As noted in the Background section of this preamble, the Treasury Department and the IRS received several public comment submissions in response to the proposed regulations. The public comments fall into six general categories: timing of the publication of the proposed regulations; the quarterly filing requirement in the proposed regulations; the proposed regulations’ retroactive applicability dates; the constitutionality of the section 5000D tax; technical issues and questions relating to the implementation of the section 5000D tax itself; and comments on the Special Analyses provided in the proposed regulations. Each of these categories of comments is addressed in turn in parts II through VII of this Summary of Comments and Explanation of Revisions.

All public comments were considered and are available at https://www.regulations.gov or upon request. After full consideration of the public comments received in response to the proposed regulations, this Treasury decision adopts the proposed regulations with three non-substantive modifications. Specifically, the final regulations modify proposed §§40.0-1, 40.6011-1(d), and 40.6302(c)-1 by clarifying that the section 5000D tax is imposed on “the sale of” designated drugs. The language, as modified, more closely tracks the language of section 5000D(a).

A commenter stated that the Treasury Department and the IRS acted prematurely when publishing proposed regulations related to procedural rules prior to publishing substantive rules for the section 5000D tax and requested that the Treasury Department and the IRS withdraw the proposed regulations until substantive rules are published.

The section 5000D tax is a self-executing tax – that is, the section 5000D tax is effective and applicable regardless of whether implementing regulations are published by the Treasury Department and the IRS. See Sundance Helicopters, Inc. v. United States, 104 Fed. Cl. 1, 11 (2012) (in determining whether the issuance of regulations is a precondition to the application of a statute, the court followed Tax Court precedent in Estate of Neumann v. Comm’r, 106 T.C. 216 (1996) (setting out the rule that “a tax statute is self-executing if the regulation referred to in the statute deals only with how, not whether, the tax is to be applied.”)). Further, under section 5000D(b)(1), the first date that a manufacturer, producer, or importer could be liable for the section 5000D tax is October 2, 2023. As a result, publication of the proposed regulations was not premature because liability can arise under section 5000D in the absence of substantive regulatory guidance, and taxpayers needed this procedural guidance on how to meet their tax reporting and payment obligations for section 5000D tax liability incurred on and after October 2, 2023. Accordingly, the Treasury Department and the IRS are finalizing the proposed regulations without adopting this comment.

A commenter expressed concern regarding the proposed regulations’ quarterly filing and payment requirement. Specifically, the commenter stated that – in the absence of substantive guidance such as clarification of what sales are subject to the section 5000D tax – it is “impossible” for the IRS to determine that a “quarterly cadence” for filing returns and paying the section 5000D tax is rational. Further, the commenter stated that the quarterly filing requirement will be overly burdensome on taxpayers.

Generally, §40.6011(a)-1(a)(2)(i) requires that taxpayers subject to Federal excise tax must file a Form 720, Quarterly Federal Excise Tax Return, beginning with the first calendar quarter during which their Federal excise tax liability arises. Once the first Form 720 is filed, a taxpayer is generally required to continue filing Forms 720 for every calendar quarter thereafter – regardless of whether additional Federal excise tax liabilities are incurred during a particular subsequent calendar quarter – until the taxpayer permanently ceases all operations with respect to which the Federal excise tax liability was incurred. See §§40.6011(a)-1(a)(2)(i) and 40.6011(a)-2(a)(1). Failure to file subsequent quarterly returns after filing the first Form 720 may result in the assessment of penalties under section 6651(a) of the Code.

In developing the proposed regulations, the Treasury Department and the IRS recognized that in the context of the section 5000D tax (under which a taxpayer may incur liability in a particular calendar quarter and then never incur liability again in subsequent calendar quarters), to require a taxpayer to continue to file Form 720 for every calendar quarter following the filing of its first Form 720 even if no tax liability is incurred in subsequent calendar quarters would be both unnecessary for tax administration and unduly burdensome on the taxpayer. As a result, the proposed regulations exempted taxpayers that incur a section 5000D tax liability (section 5000D taxpayers) and report that tax liability on a timely filed Form 720 from the general requirement to file subsequent Forms 720 if no section 5000D tax liability is incurred during a subsequent calendar quarter. Specifically, proposed §40.6011(a)-1(d) required a taxpayer to file a subsequent Form 720 only if a new section 5000D tax liability arises during a particular calendar quarter.

Regarding the requirement to pay a section 5000D tax liability quarterly with the taxpayer’s Form 720, generally, §§40.6071(a)-1(a) and 40.6151(a)-1 require that Form 720 filers must pay the tax shown on the return at the same time the return is filed. Providing a different rule for section 5000D taxpayers would introduce unnecessary complexity into the excise tax filing and payment regime. An increase in complexity could lead to taxpayer confusion and likely result in a greater burden on both taxpayers and the IRS with little to no benefit accruing to stakeholders. The Treasury Department and the IRS also note that proposed §40.6302(c)-1 exempted the section 5000D tax from the semimonthly deposit requirements that apply to most other Federal excise taxpayers. By finalizing this proposed rule without this modification to the requirement to pay with the quarterly filing, the compliance burden on section 5000D taxpayers will be further reduced.

For these reasons, as well as for reasons similar to those discussed in part II of this Summary of Comments and Explanation of Revisions (related to the necessity to timely provide section 5000D taxpayers with procedural guidance on how to meet their tax reporting and payment obligations), the Treasury Department and the IRS are finalizing the proposed regulations without adopting this comment.

The proposed regulations provided that the Treasury decision finalizing the proposed regulations will apply to calendar quarters beginning on or after October 1, 2023; in other words, the proposed regulations provided that this Treasury decision will not apply beginning on the date that it is published in the Federal Register, but rather it will retroactively apply as of the first day of the fourth calendar quarter of 2023. A commenter requested that the Treasury Department and the IRS reconsider the retroactive applicability dates provided in the proposed regulations because the section 5000D tax is new.

As discussed in part II of this Summary of Comments and Explanation of Revisions, the Treasury Department and the IRS prioritized providing section 5000D taxpayers with procedural guidance on how to meet their tax reporting and payment obligations by October 2, 2023, the first date when a taxpayer could incur a section 5000D tax liability. Because the first date when a taxpayer could incur liability for the section 5000D tax is October 2, 2023, which falls within the fourth calendar quarter of 2023, it is appropriate for the final regulations that provide rules relating to filing and payment of the section 5000D tax to relate back to the beginning of the fourth calendar quarter of 2023 (that is, October 1, 2023), which in accordance with section 7805(b)(1)(B), would be the first taxable period ending after October 2, 2023 (that is, the date the proposed regulations were published in the Federal Register). As a result, the Treasury Department and IRS are finalizing the proposed applicability dates without adopting this comment.

Some commenters stated that the Medicare Drug Price Negotiation Program generally, and the section 5000D tax specifically, may be unconstitutional. These comments are outside the scope of the proposed regulations, which set forth proposed rules for administering a duly enacted tax law. Therefore, it is not appropriate for the Treasury Department and the IRS to address these comments in the context of this rulemaking.

A commenter requested that the Treasury Department and the IRS consider providing sales-reporting and calculation “safe harbors” in these final regulations. Another commenter stated their belief that Notice 2023-52 requested clarification on how the Treasury Department and the IRS should define “sales” for purposes of the section 5000D tax. These comments are outside the scope of the proposed regulations, which related only to the procedures for reporting and paying the section 5000D tax.

A. Paperwork Reduction Act

A commenter requested that the Treasury Department and the IRS reconsider the paperwork burden estimate in the Paperwork Reduction Act (44 U.S.C. 3507(d)) (PRA) section of the proposed regulations because the commenter believes that the number of estimated hours is too low. In this request, the commenter suggested that it is possible that no taxpayers will ever incur a section 5000D tax liability. The commenter accepted that the Treasury Department and the IRS do not have historical data on the number of compliance hours affected taxpayers may experience if a section 5000D tax liability is incurred and did not offer a specific estimated number of hours it views as more accurate than the estimate provided in the proposed regulations. Similarly, the commenter did not offer an alternative calculation methodology that the Treasury Department and the IRS could use to provide a better burden estimate.

The Treasury Department and the IRS calculated the estimated number of paperwork burden hours using the long-standing and established methodology outlined in Publication 5743, Taxpayer Compliance Burden, to arrive at the estimated total annual reporting burden of 1,380 hours stated in the proposed regulations. For these reasons, the Treasury Department and the IRS estimate that this Treasury decision will impose a total annual reporting burden of 1,380 hours, as discussed in part II of the Special Analyses section of this preamble. However, the Treasury Department and the IRS will regularly examine and, as necessary, update the estimated total annual reporting burden of this Treasury decision as required by the PRA.

B. Regulatory Flexibility Act

A commenter requested that the Treasury Department and the IRS conduct a Regulatory Flexibility Act (5 U.S.C. chapter 6) (RFA) analysis because the commenter is concerned that this Treasury decision may have an indirect effect on small entities. An agency may properly certify that no RFA analysis is needed when it determines that a rule will not have a significant economic impact on a substantial number of small entities that are subject to the requirements of the proposed rule. See Mid-Tex Elec. Co-op., Inc. v. FERC, 773 F.2d 327, 342 (D.C. Cir. 1985) (holding that Congress did not intend to require consideration of every indirect effect that any regulation might have on small businesses). Accordingly, as discussed in part III of the Special Analyses section of this preamble, the Treasury Department and the IRS continue to certify that this Treasury decision will not create additional obligations for, or impose a significant economic impact on, small entities, and as a result, a regulatory flexibility analysis under the RFA is not required.

Pursuant to the Memorandum of Agreement, Review of Treasury Regulations under Executive Order 12866 (June 9, 2023), tax regulatory actions issued by the IRS are not subject to the requirements of section 6 of Executive Order 12866, as amended. Therefore, a regulatory impact assessment is not required.

The collection of information contained in these final regulations has been reviewed and approved by the Office of Management and Budget in accordance with the PRA under control number 1545-0023.

The collections of information in these regulations relate to reporting and recordkeeping requirements that will allow taxpayers to meet their tax reporting obligations. The collections of information would generally be used by the IRS for tax compliance purposes and by taxpayers to facilitate proper tax reporting and compliance. The reporting and recordkeeping requirements are covered within the form and instructions for Form 720.

Because the section 5000D tax is a new tax that has never been reported to the IRS, the Treasury Department and the IRS do not have historical data on the number of affected taxpayers. The Centers for Medicare and Medicaid Services (CMS) has selected 10 drugs for price negotiation for initial price applicability year 2026. CMS will select for negotiation a limited number of drugs for each initial price applicability year after that, as outlined in the IRA. Further, manufacturers, producers, or importers of such drugs may or may not become subject to a section 5000D tax liability. Based on the foregoing, the IRS estimates that there will be between 0 and 50 taxpayers during the next 3 years.

If a taxpayer has a section 5000D tax liability, it would be required to file Form 720 to report such liability. Form 720 is a quarterly return. A taxpayer would only be required to file Form 720 during calendar quarters in which the taxpayer has a section 5000D tax liability. Therefore, a taxpayer that has a section 5000D tax liability in one calendar quarter but not in subsequent calendar quarters would only be required to file one Form 720.

The respondents with regard to the section 5000D tax are manufacturers, producers, or importers of certain drugs. The Treasury Department and the IRS estimate the annual burden of the collections of information as follows (these estimates, which are for PRA purposes only, are based on the high end of the range of possible taxpayers and the high end of the range of the frequency of responses, in which a taxpayer would have tax liability in all four calendar quarters):

Estimated frequency of responses: Quarterly.

Estimated number of responses: 50.

Estimated burden time per respondent: 6.9 hours.

Estimated total annual reporting burden: 1,380 hours.

A Federal agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the collection of information displays a valid control number assigned by OMB. Books or records relating to a collection of information must be retained if their contents may become material in the administration of any internal revenue law. Generally, tax returns and tax return information are confidential, as required by section 6103.

The Treasury Department and the IRS received a comment suggesting that the paperwork burden estimate provided in the proposed regulations was too low. However, for the reasons discussed in detail in the Summary of Comments and Explanation of Revisions section of this preamble and in this Special Analyses section, the Treasury Department and the IRS have not changed the estimates provided herein.

For the reasons discussed in detail in the Summary of Comments and Explanation of Revisions section of this preamble and in this Special Analyses section, pursuant to the RFA, it is hereby certified that these final regulations will not have a significant economic impact on a substantial number of small entities. This certification is based on the fact that the section 5000D tax is imposed only on certain sales by manufacturers, producers, or importers of designated drugs during periods described in section 5000D(b). The periods described in section 5000D(b) relate to milestones in the Medicare Drug Price Negotiation Program, which involve only certain drugs with high Medicare expenditures. Drugs with high Medicare expenditures that are not already excluded from the Medicare Drug Price Negotiation Program under an exception such as the SSA’s small biotech exception (sections 1192(b) and (d)(2) of the SSA) are likely to be manufactured, produced, or imported by large entities, so if any section 5000D tax liability arises, an insubstantial number of taxpayers will be small entities. As noted earlier, data is not available about the number of taxpayers affected, but the number is likely to be limited, in part due to the limited number of drugs selected for the Medicare Drug Price Negotiation Program in any particular year. In addition, these final regulations will assist taxpayers in meeting their tax reporting obligations by providing clarity on how to report section 5000D tax liability, which will make it easier for taxpayers to comply with section 5000D. Therefore, these final regulations will not create additional obligations for, or impose a significant economic impact on, small entities, and a regulatory flexibility analysis under the RFA is not required.

Pursuant to section 7805(f) of the Code, the notice of proposed rulemaking preceding these final regulations was submitted to the Chief Counsel for the Office of Advocacy of the Small Business Administration for comment on its impact on small business. No comments were received from the Chief Counsel for the Office of Advocacy of the Small Business Administration.

Section 202 of the Unfunded Mandates Reform Act of 1995 requires that agencies assess anticipated costs and benefits and take certain other actions before issuing a final rule that includes any Federal mandate that may result in expenditures in any one year by a State, local, or Tribal government, in the aggregate, or by the private sector, of $100 million in 1995 dollars, updated annually for inflation. These final regulations do not include any Federal mandate that may result in expenditures by State, local, or Tribal governments, or by the private sector, in excess of that threshold.

Executive Order 13132 (Federalism) prohibits an agency from publishing any rule that has federalism implications if the rule either imposes substantial, direct compliance costs on State and local governments, and is not required by statute, or preempts State law, unless the agency meets the consultation and funding requirements of section 6 of the Executive order. These final regulations do not have federalism implications, do not impose substantial direct compliance costs on State and local governments, and do not preempt State law within the meaning of the Executive order.

Section 45Y(a)(1) provides that for purposes of the general business credit under section 38 of the Code, the section 45Y credit for any taxable year is an amount equal to the product of the kilowatt hours (kWh) of eligible electricity produced by the taxpayer at a qualified facility, multiplied by the applicable amount with respect to such qualified facility. For this purpose, eligible electricity is electricity that is either (1) sold by the taxpayer to an unrelated person during the taxable year or (2) in the case of a qualified facility that is equipped with a metering device that is owned and operated by an unrelated person, sold, consumed, or stored by the taxpayer during the taxable year.

For purposes of the general business credit under section 38, which includes the investment credit under section 46, section 48E(a)(1) provides a credit for any taxable year in which a qualified investment is made with respect to any qualified facility and any energy storage technology (EST).

On October 24, 2022, the Treasury Department and the IRS published Notice 2022-49, 2022-43 I.R.B. 321. The notice requested general comments on issues arising under sections 45Y and 48E, as well as on issues relating to three other credits. For section 45Y, the notice specifically requested comments concerning (1) industry standards for taxpayer eligibility for the credit, (2) what the Treasury Department and the IRS should consider, including around the scope and factors, for the annual GHG emissions rate table, (3) whether guidance is needed to clarify cases in which a metering device is owned and operated by an unrelated person or in which electricity produced at such a qualified facility with such a device is sold, consumed or stored by the taxpayer, and (4) what procedures the Treasury Department and the IRS should provide for a taxpayer whose facility does not have an emissions rate established by the annual rate table, and what should the Secretary consider in making such a determination. For section 48E, the notice specifically requested comments concerning what industry mechanisms currently exist for a taxpayer to demonstrate eligibility for the credit.

The Treasury Department and the IRS received over 100 comments specifically addressing sections 45Y and 48E from industry participants and other stakeholders. The Treasury Department and the IRS appreciate the commentors’ interest and engagement on these issues. These comments have been carefully considered in the preparation of these proposed regulations.

On August 30, 2023, the Treasury Department and the IRS published a notice of proposed rulemaking and a notice of public hearing (REG-100908-23) in the Federal Register (88 FR 60018), providing guidance on the prevailing wage and registered apprenticeship (PWA) requirements under sections 45, 45Y, 48, 48E and several other sections of the Code (August Proposed Regulations). The August Proposed Regulations also proposed guidance on the one-megawatt exception under sections 45, 45Y, 48, and 48E (One-Megawatt Exception). Under this exception, with respect to certain facilities with a maximum net output (or capacity for energy storage technology under section 48E) of less than one megawatt, increased credit amounts are available.

On November 22, 2023, the Treasury Department and the IRS published a notice of proposed rulemaking and a notice of public hearing (REG- 132569-17) in the Federal Register (88 FR 82188), providing guidance under section 48 of the Code. Among other matters, the proposed regulations under section 48 (Section 48 Proposed Regulations) withdrew and reproposed the regulations in §1.48-13 from the August Proposed Regulations regarding the PWA requirements under section 48, the One-Megawatt Exception under section 48(a)(9)(B)(i), and the recapture rules under section 48(a)(10)(C).

The proposed regulations under section 45Y are organized in five sections, proposed §§1.45Y-1 through 1.45Y-5 (section 45Y regulations). Proposed §1.45Y-1 would provide an overview of the section 45Y regulations, generally applicable definitions, and general rules applicable to section 45Y, including a rule for calculating the credit for a CHP property. Proposed §1.45Y-2 would provide rules relating to qualified facilities for purposes of the section 45Y credit. Section 1.45Y-3 is reserved for rules relating to the increased credit amount for meeting the prevailing wage and apprenticeship requirements. A cross reference will be added to §1.45Y-3 in the final regulations after §1.45Y-3 is finalized. Proposed §1.45Y-4 would provide the rules of general application under section 45Y, including rules that attribute production to the taxpayer, rules for the expansion of a facility and incremental production, and rules for retrofits of an existing facility. Proposed §1.45Y-5 would provide rules pertaining to the determination of a GHG emissions rate for a facility under section 45Y.

A. Amount of credit

Proposed §1.45Y-1 would provide an overview of the section 45Y regulations and definitions of terms for purposes of the section 45Y regulations, including the terms “combined heat and power system (CHP) property,” “metering device,” “related person,” “unrelated person,” and “qualified facility.”

Proposed §1.45Y-1(a)(5)(i) would define, for purposes of section 45Y(a)(1)(A)(ii)(II), the term “metering device” as equipment that is owned and operated by an unrelated person (as defined in paragraph (a)(11) of this section) for energy revenue metering to measure and register the continuous summation of an electricity quantity with respect to time. Further, proposed §1.45Y-1(a)(5)(ii) would provide standards for maintaining and operating a metering device for purposes of section 45Y(a)(1)(A)(ii)(II) and proposed §1.45Y-1(a)(5) by requiring a metering device to be maintained in proper working order according to the instructions of its manufacturer. Proposed §1.45Y-1(a)(5)(ii) would also provide that a metering device should meet the requirements of the American National Standards Institute C12.1-2022 standard, or subsequent revisions, be revenue grade with a +/- 0.5% accuracy, and be properly calibrated. Proposed §1.45Y-1(a)(5)(iii) would provide that for purposes of monitoring the metering device, the unrelated person may share network equipment, such as spare fiber optic cable owned by the taxpayer that produces the electricity, and may co-locate network equipment in the taxpayer’s facilities. Proposed §1.45Y-1(a)(5)(iv) would provide examples illustrating the proposed rules provided by proposed §1.45Y-1(a)(5).

Proposed §1.45Y-1(a)(7)(i) would provide that for purposes of section 45Y(a), the term “related person” means a person who is related to another person if such person would be treated as a single employer under the regulations in 26 CFR chapter 1 under section 52(b) of the Code. Proposed §1.45Y-1(a)(7)(ii) would provide that in the case of a corporation that is a member of a consolidated group (as defined in §1.1502-1(h)), such corporation will be treated as selling electricity to an unrelated person if such electricity is sold to an unrelated person by another member of such group.

Proposed §1.45Y-1(a)(11) would provide that for purposes of section 45Y(a), the term “unrelated person” means a person who is not a related person as defined in section 45Y(g)(4) and proposed §1.45Y-1(a)(7). In the case of sales of electricity to an individual consumer, such sales will be treated as sales to an unrelated party for purposes of the section 45Y credit. Proposed §1.45Y-1(a)(11) provides an example illustrating the application of these rules.

Proposed §1.45Y-1(b)(1) would describe the calculation of the section 45Y credit, providing that the credit is an amount equal to the product of the kWh of electricity that is produced by the taxpayer at a qualified facility (as defined in proposed §1.45Y-2(a)) and sold by the taxpayer to an unrelated person during the taxable year, multiplied by the applicable amount (as described in proposed §1.45Y-1(b)) with respect to such qualified facility. Proposed §1.45Y-1(b)(1) would further provide that in the case of a qualified facility that is equipped with a metering device that is owned and operated by an unrelated person, the section 45Y credit for any taxable year is an amount equal to the product of the kWh of electricity that is both produced at the qualified facility (as defined in proposed §1.45Y-2(a)) and sold, consumed, or stored by the taxpayer during the taxable year, multiplied by the applicable amount with respect to such qualified facility. Proposed §1.45Y-1(b)(1) would also provide that only one section 45Y credit may be claimed for each kWh of electricity produced by the taxpayer at a qualified facility.

Proposed §1.45Y-1(b)(2)(i) would define the applicable amount as the base amount described in §1.45Y-1(b)(2)(ii) or the alternative amount described in §1.45Y-1(b)(2)(iii). Proposed §1.45Y-1(b)(2)(i) would further provide that the applicable amount is subject to the inflation adjustment as provided in section 45Y(c)(1) and proposed §1.45Y-1(b)(3), and that the applicable amount may also be increased as provided in section 45Y(g)(7)) and proposed §1.45Y-1(b)(4), in the case of a qualified facility that is located in an energy community. Proposed §1.45Y-1(b)(2)(ii) would describe the base amount as 0.3 cents in the case of any qualified facility that does not satisfy the requirements provided in section 45Y(a)(2)(B). Proposed §1.45Y-1(b)(2)(iii) would describe the alternative amount as 1.5 cents if prevailing wage and apprenticeship requirements are satisfied as provided in section 45Y(a)(2)(B).

Proposed §1.45Y-1(b)(3) would provide the rules related to the inflation adjustment factor applicable to the section 45Y credit. Proposed §1.45Y-1(b)(4) would provide the rules applicable to the energy communities increase in credit. Proposed §1.45Y-1(b)(5) would provide the domestic content bonus credit amount.

Proposed §1.45Y-1(c) would provide the credit phase-out rules. Generally, proposed §1.45Y-1(c)(1) would provide that the amount of the clean electricity production credit under section 45Y(a) for any qualified facility the construction of which begins during a calendar year described in section 45Y(d)(2) is equal to the product of the amount of the credit determined under section 45Y(a) without regard to the credit phaseout rules of section 45Y(d) (credit phase-out), multiplied by the phase-out percentage provided in section 45Y(d)(2). Proposed §1.45Y-1(c)(2) would provide that the phase-out percentage is 100 percent for a facility the construction of which begins during the first calendar year following the applicable year; 75 percent for a facility the construction of which begins during the second calendar year following the applicable year; 50 percent for a facility the construction of which begins during the third calendar year following the applicable year; and 0 percent for a facility the construction of which begins during any calendar year subsequent to the calendar year described in section 45Y(d)(2)(C).

Proposed §1.45Y-1(c)(3) would define the “applicable year” for purposes of proposed §1.45Y-1(c) to mean the later of the calendar year in which the Secretary makes the determination that the annual greenhouse gas emissions from the production of electricity in the United States are equal to or less than 25 percent of the annual greenhouse gas emissions from the production of electricity in the United States for calendar year 2022, or 2032. Proposed §1.45Y-1(c)(4) would provide that, for the purposes of determining the applicable year, the annual greenhouse gas emissions from the production of electricity in the United States for any year must be assessed separately using both the Energy Information Administration’s (EIA) Electric Power Annual, using the sum of the annual carbon dioxide emissions data from conventional power plants and combined heat and power plants as currently listed in Table 9.1 and the Monthly Energy Review annual carbon dioxide emissions from the combustion of biomass to produce electricity in the electric power sector as currently listed in Table 11.7, and the U.S. Environmental Protection Agency (EPA) Inventory of U.S. Greenhouse Gas Emissions and Sinks (GHGI) annual electric power-related carbon dioxide, methane, and nitrous oxide emissions data including carbon dioxide emissions from the combustion of biomass to produce electricity. In the most current version of the GHGI, annual fossil and biogenic CO₂ from electricity production in the electric power sector is available in Table 2-11 and Tables 3-120 and 3-122, respectively; and CH₄ and N₂O from electricity production in the electric power sector is available in Table 3-8 and Table 3-9, respectively. Based on current and publicly available data in the 2024 GHGI, the estimate for 2022 GHG emissions associated with the production of electricity is 1,613 million metric tons (MMT) CO₂e. Currently, explicit data on industrial and commercial sector GHG emissions from the production of electricity is not disaggregated from overall sectoral totals. See GHGI, https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks.

For 2022, the EIA Electric Power Annual states that the annual carbon dioxide emissions from conventional power plants and combined heat and power plants are 1,650 MMT, and the Monthly Energy Review annual carbon dioxide emissions from the combustion of biomass to produce electricity in the electric power sector are 35 MMT. Thus, the EIA’s data reflects a total of 1,685 MMT in 2022. See EIA Electric Power Annual (https://www.eia.gov/electricity/annual); MER (https://eia.gov/totalenergy/monthly/).

Proposed §1.45Y-1(c)(5) would provide that, for the purposes of determining the applicable year, the Secretary will make such determination only if the annual greenhouse gas emissions from the production of electricity in the United States, as determined separately under both of the data sources described in proposed §1.45Y-1(c)(4), for the year is equal to or less than 25 percent of the annual greenhouse gas emissions from the production of electricity in the United States for calendar year 2022. Proposed §1.45Y-1(c)(5) would provide that if a data source described in proposed §1.45Y-1(c)(4) becomes unavailable (for example, it is no longer published or it does not provide the specified data), the Secretary must designate a similar data source to replace the unavailable data source. Requiring the applicable year to be determined using data from the EIA’s Electric Power Annual and Monthly Energy Review and the EPA’s GHGI ensures that this important determination is made transparently and based on reliable information. Both well-established data sources are representative of the annual greenhouse gas emissions from the production of electricity in the United States, but there are slight differences in the greenhouse gases and the emissions sources covered by each data source.

There are other United States Government greenhouse gas datasets that could serve as the basis for the Secretary’s determination as to whether the annual greenhouse gas emissions from the production of electricity in the United States are equal to or less than 25 percent compared to 2022. Two such datasets are the EPA Greenhouse Gas Reporting Program (GHGRP) and Emissions & Generation Resource Integrated Database (eGRID). The Treasury Department and the IRS request comment on which datasets are most appropriate to determine the applicable year and why.

Proposed §1.45Y-1(d) would provide requirements for CHP property and special rules for calculating the section 45Y credit for CHP property. Proposed §1.45Y-1(d)(1) would provide that CHP property must produce at least 20 percent of its total useful energy in the form of thermal energy that is not used to produce electrical or mechanical power (or combination thereof), and at least 20 percent of its total useful energy in the form of electrical or mechanical power (or combination thereof). Proposed §1.45Y-1(d)(1) would further provide that the energy efficiency percentage of CHP property must exceed 60 percent, and that these percentages are determined on a British thermal unit (Btu) basis. Section 45Y(g)(2)(B) incorporates these requirements by providing that the term “combined heat and power system property” has the same meaning given such term by section 48(c)(3) (without regard to section 48(c)(3)(A)(iv), (B), and (D)).

Proposed §1.45Y-1(d)(2) would describe the energy efficiency percentage of a CHP property stating that it is the fraction the numerator of which is the total useful electrical, thermal, and mechanical power produced by the system at normal operating rates, and expected to be consumed in its normal application, and the denominator of which is the lower heating value of the fuel sources for the system, which is a measure of heat content based on the net energy content of a combustible fuel.

Proposed §1.45Y-1(d)(3) would provide a special rule for calculating electricity produced by CHP property. For purposes of section 45Y(a) and proposed §1.45Y-1(b), the kWh of electricity produced by a taxpayer at a qualified facility will include any production in the form of useful thermal energy by any CHP property within such facility, and the amount of greenhouse gases emitted into the atmosphere by such facility in the production of such useful thermal energy will be included for purposes of determining the GHG emissions rate for such facility.

Proposed §1.45Y-1(d)(3)(ii)(A) would provide a conversion from Btu to kWh. Proposed §1.45Y-1(d)(3)(ii))(A) would provide that for purposes of section 45Y(g)(2)(A)(i) and §1.45Y-1(d)(3), the amount of kWh of electricity produced in the form of useful thermal energy is equal to the quotient of the total useful thermal energy produced by the CHP property within the qualified facility, divided by the heat rate for such facility.

Proposed §1.45Y-1(d)(3)(ii)(B) would define the term “heat rate” to mean the amount of energy used by the qualified facility to generate 1 kWh of electricity, expressed as Btus per net kWh generated. In calculating the heat rate of a qualified facility that includes CHP property that uses combustion, a taxpayer must use the annual average heat rate, defined as the total annual fuel consumption of the CHP property (in Btus, using the lower heating value of the fuel) during the taxable year for which the section 45Y credit is claimed, divided by the annual net electricity generation (in kWh) of the CHP property during such taxable year.

Section 45Y(g)(2), by cross reference to section 48(c)(3), requires that the energy efficiency percentage of the CHP property must exceed 60 percent, calculated as (1) the total useful electrical, thermal, and mechanical power produced by the system at normal operating rates, and expected to be consumed in its normal application, divided by (2) the lower heating value (LHV) of the fuel sources for the system. The LHV is calculated based on combustion. Some CHP property may not involve combustion, such as nuclear cogeneration. In these scenarios, because there is no calculable LHV, the energy efficiency percentage of the CHP property cannot be determined using the calculation provided in the statute.

The Treasury Department and the IRS request comments regarding the application of the energy efficiency percentage requirements to CHP property for which there is no combustion. Relatedly, comment is requested on whether the existing definition of heat rate provided in section 45Y(g)(2)(C)(ii) for purposes of calculating the section 45Y credit for CHP property that does not use combustion should be clarified.

B. Qualified facility

Proposed §1.45Y-2(a) would define a “qualified facility” to mean a facility owned by the taxpayer and used for the generation of electricity, that is placed in service after December 31, 2024, and has a GHG emissions rate of not greater than zero (as determined under rules provided in proposed §1.45Y-5).

1. Property Included in Qualified Facility

Proposed §1.45Y-2(b) would provide a description of the property included in a qualified facility. Proposed §1.45Y-2(b)(1) would provide that a qualified facility includes a unit of qualified facility (as defined in proposed §1.45Y-2(b)(2)(i)) that meets the requirements of proposed §1.45Y-2(b)(2)(ii). Proposed §1.45Y-2(b)(1) would provide that a qualified facility also includes qualified property owned by the taxpayer that is an integral part of a qualified facility (as defined in proposed §1.45Y-2(b)(3)). Section 45Y is silent regarding the credit eligibility of components that are part of a qualified facility but located in different locations. Proposed §1.45Y-2(b)(1) would clarify that any property that meets the requirements of a qualified facility described in proposed §1.45Y-2(b) is part of a qualified facility, regardless of where such property is located. Proposed §1.45Y-2(b)(1) would provide that a qualified facility also generally does not include equipment that is an addition or modification to an existing qualified facility, however, proposed §1.45Y-2(b)(1) would reference proposed §1.45Y-4(c) for rules regarding the expansion of a facility or incremental production and proposed §1.45Y-4(d) for rules regarding a retrofitted qualified facility (80/20 Rule).

2. Unit of Qualified Facility

Proposed §1.45Y-2(b)(2)(i) would provide that for purposes of the section 45Y credit, the unit of qualified facility includes all functionally interdependent components of property (as defined in proposed §1.45Y-2(b)(2)(ii)) owned by the taxpayer that are operated together and that can operate apart from other property to produce electricity. Proposed §1.45Y-2(b)(2)(i) would clarify that no provision of this section, §1.45Y-1, or §1.45Y-4 through §1.45Y-5 uses the term “unit” in respect of a qualified facility with any meaning other than that provided in proposed §1.45Y–2(b)(2)(i). A reference to §1.45Y-3 will also be added to the previous sentence in proposed §1.45Y-2(b)(2)(i) when proposed §1.45Y-2(b)(2)(i) is finalized, but it cannot be added until §1.45Y-3 is finalized.

Proposed §1.45Y-2(b)(2)(ii) would provide that components are functionally interdependent if placing in service each component is dependent upon placing in service other components to produce electricity. See the discussion in section I.A. of the Explanation of Provisions regarding the special rule for CHP property.

3. Integral Part

Proposed §1.45Y–2(b)(3)(i) would provide that for purposes of the section 45Y credit, a component of property owned by a taxpayer is an integral part of a facility if it is used directly in the intended function of the qualified facility and is essential to the completeness of such function.

Proposed §1.45Y–2(b)(3)(ii) would provide that components of property that are an integral part of a qualified facility include power conditioning equipment and transfer equipment. Proposed §1.45Y–2(b)(3)(ii) would provide that power conditioning equipment includes equipment that modifies the characteristics of electricity into a form suitable for use or transmission or distribution. Proposed §1.45Y–2(b)(3)(ii) would provide that parts related to the functioning or protection of power conditioning equipment are also treated as power conditioning equipment and includes examples.

Proposed §1.45Y–2(b)(3)(ii) would provide that transfer equipment includes components that permit the aggregation of electricity generated by components of qualified facilities and components that alter voltage in order to permit transfer to a transmission or distribution line. Proposed §1.45Y–2(b)(3)(ii) would also clarify that transfer equipment does not include transmission or distribution lines. Proposed §1.45Y–2(b)(3)(ii) would provide that examples of transfer equipment include, but are not limited to, wires, cables, and combiner boxes that conduct electricity. Proposed §1.45Y–2(b)(3)(ii) would provide that parts related to the functioning or protection of transfer equipment are also treated as transfer equipment and include examples.

Proposed §1.45Y-2(b)(3)(iii) would provide that roads that are an integral part of a qualified facility are those roads integral to the intended function of the qualified facility, such as onsite roads that are used to operate and maintain the qualified facility. Proposed §1.45Y–2(b)(3)(iii) would also clarify that roads used primarily for access to the site, or roads used primarily for employee or visitor vehicles, are not integral to the intended function of the qualified facility and thus are not an integral part of a qualified facility.

Proposed §1.45Y–2(b)(3)(iv) and (v) would also provide that fences and buildings (also referred to as structures) are generally not integral parts of a qualified facility because they are not integral to the intended function of the qualified facility. However, a building (or structure) may be an integral part of a qualified facility if it is essentially an item of machinery or equipment and a structure that houses components of property that are integral to the intended function of the qualified facility if the use of the structure is so closely related to the use of the housed components of property therein that the structure clearly can be expected to be replaced if the components of property it initially houses are replaced.

Proposed §1.45Y-2(b)(3)(vi) would provide a rule for shared integral property by stating that multiple qualified facilities (whether owned directly by one or more taxpayers), including qualified facilities with respect to which a taxpayer has claimed a credit under section 45Y or section 48E, may include shared property that can be considered an integral part of each qualified facility. Proposed §1.45Y-2(b)(3)(vi) would also provide that a component of property that is shared by a qualified facility (as defined in section 45Y(b)) (45Y Qualified Facility) and a qualified facility (as defined in section 48E(b)(3)) (48E Qualified Facility) that is an integral part of both qualified facilities will not affect the eligibility of the section 45Y Qualified Facility to claim the section 45Y credit or the section 48E Qualified Facility to claim a section 48E credit. Proposed §1.45Y-2(b)(3)(vii) would provide examples illustrating proposed §1.45Y-2(b)(3).

4. Coordination with Other Credits

Proposed §1.45Y-2(c)(1) would provide that the term “qualified facility” (as defined in section 45Y(b)) will not include any facility for which a credit determined under section 45, 45J, 45Q, 45U, 48, 48A, or 48E is allowed under section 38 of the Code for the taxable year or any prior taxable year. Proposed §1.45Y-2(c)(1) would further clarify that a taxpayer that directly owns a qualified facility (as defined in section 45Y(b)) that is eligible for both a section 45Y credit and another Federal income tax credit is eligible for the section 45Y credit only if the other Federal income tax credit was not allowed with respect to the qualified facility. Proposed §1.45Y-2(c)(1) would also add that nothing in §1.45Y-2(c) precludes a taxpayer from claiming a section 45Y credit with respect to a qualified facility (as defined in section 45Y(b)) that is co-located with another facility for which a credit determined under section 45, 45J, 45Q, 45U, 48, 48A, or 48E is allowed under section 38 for the taxable year or any prior taxable year. Proposed §1.45Y-2(c)(2) would clarify that for purposes of proposed §1.45Y-2(c)(1), the term “allowed” only includes credits that taxpayers have claimed on a Federal income tax return or Federal return, as appropriate, and that the IRS has not challenged in terms of the taxpayer’s eligibility. Proposed §1.45Y-2(c)(3) includes several examples illustrating the rules of §1.45Y-2(c).

C. Rules of general application to section 45Y

1. Only Production in the United States Taken into Account

Proposed §1.45Y-4(a) would provide that consumption, sales, or storage of electricity are taken into account for purposes of the section 45Y credit only with respect to electricity produced within the United States (as defined in section 638(1)), or a United States territory, which for purposes of section 45Y and the section 45Y regulations has the meaning of the term “possession” of the United States (as defined in section 638(2)).

2. Production Attributable to the Taxpayer and Section 761(a) Elections

Proposed §1.45Y-4(b)(1) would provide that in the case of a qualified facility in which more than one person has an ownership share (and such arrangement is not treated as a partnership for Federal tax purposes), production from the qualified facility is allocated among such persons in proportion to their respective ownership share in the gross sales from such qualified facility during the taxable year. The respective owners each determine their respective section 45Y credit under section 45Y(a) based on their respective ownership shares in the gross sales from such qualified facility. Proposed §1.45Y-4(b)(2) would provide an example demonstrating the application of this rule.

Proposed §1.45Y-4(b)(3) would provide that if a qualified facility is owned through an unincorporated organization that has made a valid election under section 761(a) of the Code, each member’s undivided ownership share in the qualified facility will be treated as a separate qualified facility owned by such member.

3. Expansion of Facility; Incremental Production

Proposed §1.45Y-4(c)(1) would provide, solely for purposes of proposed §1.45Y-4(c), that the term “qualified facility” includes either a new unit or an addition of capacity placed in service after December 31, 2024, in connection with a facility described in section 45Y(b)(1)(A) (without regard to clause (ii) of such paragraph), which was placed in service before January 1, 2025, but only to the extent of the increased amount of electricity produced at the facility by reason of such new unit or addition of capacity. Proposed §1.45Y-4(c)(1) would also provide that a new unit or an addition of capacity will be treated as a separate qualified facility. Proposed §1.45Y-4(c)(1) would provide for purposes of proposed §1.45Y-4(c), that a new unit or an addition of capacity require the addition or replacement of components of property, including any new or replacement integral property, added to a facility necessary to increase capacity. If applicable for purposes of proposed §1.45Y-4(c), taxpayers must use modified or amended facility operating licenses or the International Standard Organization (ISO) conditions to measure the maximum electrical generating output of a facility to determine its nameplate capacity. Additionally, proposed §1.45Y-4(c)(1) would provide that for purposes of section 45Y(a)(2)(B)(i) (that is, the One-Megawatt Exception), the capacity for a new unit or an addition of capacity is the sum of the nameplate capacity of the added qualified facility and the nameplate capacity of the facility to which the qualified facility was added.

Proposed §1.45Y-4(c)(2) would provide that solely for purposes of §1.45Y-4(c), a facility that is decommissioned or in the process of decommissioning and restarts can be considered to have increased capacity if the following conditions are met: (1) the existing facility must have ceased operations; (2) the existing facility must have a shutdown period of at least one calendar year during which it is without a valid operating license from its respective Federal regulatory authority (that is, the Federal Energy Regulatory Commission (FERC) or the Nuclear Regulatory Commission (NRC)); and (3) the increased capacity of the restarted facility must have a new, reinstated, or renewed operating license issued by either FERC or NRC.

Proposed §1.45Y-4(c)(3) would describe how to compute the increased amount of electricity produced as a result of a new unit or an addition of capacity. Proposed §1.45Y-4(c)(3) would provide that to determine the increased amount of electricity produced by a facility by reason of a new unit or an addition of capacity, a taxpayer must multiply the amount of electricity that the facility produces during a taxable year after the new unit or addition of capacity is placed in service by a fraction, the numerator of which is the added nameplate capacity that results from the new unit or addition of capacity, and the denominator of which is the total nameplate capacity of the facility with the new unit or addition of capacity added.

Proposed §1.45Y-4(c)(4) would illustrate the application of these rules to determine the increased amount of electricity attributable to a new unit or an addition of capacity described in §1.45Y-4(c).

4. Retrofit of an Existing Facility (80/20 Rule)

Proposed §1.45Y-4(d)(1) would provide that for purposes of section 45Y(b)(1)(B), a facility may qualify as originally placed in service even if it contains some used components of property within the unit of qualified facility, provided the fair market value of the used components of the unit of qualified facility is not more than 20 percent of the total value of the unit of qualified facility (that is, the cost of the new components of property plus the fair market value of the used components of property within the unit of qualified facility) (80/20 Rule). Proposed §1.45Y-4(d)(1) would further provide that if a facility satisfies the requirements of the 80/20 Rule, then the date on which such qualified facility is considered originally placed in service for purposes of section 45Y(B)(1)(b) is the date on which the new components of property of the unit of qualified facility are placed in service. Proposed §1.45Y-4(d)(2) would provide that, for purposes of this 80/20 Rule, the cost of new components of the unit of qualified facility includes all costs properly included in the depreciable basis of the new components of property. Lastly, proposed §1.45Y-4(d)(3) would provide examples demonstrating the 80/20 Rule.

D. Greenhouse gas emissions rates

Section 45Y(b)(2) provides rules for determining GHG emissions rates. Proposed §1.45Y-5(a) would provide an overview of the rules pertaining to GHG emissions rates for facilities under section 45Y.

1. Definitions Related to Greenhouse Gas Emissions Rates

Proposed §1.45Y-5(b) would provide definitions of terms relevant to determining GHG emissions rates. Section 45Y(e)(1) defines the term “CO₂e per kWh” as, with respect to any greenhouse gas, the equivalent carbon dioxide (as determined based on global warming potential) per kWh of electricity produced. Proposed §1.45Y-5(b)(1) would clarify that the term “CO₂e per kWh” means with respect to any greenhouse gas, the equivalent carbon dioxide (as determined based on the 100-year time horizon global warming potential (GWP-100)) per kWh of electricity produced. Proposed §1.45Y-5(b)(1) would also provide global warming potentials for certain greenhouse gases from the Intergovernmental Panel on Climate Change’s Fifth Assessment Report (AR5).

Proposed §1.45Y-5(b)(8) would provide that the term “fuel” means material directly used to produce electricity or energy inputs that are used to produce electricity. Proposed §1.45Y-5(b)(9) would provide that the term “feedstock” means any raw material used in a process for electricity generation or to produce an intermediate product or finished fuel used for electricity generation.

Section 45Y(b)(2)(B) provides rules for determining a GHG emissions rate for a facility that produces electricity through combustion or gasification. Proposed §1.45Y-5(b)(2) would provide that the term “combustion” means a rapid exothermic chemical reaction, specifically the oxidation of a fuel, which liberates energy including heat and light. This proposed definition of “combustion” would include, for example, burning fossil fuels, but it would not include the reaction that produces electricity inside a fuel cell.

Gasification produces fuel but not electricity. Proposed §1.45Y-5(b)(3) would provide that the term “gasification” means a thermochemical process that converts carbon-containing materials into syngas, a gaseous mixture that is composed primarily of carbon monoxide, carbon dioxide, and hydrogen. Because gasification does not produce electricity, the inclusion of the term “gasification” as a category separate from “combustion” in section 45Y(b)(2)(B) would have no independent significance unless it is interpreted as applying to the production of an energy source that is ultimately used by the facility to generate electricity (for example, syngas used to make electricity). Thus, proposed §1.45Y-5(b)(4) would interpret the phrase “facility which produces electricity through combustion or gasification” in section 45Y(b)(2)(B) as applying to facilities that produce electricity through combustion or use an input energy source to produce electricity, which energy source was produced through a fundamental transformation, or multiple transformations, of one energy source into another using combustion or gasification. The Treasury Department and the IRS request comment on this proposed interpretation, including whether the application of this proposed interpretation should be clarified with respect to any type of fundamental transformation of an energy source and any related activities or operations. Comment is also requested on supply chain tracing requirements that the Treasury Department and the IRS may apply to verify whether or not a feedstock or fuel (including energy inputs) used by a facility to produce electricity was produced using combustion or gasification.

Section 45Y(b)(2)(B) provides that in the case of electricity produced through combustion or gasification, the GHG emissions rate for such facility is equal to the net rate of greenhouse gases emitted into the atmosphere by such facility (taking into account lifecycle greenhouse gas emissions, as described in section 211(o)(1)(H) of the CAA (42 U.S.C. 7545(o)(1)(H)) in the production of electricity. Proposed §1.45Y-5(b)(4) would provide that a “facility that produces electricity through combustion or gasification” (C&G Facility) means a facility that produces electricity through combustion or uses an input energy source to produce electricity, if the input energy source was produced through a fundamental transformation, or multiple transformations, of one energy source into another using combustion or gasification. Under proposed §1.45Y-5(b)(4), a facility that produces electricity using any fuel that was produced using electricity that had been produced, in whole or in part, from the combustion of fossil fuels would be considered a C&G Facility. For example, a hydrogen fuel cell would be considered a C&G Facility 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. A fuel cell facility such as a solid oxide fuel cell, which uses methane as fuel, would be considered a C&G Facility, because the methane reforming reaction that produces syngas within the fuel cell prior to the production of electricity would be considered a gasification reaction. In contrast, a hydrogen fuel cell facility using hydrogen produced exclusively using electricity from a new solar array or wind farm co-located with the hydrogen fuel cell facility would not be considered a C&G Facility, because the input energy source was not produced through a transformation of one energy source into another using combustion or gasification.

The Treasury Department and the IRS request comment on whether the proposed definitions of gasification, combustion, and C&G Facility would result in certain types of fuel cells that use fossil or biogenic fuel inputs (via combustion or gasification) to produce electricity being unable to demonstrate a net rate of greenhouse gas emissions that is not greater than zero with a lifecycle analysis because they are not classified as a C&G Facility as defined in proposed §1.45Y-5(b)(4). Because the energy transformation that produces electricity in a fuel cell would not be considered combustion under the definition in proposed §1.45Y-5(b)(2), a fuel cell facility would only qualify as a C&G Facility if the fuel it used to produce electricity was produced through combustion or gasification under these proposed regulations.

Proposed §1.45Y-5(b)(7) would provide that a “Non-C&G Facility” means a facility that produces electricity and is not described in proposed §1.45Y-5(b)(4).

Proposed §1.45Y-5(b)(5) would provide that, consistent with section 45Y(b)(2)(A), the term “greenhouse gas emissions rate” means the amount of greenhouse gases emitted into the atmosphere by a facility in the production of electricity, expressed as grams of CO₂e per kWh.

Proposed §1.45Y-5(b)(6) would provide that, for the purposes of section 45Y(b)(2)(A), for both C&G Facilities and Non-C&G Facilities, the term “greenhouse gases emitted into the atmosphere by a facility in the production of electricity” means emissions from a facility that directly occur from the process that transforms the input energy source into electricity. Proposed §1.45Y-5(b)(6)(i) through §1.45Y-5(b)(6)(vi) would exclude emissions that may relate to a facility but do not occur “in the production of electricity” as specified in section 45Y(b)(2)(A). Proposed §1.45Y-5(c)(1) would provide, for Non-C&G Facilities only, additional types of excluded emissions under section 45Y(b)(2)(A). Proposed §1.45Y-5(d)(2) would provide, for C&G Facilities only, that additional rules on included and excluded emissions apply in order to conduct a lifecycle analysis as required by section 45Y(b)(2)(B).

Proposed §1.45Y-5(b)(6)(i) through §1.45Y-5(b)(6)(vi) would clarify that for the purposes of both Non-C&G and C&G Facilities this definition excludes: 1) emissions from back-up generators that are primarily used in maintaining critical systems in case of a power system outage or for supporting restart of a generator after an outage; 2) emissions from routine operational and maintenance activities that are integral to the production of electricity, including, but not limited to, emissions from internal combustion vehicles used to access and perform maintenance on remote electricity generating facilities or emissions occurring from heating and cooling control rooms or dispatch centers; 3) emissions from a step-up transformer that conditions the electricity into a form suitable for productive use or sale; 4) emissions that occur before commercial operations commence or after commercial operations terminate, including, but not limited to, on-site emissions occurring from construction or manufacturing of the facility itself, emissions from the off-site manufacturing of facility components, or emissions occurring due to siting or decommissioning; 5) emissions from infrastructure associated with the facility, including, but not limited to, emissions from road construction for feedstock production; and 6) emissions from the distribution of electricity to consumers.

2. Greenhouse Gas Emissions Rates for Non-C&G Facilities

Proposed §1.45Y-5(c) would provide the rules for determining a GHG emissions rate for Non-C&G Facilities, including by the Secretary when publishing a table described in section 45Y(b)(2)(C)(i) or determining an emissions rate as provided in section 45Y(b)(2)(C)(ii). Proposed §1.45Y-5(c)(1) would provide that GHG emissions rates for Non-C&G Facilities must be determined under proposed §1.45Y-5(c) and (e). In addition, proposed §1.45Y-5(c)(1)(i) would provide that, with respect to Non-C&G Facilities only, greenhouse gases emitted into the atmosphere by a facility in the production of electricity excludes emissions of greenhouse gases that are not directly produced by the fundamental transformation of the input energy source into electricity, including, but not limited to, the following: 1) emissions from hydropower reservoirs due to anoxic conditions; 2) ebullitive, diffuse, and degassing emissions from hydropower operations; 3) emissions of non-condensable gases from underground reservoirs during geothermal operations; 4) emissions from a step-up transformer that conditions the electricity into a form suitable for productive use or sale; and 5) emissions occurring due to activities and operations occurring off-site, including but not limited to, the production and transportation of fuels used by the facility, or land use change from siting or changes in demand. Proposed §1.45Y-5(c)(1)(i) would thus exclude emissions that may relate to a Non-C&G Facility but do not occur “in the production of electricity” as specified in section 45Y(b)(2)(A) because such emissions do not arise directly from the transformation of the input energy source into electricity. For example, emissions from land use change from siting or changes in demand would be excluded because such emissions do not occur “in the production of electricity” for Non-C&G Facilities under section 45Y(b)(2)(A), but this exclusion does not apply to C&G Facilities because section 45Y(b)(2)(B) requires a broader standard for assessing GHG emissions than section 45Y(b)(2)(A).

Proposed §1.45Y-5(c)(1)(ii) would provide that, subject to proposed §1.45Y-5(b)(6) and (c)(1), a GHG emissions rate for a Non-C&G Facility must be determined through a technical and engineering assessment of the fundamental energy transformation into electricity, and that such assessment must consider all input and output energy carriers and chemical reactions or mechanical processes taking place at the facility in the production of electricity. Proposed §1.45Y-5(c)(1)(iii) would provide an example of a GHG emissions rate determination for a Non-C&G Facility.

Proposed §1.45Y-5(c)(2) would identify certain types or categories of facilities that are categorically Non-C&G Facilities with a GHG emissions rate that is not greater than zero. Proposed §1.45Y-5(c)(2)(i) through (viii) would provide that these include wind facilities (including small wind properties), hydropower facilities (including retrofits adding power production to non-powered dams, conduit hydropower, hydropower using new impoundments, and hydropower using diversions such as a penstock or channel), marine and hydrokinetic facilities, solar facilities (including photovoltaic and concentrating solar power), geothermal facilities (including flash and binary plants), nuclear fission facilities, nuclear fusion facilities, and waste energy recovery property (WERP) that derives energy from any of the energy sources described in proposed §1.45Y-5(c)(2)(i) through (vii) (including geothermal or solar waste heat recovery such as from a district geothermal heating system, and waste heat recovery such as from a nuclear reactor dedicated to heat production for an industrial facility).

WERP is property that generates electricity solely from heat from buildings or equipment if the primary purpose of such building or equipment is not the generation of electricity. Examples of buildings or equipment the primary purpose of which is not the generation of electricity include, but are not limited to, manufacturing plants, medical care facilities, facilities on school campuses, pipeline compressor stations, and associated equipment. The Treasury Department and the IRS request comment on whether this definition of WERP is appropriate. Comment is further requested on whether and why it would be appropriate to revise proposed §1.45Y-5(c)(2)(viii) to include additional energy sources (such as energy from exothermic chemical reactions or pressure drop technologies) that do not rely on combustion or gasification but could include equipment related to the transport of fossil fuels (for example, natural gas).

For purposes of proposed §1.45Y-5(c)(2)(ii), hydropower includes retrofits that add electricity production to non-powered dams, conduit hydropower, hydropower using new impoundments, and hydropower using diversions such as a penstock or channel. Greenhouse gas emissions are not created by the fundamental transformation of electricity needed to produce electricity in a hydropower facility. A hydropower facility converts the potential energy of flowing water into electricity. The potential energy results from changes in gravitational potential energy from the flowing water, which the hydropower facility captures with a turbine which spins a rotor within a generator to produce electricity. Hydropower facilities may release greenhouse gas emissions from the hydropower reservoir due to diffusion at the water surface or due to ebullition, and from degassing when water passes through a pump house or turbine. Such emissions from hydropower facilities would not be considered greenhouse gases emitted into the atmosphere by a Non-C&G Facility in the production of electricity under proposed §1.45Y-5(b)(6)(C), because emissions of greenhouse gasses are not created by the fundamental transformation of potential energy in flowing water into electricity, but rather from processes that are not fundamental to the transformation of potential energy into electricity.

Similarly, greenhouse gas emissions are not created by the fundamental transformation of energy from high-pressure hot water into electricity in a flash geothermal facility, which is included in proposed §1.45Y-5(c)(2)(v). A flash geothermal facility uses high-pressure hot water from deep inside the earth and converts it directly to steam that drives a turbine and generator. After the steam passes through the turbine, it is released into the atmosphere and any non-condensable gases including greenhouse gases dissolved in the steam are also released. Such emissions from flash geothermal facilities would not be considered greenhouse gases emitted into the atmosphere by a facility in the production of electricity under proposed §1.45Y-5(c)(1)(i)(C), because the greenhouse gases are already present in the underground water and are not created by the fundamental transformation of the thermal energy in the water into electricity, but rather by processes that are not fundamental to the transformation of the thermal energy into electricity. This proposed treatment of flash geothermal facilities is supported by surveys indicating that underground carbon dioxide in certain geothermal reservoirs is emitted passively into the atmosphere even in the absence of geothermal electricity generation. The Treasury Department and the IRS request comment on whether the identification of flash geothermal facilities as Non-C&G Facilities with a GHG emissions rate that is not greater than zero in proposed §1.45Y-5(c)(2)(v) is appropriate.

For purposes of proposed §1.45Y-5(c)(2)(iv), solar includes concentrated solar power. Concentrated solar power facilities may have auxiliary burners that in some cases use combustion exclusively for the purposes of cold starts or freeze protection of thermal working fluids, but in other cases, may also be used to generate electricity in hybrid configurations. The Treasury Department and the IRS request comment on whether the existing definitions of C&G Facilities and Non-C&G Facilities is sufficient to distinguish between these two categories of facilities, or whether additional clarification is needed.

3. Greenhouse Gas Emissions Rates for C&G Facilities

Section 45Y(b)(2)(B) provides that in the case of electricity produced through combustion or gasification, the GHG emissions rate for such facility is equal to the net rate of greenhouse gases emitted into the atmosphere by such facility (taking into account lifecycle greenhouse gas emissions, as described in section 211(o)(1)(H) of the CAA) in the production of electricity.

Section 211(o)(1)(H) of the CAA provides that “lifecycle greenhouse gas emissions” means the aggregate quantity of greenhouse gas emissions (including direct emissions and significant indirect emissions such as significant emissions from land use changes) related to the full fuel lifecycle, including all stages of fuel and feedstock production and distribution, from feedstock generation or extraction through the distribution and delivery and use of the finished fuel to the ultimate consumer, if the mass values for all greenhouse gases are adjusted to account for their relative global warming potential.

The EPA promulgated its interpretation of section 211(o)(1)(H) of the CAA in a 2010 notice-and-comment rulemaking establishing the regulatory framework for the updated renewable fuel standard (RFS2) program. The EPA interpreted section 211(o)(1)(H) of the CAA in the context of the facts and policy framework of the RFS program and based on information available at that time; however, the EPA’s analysis and implementation of the RFS2 rule offer relevant precedent for the Treasury Department’s and the IRS’s interpretation of section 45Y(b)(2)(B). In the RFS2 rulemaking, the EPA interpreted 211(o)(1)(H) of the CAA as requiring the agency to account for the real-world emissions consequences of increased production of biofuels. Thus, the EPA determined in the RFS2 context that the inclusion of direct emissions and significant indirect emissions such as significant emissions from land-use changes in section 211(o)(1)(H) of the CAA requires a consequential approach to considering the real-world emissions associated with biofuel production. A “consequential” approach considers the real-world greenhouse gas emissions associated with biofuel production, including secondary or indirect emissions resulting from market interactions induced by expanded biofuel production and use. Such an approach includes consideration of market interactions induced by expanded biofuel production and use that may result in secondary or indirect greenhouse gas emissions, domestically and globally.

Proposed §1.45Y-5(d) would provide the rules applicable to determining a net rate of GHG emissions for C&G Facilities, including by the Secretary when publishing a table described in section 45Y(b)(2)(C)(i) or determining an emissions rate as provided in section 45Y(b)(2)(C)(ii). Proposed §1.45Y-5(d)(1) would provide that GHG emissions rates for C&G Facilities must be determined by a lifecycle analysis (LCA) that complies with proposed §1.45Y-5(d) and (e), and that such rate equals the net rate of greenhouse gases emitted into the atmosphere by such facility (taking into account lifecycle greenhouse gas emissions, as described in section 211(o)(1)(H) of the CAA) in the production of electricity, expressed as grams of CO₂e per kWh.

Proposed §1.45Y-5(d)(2) would provide that an LCA used for determining the net rate of greenhouse gases emitted into the atmosphere by a facility must comply with the requirements provided in proposed §1.45Y-5(d)(2)(i) through (vii). Proposed §1.45Y-5(d)(2)(i) would provide that the starting boundary of the LCA for an LCA involving generation-derived feedstocks (such as biogenic feedstocks) is feedstock generation, and the starting boundary of the LCA for an LCA involving extraction-derived feedstocks (such as fossil fuel feedstocks) is feedstock extraction. Under proposed §1.45Y-5(d)(2)(i), 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. The starting conditions are the material and energy flows, including associated direct and indirect greenhouse gas emissions, of the processes associated with the extraction or production of raw feedstock materials or fuel.

Proposed §1.45Y-5(d)(2)(ii) would provide that the ending boundary of an LCA for electricity that is transmitted to the grid or electricity that is used on-site is the meter at the point of production of the C&G Facility. The distribution, transmission, and use of such electricity generated by a C&G Facility (and other types of energy sources it may displace while in use) are outside of the LCA boundary; therefore, such emissions would not be taken into account because they do not occur in the “production of electricity” as described in section 45Y(b)(2)(B). Given the particular context of section 45Y(b)(2)(B) (that is, a tax credit for the production of clean electricity), proposed §1.45Y-5(d)(2)(ii) is consistent with section 45Y(b)(2)(B) of the Code (and the term “ultimate consumer” in section 211(o)(1)(H) of the CAA referenced therein) because it would treat the C&G Facility as the ultimate consumer of the fuel used to produce electricity.

Proposed §1.45Y-5(d)(2)(iii) would provide that an LCA must be based on a future anticipated baseline, which projects future status quo in the absence of the availability of the sections 45Y and 48E credits (taking into account anticipated changes in technology, policies, practices, and environmental and other socioeconomic conditions).

Proposed §1.45Y-5(d)(2)(iv) would provide that 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 in an LCA.

Proposed §1.45Y-5(d)(2)(v) would interpret the reference to section 211(o)(1)(H) of the CAA as requiring that an LCA must take into account direct emissions, significant indirect emissions in the United States or other countries, emissions associated with market-mediated changes in related commodity markets, emissions associated with feedstock generation or extraction, emissions consequences of increased production of feedstocks, emissions at all stages of fuel and feedstock production and distribution, and emissions associated with distribution, delivery, and use of feedstocks to and by a C&G Facility. Proposed §1.45Y-5(d)(2)(v) would interpret section 45Y(b)(2)(B) of the Code (and the term “ultimate consumer” in section 211(o)(1)(H) of the CAA referenced therein) as applying to the C&G Facility because it is the ultimate consumer of the fuel used to produce electricity.

Proposed §1.45Y-5(d)(2)(v)(A) would provide that direct emissions include, but are not limited to: 1) emissions from feedstock generation, production, and extraction (including emissions from feedstock and fuel harvesting and extraction and direct land use change and management, including emissions from fertilizers, and changes in carbon stocks); 2) emissions from feedstock and fuel transport (including emissions from transporting the raw or processed feedstock to the fuel processing facility); 3) emissions from transporting and distributing fuels to the electricity production facility; 4) emissions from handling, processing, upgrading, and/or storing feedstocks, fuels and intermediate products (including emissions from on/offsite storage and preparation/pre-treatment for use (for example, torrefaction or pelletization) and emissions from process additives); and 5) emissions from combustion and gasification at the electricity generating facility (including emissions from the combustion and/or gasification process and emissions from gasification or combustion additives). Proposed §1.45Y-5(d)(2)(v)(B) would provide examples of significant indirect emissions including, but not limited to, emissions from indirect land use and land use change and other induced emissions associated with the increased use of the feedstock for electricity production. Significant indirect emissions may include positive or negative emissions. For biogenic resources, significant indirect emissions may include emissions from growth and regrowth.

Proposed §1.45Y-5(d)(2)(vi) would provide principles for excluded emissions by listing types of emissions that the LCA must not take into account.

Proposed §1.45Y-5(d)(2)(vii) would provide that an LCA may consider alternative fates and may account for avoided emissions. Alternative fate means a set of informed assumptions (for example, production processes, material outcomes, market-mediated effects) used to estimate the emissions from the use of each feedstock were it not for the feedstock’s new use due to the implementation of policy (that is, to produce electricity). Avoided emissions means the estimated emissions associated with the feedstock, including the feedstock’s production and use, that would have occurred in the alternative fate (if such feedstock had not been diverted for electricity production) but are instead avoided with the feedstock’s use for electricity production. It is important to note that, while, in some circumstances, emissions may be avoided if compared to the alternative fate, in others the new use of the material (for example, for electricity production) may involve additional emissions that were not emitted in the alternative fate estimation. Relatedly, in some circumstances, emissions may be avoided in one part of the supply chain only to occur elsewhere along the supply chain due to the new use.

4. Additional Issues Regarding Greenhouse Gas Emissions Rates for C&G Facilities

The determination of net GHG emissions rates for C&G Facilities raises a range of complex technical questions that are relevant to determining eligibility for the section 45Y and section 48E credits. The Treasury Department and the IRS request comment on the following topics: (1) the treatment of renewable natural gas (RNG) and fugitive sources of methane; (2) analytical LCA parameters, including spatial scales and time horizons; (3) whether and how to distinguish between co-products, byproducts, and waste products and how emissions should be allocated to each in LCAs; (4) how to attribute emissions to the heat produced by facilities using combined heat and power systems; (5) how to create and maintain LCA baselines; and (6) certain issues related to LCA modeling.

a. Treatment of biogas, renewable natural gas (RNG), or fugitive sources of methane

The Treasury Department and the IRS intend to provide rules addressing facilities that produce electricity using biogas, renewable natural gas (RNG), or fugitive sources of methane (for example, from coal mine operations) for purposes of the section 45Y credit or the section 48E credit, collectively referred to as the “Clean Electricity Tax Credits.” In the context of this guidance, the term “RNG” refers to biogas that has been upgraded to be equivalent in nature to fossil natural gas. Fugitive methane refers to the release of methane through, for example, equipment leaks during the extraction, processing, transformation, and delivery of fossil fuels to the point of final use, such as coal mine methane. Such rules would apply to all biogas, RNG, or fugitive methane used for the purposes of the Clean Electricity Tax Credits and would provide requirements that must be met to account for any greenhouse gas emissions benefits from biogas, RNG, or fugitive methane in determining GHG emissions rates for purposes of the Clean Electricity Tax Credits. Such requirements would be designed to reflect the ways in which additional demand for biogas, RNG or fugitive methane can impact greenhouse gas emissions outcomes.

The Treasury Department and the IRS anticipate requiring that for purposes of the Clean Electricity Tax Credits, in order for biogas, biogas-based RNG, or fugitive methane to receive an emissions value consistent with such gases (and not standard natural gas), the biogas or RNG used to produce electricity or to produce a feedstock or fuel that is used to produce electricity must originate from the first productive use of the relevant methane. For any specific source of biogas, RNG, or fugitive methane, productive use is generally defined as any valuable application of the relevant methane (including to provide heat or cooling, generate electricity, or upgraded to RNG in the case of biogas or fugitive methane), and specifically excludes venting to the atmosphere or capture and flaring. The Treasury Department and the IRS further propose to define first productive use of the relevant methane as the time when a producer of that gas first begins using or selling it for productive use in the same taxable year as (or after) the electricity production facility was placed in service. The implication of this proposal is that biogas, for example, from any source that had been productively used in a taxable year prior to the taxable year in which the relevant electricity production facility was placed in service would not include GHG emissions benefits that might otherwise be attributable to biogas-based RNG, but would instead receive a value consistent with natural gas. This proposal would limit emissions associated with the diversion of biogas, RNG, or fugitive methane from other pre-existing productive uses.

For existing biogas sources that typically productively use or sell a portion of the biogas and flare or vent the remaining excess, the flared or vented portion may be eligible for first productive use as defined above if the flaring or venting volume can be adequately demonstrated and verified. In such circumstances, the flared or vented volume may be determined based on the previous taxable year’s flared or vented volume as demonstrated via reported data to programs such as the Greenhouse Gas Reporting Program. Requirements would be established to reduce the risk that entities will deliberately generate additional biogas for purposes of the Clean Electricity Tax Credits, above historic and expected future levels or an equivalent metric, for example by generating biogas through the intentional generation of waste, and to ensure that other factors affecting the emissions rate of electricity produced with biogas, biogas-based RNG or RNG procurement via RNG certificates are taken into account. The Treasury Department and the IRS request comment on these and other potential conditions. Any fugitive sources of methane would be treated in the same fashion as biogas or RNG with respect to these requirements, albeit with different considerations in development of the counterfactual.

The Treasury Department and the IRS also recognize that different sources of methane may have significantly different characteristics (for example, counterfactuals, alternative fates, baseline characteristics, upstream leakage rates, etc.) and therefore significantly different lifecycle emissions. For this reason, the Treasury Department and the IRS are considering requiring an LCA to be conducted for electricity produced by each category of feedstock, rather than across all feedstocks used for the production of electricity by a facility. The Treasury Department and the IRS request comment on whether LCAs should be conducted on a feedstock-by-feedstock basis or averaged across feedstocks, and how to determine the appropriate categories of feedstock.

For purposes of the Clean Electricity Tax Credits, producers using biogas, RNG, or fugitive methane would be required to acquire and retire corresponding energy attribute certificates (EACs) through a book-and-claim system that can verify in an electronic tracking system that all applicable requirements are met.

Electricity producers would also be required to have a pipeline interconnection and measurement capability using a revenue grade meter. These rules would apply to the use of EACs with both direct and non-direct claims of biogas, RNG, or fugitive methane use. Direct use would involve a direct exclusive pipeline connection to a facility that generates biogas or RNG or from which fugitive methane is being sourced, while non-direct use would involve production using biogas, RNG, or fugitive methane sourced from a commercial or common-carrier natural gas or other specified pipeline. In all cases, EACs would need to document the biogas, RNG, or fugitive methane procurement use claims and that the energy attributes of the RNG or fugitive methane being used are not sold to other parties or used for compliance with other policies or programs.

The Treasury Department and the IRS request comments on these and other approaches related to biogas, RNG and fugitive methane. Regarding these sources of methane, the Treasury Department and the IRS request comment on the appropriate LCA considerations associated with them, such as counterfactual scenarios (that is, appropriate baselines), to account for direct and significant indirect emissions, and also the manner in which to assess methane from these sources if the current practice is flaring. In particular, the Treasury Department and the IRS request comments on the following questions:

(1) What data sources and peer reviewed studies provide information on fugitive methane, biogas, and RNG production systems (including biogas production and reforming systems), markets, monitoring, reporting, and verification processes, and greenhouse gas emissions associated with these production systems and markets?

(2) What conditions for the use of biogas, RNG, and fugitive methane would ensure that emissions accounting for purposes of the Clean Electricity Tax Credits reflect and reduce the risk of indirect emissions effects from electricity production using biogas and RNG? How can taxpayers verify that they have met these requirements?

(3) How broadly available and reliable are existing electronic tracking systems and verification protocols and practices for biogas, RNG, or fugitive methane certificates in book and claim systems? What developments may be required, if any, before such systems are appropriate for use with biogas or RNG certificates used to claim the Clean Electricity Tax Credits?

(4) How should biogas, RNG or fugitive methane resulting from the first productive use of methane be defined, documented, and verified? What industry best practices or alternative methods would enable such verification to be reflected in a biogas, RNG or methane certificate or other documentation? What additional information should be included in such EACs to help certify compliance?

(5) What are the emissions associated with different methods of transporting biogas, RNG or fugitive methane to electricity producers (for example, vehicular transport, pipeline)?

(6) How can the final regulations reflect and mitigate indirect emissions effects from the diversion of biogas, RNG, or fugitive methane from potential future productive uses? What other new uses of biogas, RNG, or fugitive methane could be affected in the future if more gas from new capture and productive use of methane from these sources is used in the electricity production process?

(7) How can the potential for the generation of additional emissions from the production of additional waste, waste diversion from lower-emitting disposal methods, and changes in waste management practices be limited through emissions accounting or rules for biogas and RNG use established for purposes of the Clean Electricity Tax Credits?

(8) To limit the additional production of waste, should the final regulations limit eligibility to methane sources that existed as of a certain date or waste or waste streams that were produced before a certain date, such as the date that the IRA was enacted? If so, how can that be documented or verified? How should any changes in volumes of waste and waste capacity at existing methane sources be documented and treated for purposes of the Clean Electricity Tax Credits? How should additional capture of existing waste or waste streams be documented and treated?

(9) Are geographic or temporal deliverability requirements needed to reflect and reduce the risk of indirect emissions effects from biogas, RNG, or fugitive methane use in the electricity production process? If so, what should these requirements be and are electronic tracking systems able to capture these details?

(10) How should variation in methane leakage across the existing natural gas pipeline system be taken into account in estimating the emissions from the transportation of RNG or fugitive methane or establishing rules for RNG or fugitive methane use? How should methane leakage rates be estimated based on factors such as the location where RNG or fugitive methane is injected and withdrawn, the distance between the locations where RNG or fugitive methane is injected and withdrawn, season of year, age of pipelines, or other factors? Are data or analysis available to support this?

(11) What counterfactual assumptions and data should be used to assess the net greenhouse gas emissions of facilities that rely on biogas, RNG, or fugitive methane (for example, venting, flaring, or other practice)? Is venting an appropriate counterfactual assumption in some cases? If not, what other factors should be considered?

(12) What criteria should be used in assessing biogas, fugitive methane, or RNG-based provisional emissions rates? What practices should be put in place to reduce the risk of unintended consequences (for example, gaming)? Should conservative default parameters and counterfactuals be used unless proven otherwise by a third party?

(13) What are the effects on greenhouse gas emissions of capturing methane emissions for use as biogas or RNG, such as on livestock farms?

The Treasury Department and the IRS recognize that sufficient tracking and verification mechanisms for biogas, RNG, or fugitive methane are not yet available, and existing systems have limited capabilities for tracking and verifying RNG pathways, especially in the part of the production process before the methane has been reformed to RNG. Existing tracking and verification systems do not clearly distinguish between inputs, verify or require verification of underlying practices claimed by biogas or RNG production sources, require proof of generator interconnection or revenue-quality metering, provide validation of generation methodology, include exclusively United States based-generation, verify generator registration, and track the vintage of generator interconnection. The Treasury Department and the IRS are considering providing rules to address whether or how book-and-claim systems with sufficient tracking and verification mechanisms may be used to attribute the environmental benefits of biogas, RNG, or fugitive methane in the final regulations.

The treatment of biogas, RNG, and fugitive methane presents a range of complex issues that the Treasury Department and the IRS will consider in the development of the final regulations.

b. Analytical LCA parameters, including spatial scales and time horizons

An LCA may require decisions on a wide range of analytical parameters that may have a meaningful impact on the accuracy and utility of its results. The Treasury Department and the IRS request comment on the analytical LCA parameters that are most relevant to particular types of categories of facilities that may be eligible for the Clean Electricity Tax Credits.

The Treasury Department and the IRS specifically request comment regarding spatial and temporal scales, including the factors that should be considered in setting the spatial and temporal scales for LCAs conducted for the Clean Electricity Tax Credits. Spatial scale involves defining the area over which emissions impacts will be evaluated. Temporal scale involves defining the time period over which emissions impacts will be evaluated. The decision of setting the spatial scale should be considered in conjunction with decisions on temporal scale, as the two can interact in ways that affect greenhouse gas assessment outcomes.

In conducting a greenhouse gas assessment for biomass feedstocks, for example, carbon stocks or flows that have high variability at fine spatial or temporal scales may have much less variability if averaged over larger areas or longer temporal scales. Averaging over long temporal scales may reduce the variability observed at small spatial scales, and averaging over large areas may reduce the variability observed over small temporal scales. However, it is not safe to assume that integrating over large areas and long timeframes is always preferable. Large spatial scales and long temporal scales are not necessarily the most accurate way to conduct specific policy or program assessments because the combination of the two may obscure important information (for example, biophysical differences in species or landscapes, or shorter time frames or subregional analysis needed for policy analysis) or may mask important smaller-scale impacts. It is important to note that utilizing a large spatial scale and a short temporal scale could yield the same result as a small spatial scale combined with a longer temporal scale.

The Treasury Department and the IRS acknowledge that it may be appropriate to utilize different spatial and temporals scales for different feedstocks given their heterogeneity. The Treasury Department and the IRS request comment on the following questions regarding spatial and temporal scale:

(1) What factors should be considered in establishing the timeframe for the LCA analysis? What timeframe would provide confidence that significant emissions have been accounted for?

(2) Should the LCA distinguish between an “emissions horizon” (the timeframe over which emissions effects from the feedstock use persist into the future) and an “assessment horizon” (the timeframe over which the emissions effects are included in the analysis), and how would that be reflected in the choice of temporal scale? What assessment horizon will provide reasonable confidence that significant LCA emissions have been incorporated? Should the modeled future anticipated baseline include estimated emissions from electricity production to reflect the effects of the anticipated phase out of the Clean Electricity Tax Credits?

(3) If the assessment horizon is shorter than the emissions horizon, should an estimate of the emissions beyond the assessment horizon be included in the LCA?

(4) What considerations should be reflected in the choice(s) of spatial scale? For example, the increased use of some fuels/feedstocks may have global effects (for example, changes in commodity production and ensuing land use and greenhouse gas changes), though this may not be the case for all feedstocks or fuels. What factors should be considered to assess whether a global scale is necessary for certain feedstocks to ensure that significant emissions are captured? Should all feedstock/fuels assessments be conducted with the same spatial scale to determine the extent to which increased use has estimated global ramifications?

(5) The choice of spatial scale can be greatly influenced by the availability and accuracy of data and the precision with which one can measure and model feedstock production as well as market dynamics. What sources of data would be most important to consider for modeling? What strengths or weaknesses do these sources have?

c. Distinguish between co-products, byproducts, and waste products and how emissions should be allocated to each in LCAs

The categorization and assessment of products as co-products, byproducts, or waste products in an LCA may affect the LCA’s results. Products, co-products, byproducts, and wastes may all be produced in the full fuel cycle or used as inputs to the same. A co-product is a product produced together with another product, both of which are economic drivers of the process. A byproduct is a product that is produced together with another product, and which has a productive use but is not the primary economic driver of the process from which it is produced. It is not solely or separately produced. A waste product is a substance or object that the holder intends or is required to dispose of. See ISO:14040, “Environmental management – Life cycle assessment – Principles and framework. For biogenic sources, scientific literature often classifies byproducts, wastes, and residues together in one category.

The categorization of products as co-products, byproducts, and waste products may be relevant to an LCA’s assessment of the greenhouse gas emissions related to the production of inputs to electricity generation or in the generation of electricity itself if the LCA modeling approach or approaches used for purposes of the Clean Electricity Tax Credits have the ability to distinguish between such categories. For example, in certain circumstances, the use of a waste product as a feedstock or fuel for electricity production may generate more, less, or the same greenhouse gas emissions than relevant disposal practices for that waste material. The emissions released in the production process during which a waste product is created could be fully allocated to the main product, co-products, and byproducts of that process meaning that the emissions associated with the production of the waste could be considered zero in the LCA assessment pending further analysis, potentially reducing the overall LCA GHG emissions rates for the electricity production. Alternatively, if the waste product were considered to have a productive use and therefore instead categorized as a co-product it would be considered as a driver of the production process and could have a positive emissions value. A material may initially have no economic value or useful purpose, but if that material later gains an economic value, its categorization may shift to a byproduct or co-product.

The Treasury Department and the IRS intend to clarify the principles for categorizing products as co-products, byproducts, or waste input materials and products and assessing the emissions impacts for such products in an LCA for C&G Facilities in the final regulations for the Clean Electricity Tax Credits if such categorization is relevant to the LCA model or models used. Under such principles, if byproducts are produced concurrently with electricity production, then a portion of the process emissions may be allocated to those byproducts. If applying an analytical approach that considers the consequences of the material being used for electricity production and byproducts are produced concurrent with electricity production, the LCA may consider the market impacts associated with the byproducts. In addition, if wastes are produced concurrently with electricity production, then no process emissions may be allocated to those wastes; all emissions must be associated with the electricity produced. Whether alternative productive uses of a byproduct-derived feedstock exist would be determined by expert analysis of the likely alternative uses of the byproduct, taking into account technological and economic capabilities and common practice. The alternative fate of waste-derived feedstocks would be determined by expert analysis, literature review, and historical practice.

To inform the development of these categorization principles for the final regulations, the Treasury Department and the IRS request comment on the following:

(1) What principles should be used to distinguish between co-products, byproducts, and waste products for the purposes of the Clean Electricity Tax Credits? Are there common scientific or industry definitions that can be relied upon to distinguish between co-products, byproducts, and waste products?

(2) What principles should be used to determine whether a product has sufficient value to be considered a co-product or byproduct?

(3) The Clean Electricity Tax Credits may provide additional economic incentive for the consumption of a product categorized as waste prior to the availability of the incentive provided by the Clean Electricity Tax Credits. How should this additional economic incentive be considered to determine if a product is a waste product, byproduct, or co-product? Should this categorization be reevaluated and, if so, how often?

(4) To limit the additional production of waste, should the final regulations limit eligible waste sources that existed as of a certain date, or waste or waste streams that were produced before a certain date, such as the date that the IRA was enacted? If so, how could that be documented or verified? How should any changes in volumes of waste and waste capacity at existing sources be documented and treated for purposes of the Clean Electricity Tax Credits? How should additional capture of existing waste or waste streams be documented and treated?

(5) More generally, how could the potential for the intentional generation of waste or co-products for the purposes of lowering the allocated process emissions to electricity be addressed?

(6) Would the classification of feedstocks as products, co-products, byproducts, or waste change depending on the technology? For example, would products, co-products, byproducts, and waste be described and accounted for differently if derived from biogenic sources, such as biogenic biomass?

d. Attributing emissions to the heat produced by facilities using CHP property

Section 45Y(g)(2)(A) provides that the kWh of electricity produced by a taxpayer at a qualified facility includes any production in the form of useful thermal energy by any CHP property within such facility, and the amount of greenhouse gases emitted into the atmosphere by such facility in the production of such useful thermal energy will be included for purposes of determining the GHG emissions rate for such facility. See Explanation of Provisions section I.A. for the definition of CHP property. The inclusion of thermal energy production-related emissions in an LCA for a CHP facility introduces additional considerations, such as how to set an appropriate baseline for useful energy production-related emissions and what rules should govern the attribution of emissions for thermal energy production. The Treasury Department and the IRS intend to clarify the principles for assessing the emissions related to the generation of useful thermal energy by a CHP facility in an LCA in the final regulations for the Clean Electricity Tax Credits. Accordingly, the Treasury Department and the IRS request comment on the following:

(1) To determine the amount of greenhouse gases emitted by a CHP facility, the LCA must include the greenhouse gas emissions emitted by that facility in the production of useful thermal energy. For purposes of the LCA of a CHP facility, what principles should govern how emissions from the production of useful thermal energy are calculated?

(2) What principles should be used to determine the baseline for useful thermal energy production by a CHP facility? For example, should the baseline for the heat production for a CHP facility be an alternative form of thermal energy production such as natural gas boilers, such that emissions from the production of thermal energy from the boilers would be subtracted from the facility’s emissions? Alternatively, is it more appropriate if the baseline for a CHP facility is no thermal energy production by the facility?

(3) There may be scenarios in which a facility generates electricity that is used (a) by the electricity generation facility in the production of electricity or (b) in the production of fuel ultimately consumed by that facility to generate electricity. For example, a wastewater treatment plant’s post-processing materials are digested to produce biogas; this biogas is then used in a CHP facility that produces electricity; this electricity is consumed by the wastewater treatment facility. In such scenarios, what principles should be used to determine how emissions from the consumption of electricity in the production of electricity or in the production of the fuel consumed by the facility are calculated? Similarly, there may be scenarios in which a facility self-consumes thermal energy that it produces, for example, if a facility generates steam as a byproduct that is used (a) by the facility to turn a turbine that generates electricity or (b) to clean or compress fuel ultimately consumed by that facility to generate electricity. What principles should be used be used to determine emissions from the self-consumption of thermal energy by the CHP facility?

e. Certain issues related to LCA baselines and modeling

The Treasury Department and the IRS intend to provide additional rules and principles addressing what factors must be considered to assess the emissions associated with feedstocks used by C&G Facilities to produce electricity for purposes of the Clean Electricity Tax Credits.

Such rules would apply to all feedstocks used for the purposes of the Clean Electricity Tax Credits and would provide conditions that must be met in determining GHG emissions rates for purposes of the Clean Electricity Tax Credits. The CAA explicitly defines the term “lifecycle greenhouse gas emissions” to include “the aggregate quantity of greenhouse gas emissions (including direct emissions and significant indirect emissions such as significant emissions from land use changes).” Given the highly interconnected economic, energy, and agricultural and other lands-based systems involved in electricity production, the Treasury Department and the IRS recognize that electricity production may have effects, including emissions effects, beyond the direct supply chain. The Treasury Department and the IRS think that the provision “including direct emissions and significant indirect emissions” requires any LCA for the Clean Electricity Tax Credits to adopt an approach that considers the consequential, or market-mediated, impacts of increased demand for the input feedstocks or fuels used in electricity production.

The EPA interpreted CAA 211(o)(1)(H) as requiring the agency in the RFS context to account for the real-world emissions consequences of increased production of biofuels. Thus, the EPA determined that CAA section 211(o)(1)(H)’s inclusion of “direct emissions and significant indirect emissions such as significant emissions from land-use changes” requires a “consequential” approach to considering the real-world emissions associated with biofuel production. Such an approach includes consideration of market interactions induced by expanded biofuel production and use that may result in secondary or indirect greenhouse gas emissions.

The Treasury Department and the IRS propose to use a future anticipated baseline approach for analyzing the greenhouse gas emissions associated with the production of electricity by C&G Facilities and feedstocks used by such facilities. This approach would require generating a baseline projection of the future, which reflects estimated future conditions under a business-as-usual (BAU) trajectory that incorporates key drivers and trends informed by historical data and other considerations. This baseline would then serve as the “reference” against which another scenario in which specific conditions or changes, such as implementation of the policy embodied by the Clean Electricity Tax Credits, can be projected. This construct would allow for the evaluation of the projected estimated change or difference of emissions outcomes between the two scenarios. These scenarios would include (1) the baseline scenario (that is, without the Clean Electricity Tax Credits) and (2) a policy scenario (that is, with the Clean Electricity Tax Credits).

These scenarios would require, to the extent possible, data on: (1) feedstock or fuel production systems (including fuel/feedstock generation or extraction, etc.); (2) associated greenhouse gas emissions and, if applicable, carbon pool fluxes; (3) the feedstock or fuel’s sector details; (4) feedstock or fuel demand and prices; (5) energy market projections, including electricity demand and supply and prices, if applicable; (6) future macroeconomic factors (for example, EIA Annual Energy Outlook-derived population growth, gross domestic product projections, demand functions tied to population or income); (7) technological progress assumptions, especially if applicable to stationary sources for which efficiency improvements are possible and anticipated; and (8) other parameters (for example, representation of current and anticipated, energy, environmental, or other policies including expected outcomes from other parts of the IRA or other policies, if relevant, that can inform or constrain BAU trajectories).

For example, the list that follows identifies proposed key modeling approach elements and considerations for simulation of a future anticipated baseline and policy scenarios specific to biomass-based feedstocks: (1) model function types and model dynamics (for example, economic optimization, intertemporal and/or recursive dynamic); (2) anticipated future conditions (for example, macroeconomic, biophysical, chemical); (3) greenhouse gas emissions representation, by including the different greenhouse gases and the relevant greenhouse gas emissions and sequestration sources (for example, how greenhouse gases and their effects on the environment are incorporated and represented, such as what emissions sources and factors are reflected in the model or models); (4) forest sector representation (for example, how are forestry and forest industries reflected in the model and how are they tied to the rest of the economy); (5) agricultural sector representation; (6) land use competition; (7) energy sector representation; and (8) the appropriate spatial scale (for example, international representation) for all of these considerations.

There may be different ways to model or estimate greenhouse gas emissions associated with the production of electricity by a C&G Facility. Consistent with the parameters in proposed §1.45Y-5(d), the Treasury Department and the IRS seek comment on general principles and factors to be considered to estimate net greenhouse gas emissions associated with electricity production by C&G Facilities, including the selection or creation of an assessment or modeling approach for the purposes of Clean Electricity Tax Credits. Comment is specifically requested on the following topics:

(1) What factors should be considered in deciding how to create and maintain LCA baseline scenarios?

(2) What factors should be considered in deciding how to create and maintain LCA scenarios other than the baseline?

(3) What existing model or suite of models are capable of completing an LCA consistent with the section 45Y(b)(2)(B) and proposed §1.45Y-5(d) and (e)? Please explain whether any such model or models are open source or proprietary including what type of documentation is publicly available detailing the model design, data, inputs, and assumptions, as well as whether such models are able to link with external data sources or models. Please also explain which entities own, manage, or update such models. Furthermore, because some LCA models may be used for only a certain aspect of the total required analysis (for example, a model may solely assess the agriculture sector) or only include certain feedstocks or technologies, please specify what technologies, feedstocks, or type of impacts are included or are not included in the recommended model or models. Please also explain how widely and for what purposes the recommended model or models are used, including whether the model has previously been used by a Federal or State agency or national laboratory. Please explain whether and how the model has been peer-reviewed. Finally, please explain whether the recommended model or models would need to be updated or combined with another model in order to be fully consistent with section 45Y(b)(2)(B) and proposed §1.45Y-5(d) and (e).

(4) What data sources and peer-reviewed studies provide information on different feedstock production systems that would be most important to consider for gathering data for LCA modeling? These sources and studies should provide information on the feedstock production process (ideally, beginning with the extraction or generation of the feedstock and ending at the electrical meter) and on markets related to the feedstock production process. Appropriate sources and studies should also describe the greenhouse gas emissions associated with these production systems and markets, as well as any monitoring, reporting, and verification processes used in the creation of the source or study. If recommending data sources or peer-reviewed studies, please specify whether they are open source or proprietary; their temporal and spatial scale (for example, regional versus national studies); whether they are regularly updated and with what frequency; whether they are collected by a Federal or State agency or statistical agency or national laboratory; and whether they employ direct measurements or modeling or use remote sensing data. Finally, please assess overall the strengths and weaknesses of the recommended sources or studies with respect to their usefulness as modeling data inputs.

(5) The availability of the Clean Electricity Tax Credits may create an incentive to use a given material differently than in the past (for example, a material that was not typically used for electricity production is initially used or used more broadly after the credits are available). How could an LCA or LCAs establish and account for whether the incentives created by the Clean Electricity Tax Credits have resulted in a reduction, removal of, or increase in greenhouse gas emissions beyond the emissions that would have occurred in the absence of the Clean Electricity Tax Credits? For example, consider a scenario in which, in the absence of the incentive provided by the Clean Electricity Tax Credits, an amount of woody biomass would be either left standing or laying in a forest, pile burned, or used to create timber products, such as charcoal or mulch, each an “alternative fate.” In the presence of the Clean Electricity Tax Credits, that amount of woody biomass is now being used to generate electricity. How should the possible fates of the feedstock in the absence of the Clean Electricity Tax Credits (for example, left in standing or laying in a forest, pile burned, or used to create a timber product, such as charcoal or mulch) be represented in an LCA, including the different potential direct and indirect greenhouse gas effects of those fates?

(6) How could an LCA account for alternative fates stemming from events such as potential future greenhouse gas emissions from wildfires that could be associated with woody biomass feedstocks that may be left on the landscape in the absence of the incentive created by the Clean Electricity Tax Credits? How would these considerations be affected if, in the absence of the incentive provided by the Clean Electricity Tax Credits, a feedstock is used productively but not in electricity production?

(7) Which feedstock classification categories should be established for purposes of LCA analyses, if any? To what extent should the LCA or LCAs differentiate between the sources and subtypes of a given feedstock for electricity production or not (for example, all forest-derived materials as one category, or subcategories such as logging residues)? If applied, should subcategories of feedstocks be aggregated in modeling, or should they be should they be separately modeled? How could the LCA or LCAs account for the emissions attributed to feedstocks that include a mixture of sub-types of feedstocks, such as products, coproducts, byproducts and residues? Should LCAs be standardized or provide average estimates for feedstocks and how could such standardization best be done?

(8) What factors should be considered to determine the appropriate scale(s) of feedstock demand changes or other shocks to evaluate the extent to which the production, processing, and use of the feedstocks used for electricity production results in net greenhouse gas emissions?

(9) Should the shock reflect a small incremental increase in use of the feedstock to reflect the marginal impact, or a large increase to reflect the average effect of all potential users?

(10) What could the general increment of the shock be? Should it be specified as an absolute or relative increase?

(11) What factors should be considered to determine whether shocks for different feedstocks should be implemented in isolation (separate model runs), in aggregate (for example, as an across-the-board increase in biomass usage endogenously allocated by the model across feedstocks), or something in between (for example, separately model agriculture-derived and forest-derived feedstocks, but endogenously allocate within each category)?

(12) How should variation and uncertainty be considered in evaluating model estimates of the GHG emissions associated with an increase in the use of a feedstock for electricity generation? Feedstock modeling will likely involve uncertainties and variabilities associated with data, parameterization, scenario, and model choices. For example, if the modeling reports a range of GHG emissions changes that are greater and less than zero, how should such a range of outcomes be evaluated under section 45Y(b)(2)(B)?

f. Book and claim accounting

The Treasury Department and the IRS are considering whether to allow and provide rules governing the use of book and claim accounting in the final regulations for the Clean Electricity Tax Credits. Under these proposed regulations, the methods used, and emissions associated with the production of fuels and feedstocks used in the generation of electricity are essential to determining whether a facility is a C&G Facility and assessing its GHG emissions rate. See Explanation of Provisions sections I.D.1 and I.D.3 for discussion of tracking fuel or feedstock production to determine whether a facility is a C&G Facility or Non-C&G Facility. EACs are a form of book-and-claim accounting that conveys information about the attributes associated with a unit of energy, including the fuel or feedstock used to create the energy. EACs may also include information about the location of the facility that generated the unit of energy, when that facility began operations, and when the unit of energy was produced. Because EACs can serve as a system for tracking the attributes associated with the production of a unit of energy and as a means to avoid double-counting, the Treasury Department and the IRS are considering whether to provide rules that address the use of book-and-claim systems as a means of verifying the emissions profile of a facility’s use of fuel and electricity production. The Treasury Department and the IRS request comment on whether and how it may be appropriate for such systems to be used in determining GHG emissions rates in the final regulations for the Clean Electricity Tax Credits. In particular, comment is requested regarding what types of energy inputs, including fuels and feedstocks, have or may develop sufficiently robust book-and-claim systems that may be suitable for use in substantiating and verifying claims of use of such energy inputs for purposes of the Clean Electricity Tax Credits. The Treasury Department and the IRS are considering providing rules that may permit the use of book and claim accounting in the final regulations if there are sufficient assurances that the energy attributes claimed under such system are verifiable and not susceptible to double counting.

5. Carbon Capture and Sequestration

Proposed §1.45Y-5(e) would provide that, for purposes of proposed §1.45Y-5(c) and (d), the GHG emissions rate for a Non-C&G Facility or C&G Facility must exclude any qualified carbon dioxide in such facility’s production of electricity that is captured by the taxpayer, and, pursuant to any regulations established under section 45Q(f)(2), disposed of by the taxpayer in secure geological storage, or utilized by the taxpayer in a manner described in section 45Q(f)(5) and any regulations established under such section. The Treasury Department and the IRS request comment on the following:

(1) What requirements should apply to substantiate and verify that carbon dioxide that is captured by the taxpayer is (a) disposed of by the taxpayer in secure geological storage pursuant to any regulations established under section 45Q(f)(2), disposed of by the taxpayer in secure geological storage, or (b) utilized by the taxpayer in a manner described in section 45Q(f)(5)? For example, would it be appropriate to limit the carbon dioxide that may be considered to be qualified carbon dioxide under section 45Y(e)(3), and thus excluded under section 45Y(b)(2)(D), to carbon dioxide that has been reported to the U.S. Greenhouse Gas Reporting Program (GHGRP)? If so, which GHGRP subpart or subparts should be used?

(2) In the event that carbon dioxide that was captured and sequestered as required by section 45Y(e)(3) subsequently escapes into the atmosphere after such carbon dioxide was taken into account by a taxpayer that claimed a Clean Electricity Tax Credit, what enforcement mechanisms or regulatory regimes should be used to identify when such emissions leakages have occurred? How should such emissions leakages be taken into account in determining compliance with the GHG emissions rate requirements under sections 45Y and 48E? Are the existing recapture provisions under section 45Q sufficient for this purpose?

(3) Should carbon capture and sequestration that occurs in the production of fuel that is used by a facility to produce electricity be taken into account under proposed §1.45Y-5(e) and section 45Y(e)(3)? If so, how should such use of carbon capture and sequestration (for example, emissions from CO₂ capture, purification and compression, transportation, and CO₂ site injection) be assessed in an LCA? Should emissions that occur from carbon capture and sequestration be taken into account in determining the net rate of greenhouse gases emitted into the atmosphere by a C&G Facility in the production of electricity? What verification and substantiation requirements would be appropriate to establish that carbon capture and sequestration that met the requirements of proposed §1.45Y-5(e) and section 45Y(e)(3) were met in the production of a fuel or feedstock? Are the existing recapture provisions under section 45Q sufficient for this purpose?

6. Annual Table

Proposed §1.45Y-5(f)(1) would provide that, as required by section 45Y(b)(2)(C)(i), the Secretary will annually publish a table that sets forth the GHG emissions rates for types or categories of facilities (Annual Table), which a taxpayer must use for purposes of section 45Y. Proposed §1.45Y-5(f)(1) would further provide that, except as provided in proposed §1.45Y-5(h), a taxpayer that owns a facility that is described in the Annual Table on the first day of the taxpayer’s taxable year in which the section 45Y or section 48E credit is determined with respect to such facility must use the Annual Table as of such date to determine an emissions rate for such facility for such taxable year. Types or categories of facilities must be added or removed from the Annual Table consistent with, for Non-C&G Facilities, a technical assessment of the fundamental energy transformation into electricity as provided in proposed §1.45Y-5(c)(1)(ii), and, for C&G Facilities, an LCA that complies with proposed §1.45Y-5(d) and (e). Proposed §1.45Y-5(f)(2) would also provide that in connection with the publication of the Annual Table, the Secretary must publish an accompanying expert analysis that addresses any types or categories of facilities added or removed from the Annual Table since its last publication. Such analysis must be prepared by one or more of the National Laboratories, in consultation with other agency experts, such as experts from DOE, the Treasury Department, the United States Department of Agriculture (USDA), and the EPA, as appropriate, and must address whether the addition or removal of types or categories of facilities from the Annual Table complies with section 45Y(b)(2)(A) and 45Y(b)(2)(B) (which refers to the definition of lifecycle greenhouse gas emissions in section 211(o)(1)(H) of the CAA) of the Code and proposed §1.45Y-5. The Treasury Department and the IRS view the requirement to publish an expert analysis prepared by the National Laboratories of changes to the Annual Table as essential to ensuring public accountability and adherence to sound scientific principles. This requirement would also ensure that the Secretary has a robust record to inform any changes to the Annual Table.

The Treasury Department and the IRS intend to include in the Annual Table the types or categories of facilities that are described in the final regulations as having a GHG emissions rate that is not greater than zero. The Treasury Department and the IRS intend to publish the first Annual Table after the publication of the final regulations. Until the first publication of the Annual Table, taxpayers may treat the types or categories of facilities that are listed in proposed §1.45Y-5(c)(2)(i) through (viii) as being described in an Annual Table as having a GHG emissions rate that is not greater than zero. Further, any types or categories of facilities that are added or removed from this list in the first publication of the Annual Table must be accompanied by the publication of an expert analysis of such change as provided in proposed §1.45Y-5(f)(2).

7. Provisional Emissions Rates

Proposed §1.45Y-5(g) would provide the rules applicable to provisional emissions rates. Proposed §1.45Y-5(g)(1) would provide that, in the case of any facility that is of a type or category for which an emissions rate has not been established by the Secretary under proposed §1.45Y-5(g), a taxpayer that owns such facility may file a petition with the Secretary for the determination of the emissions rate with respect to such facility (Provisional Emissions Rate or PER).

Proposed §1.45Y-5(g)(2) would provide that an emissions rate has not been established by the Secretary for a facility for purposes of section 45Y(b)(2)(C)(ii) if such facility is not described in the Annual Table. Proposed §1.45Y-5(g)(2) would further provide that if a taxpayer’s request for an emissions value pursuant to proposed §1.45Y-5(g)(5) is pending at the time such facility is or becomes described in the Annual Table, the taxpayer’s request for an emissions value will be automatically denied.

Proposed §1.45Y-5(g)(3) would provide the process for filing a PER petition. Proposed §1.45Y-5(g)(3) would provide that to file a PER petition with the Secretary, a taxpayer must submit a PER petition by attaching it to the taxpayer’s Federal income tax return or Federal return, as appropriate, for the first taxable year in which the taxpayer claims the section 45Y credit with respect to the facility to which the PER petition applies. Proposed §1.45Y-5(g)(3) would further provide that a PER petition must contain an emissions value and, if applicable, the associated DOE letter. An emissions value may be obtained from DOE or by using the LCA model designated in proposed §1.45Y-5(g)(6). An emission value obtained from DOE will be based on an analytical assessment of the emissions rate associated with the facility, performed by one or more National Laboratories, in consultation with other agency experts as appropriate, consistent with proposed §1.45Y-5. A taxpayer would be required to retain in its books and records the request to DOE for an emissions value, including any information provided by the taxpayer to DOE pursuant to the emissions value request process provided in proposed §1.45Y-5(g)(5). Alternatively, an emissions value can be determined by the taxpayer for a facility using the most recent version of an LCA model or models, as of the time the PER petition is filed, that have been designated by the Secretary for such use under proposed §1.45Y-5(g)(6). If an emissions value is determined using the designated model, a taxpayer is required to provide to the IRS information to support its determination of the emissions value in the form and manner prescribed in IRS forms or instructions or in publications or guidance published in the Internal Revenue Bulletin. A taxpayer may not request an emissions value from DOE for a facility for which an emissions value can be determined by using the most recent version of an LCA model or models that have been designated by the Secretary for such use under proposed §1.45Y-5(g)(6).

Proposed §1.45Y-5(g)(4) would provide that, upon the IRS’s acceptance of the taxpayer’s Federal income tax return or Federal return, as appropriate, containing a PER petition, the emissions value of the facility specified on such petition will be deemed accepted. Proposed §1.45Y-5(g)(4) would further provide that a taxpayer would be able to rely upon an emissions value provided by DOE for purposes of calculating and claiming a section 45Y credit, provided that any information, representations, or other data provided to DOE in support of the request for an emissions value are accurate. If applicable, a taxpayer may rely upon an emissions value determined for a facility using the most recent version of the LCA model or models that, as of the time the PER petition is filed, have been designated by the Secretary for such use under proposed §1.45Y-5(g)(6), provided that any information, representations, or other data used to obtain such emissions value are accurate. The IRS’s deemed acceptance of an emissions value is the Secretary’s determination of the PER. Finally, proposed §1.45Y-5(g)(4) would provide that the taxpayer must still comply with all applicable requirements for the section 45Y credit and any information, representations, or other data supporting an emissions value are subject to later examination by the IRS.

Proposed §1.45Y-5(g)(5) would provide the rules applicable to the emissions value request process. Proposed §1.45Y-5(g)(5) would provide that an applicant that submits a request for an emissions value must follow the procedures specified by DOE to request and obtain such emissions value, and that emissions values will be determined consistent with the rules provided in proposed §1.45Y-5. Proposed §1.45Y-5(g)(5) would further provide that an applicant may request an emissions value from DOE only after a front-end engineering and design (FEED) study or similar indication of project maturity, as determined by DOE, such as the completion of a project specification and cost estimation sufficient to inform a final investment decision for the facility. Proposed §1.45Y-5(g)(5) would provide that DOE may decline to review applications that are non-responsive and those applications that relate to a facility that is described in the Annual Table (consistent with proposed §1.45Y-5(g)(2)) or a facility that can determine an emissions value using a designated LCA model under proposed §1.45Y-5(g)(6) (consistent with proposed §1.45Y-5(g)(3)), or applications that are incomplete. Proposed §1.45Y-5(g)(5) would also provide that applicants must follow DOE’s guidance and procedures for requesting and obtaining an emissions value from DOE. DOE will publish guidance and procedures that applicants must follow to request and obtain an emissions value from DOE. DOE’s guidance and procedure will include a process, under limited circumstances, for a taxpayer to request a revision to DOE’s initial assessment of an emissions value on the basis of revised technical information or facility design and operation. The Treasury Department and the IRS anticipate that the emissions value request process will open after the publication of the final regulations.

Proposed §1.45Y-5(g)(6) would provide that the Secretary may designate one or more LCA models for a taxpayer to determine an emissions value for C&G Facilities that are not described in the Annual Table. Proposed §1.45Y-5(g)(6) would further provide that a model may only be designated if it complies with section 45Y(b)(2)(B) and proposed §1.45Y-5(d) and (e). The Secretary may revoke the designation of an LCA model or models. In connection with the designation or revocation of a designation of an LCA model or models, the Secretary would be required to publish an accompanying expert analysis of the model prepared by one or more of the National Laboratories, in consultation with other agency experts as appropriate, and such analysis must address the model’s compliance with section 45Y(b)(2)(B) of the Code and proposed §1.45Y-5(d) and (e). The Treasury Department and the IRS view the requirement to publish an expert analysis prepared by the National Laboratories of the designation or revocation of designation of an LCA model or models as essential to ensuring public accountability and adherence to sound scientific principles. This requirement would also ensure that the Secretary has a robust record to inform any designations or revocations of an LCA model or models.

Proposed §1.45Y-5(g)(7) would provide the rules governing the effect of a PER. Proposed §1.45Y-5(g)(7) would provide that a taxpayer may use a PER determined by the Secretary to determine the section 45Y credit for the facility to which the PER applies, provided all other requirements of section 45Y are met. Proposed §1.45Y-5(g)(7) would further provide that the Secretary’s PER determination is not an examination or inspection of books of account for purposes of section 7605(b) of the Code and does not preclude or impede the IRS (under section 7605(b) or any administrative provisions adopted by the IRS) from later examining a return or inspecting books or records with respect to any taxable year for which the section 45Y credit is claimed. Finally, proposed §1.45Y-5(g)(7) would provide that a PER determination does not signify that the IRS has determined that the requirements of section 45Y have been satisfied for any taxable year.

8. Reliance on Annual Table or Provisional Emissions Rate

Proposed §1.45Y-5(h) would provide that taxpayers may rely on the Annual Table in effect as of the date a facility began construction or the provisional emissions rate that has been determined by the Secretary for the taxpayer’s facility under proposed §1.45Y-5(g)(4) to determine the facility’s GHG emissions rate for that facility for any taxable year that is within the 10-year period described in section 45Y(b)(1)(B), provided that the facility continues to operate as a type of facility that is described in the Annual Table or the facility’s emissions value request, as applicable, for the entire taxable year.

9. Substantiation

Taxpayers have a general obligation to substantiate and verify that they have met the requirements of any tax credits claimed on their tax returns. Section 6001 of the Code provides that every person liable for any tax imposed by the Code, or for the collection thereof, must keep such records as the Secretary may from time to time prescribe. Section 1.6001-1(a) provides that any person subject to income tax must keep such permanent books of account or records as are sufficient to establish the amount of gross income, deductions, credits, or other matters required to be shown by such person in any return of such tax. Section 1.6001-1(e) provides that the books and records required by §1.6001-1 must be retained so long as the contents thereof may become material in the administration of any internal revenue law.

In addition to this general obligation to substantiate eligibility for a claimed tax credit, taxpayers may also be required to keep specific records as prescribed by the Secretary. This may be appropriate for purposes of the section 45Y credit because certain types of facilities may depend on operational choices, such as the use of certain types of feedstocks or fuels or engaging in carbon capture and sequestration, to achieve a net GHG emissions rate that is not greater than zero for a taxable year, and these operational choices may vary by year. Proposed §1.45Y-5(i)(1) would provide that a taxpayer must maintain in its books and records documentation regarding the design, operation, and if applicable, feedstock or fuel source used by the facility that establishes that such facility had a GHG emissions rate, as determined under §1.45Y-5, that is not greater than zero for the taxable year. The Treasury Department and the IRS intend to require in the final regulations that taxpayers maintain specific types of documentation to substantiate that a facility for which a section 45Y credit is claimed has a net GHG emissions rate that is not greater than zero. The Treasury Department and the IRS request comment on the types of documentation taxpayers should be required to maintain to substantiate eligibility for the section 45Y credit.

Proposed §1.45Y-5(i)(2) would further provide that documentation that is sufficient to substantiate that a facility had a GHG emissions rate of not greater than zero includes documentation or a report prepared by an unrelated party that verifies that a facility had such an emissions rate. Proposed §1.45Y-5(i)(2) would also provide that facilities described in §1.45Y-5(c)(2) can maintain sufficient documentation to demonstrate a GHG emissions rate showing that the facility is described in §1.45Y-5(c)(2). Finally, proposed §1.45Y-5(i)(2) would provide that future guidance may describe sufficient documentation to substantiate that certain facilities have a GHG emissions rate of not greater than zero. Because certain types or categories of facilities may have emissions rates that are highly variable and dependent on complex interactions between design choices, operational choices, and fuel and feedstock sourcing choices, the Treasury Department and the IRS seek comment on the relative risk of inadvertently crediting above-zero-emissions electricity generation for types or categories of facilities that may potentially be ineligible for the section 45Y credit. In addition, comment is also requested on supply chain tracing and substantiation requirements that the Treasury Department and the IRS may require in the final regulations to demonstrate whether a facility used a specific fuel to produce electricity and that such fuel has the emissions attributes claimed by the taxpayer. Specifically, to inform the development of the substantiation rules for the Clean Electricity Tax Credits, comment is requested on the following topics:

(1) What types of documentation or substantiation should a taxpayer maintain to establish that an input in the supply chain of a fuel/feedstock used for electricity production has the energy attributes or other relevant characteristics (for example, source and production process) that were taken into account in determining a GHG emissions rate?

(2) What existing systems, industry standards, or practices may be used to substantiate that a facility’s operations and the supply chain for the inputs it used to produce electricity resulted in a GHG emissions rate that is not greater than zero for a taxable year? If existing systems, standards, or practices are currently not sufficiently developed to serve as a form of substantiation, how should such tracking and verification systems be developed and how long might such development take?

(3) What supply chain tracing systems or verification bodies address fuels or feedstocks that may be commonly used by facilities that may be eligible for the Clean Electricity Tax Credits? What fuels or feedstocks could these systems or bodies address and for what purpose?

E. One-Megawatt Exception for section 45Y

The Treasury Department and the IRS intend to provide a more detailed definition for the One-Megawatt Exception in section 45Y(a)(2)(B)(i) by expanding upon the definition provided in the August Proposed Regulations. The final regulations would provide that, for purposes of section 45Y(a)(2)(B)(i), the determination of whether a qualified facility has a maximum net output of less than one megawatt of electricity (as measured in alternating current) is determined based on the nameplate capacity. If applicable, taxpayers must use the International Standard Organization (ISO) conditions to measure the maximum electrical generating output of a qualified facility. For purposes of this measurement, the nameplate capacity is the maximum electrical generating output in MW (as measured in alternating current) that the qualified facility is capable of producing on a steady state basis and during continuous operation under standard conditions, as measured by the manufacturer and consistent with the definition of nameplate capacity provided in 40 CFR 96.202. The Treasury Department and the IRS request comment on this proposed definition. This rule is proposed to apply to qualified facilities placed in service after December 31, 2024, and during taxable years ending on or after the date of publication of the final regulations in the Federal Register.

These proposed regulations are organized in five sections, proposed §§1.48E-1 through 1.48E-5 (section 48E regulations). Proposed §1.48E-1 would provide an overview of the section 48E regulations, generally applicable definitions, and the rules applicable to the calculation of the section 48E credit. Proposed §1.48E-2 would provide rules relating to a qualified facility, a qualified investment, a qualified property, and an energy storage technology (EST). Section 1.48E-3 is reserved for rules relating to the increased credit amount for meeting the prevailing wage and apprenticeship requirements. A cross reference will be added to §1.48E-3 in the final regulations when §1.48E-3 is finalized. Proposed §1.48E-4 would provide the rules of general application under section 48E, including the rules regarding the inclusion of qualified interconnection costs in the basis of a low-output associated qualified facility, rules for expansion of a facility and incremental production, rules for retrofitting an existing facility, rules for the ownership of a qualified facility or an EST, rules regarding the coordination of the section 48E credit with other Federal income tax credits, and rules for credit recapture. Proposed §1.48E-5 would provide rules pertaining to the determination of a GHG emissions rate for a facility under section 48E.

A. Amount of credit

Proposed §1.48E-1(a) would provide an overview of the section 48E regulations and provide definitions of terms for purposes of the section 48E regulations. Proposed §1.48E-1(b) would explain how to calculate the amount of the section 48E credit for any taxable year.

Proposed §1.48E-1(b)(1) would provide that the credit is an amount equal to the applicable percentage of the qualified investment for such taxable year with respect to any qualified facility (as defined in proposed §1.48E-2(a)) and any EST (as defined in proposed §1.48E-2(g)). Proposed §1.48E-1(b)(2) would define the applicable percentage as the base rate in proposed §1.48E-1(b)(3) or the alternative rate in proposed §1.48E-1(b)(4). Proposed §1.48E-1(b)(2) would also propose that the applicable percentage may be increased as provided in section 48E(a)(3)(A) and proposed §1.48E-1(b)(5) in the case of a qualified facility that is located in an energy community. Similarly, §1.48E-1(b)(2) would propose that the applicable percentage may be increased as provided in section 48E(a)(3)(B) and proposed §1.48E-1(b)(6) in the case of a qualified facility that satisfies the domestic content requirements.

Proposed §1.48E-1(b)(3) would describe the base rate as 6 percent. Proposed §1.48E-1(b)(4) would describe the alternative rate as 30 percent if certain prevailing wage and apprenticeship requirements are satisfied.

Proposed §1.48E-1(b)(5) would provide rules applicable to the energy communities increase in credit rate. Proposed §1.48E-1(b)(6) would provide rules applicable to the domestic content increase in credit rate.

Proposed §1.48E-1(c) would provide the credit phase-out rules. Generally, proposed §1.48E-1(c)(1) would provide that the amount of the clean electricity investment credit under section 48E for any qualified facility or EST the construction of which begins during a calendar year described in section 48E(e)(2) is equal to the product of the amount of the credit determined under section 48E(a) and proposed §1.48E-1(b) without regard to section 48E(e), multiplied by the phase-out percentage under section 48E(e)(2) and proposed §1.48E-1(c)(2). Proposed §1.48E-1(c)(2) would provide that the phase-out percentage is 100 percent for any qualified investment with respect to any qualified facility or EST the construction of which begins during the first calendar year following the applicable year; 75 percent for any qualified investment with respect to any qualified facility or EST the construction of which begins during the second calendar year following the applicable year; 50 percent for any qualified investment with respect to any qualified facility or EST the construction of which begins during the third calendar year following the applicable year; and 0 percent for any qualified investment with respect to any qualified facility or EST the construction of which begins during any calendar year subsequent to the calendar year described in section 48E(e)(2)(C). Proposed §1.48E-1(c)(3) would define “applicable year” for purposes of proposed §1.48E-1(c) as having the same meaning as provided in proposed §1.45Y-1(c)(3).

B. Qualified facility

Proposed §1.48E-2(a) would define a “qualified facility” to mean a facility that is used for the generation of electricity; is placed in service by the taxpayer after December 31, 2024; and has a GHG emissions rate of not greater than zero (as determined under rules provided in §1.45Y-5).

1. Property included in Qualified Facility

Proposed §1.48E-2(b) would provide that a qualified facility includes a unit of qualified facility (as defined in proposed §1.48E-2(b)(2)(i)) and property owned by the same taxpayer that is integral to the unit of qualified facility (as described in proposed §1.48E-2(b)(3)). Proposed §1.48E-2(b)(1) would provide that any component of property that meets the requirements of proposed §1.48E-2(b) is part of a qualified facility regardless of where such component of property is located. Proposed §1.48E-2(b)(1) would provide that a qualified facility does not include any electrical transmission equipment, such as transmission lines and towers, or any equipment beyond the electrical transmission stage. Proposed §1.48E-2(b)(1) would also provide that a qualified facility generally does not include equipment that is an addition or modification to an existing qualified facility. However, proposed §1.48E-2(b)(1) would reference proposed §1.48E-4(b) regarding the expansion of a facility or incremental production and proposed §1.48E-4(c) for rules regarding retrofitted facilities (80/20 Rule).

2. Functionally Interdependent

Proposed §1.48E-2(b)(2)(i) would provide that the unit of a qualified facility includes functionally interdependent components of a property (as defined in §1.48E-2(b)(2)(ii) owned by the taxpayer that are operated together and that can operate apart from other property to produce electricity. Proposed §1.48E-2(b)(2)(i) would further provide that no provision of this section, §1.48E-1, or §1.48E-4 through 1.48E-5 uses the term “unit” in respect of a qualified facility with any meaning other than that provided in §1.48E-2(b)(2)(ii). A reference to §1.48E-3 will also be added to the previous sentence in proposed §1.48E-2(b)(2)(i) when that regulation is finalized, but it cannot be added until §1.48E-3 is finalized. Proposed §1.48E-2(b)(2)(ii) would define components as “functionally interdependent” if the placing in service of each of the components is dependent upon the placing in service of each of the other components to produce electricity.

3. Integral Part

Proposed §1.48E-2(b)(3)(i) would provide that property owned by a taxpayer is an integral part of a qualified facility owned by the same taxpayer if it is used directly in the intended function of the qualified facility and is essential to the completeness of the intended function. Proposed §1.48E–2(b)(3)(i) would also clarify that property that is an integral part of a qualified facility is part of the qualified facility. Lastly, proposed §1.48E–2(b)(3)(i) would explain that a taxpayer may not claim the section 48E credit for any property that is an integral part of a qualified facility that is not owned by the taxpayer.

Proposed §1.48E–2(b)(3)(ii) would describe power conditioning equipment and transfer equipment as integral parts of a qualified facility. Proposed §1.48E–2(b)(3)(ii) would further provide that power conditioning equipment includes equipment that modifies the characteristics of electricity into a form suitable for use or transmission or distribution. Proposed §1.48E–2(b)(3)(ii) would also provide that parts related to the functioning or protection of power conditioning equipment are also treated as power conditioning equipment and include examples.

Proposed §1.48E–2(b)(3)(ii) would further provide that transfer equipment includes components that permit the aggregation of electricity generated by components of qualified facilities and components that alter voltage to permit transfer to a transmission or distribution line and would clarify that transfer equipment does not include transmission or distribution lines. Proposed §1.45Y–2(b)(3)(ii) would provide examples of transfer equipment that include, but are not limited to, wires, cables, and combiner boxes that conduct electricity. Proposed §1.45Y–2(b)(3)(ii) would provide that parts related to the functioning or protection of transfer equipment are also treated as transfer equipment and include examples.

Proposed §1.48E-2(b)(3)(iii) would provide that roads that are an integral part of a qualified facility are those roads integral to the intended function of the qualified facility such as onsite roads that are used to operate and maintain the qualified facility. Proposed §1.48E–2(b)(3)(iii) would also clarify that roads primarily for access to the site, or roads used primarily for employee or visitor vehicles, are not integral to the intended function of the qualified facility, and thus are not an integral part of a qualified facility.

Proposed §1.48E-2(b)(3)(iv) and (v) would provide that fences and buildings (also referred to as structures) are generally not integral parts of a qualified facility because they are not integral to the intended function of the qualified facility. However, a building (or structure) may be an integral part of a qualified facility if it is essentially an item of machinery or equipment and a structure that houses property that is integral to the intended function of the qualified facility, if the use of the structure is so closely related to the use of the housed components of property therein that the structure clearly can be expected to be replaced if the components of property it initially houses are replaced.

Proposed §1.48E-2(b)(3)(vi) would provide a rule for shared integral property stating that multiple qualified facilities (whether owned by one or more taxpayers), including qualified facilities with respect to which a taxpayer has claimed a credit under section 48E or another Federal income tax credit, may include shared property that may be considered an integral part of each qualified facility so long as the cost basis for the shared property is properly allocated to each qualified facility and the taxpayer only claims a section 48E credit with respect to the portion of the cost basis properly allocable to a facility for which the taxpayer is claiming a section 48E credit. Proposed §1.48E-2(b)(3)(vi) would further clarify that the total cost basis of such shared property divided among the qualified facilities may not exceed 100 percent of the cost of such shared property. Lastly, proposed §1.48E-2(b)(3)(vi) specifies that property that is shared by a qualified facility (as defined in section 48E(b)(3)) (48E Qualified Facility) and a qualified facility (as defined by section 45Y(b) (45Y Qualified Facility) that is an integral part of both qualified facilities will not affect the eligibility of the 48E Qualified Facility for the section 48E credit or the 45Y Qualified Facility for the section 45Y credit.

4. Coordination with Other Credits

Proposed §1.48E-2(c)(1) would provide that the term “qualified facility” (as defined in section 48E(b)(3)) will not include any facility for which a credit determined under section 45, 45J, 45Q, 45U, 45Y, 48, or 48A is allowed under section 38 for the taxable year or any prior taxable year. Proposed §1.48E-2(c)(1) would further clarify that a taxpayer that directly owns a qualified facility (as defined in section 48E(b)(3)) that is eligible for both a section 48E credit and another Federal income tax credit is eligible for the section 48E credit only if the other Federal income tax credit was not allowed with respect to the qualified facility. Proposed §1.48E-2(c)(1) would provide that nothing in proposed §1.48E-2(c) precludes a taxpayer from claiming a section 48E credit with respect to a qualified facility (as defined in section 48E(b)(3)) that is co-located with another facility for which a credit determined under section 45, 45J, 45Q, 45U, 45Y, 48, or 48A is allowed under section 38 for the taxable year or any prior taxable year.

Proposed §1.48E-2(c)(2) would clarify that for purposes of proposed §1.48E-2(c)(1), the term “allowed” only includes credits that taxpayers have claimed on a Federal income tax return or Federal return, as appropriate, and that the IRS has not challenged in terms of the taxpayer’s eligibility.

Proposed §1.48E-2(c)(3) would include several examples that illustrate the application of the rules provided in proposed §1.48E-2(c).

5. Qualified Investment with Respect to a Qualified Facility

Proposed §1.48E-2(d) would describe a qualified investment with respect to any qualified facility for any taxable year as the sum of the basis of any qualified property (as defined in proposed §1.48E-2(e)(1)) placed in service by the taxpayer during such taxable year that is part of a qualified facility (as defined in proposed §1.48E-2(a)) and the amount of any expenditures paid or incurred by the taxpayer for qualified interconnection property (as defined in proposed §1.48E-4(a)(2)).

6. Qualified Property

a. Generally

Proposed §1.48E-2(e) would define “qualified property” for purposes of proposed §1.48E-2(a) to mean property that meets three requirements. First, proposed §1.48E-2(e)(1)(i) would require that the property is tangible personal property (as defined in proposed §1.48E-2(f)(1)) or other tangible property (not including a building or its structural components) (as defined in proposed §1.48E-2(f)(2)), but only if such other tangible property is used as an integral part (as defined in proposed §1.48E-2(b)(3)) of the qualified facility (as defined in proposed §1.48E-2(a)).

Second, proposed §1.48E-2(e)(1)(ii) would require that depreciation (or amortization in lieu of depreciation) be allowable (as defined in proposed §1.48E-2(f)(6)) with respect to the property.

Third, proposed §1.48E-2(e)(1)(iii) would require that the taxpayer either constructs, reconstructs, or erects the property (as defined in proposed §1.48E-2(f)(3)) or acquires the property (as defined in proposed §1.48E-2(f)(4)) if the original use of the property (as defined in proposed §1.48E-2(f)(5)) commences with the taxpayer.

Proposed §1.48E-2(e)(2) would provide that any component of a qualified property that meets the requirements of proposed §1.48E-2(e) is part of a qualified facility regardless of where such component of property is located.

b. Definitions related to qualified property

Tangible personal property

Proposed §1.48E-2(f)(1) would define the term “tangible personal property” for purposes of section 48E and proposed §1.48E-2(b) to mean any tangible property except land and improvements thereto, such as buildings or other inherently permanent structures (including items that are structural components of such buildings or structures). Proposed §1.48E-2(f)(1) would further provide that tangible personal property includes all property (other than structural components) that is contained in or attached to a building and that all property that is in the nature of machinery (other than structural components of a building or other inherently permanent structure) is considered tangible personal property even though located outside a building. Finally, proposed §1.48E-2(f)(1) would clarify that local law is not controlling for purposes of determining whether property is or is not tangible property or tangible personal property. Therefore, proposed §1.48E-2(f)(1) would explain that tangible property may be personal property for purposes of the section 48E credit even though under local law the property is considered a fixture and therefore real property.

Other tangible property

Proposed §1.48E-2(f)(2) would define the term “other tangible property” to mean tangible property other than tangible personal property (not including a building and its structural components), that is used as an integral part of furnishing electricity by a person engaged in a trade or business of furnishing any such service.

Construction, reconstruction, or erection of qualified property

Proposed §1.48E-2(f)(3) would define the term “construction, reconstruction, or erection of qualified property” to mean work performed to construct, reconstruct, or erect qualified property either by the taxpayer or for the taxpayer in accordance with the taxpayer’s specifications.

Acquisition of qualified property

Proposed §1.48E-2(f)(4) would define the term “acquisition of qualified property” to mean a transaction by which a taxpayer obtains rights and obligations with respect to qualified property including title to the qualified property under the law of the jurisdiction in which the qualified property is placed in service, unless the qualified property is possessed or controlled by the taxpayer as a lessee, and physical possession or control of the qualified property.

Original use of qualified property

Proposed §1.48E-2(f)(5)(i) would provide that the term “original use of qualified property” means the first use to which qualified property is put, whether or not such use is by the taxpayer. Proposed §1.48E-2(f)(5)(ii) would clarify that a retrofitted qualified facility acquired by the taxpayer will not be treated as being put to original use by the taxpayer unless the rules in proposed §1.48E–4(c) regarding retrofitted qualified facilities (80/20 Rule) apply. Proposed §1.48E-2(f)(5)(ii) explains that the question of whether a qualified facility meets the 80/20 Rule is a facts and circumstances determination.

Depreciation allowable

Proposed §1.48E-2(f)(6)(i) would provide a general rule for purposes of applying proposed §1.48E-2(b), that depreciation (or amortization in lieu of depreciation) is allowable with respect to qualified property if such property is of a character subject to the allowance for depreciation under section 167 of the Code and the basis or cost of such property is recovered using a method of depreciation (for example, the straight line method), which includes any additional first year depreciation deduction method of depreciation (for example, under section 168(k) of the Code). Proposed §1.48E-2(f)(6)(i) would further clarify that if an adjustment with respect to the Federal income tax or Federal return for such taxable year requires the basis or cost of such qualified property to be recovered using a method of depreciation, depreciation is allowable to the taxpayer with respect to the qualified property. Proposed §1.48E-2(f)(6)(ii) would describe exclusions from allowable depreciation stating that for purposes of proposed §1.48E-2(b), depreciation is not allowable with respect to a qualified facility if the basis or cost of such qualified facility is not recovered through a method of depreciation but, instead, such basis or cost is recovered through a deduction of the full basis or cost of the qualified facility in one taxable year (for example, under section 179 of the Code).

Placed in service

Proposed §1.48E-2(f)(7)(i) would provide the general rule for determining when a qualified facility has been placed in service for purposes of the section 48E credit. Proposed §1.48E-2(f)(7)(ii) would provide that notwithstanding the general placed in service rules provided in proposed §1.48E-2(f)(7)(i), a qualified facility with respect to which an election is made under §1.48-4 to treat the lessee as having purchased such qualified facility is considered placed in service by the lessor in the taxable year in which possession is transferred to such lessee.

Claim

Proposed §1.48E-2(f)(8) would provide that with respect to a section 48E credit determined with respect to qualified facility of a taxpayer, the term “claim” would be defined to mean filing a completed Form 3468, Investment Credit, or any successor form(s), with the taxpayer’s timely filed (including extensions) Federal income tax return or Federal return, as appropriate, for the taxable year in which the qualified facility is placed in service, and includes making an election under section 6417 or 6418 of the Code and corresponding regulations with respect to such section 48E credit and made on the taxpayer’s filed return.

C. Energy storage technology

1. General Rule

Proposed §1.48E-2(g)(1) would provide that an EST includes a unit of EST that meets the requirements of proposed §1.48E-2(g)(2)(i). An EST also would include property owned by the taxpayer that is an integral part (as defined in proposed §1.48E-2(g)(3)) of the unit of EST. Proposed §1.48E-2(g)(1) would provide that equipment that is an addition or modification to an existing EST is not eligible for the section 48E credit. Proposed §1.48E-2(g)(1) would further provide that, an EST would include electrical energy storage property described in proposed §1.48E-2(g)(6)(i), thermal energy storage property described in proposed §1.48E-2(g)(6)(ii), and hydrogen energy storage property described in proposed §1.48E-2(g)(6)(iii).

Proposed §1.48E-2(g)(2) would provide that a unit of EST includes all functionally interdependent components of property (as defined in proposed §1.48E-2(g)(2)(ii)), owned by the taxpayer that are operated together and that can operate apart from other property to perform the intended function of the EST.

2. Functionally Interdependent

Proposed §1.48E-2(g)(2)(i) would provide that for purposes of the section 48E credit, a unit of EST includes all functionally interdependent components of property (as defined in proposed §1.48E-2(g)(2)(ii)) owned by the taxpayer that are operated together and that can operate apart from other property to perform the intended function of the EST. Proposed §1.48E-2(g)(2)(i) would also provide that no provision of this section, §1.48E-1, or §1.48E-4 through 1.48E-5 uses the term unit in respect of an EST with any meaning other than that provided in §1.48E-2(g)(2)(i). Proposed §1.48E-2(g)(2)(ii) would provide that components are functionally interdependent if the placing in service of each of the components is dependent upon the placing in service of each of the other components to perform the intended function of the EST.

3. Integral Part

Proposed §1.48E-2(g)(3) would provide that property owned by a taxpayer is an integral part of EST owned by the same taxpayer if it is used directly in the intended function of the EST and is essential to the completeness of such function. Proposed §1.48E-2(g)(3) would also provide that property that is an integral part of an EST is part of an EST. Lastly, proposed §1.48E-2(g)(3) would provide that a taxpayer may not claim the section 48E credit for any property that is an integral part of an EST that is not owned by the taxpayer.

4. Qualified Investment with Respect to Energy Storage Technology

Proposed §1.48E-2(g)(4) would describe the qualified investment with respect to any EST for any taxpayer year as the basis of any EST placed in service by the taxpayer during such taxable year.

5. Placed in Service

Proposed §1.48E-2(g)(5)(i) would provide rules for determining when an EST has been placed in service for purposes of the section 48E credit. Proposed §1.48E-2(g)(5)(ii) also would provide that notwithstanding the general placed in service rules provided in proposed §1.48E-2(g)(5)(i), an EST with respect to which an election is made under §1.48-4 to treat the lessee as having purchased such EST is considered placed in service by the lessor in the taxable year in which possession is transferred to such lessee.

6. Types of Energy Storage Technologies

Proposed §1.48E-2(g)(6)(i) would describe electrical energy storage property as property (other than property primarily used in the transportation of goods or individuals and not for the production of electricity) that receives, stores, and delivers energy for conversion to electricity and has a nameplate capacity of not less than 5 kWh. See subsection C of Overview of Section 48E. Proposed §1.48E-2(g)(6)(i) also would provide examples of such electrical energy storage property, subject to the exclusion for property primarily used in the transportation of goods or individuals.

The Treasury Department and the IRS understand that this exclusion for property primarily used in the transportation of goods or individuals, at a minimum, would apply to batteries and other EST that are incorporated into or otherwise physically integrated within motor vehicles and other modes of transportation of goods or individuals and from which an electric motor of such vehicle or other mode of transportation draws electricity for propulsion.

Proposed §1.48E-2(g)(6)(ii) would describe thermal energy storage property as property comprising a system that is directly connected to a heating, ventilation, or air conditioning (HVAC) system; removes heat from, or adds heat to, a storage medium for subsequent use; and provides energy for the heating or cooling of the interior of a residential or commercial building. See section C of Overview of Section 48E. Proposed §1.48E-2(g)(6)(ii) would also provide that thermal energy storage property includes equipment and materials, and parts related to the functioning of such equipment, to store thermal energy for later use to heat or cool, or to provide hot water for use in heating a residential or commercial building. In addition, proposed §1.48E-2(g)(6)(ii) would provide that thermal energy storage property does not include a swimming pool, CHP property, or a building or its structural components. Lastly, proposed §1.48E-2(g)(6)(ii) would provide examples of thermal energy storage property.

Proposed §1.48E-2(g)(6)(iii) would provide that hydrogen energy storage property is property (other than property primarily used in the transportation of goods or individuals and not for the production of electricity) that stores hydrogen and has a nameplate capacity of not less than 5 kWh, equivalent to 0.127 kg of hydrogen or 52.7 standard cubic feet (scf) of hydrogen. Proposed §1.48E-2(g)(6)(iii) would also provide that hydrogen energy storage property must store hydrogen that is solely used as energy and not for other purposes such as for the production of end products such as fertilizer. Proposed §1.48E-2(g)(6)(iii) would also provide examples of hydrogen energy storage property.

Although the list of examples of energy storage technologies that proposed §1.48E–2(g)(6) would provide is nonexclusive, and therefore many other technologies that are not addressed would meet these functional definitions, there are some examples that do not meet the functional definition. For example, some technologies are marketed as “virtual batteries,” which are aggregations of controllable electricity demand providing similar electrical grid services to an electrical grid battery. Such “virtual batteries” receive energy in the form of electricity, but they do not store it for later discharge as electricity. The function of “virtual batteries” is to shift demand to different points in time. Because such demand shifting is not a storage activity for purposes of section 48(c)(6) (and thus for purposes of section 48E(c)(2)), this technology is not an EST. There are other technologies for which the determination of whether they meet the statutory requirements is less clear.

7. Modification of Energy Storage Technology

Proposed §1.48E-2(g)(7) would provide rules for modification of EST. Based on the rules in section 48(c)(6)(B), proposed §1.48E-2(g)(7) would provide that with respect to electrical energy storage property and hydrogen energy storage property, modified as set forth in proposed §1.48E-2(g)(7), such property will be will be treated as an electrical energy storage property (as described in proposed §1.48E-2(g)(6)(i)) or a hydrogen energy storage property (as described in proposed §1.48E-2(g)(6)(iii)), except that the basis of any existing electrical energy storage property or hydrogen energy storage property prior to such modification is not taken into account for purposes of proposed §1.48E-2(g)(7) and section 48E.

8. Claim

Proposed §1.48E-2(g)(8) would provide that with respect to a section 48E credit determined with respect to an EST of a taxpayer, the term “claim” means filing a completed Form 3468, Investment Credit, or any successor form(s), with the taxpayer’s timely filed (including extensions) Federal income tax return or Federal return, as appropriate, for the taxable year in which the EST is placed in service, and includes making an election under section 6417 or 6418 and corresponding regulations with respect to such section 48E credit and made on the taxpayer’s filed return.

D. Rules of general application to section 48E

1. Rules for Certain Lower-Output Qualified Facilities

Proposed §1.48E-4(a)(1) would provide rules for qualified facilities with a maximum net output of not greater than 5 megawatts to include qualified interconnection costs in the basis of an associated qualified facility. Proposed §1.48E-4(a)(1) would provide that the qualified investment for a qualified facility includes amounts paid or incurred by the taxpayer for qualified interconnection property in connection with the installation of a qualified facility that has a maximum net output of not greater than 5 MW (as measured in alternating current) (Five-Megawatt Limitation). Proposed §1.48E-4(a)(1) would provide that the qualified interconnection property must provide for the transmission or distribution of the electricity produced by a qualified facility and must be properly chargeable to the capital account of the taxpayer as reduced by proposed §1.48E-4(a)(6). Proposed §1.48E-4(a)(2) would define the term “qualified interconnection property.” Proposed §1.48E-4(a)(2) would further provide that qualified interconnection property is not taken into account to determine if a qualified facility meets the requirements for the increase in credit rate for energy communities or domestic content because qualified interconnection property is not part of a qualified facility.

Proposed §1.48E-4(a)(3) would describe the Five-Megawatt Limitation as a measurement taken at the qualified facility level. Proposed §1.48E-4(a)(3)(i) would provide that the maximum net output of a qualified facility is measured only by the nameplate generating capacity of the unit of qualified facility, which does not include the nameplate capacity of any integral property, at the time that the qualified facility is placed in service. Further, proposed §1.48E-4(a)(3)(i) would also provide that the nameplate generating capacity of the unit of qualified facility is measured independently from any other qualified facilities that share the same integral property.

Proposed §1.48E-4(a)(4) would define the term “interconnection agreement.” and proposed §1.48E-4(a)(5) would define the term “utility.”

Proposed §1.48E-4(a)(6) would provide that expenses paid or incurred for qualified interconnection property and amounts otherwise chargeable to capital account with respect to such expenses must be reduced under rules similar to the rules contained in section 50(c). The taxpayer must pay or incur the interconnection property costs, and therefore, any reimbursement, including by a utility, must be accounted for by reducing the taxpayer’s expenditure to determine eligible costs.

A taxpayer that is reimbursed for these costs may not include such reimbursed costs in the amount paid or incurred by the taxpayer for qualified interconnection property. Proposed §1.48E-4(a)(6) would adopt this rule. In the case of a utility reimbursing a taxpayer for costs the taxpayer pays or incurs for qualified interconnection property, the utility should provide the taxpayer with information regarding such costs by the date on which the project is placed in service.

The Treasury Department and the IRS are aware of common situations in which a taxpayer could ultimately receive a payment, credit, or service from another entity, including a utility, related to the costs the taxpayer pays or incurs for qualified interconnection property. For example, one taxpayer may place in service a qualified facility and make payments to a utility with respect to qualified interconnection property involving the addition, modification, or upgrade to the utility’s transmission system related to such qualified facility. Subsequently, a different taxpayer may, at a later date, place in service a qualified facility and make payments to the same utility related to the same additions, modifications, or upgrades to the utility’s transmission system that were made in response to the first taxpayer’s interconnection. The utility may pay, credit, or provide services to the first taxpayer in an amount related to the costs paid by the second taxpayer. The likely amount or timing of any such payment, credit, or service would not be known at the time the first taxpayer interconnects to the utility’s transmission system.

The Treasury Department and the IRS request comment on whether such payment, credit, or service received by the first taxpayer, as the result of subsequent payments made to a utility by other parties, should be treated as a reimbursement to the first taxpayer and impact the amount of the costs of qualified interconnection property that the first taxpayer may include in its basis for purposes of the section 48E credit. The Treasury Department and the IRS also request comment on whether the costs paid by the second taxpayer should be treated as amounts paid or incurred for qualified interconnection property in connection with the installation of the second taxpayer’s qualified facility. The Treasury Department and the IRS request comment on industry practices relevant to the determination of costs paid or incurred for qualified interconnection property, including the accounting treatment of costs paid or incurred for qualified interconnection property. The Treasury Department and the IRS also request comment on whether any clarifications are needed regarding the tax treatment of amounts paid or incurred for qualified interconnection property, including reimbursement of costs paid or incurred by a taxpayer for qualified interconnection costs.

In section 3.02(1)(b)(ii) of Notice 2022-49, the Treasury Department and the IRS requested comments concerning what type of documentation, in addition to interconnection agreements and cost certification reports, is readily available for a taxpayer to demonstrate that they have paid or incurred interconnection costs in the context of the section 48 credit. Taxpayers must retain documentation in compliance with section 6001. The proposed regulations do not provide any specific type of required documentation, and any documentation that satisfies section 6001 will suffice to substantiate that a taxpayer has paid or incurred qualified interconnection costs. Commenters to Notice 2022-49 provided feedback on the documentation that taxpayers may use to substantiate costs paid or incurred for qualified interconnection property in the context of the section 48 credit. The Treasury Department and the IRS request comments on this same question in the context of the section 48E credit.

Qualified interconnection property is either constructed, reconstructed, or erected by the taxpayer, or the taxpayer pays or incurs the cost with respect to the construction, reconstruction, or erection of such property; and the original use of which, pursuant to an interconnection agreement, commences with a utility. Therefore, in some cases, taxpayers will have the necessary information and documentation on these costs. In other cases, the taxpayers will need to receive this information from the utility, which, the Treasury Department and the IRS understand, will be a common scenario. For situations in which property is constructed, reconstructed, or erected by a party other than the taxpayer, final information with conclusive details such as a true-up report with the actual costs, final invoices, proof of payment or reimbursement, and permission to operate documentation or any other final project accounting documentation should be maintained. Other examples of cost documentation records include, but are not limited to, the interconnection agreement, interconnection study, signed customer contracts, and cost certification reports.

2. Expansion of Facility; Incremental Production

Proposed §1.48E-4(b) would provide rules related to the expansion of capacity of a qualified facility by the addition of a new unit or an addition of capacity. Proposed §1.48E-4(b)(1) would provide, that solely for purposes of §1.48E-4(b), the term “qualified facility” includes either a new unit or an addition of capacity placed in service after December 31, 2024, in connection with a facility described in section 48E(b)(3)(A) (without regard to clause (ii) of such paragraph), which was placed in service before January 1, 2025, but only to the extent of the increased amount of electricity produced at the facility by reason of such new unit or addition of capacity. Proposed §1.48E-4(b)(1) further provides that a new unit or an addition of capacity that meets the requirements of proposed §1.48E-4(b) will be treated as a separate qualified facility. Proposed §1.48E-4(b) provides that a new unit or addition of capacity requires the addition or replacement of qualified property (as defined in §1.48E-2(e)), including any new or replacement integral property added to the facility necessary to increase capacity. If applicable, taxpayers must use modified or amended facility operating licenses or the International Standard Organization (ISO) conditions to measure the maximum electrical generating output of a facility to determine nameplate capacity. Additionally, §1.48E-4(b)(1) would provide that for purposes of section 48E(a)(2)()(ii)(I) (that is, the One-Megawatt Exception), the capacity for a new unit or an addition of capacity is the sum of the nameplate capacity of the added qualified facility and the nameplate capacity of the facility to which the qualified facility was added.

Proposed §1.48E-4(b)(2) would provide that solely for purposes of §1.48E-4(b), a facility that is decommissioned or in the process of decommissioning and restarts can be considered to have increased capacity if the following conditions are met: (1) the existing facility must have ceased operations; (2) the existing facility must have a period of at least one calendar year during which it is without a valid operating license from its respective Federal regulatory authority (that is, the Federal Energy Regulatory Commission (FERC) or the Nuclear Regulatory Commission (NRC)); and (3) the increased capacity of the restarted facility must have a new, reinstated, or renewed operating license issued by either FERC or NRC.

Proposed §1.48E-4(b)(3) would describe two different methods for a taxpayer to compute the qualified investment that increased the amount of electricity produced by either a new unit or an addition of capacity described in §1.48E-4(b)(1). Proposed §1.48E-4(b)(3)(i) would provide that the term “new unit” means components of property including any new or replacement integral property added to a facility necessary to increase the capacity of the facility but do not replace the existing capacity of the facility. Further, proposed §1.48E-4(b)(3)(i) would provide that the taxpayer’s qualified investment in the new unit during the taxable year that results in an increase in capacity is eligible for the section 48E credit.

Proposed §1.48E-4(b)(3)(ii) would address the application of the rule to an addition of capacity by providing that the term “addition of capacity” means components of property, including any new or replacement integral property added to a facility necessary to increase the capacity of the facility by replacing, in whole or in part, the existing capacity of the facility. Proposed §1.48E-4(b)(3)(ii) would provide that to determine a taxpayer’s qualified investment during the taxable year that resulted in an increased capacity of a facility by reason of an addition of capacity not described in proposed §1.48E-4(b)(3)(i), a taxpayer must multiply its total qualified investment during the taxable year with respect to the facility, by a fraction, the numerator of which is the increase in nameplate capacity that results from the addition of capacity, and the denominator of which is the total nameplate capacity associated with the components of property that result in the addition of capacity.

Proposed §1.48E-4(b)(4) would provide examples to illustrate the application of both methods to determine the increased amount of electricity attributable to a new unit or an addition of capacity described in §1.48E-4(b)(1).

3. Retrofit of an Existing Facility (80/20 Rule)

Proposed §1.48E-4(c) would provide rules related to the retrofit of an existing qualified facility. Proposed §1.48E-4(c)(1) would provide that for purposes of section 48E(b)(3)(A)(ii), a facility may qualify as originally placed in service even if it contains some used components of property within the unit of qualified facility, provided that the fair market value of the used components of the unit of qualified facility is not more than 20 percent of the unit of qualified facility’s total value (that is, the cost of the new components of property plus the value of the used components of property within the unit of qualified facility) (80/20 Rule).

Proposed §1.48E-4(c)(2) would provide that only expenditures paid or incurred that related to the new components of the unit of qualified facility are taken into account for computing the section 48E credit with respect to the unit of qualified facility.

Proposed §1.48E-4(c)(3) would provide that the cost of new components of the unit of qualified facility includes all costs properly included in the depreciable basis of the new components.

Proposed §1.48E-4(c)(4) would provide that if the taxpayer satisfies the 80/20 Rule with regard to a unit of qualified facility, and the taxpayer incurs new costs for property that is an integral part of the qualified facility, the taxpayer may include these new costs paid or incurred for property that is an integral part of the qualified facility in the basis of the qualified facility for purposes of calculating the section 48E credit.

Proposed §1.48E-4(c)(5) would provide that costs incurred for new components of property added to used components of a unit of qualified facility may not be taken into account for purposes of the section 48E credit unless the taxpayer satisfies the 80/20 Rule. Proposed §1.48E-4(c)(6) would provide examples.

4. Special Rules Regarding Ownership

Proposed §1.48E-4(d) would provide rules related to the ownership of a qualified facility or EST. Proposed §1.48E-4(d)(1) would provide that a taxpayer that owns a qualified investment with respect to a qualified facility or EST is eligible for the section 48E credit only to the extent of the taxpayer’s eligible investment in the qualified facility or EST. In the case of multiple taxpayers holding direct ownership through their qualified investments in a single qualified facility or EST, each taxpayer determines its eligible investment based on the taxpayer’s fractional ownership interest in the qualified facility or EST.

Proposed §1.48E-4(d)(2) would provide that a taxpayer must directly own at least a fractional interest in the entire unit of qualified facility (as defined in §1.48E-2(b)(2) or unit of EST (as defined in §1.48E-2(g)(2)) for a section 48E credit to be determined with respect to such taxpayer’s interest. Proposed §1.48E-4(d)(2) also provides that no section 48E credit may be determined with respect to a taxpayer’s ownership of one or more separate components of a qualified facility or EST if the components do not constitute a unit of qualified facility (as defined in proposed §1.48E-2(b)(2)) or unit of EST (as defined in proposed §1.48E-2(g)(2)). However, proposed §1.48E-4(d)(2) provides that the use of the components of property owned by one taxpayer that is an integral part of a qualified facility or EST owned by another taxpayer will not prevent a section 48E credit from being determined with respect to the second taxpayer’s qualified investment in a qualified facility or EST.

Proposed §1.48E-4(d)(3) would provide that if a qualified facility or EST is owned through an unincorporated organization that has made a valid election under section 761(a), each member’s undivided ownership share in the facility or EST will be treated as a separate qualified facility or EST owned by such member.

Proposed §1.48E-4(d)(4)(i) would define the term “related taxpayers” and proposed §1.48E-4(d)(4)(ii) would provide a related taxpayer rule, that related taxpayers are treated as one taxpayer in determining whether a taxpayer has made an investment in a qualified facility or EST with respect to which a section 48E credit may be determined. Proposed §1.48E-4(d)(5) would provide examples illustrating these ownership rules.

5. Coordination Rule for Section 42 and 48E Credits

Proposed §1.48E-4(e) would provide that as provided under section 50(c)(3)(C), in the case of a taxpayer determining eligible basis for purposes of calculating a credit under section 42 of the Code (section 42 credit), a taxpayer is not required to reduce its basis in a qualified facility or EST by the amount of the section 48E credit determined with respect to the qualified investment with respect to such qualified facility or EST. Further, proposed §1.48E-4(e) would provide that the qualified investment with respect to a qualified facility or EST may be used to determine a section 48E credit and may also be included in eligible basis to determine a section 42 credit.

6. Credit Recapture

Proposed §1.48E-4(f)(1) would provide recapture rules for the section 48E credit that incorporate the recapture provisions of section 50(a). Proposed §1.48E-4(f)(1) would further provide that the credit calculated under proposed §1.48E-1(b) is subject to recapture for any qualified facility that has a GHG emissions rate (as determined under proposed §1.48E-5) that exceeds 10 grams of CO₂e per kWh during the five-year period beginning on the date such qualified facility is originally placed in service (five-year recapture period).

Recapture Event

Proposed §1.48E-4(f)(2)(i) would provide that any failure of the qualified facility to not exceed a GHG emissions rate of 10 grams per CO₂e per kWh during the five-year recapture period is a recapture event. If a qualified facility’s GHG emissions rate exceeds 10 grams of CO₂e per kWh averaged over the taxable year, the section 48E credit is subject to recapture. Proposed §1.48E-4(f)(2)(ii) would provide that a change to the GHG emissions rate for a type or category of facility that is published in the Annual Table (as defined in proposed §1.45Y-5(f)) after the facility is placed in service does not result in a recapture event.

Proposed §1.48E-4(f)(2)(iii) would provide that a determination of whether a recapture event has occurred must be made for each taxable year (or portion thereof) occurring within the five-year recapture period, beginning with the taxable year ending after the date the qualified facility is placed in service. For each taxable year that begins or ends within the five-year recapture period, the taxpayer must determine, for any qualified facility for which it has claimed the section 48E credit, whether such facility has maintained a GHG emissions rate of not greater than 10 grams of CO₂e per kWh. A taxpayer that has claimed the section 48E credit amount under proposed §1.48E-1 or transferred a specified credit portion under section 6418 of the Code is required to provide to the IRS information on the GHG emissions rate of the qualified facility during the recapture period at the time and in the form and manner prescribed in IRS forms or instructions or in publications or guidance published in the Internal Revenue Bulletin.

Proposed §1.48E-4(f)(2)(iv) would provide that in the case of any recapture event, the carrybacks and carryforwards under section 39 must be adjusted by reason of such recapture event.

Proposed §1.48E-4(f)(3)(i) would provide that if a recapture event has occurred, the tax under chapter 1 of the Code for the taxable year in which the recapture event occurs is increased by an amount equal to the applicable recapture percentage multiplied by the credit amount that was claimed by the taxpayer under proposed §1.48E-1. Proposed §1.48E-4(f)(3)(ii) provides the applicable recapture percentage for each year during the five-year recapture period.

Proposed §1.48E-4(f)(4) would provide that the five-year recapture period begins on the date the qualified facility is placed in service and ends on the date that is five full years after the placed-in-service date. Each 365-day period (366-day period in the case of a leap year) within the five-year recapture period is a separate recapture year for recapture purposes.

Proposed §1.48E-4(f)(5) would provide that the increased tax under chapter 1 of the Code for the recapture of the credit amount under proposed §1.48E-1 occurs in the year of the recapture event.

E. Greenhouse gas emissions rates

Section 48E(b)(3)(B)(ii) provides that rules similar to the rules of section 45Y(b)(2) regarding greenhouse emissions rates apply for purposes of section 48E. Proposed §1.48E-5(a) would provide an overview of the rules pertaining to GHG emissions rates for qualified facilities under section 48E. Proposed §1.48E-5(b) through (f) would clarify that the definitions of certain terms, rules for determining GHG emissions rates for Non-C&G Facilities, the rules for determining net GHG emissions rates for C&G Facilities, rules regarding carbon capture and sequestration, and requirement to publish the Annual Table provided in proposed §1.45Y-5(b) through (f) also apply for purposes of section 48E and this section.

Proposed §1.48E-5(g) would provide the rules applicable to provisional emissions rates. Proposed §1.48E-5(g)(1) would provide that, in the case of any facility for which an emissions rate has not been established by the Secretary, a taxpayer that owns such facility may file a petition with the Secretary for determination of the emissions rate with respect to such facility (Provisional Emissions Rate or PER).

Proposed §1.48E-5(g)(2) would provide that an emissions rate has not been established by the Secretary for a facility if such facility is not described in the Annual Table. Proposed §1.48E-5(g)(2) would further provide that if a taxpayer’s request for an emissions value pursuant to proposed §1.48E-5(g)(5) is pending at the time such facility is or becomes described in the Annual Table, the taxpayer’s request for an emissions value would be automatically denied.

Proposed §1.48E-5(g)(3) would provide the process for filing a PER petition. Proposed §1.48E-5(g)(3) would provide that to file a PER petition with the Secretary, a taxpayer must submit a PER petition attached to the taxpayer’s Federal income tax return or Federal return, as appropriate, for the taxable year in which the taxpayer claims the section 48E credit with respect to the facility. Proposed §1.48E-5(g)(3) would further provide that a PER petition must contain an emissions value and, if applicable, include as an attachment the DOE letter. An emissions value obtained from DOE will be based on an analytical assessment of the emissions rate associated with the facility performed by one or more of the National Laboratories, in consultation with other agency experts as appropriate, consistent with proposed §1.48E-5. A taxpayer would be required to retain its books and records a copy of the taxpayer’s request to DOE for an emissions value, including any information provided by the taxpayer to DOE pursuant to the emissions value request process provided in proposed §1.48E-5(g)(5). Alternatively, an emissions value can be determined for a facility by using the most recent version of an LCA model, as of the time the PER petition is filed, that has been designated by the Secretary for such use under paragraph (g)(6) of this section. If an emissions value is determined using a designated LCA model or models, the taxpayer would be required to provide to the IRS information to support its use of the model or models in the form and manner prescribed in IRS forms or instructions or in publications or guidance published in the Internal Revenue Bulletin. A taxpayer may not request an emissions value from DOE for a facility for which an emissions value can be determined by using the most recent version of an LCA model or models that have been designated by the Secretary for such use under proposed §1.48E-5(g)(6).

Proposed §1.48E-5(g)(4) would provide that, upon the IRS’s acceptance of the taxpayer’s Federal income tax return or Federal return, as appropriate, containing a PER petition, the emissions value of the facility specified on such petition will be deemed accepted. Proposed §1.48E-5(g)(4) would further provide that a taxpayer would be able to rely upon an emissions value provided by DOE for purposes of claiming a section 48E credit, provided that any information, representations, or other data provided to DOE in support of the request for an emissions value are accurate. If applicable, a taxpayer may rely upon an emissions value determined for a facility using an LCA model or models that have been designated by the Secretary for such use under proposed §1.48E-5(g)(6), provided that any information, representations, or other data used to obtain such emissions value are accurate. The IRS’s deemed acceptance of an emissions value would be the Secretary’s determination of the PER. Finally, proposed §1.48E-5(g)(4) would provide that the taxpayer must also comply with all applicable requirements for the section 48E credit, and any information, representations, or other data provided to DOE in support of the request for an emissions value would be subject to later examination by the IRS.

Proposed §1.48E-5(g)(5) would provide the rules applicable to the emissions value request process. Proposed §1.48E-5(g)(5) would provide that an applicant that submits a request for an emissions value must follow the procedures specified by DOE to request and obtain such emissions value, and that emissions values will be determined consistent with the rules provided in proposed §1.48E-5. Proposed §1.48E-5(g)(5) would further provide that an applicant may request an emissions value from DOE only after a front-end engineering and design (FEED) study or similar indication of project maturity, as determined by DOE, such as the completion of a project specification and cost estimation sufficient to inform a final investment decision for the facility. Proposed §1.48E-5(g)(5) would provide that DOE may decline to review applications that are non-responsive, and those applications that relate to a facility that is described in the Annual Table (consistent with proposed §1.48E-5(g)(2)) or a facility that can determine an emissions value using a designated LCA model under proposed §1.48E-5(g)(6) (consistent with proposed §1.48E-5(g)(3)), or applications that are incomplete. Proposed §1.45Y-5(g)(5) would also provide that applicants must follow DOE’s guidance and procedures for requesting and obtaining an emissions value from DOE. DOE will publish guidance and procedures that applicants must follow to request and obtain an emissions value from DOE. DOE’s guidance and procedures will include a process that, under limited circumstances, a taxpayer may request a revision to DOE’s initial assessment of an emissions value on the basis of revised technical information or facility design and operation. The Treasury Department and the IRS anticipate that the emissions value request process will open after the publication of the final regulations.

Proposed §1.48E-5(g)(6) would provide that the rules provided in proposed §1.45Y-5(g)(6) regarding the designation of an LCA model or models for determining an emissions value for C&G Facilities apply for purposes of section 48E and this section.

Proposed §1.48E-5(g)(7) would provide rules governing the effect of a PER. Proposed §1.48E-5(g)(7) would provide that a taxpayer may use a PER determined by the Secretary to determine the eligibility for the section 48E credit for a taxable year for the facility to which the PER relates, provided all other requirements of section 48E are met, unless the emissions rate for such type or category of facility is provided in the Annual Table for any portion of the taxable year. Proposed §1.48E-5(g)(7) would further provide that the Secretary’s PER determination is not an examination or inspection of books of account for purposes of section 7605(b) of the Code and does not preclude or impede the IRS (under section 7605(b) or any administrative provisions adopted by the IRS) from later examining a return or inspecting books or records with respect to any taxable year for which the section 48E credit is claimed. Finally, proposed §1.48E-5(g)(7) would provide that a PER determination does not signify that the IRS has determined that the requirements of section 48E have been satisfied for any taxable year.

Proposed §1.48E-5(h) would provide the rules applicable to determining an anticipated GHG emissions rate. Proposed §1.48E-5(h)(1) would provide that a facility’s anticipated GHG emissions rate must be objectively determined based on an examination of all the facts and circumstances. Proposed §1.48E-5(h)(1) would further provide that certain Non-C&G Facilities, such as the facilities described in proposed §1.45Y-5(c)(2), may have an anticipated GHG emissions rate that is not greater than zero based on the technology and practices they rely upon to generate electricity. Finally, proposed §1.48E-5(h)(1) would provide that for facilities that require the use of certain feedstocks or carbon capture and sequestration, which may vary, to generate electricity with a GHG emissions rate that is not greater than zero, objective indicia that such facilities will operate with a GHG emissions rate that is not greater than zero for at least 10 years beginning from the date the facility is placed in service are required to establish that its anticipated GHG emissions rate is not greater than zero.

Proposed §1.48E-5(h)(2) would provide a non-exhaustive list of examples of objective indicia that may establish an anticipated GHG emissions rate that is not greater than zero. Proposed §1.48E-5(h)(2)(i) through (iv) would provide that these examples include co-location of the facility with a fuel source for which the combination of fuel, type of facility, and practice is reasonably expected to result in a GHG emissions rate that is not greater than zero; a 10-year contract to purchase fuels for which the combination of fuel, type of facility, and practice is reasonably expected to result in a GHG emissions rate that is not greater than zero; a facility type that only accommodates one type of fuel or a small range of fuels for which the combination of fuel, type of facility, and practice is reasonably expected to result in a GHG emissions rate that is not greater than zero; or a 10-year contract for the capture, disposal, or utilization of qualified carbon dioxide from the facility for which the combination of fuel, type of facility, and practice is reasonably expected to result in a GHG emissions rate that is not greater than zero.

The Treasury Department and the IRS interpret the reference in section 48E(b)(3)(A)(iii) to an “anticipated greenhouse gas emissions rate” that is not greater than zero to require a reasonable expectation that a facility will operate with a rate or net rate of greenhouse gas emissions that is not greater than zero over a specified period of time (for example, the anticipated lifetime of the facility). The Treasury Department and the IRS request comment on what evidence or substantiation taxpayers should be required to maintain to establish an anticipated GHG emissions rate for a facility. In addition, comment is requested on the appropriate period of time for which taxpayers should be required to demonstrate that there is a reasonable expectation that a facility will operate with a GHG emissions rate that is not greater than zero.

Proposed §1.48E-5(i) would provide that taxpayers may rely on the Annual Table in effect as of the date a facility began construction or the provisional emissions rate determined by the Secretary for the taxpayer’s facility to determine the facility’s GHG emissions rate, provided that the facility continues to operate as a type of facility that is described in the Annual Table or the facility’s emissions value request, as applicable, for the entire taxable year.

Proposed §1.48E-5(j)(1) would provide that a taxpayer must maintain in its books and records documentation regarding the design and operation of a facility that establishes that such facility had an anticipated GHG emissions rate that is not greater than zero in the year in which the section 48E credit is determined and operated with a GHG emissions rate that is not greater than 10 grams of CO₂e per kWh during each year of the recapture period that applies for purposes of section 48E(g).

Proposed §1.48E-5(j)(2) would further provide that documentation sufficient to substantiate that a facility had a GHG emissions rate that is not greater than 10 grams of CO₂e per kWh during each year of the recapture period includes documentation or a report prepared by an unrelated party that verifies the facility’s actual emissions rate. Proposed §1.48E-5(j)(2) would also provide that facilities described in §1.45Y-5(c)(2) can maintain sufficient documentation to demonstrate a GHG emissions rate that is not greater than 10 grams of CO₂e per kWh during each year of the recapture period by showing that the facility is described in §1.45Y-5(c)(2). Finally, proposed §1.48E-5(j)(2) would provide that future guidance may describe sufficient documentation to substantiate that certain other types of facilities have a GHG emissions rate that is not greater than 10 grams of CO₂e per kWh during each year of the recapture period.

Pursuant to the Memorandum of Agreement, Review of Treasury Regulations under Executive Order 12866 (June 9, 2023), tax regulatory actions issued by the IRS are not subject to the requirements of section 6 of Executive Order 12866, as amended. Therefore, a regulatory impact assessment is not required.

The Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520) (PRA) generally requires that a Federal agency obtain the approval of the Office of Management and Budget (OMB) before collecting information from the public, whether such collection of information is mandatory, voluntary, or required to obtain or retain a benefit.

The collections of information in these proposed regulations contain recordkeeping and reporting requirements that are required to substantiate eligibility to claim a section 45Y or section 48E credit. These collections of information would generally be used by the IRS for tax compliance purposes and by taxpayers to facilitate proper reporting and compliance. The general recordkeeping requirements mentioned within these proposed regulations are considered general tax records under §1.6001-1(e).

The recordkeeping requirements in these proposed regulations with respect to section 45Y would include the requirement in proposed §1.45Y-5(i)(1) that taxpayers claiming the section 45Y credit must maintain in its books and records documentation regarding the design and operation of a facility that establishes that such facility had a GHG emissions rate that is not greater than zero for the taxable year. Included in proposed §1.45Y-5(i)(2) are examples of documentation that sufficiently substantiates that a facility has a GHG emissions rate that is not greater than zero for the taxable year, which includes documentation, or a report prepared by an unrelated party that verifies that a facility had such an emissions rate. A facility described in proposed §1.45Y-5(c)(2) can maintain sufficient documentation to demonstrate a GHG emissions rate that is not greater than zero for the taxable year by showing that it is a type of facility described in proposed §1.45Y-5(c)(2). Proposed §1.45Y-5(i)(2) would provide that Secretary may determine that other types of facilities can sufficiently substantiate a GHG emissions rate, as determined under this section, that is not greater than zero with certain documentation and will describe such facilities and documentation in IRS forms or instructions or in publications or guidance published in the Internal Revenue Bulletin. For PRA purposes, these general tax records are already approved by OMB under 1545–0074 for individuals, 1545–0123 for business entities, 1545–0092 for trust and estate filers, and 1545–0047 for tax-exempt organizations.

The recordkeeping requirements in these proposed regulations with respect to section 48E would include the requirement in proposed §1.48E-5(i)(1) that a taxpayer must maintain in its books and records documentation regarding the design and operation of a facility that establishes that such facility had an anticipated GHG emissions rate that is not greater than 10 grams of CO₂e per kWh during each year of the recapture period that applies for purposes of section 48E(g). Included in proposed §1.48E-5(i)(2) are examples of documentation that sufficiently substantiates that a facility has a GHG emissions rate that is not greater 10 grams of CO₂e per kWh during each year of the recapture period, which includes documentation, or a report prepared by an unrelated party that verifies that a facility had such an emissions rate. A facility described in proposed §1.45Y-5(c)(2) can maintain sufficient documentation to demonstrate a GHG emissions rate that is not greater than 10 grams of CO₂e per kWh by showing that it is a type of facility described in proposed §1.45Y-5(c)(2). The Secretary may determine that other types of facilities can sufficiently substantiate a GHG emissions rate that is not greater than 10 grams of CO₂e per kWh with certain documentation and will describe such facilities and documentation in IRS forms or instructions or in publications or guidance published in the Internal Revenue Bulletin. For PRA purposes, these general tax records are already approved by OMB under 1545–0074 for individuals, 1545–0123 for business entities, 1545–0092 for trust and estate filers, and 1545–0047 for tax-exempt organizations.

The reporting requirements in these proposed regulations are in proposed §§ 1.45Y–5 and 1.48E-5, which provide the process for applicants to file a petition with the Secretary for a PER determination. To file a PER petition with the Secretary, a taxpayer must submit the PER petition attached to the taxpayer’s Federal income tax return or Federal return, as appropriate, for the taxable year in which the taxpayer claims the section 45Y credit or the section 48E credit with respect to the facility to which the PER petition relates. A PER petition must contain an emissions value. If the applicant obtained an emissions value from DOE, the PER petition made to the IRS must include and emissions value letter from DOE. This emission value letter process will be approved by OMB under the DOE Control Number 1910-####. A taxpayer must retain in its books and records a copy of the taxpayer’s request to DOE for an emissions value, including the supporting documentation provided to DOE with the request. Alternatively, if applicable, a PER petition may contain an emissions value determined for a facility using the most recent version of an LCA model, as of the time the PER petition is filed, that has been designated by the Secretary for such use. If an emissions value is determined using a designated model, a taxpayer is required to provide to the IRS information to support its determination of the emissions value in the form and manner prescribed in IRS forms or instructions or in publications or guidance published in the Internal Revenue Bulletin. The burden for these requirements will be included within the forms and instructions applicable to sections 45Y and 48E. For section 45Y, the burden for these requirements will be associated the form and instructions applicable to claiming this credit and will be approved by OMB, in accordance with 5 CFR 1320.10, under the following OMB control numbers: 1545–0074 for individuals/sole proprietors, 1545–0123 for business entities, 1545–0047 for tax-exempt organizations, and 1545–0092 for trust and estate filers. For section 48E, the burden for these requirements will be associated with Form 3468, Investment Credit, and will be approved by OMB, in accordance with 5 CFR 1320.10, under the following OMB control numbers: 1545–0074 for individuals/sole proprietors, 1545–0123 for business entities, 1545–0047 for tax-exempt organizations, and 1545–0092 for trust and estate filers.

The Regulatory Flexibility Act (5 U.S.C. 601 et seq.) (RFA) imposes certain requirements with respect to Federal rules that are subject to the notice and comment requirements of section 553(b) of the Administrative Procedure Act (5 U.S.C. 551 et seq.) and that are likely to have a significant economic impact on a substantial number of small entities. Unless an agency determines that a proposal is not likely to have a significant economic impact on a substantial number of small entities, section 603 of the RFA requires the agency to present an initial regulatory flexibility analysis (IRFA) of the proposed rule. The Treasury Department and the IRS have not determined whether the proposed rule, when finalized, will likely have a significant economic impact on a substantial number of small entities. This determination requires further study. However, because there is a possibility of significant economic impact on a substantial number of small entities, an IRFA is provided in these proposed regulations. The Treasury Department and the IRS invite comments on both the number of entities affected and the economic impact on small entities.

Pursuant to section 7805(f) of the Code, this notice of proposed rulemaking has been submitted to the Chief Counsel of the Office of Advocacy of the Small Business Administration for comment on its impact on small business.

A. Need for and objectives of the rule

The proposed regulations would provide greater clarity to taxpayers for purposes of claiming the section 45Y credit or the section 48E credit. The proposed regulations would provide necessary definitions and rules regarding the determination of credit amounts and the procedure for requesting a provisional emissions rate. The proposed regulations will provide greater clarity to taxpayers for purposes of claiming the section 45Y credit and the section 48E credit and encourage taxpayers to produce clean energy or invest in clean energy facilities and energy storage technologies. Thus, the Treasury Department and the IRS intend and expect that the proposed rules will deliver benefits across the economy that will beneficially impact various industries.

B. Affected small entities

The RFA directs agencies to provide a description of, and if feasible, an estimate of, the number of small entities that may be affected by the proposed rules, if adopted. The Small Business Administration’s Office of Advocacy estimates in its 2023 Frequently Asked Questions that 99.9 percent of American businesses meet its definition of a small business. The applicability of these proposed regulations does not depend on the size of the business, as defined by the Small Business Administration.

As described more fully in the preamble to this proposed regulation and in this IRFA, the section 45Y credit and the section 48E credit incentivize the production of clean energy and the investment in clean energy facilities and energy storage technologies. Because the potential credit claimants can vary widely, it is difficult to estimate at this time the impact of these proposed regulations, if any, on small businesses.

The Treasury Department and the IRS expect to receive more information on the impact on small businesses through comments on these proposed rules and again once taxpayers start to claim the section 45Y credit or the section 48E credit using the guidance and procedures provided in these proposed regulations.

C. Impact of the rules

The proposed regulations will allow taxpayers to plan investments and transactions based on the ability to claim the section 45Y production credit and/or the section 48E investment credit. The increased use of these credits will incentivize increased production and use of clean energy as well as the development of new methods and technologies for generating clean energy. The use of the credits will also incentivize additional investment in facilities that produce and develop clean energy.

Because recordkeeping and reporting requirements relating to the section 45Y and 48E credits will not materially differ from the requirements relating to existing energy production and investment tax credits, the recordkeeping and reporting requirements should not materially increase for taxpayers that already claim existing credits. To claim the section 45Y credit or the 48E credit, taxpayers will continue to need to execute the relevant form (or successor form, or pursuant to instructions and other guidance) and file such form with the taxpayer’s timely filed return (including extensions) for the taxable year in which the property is placed in service.

Although the Treasury Department and the IRS do not have sufficient data to precisely determine the likely extent of the increased costs of compliance, the estimated burden of complying with the recordkeeping and reporting requirements are described in the Paperwork Reduction Act section of this preamble.

D. Alternatives considered

The Treasury Department and the IRS considered alternatives to the proposed regulations. For example, the Treasury Department and the IRS considered whether to impose different rules for determining if a section 48E qualified facility had a recapture event, and how and when a taxpayer was required to notify the Secretary that the emissions rate at a qualified facility was greater than 10 grams of CO₂e per kWh. The proposed regulations were designed to minimize burdens on taxpayers while ensuring that the IRS has sufficient information to determine if a section 48E qualified facility’s emissions rate exceeded the recapture threshold. The proposed guidance requires that a taxpayer that claimed the section 48E credit to annually report to the IRS its GHG emissions rate in the form and manner prescribed in IRS forms or instructions or in published guidance as published in the Internal Revenue Bulletin.

An additional example is that the Treasury Department and the IRS considered alternatives to how a taxpayer should compute any increase in capacity at a qualified facility that for purposes of section 45Y and 48E was a qualified facility due to an increase in capacity. The proposed regulations were designed to provide a rule that was administrable for the IRS and taxpayers. Thus, the proposed regulations adopt a rule for taxpayers to compute the increase in capacity by multiplying the amount of electricity that the facility produces during a taxable year after the new unit or an addition of capacity is placed in service by a fraction, the numerator of which is the nameplate capacity that results from the new unit or an addition of capacity, and the denominator of which is the total nameplate capacity of the facility with the new unit or an addition of capacity

Comments are requested on the requirements in the proposed regulations, including specifically, whether there are less burdensome alternatives that ensure the IRS has sufficient information to administer the Clean Electricity Tax Credits.

E. Duplicative, overlapping, or conflicting Federal rules

The proposed rules would not duplicate, overlap, or conflict with any relevant Federal rules. As discussed above, the proposed regulations would provide guidance relating to the section 45Y tax credit and the section 48E tax credit. The Treasury Department and the IRS invite input from interested members of the public about identifying and avoiding overlapping, duplicative, or conflicting requirements.

Section 202 of the Unfunded Mandates Reform Act of 1995 (UMRA) requires that agencies assess anticipated costs and benefits and take certain other actions before issuing a final rule that includes any Federal mandate that may result in expenditures in any one year by a State, local, or Indian Tribal government, in the aggregate, or by the private sector, of $100 million (updated annually for inflation). This proposed rule does not include any Federal mandate that may result in expenditures by State, local, or Indian Tribal governments, or by the private sector in excess of that threshold.

Executive Order 13132 (Federalism) prohibits an agency from publishing any rule that has federalism implications if the rule either imposes substantial, direct compliance costs on State and local governments, and is not required by statute, or preempts State law, unless the agency meets the consultation and funding requirements of section 6 of the Executive order. This proposed rule does not have federalism implications and does not impose substantial direct compliance costs on State and local governments or preempt State law within the meaning of the Executive order.

Executive Order 13175 (Consultation and Coordination With Indian Tribal Governments) prohibits an agency from publishing any rule that has Tribal implications if the rule either imposes substantial, direct compliance costs on Indian Tribal governments, and is not required by statute, or preempts Tribal law, unless the agency meets the consultation and funding requirements of section 5 of the Executive order. This proposed rule does not have substantial direct effects on one or more federally recognized Indian tribes and does not impose substantial direct compliance costs on Indian Tribal governments within the meaning of the Executive order.