewed in published guidance) that has now passed, we expect at least some of DOE’s efforts to become public in the coming months as the Department begins to settle enforcement actions and assess civil penalties against non-compliant lamp manufacturers, importers, distributors, and retailers.

The Final Rule

Following a rulemaking process that took many twists and turns over the past decade (as summarized in a prior alert), as of July 25, 2022, the sale of any general service lamp that does not meet a minimum efficacy standard of 45 lumens per watt hour (lm/W) is prohibited. 10 C.F.R. § 430.32(dd).

A “general service lamp” (GSL) is a lamp that:

  1. Has an ANSI base;
  2. For an integrated lamp, is able to operate at a voltage or in a voltage range of 12 or 24 volts, 100–130 volts, 220–240 volts, or 277 volts;
  3. For a non-integrated lamp, is able to operate at any voltage;
  4. Has an initial lumen output of greater than or equal to 310 lumens (or 232 lumens for modified spectrum general service incandescent lamps) and less than or equal to 3,300 lumens;
  5. Is not a light fixture;
  6. Is not an LED downlight retrofit kit; and
  7. Is used in general lighting applications.

10 C.F.R. § 430.2. GSLs include, but are not limited to, general service incandescent lamps, compact fluorescent lamps, general service light-emitting diode lamps, and general service organic light-emitting diode lamps. GSLs consist of pear-shaped A-type bulbs, but also five categories of specialty incandescent lamps (rough service lamps, shatter-resistant lamps, 3-way incandescent lamps, high lumen incandescent lamps, and vibration service lamps), incandescent reflector lamps, and a variety of decorative lamps (T-Shape, B, BA, CA, F, G16-1/2, G25, G30, S, M-14 of 40W or less, and candelabra base lamps). DOE maintains exclusions for twenty-six categories of lamps, including appliance lamps and colored lamps, among others. Id.

Approximately 30 percent of light bulbs sold across the United States in 2020 were incandescent or halogen incandescent lamps. Almost all such lamps would fail to meet the statutory 45 lm/W backstop standard. Because many LED lamps, in contrast, can meet the 45 lm/W standard, DOE’s actions are accelerating a transition to LEDs.

Federal and State Enforcement

During this transition, DOE enforcement is likely to most aggressively target manufacturers and importers continuing to distribute non-compliant lamps, and will include the assessment of civil penalties. DOE is authorized to assess penalties of as much as $560 for each non-compliant lamp sold. While enforcement actions typically settle for tens or hundreds of thousands of dollars, DOE has obtained seven-figure settlements for more significant violations or where a business has repeatedly failed to comply.

Specifically with respect to general service lamps (but not for other covered products), the Department is also authorized to enforce against distributors and retailers who sell non-compliant lamps, and early indications are that DOE is beginning to act on that authority. Because the federal backstop standard is enforced at the time of sale, lamps imported into the United States before July 25, 2022, are not exempt from enforcement if sold after the deadline.

Separately, some states—including California—also enforce their own efficiency standards for products not subject to federal standards. The California Energy Commission recently settled an enforcement action for over $120,000 against a company that was selling state-regulated LEDs that were not certified in California’s compliance database prior to sale, and which did not meet state standards.

Next Steps

Businesses operating at any stage in the lamp supply chain should, therefore, take immediate steps to ensure they are not making, importing, distributing, or selling to consumers any lamps that do not meet applicable federal or state requirements. To determine whether a particular general service lamp meets the backstop standard, one can take the total lumens produced by the lamp and divide it by its wattage. If the calculated number is below 45, and the product does not qualify for any of the listed exclusions, then it is non-compliant, and its continued sale could prompt federal enforcement.

Deep-Sea Mining–Article 1: What Is Happening With Deep-Sea Mining?

Debate continues on whether the UAE Consensus achieved at COP28 represents a promising step forward or a missed opportunity in the drive towards climate neutral energy systems. However, the agreement that countries should “transition away from fossil fuels” and triple green power capacity by 2030 spotlights the need for countries to further embrace renewable power.

This series will examine the issues stakeholders need to consider in connection with deep-sea mining. We first provide an introduction to deep-sea mining and its current status. Future articles will consider in greater detail the regulatory and contractual landscape, important practical considerations, and future developments, including decisions of the ISA Council.

POLYMETALLIC NODULES

Current technology for the generation of wind and solar power (as well as the batteries needed to store such power) requires scarce raw materials, including nickel, manganese, cobalt, and copper. The fact that these minerals are found in the millions of polymetallic nodules scattered on areas of the ocean floor gives rise to another debate on whether the deep-sea mining of these nodules should be pursued.
This issue attracted considerable attention over the summer of 2023, when the International Seabed Authority (ISA) Assembly and Council held its 28th Session and, in January 2024, when Norway’s parliament (the Storting) made Norway the first country to formally authorise seabed mining activities in its waters.

INTERNATIONAL REGULATION OF DEEP-SEA MINERALS: UNCLOS AND ISA

The United Nations Convention on the Law of the Sea (UNCLOS) provides a comprehensive regime for the management of the world’s oceans. It also established ISA.

ISA is the body that authorises international seabed exploration and mining. It also collects and distributes the seabed mining royalties in relation to those areas outside each nation’s exclusive economic zone (EEZ).

Since 1994, ISA has approved over 30 ocean-floor mining exploration contracts in the Atlantic, Pacific, and Indian oceans, with most covering the so-called ‘Clarion-Clipperton Zone’ (an environmental management area of the Pacific Ocean, between Hawaii and Mexico). These currently-approved contracts run for 15 years and permit contract holders to seek out (but not commercially exploit) polymetallic nodules, polymetallic sulphides, and cobalt-rich ferromanganese crusts from the deep seabed.

UNCLOS TWO-YEAR RULE AND ISA’S 28TH SESSION

Section 1(15) of the annex to the 1994 Implementation Agreement includes a provision known as the “two-year rule.” This provision allows any member state of ISA that intends to apply for the approval of a plan of work for exploitation of the seabed to request that the ISA Council draw up and adopt regulations governing such exploitation within two years.

In July 2021, the Republic of Nauru triggered the two-year rule, seeking authority to undertake commercial exploitation of polymetallic nodules under license. That set an operative deadline of 9 July 2023.

At meetings of the ISA Assembly and ISA Council in July 2023, the ISA Council determined that more time was needed to establish processes for prospecting, exploring, and exploiting mineral resources, and a new target was set for finalising the rules: July 2025.

The expiration of the two-year rule in July 2023 does allow mining companies to submit a mining license application at any time. However, the above extension gives the ISA Council direct input into the approval process, which will make approval of any application difficult.

NORWAY’S DEEP-SEA MINING PLAN

State legislation regulates deep-sea mining in different EEZs. Norway is one of the only countries that has its own legislation (the Norway Seabed Minerals Act of 2019) regulating the exploration and extraction of deep-sea minerals.

In December 2023, Norway agreed to allow seabed mineral exploration off the coast of Norway, ahead of a formal parliamentary decision. The proposal was voted 80-20 in favour by the Storting on 9 January 2024.

The proposal will permit exploratory mining across a large section of the Norwegian seabed, after which the Storting can decide whether to issue commercial permits.

The decision initially applies to Norwegian waters and exposes an area larger than Great Britain to potential sea-bed mining, although the Norwegian government has noted that it will only issue licenses after more environmental research has been done.

The Norwegian government has defended the plan as a way to seize an economic opportunity and shore up the security of critical supply chains. However, there is concern that this will pave the way towards deep-sea mining around the world. Green activists, scientists, fishermen, and investors have called upon Oslo to reconsider its position. They cite the lack of scientific data about the effects of deep-sea mining on the marine environment, as well as the potential impact on Arctic ecosystems. In November 2023, 120 European Union lawmakers wrote an open letter to Norwegian members of the Storting, urging them unsuccessfully to reject the project, and in February 2024, the European Parliament voted in favour of a resolution that raised concerns about Norway’s deep-sea mining regulations. This resolution carries no legal power, but it does send a strong signal to Norway that the European Union does not support its plans.

In May 2024, WWF-Norway announced it will sue the Norwegian government for opening its seabed to deep-sea mining. WWF-Norway claim that the government has failed to properly investigate the consequences of its decision, has acted against the counsel of its own advisors, and has breached Norwegian law.

METHODS OF POLYMETALLIC NODULE EXTRACTION

Should Norway, or any other nation, initiate commercial deep-seabed mining, one of the following methods of mineral extraction may be employed:

Continuous Line Bucket System

This system utilises a surface vessel, a loop of cable to which dredge buckets are attached at 20–25 meter intervals, and a traction machine on the surface vessel, which circulates the cable. Operating much like a conveyor belt, ascending and descending lines complete runs to the ocean floor, gathering and then carrying the nodules to a ship or station for processing.

Hydraulic Suction System

A riser pipe attached to a surface vessel “vacuums” the seabed, for example, by lifting the nodules on compressed air or by using a centrifugal pump. A separate pipe returns tailings to the area of the mining site.

Remotely Operated Vehicles (ROVs)

Large ROVs traverse the ocean floor collecting nodules in a variety of ways. This might involve blasting the seafloor with water jets or collection by vacuuming.

Recent progress has been made in the development of these vehicles; a pre-prototype polymetallic nodule collector was successfully trialed in 2021 at a water depth of 4,500 metres, and in December 2022, the first successful recovery of polymetallic nodules from the abyssal plain was completed, using an integrated collector, riser, and lift system on an ROV. A glimpse of the future of deep-sea ROVs perhaps comes in the form of the development of robotic nodule-collection devices, equipped with artificial intelligence that allows them to distinguish between nodules and aquatic life.

Key to all three methods of mineral extraction is the production support vessel, the main facility for collecting, gathering, filtering, and storing polymetallic nodules. Dynamically positioned drillships, formerly utilised in the oil and gas sector, have been identified/converted for this purpose, and market-leading companies active in deep-water operations, including drilling and subsea construction, are investing in this area. It will be interesting to see how the approach to the inherent engineering and technological challenges will continue to develop.

THE RISKS OF DEEP-SEA MINING

As a nascent industry, deep-sea mining presents risks to both the environment and the stakeholders involved:

Environmental Risks

ISA’s delayed operative deadline for finalising regulations has been welcomed by parties who are concerned about the environmental impact that deep-sea mining may have.

Scientists warn that mining the deep could cause an irreversible loss of biodiversity to deep-sea ecosystems; sediment plumes, wastewater, and noise and light pollution all have the potential to seriously impact the species that exist within and beyond the mining sites. The deep-ocean floor supports thousands of unique species, despite being dark and nutrient-poor, including microbes, worms, sponges, and other invertebrates. There are also concerns that mining will impact the ocean’s ability to function as a carbon sink, resulting in a potentially wider environmental impact.

Stakeholder and Investor Risks

While deep-sea mining doesn’t involve the recovery and handling of combustible oil or gas, which is often associated with offshore operations, commercial risks associated with the deployment of sophisticated (and expensive) equipment in water depths of 2,000 metres or greater are significant. In April 2021, a specialist deep-sea mining subsidiary lost a mining robot prototype that had uncoupled from a 5-kilometer-long cable connecting it to the surface. The robot was recovered after initial attempts failed, but this illustrates the potentially expensive problems that deep-sea mining poses. Any companies wishing to become involved in deep-sea mining will also need to be careful to protect their reputation. Involvement in a deep-sea mining project that causes (or is perceived to cause) environmental damage or that experiences serious problems could attract strong negative publicity.

INVESTOR CONSIDERATIONS

Regulations have not kept up with the increased interest in deep-sea mining, and there are no clear guidelines on how to structure potential deep-sea investments. This is especially true in international waters, where a relationship with a sponsoring state is necessary. Exploitative investments have not been covered by ISA, and it is unclear how much control investors will have over the mining process. It is also unclear how investors might be able to apportion responsibility for loss/damage and what level of due diligence needs to be conducted ahead of operations. Any involvement carries with it significant risk, and stakeholders will do well to manage their rights and obligations as matters evolve.

Treasury Proposes Clean Electricity Tax Guidance

On May 29, 2024, the Internal Revenue Service (IRS) and the Treasury Department released the pre-publication version of proposed guidance to implement “technology-neutral” clean electricity tax credits, including deeming certain technologies as per se zero-emitting and outlining potential methodologies for determining how other technologies—namely those involving combustion or gasification—could qualify as zero-emitting based on a lifecycle emissions analysis (LCA). The Clean Electricity Production Credit (45Y) and Clean Electricity Investment Credit (48E) were enacted in the Inflation Reduction Act (IRA) of 2022 and replace the current production and investment tax credits that are explicitly tied to certain types of renewable energy technologies.

Stakeholders have cited the 45Y and 48E credits as the most important driver of greenhouse gas (GHG) emission cuts possible from the IRA over the next decade. One study by the Rhodium Group found that the credits could reduce the power sector’s GHG emissions by up to 73 percent by 2035. The tax credits aim to give qualifying facilities the ability to develop technologies over time as they reduce emissions and offer longer-term certainty for investors and developers of clean energy projects. This proposed rule, when finalized, will be a critical driver for developers and companies allocating resources among different projects and investments.

The proposed guidance is scheduled to be published June 3, 2024 in the Federal Register, launching a 60-day comment period. A public hearing will be held August 12-13, 2024.

Proposed Guidance Details

Starting in Fiscal Year (FY) 2025 for projects placed into service after Dec. 31, 2024, 45Y provides taxpayers with a base credit of 0.3 cents (1.5 cents, if the project meets prevailing wage and apprenticeship requirements) per kilowatt of electricity produced and sold or stored at facilities with zero or negative GHG emissions. (These per kilowatt credit values are adjusted for inflation using 1990 as the base year.) Under 48E, taxpayers would receive a 6 percent base credit (30 percent, if the project meets prevailing wage and apprenticeship requirements) on qualified investment in a qualified facility for the year the project is placed in service. Both credits include bonus amounts for projects located in historical energy communities, low-income communities, or on tribal land; for meeting certain domestic manufacturing requirements; or for being part of a low-income residential building or economic benefit project. Direct pay and transferability are options for both credits. Both credits are in effect until 2032, when they become subject to a three-year phaseout.

Technologies recognized as per se zero-emissions in the guidance are wind, solar, hydropower, marine and hydrokinetic, nuclear fission and fusion, geothermal, and certain types of waste energy recovery property (WERP). The guidance also outlines how energy storage can qualify, including by proposing definitions of electricity, thermal, and hydrogen storage property.

A principal debate in the proposal is how to determine, using an LCA, whether certain combustion and gasification (C&G) technologies can qualify as zero-emitting.

The guidance includes a set of definitions and interpretations critical to implementation of the tax credits. For example, the proposed C&G definition includes a hydrogen fuel cell if it “produced electricity using hydrogen that was produced by an electrolyzer powered, in whole or in part, by electricity from the grid because some of the electricity from the grid was produced through combustion or gasification.” The proposed C&G definition would also include both biogas- and biomass-based power, but eligibility depends on the LCA results; for biomass, the guidance seeks comment on what spatial and temporal scales should apply and how land use impacts the LCA.

The guidance states that the IRS intends to establish rules for qualifying facilities that generate electricity from biogas, renewable natural gas, and fugitive sources of methane. The guidance says that Treasury and the IRS “anticipate” requiring that, for such facilities, the gas must originate from the “first productive use of the relevant methane.”

The proposed C&G definition allows for carbon capture and storage (CCS) that meets LCA requirements. However, the IRA does not allow credits to go toward facilities already using certain other credits, including the relatively more generous section 45Q credits for CCS.

Specifically, there are seven other credits that cannot be used in combination with a 45Y or 48E credit: 45 (existing clean electricity production credit); 45J (advanced nuclear electricity credit); 45Q (CCS); 45U (zero-emission nuclear credit); 48 (existing clean electricity investment credit); for 45Y, 48E (new clean electricity production credit); and for 48E, 45Y (new clean electricity investment credit).

The guidance proposes beginning and ending boundaries for LCAs, stating “the starting boundaries would include the processes necessary to produce and collect or extract the raw materials used to produce electricity from combustion or gasification technologies, including those used as energy inputs to electricity production. This includes the emissions effects of relevant land management activities or changes related to or associated with feedstock production.” Another topic in the guidance is the use of carbon offsets to reach net-zero qualification status, with the proposal seeking comment on boundaries: “offsets and offsetting activities that are unrelated to the production of electricity by a C&G Facility, including the production and distribution of any input fuel, may not be taken into account” by an LCA. The guidance also includes rules on qualified interconnection costs in the basis of a low-output associated qualified facility, the expansion of a facility and incremental production, and the retrofitting of an existing facility.

The guidance describes the role of the Department of Energy (DOE) in implementing the tax credits. Any future changes to technologies designated as zero-emitting or to the LCA models must be completed with analyses prepared by DOE’s national labs along with other technical experts. Facilities seeking eligibility may also request a “provisional emissions rate,” which DOE would administer with the national labs and experts “as appropriate.”

Next Steps

As noted above, the proposed guidance is scheduled to be published June 3, 2024 in the Federal Register, launching a 60-day comment period for interested parties to make arguments and provide evidence for changes they would like to see before the rule becomes final. A public hearing will be held August 12-13, 2024. The Treasury Department in consultation with interagency experts plans to carefully review comments and continue to evaluate how other types of clean energy technologies, including C&G technologies, may qualify for the clean electricity credits.

The Domestic Content Bonus Credit’s Promising New Safe Harbor

On May 16, 2024, the Internal Revenue Service (IRS) published Notice 2024-41 (Notice), which modifies Notice 2023-38 (Prior Notice) by providing a new elective safe harbor (Safe Harbor) that will allow taxpayers to use assumed domestic cost percentages in lieu of percentages derived from manufacturers’ direct cost information to determine eligibility for the domestic content bonus credit (Domestic Content Bonus). The Notice grants a promising reprieve to the Prior Notice’s relatively inflexible (and arguably impracticable) standard on seeking direct cost information from manufacturers, raising novel structuring considerations for energy producers, developers, investors and buyers.

The Notice also expands the list of technologies covered by the Prior Notice (Applicable Projects).

In this article, we share key takeaways from the Notice as they apply to energy producers, developers and investors and provide a brief overview of the Domestic Content Bonus as well as a high-level summary of the Notice’s substantive content.

IN DEPTH


KEY TAKEAWAYS FROM THE NOTICE

The Notice provides a key step forward in eliminating qualification challenges for the Domestic Content Bonus by providing an alternative to the Prior Notice’s stringent requirement of seeking direct cost information from manufacturers. In short, a taxpayer can aggregate the assumed percentages in the Notice that correspond with the US-made manufactured products in its project. If the assumed percentages total is greater than the manufactured product percentage applicable to such project (currently 40%), then the taxpayer is treated as satisfying the manufactured product requirement. Although the Notice promises forthcoming proposed regulations that could amend or override the Notice, this gives taxpayers time to appropriately interpret the latest rules and respond accordingly.

The new guidance’s impact will likely require restructuring to the existing development of energy projects as it relates to the Domestic Content Bonus. Below, we outline some key considerations for energy producers, developers, investors and buyers alike:

  • The Safe Harbor is expected to dramatically increase the availability of the Domestic Content Bonus. The Prior Notice’s challenging cost substantiation requirements left most industry participants on the sidelines. Initial feedback from developers, investors and credit buyers was extremely positive, and we have already seen fulsome renegotiation and speedy agreement between counterparties over domestic content contractual provisions in project documents.
  • While the Safe Harbor eliminates the requirement to seek direct cost information from manufacturers for certain Applicable Projects, a taxpayer’s obligations with respect to substantiation requirements for manufacturers’ US activities is not clear in the Notice. Given the standing federal income tax principles on recordkeeping and substantiation, taxpayers should carefully reconsider positions on diligence and review existing relationships with manufacturers.
  • Although the Notice expressly provides that the Safe Harbor is elective with respect to a specific Applicable Project, it’s unclear whether the Safe Harbor is extended by default to any and all of a taxpayer’s Applicable Projects upon election effect or whether an elective position is required with respect to each Applicable Project. Taxpayers, especially those with multiple Applicable Projects, should consider the various implications resulting from an elective position prior to reliance on the Safe Harbor.
  • For Safe Harbor purposes, the Notice provides a formula for computing a single domestic cost percentage for solar energy property and battery energy storage technologies that are treated as a single energy project (PV+BESS Project), but ambiguity exists as to whether such technologies should be aggregated for other purposes under the investment tax credit.
  • It’s unclear how the calculations would operate for repowered facilities given the assumed domestic cost percentage approach.
  • The Notice limits the Safe Harbor to solar photovoltaic, onshore wind and battery energy storage systems, leaving taxpayers with other types of Applicable Projects stranded with the Prior Notice. For example, the Notice does not cover renewable natural gas or fuel cell. The IRS seeks comments on whether the Safe Harbor should account for other technologies, the criteria and how often the list of technologies should be updated. Affected taxpayers should fully consider the requested comments and provide feedback as necessary.
  • The IRS seeks comments on various issues with respect to taxpayers who have a mix of foreign and domestic manufactured product components (mixed source items). Taxpayers with mixed source items that the Notice attributes as disregarded and entirely foreign sourced (notwithstanding the domestic portion) should take cautionary note and provide feedback as necessary.

BACKGROUND: THE DOMESTIC CONTENT BONUS CREDIT

The Inflation Reduction Act of 2022 spurred the creation of “adder” or “bonus” incentive tax credits. In pertinent part, Applicable Projects could further qualify for an increased credit (i.e., the Domestic Content Bonus) upon satisfaction of the domestic content requirement.

To qualify for the Domestic Content Bonus, taxpayers must meet two requirements. First, steel or iron components of the Applicable Project that are “structural” in nature must be 100% US manufactured (Steel or Iron Requirement). Second, costs associated with “manufactured components” of the Applicable Project must meet the “adjusted percentage” set forth in the Internal Revenue Code (Manufactured Products Requirement). For projects beginning construction before 2025, the adjusted percentage is 40%.

The Prior Notice provided guidance for meeting these requirements. Taxpayers should begin by identifying each “Applicable Project Component” (i.e., any article, material or supply, whether manufactured or unmanufactured, that is directly incorporated into an Applicable Project). Subsequently, taxpayers must determine whether the Applicable Project Component is subject to the Steel or Iron Requirement or the Manufactured Products Requirement.

If the Applicable Project Component is steel or iron, it must be 100% US manufactured with no exception. If the Applicable Project Component is a manufactured product, such component and its “manufactured product components” must be tested as to whether they are US manufactured. If the manufactured product and all its manufactured product components are US manufactured, then the manufacturer’s cost of the manufactured product is included for purposes of satisfying the adjusted percentage. If any of the manufactured product or its manufactured product components are not US manufactured, only the cost to the manufacturer of any US manufactured product components are included.

The core tension lies in sourcing the total costs from the manufacturer of the manufactured product or its manufactured product components. There’s a substantiation requirement on the taxpayer imposed by the Prior Notice, but there’s also a shrine of secrecy from the corresponding manufacturer.

Apparently acknowledging the need for reconciliation, the Notice aims to pave a promising path for covered technologies (i.e., solar, onshore wind and battery storage).

THE MODIFICATIONS: A PROMISING PATH FOR THE DOMESTIC CONTENT BONUS CREDIT

NEW ELECTIVE SAFE HARBOR

Generally

The Safe Harbor allows a taxpayer to elect to assume the domestic percentage costs (assumed cost percentages) for manufactured products. Importantly, the election eliminates the requirement for a taxpayer to source a manufacturer’s direct costs with respect to the taxpayer’s Applicable Project and instead allows for the reliance on the assumed cost percentages. The Notice prohibits any partial Safe Harbor reliance, meaning taxpayers who elect to use the Safe Harbor must apply it in its entirety to the Applicable Project for which the taxpayer makes such election.

The Safe Harbor only applies to the Applicable Projects of solar photovoltaic facilities (solar PV), onshore wind facilities and battery energy storage systems (BESS). Taxpayers with other technologies must continue to comply with the Prior Notice. Notably, the Notice expands Solar PV into four subcategories: Ground-Mount (Tracking), Ground-Mount (Fixed), Rooftop (MLPE) and Rooftop (String), each having differing assumed cost percentages for the respective manufactured product component. Similarly, BESS is expanded into Grid-Scale BESS and Distributed BESS, each with differing assumed cost percentages for the respective manufactured product component.

For solar PV, onshore wind facilities and BESS, the Safe Harbor provides a list via Table 1[1] (Safe Harbor list) that denotes each relevant manufactured product component with its corresponding assumed cost percentage. Each manufactured product component (and steel or iron component) are classified under a relevant Applicable Project Component.

Of note are the disproportionately higher assumed cost percentages of certain listed components within the Safe Harbor list. For solar PV, cells under the PV module carry an assumed cost percentage of 36.9% (Ground-Mount (Tracking)), 49.2% (Ground-Mount (Fixed)), 21.5% (Rooftop (MLPE)) or 30.8% (Rooftop (String)).

For onshore wind facilities, blades and nacelles under wind turbine carry an assumed cost percentage of 31.2% and 47.5%, respectively.

For BESS, under battery pack, Grid-scale BESS cells and Distributed BESS packaging carry an assumed cost percentage of 38.0% and 30.15%, respectively. Accordingly, projects incorporating US manufactured equipment in these categories are likely to meet the Manufactured Products Requirement with little additional spend. Conversely, projects without these components are unlikely to satisfy the threshold.

Mechanics of the Safe Harbor

Reliance on the Safe Harbor is a simple exercise of component selection and subsequent assumed cost percentage addition. Put more specifically, a taxpayer identifies the Applicable Project on the Safe Harbor list and assumes the list of components within (without regard to any components in the taxpayer’s project that are not listed). Then, the taxpayer (i) identifies which of the components within the Safe Harbor list are in their project, (ii) confirms that any steel or iron components on the Safe Harbor list fulfill the Steel or Iron Requirement, and (iii) sums the assumed cost percentages of all identified listed components that are 100% US manufactured to determine whether their Applicable Project meets the relevant adjusted percentage threshold.

The Notice addresses nuances in situations involving mixed 100% US manufactured and 100% foreign manufactured components that are of like-kind, component production costs and treatment for PV+BESS Projects.

The Notice also provides that a taxpayer adjusts for a mix of US manufactured and foreign manufactured components by applying a weighted formula to account for the foreign components.

Consistent with the Prior Notice, the Notice provides that the assumed cost percentage of “production” costs may be summed and included in the domestic cost percentage only if all the manufactured product components of a manufactured product are 100% US manufactured.

Lastly, in accordance with the view that a PV+BESS Project is treated as a single project, the Notice provides that a taxpayer may use a weighted formula to determine a single domestic content percentage for the project.

The numerator is the sum of the (i) aggregated assumed cost percentages of the manufactured product components that constitute the solar PV multiplied by the solar PV nameplate capacity and (ii) aggregated assumed cost percentages of the manufactured product components that constitute BESS multiplied by the BESS nameplate capacity and the “BESS multiplier.” The BESS multiplier converts the BESS nameplate capacity into proportional equivalency (i.e., equivalent units) to the solar PV nameplate capacity. The denominator is the sum of the solar PV nameplate capacity and the BESS nameplate capacity. Divided accordingly, the final fraction constitutes the single domestic content percentage that the taxpayer uses to determine whether its PV+BESS Project meets the relevant manufactured product adjusted percentage threshold.

Additionally, the Notice confirms that taxpayers can ignore any components not included in the Safe Harbor list. Compared with the Prior Notice, this can be a benefit for taxpayers with non-US manufactured products that are not on the Safe Harbor list. Conversely, for taxpayers with US manufactured products that are not on the Safe Harbor list, they lose the benefit of including such costs in the Manufactured Products Requirement. However, this is mostly a benefit because it eliminates any ambiguity surrounding the treatment of components not listed in the Prior Notice.

EXPANSION OF COVERED TECHNOLOGIES

The Notice adds “hydropower facility or pumped hydropower storage facility” to the list of Applicable Projects as a modification to Table 2 in the Prior Notice. The modification is complete with a list of a hydropower facility or pumped hydropower storage facility’s Applicable Project Components that are delineated as either steel or iron components or manufactured products, though no assumed cost percentages are provided. Further, the Prior Notice’s “utility-scale photovoltaic system” is redesignated as “ground-mount and rooftop photovoltaic system.”

CERTIFICATION

To elect to rely on the Safe Harbor, in its domestic content certification statement, a taxpayer must provide a statement that says they are relying on the Safe Harbor. This is submitted with the taxpayer’s tax return.

RELIANCE AND COMMENT PERIOD

Taxpayers may rely on the rules set forth in the Notice and the Prior Notice (as modified by the Notice) for Applicable Projects, the construction of which begins within 90 days after the publication of intended forthcoming proposed regulations.

Comments should be received by July 15, 2024.

CONCLUSION

While this article provides a high-level summary of the substantive content in the Notice, the many potential implications resulting from these developments merit additional attention. We will continue to follow the development of the guidance and provide relevant updates as necessary.

US Issues Final Regulations on FEOC Exclusions from Clean Vehicle Credit

On May 6, 2024, the U.S. Department of the Treasury (Treasury) and Internal Revenue Service (IRS) published final regulations (Final Regulations) regarding clean vehicle tax credits under Internal Revenue Code sections 25E and 30D established by the Inflation Reduction Act of 2022 (IRA). Among other important guidance, the Treasury regulations finalized its rules on Foreign Entity of Concern (FEOC) restrictions regarding the section 30D tax credit. On the same day, in conjunction with the Treasury final regulations, the U.S. Department of Energy (DOE) published a final interpretive rule (Notification of Final Interpretive Rule) finalizing its guidance for interpreting the statutory definition of FEOC under Section 40207 of the Infrastructure Investment and Jobs Act (IIJA). The Treasury final regulations and the DOE final interpretive rule largely adopted the proposed regulations and interpretive rule on FEOC published by the Treasury and the DOE on December 4, 2023, with some important changes and clarifications.

DOE Final Interpretative Rule on FEOC

The DOE’s final interpretive rule confirms the major elements of the December 2023 proposed interpretive rule and clarifies the definition of “foreign entity of concern” by providing interpretations of the following key terms: “government of a foreign country,” “foreign entity,” “subject to the jurisdiction,” and “owned by, controlled by, or subject to the direction.”

The final rule does not make any changes to its interpretations of “foreign entity” and “subject to the jurisdiction,” but makes clarifying changes to its interpretations of “government of a foreign country” and “owned by, controlled by, or subject to the direction.”

Government of a Foreign Country

The DOE’s final interpretive rule does not change the framework of the definition of “government of a foreign country,” which includes, among other elements, current or former senior political figures of a foreign country and their immediate family members. However, in the specific context of the PRC, DOE makes substantial changes and clarifies that the definition of “senior foreign political figure” now also includes current and former members of the National People’s Congress and Provincial Party Congresses, and current but not former members of local or provincial Chinese People’s Political Consultative Conferences.

Moreover, the final rule further clarifies and broadens when an official will be considered “senior” as follows: “an official should be or have been in a position of substantial authority over policy, operations, or the use of government-owned resources” (emphasis added).

Owned by, Controlled by, or Subject to the Direction

The DOE’s final interpretive rule is largely consistent with the proposed interpretive rule for the interpretations of “owned by, controlled by, or subject to the direction,” but makes some clarifying edits in response to public comments.

  • Control by 25% Interest

The DOE’s final interpretive rule finalizes the 25% control test provided in the proposed interpretive rule and makes further clarifications to the method for calculating the control percentage. The 25% threshold is to apply to each metric (board seats, voting rights, and equity interests) independently, not in combination, and the highest metric is used for the FEOC analysis. For example, if an entity has 20% of its voting rights, 10% of its equity interests, and 15% of its board seats held by the government of a covered nation, the entity would be treated as being 20% controlled by the covered nation government (not combined 45% control).

  • Effective Control by Licensing and Contracting

The DOE’s final interpretive rule finalizes that licensing agreements or other contracts can create a control relationship for FEOC test purposes and has proposed a safe harbor for evaluation of “effective control.” The final interpretive rule provides a list of rights covering five categories that need to be expressly reserved under the safe harbor rule. One requirement is that a non-FEOC needs to retain access to and use of any intellectual property, information, and data critical to production. In response to public comments, the final interpretive rule makes compromise regarding this requirement and provides that the non-FEOC entities need to retain such access and use no longer than “the duration of the contractual relationship.”

Moreover, in the final interpretive rule, the DOE declines to expand the definition of “control” to include foreign entities that receive significant government subsidies, grants, or debt financing from the government of a covered nation.

Treasury Final Regulations on FEOC Restrictions

The Treasury’s final regulations cross-reference the DOE’s FEOC interpretive guidance regarding FEOC definitions. Similar to the DOE’s final interpretive rule, the Treasury’s final regulations generally follow the December 2023 proposed regulations regarding FEOC restrictions and compliance regulations relating to the section 30D clean vehicle tax credit, but have also made certain important modifications and clarifications outlined below:

Allocation-based Accounting Rules

For the FEOC restrictions, the Treasury final regulations make permanent the allocation-based accounting rules for applicable critical minerals contained in battery cells and associated constituent materials.

Due Diligence

The final regulations confirm that to satisfy the due diligence requirement for FEOC compliance, and in addition to the due diligence conducted by the manufacturers meeting the qualification requirements of the regulations (qualified manufacturers) themselves, the qualified manufacturers can also reasonably rely on due diligence and attestations and certifications from suppliers if the qualified manufacturers do not know or have reason to know that such attestations or certifications are incorrect.

Impracticable-to-trace Battery Materials

The final regulations finalize a transition rule, which provides that the FEOC restrictions will not apply to qualified manufacturers as to “impracticable-to-trace battery materials” before 2027. The term “impracticable-to-trace battery materials” replaces the proposed regulations’ reference to “non-traceable battery materials.” Impracticable-to-trace battery materials are defined in the final regulations as specifically identified low-value battery materials that originate from multiple sources and are commingled by suppliers during production processes to a degree that the qualified manufacturers cannot determine the origin of such materials. The final regulations also identify certain battery materials as constituting impracticable-to-trace battery materials. Qualified manufacturers may temporarily exclude impracticable-to-trace battery materials from the required FEOC due diligence and FEOC compliance determinations until January 1, 2027. To take advantage of this transition rule, qualified manufacturers must submit a report during the upfront review process as set forth in the final regulations, demonstrating how they will comply with the FEOC restrictions once the transition rule is no longer in effect.

Traced Qualifying Value Test

The final regulations provide a new test, the “traced qualifying value test,” for OEMs to trace the sourcing of critical minerals and determine the actual value-added percentage for each applicable qualifying critical mineral for each procurement chain.

Exemption for New Qualified Fuel Cell Motor Vehicles

The final regulations also confirm that the FEOC restrictions generally do not apply to new qualified fuel cell motor vehicles (with certain exception) as they do not contain clean vehicle batteries.

Conclusion

Under the final regulations and final interpretive rule, to take advantage of the section 30D tax credit, qualified manufacturers shall conduct FEOC and supply chain analysis and satisfy the due diligence, certification and other requirements. Moreover, for the qualified manufacturers that seek to rely on their battery suppliers’ due diligence and relevant attestations or certifications, they should consider incorporating terms in their contracts with such suppliers that require reporting and tracing assurances regarding battery materials and critical minerals.

The DOE’s final interpretive rule became effective on May 6, 2024. The Treasury’s final regulations will be effective on July 5, 2024.

Good News for Offshore Wind Blows in With New Guidance From the Treasury and IRS

The Inflation Reduction Act of 2022 (IRA) includes several tax credits to encourage investment in renewable energy projects, including an Investment Tax Credit (ITC) that is worth up to 30% of the overall project cost. The developer of a renewable energy project can receive a bonus of up to 10% on top of the ITC for a qualified facility that is located or placed in service in an “energy community.” One type of area that can qualify as an energy community under the IRA — the one most relevant to offshore wind projects — is an area that has significant employment or local tax revenues from fossil fuels and a higher-than-average unemployment rate.

In order to apply the criteria to offshore wind facilities, the US Department of Treasury initially proposed that an offshore wind project would be deemed to be located or placed in service at the place closest to the point of interconnection (POI) where there is land-based equipment that conditions the energy generated by the offshore wind project for transmission, distribution, or use.

Stakeholders in the offshore wind industry believed, however, that this approach did not adequately reflect the original intent of the IRA as it neglected to take into account the long-term benefits of activity related to offshore wind projects at locations, particularly ports, that were not at the POI.

Responding to stakeholder advocacy over the past several months, on March 22, the Internal Revenue Service (IRS) released updated guidance in IRS Notice 2024-30 (the Notice). The Notice permits projects with multiple POIs to qualify for the bonus credit, so long as one of the POIs is within an energy community. Stakeholders believe that this will be key in developing the shared transmission infrastructure that will be required for effective use of offshore wind energy.

Further, the Notice permits offshore wind facilities to attribute their nameplate capacity to additional property — namely, to supervisory control and data acquisition system (SCADA) equipment owned by the owner of the offshore wind project and located in an EC Project Port (as defined in the Notice). SCADA equipment is property that is used to remotely monitor and control the operations of the offshore wind project. The SCADA system is effectively the nerve center for an offshore wind project.

An “EC Project Port” is defined in the Notice as a port that is used either full or part time to facilitate maritime operations necessary for the installation or operation and maintenance of the offshore wind project, and that has a significant long-term relationship with the project’s owner by virtue of ownership or lease arrangements. The personnel based at the port need to include staff who are employed by, or who work as independent contractors for, the project’s owner and who perform functions essential to the project’s operations. Staff based at the port will be considered to perform functions essential to the project’s operations only if they collectively perform all the following functions: management of marine operations, inventory and handling of spare parts and consumables, and berthing and dispatch of operation and maintenance vessels and associated crews and technicians.

Finally, the Notice adds two industry codes from the North American Industry Classification System (NAICS) to those that are used to determine a community meets the IRA’s required percentage of its workforce who are employed in the extraction, processing, transport, or storage of coal, oil, or natural gas. These additional NAICS codes designate oil pipeline infrastructure and natural gas distribution infrastructure. These additional codes are intended to bring the benefits of the energy community bonus credit to more communities and the IRS has amended its list of energy communities accordingly.

Advocates note that the updated guidance in the Notice represents a more holistic approach to the energy communities bonus credit that will give offshore wind project developers more flexibility in identifying ports for their investment, The increased flexibility will bring the economic benefit of the offshore wind industry to more communities, which will ultimately reduce the cost burden to ratepayers.

President Biden Nominates Three FERC Commissioners

On February 29, 2024, President Biden nominated three new commissioners of the Federal Energy Regulatory Commission (“FERC”). The nominations will be reviewed and voted on by the Senate Energy and Natural Resources Committee and are subject to confirmation by the full Senate. If approved, the nominees will provide FERC with a full slate of five commissioners, including three Democrats and two Republicans.

Judy Chang is the Managing Principal of the Analysis Group in Boston and former Undersecretary of Energy and Climate Solutions of the Massachusetts Department of Energy Resources. She is a Democrat and will succeed Commissioner Allison Clements with a term ending June 30, 2029. Commissioner Clements has announced that she would not serve a second term, but she may remain on FERC after June 30, 2024, until replaced or through December 31, 2024. Ms. Chang was the keynote speaker at Pierce Atwood’s 2022 Energy Infrastructure Symposium.

Lindsay See is the Solicitor General of the State of West Virginia. Ms. See is a Republican, recommended to the President by Senate Minority Leader Mitch McConnell, and will succeed former Commissioner James Danly with a term ending June 30, 2028. Ms. See has represented West Virginia in many multi-state legal coalitions on a variety of national issues, including energy and environmental rules and policies.

David Rosner is a member of the FERC staff, an energy industry analyst who has been on loan to the majority staff of the Senate Energy and Natural Resources Committee, which is chaired by Senator Joe Manchin of West Virginia. Mr. Rosner will succeed former Chairman Richard Glick with a term ending June 30, 2027.

All three nominations have been received by the Senate and referred to the Energy and Natural Resources Committee, which will hold a hearing on each nominee. The Committee has not yet scheduled any hearings.

FERC Chairman Willie L. Phillips was designated as chairman on February 9, 2024. He was previously acting chairman. His term ends June 30, 2026. Commissioner Mark C. Christie’s term ends on June 30, 2025.

Striking a Balance: The Supreme Court and the Future of Chevron Deference

In its frequent attempts to enforce the separation of powers that the Constitution’s framers devised as a system of checks and balances among the executive, legislative, and judicial branches of the federal government, it is often the so-called “Fourth Branch”—that includes the varied administrative agencies—that is at the heart of things.[1]

These agencies possess a level of technical and scientific expertise that the federal courts generally lack. And, without reference to expertise, Congress often leaves it to agencies and the courts to interpret and apply statutes left intentionally vague or ambiguous as the product of the legislative compromise required to gain passage. This phenomenon begs the question of the extent to which the federal courts may defer to administrative agencies in interpreting such statutes, or whether such deference abnegates the judicial prerogative of saying what the law is. Having passed on several opportunities to revisit this question, the Supreme Court of the United States has finally done so.

In what potentially will lead to a decision that might substantially change the face of federal administrative law generally while voiding an untold number of agency regulations, the Supreme Court, on January 17, 2024, heard oral argument in a pair of appeals, Loper Bright Enterprises, et al., v. Raimondo, No. 22-451, and Relentless, Inc., et al. v. Department of Commerce, No. 22-1219, focusing on whether the Court should overrule or limit its seminal decision in Chevron U.S.A., Inc. v. Natural Resources Defense CouncilInc., 467 U.S. 837 (1984).

Almost 40 years ago, the Chevron decision articulated the doctrine commonly known as “Chevron deference,” which involves a two-part test for determining when a judicial determination must be deferential to the interpretation of a statute. The first element requires determining what Congress has spoken directly to the specific issue in question, and the second is “whether the agency’s answer is based on a permissible construction of the statute.”

Among the most cited Supreme Court cases, Chevron has become increasingly controversial, especially within the conservative wing of the Court, with several Justices having suggested that the doctrine has led to the usurpation of the essential function of the judiciary.

Chevron deference affects a wide range of federal regulations, and the Court’s ruling, whether or not Chevron is retained in some form, is likely to result in significant changes to how agencies may implement statutes and how parties affected by regulations may seek relief from the impact of those regulations. Interestingly, commentators on the recent oral argument in the case are widely divided in their predictions as to the outcome—some suggesting that the conservative majority of the Court will overrule Chevron outright, others suggesting that the Court has no intention at all to do so.

Based on remarks made during the oral arguments by Justice Gorsuch, and by Justices Amy Coney Barrett and Elena Kagan, as well as Justice Kagan’s fashioning of a majority that clarified a related interpretive rule in an earlier case focusing on agencies’ authority to interpret their own regulations, we suggest that there is a substantial possibility that the Court will take a moderate path by strengthening judicial scrutiny at the “Step One” level while recognizing that there are technical and scientific matters as to which courts have no expertise. At the same time, the Court may make it clear that, essentially, legal issues are within its prerogatives and are not subject to agency interpretation.

We examine how the Court might find a path to a better balancing of agency and judicial functions that is consistent with and builds upon other recent rulings involving the review of actions taken by administrative agencies. Whatever the outcome, the Court’s ruling in these cases will have a profound impact on individuals and entities that are regulated by federal agencies or that depend on participation in government programs, such as Medicare and Social Security.

Chevron Refresher

Most law students and lawyers have some familiarity with the touchstone for judicial review of agency rules that was articulated in Chevron, a case that dealt with regulations published by the Environmental Protection Agency to implement a part of the Clean Air Act.[2] The Supreme Court explained that judicial review of an agency’s final rule should be based on the two-part inquiry that we mentioned earlier. First, the reviewing court should determine whether Congress made its intent unambiguously clear in the text of the statute; if so, the inquiry ends, and both the agency and the reviewing court must give effect to Congress’s intent. This has become known by the shorthand phrase “Step One.”

If Congress’s intent is not clear, either because it did not address a specific point or used ambiguous language, then the court should defer to the agency’s construction if it is based on a permissible reading of the underlying statute. This has become known as “Step Two.”

In applying Step Two, a reviewing court should determine if the gap left by Congress was explicit or implicit. If the ambiguity is explicit, then the agency’s regulations should be upheld unless they are arbitrary, capricious, or contrary to the statute.[3] If the ambiguity is implicit, then the “court may not substitute its own construction of a statutory provision for a reasonable interpretation made by the administrator of an agency.”[4]

Chevron deference is not a blank slate for courts to find ambiguity. It recognized that the judiciary “is the final authority on issues of statutory construction” and instructed that in applying Step One, judges are expected to apply the “traditional tools of statutory construction.”[5] It also recognized that any deference analysis should fit within the balance among the branches of government. The Supreme Court explained that while Congress sets an overall policy, it may not reach specific details in explaining how that policy is to be executed in particular contexts. In these situations, the executive branch may have the necessary technical expertise to fill in the details, as it is charged with administering the policy enacted into law. The Court noted that the judiciary was not the ideal entity to fill in any gaps left in legislation because “[j]udges are not experts in the field” and that courts are not political entities. As a result, agencies with expertise are better suited to carry out those policies. Moreover, even if agencies are not accountable to the public, they are part of the executive branch headed by the President, who (unlike judges with life tenure) is directly accountable to the electorate.[6]

Nevertheless, during the recent oral arguments, the Chief Justice stated that the Court had not in recent years employed Chevron itself in its analysis of agency action. The reason why the issue of whether Chevron unduly intrudes upon the judicial function, and whether it should be overruled or modified, relates to the fact that it is widely used in lower court review of administrative actions. Its reconsideration also relates to increasing jurisprudential conservatism on the Supreme Court and the application of originalism and, more widely, textualism.

The Chevron concept of deference to agency regulations exists alongside a line of cases in which courts have deferred to an agency’s interpretations of its own regulations. In both Bowles v. Seminole Rock & Sand Co.[7] and Auer v. Robbins,[8] the Supreme Court developed the principle that courts are not supposed to substitute their preference for how a regulation should be interpreted; instead, a court should give “controlling weight” to that interpretation unless it is “plainly erroneous or inconsistent with the regulation.”[9] Nevertheless, the Court has refused to extend that form of deference to subregulatory guidelines and manuals where there is little or no evidence of a formal process intended to implement Congress’s expressed intent.[10]

The Chevron framework has generated criticism, including statements by several current Justices. Their position relies on an argument that Chevron distorts the balance of authority in favor of the executive and strips courts of their proper role. In a recent dissent from a denial of certiorari, Justice Gorsuch complained that Chevron creates a bias in favor of the federal government and that instead of having a neutral judge determine rights and responsibilities, “we outsource our interpretive responsibilities. Rather than say what the law is, we tell those who come before us to go ask a bureaucrat.”[11] Justice Thomas has written that the Administrative Procedure Act does not require deference to agency determinations and raises constitutional concerns because it undercuts the “obligation to provide a judicial check on the other branches, and it subjects regulated parties to precisely the abuses that the Framers sought to prevent.”[12]

Chevron and the Herring Fishermen

The dispute that has brought Chevron deference to the Supreme Court in 2024 starts with the business of commercial fishing for herring. The National Marine Fisheries Service (NMFS) published a regulation in 2020 that requires operators of certain fishing vessels to pay the cost of observers who work on board those vessels to ensure compliance with that agency’s rules under the Magnuson-Stevens Fishery Conservation and Management Act of 1976 (“Act”). Several commercial fishing operators challenged the regulations, which led to two decisions by the U.S. Courts of Appeals for the District of Columbia Circuit and the First Circuit. Both courts upheld the regulations, but on slightly different grounds. In the first decision, Loper Bright Enterprises, Inc. v. Raimondo,[13] the District of Columbia Circuit followed the traditional Chevron analysis and concluded that the Act did not expressly address who would bear the cost of the monitors. The NMFS’s interpretation of the statute in the regulation was found to be reasonable under Step Two of Chevron based on the finding that the agency was acting within the scope of a broad delegation of authority to the agency to further the Act’s conservation and management goals, and on the established precedent concluding that the cost of compliance with a regulation is typically borne by the regulated party.

The second decision by the First Circuit, Relentless, Inc. v. United States Department of Commerce,[14] took a slightly different approach. That court focused on the text of the Act and concluded that the agency’s interpretation was permissible. It did not anchor its decision in a Chevron analysis and stated that “[w]e need not decide whether we classify this conclusion as a product of Chevron step one or step two.”[15] The First Circuit also emphasized that the operators’ arguments did not overcome the presumption that regulated entities must bear the cost of compliance with a relevant statute or regulation.

The parties have staked out starkly different views of Chevron’s legitimacy and whether it is compatible with the separation of powers in the U.S. Constitution. The fishermen petitioners argue that Chevron is not entitled to respect as precedent because the two-part test was only an interpretive methodology and not the holding construing the Clean Air Act. Their core argument is that Chevron improperly and unconstitutionally shifts power to the executive branch by giving more weight to the agencies in rulemaking and in resolving disputes where the agency is a party and shifts power away from the judiciary’s role under Article III to interpret laws and Congress’s legislative authority power under Article I. Taking this one step further, the petitioners argue that this shift violates the due process rights of regulated parties. They also argue that Chevron is unworkable in practice, citing instances where the Supreme Court itself has declined to apply the two-part test and the lack of a consensus as to when a statute is clear or ambiguous, making the application of Chevron inconsistent. Put another way, according to the petitioners, the problem with Chevron is that there is no clear rule spelling out how much ambiguity is needed to trigger deference to an agency’s rule. Next, they argue that Chevron cannot be applied when an underlying statute is silent because this allows agencies to legislate when there is a doubt as to whether Congress delegated that power to the agency at all and that it would run counter to accepted principles of construction that silence can be construed to be a grant of power to an agency. Finally, they contend that Chevron deference to agencies conflicts with Section 706 of the Administrative Procedure Act, where Congress authorized courts to “decide all relevant questions of law, interpret constitutional and statutory provisions, and determine the meaning or applicability of the terms of an agency action.”[16]

The Secretary of Commerce argues that there are multiple reasons to preserve Chevron deference. First, the Secretary argues that Chevron fits within the balance of power between the branches of the federal government. In the Secretary’s view, Chevron deference is consistent with the separation of powers doctrine, as it respects (1) Congress’s authority to legislate and to delegate authority to an administrative agency, (2) the agency’s application of its expertise in areas that may be complex, and (3) the judiciary’s authority to resolve disputed questions of law. Therefore, the Chevron framework avoids situations where courts may function like super-legislatures in deciding how a statute should be implemented or administered and second-guess policy decisions.

According to the Secretary, courts know how to apply the traditional tools of statutory interpretation, and if an ambiguity exists after that exercise is complete, it is appropriate to defer to an administrative agency that has technical or scientific experience with the subject matter being regulated. In addition, the Secretary contends that Chevron promotes consistency in the administration of statutes and avoids a patchwork of court rulings that may make it difficult or impossible to administer a nationwide program, such as Social Security or Medicare. Third, the Secretary notes that Chevron is a doctrine that has been workable for 40 years and that over those decades, Congress has not altered or overridden its holding, even as it has enacted thousands of statutes since 1984 that either require rulemaking or have gaps that have been filled by rulemaking. As a result, the Secretary argues that there are settled interpretations that agencies and regulated parties rely on, and overruling Chevron would lead to instability and relitigating settled cases. Finally, the Secretary argues that Chevron deference cannot be limited to interpretations of ambiguous language alone, as there are no accepted criteria for distinguishing ambiguous statutory language from statutory silence.

The Oral Argument

The Supreme Court heard arguments in both cases on January 17, 2024. Over more than three hours of argument, the Justices focused on several questions. Justices Kagan, Sotomayor, and Jackson expressed concerns that abandoning the Chevron framework would put courts in the position of making policy rather than just ruling on questions of law. In their view, courts lack the skills and expertise to craft policy and should not act as super-legislators. They also stressed that there are situations in which the tools of statutory construction do not yield a single answer or that Congress has not addressed the question either because it left some matters unresolved in the statute or through other subsequent changes not contemplated by Congress, such as the adoption of new technologies. In these cases, the Justices wanted to know why deference to an agency was not appropriate and did not see any clear indication that Congress intended that courts, not agencies, should make determinations when the statutory language is ambiguous or silent. They also questioned why the Supreme Court should overrule Chevron when Congress has been fully aware of the decision for 40 years and has not enacted legislation to eliminate the ability of a court to defer to an agency’s determinations.

The members of the more conservative wing of the Supreme Court questioned counsel about weaknesses in the Chevron framework. Justice Gorsuch returned to his earlier criticism of Chevron and asked the parties to define what constitutes enough ambiguity to allow a court to move from Step One to Step Two. He further questioned whether there was sufficient evidence that Congress ever intended to give the government the benefit of the doubt when an individual or regulated entity challenges agency action. Justice Gorsuch, along with Justices Thomas and Kavanaugh, asked whether Chevron actually resulted in greater instability and whether it was appropriate to abandon Chevron in favor of the lesser form of deference articulated in Skidmore v. Swift & Co., where deference is not a default outcome and a court is supposed to exercise its independent judgment to give weight to agency determinations based on factors including the thoroughness of the agency’s analysis, the consistency and validity of the agency’s position, and the agency’s “consistency with earlier and later pronouncements, and all those factors which give it power to persuade.”[17] The follow-up questions asked whether it was correct to accord deference to agency regulations when the agency’s policy can shift from administration to administration.

Where Is the Conservative Court Likely to Go?

The length of the argument and the alacrity of questioning do not mean that the Supreme Court is going to overrule the 40-year-old, highly influential Chevron doctrine. It is, however, quite likely that the doctrine will be narrowed and clarified. To say nothing of the recent oral argument, several recent decisions evidence a reluctance to abandon deference altogether. In a pair of decisions issued in 2022 involving Medicare reimbursement to hospitals, the Court resolved deference questions by relying on the statutory text alone.

Those decisions involved challenges to a Medicare regulation governing hospital reimbursement, and a published interpretation of a section of the Medicare statute governing reimbursement for outpatient drugs. Although the Court ruled in the government’s favor in the former case and against the government in the latter case, neither decision relies on Chevron—even though in one case, the petitioner’s counsel expressly asked the Court to overrule Chevron during the oral argument.[18] Yet, by relying on the text of each statute to resolve a regulatory dispute, the Court’s reasoning in both decisions is consistent with Step One of the Chevron test and demonstrates that it is workable in practice and need not result in a dilution of judicial review. In addition, the Court has developed another limit to agency action in its decisions, finding that when a regulatory issue presents a “major question,” deference is irrelevant unless the agency can show that Congress expressed a clear intent that the agency exercise its regulatory authority. This concept remains a work in progress because the Court has not defined criteria that make an issue a major question.[19]

These cases provide a useful background to an increasingly jurisprudentially conservative, textually oriented Court. Two cases that were specifically discussed during oral argument are particularly significant in plotting the Court’s landing place with regard to Chevron. Justice Gorsuch made multiple references to Skidmore, which sets forth the principle that a federal agency’s determination is entitled to judicial respect if the determination is authorized by statute and made based on the agency’s experience and informed judgment. Unlike the Chevron standard, the Skidmore standard considers an agency’s consistency in interpreting a law it administers.

The second, and more recent, precedent that is even more likely to guide the narrowing of Chevron is Kisor v. Wilkie.[20] There, a 5-4 divided Court adopted a multi-stage regime for reviewing an agency’s reliance upon arguably ambiguous regulations that is roughly analogous to Chevron’s two-stage analytical modality. In doing so, it modified, but did not overrule, Auer v. Robbins, 519 U.S. 452 (1997), and its doctrinal predecessor, Bowles v. Seminole Rock & Sand Co., 325 U.S. 410 (1945), which permit a court to defer to an agency’s interpretation of its own ambiguous regulation, so long as that interpretation is reasonable, even if the court believes another reasonable reading of the regulation is the better reading.

Kisor saw a mixed bag of Justices joining, or dissenting from, various parts of the Kagan opinion. What made the majority as to its operative section was the Chief Justice’s joining Justice Ginsburg, Breyer, and Sotomayor. With Justice Ginsburg having been succeeded by Justice Barrett, and Justice Breyer having been succeeded by Justice Jackson, one might hypothesize that there now would be a conservative 5-4 majority that would have overruled Auer. However, it was Justice Barrett who raised the possibility of “Kisorizing” Chevron, a suggestion quickly adopted by Justice Kagan. Justice Gorsuch, a longtime opponent of Chevron, is likely amenable to a Skidmore-oriented result.

The Kagan opinion cabins and arguably lowers the level of deference an agency’s interpretation of a rule should receive. Thus, with a strong nod to the Court’s jurisprudential drift to the right, Justice Kagan begins with the truism that whatever discretion an agency might claim, the Court’s analysis must proceed under the proposition that an unambiguous rule must be applied precisely as its text is written. It is not unlikely that, if the Court narrows Chevron (as we predict it shall), it also will begin with a more robust requirement to apply the statutory text in Step One and re-emphasize the need to exhaust all of the tools of statutory construction; in other words, there is no need for deference unless there is genuine ambiguity. If an agency’s determination is to become relevant, it only becomes so after ambiguity is established.[21]

In short, if the law gives a definitive answer on its face, there is nothing to which a court should defer, even if the agency argues that there is an interpretation that produces a better, more reasonable result. This is a textual determination that addresses the criticism of the so-called Administrative State’s acting as a quasi-legislature to which the Court yields its own power to say what the law is.

However, even a reasonable agency interpretation, the Kagan opinion notes, might not be dispositive. The opinion must be the agency’s official position, not one ginned up for litigation purposes, and it must reflect the agency’s particular expertise.

­Conclusion

In its 40-year life, Chevron deference has been at the heart of the application of federal administrative law. No case among all of the many governmental functions that the Supreme Court considers has been more widely cited, and no administrative law case has been more controversial, especially among jurisprudential conservatives. While asked by various parties to do so, the Court has declined, and the Chevron structure has been applied, often inconsistently, by federal courts. Perhaps reflecting the increasingly conservative direction of the Court, we have reached a point where the Court will consider retiring this long-standing precedent or, alternatively, refreshing it based on the experience of courts and agencies since 1984.

Justice Kagan’s analytic method in Kisor v. Wilkie could also apply to tightening Chevron. In her decisions, she has exhibited great fidelity to reading text literally, avoiding the perils of legislation from the bench. As she wrote in Kisor:

[B]efore concluding that a rule is genuinely ambiguous, a court must exhaust all the traditional tools of construction. . . . For again, only when that legal toolkit is empty and the interpretive question still has no single right answer can a judge conclude that it is more one of policy than of law. That means a court cannot wave the ambiguity flag just because it found the regulation impenetrable on first read. Agency regulations can sometimes make the eyes glaze over. But hard interpretive conundrums, even relating to complex rules, can often be solved. A regulation is not ambiguous merely because discerning the only possible interpretation requires a taxing inquiry. To make that effort, a court must carefully consider the text, structure, history, and purpose of a regulation, in all the ways it would if it had no agency to fall back on. . . . Doing so will resolve many seeming ambiguities out of the box, without resort to . . . deference” (citations and internal punctuation omitted).[22]

Text alone might not provide the answer in every case, as Justice Kagan recognizes as she outlines four additional steps that might lead to judicial deference to agency statutory interpretations. However, to the extent that a majority of the Court elects to retain Chevron, though narrowing it, her approach in the analogous setting reflected in Kisor would be effective in resolving the two cases now at bar—recognizing agency expertise in technical and scientific matters beyond the competency of the judiciary while preserving the function of the courts to determine what the legislature actually wrote, not to write it themselves.

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ENDNOTES

[1] Besides the administrative bureaucracy, various jurists and commentators have, under this rubric, included the press, the people acting through grand juries, and interest or pressure groups. Those institutions represent the arguable influence of extra-governmental sources. We are focused here on the level of judicial deference afforded to federal administrative agencies.

[2] 467 U.S. at 842-43.

[3] 5 U.S.C. § 706(2)(A).

[4] Id. at 844.

[5] Id. at 843, fn.9.

[6] Id. at 865-66.

[7] 325 U.S. 410, 414 (1945).

[8] 519 U.S. 452, 461 (1997).

[9] Id.

[10] United States v. Mead Corp., 533 U.S. 218, 229 (2001); Christensen v. Harris County, 529 U.S. 576 (2000).

[11] Buffington v. McDonough, No. 21-972 (Gorsuch, J., dissenting at 9) (2022).

[12] Perez v. Mortgage Bankers Ass’n, 135 S.Ct. 1199,1213 (2015) (Thomas, J., concurring in the judgment).

[13] 45 F.4th 359 (D.C. Cir. 2022).

[14] 62 F.4th 621 (1st Cir. 2023).

[15] Id. at 634.

[16] 5 U.S.C. § 706.

[17] 323 U.S. 134, 140 (1944).

[18] Becerra v. Empire Health Foundation, 142 S.Ct. 2354 (2022), and American Hospital Ass’n v. Becerra, 142 S.Ct. 1896 (2022). The request to overrule Chevron appears in the transcript of the American Hospital Ass’n oral argument, at 30.

[19] West Virginia v. EPA, 142 S.Ct. 2587 (2022); Utility Air Regulatory Group v. EPA, 573 U.S. 302, 324 (2014).

[20] 139 S. Ct. 2400 (2019).

[21] Kisor predicated deference, if at all, upon five preliminary stages. First, as noted, the reviewing court should determine that a genuine ambiguity exists after applying all of the tools of statutory construction. This is consistent with Step One of Chevron, but Justice Kagan makes it clear that this is a heightened textual barrier. Second, the agency’s construction of the regulation must be “reasonable”; this is a restatement of Step Two of Chevron. The Court cautioned that an agency can fail at this step. Third, the agency’s construction must be “the agency’s ‘authoritative’ or ‘official position,’” which was explained as an interpretation that is authorized by the agency’s head or those in a position to formulate authoritative policy. Fourth, the regulatory interpretation must implicate the agency’s “substantive expertise.” Finally, the regulatory interpretation must reflect the agency’s “fair and considered judgment” and that a court should decline to defer to a merely “convenient litigating position” or “post hoc rationalizatio[n] advanced” to “defend past agency action against attack.”

[22] 139 S.Ct. at 2415.