Code of Federal Regulations · Section

§ 1.45Y-5 — y-5 Greenhouse Gas Emissions Rates For Qualified Facilities Under Section 45y

26 C.F.R. § 1.45Y-5

View:

(a) In general. This section provides rules and definitions for determining emissions rates for purposes of section 45Y of the Internal Revenue Code (Code). Paragraph (b)(4) of this section provides a definition for a facility that produces electricity through combustion or gasification and paragraph (b)(7) of this section defines a facility that does not produce electricity through combustion or gasification. Paragraphs (c) through (e) provide rules for determining the greenhouse gas emissions rates for facilities for purposes of section 45Y. Paragraph (f) of this section provides rules for the annual publication of emissions rates. Paragraph (g) of this section provides rules related to provisional emissions rates. Paragraph (h) of this section provides rules regarding reliance on the annual publication of emissions rates and provisional emissions rates. Finally, paragraph (i) of this section provides rules regarding substantiation requirements.

(b) Definitions. The definitions in this paragraph (b) apply for purposes of this section.

(1) CO2e per kWh. The term CO2e per kWh means with respect to any greenhouse gas, the equivalent carbon dioxide (as determined based on global warming potential) per kWh of electricity produced. The 100-year time horizon global warming potentials (GWP-100) from the Intergovernmental Panel on Climate Change's Fifth Assessment Report (AR5) must be used to convert emissions to equivalent carbon dioxide emissions. For purposes of this paragraph (b)(1), the GWP-100 from AR5 (as shown in table 1 to this paragraph (b)(1)) excludes climate-carbon feedbacks. Table 1 to this paragraph (b)(1) provides GWP-100 amounts for certain greenhouse gases applicable to this section.

Table 1 to Paragraph (b)(1)—100 Year Global Warming Potentials for Greenhouse Gases

(2) Combustion. The term combustion means a rapid exothermic chemical reaction, specifically the oxidation of a fuel, which liberates energy including heat and light.

(3) Gasification. 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.

(4) Facility that produces electricity through combustion or gasification (C&G Facility). Consistent with section 45Y(b)(2)(B), the term 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 of one energy source into another using combustion or gasification.

(5) Greenhouse gas emissions rate. 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.

(6) Greenhouse gases emitted into the atmosphere by a facility in the production of electricity. For purposes of section 45Y(b)(2)(A), for both C&G 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 processes that transform the input energy source into electricity but excludes emissions described in paragraphs (b)(6)(i) through (vi) of this section.

(i) Emissions from electricity production by back-up or auxiliary 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.

(ii) 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.

(iii) Emissions from a step-up transformer that conditions the electricity into a form suitable for productive use or sale.

(iv) 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.

(v) Emissions from infrastructure associated with the facility, including, but not limited to, emissions from road construction for feedstock production.

(vi) Emissions from the distribution of electricity to consumers.

(7) Non-C&G Facility. The term Non-C&G Facility means a facility that produces electricity and is not described in paragraph (b)(4) of this section.

(8) Fuel. The term fuel means material directly used to produce electricity or energy inputs that are used to produce electricity.

(9) Feedstock. 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.

(10) Market-mediated effects. The term market-mediated effects means effects resulting from policy interventions and other factors (for example, technological advances) that alter the availability of and demand for marketed goods and activities and their related greenhouse gas (GHG) emissions profiles. These effects are driven by and result in changes in absolute and relative prices which can occur at local, national, and global boundaries. Examples of market-mediated effects include direct and significant indirect emissions, such as land use changes or land use management changes that result from the production of fuels derived from biomass and shifts in total market demand and supply for input fuels, feedstocks and related commodities, and other materials, as a result of changes associated with the policy intervention.

(c) Non-C&G Facilities—(1) Determining a greenhouse gas emissions rate for Non-C&G Facilities. Greenhouse gas emissions rates for Non-C&G Facilities must be determined under paragraphs (c) and (e) of this section.

(i) Excluded emissions. 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:

(A) Emissions from hydropower reservoirs due to anoxic conditions;

(B) Ebullitive, diffuse, and degassing emissions from hydropower operations;

(C) Emissions of non-condensable gases from underground reservoirs during geothermal operations; and

(D) 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.

(ii) Emissions assessment process. Subject to paragraphs (b)(6) and (c)(1) of this section, a greenhouse gas emissions rate for a Non-C&G Facility must be determined through a technical and engineering assessment of the fundamental energy transformation into electricity. This 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.

(iii) Example of greenhouse gas emissions rate determination for a Non-C&G Facility—(A) Facts. A facility uses solar photovoltaic technologies to convert light directly into electricity through use of the photovoltaic effect. This is a physical phenomenon in which certain semiconducting materials upon exposure to light, absorb the light and transform the energy contained in the light directly into an electric current. There are many materials that may be used to generate electricity through this method, including crystalline silicon, amorphous silicon, cadmium telluride, copper indium gallium diselenide, perovskites, quantum dots, and carbon-based materials known as organic photovoltaics. The smallest unit of photovoltaic materials is a cell. Multiple cells are typically assembled into a panel or module and electrically connected. Multiple modules or panels are generally connected to comprise a solar system or installation. Solar photovoltaic technologies produce direct current electricity that can be used as is or, more typically, can be fed into inverters to transform it into alternating current. Solar panels can be ground mounted at a fixed angle or can be mounted with tracking systems that move the panels to track the location of the sun over the course of the day and season in order to maximize electricity production. Solar panels may also be mounted on buildings (for example, on roofs), or solar photovoltaic materials can be integrated into other building components such as roofing tiles.

(B) Analysis. For solar photovoltaic technologies, the fundamental transformation of input energy (solar electromagnetic radiation) into electricity using the photovoltaic effect involves no mechanical energy or chemical reactions. Academic studies on the lifecycle greenhouse gas emissions from solar photovoltaic power indicate that there is a small but non-zero amount of emissions associated with the operational phase of these technologies. However, these emissions exclusively occur due to ongoing maintenance (for example, the washing of solar panels), preventative maintenance (for example, the periodic replacement of electrical equipment such as inverters), and a minimal amount of project management (for example, inverter standby mode at night). These emissions do not occur directly due to the production of electricity. Therefore, consistent with paragraph (c)(1)(ii) of this section, the greenhouse gas emissions rate for facilities that produce electricity by solar photovoltaic properties is not greater than zero.

(2) Non-C&G Facilities with a greenhouse gas emissions rate that is not greater than zero. The types or categories of facilities described in paragraphs (c)(2)(i) through (viii) of this section are Non-C&G Facilities with a greenhouse gas emissions rate that is not greater than zero and may be treated as listed in the Annual Table (see paragraph (g) of this section) with an emissions rate that is not greater than zero:

(i) Wind (including small wind properties);

(ii) Hydropower (including 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);

(iii) Marine and hydrokinetic;

(iv) Solar (including photovoltaic and concentrated solar power);

(v) Geothermal (including flash and binary plants);

(vi) Nuclear fission;

(vii) Fusion energy; and

(viii) Waste energy recovery property that derives energy from a source described in paragraphs (c)(2)(i) through (vii) of this section.

(d) C&G Facilities—(1) Determining a greenhouse gas emissions rate for C&G Facilities. The greenhouse gas emissions rate for a C&G Facility—

(i) Must be determined by a lifecycle analysis (LCA) that complies with the requirements of paragraphs (d) and (e) of this section; and

(ii) Equals the net rate of greenhouse gases emitted into the atmosphere by such facility (taking into account lifecycle greenhouse gas emissions, as described in 42 U.S.C. 7545(o)(1)(H)) in the production of electricity, expressed as grams of CO2e per kWh.

(2) LCA requirements. For purposes of this paragraph (d), an LCA must comply with the requirements of paragraphs (d)(2)(i) through (x) of this section:

(i) Starting boundary. The starting boundary of the LCA for an LCA involving generation-derived feedstocks (such as biogenic feedstocks) is feedstock generation. The starting boundary of the LCA for an LCA involving extraction-derived feedstocks (such as fossil fuel feedstocks) is feedstock extraction. The starting boundaries include the processes and inputs 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, but is not limited to, the emissions effects, including associated direct and indirect greenhouse gas emissions, of relevant land management activities or changes related to or associated with the extraction or production of raw feedstock materials or fuel.

(ii) Ending boundary. The ending boundary of the 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 use of such electricity generated by the C&G Facility (and what other types of energy sources it displaces), including emissions from transmission and distribution, are outside of the LCA boundary.

(iii) Baseline. The LCA must be based on a future anticipated baseline, which projects future status quo in the absence of the availability of the section 45Y and 48E credits (taking into account anticipated changes in technology, policies, practices, and environmental and other socioeconomic conditions). The future anticipated baseline must be updated as necessary to capture material regulatory, economic, supply chain, or environmental changes. The baseline must be updated at least every ten years, but not more often than every five years.

(iv) Offsets and offsetting activities. Offsets and offsetting activities may not be taken into account in the LCA.

(v) Principles for included emissions. The LCA must take into account direct emissions and significant indirect emissions. Sources of direct emissions include those associated with feedstock production or extraction, including 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. Sources of significant indirect emissions include emissions in the United States and other countries associated with market-mediated changes in related commodity markets, such as emission from indirect land use change and emissions consequences of commodity production. These included emissions are within the system boundary of the LCA.

(A) Direct emissions. For purposes of this paragraph (d)(2)(v), 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 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 emission from gasification or combustion additives).

(B) Significant indirect emissions. For purposes of this paragraph (d)(2)(v), examples of significant indirect emissions include, but are not limited to, emissions from indirect land use and land use change, and induced emissions associated with the increased use of the feedstock for energy production.

(vi) Principles for excluded emissions. The LCA must not take into account the types of emissions described in paragraphs (d)(2)(vi)(A) through (D) of this section:

(A) Emissions from facility construction, siting or decommissioning (including on-site emissions occurring from construction or manufacturing of the facility itself);

(B) Emissions from facility maintenance (including emissions from the on and offsite construction or maintenance of the facility; emissions from vehicles used to access and perform maintenance on electricity generating facilities; emissions from back-up generators that do not provide additional firm power and are used in maintaining critical systems in case of a power system outage or for supporting restart of a generator after an outage; and emissions occurring from heating and cooling control rooms or dispatch centers);

(C) Emissions from infrastructure associated with the facility (including emissions from road construction for feedstock production and emissions from onsite backup or emergency generators used in an emergency or unplanned outage); and

(D) Emissions from the distribution of electricity to consumers.

(vii) Alternative fates and avoided emissions. The LCA may consider alternative fates and account for avoided emissions, including for the fuels and feedstocks consumed in the fuel and feedstock supply chain and at the electricity generating facility. The term alternative fate means a set of informed assumptions (for example, production processes, material outcomes, and market-mediated effects) used to estimate the emissions from the use or disposal of each feedstock were it not for the feedstock's new use due to the implementation of policy (that is, to produce electricity). The term avoided emissions means the estimated emissions associated with the feedstock, including the feedstock's production and use or disposal, 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.

(viii) Temporal scales. The LCA should evaluate the emissions over a time horizon of 30 years from the year in which a qualified facility first qualifies for the credit (or, for purposes of the section 48E credit, the year in which a qualified facility was placed in service).

(ix) Spatial scales. To determine the initial spatial scope of the LCA, the initial qualitative assessment should analyze whether the feedstock has been or is anticipated: to be used or sold on the market in the absence of the section 45Y and 48E credits; to be used directly in or as an input to an activity or good in local markets; to be transported for use in domestic markets elsewhere; to be traded for use in international markets; and to be used in a manner that has significant ramifications on other markets. If this assessment concludes that the feedstock does not meet one or more of the criteria in this paragraph (d)(2)(ix), then the market-mediated effects analysis would not be necessary beyond the relevant spatial scale(s) (for example, if the feedstock is not traded or not anticipated to be traded for use in international markets and increased use in the United States is not anticipated to have significant market ramifications abroad, international market-mediated effects analysis would not be necessary). Based on the results of the assessment, the LCA should evaluate the emissions on a sub-regional, regional, national, or international scale as appropriate. The evaluation of emissions should include the market and emissions implications of sourcing new or additional material for electricity generation across the applicable market and spatial scales.

(x) Categorization of products. As appropriate, the LCA should distinguish between primary products, co-products, byproducts, and waste products.

(A) Products should be categorized based on the definitions in paragraphs (d)(2)(x)(A)(1) through (4) of this section.

(1) A primary product is an input or an output with marketability and is the main driver of the process from which it is produced.

(2) A co-product is an input or an output with marketability that is produced together with another product, both of which are economic drivers of the process from which they are produced.

(3) A byproduct is an input or an output that is produced together with another product, and which has a market recognized economic value of zero or greater, but the output is not an economic driver of the process from which it is produced.

(4) A waste product is an input or an output with negative economic value, demonstrated by—

(i) The absence of a market in which the product is purchased and sold; and

(ii) The existence of a market in which producers pay for the collection and removal or disposal of the input or output material or the existence of a predominant operational practice in which producers themselves collect and remove, give away, or dispose of the input or output material as part of operational processes.

(B) The LCA should adopt the principles in paragraphs (d)(2)(x)(B)(1) through (6) of this section for categorizing and assessing the emissions outcomes for different types of products if such categorization is relevant to the LCA model or models used.

(1) All classification of materials and LCAs should take into account relevant geospatial variations in supply and demand (that is, differences across local, sub-regional, and larger regions), as well as variations across specific product types and characteristics, and producer types as relevant.

(2) The LCA should assess whether there are market-mediated effects and, if so, take these into account as part of the GHG analysis.

(3) Regardless of how a material is categorized, the LCA should consider whether the availability of the section 45Y and 48E credits is expected to result in additional production of that material or in material changes in the supply chain, and, if so, should take into account the direct and indirect emissions impact of the additional production or changes in the supply chain.

(4) Policy and other interventions (for example, technological advances) can alter the availability and demand for marketed goods and services, which can alter the treatment of materials once disposed of. Therefore, reevaluation of material categorization should occur at least every ten years, but not more often than every five years.

(5) All determinations of marketability, market-mediated effects, and behavioral changes must be supported by an analytical assessment performed by one or more National Laboratories, in consultation with other Federal agency experts as appropriate.

(6) A material should be considered to have a market recognized economic value and an established market if one existed within the last five years as of the date of the analysis.

(e) Use of methane from certain sources to produce electricity—(1) In general. The requirements provided by this paragraph (e) apply to C&G Facilities (as defined in paragraph (b)(4) of this section) that produce electricity through combustion or gasification using methane derived from biogas, renewable natural gas (RNG) derived from biogas, or fugitive sources of methane (or any hydrogen derived from methane from these sources) as a fuel or feedstock.

(2) Definitions. The following definitions apply for purposes of paragraph (e) of this section:

(i) Biogas. The term biogas means gas containing methane that results from the decomposition of organic matter under anaerobic conditions.

(ii) Coal mine methane. The term coal mine methane means methane that is stored within coal seams and is liberated as a result of current or past mining activities. Liberated coal mine methane can be released intentionally by the mine for safety purposes, such as through mine degasification boreholes or underground mine ventilation systems, or it may leak out of the mine through vents, fissures, or boreholes. The term coal mine methane does not include methane removed from virgin coal seams (for example, coal bed methane).

(iii) Fugitive methane. The term fugitive methane means methane released from equipment leaks or venting during the extraction, processing, transformation, or delivery of fossil fuels and other gaseous fuels to the point of final use.

(iv) Renewable natural gas. The term renewable natural gas (RNG) means biogas that has been upgraded to remove water, CO2, and other impurities such that it is interchangeable with fossil natural gas.

(3) Considerations regarding the lifecycle greenhouse gas emissions associated with the production of electricity using methane from certain sources—(i) In general. For purposes of determining the GHG emissions rate of a C&G Facility (as provided in paragraph (d)(1) of this section) that produces electricity through combustion or gasification using methane derived from biogas, RNG derived from biogas, or fugitive sources of methane (or any hydrogen derived from methane from these sources) as a fuel or feedstock, measurements of lifecycle GHG emissions must consider all the direct and significant indirect emissions associated with a C&G Facility's production of electricity. For purposes of determining the alternative fates and avoided emissions under paragraph (d)(2)(vii) of this section, such determinations must consider the alternative fates of that methane, including avoided emissions and alternative productive uses of that methane; the risk that the availability of tax credits creates incentives resulting in the production of additional methane or otherwise induces additional emissions; and observable trends and anticipated changes in waste management and disposal practices over time as they are applicable to methane generation and uses.

(ii) Methane from landfill sources. For purposes of determining the GHG emissions rate of a C&G Facility (as provided in paragraph (d)(1) of this section) that produces electricity through combustion or gasification using methane derived from landfill sources as a fuel or feedstock, the alternative fate of such gas must be flaring.

(iii) Methane from wastewater sources. For purposes of determining the GHG emissions rate of a C&G Facility (as provided in paragraph (d)(1) of this section) that produces electricity through combustion or gasification using methane derived from wastewater sources as a fuel or feedstock, the alternative fate of such gas must be flaring of gas not used to heat the anaerobic digester.

(iv) Coal mine methane. For purposes of determining the GHG emissions rate of a C&G Facility (as provided in paragraph (d)(1) of this section) that produces electricity through combustion or gasification using coal mine methane that is drainage gas as a fuel or feedstock, the alternative fate of such gas must be flaring.

(v) Methane from animal waste. For purposes of determining the GHG emissions rate of a C&G Facility (as provided in paragraph (d)(1) of this section) that produces electricity through combustion or gasification using methane derived from animal waste as a fuel or feedstock, the emissions associated with producing and transporting such biogas must use an alternative fate derived from the national average of all animal waste management practices, which results in a carbon intensity score of -51 gCO2e/megajoule (MJ), where the MJ basis refers to the lower heating value of the methane contained in the biogas prior to upgrading.

(vi) Fugitive methane other than coal mine methane. For purposes of determining the GHG emissions rate of a C&G Facility (as provided in paragraph (d)(1) of this section) that produces electricity through combustion or gasification using fugitive methane other than coal mine methane as a fuel or feedstock, such as fugitive methane from oil and gas operations, the alternative fate of such gas must be productive use, resulting in emissions equivalent to the carbon intensity of using fossil natural gas.

(4) Book-and-claim. For purposes of determining a GHG emissions rate of a facility under section 45Y or 48E, a book-and-claim accounting system may not be used to establish or claim the energy attributes of biogas, RNG, coal mine methane, or any other methane described in this paragraph (e), or any other input or feedstock.

(f) Carbon capture and sequestration—(1) In general. For purposes of determining a greenhouse gas emissions rate for a Non-C&G Facility or C&G Facility, the greenhouse gas emissions rate must not include any qualified carbon dioxide (as defined in section 45Y(c)(3)) that is produced in such facility's production of electricity, that is captured by the taxpayer, and pursuant section 45Q(f)(2) and 26 CFR 1.45Q-3, disposed of by the taxpayer in secure geological storage, or utilized by the taxpayer in a manner described in section 45Q(f)(5) and 26 CFR 1. 45Q-4.

(2) Substantiation. The requirements for substantiation and verification of carbon capture and sequestration provided by regulations and guidance published in the Internal Revenue Bulletin (see § 601.601 of this chapter) under section 45Q (section 45Q requirements) must be satisfied for qualified carbon dioxide to be taken into account under paragraph (e)(1) of this section. A taxpayer that uses carbon capture and sequestration at a qualified facility for which a section 45Y credit is claimed must comply with applicable requirements of the U.S. Environmental Protection Agency's Greenhouse Gas Reporting Program (GHGRP) under 40 CFR part 98, subpart PP (for carbon capture), subpart RR (for geological storage), and subpart RR or VV (for storage through enhanced oil recovery). In addition to the section 45Q requirements, taxpayers using the ISO 27916 standard for enhanced oil recovery must report information to GHGRP under 40 CFR part 98, subpart VV. Furthermore, the taxpayer must also include their applicable GHGRP ID number(s) on the IRS Form used to claim the section 45Y or section 48E credit, with the exception of taxpayers claiming the credits by performing carbon capture and utilization. The GHGRP does not provide a reporting mechanism for utilization.

(g) Annual publication of emissions rates—(1) In general. As required by section 45Y(b)(2)(C)(i), the Secretary will annually publish a table that sets forth the greenhouse gas emissions rates for types or categories of facilities (Annual Table), which a taxpayer must use for purposes of section 45Y. Except as provided in paragraph (h) of this section, 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 credit 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.

(2) Publication of analysis required for changes to the Annual Table. 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, as well as any changes to emissions determinations for any types or categories of facilities in the Annual Table, since its last publication. Types or categories of facilities will 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 paragraph (c)(1)(ii) of this section, and, for C&G Facilities, an LCA that complies with paragraphs (d) and (f) of this section. Such expert analysis must be prepared by one or more of the National Laboratories, in consultation with other Federal agency experts 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 (B) of the Internal Revenue Code and this section.

(h) Provisional emissions rates—(1) In general. 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 paragraph (g) of this section, 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). A PER must be determined and obtained under the rules of this section.

(2) Rate not established. 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. If a taxpayer's request for an emissions value pursuant to paragraph (h)(5) of this section 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.

(3) Process for filing a PER petition. 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. The PER petition must contain an emissions value, and, if applicable, the associated letter from the Department of Energy (DOE). An emissions value may be obtained from DOE or by using the designated LCA model in accordance with paragraph (h)(6) of this section. 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 Federal agency experts as appropriate, consistent with this section. A taxpayer must retain in its books and records a copy of the application and correspondence to and from DOE including a copy of the taxpayer's request to DOE for an emissions value and any information provided by the taxpayer to DOE pursuant to the emissions value request process provided in paragraph (h)(5) of this section. Alternatively, an emissions value can be determined by the taxpayer 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 under paragraph (h)(6) of this section. If an emissions value is determined using the most recent version of the model or models, the taxpayer is required to provide to the IRS information to support its determination in the form and manner prescribed in IRS forms or instructions or in publications or guidance published in the Internal Revenue Bulletin. See § 601.601 of this chapter. 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 paragraph (h)(6) of this section.

(4) PER determination. 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. A taxpayer may rely upon an emissions value provided by DOE for purposes of 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 specific LCA model or models that, as of the time the PER petition is filed, have been designated by the Secretary for such use under paragraph (h)(6) of this section, 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. However, 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.

(5) Emissions value request process. An applicant that submits a request for an emissions value must follow the procedures specified by DOE to request and obtain such emissions value. Emissions values will be determined consistent with the rules provided in this section. 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 completion of a project specification and cost estimation sufficient to inform a final investment decision for the facility. DOE may decline to review applications that are not responsive, including those applications that relate to a facility described in the Annual Table (consistent with paragraph (h)(2) of this section) or a facility for which an emissions value can be determined by an LCA model designated under paragraph (h)(6) of this section (consistent with paragraph (h)(3) of this section), or applications that are incomplete. 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 for, under limited circumstances, requesting a revision to DOE's initial assessment of an emissions value based on revised technical information or facility design and operation.

(6) LCA model for determining an emissions value for C&G Facilities. The Secretary may designate one or more LCA models for determining an emissions value for C&G Facilities that are not described in the Annual Table. The Secretary may only designate a model under this paragraph (h)(6) if the model complies with section 45Y(b)(2)(B) and paragraphs (d) and (f) of this section. 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 is required to publish an accompanying expert analysis of the model that is prepared by one or more of the National Laboratories, in consultation with other Federal agency experts as appropriate, and such analysis must address the model's compliance with section 45Y(b)(2)(B) of the Internal Revenue Code and paragraphs (d) and (f) of this section.

(7) Effect of PER. A taxpayer may use a PER determined by the Secretary to determine eligibility for the section 45Y credit for the facility to which the PER applies, provided all other requirements of section 45Y are met. 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. Further, a PER determination does not signify that the IRS has determined that the requirements of section 45Y have been satisfied for any taxable year.

(i) Reliance on Annual Table or provisional emissions rate. 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 under paragraph (h)(4) of this section to determine the facility's greenhouse gas emissions rate 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.

(j) Substantiation—(1) In general. 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 greenhouse gas emissions rate, as determined under this section, that is not greater than zero for the taxable year.

(2) Sufficient substantiation. Documentation sufficient to substantiate that a facility had a greenhouse gas emissions rate, as determined under this section, that is not greater than zero for the taxable year includes documentation or a report prepared by an unrelated party that verifies that a facility had such an emissions rate. For a facility described in paragraph (c)(2) of this section, the taxpayer can maintain sufficient documentation to demonstrate a greenhouse gas emissions rate that is not greater than zero for the taxable year by showing that it is the type of facility described in paragraph (c)(2). For qualified facilities not described in paragraph (c)(2), the taxpayer must demonstrate that the qualified facility meets the specific criteria that the analytical assessment prepared by the National Laboratories, in consultation with other Federal agency experts as appropriate, has found are necessary for a facility to meet the statutory requirement of a greenhouse gas emissions rate not greater than zero. For C&G Facilities that utilize biomass feedstocks, the taxpayer must substantiate that the source of such fuels or feedstocks used are consistent with the taxpayer's claims. The Secretary may determine that qualified facilities not described in paragraph (c)(2) can sufficiently substantiate a greenhouse gas 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. See § 601.601 of this chapter. For facilities that utilize unmarketable feedstocks that are indistinguishable from marketable feedstocks (for instance, after processing), the taxpayer will be required to maintain documentation substantiating the origin and original form of the feedstock.

(k) Applicability date. This section applies to qualified facilities placed in service after December 31, 2024, and during a taxable year ending on or after January 15, 2025.

26 C.F.R. § 1.45Y-4 26 C.F.R. § 1.45Z-1-1.45Z-2

Authorizing Statute