Commercial package air conditioning and heating equipment is included in the list of “covered equipment” for which DOE is authorized to establish and amend energy conservation standards and test procedures. (42 U.S.C. 6311(1)(B)-(D)) This equipment includes air-cooled commercial unitary air conditioners with a rated cooling capacity greater than or equal to 65,000 British thermal units per hour (“Btu/h”) (“ACUACs”), air-cooled commercial unitary heat pumps with a rated cooling capacity greater than or equal to 65,000 Btu/h (“ACUHPs”), evaporatively-cooled commercial unitary air conditioners (“ECUACs”), and water-cooled commercial unitary air conditioners (“WCUACs”), which are all the subject of this RFI. 1 (ACUACs, ACUHPs, ECUACs, and WCUACs are referred to collectively as “CUACs and CUHPs” in this document). The current DOE test procedures for CUACs and CUHPs are codified in Table 1 at title 10 of the Code of Federal Regulations (“CFR”) part 431, subpart F, section 96. See 10 CFR 431.96. The current Federal energy conservation standards for ACUACs and ACUHPs are established at 10 CFR 431.97(b). The following sections discuss DOE's authority to establish and amend test procedures and energy conservation standards for CUACs and CUHPs, as well as relevant background information regarding DOE's considerations of test procedures and standards for this equipment.

The Energy Policy and Conservation Act, as amended (“EPCA”), 2 authorizes DOE to regulate the energy efficiency of a number of consumer products and certain industrial equipment. (42 U.S.C. 6291-6317) Title III, Part C  3 of EPCA, added by Public Law 95-619, Title IV, § 441(a), established the Energy Conservation Program for Certain Industrial Equipment, which sets forth a variety of provisions designed to improve energy efficiency. This covered equipment includes small, large, and very large commercial package air conditioning and heating equipment. (42 U.S.C. 6311(1)(B)-(D)) Commercial package air conditioning and heating equipment includes CUACs and CUHPs, which are the subject of this NOPR.

The energy conservation program under EPCA consists essentially of four parts: (1) Testing, (2) labeling, (3) Federal energy conservation standards, and (4) certification and enforcement procedures. Relevant provisions of EPCA include definitions (42 U.S.C. 6311), test procedures (42 U.S.C. 6314), labeling provisions (42 U.S.C. 6315), energy conservation standards (42 U.S.C. 6313), and the authority to require information and reports from manufacturers (42 U.S.C. 6316).

The Federal testing requirements consist of test procedures that manufacturers of covered equipment must use as the basis for: (1) Certifying to DOE that their equipment complies with the applicable energy conservation standards adopted pursuant to EPCA (42 U.S.C. 6316(b); 42 U.S.C. 6296), and (2) making representations about the efficiency of that equipment (42 U.S.C. 6314(d)). Similarly, DOE uses these test procedures to determine whether the equipment complies with relevant standards promulgated under EPCA.

Federal energy efficiency requirements for covered equipment established under EPCA generally supersede State laws and regulations concerning energy conservation testing, labeling, and standards. (42 U.S.C. 6316(a) and (b); 42 U.S.C. 6297) DOE may, however, grant waivers of Federal preemption for particular State laws or regulations, in accordance with the procedures and other provisions of EPCA. (42 U.S.C. 6316(b)(2)(D))

Under 42 U.S.C. 6314, EPCA also sets forth the general criteria and procedures DOE is required to follow when prescribing or amending test procedures for covered equipment. EPCA requires that any test procedure prescribed or amended under this section must be reasonably designed to produce test results which reflect energy efficiency, energy use, or estimated operating cost of covered equipment during a representative average use cycle and requires that test procedures not be unduly burdensome to conduct. (42 U.S.C. 6314(a)(2))

EPCA requires that the test procedures for CUACs and CUHPs be those generally accepted industry testing procedures or rating procedures developed or recognized by the Air-Conditioning, Heating, and Refrigeration Institute (“AHRI”) or by the American Society of Heating, Refrigerating and Air-Conditioning Engineers (“ASHRAE”), as referenced in ASHRAE Standard 90.1, “Energy Standard for Buildings Except Low-Rise Residential Buildings” (“ASHRAE Standard 90.1”). (42 U.S.C. 6314(a)(4)(A)) If such an industry test procedure is amended, DOE must update its test procedure to be consistent with the amended industry test procedure, unless DOE determines, by rule published in the Federal Register and supported by clear and convincing evidence, that the amended test procedure would not meet the requirements in 42 U.S.C. 6314(a)(2) and (3) related to representative use and test burden. (42 U.S.C. 6314(a)(4)(B) and 42 U.S.C. 6314(a)(4)(C))

EPCA also requires that, at least once every 7 years, DOE evaluate test procedures for each type of covered equipment, including CUACs and CUHPs, to determine whether amended test procedures would more accurately or fully comply with the requirements for the test procedures to not be unduly burdensome to conduct and be reasonably designed to produce test results that reflect energy efficiency, energy use, and estimated operating costs during a representative average use cycle. (42 U.S.C 6314(a)(1))

In addition, if the Secretary determines that a test procedure amendment is warranted, the Secretary must publish proposed test procedures in the Federal Register , and afford interested persons an opportunity (of not less than 45 days' duration) to present oral and written data, views, and arguments on the proposed test procedures. (42 U.S.C 6314(b)) If DOE determines that test procedure revisions are not appropriate, DOE must publish its determination not to amend the test procedures. (42 U.S.C 6314(a)(1))

In EPCA, as amended by the Energy Policy Act of 1992 (“EPAct”) (Pub. L. 102-486), Congress initially set mandatory energy conservation standards for certain types of commercial heating, air-conditioning, and water-heating equipment. (106 Stat. 2776, 2810-2814) Specifically, the statute set standards for small, large, and very large commercial package air conditioning and heating equipment, packaged terminal air conditioners (“PTACs”) and packaged terminal heat pumps (“PTHPs”), warm-air furnaces, packaged boilers, storage water heaters, instantaneous water heaters, and unfired hot water storage tanks. Id. In initially establishing Federal energy conservation standards, the EPAct amendments to EPCA prescribed standards at levels that generally corresponded to the levels in ASHRAE Standard 90.1, as in effect on October 24, 1992 ( i.e., the 1989 edition of ASHRAE Standard 90.1), for each type of covered equipment listed.

In acknowledgement of technological changes that yield energy efficiency benefits, Congress further directed DOE through EPCA to consider amending the existing Federal energy conservation standard for each type of covered equipment listed, each time ASHRAE amends Standard 90.1 with respect to such equipment. (42 U.S.C. 6313(a)(6)(A)) When triggered in this manner, DOE must undertake and publish an analysis of the energy savings potential of amended energy efficiency standards, and amend the Federal standards to establish a uniform national standard at the minimum level specified in the amended ASHRAE Standard 90.1, unless DOE determines that there is clear and convincing evidence to support a determination that a more-stringent standard level as a national standard would produce significant additional energy savings and be technologically feasible and economically justified. (42 U.S.C. 6313(a)(6)(A)(i)-(ii)) If DOE decides to adopt as a national standard the minimum efficiency levels specified in the amended ASHRAE Standard 90.1, DOE must establish such standard not later than 18 months after publication of the amended industry standard. (42 U.S.C. 6313(a)(6)(A)(ii)(I)) However, if DOE determines, supported by clear and convincing evidence, that a more-stringent uniform national standard would result in significant additional conservation of energy and is technologically feasible and economically justified, then DOE must establish such more-stringent uniform national standard not later than 30 months after publication of the amended ASHRAE Standard 90.1. (42 U.S.C. 6313(a)(6)(A)(ii)(II) and 42 U.S.C. 6313(a)(6)(B))

Although EPCA does not explicitly define the term “amended” in the context of what type of revision to ASHRAE Standard 90.1 would trigger DOE's obligation, DOE's longstanding interpretation has been that the statutory trigger is an amendment to the standard applicable to that equipment under ASHRAE Standard 90.1 that increases the energy efficiency level for that equipment. See 72 FR 10038, 10042 (March 7, 2007). In other words, if the revised ASHRAE Standard 90.1 leaves the energy efficiency level unchanged (or lowers the energy efficiency level), as compared to the energy efficiency level specified by the uniform national standard adopted pursuant to EPCA, regardless of the other amendments made to the ASHRAE Standard 90.1 requirement ( e.g., the inclusion of an additional metric), DOE has stated that it does not have the authority to conduct a rulemaking to consider a higher standard for that equipment pursuant to 42 U.S.C. 6313(a)(6)(A). See 74 FR 36312, 36313 (July 22, 2009) and 77 FR 28928, 28937 (May 16, 2012). However, DOE notes that Congress adopted amendments to these provisions related to ASHRAE Standard 90.1 equipment under the American Energy Manufacturing Technical Corrections Act (Pub. L. 112-210 (Dec. 18, 2012)) (“AEMTCA”). In relevant part, DOE is prompted to act whenever ASHRAE Standard 90.1 is amended with respect to “the standard levels or design requirements applicable under that standard” to any of the enumerated types of commercial air conditioning, heating, or water heating equipment. (42 U.S.C. 6313(a)(6)(A)(i))

EPCA does not detail the exact type of amendment that serves as a triggering event. However, DOE has considered whether its obligation is triggered in the context of whether the specific ASHRAE Standard 90.1 requirement on which the most current Federal requirement is based is amended ( i.e., the regulatory metric or design requirement). For example, if an amendment to ASHRAE Standard 90.1 changed the metric for the standard on which the Federal requirement was based, DOE would perform a crosswalk analysis to determine whether the amended metric under ASHRAE Standard 90.1 resulted in an energy efficiency level that was more stringent than the current DOE standard. Conversely, if an amendment to ASHRAE Standard 90.1 were to add an additional metric by which a class of equipment is to be evaluated, but did not amend the requirement that is in terms of the metric on which the Federal requirement was based, DOE would not consider its obligation triggered.

In those situations where ASHRAE has not acted to amend the levels in Standard 90.1 for the equipment types enumerated in the statute, EPCA also provides for a 6-year-lookback to consider the potential for amending the uniform national standards. (42 U.S.C. 6313(a)(6)(C)) Specifically, pursuant to the amendments to EPCA under AEMTCA, DOE is required to conduct an evaluation of each class of covered equipment in ASHRAE Standard 90.1 “every 6 years” to determine whether the applicable energy conservation standards need to be amended. (42 U.S.C. 6313(a)(6)(C)(i)) DOE must publish either a notice of proposed rulemaking (“NOPR”) to propose amended standards or a notification of determination that existing standards do not need to be amended. (42 U.S.C. 6313(a)(6)(C)) In proposing new standards under the 6- year review, DOE must undertake the same considerations as if it were adopting a standard that is more stringent than an amendment to ASHRAE Standard 90.1. (42 U.S.C. 6313(a)(6)(C)(i)(II)) This is a separate statutory review obligation, as differentiated from the obligation triggered by an ASHRAE Standard 90.1 amendment. While the statute continues to defer to ASHRAE's lead on covered equipment subject to Standard 90.1, it does allow for a comprehensive review of all such equipment and the potential for adopting more-stringent standards, where supported by the requisite clear and convincing evidence. That is, DOE interprets ASHRAE's not amending Standard 90.1 with respect to a product or equipment type as ASHRAE's determination that the standard applicable to that product or equipment type is already at an appropriate level of stringency, and DOE will not amend that standard unless there is clear and convincing evidence that a more stringent level is justified. As a preliminary step in the process of reviewing the changes to ASHRAE Standard 90.1, EPCA directs DOE to publish in the Federal Register for public comment an analysis of the energy savings potential of amended standards within 180 days after ASHRAE Standard 90.1 is amended with respect to any of the covered equipment specified under 42 U.S.C. 6313(a). (42 U.S.C. 6313(a)(6)(A))

DOE's existing test procedure for CUACs and CUHPs appears at 10 CFR 431.96 (“Uniform test method for the measurement of energy efficiency of commercial air conditioners and heat pumps”). The test procedure for ACUACs and ACUHPs specified in 10 CFR 431.96 references appendix A to subpart F of part 431, “Uniform Test Method for the Measurement of Energy Consumption of Air-Cooled Small (≥65,000 Btu/h), Large, and Very Large Commercial Package Air Conditioning and Heating Equipment” (“appendix A”). Appendix A references certain sections of ANSI/AHRI Standard 340/360-2007, “2007 Standard for Performance Rating of Commercial and Industrial Unitary Air-Conditioning and Heat Pump Equipment,” approved by ANSI on October 27, 2011, and updated by addendum 1 in December 2010 and addendum 2 in June 2011 (“ANSI/AHRI 340/360-2007”); ANSI/ASHRAE Standard 37-2009, “Methods of Testing for Rating Electrically Driven Unitary Air-Conditioning and Heat Pump Equipment” (“ANSI/ASHRAE 37-2009”); and specifies other test procedure requirements related to minimum external static pressure (“ESP”), optional break-in period, refrigerant charging, setting indoor airflow, condenser head pressure controls, tolerance on capacity at part-load test points, and condenser air inlet temperature for part-load tests. The DOE test procedure for ECUACs and WCUACs with a rated cooling capacity of greater than or equal to 65,000 Btu/ h specified in 10 CFR 431.96 incorporates by reference ANSI/AHRI 340/360-2007 (excluding Section 6.3 of ANSI/AHRI 340/360-2007 and including paragraphs (c) and (e) of 10 CFR 431.96). The DOE test procedure for ECUACs and WCUACs with a rated cooling capacity of less than 65,000 Btu/ h incorporates by reference ANSI/AHRI Standard 210/240-2008, “2008 Standard for Performance Rating of Unitary Air-Conditioning & Air-Source Heat Pump Equipment,” approved by ANSI on October 27, 2011, and updated by addendum 1 in June 2011 and addendum 2 in March 2012 (“ANSI/AHRI 210/240-2008”).

On October 26, 2016, ASHRAE published ASHRAE Standard 90.1-2016, which included updates to the test procedure references for CUACs and CUHPs (excluding ECUACs and WCUACs with a rated cooling capacity less than 65,000 Btu/h) to reference AHRI Standard 340/360-2015, “2015 Standard for Performance Rating of Commercial and Industrial Unitary Air-Conditioning and Heat Pump Equipment” (“AHRI 340/360-2015”). On July 25, 2017, DOE published an RFI (“July 2017 TP RFI”) to collect information and data to consider amendments to DOE's test procedures for certain categories of commercial package air conditioning and heating equipment, including CUACs and CUHPs. 82 FR 34427. As part of the July 2017 TP RFI, DOE identified several aspects of the currently applicable Federal test procedures for CUACs and CUHPs that might warrant modifications, in particular: Incorporation by reference of the most recent version of the relevant industry standard(s); efficiency metrics and calculations; and clarification of test methods. 82 FR 34427, 34439-34448. DOE also requested comment on any additional topics that may inform DOE's decisions in a future test procedure rulemaking, including methods to reduce regulatory burden while ensuring the procedures' accuracies. 82 FR 34427, 34448.

On October 24, 2019, ASHRAE published ASHRAE 90.1-2019, which updated the AHRI Standard 340/360 reference to the 2019 edition, “2019 Standard for Performance Rating of Commercial and Industrial Unitary Air-Conditioning and Heat Pump Equipment” (“AHRI 340/360-2019”). On January 25, 2022, AHRI approved an updated version of its test method for CUACs and CUHPs, with the publication of AHRI Standard 340/360-2022, “2022 Standard for Performance Rating of Commercial and Industrial Unitary Air-conditioning and Heat Pump Equipment” (“AHRI 340/360-2022”).

For ECUACs and WCUACs with a rated cooling capacity less than 65,000 Btu/h, ASHRAE 90.1-2016 references ANSI/AHRI 210/240-2008. After the publication of the July 2017 TP RFI, AHRI published AHRI Standard 210/240-2017, “2017 Standard for Performance Rating of Unitary Air-conditioning & Air-source Heat Pump Equipment,” (“AHRI 210/240-2017”). ASHRAE 90.1-2019 references AHRI 210/240-2017 as the test procedure for ECUACs and WCUACs. After the publication of AHRI 210/240-2017, AHRI released two updates to the industry standard: (1) AHRI Standard 210/240-2017 with Addendum 1, “2017 Standard for Performance Rating of Unitary Air-conditioning & Air-source Heat Pump Equipment,” (“AHRI 210/240-2017 with Addendum 1”), which was published in April 2019; and (2) AHRI Standard 210/240-2023, “2023 Standard for Performance Rating of Unitary Air-conditioning & Air-source Heat Pump Equipment,” (“AHRI 210/240-2023”), which was published in May 2020.

Notably, ECUACs and WCUACs with a rated cooling capacity less than 65,000 Btu/h were removed from the scope of AHRI 210/240-2023. ECUACs and WCUACs with a rated cooling capacity less than 65,000 Btu/h were instead included in the scope of AHRI 340/360-2022.

The updates in AHRI 340/360-2022, AHRI 210/240-2023, as well as comments received in the interim that relate to the CUAC and CUHP test procedure have prompted DOE to publish this RFI to investigate additional aspects of the CUAC and CUHP test procedure. Upon further evaluation, DOE has identified several issues that would benefit from further comment. DOE discusses these topics in section II.A of this document. 4

In a direct final rule published on January 15, 2016, (“January 2016 direct final rule”), DOE adopted amended standards for ACUACs, and ACUHPs. 81 FR 2420. For ACUACs and ACUHPs, DOE adopted two tiers of amended standards with staggered compliance dates and changed the regulated cooling metric from energy efficiency ratio (“EER”) to integrated energy efficiency ratio (“IEER”). 5 81 FR 2420, 2531-2532. The first tier of amended standards—with a compliance date of January 1, 2018—are equivalent to the IEER minimum efficiency levels for ACUACs and ACUHPs in ASHRAE 90.1-2016. The second tier of amended standards—with a compliance date of January 1, 2023—are more stringent than the levels in ASHRAE 90.1-2016.

The current energy conservation standards for ACUACs and ACUHPs are codified in DOE's regulations at 10 CFR 431.97.

Since publication of the January 2016 direct final rule, ASHRAE published an updated version of ASHRAE Standard 90.1 (“ASHRAE 90.1-2019”), which updated the minimum efficiency levels for ACUACs and ACUHPs to align with those adopted by DOE in the January 2016 direct final rule ( i.e., specifying two tiers of minimum levels for ACUACs and ACUHPs, with a 2023 compliance date for the second tier).

As a preliminary step in the process of reviewing the standards for ACUACs and ACUHPs, DOE published an RFI on May 12, 2020 (“May 2020 ECS RFI”) to request data and information pursuant to its 6-year-lookback review. 85 FR 27941. The May 2020 ECS RFI sought information to help DOE inform its decisions, consistent with its obligations under EPCA. DOE received multiple comments from stakeholders in response to the May 2020 ECS RFI that prompted DOE to publish this RFI to investigate additional aspects of the ACUAC and ACUHP standards. Upon further evaluation, DOE has identified several issues that would benefit from further comment. DOE discusses these topics (including any comments received in response to the May 2020 ECS RFI that are related to these topics) in section II.B of this document. DOE also received comments in response to the May 2020 ECS RFI that relate to the CUAC and CUHP test procedure, which are addressed in section in section II.A of this document. 6

The Commission issued the Energy Labeling Rule (“Rule”) in 1979, 1 pursuant to the Energy Policy and Conservation Act of 1975 (“EPCA”). 2 The Rule requires energy labeling for major home appliances and other consumer products to help consumers compare competing models. It also contains labeling requirements for refrigerators, refrigerator-freezers, freezers, dishwashers, water heaters, clothes washers, room air conditioners, furnaces, central air conditioners, heat pumps, plumbing products, lighting products, ceiling fans, and televisions.

The Rule requires manufacturers to attach yellow EnergyGuide labels to many covered products and prohibits retailers from removing these labels or rendering them illegible. In addition, it directs sellers, including retailers, to post label information on websites and in paper catalogs from which consumers can order products. EnergyGuide labels for most covered products contain three key disclosures: Estimated annual energy cost, a product's energy consumption or energy efficiency rating as determined by DOE test procedures, and a comparability range displaying the highest and lowest energy costs or efficiency ratings for all similar models. For cost calculations, the Rule specifies national average costs for applicable energy sources ( e.g., electricity, natural gas, oil) based on DOE estimates. Under the Rule, the Commission periodically updates comparability range and annual energy cost information based on manufacturer data submitted pursuant to the Rule's reporting requirements. The Rule sets a five-year schedule for updating range of comparability and annual energy cost information. 3 Pursuant to that schedule the Commission proposes the following amendments.

As discussed below, the Commission proposes to update comparability ranges and national average energy cost figures (Appendix K1 and K2) for several product categories consistent with the Rule's five-year schedule. The proposed amendments also update § 305.10 to clarify that manufacturers must determine capacity for room air conditioners using current DOE requirements.

In accordance with the Rule's five-year schedule for comparability range updates (§ 305.12), this Document proposes revisions to the comparability range and energy cost information in the Rule's appendices for televisions, refrigerators and freezers, dishwashers, water heaters, room air conditioners (ranges only), clothes washers, furnaces, and pool heaters. 4 In addition, the Commission proposes updating the average energy cost figures manufacturers must use to calculate a model's estimated energy cost for the label based on national average cost figures published by DOE. 5 Specifically, the proposed amendments update the energy cost tables in Appendix K1 and K2. 6 This document also contains proposed conforming changes to the sample labels in the Rule's appendices to reflect the new range and cost information.

Pursuant to 305.12, manufacturers must begin using this information on new product labels within 90 days after publication of a final notice announcing updated ranges for specific products. 7 Manufacturers do not have to relabel products labeled prior to the effective date of the changes. For room air conditioners, the Commission proposes setting an October 1, 2022 effective date for those ranges because this label must appear on product boxes, and such package changes can require additional planning and coordination. The proposed October date coincides with the annual production cycle ( i.e., the cooling season) for those products.

The Commission does not propose amending range and cost information for central air conditioner and portable air conditioner labels because the Commission recently updated those ranges. 8 Additionally, the Commission does not propose changing the cost figure for room air conditioner labels because such a change would make room air conditioner labels inconsistent with cost information on portable air conditioners, a similar product category. Accordingly, the electricity cost figure (¢13/kWh) for those two categories appear in Appendix K2 and has been used to create the room air conditioner ranges (Appendix E) in the proposed amendments.

Finally, the proposed amendments update § 305.10 to clarify that manufacturers must determine capacity for room air conditioners using current DOE requirements. Specifically, the amendment eliminates obsolete text related to rounding and updates references to existing DOE requirements for capacity determinations. The Commission proposes making the change effective on October 1, 2022 to coincide with the effective date of the Commission's previously published requirements for EnergyGuide labels for portable air conditioners. 9

The Commission seeks comment on the amendments proposed in this document. You can file a comment online or on paper. For the Commission to consider your comment, we must receive it on or before July 11, 2022. Write “Range Updates, Matter No. R611004” on your comment. Your comment—including your name and your state—will be placed on the public record of this proceeding, including, to the extent practicable, on the website https://www.regulations.gov.

Because of the public health emergency in response to the COVID-19 outbreak and the agency's heightened security screening, postal mail addressed to the Commission will be subject to delay. We strongly encourage you to submit your comments online through the https://www.regulations.gov website. To ensure the Commission considers your online comment, please follow the instructions on the web-based form.

If you file your comment on paper, write “Range Updates, Matter No. R611004” on your comment and on the envelope, and mail your comment to the following address: Federal Trade Commission, Office of the Secretary, Mail Drop H-144, 600 Pennsylvania Avenue NW, Washington, DC 20580.

Because your comment will be placed on the public record, you are solely responsible for making sure your comment does not include any sensitive or confidential information. Your comment should not contain sensitive personal information, such as your or anyone else's Social Security number; date of birth; driver's license number or other state identification number or foreign country equivalent; passport number; financial account number; or credit or debit card number. You are also solely responsible for making sure your comment does not include any sensitive health information, such as medical records or other individually identifiable health information. In addition, your comment should not include any “[t]rade secret or any commercial or financial information which . . . is privileged or confidential”—as provided in Section 6(f) of the FTC Act, 15 U.S.C. 46(f), and FTC Rule 4.10(a)(2), 16 CFR 4.10(a)(2)—including competitively sensitive information such as costs, sales statistics, inventories, formulas, patterns, devices, manufacturing processes, or customer names.

Comments containing material for which confidential treatment is requested must be filed in paper form, must be clearly labeled “Confidential,” and must comply with FTC Rule 4.9(c), 16 CFR 4.9(c). In particular, the written request for confidential treatment that accompanies the comment must include the factual and legal basis for the request and must identify the specific portions of the comment to be withheld from the public record. See FTC Rule 4.9(c). Your comment will be kept confidential only if the General Counsel grants your request in accordance with the law and the public interest. Once your comment has been posted publicly at www.regulations.gov —as legally required by FTC Rule 4.9(b), 16 CFR 4.9(b)—we cannot redact or remove your comment, unless you submit a confidentiality request that meets the requirements for such treatment under FTC Rule 4.9(c), and the General Counsel grants that request.

Visit the FTC website to read this document and the news release describing it. The FTC Act and other laws the Commission administers permit the collection of public comments to consider and use in this proceeding as appropriate. The Commission will consider all timely and responsive public comments it receives on or before July 11, 2022. For information on the Commission's privacy policy, including routine uses permitted by the Privacy Act, see https://www.ftc.gov/siteinformation/privacypolicy.

Because written comments appear adequate to present the views of all interested parties, the Commission has not scheduled an opportunity for presentation of oral comments regarding these proposed amendments. Interested parties may request an opportunity to present views orally. If such a request is made, the Commission will publish a document in the Federal Register stating the time and place for such oral presentation(s) and describing the procedures that will be followed. Interested parties who wish to present oral views must submit a request, on or before July 11, 2022, in the form of a written comment that describes the issues on which the party wishes to speak. If no oral presentations are scheduled, the Commission will base its decision on the written rulemaking record.

The current Rule contains recordkeeping, disclosure, testing, and reporting requirements that constitute information collection requirements as defined by 5 CFR 1320.3(c), the definitional provision within the Office of Management and Budget (OMB) regulations that implement the Paperwork Reduction Act (PRA). OMB has approved the Rule's existing information collection requirements through February 29, 2024 (OMB Control No. 3084-0069). The proposed amendments do not change the substance or frequency of the recordkeeping, disclosure, or reporting requirements and, therefore, do not require further OMB clearance.

The Regulatory Flexibility Act (“RFA”), 5 U.S.C. 601-612, requires that the Commission conduct an analysis of the anticipated economic impact of the proposed amendment on small entities. The RFA requires that the Commission provide an Initial Regulatory Flexibility Analysis (“IRFA”) with a rule unless the Commission certifies that the rule will not have a significant economic impact on a substantial number of small entities. 5 U.S.C. 605. The proposed amendments merely implements routine updates to comparability range information and other minor clarifications. The proposed amendments do not significantly change the substance or frequency of the Rule's recordkeeping, disclosure, or reporting requirements. Thus, the amendments will not have a “significant economic impact on a substantial number of small entities.” 5 U.S.C. 605. The Commission has concluded, therefore, that a regulatory flexibility analysis is not necessary, and certifies, under Section 605 of the Regulatory Flexibility Act (5 U.S.C. 605(b)), that the proposed amendments will not have a significant economic impact on a substantial number of small entities.

For the reasons stated above, the Commission proposes to amend part 305 of title 16 of the Code of Federal Regulations as follows:

1. On June 24, 2021, American Gas Association, American Public Gas Association, American Forest & Paper Association, Industrial Energy Consumers of America, Process Gas Consumers Group and Natural Gas Supply Association (collectively, Petitioners) filed a petition requesting that the Commission institute a rulemaking to revise its regulations, or at the minimum, issue an order revising and updating the FERC Implementation Guide for Electronic Filing of Parts 35, 154, 284, 300 and 341 Tariff Filings (FERC Implementation Guide) to require natural gas pipelines to submit all supporting statements, schedules and workpapers in native format  1 with all links and formulas intact when filing a general Natural Gas Act (NGA) section 4  2 rate case (Petition). Petitioners state that the Commission's current policy does not ensure that Commission staff and stakeholders have access to all the information needed to perform routine rate analyses.

2. CenterPoint Energy Resources Corporation (CenterPoint), National Grid Gas Delivery Companies (National Grid), 3 and Exelon Corporation, Exelon Generation Company, LLC, and affiliates (collectively, Exelon) filed general comments in support of the Petition. In its comments, CenterPoint states that the changes proposed in the Petition may expedite proceedings by removing the additional step where intervenors must submit separate requests for supporting statements, schedules and workpapers in native format, in effect reducing time and expense for all stakeholders. National Grid states that when a natural gas pipeline does not file in native format, a party's only recourse is either the time-consuming process of raising the matter in protests and waiting for the Commission to direct the filer to provide all statements, schedules and workpapers in native format and subsequently the pipeline's compliance with those directives or pursuing this necessary information even later in the process through discovery. National Grid further states that these recourses are not only inefficient but cost parties time waiting on workpapers that allow for a complete and thorough assessment of the rate filing. Exelon maintains that supporting statements, schedules and workpapers should be provided in native format for stakeholders to review and determine whether a natural gas pipeline's proposed rate increase is just and reasonable and in conformance with Commission policies. Exelon argues that it is difficult to conduct a thorough analysis of a rate case if supporting statements, schedules and workpapers are submitted in Adobe PDF format.

3. As required by § 284.10 of the Commission's regulations, 4 interstate natural gas pipelines generally have stated rates for their services, which are approved in a rate proceeding under NGA sections 4 or 5 and remain in effect until changed in a subsequent section 4 or 5 proceeding. When a natural gas pipeline files under NGA section 4 to change its rates, the Commission requires the pipeline to provide detailed support for all the components of its cost of service. 5 Further, section 4(c) of the NGA requires that a natural gas pipeline file proposed changes in rates with the Commission 30 days prior to the proposed effective date. 6

4. Commission regulations require that natural gas pipelines filing general section 4 rate cases provide certain statements (Statements A through P). 7 In 1995, the Commission issued its Filing and Reporting Requirements for Interstate Natural Gas Company Rate Schedules and Tariffs (Order No. 582), stating that Statements I, J and a portion of H (containing state tax formulations) must be received in spreadsheet format with formulas included, as the data provided in these statements are essential to understanding a natural gas pipeline's position with regard to cost allocation and rate design. 8 The Commission found that although these spreadsheets could be obtained through discovery, that process is burdensome, often redundant of the initial filing and inhibits better-informed protests. 9 Subsequently, the FERC Implementation Guide stated that the “submission of spreadsheets in native file format is preferred for Statements A through M, including related schedules. Statements O and P may use any electronic format that renders text, graphics, spreadsheets or data bases that the Commission accepts (the list of FERC Acceptable File Formats is available on http://www.ferc.gov ).”  10 Furthermore, for Statements I, J and a portion of H, the FERC Implementation Guide stated that if spreadsheets in native format ( e.g., Microsoft Excel) are not available that the natural gas pipeline may submit using any of the aforementioned acceptable electronic formats which the Commission accepts. 11

5. Pursuant to NGA section 4, we propose to establish a rule to require natural gas pipelines to submit all statements, schedules and workpapers in native format with formulas and links intact  12 when filing a general NGA section 4 rate case.

6. First, requiring all statements, schedules and workpapers to be filed in native format will reconcile any ambiguity in the current requirements with a formal requirement for all natural gas pipelines to file accordingly. For example, in the Order on Clarification of Order No. 582, the Commission states that if there are no underlying links used to develop a spreadsheet ( i.e., the spreadsheets are prepared separately from each other) then links do not need to be created. Currently, when a natural gas pipeline submits a section 4 rate case filing, the Commission often cannot verify whether there were underlying links used to develop a spreadsheet or whether a pipeline severed those links before filing its rate case. We seek to address this information gap and require natural gas pipelines to file statements and schedules linking progressive calculations regardless of how the statements and schedules were created. Furthermore, requiring spreadsheets with links and formulas intact will enable rate case participants to manipulate the cost-of-service components (including billing determinants) to evaluate different rate outcomes without the need to create their own rate models. This will expedite settlement negotiations and will allow all rate case participants to evaluate the filing on equal footing with the natural gas pipeline and without the need to hire experts or rely on other parties to recreate a pipeline's rate model.

7. Second, submitting all statements, schedules and workpapers in native format will provide for a timely and comprehensive analysis of a rate case filing. If natural gas pipelines are required to submit all statements, schedules and workpapers in native format with links and formulas intact in the initial filing, stakeholders will be provided with pertinent information to analyze the rates and determine if they are just and reasonable. Parties can begin examining the entire filing during the typical 12-day comment period and thus file more informed protests. Furthermore, if natural gas pipelines are required to file all statements and schedules with formulas and links intact, all rate case participants will be able to evaluate the filing and any settlement offers from the same baseline, as opposed to all parties creating their own rate models. This will streamline the rate case process, including settlement discussions, and avoid parties exchanging multiple rounds of discovery and testimony merely to understand the rate model's underlying calculations. The Commission acknowledged this in the Order on Clarification of Order No. 582, stating: “Requiring parties, including staff, to input all the figures from the rate case and spend weeks and rounds of discovery to recreate the pipeline's computations is grossly inefficient and unduly burdensome. Receiving the rate case in a manipulable format is critical given the 12-day period for comment and protest.”  13

8. Third, the current regulations are outdated. Order No. 582 was issued in 1995. Since then, information technology has significantly improved. Section 4 rate cases are now generally developed using Microsoft Excel and submitted electronically. The concerns raised in the comments submitted in the rulemaking underlying Order No. 582 no longer exist ( e.g., outdated software programs, or submitting numerous diskettes). With this rulemaking, we seek to update the filing requirements to reflect current information technology capabilities. We recognize that a final rule adopting these proposals could increase the burden on natural gas pipelines associated with submitting section 4 rate case filings. Currently, natural gas pipelines are only required to submit Statements I, J and the state income taxes portion of Schedule H-3 in native format with formulas and links intact. One specific burden mentioned in the Order on Clarification of Order No. 582 is the need to create links in files where they do not naturally occur when the spreadsheet is developed. As stated above, the Commission cannot verify whether underlying links exist or not but to the extent natural gas pipelines will need to create links among multiple spreadsheets that did not naturally occur when the spreadsheets were generated, their filing burden will increase. However, we do not anticipate that this requirement will be excessively burdensome on natural gas pipelines, as any entity that wants to calculate rates, including the pipeline, needs a linked rate model, and must create one if it is not provided in the original rate case filing.

9. The information collection requirements contained in this NOPR are subject to review by the Office of Management and Budget (OMB) under section 3507(d) of the Paperwork Reduction Act of 1995. 14 OMB's regulations require approval of certain information collection requirements imposed by agency rules. 15 Upon approval of a collection of information, OMB will assign an OMB control number and expiration date. Respondents subject to the filing requirements of this proposed rule will not be penalized for failing to respond to these collections of information unless the collections of information display a valid OMB control number.

10. This NOPR will modify the currently approved information collection associated with FERC-545, Gas Pipeline Rates: Rate Change (Non-Formal) (OMB Control No. 1902-0154) (FERC-545) by updating the requirements for submitting a rate case under section 4 of the NGA.

11. Interested persons may obtain information on the reporting requirements by contacting Ellen Brown, Office of the Executive Director, Federal Energy Regulatory Commission, 888 First Street, NE, Washington, DC 20426 via email ( DataClearance@ferc.gov ) or telephone ((202) 502-8663).

12. The Commission solicits comments on the Commission's need for this information, whether the information will have practical utility, the accuracy of the burden estimates, ways to enhance the quality, utility, and clarity of the information to be collected or retained, and any suggested methods for minimizing respondents' burden, including the use of automated information techniques.

13. Please send comments concerning the collection of information and the associated burden estimates to: Office of Information and Regulatory Affairs, Office of Management and Budget, 725 17th Street, NW, Washington, DC 20503 [Attention: Desk Officer for the Federal Energy Regulatory Commission]. Due to security concerns, comments should be sent electronically to the following email address: oira_submission@omb.eop.gov. Comments submitted to OMB should refer to OMB Control No. 1902-0154.

14. Please submit a copy of your comments on the information collection to the Commission via the eFiling link on the Commission's website at http://www.ferc.gov. If you are not able to file comments electronically, please send a copy of your comments to: Federal Energy Regulatory Commission, Secretary of the Commission, 888 First Street NE, Washington, DC 20426. Comments on the information collection that are sent to FERC should refer to RM21-18-000.

15. Title: Gas Pipeline Rates: Rate Change (Non-Formal).

16. Action: Proposed modification of collection of information in accordance with RM21-18-000.

17. OMB Control No.: 1902-0154.

18. Respondents for this Rulemaking: Gas pipelines filing an NGA section 4 rate case.

19. Frequency of Information Collection: As needed for section 4 rate cases.

20. Necessity of Information: The proposed rule will require all statements, schedules and workpapers submitted during a section 4 rate case to be submitted in native format with all links and formulas intact. The modification to this collection is intended to reduce the overall burden for all parties involved in a section 4 rate case.

21. Internal Review: The Commission has reviewed the changes and has determined that such changes are necessary. These requirements conform to the Commission's need for efficient information collection, communication, and management within the energy industry. The Commission has specific, objective support for the burden estimates associated with the information collection requirements.

22. The Commission estimates that the NOPR will affect the burden  16 and cost  17 as follows:

The Alcohol and Tobacco Tax and Trade Bureau (TTB) administers regulations setting forth standards of fill for containers of beverage distilled spirits and wine products distributed within the United States.

The authority to establish these standards is based on two provisions of law: (1) Section 5301(a) of the Internal Revenue Code of 1986 (IRC), codified at 26 U.S.C. 5301(a) in the case of distilled spirits, and (2) section 105(e) of the Federal Alcohol Administration Act (FAA Act), codified at 27 U.S.C. 205(e), for both distilled spirits and wine. Section 5301(a) of the IRC authorizes the Secretary of the Treasury to prescribe regulations “to regulate the kind, size, branding, marking, sale, resale, possession, use, and reuse of containers (of a capacity of not more than 5 wine gallons) designed or intended for use for the sale of distilled spirits . . .” when the Secretary determines that such action is necessary to protect the revenue. Section 105(e) of the FAA Act authorizes the Secretary of the Treasury to prescribe regulations relating to the “packaging, marking, branding, and labeling and size and fill” of alcohol beverage containers “as will prohibit deception of the consumer with respect to such products or the quantity thereof . . . .”

TTB administers regulations setting forth the tax tolerance for containers of wine products based on sections 5041(e) and 5368 of the IRC. TTB administers the IRC and FAA Act pursuant to section 1111(d) of the Homeland Security Act of 2002, as codified at 6 U.S.C. 531(d). In addition, the Secretary of the Treasury has delegated certain administrative and enforcement authorities to TTB through Treasury Department Order 120-01.

The standards of fill for wine are contained in subpart H of part 4 of the TTB regulations (27 CFR part 4). The term “standard of fill” is used in the TTB regulations and in this document to refer to the authorized amount of liquid in the container, rather than the size or capacity of the container itself. For better readability, however, this document sometimes uses the terms “size” or “container size” and “standards of fill” interchangeably. Within subpart H, paragraph (a) of § 4.72 (27 CFR 4.72(a)) authorizes the use of the following metric standards of fill for containers, in addition to those described in paragraph (b) which are discussed further below:

• 3 liters;

• 1.5 liters;

• 1 liter;

• 750 milliliters;

• 500 milliliters;

• 375 milliliters;

• 355 milliliters;

• 250 milliliters;

• 200 milliliters;

• 187 milliliters;

• 100 milliliters; and

• 50 milliliters.

Paragraph (b) of § 4.72 states that wine may be bottled or packed in containers of 4 liters or larger if the containers are filled and labeled in quantities of even liters (4 liters, 5 liters, 6 liters, etc.).

The standards of fill for distilled spirits are contained in subpart K of part 5 of the TTB regulations (27 CFR part 5). Note that these standards of fill were contained in subpart E of part 5 until March 11, 2022, when the reorganization of part 5 went into effect pursuant to TTB's recent final rule, Modernization of the Labeling and Advertising Regulations for Distilled Spirits and Malt Beverages (T.D. TTB-176, February 9, 2022, 87 FR 7526).

Within subpart K, paragraph (a)(1) of § 5.203 (27 CFR 5.203(a)(1)) specifies the following metric standards of fill for containers other than those described in paragraph (a)(2) of that section:

• 1.8 Liters.

• 1.75 Liters.

• 1 Liter.

• 900 mL.

• 750 mL.

• 720 mL.

• 700 mL.

• 375 mL.

• 200 mL.

• 100 mL.

• 50 mL.

In the case of distilled spirits in metal containers that have the general shape and design of a can, that have a closure which is an integral part of the container, and that cannot be readily reclosed after opening, paragraph (a)(2) of § 5.203 authorizes the use of the following metric standards of fill:

• 355 mL.

• 200 mL.

• 100 mL.

• 50 mL.

In addition to the metric standards specified above, § 5.203 contains provisions regarding tolerances (discrepancies between actual and stated fill), unreasonable shortages in fill, and distilled spirits bottled or imported before January 1, 1980, and marketed or released from customs custody on or after that date (the date on which the U.S. volumetric standards were replaced by the § 5.203 metric standards).

On July 1, 2019, TTB published in the Federal Register Notice No. 182, Elimination of Certain Standards of Fill for Wine, and Notice No. 183, Elimination of Certain Standards of Fill for Distilled Spirits; Amendment of Malt Beverage Net Content Labeling Regulation (84 FR 31257 and 84 FR 31264). The two documents proposed to eliminate most standards of fill for wine and distilled spirits. Both documents proposed to maintain a minimum standard of fill of 50 milliliters to ensure sufficient space on the container for required labeling. Notice No. 183 also proposed a maximum standard of fill of 3.785 liters (one gallon) for distilled spirits, which corresponds to the FAA Act definition of a bulk container for distilled spirits, codified at 27 U.S.C. 206(c). In addition, the documents also sought comments on the relative merits of alternatives, such as adding new authorized standards of fill.

Notice No. 182 described a number of petitions and inquiries that TTB had received over the course of several years requesting the approval of new standards of fill for wine. TTB requested comments on adding the requested sizes. TTB addressed the comments it had received and added certain of the proposed standards of fill to the TTB regulations through publication of a final rule, T.D. TTB-165, on December 29, 2020 (85 FR 85514).

In the final rule, TTB also described an agreement between the United States and Japan that included a commitment for the United States to engage in rulemaking on certain standards of fill, described more fully below. TTB stated in the final rule that TTB would conduct additional rulemaking to propose the addition of new standards of fill for wine, including the 180, 300, 360, 550, and 720 milliliters and 1.8 liters sizes. Japanese government entities and Japanese industry associations requested the addition of those sizes during the comment period for Notice No. 182, and they were included in a Side Letter signed as part of the U.S.-Japan Trade Agreement.

Given that TTB is requesting comment on additional wine sizes pursuant to a Side Letter to the U.S.-Japan Trade Agreement, this document provides a new opportunity for commenters to provide information on three wine standards of fill that TTB proposed in Notice No. 182, but did not incorporate into the regulations in the final rule. TTB received only two, one, and zero comments on the 620 milliliters, 700 milliliters, and 2.25 liters sizes, respectively. TTB found that these comments did not provide sufficient information to make a determination on these sizes, and therefore TTB did not incorporate these sizes into the regulations at that time. TTB summarizes the petition and inquiries for those sizes below.

TTB has received several inquiries over the years regarding the importation of the French product known as “vin jaune” (“yellow wine” in English). Vin jaune is made in the Jura region of France, using a technique similar to that used for making sherry. In accordance with French and European Union regulations, it must be sold in a 620-milliliter bottle. Since 620 milliliters is not an authorized size in § 4.72, vin jaune cannot be imported into the United States in a container with a 620 milliliter standard of fill. The two commenters to Notice No. 182 who specifically addressed this size stated generally that the 620 milliliters size is available internationally and its approval would facilitate trade. After the completion of Notice No. 182, a number of U.S. importers submitted petitions for the 620 milliliters size to TTB. The petitions state that vin jaune is historically and currently bottled in the 620 milliliters size and request the change so that U.S. importers can legally import the wine in the traditional 620 milliliter size.

TTB has received inquiries from foreign governments regarding the 700 milliliter size for wine. Among them was a 2007 request from the Government of Moldova asking that TTB waive the standards of fill requirements for importations of Moldovan wine. At the time, Moldova reported that it had over a million bottles of aged wine in its National Treasury of Wine that could not be sold in the United States due to the U.S. bottle size limitations. Also in 2007, the Government of Georgia requested that TTB add the 700-milliliter bottle to the authorized standards of fill. It stated that the 700-milliliter bottle was a standard size in the former Soviet Union, and the addition of the 700-milliliter standard of fill in the TTB regulations would eliminate a restriction on the sale of Georgian wines in the United States. A commenter to Notice No. 182 recommended approval of the 700 milliliters size because it is consistent with containers available internationally.

TTB received a petition from an importer of boxed wine requesting that the agency authorize a standard of fill of 2.25 liters for wine containers. The importer stated that such a container would significantly reduce the environmental impact of wine packaging because it holds as much as three 750-milliliter wine bottles at half the weight of such bottles. TTB received no comments on Notice No. 182 specifically addressing the 2.25 liters size.

After the publication of T.D. TTB-165, TTB received a petition from a South African wine exporter requesting the approval of 330 milliliters as a standard of fill for wine. The petitioner stated that 330 milliliters is the standard can size for beer and soda products in South Africa and in most European countries, unlike in the U.S. where the standard size is 355 milliliters. The petitioner states they would like to export to the United States but cannot procure cans in the 355 milliliters size in South Africa.

On October 7, 2019, the United States and Japan reached an agreement (the Agreement) on market access for certain agriculture and industrial goods. On December 30, 2019, the U.S. published a document in the Federal Register (84 FR 72187) to implement the Agreement, effective January 1, 2020. As part of the Agreement, the United States Government reached a Side Letter agreement with Japan dated October 7, 2019, which addresses issues related to alcohol beverages, including standards of fill (“Side Letter”). See https://ustr.gov/sites/default/files/files/agreements/japan/Letter_Exchange_on_Alcoholic_Beverages.pdf. The Side Letter states that the U.S. Department of the Treasury will take final action on Notice Nos. 182 and 183. If the final action does not address certain sizes—180, 300, 360, 550, and 720 milliliters and 1.8 liters for wine, and 700, 720, and 900 milliliters and 1.8 liters for distilled spirits—then the U.S. Department of the Treasury shall undertake new rulemaking proposing those sizes, and take final action in respect to that rulemaking. The Side Letter took effect with the U.S.-Japan Trade Agreement, which entered into force on January 1, 2020.

The distilled spirits sizes listed in the Side Letter were all referenced in Notice No. 183, and TTB described in that document the petitions from three Japanese trade associations and a Japanese government agency for those sizes. The same entities submitted comments that supported the elimination of standards of fill generally, but further stated that if the standards are not eliminated they support the approval of their petitioned-for sizes. The wine sizes listed in the Side Letter were not referenced in Notice No. 182, as TTB had not previously received petitions for those sizes. TTB did receive comments from a Japanese trade association and a Japanese government agency proposing the approval of those sizes. The two comments supported the elimination of the standards of fill, but requested the approval of the 180, 300, 360, 550, and 720 milliliters and 1.8 liters sizes for wine if the standards of fill for wine were not eliminated. The two commenters did not provide any reasons that TTB should approve these specific sizes, though the Japanese government agency generally referenced its “proactive efforts for the sound development” of Japan's liquor industry.

Because the requested wine sizes—180, 300, 360, 550, and 720 milliliters, and 1.8 liters—were not referenced in Notice No. 182, TTB is proposing the addition of those sizes to § 4.72 in this notification to ensure that the public is given ample opportunity to provide comment on the sizes.

On February 9, 2022, the Department of the Treasury released a report, “Competition in the Markets for Beer, Wine, and Spirits,” that recommended rulemaking to “again consider eliminating the standards of fill requirements.” See Treasury Report on Competition in the Markets for Beer, Wine, and Spirits (February 9, 2022), available at https://home.treasury.gov/system/files/136/Competition-Report.pdf. That report, produced in response to Executive Order 14036, “Promoting Competition in the American Economy” (published July 9, 2022, at 86 FR 36987), noted that “[c]ontainer size requirements can be a barrier to innovation and competition, insofar as producers must conform their packaging to the Treasury-mandated sizes.” TTB has received questions regarding standards of fill from industry members struggling to source compliant containers in the current market.

For the reasons described above, TTB is proposing to add the six standards of fill for wine listed in the Side Letter discussed above—180, 300, 360, 550, and 720 milliliters, and 1.8 liters—to § 4.72 as authorized standards of fill for wine. TTB is also proposing to add the 330, 620, and 700 milliliters and 2.25 liters sizes to § 4.72 as authorized standards of fill for wine. TTB is specifically interested in comments that address whether the proposed sizes would result in consumer confusion regarding the quantity of wine in the container.

TTB also seeks comment on an alternative of eliminating the existing standards of fill for wine and distilled spirits, except to maintain in the regulations a minimum standard of 50 milliliters for both wine and distilled spirits and a maximum standard of fill of 3.785 liters for distilled spirits. Conforming edits would also be required in 27 CFR parts 19, 26, and 27.

TTB believes a minimum container size is needed to ensure sufficient space on the container for required labeling. TTB believes a maximum container size also is needed to maintain the distinction between bottled and bulk distilled spirits products. See also 27 U.S.C. 206(c). However, TTB is considering eliminating the standards of fill within those limits for many of the same reasons it described in previous notices of proposed rulemaking, “Elimination of Certain Standards of Fill for Wine” (Notice No. 182, July 1, 2019, 84 FR 31257) and “Elimination of Certain Standards of Fill for Distilled Spirits; Amendment of Malt Beverage Net Contents Labeling Regulation” (Notice No. 183, July 1, 2019, 84 FR 31264):

1. Elimination of the existing standards of fill would address the recent petitions on this issue, would eliminate the need for industry members to petition for additional authorizations if marketplace conditions favor different standards in the future, and would eliminate requirements that restrict competition and the movement of goods in domestic and international commerce.

2. It would address concerns that the current standards of fill unnecessarily limit manufacturing options and consumer purchasing options, particularly where consumers may seek smaller containers to target a specific amount of consumption.

3. TTB believes that current labeling requirements regarding net contents (see 27 CFR 4.32(b)(2),4.37, 5.63(b)(3), and 5.70) and those regarding the design and fill of containers (see 27 CFR 4.71 and 5.202) may provide consumers with adequate information about container contents.

4. Limiting standards of fill is no longer necessary to ensure accurate calculation of tax liabilities or to protect the revenue. TTB verifies tax liability on the basis of a producer's production and removal records, and TTB believes that allowing additional standards of fill would not undermine its efforts in this regard. TTB's predecessor agency, the Bureau of Alcohol, Tobacco and Firearms (ATF), and TTB previously took the position that limiting the number of bottle sizes protected the revenue by facilitating accurate tax computations. In Goldstein v. Miller, 488 F.Supp. 156, 171 (D. Md. 1980), aff'd 649 F.2d 863 (4th Cir. 1981), the court reviewed that position and concluded that limiting standards of fill was reasonably related to the collection of the revenue, though it also noted that ATF had the discretionary power to withdraw or amend the requirements. The litigation arose shortly after the enactment of the all-in-bond system of tax payment for distilled spirits under the Distilled Spirits Tax Revision Act of 1979, Title VIII of Public Law 96-39, 96th Cong., 1st Sess. Under this system, the tax was calculated at the time of the removal of the bottled distilled spirits from the distilled spirits plant rather than at the early bulk stages before bottling. Due to the implementation of the system, ATF was especially concerned about maintaining standards of fill at that time, as a back-up to the then new all-in-bond system, whose efficacy was untested. The all-in-bond system has now been in place for over 40 years. Audit experience since implementation of the all-in-bond system and since the Goldstein litigation leads TTB to believe that the limitations on standards of fill are no longer necessary for revenue protection purposes.

In the subsequent final rule, T.D. TTB-165 (December 29, 2020, 85 FR 85514), TTB authorized seven new standards of fill for wine, four new standards of fill for distilled spirits, and did not eliminate the standards of fill. Some commenters contended that eliminating the standards of fill would cause consumer confusion and potentially lead to a proliferation of differing State container size requirements that could cause further consumer confusion. Commenters also expressed concern about significant market disruption. Based on these comments, TTB declined at that time to eliminate all standards of fill but instead authorized additional specific sizes.

However, in light of the several additional requests for yet more sizes in the short time since additional sizes were last adopted, as well as heightened concern that standards of fill can impose barriers to competition, TTB is again considering eliminating the standards of fill. Although TTB acknowledges that some commenters suggested there would be consumer confusion, TTB is not aware of consumer confusion related to container sizes of malt beverages, for which there is no standard of fill requirement. Moreover, with the addition of the eleven new standards of fill authorized with the final rules published in December 2020, and the potential of ten more new standards to address international agreements and petitions described in this document, the value of the defined standards may be of increasingly fleeting utility to consumers. Any potential for confusion may also be mitigated or eliminated by the net contents labeling that is mandatory. Moreover, concerns regarding confusion should be weighed against other concerns, including the possibility that container size requirements can be a barrier to innovation and competition. TTB again seeks comments on this matter generally, and also specifically with regard to whether the potential impact on competition of continuing to restrict standards of fill outweighs potential consumer confusion.

Under the TTB regulations, wine labels must bear a statement of net contents. The regulations at 27 CFR 4.37(b) provide that the mandatory net contents statement may include, in addition to the required metric measure, the equivalent volume in United States measure. If the U.S. measure is shown on the label, it must appear as stated in § 4.37(b) for each standard of fill authorized in § 4.72.

When TTB published T.D. TTB-165, it did not amend § 4.37(b) to add the equivalent U.S. measures for the newly approved standards of fill of 355 milliliters, 250 milliliters, and 200 milliliters. TTB therefore plans to correct this oversight in this document by including in the proposed regulations the U.S. measures for each of the three new standards of fill. The U.S. measures will be shown as follows, in the format currently required by § 4.37(b): 355 ml (12.0 fl. oz.); 250 ml (8.5 fl. oz.); and 200 ml (6.8 fl. oz.).

The proposed regulations also include the addition to § 4.37(b) of U.S. equivalents for each standard of fill that is proposed in this document. For readability, the proposed regulatory text will list the sizes in a table format. The proposed sizes and their U.S. equivalents are as follows:

• 2.25 liters (76.1 fl. oz.);

• 1.8 liters (60.9 fl. oz.);

• 720 milliliters (24.3 fl. oz.);

• 700 milliliters (23.7 fl. oz.);

• 620 milliliters (21.0 fl. oz.);

• 550 milliliters (18.6 fl. oz.);

• 360 milliliters (12.2 fl. oz.);

• 330 milliliters (11.2 fl. oz.);

• 300 milliliters (10.1 fl. oz.); and

• 180 milliliters (6.1 fl. oz.).

Section 5041(e) of the IRC authorizes the Secretary of the Treasury to prescribe by regulation tolerances for wine containers. TTB regulations at 27 CFR 24.255(b) require that wine proprietors fill bottles or other containers as nearly as possible to the amount shown on the container. TTB regulations at 27 CFR 24.255(c) require that “[t]he net contents of bottles or other containers of untaxpaid wine in the same tax class filled during six consecutive tax return periods . . . shall not vary by more than 0.5 percent from the net contents as stated on the bottles or other containers.” TTB regulations at § 24.255(b) clarify that in no event may the amount of wine in any one specific container exceed the fill tolerances listed in the regulation based on the container's size. Note that 27 CFR part 4 contains further clarification on fill tolerance.

When TTB published T.D. TTB-165, it did not amend § 24.255(b) to add fill tolerances for the newly approved standards of fill of 355 milliliters, 250 milliliters, and 200 milliliters. Additionally, when ATF published T.D. ATF-303 on October 23, 1990 (55 FR 42710), it did not amend § 24.255(b) to add a fill tolerance for the newly approved standard of fill of 500 milliliters. TTB therefore plans to correct these oversights in this document by adding fill tolerances for these sizes to § 24.255(b). Based on the existing tolerances, TTB is proposing the following tolerances for these sizes:

• 2.5 percent for 500 milliliters;

• 3 percent for 355 milliliters;

• 4 percent for 250 milliliters; and

• 4 percent for 200 milliliters.

TTB is also proposing the addition of tolerances to § 24.255(b) for most of the standards of fill that are proposed in this document. TTB does not need to add additional tolerances for the proposed sizes of 2.25 liters and 1.8 liters, as the current tolerance of 1.5 percent for containers that are 1.0 liter to 14.9 liters covers those sizes. For the remaining sizes proposed in this document, TTB is proposing the following tolerances:

• 2 percent for 720 milliliters;

• 2 percent for 700 milliliters;

• 2 percent for 620 milliliters;

• 2 percent for 550 milliliters;

• 3 percent for 360 milliliters;

• 3 percent for 330 milliliters;

• 3 percent for 300 milliliters; and

• 4.5 percent for 180 milliliters.

For readability, the proposed regulatory text will include ranges of sizes, rather than listing most of the sizes individually, as the regulation currently does. The proposed regulatory text also includes some additional minor edits for readability.

TTB is also proposing a number of conforming edits to parts 19, 26, and 27 of the TTB regulations (27 CFR parts 19, 26, and 27) to reflect the changes proposed in this rulemaking and the reorganization of parts 5 and 7 (27 CFR parts 5 and 7) that went into effect pursuant to TTB's recent final rule, Modernization of the Labeling and Advertising Regulations for Distilled Spirits and Malt Beverages (T.D. TTB-176, February 9, 2022, 87 FR 7526). TTB also is making additional, nonsubstantive amendments to conform the regulations described in this document to the current regulatory authority citation requirements of the Office of the Federal Register.

TTB requests comments on the proposal to add some or all of the additional standards of fill for wine described in this document, and the alternative of eliminating all but a minimum standard of fill for wine. TTB also requests comments on the proposal to eliminate all but a minimum and maximum standard of fill for distilled spirits. In particular, TTB requests comments on whether it should authorize the proposed sizes (or eliminate the standards of fill altogether) based on the considerations relevant to the FAA Act, such as whether the proposed sizes would result in consumer confusion. TTB also welcomes comments on the proposed container fill tolerances for wine. TTB further welcomes comments on the appropriate number of bottles per case to list in the table at 27 CFR 24.300(a)(1) for the proposed new container sizes, and the existing container sizes not currently listed there. Any person submitting comments may present such data, views, or arguments as he or she desires. Comments that provide the factual basis supporting the views or suggestions presented will be particularly helpful in developing a reasoned regulatory decision on this matter.

You may submit comments on this proposal as an individual or on behalf of a business or other organization via the Regulations.gov website or via postal mail, as described in the ADDRESSES section of this document. Your comment must reference Notice No. 210 and must be submitted or postmarked by the closing date shown in the DATES section of this document. You may upload or include attachments with your comment. You also may submit a comment requesting a public hearing on this proposal. The TTB Administrator reserves the right to determine whether to hold a public hearing.

All submitted comments and attachments are part of the rulemaking record and are subject to public disclosure. Do not enclose any material in your comments that you consider confidential or that is inappropriate for disclosure.

TTB will post, and you may view, copies of this document, selected supporting materials, and any comments TTB receives about this proposal within the related Regulations.gov docket. In general, TTB will post comments as submitted, and it will not redact any identifying or contact information from the body of a comment or attachment.

Please contact TTB's Regulations and Rulings division by email using the web form available at https://www.ttb.gov/contact-rrd, or by telephone at 202-453-2265, if you have any questions regarding how to comment on this proposal or to request copies of this document, its supporting materials, or the comments received in response.

TTB certifies that this proposed regulation, if adopted, would not have a significant economic impact on a substantial number of small entities. If adopted, the amendments would provide bottlers and importers of wine and distilled spirits with additional flexibility to use new bottle sizes if they so choose. The proposed regulation would impose no new reporting, recordkeeping, or other administrative requirement. Therefore, no regulatory flexibility analysis is required.

The collection of information in this rule has been previously approved by the Office of Management and Budget (OMB) under the title “Labeling and Advertising Requirements Under the Federal Alcohol Administration Act,” and assigned control number 1513-0087. This proposed regulation would not result in a substantive or material change in the previously approved collection action, since the nature of the mandatory information that must appear on labels affixed to the container remains unchanged.

It has been determined that this proposed rule is not a significant regulatory action as defined by Executive Order 12866 of September 30, 1993. Therefore, no regulatory assessment is required.

Jennifer Berry of the Regulations and Rulings Division drafted this document.

For the reasons discussed in the preamble, TTB proposes to amend 27 CFR parts 4 and 24 as follows:

The revision reads as follows:

On March 30, 2022, OSHA published a notice of proposed rulemaking to amend its recordkeeping regulation to require certain employers to electronically submit injury and illness information to OSHA that employers are already required to keep under the recordkeeping regulation (87 FR 18528). The notice set a deadline of May 31, 2022, for submitting written comments. OSHA has received a request from the American Federation of Labor and Congress of Industrial Organizations (AFL-CIO) to extend the comment period between 30 to 60 additional days (Document ID 0027). The AFL-CIO's request explains that the agency has multiple deadlines within a one-week period, and the AFL-CIO wishes to have time to meaningfully respond to the important issues in both this notice and the several other requests for comment by OSHA. After reviewing this comment, OSHA has decided to extend the deadline for submitting comments to June 30, 2022, in order to provide stakeholders an additional 30 days (90 days total) to prepare and submit meaningful responses to this rulemaking.

This document was prepared under the direction of Douglas L. Parker, Assistant Secretary of Labor for Occupational Safety and Health, U.S. Department of Labor, 200 Constitution Avenue NW, Washington, DC 20210. It is issued under sections 8 and 24 of the Occupational Safety and Health Act (29 U.S.C. 657, 673), section 553 of the Administrative Procedure Act (5 U.S.C. 553), and Secretary of Labor's Order No. 08-2020 (85 FR 58393, Sept. 18, 2020).

The Amtrak Railroad Bridge, mile 0.9, over Trail Creek, in Michigan City, Indiana, was authorized to operate remotely by letter during the United States Coast Guard's transition from the Department of Transportation to the Department of Homeland Security. Inclusion of the Amtrak Railroad Bridge, mile 0.9, into the regulations was overlooked and this proposed rule will correct that oversight and provide the public the opportunity to comment on the bridge operations.

Trail Creek is 7.3 miles long and used by small powered and unpowered recreational vessels, commercial passenger vessels, and fishing vessels. Freighters have not utilized the waterway for several years. The Amtrak Railroad Bridge, mile 0.9 is a swing railroad bridge and provides a horizontal clearance of 41 feet in the right draw and 44 feet in the left draw and a vertical clearance of 7 feet above LWD in the closed position and an unlimited vertical clearance in the open position. Each day during the summer, approximately 35 recreational and commercial fishing vessels transit the Amtrak Railroad Bridge, mile 0.9; most of the 35 vessels make daily roundtrips, transiting the bridge two times each day.

In 33 CFR 117.401, the Amtrak Railroad Bridge, mile 0.9, is required to open on signal except that, from December 1 through March 15 the Amtrak Railroad Bridge, mile 0.9, is required to open on signal if a 12-hour advance notice is provided.

This proposed rule will allow the public to comment on how well the bridge has been operated remotely for the last 19 years. The drawtender will continue to remain in Chicago, Illinois and will be responsible for the remote operation of two remote railroad bridges: The Amtrak Railroad Bridge, mile 0.9, over Trail Creek and the Amtrak Railroad Bridge, mile 3.77, over the South Branch of the Chicago River.

The Amtrak Railroad Bridge, mile 0.9, will continue to operate a 2-way public address system to answer calls from: (1) Vessel horn signals; (2) a VHF-FM Marine Radio that will monitor channel 16; and (3) cameras that will monitor the tracks, the underside of the bridge, and the upriver and down river view of the river.

We developed this proposed rule after considering numerous statutes and Executive Orders related to rulemaking. Below we summarize our analyses based on these statutes and Executive Orders and we discuss First Amendment rights of protestors.

Executive Orders 12866 and 13563 direct agencies to assess the costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits. This NPRM has not been designated a “significant regulatory action,” under Executive Order 12866. Accordingly, the NPRM has not been reviewed by the Office of Management and Budget (OMB).

This regulatory action determination is based on the fact that remote operation will not significantly impact a vessel's ability to transit the bridge; further, the bridge has operated in said manner since 2003 without comment or complaint.

The Regulatory Flexibility Act of 1980 (RFA), 5 U.S.C. 601-612, as amended, requires Federal agencies to consider the potential impact of regulations on small entities during rulemaking. The term “small entities” comprises small businesses, not-for-profit organizations that are independently owned and operated and are not dominant in their fields, and governmental jurisdictions with populations of less than 50,000. The Coast Guard certifies under 5 U.S.C. 605(b) that this proposed rule would not have a significant economic impact on a substantial number of small entities.

While some owners or operators of vessels intending to transit the bridge may be small entities, for the reasons stated in section IV.A above, this proposed rule would not have a significant economic impact on any vessel owner or operator.

If you think that your business, organization, or governmental jurisdiction qualifies as a small entity and that this rule would have a significant economic impact on it, please submit a comment (see ADDRESSES ) explaining why you think it qualifies and how and to what degree this rule would economically affect it.

Under section 213(a) of the Small Business Regulatory Enforcement Fairness Act of 1996 (Pub. L. 104-121), we want to assist small entities in understanding this proposed rule. If the rule would affect your small business, organization, or governmental jurisdiction and you have questions concerning its provisions or options for compliance, please contact the person listed in the FOR FURTHER INFORMATION CONTACT section. The Coast Guard will not retaliate against small entities that question or complain about this proposed rule or any policy or action of the Coast Guard.

This proposed rule would call for no new collection of information under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520.).

A rule has implications for federalism under Executive Order 13132 (Federalism), if it has a substantial direct effect on the States, on the relationship between the National Government and the States, or on the distribution of power and responsibilities among the various levels of government. We have analyzed this proposed rule under that Order and have determined that it is consistent with the fundamental federalism principles and preemption requirements described in Executive Order 13132.

Also, this proposed rule does not have tribal implications under Executive Order 13175 (Consultation and Coordination with Indian Tribal Governments) because it would not have a substantial direct effect on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes. If you believe this proposed rule has implications for federalism or Indian tribes, please contact the person listed in the FOR FURTHER INFORMATION CONTACT section.

The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531-1538) requires Federal agencies to assess the effects of their discretionary regulatory actions. In particular, the Act addresses actions that may result in the expenditure by a State, local, or tribal government, in the aggregate, or by the private sector of $100,000,000 (adjusted for inflation) or more in any one year. Though this proposed rule will not result in such an expenditure, we do discuss the effects of this proposed rule elsewhere in this preamble.

We have analyzed this rule under Department of Homeland Security Management Directive 023-01, Rev.1, associated implementing instructions, and Environmental Planning Policy COMDTINST 5090.1 (series), which guide the Coast Guard in complying with the National Environmental Policy Act of 1969 (NEPA) (42 U.S.C. 4321-4370f). The Coast Guard has determined that this action is one of a category of actions that do not individually or cumulatively have a significant effect on the human environment. This proposed rule promulgates the operating regulations or procedures for drawbridges. Normally such actions are categorically excluded from further review, under paragraph L49, of Chapter 3, Table 3-1 of the U.S. Coast Guard Environmental Planning Implementation Procedures.

Neither a Record of Environmental Consideration nor a Memorandum for the Record are required for this rule. We seek any comments or information that may lead to the discovery of a significant environmental impact from this proposed rule.

We view public participation as essential to effective rulemaking, and will consider all comments and material received during the comment period. Your comment can help shape the outcome of this rulemaking. If you submit a comment, please include the docket number for this rulemaking, indicate the specific section of this document to which each comment applies, and provide a reason for each suggestion or recommendation.

We encourage you to submit comments through the Federal Decision Making Portal at https://www.regulations.gov. To do so, go to https://www.regulations.gov, type USCG-2022-0303 in the search box and click “Search.” Next, look for this document in the Search Results column, and click on it. Then click on the Comment option. If your material cannot be submitted using https://www.regulations.gov, contact the person in the FOR FURTHER INFORMATION CONTACT section of this document for alternate instructions.

To view documents mentioned in this proposed rule as being available in the docket, find the docket as described in the previous paragraph, and then select “Supporting & Related Material” in the Document Type column. Public comments will also be placed in our online docket and can be viewed by following instructions on the https://www.regulations.gov Frequently Asked Questions web page. We review all comments received, but we will only post comments that address the topic of the proposed rule. We may choose not to post off-topic, inappropriate, or duplicate comments that we receive.

We accept anonymous comments. Comments we post to https://www.regulations.gov will include any personal information you have provided. For more about privacy and submissions in response to this document, see DHS's eRulemaking System of Records notice (85 FR 14226, March 11, 2020).

For the reasons discussed in the preamble, the Coast Guard proposes to amend 33 CFR part 117 as follows:

On March 28, 2022, the Wood Island Life Saving Station Association notified the Coast Guard that it will be conducting a fireworks display from 9 p.m. to 9:30 p.m. on August 6, 2022. The fireworks are to be launched from anchored floats on the Piscataqua River located approximately 1000 yards northwest of Fort Foster, Kittery, ME in position 43°04′23.9″ N, 070°41′57.4″ W (NAD83). Hazards from firework displays include accidental discharge of fireworks, dangerous projectiles, and falling hot embers or other debris. The Captain of the Port Northern New England (COTP) has determined that potential hazards associated with the fireworks to be used in this display would be a safety concern for anyone within a 500-foot radius of the fireworks launch floats.

The purpose of this rulemaking is to ensure the safety of vessels on the navigable waters within a 500-foot radius of the firework launch floats before, during, and after the scheduled event. The Coast Guard is proposing this rulemaking under authority in 46 U.S.C. 70034 (previously 33 U.S.C. 1231).

The COTP is proposing to establish a safety zone from 9 p.m. to 9:30 p.m. on August 6, 2022. The safety zone would cover all navigable waters within 500 feet of the anchored firework floats in the Piscataqua River located approximately 1000 yards northwest of Fort Foster in Kittery, ME. The duration of the zone is intended to ensure the safety of vessels and these navigable waters before, during, and after the scheduled 9 p.m. to 9:30 p.m. fireworks display on August 6, 2022. No vessel or person would be permitted to enter the safety zone without obtaining permission from the COTP or a designated representative. The regulatory text we are proposing appears at the end of this document.

We developed this proposed rule after considering numerous statutes and Executive orders related to rulemaking. Below we summarize our analyses based on a number of these statutes and Executive orders, and we discuss First Amendment rights of protestors.

Executive Orders 12866 and 13563 direct agencies to assess the costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits. This NPRM has not been designated a “significant regulatory action,” under Executive Order 12866. Accordingly, the NPRM has not been reviewed by the Office of Management and Budget (OMB).

This regulatory action determination is based on the size, location, and duration of the safety zone. The safety zone would only impact a 500-foot radius around firework launch floats on the Piscataqua River in Kittery, ME and would only be enforced during the 9 p.m. to 9:30 p.m. fireworks display on August 6, 2022. Public notice of enforcement will be given through appropriate means, which may include, but are not limited to, publication in the Local Notice to Mariners and Broadcast Notice to Mariners via VHF-FM marine channel 16.

The Regulatory Flexibility Act of 1980, 5 U.S.C. 601-612, as amended, requires Federal agencies to consider the potential impact of regulations on small entities during rulemaking. The term “small entities” comprises small businesses, not-for-profit organizations that are independently owned and operated and are not dominant in their fields, and governmental jurisdictions with populations of less than 50,000. The Coast Guard certifies under 5 U.S.C. 605(b) that this proposed rule would not have a significant economic impact on a substantial number of small entities.

While some owners or operators of vessels intending to transit the safety zone may be small entities, for the reasons stated in section IV.A above, this proposed rule would not have a significant economic impact on any vessel owner or operator.

If you think that your business, organization, or governmental jurisdiction qualifies as a small entity and that this proposed rule would have a significant economic impact on it, please submit a comment (see ADDRESSES ) explaining why you think it qualifies and how and to what degree this rule would economically affect it.

Under section 213(a) of the Small Business Regulatory Enforcement Fairness Act of 1996 (Public Law 104-121), we want to assist small entities in understanding this proposed rule. If the proposed rule would affect your small business, organization, or governmental jurisdiction and you have questions concerning its provisions or options for compliance, please call or email the person listed in the FOR FURTHER INFORMATION CONTACT section. The Coast Guard will not retaliate against small entities that question or complain about this proposed rule or any policy or action of the Coast Guard.

This proposed rule would not call for a new collection of information under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520).

A rule has implications for federalism under Executive Order 13132 (Federalism), if it has a substantial direct effect on the States, on the relationship between the National Government and the States, or on the distribution of power and responsibilities among the various levels of government. We have analyzed this proposed rule under that Order and have determined that it is consistent with the fundamental federalism principles and preemption requirements described in Executive Order 13132.

Also, this proposed rule does not have tribal implications under Executive Order 13175 (Consultation and Coordination with Indian Tribal Governments) because it would not have a substantial direct effect on one or more Indian tribes, on the relationship between the Federal Government and Indian tribes, or on the distribution of power and responsibilities between the Federal Government and Indian tribes. If you believe this proposed rule has implications for federalism or Indian tribes, please call or email the person listed in the FOR FURTHER INFORMATION CONTACT section.

The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531-1538) requires Federal agencies to assess the effects of their discretionary regulatory actions. In particular, the Act addresses actions that may result in the expenditure by a State, local, or tribal government, in the aggregate, or by the private sector of $100,000,000 (adjusted for inflation) or more in any one year. Though this proposed rule would not result in such an expenditure, we do discuss the potential effects of this proposed rule elsewhere in this preamble.

We have analyzed this proposed rule under Department of Homeland Security Directive 023-01, Rev. 1, associated implementing instructions, and Environmental Planning COMDTINST 5090.1 (series), which guide the Coast Guard in complying with the National Environmental Policy Act of 1969 (42 U.S.C. 4321-4370f), and have made a preliminary determination that this action is one of a category of actions that do not individually or cumulatively have a significant effect on the human environment. This proposed rule involves establishing a safety zone that would be enforced for 0.5 hours that would prohibit entry within a 500-foot radius of firework launch floats. Normally such actions are categorically excluded from further review under paragraph L60(a) of Appendix A, Table 1 of DHS Instruction Manual 023-01-001-01, Rev. 1. A preliminary Record of Environmental Consideration supporting this determination is available in the docket. For instructions on locating the docket, see the ADDRESSES section of this preamble. We seek any comments or information that may lead to the discovery of a significant environmental impact from this proposed rule.

The Coast Guard respects the First Amendment rights of protesters. Protesters are asked to call or email the person listed in the FOR FURTHER INFORMATION CONTACT section to coordinate protest activities so that your message can be received without jeopardizing the safety or security of people, places, or vessels.

We view public participation as essential to effective rulemaking, and will consider all comments and material received during the comment period. Your comment can help shape the outcome of this rulemaking. If you submit a comment, please include the docket number for this rulemaking, indicate the specific section of this document to which each comment applies, and provide a reason for each suggestion or recommendation.

Submitting comments. We encourage you to submit comments through the Federal Decision Making Portal at https://www.regulations.gov. To do so, go to https://www.regulations.gov, type USCG-2022-0278 in the search box and click “Search.” Next, look for this document in the Search Results column, and click on it. Then click on the Comment option. If you cannot submit your material by using https://www.regulations.gov, call or email the person in the FOR FURTHER INFORMATION CONTACT section of this proposed rule for alternate instructions.

Viewing material in docket. To view documents mentioned in this proposed rule as being available in the docket, find the docket as described in the previous paragraph, and then select “Supporting & Related Material” in the Document Type column. Public comments will also be placed in our online docket and can be viewed by following instructions on the https://www.regulations.gov Frequently Asked Questions web page. We review all comments received, but we will only post comments that address the topic of the proposed rule. We may choose not to post off-topic, inappropriate, or duplicate comments that we receive.

Personal information. We accept anonymous comments. Comments we post to https://www.regulations.gov will include any personal information you have provided. For more about privacy and submissions to the docket in response to this document, see DHS's eRulemaking System of Records notice (85 FR 14226, March 11, 2020).

For the reasons discussed in the preamble, the Coast Guard is proposing to amend 33 CFR part 165 as follows:

Submit your comments, identified by Docket ID No. EPA-R03-OAR-2022-0347 at https://www.regulations.gov (our preferred method), or the other methods identified in the ADDRESSES section. Once submitted, comments cannot be edited or removed from the docket. EPA may publish any comment received to its public docket. Do not submit to EPA's docket at https://www.regulations.gov any information you consider to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Multimedia submissions (audio, video, etc.) must be accompanied by a written comment. The written comment is considered the official comment and should include discussion of all points you wish to make. EPA will generally not consider comments or comment contents located outside of the primary submission ( i.e., on the web, cloud, or other file sharing system). For additional submission methods, the full EPA public comment policy, information about CBI or multimedia submissions, and general guidance on making effective comments, please visit https://www.epa.gov/dockets/commenting-epa-dockets.

Due to public health concerns related to COVID-19, EPA Docket Center and Reading Room are open to the public by appointment only. Our Docket Center staff also continues to provide remote customer service via email, phone, and webform. Hand deliveries or couriers will be received by scheduled appointment only. For further information and updates on EPA Docket Center services, please visit us online at https://www.epa.gov/dockets.

EPA continues to carefully and continuously monitor information from the Centers for Disease Control and Prevention (CDC), local area health departments, and our Federal partners so that we can respond rapidly as conditions change regarding COVID-19.

Please note that because of current CDC recommendations, as well as state and local orders for social distancing to limit the spread of COVID-19, EPA cannot hold in-person public meetings at this time.

EPA will begin pre-registering speakers for the hearing no later than 1 business day after publication of this document in the Federal Register . To register to speak at the virtual hearing, please use the online registration form available at https://www.epa.gov/pa/epa-meetings-and-events-pennsylvania. The last day to pre-register to speak at the hearing will be June 6, 2022. EPA will post a general agenda for the hearing that will list pre-registered speakers in approximate order at: https://www.epa.gov/pa/epa-meetings-and-events-pennsylvania.

The virtual public hearing will be held via teleconference on June 9, 2022. The virtual public hearing will convene at 4 p.m. Eastern Time (ET) and will conclude at 7 p.m. ET. EPA may close a session 15 minutes after the last pre-registered speaker has testified if there are no additional speakers. For information or questions about the public hearing, please contact Ms. Karen Delgrosso at delgrosso.karen@epa.gov. EPA will announce further details at https://www.epa.gov/pa/epa-meetings-and-events-pennsylvania.

EPA will make every effort to follow the schedule as closely as possible on the day of the hearing; however, please plan for the hearings to run either ahead of schedule or behind schedule.

Each commenter will have 5 minutes to provide oral testimony. EPA encourages commenters to provide EPA with a copy of their oral testimony electronically (via email) by emailing it to delgrosso.karen@epa.gov. EPA also recommends submitting the text of your oral comments as written comments to the rulemaking docket.

EPA may ask clarifying questions during the oral presentations, but will not respond to the presentations at that time. Written statements and supporting information submitted during the comment period will be considered with the same weight as oral comments and supporting information presented at the public hearing.

Please note that any updates made to any aspect of the hearing will be posted online at https://www.epa.gov/pa/epa-meetings-and-events-pennsylvania. While EPA expects the hearing to go forward as set forth above, please monitor our website or contact Ms. Karen Delgrosso at delgrosso.karen@epa.gov to determine if there are any updates. EPA does not intend to publish a document in the Federal Register announcing updates.

If you require the services of a translator or special accommodations such as audio description, please pre-register for the hearing and describe your needs by June 6, 2022. EPA may not be able to arrange accommodations without advanced notice.

The CAA regulates emissions of NO X and volatile organic compounds (VOC) to prevent photochemical reactions that result in ozone formation. RACT is an important requirement for reducing NO X and VOC emissions from major stationary sources and sources covered by EPA's control technique guidelines (CTG). Areas designated nonattainment for the ozone NAAQS are subject to section 182(b)(2) of the CAA which sets forth RACT requirements specific to ozone nonattainment areas classified as Moderate nonattainment or higher.

Specifically, section 182(b)(2) of the CAA sets forth three distinct requirements regarding RACT for the ozone NAAQS. First, section 182(b)(2)(A) requires states with ozone nonattainment areas designated Moderate or higher to submit a RACT rule (or negative declaration) for each category of VOC sources in the area covered by a CTG document issued by EPA between November 15, 1990, and the date of attainment for an ozone NAAQS. Second, section 182(b)(2)(B) requires a RACT rule (or negative declaration) for all VOC sources in the nonattainment area covered by any CTG issued before November 15, 1990. Third, section 182(b)(2)(C) requires a RACT rule or rules (or negative declaration) for any other major stationary sources of VOCs located in the nonattainment area.

In addition, section 182(f) subjects major stationary sources of NO X to the same RACT requirements that are applicable to major stationary sources of VOC. Therefore, the RACT requirement for major stationary sources found in 182(b)(2)(C) applies to sources of NO X . A “major source” for purposes of RACT applicability in section 182 is defined based on the source's potential to emit (PTE) of NO X , VOC, or both pollutants, and the applicable thresholds are defined based on the classification of the nonattainment area in which the source is located. See sections 182(c)-(f) and 302 of the CAA. The ozone RACT requirements under section 182(b)(2) are usually referred to as VOC CTG RACT, non-CTG major VOC RACT, and major NO X RACT. 1

Section 184(a) of the CAA, which was added by the 1990 Amendments to the CAA, established an Ozone Transport Region (the OTR) comprised of all or parts of 12 eastern states, and the District of Columbia, including all of Pennsylvania. 2 Section 184(b)(1)(B) extends the VOC CTG RACT requirements in section 182(b)(2)(A) and (B) to all areas in the OTR regardless of NAAQS attainment status. Put another way, because the entire State of Pennsylvania is in the OTR, the requirements of CAA section 184 apply statewide even if all areas of the State were attaining the ozone NAAQS. Further, section 184(b)(2) states that “any stationary source that emits or has the potential to emit at least 50 tons per year (TPY) of volatile organic compounds shall be considered a major stationary source and subject to the requirements which would be applicable to major stationary sources if the area were classified as a Moderate nonattainment area.” This language applies the RACT requirement of 182(b)(2)(C) to all stationary sources in the OTR that have a PTE of at least 50 TPY of VOC. The EPA further clarified in 1992 that for purposes of applying section 182(f) requirements to NO X sources in the OTR, and certain other areas, a major stationary source for purposes of NO X RACT applicability will be defined as any stationary source in the OTR that emits or has the potential to emit 100 tons per year or more of NO X . 3 In total, these RACT requirement in section 184 are referred to as “OTR RACT.”

Since the 1970's, EPA has consistently defined RACT as “the lowest emission limit that a particular source is capable of meeting by the application of the control technology that is reasonably available considering technological and economic feasibility.”  4 Since then, EPA has provided more substantive information on RACT requirements through implementation rules for each ozone NAAQS, and has issued additional guidance documents on RACT. 5 In 2004 and 2005, EPA promulgated an implementation rule for the 1997 8-hour ozone NAAQS in two phases: “Phase 1 of the 1997 Ozone Implementation Rule;” and “Phase 2 of the 1997 Ozone Implementation Rule.” See 69 FR 23951 (April 30, 2004) and 70 FR 71612 (November 29, 2005), respectively. Particularly, the Phase 2 Ozone Implementation Rule addressed RACT statutory requirements under the 1997 8-hour ozone NAAQS. See 70 FR 71652.

On March 6, 2015, EPA issued its final rule for implementing the 2008 8-hour ozone NAAQS (the “2008 Ozone SIP Requirements Rule”). See 80 FR 12264. At the same time, EPA revoked the 1997 8-hour ozone NAAQS, effective on April 6, 2015. The 2008 Ozone SIP Requirements Rule provided comprehensive requirements related to the revoked 1997 8-hour ozone NAAQS, codified in 40 CFR part 51, subpart AA. EPA determined that areas designated nonattainment for both the 1997 and 2008 8-hour ozone NAAQS at the time the 1997 8-hour ozone NAAQS was revoked retain certain nonattainment area requirements ( i.e. anti-backsliding requirements) for the 1997 8-hour ozone NAAQS, including RACT. See 40 CFR 51.1105(a)(1); 51.1100(o). Pennsylvania is also required to implement certain RACT requirements statewide since the entirety of the state is in the OTR. CAA section 184(b). Thus, all of Pennsylvania remains subject to RACT requirements for both the 1997 8-hour ozone NAAQS and the 2008 8-hour ozone NAAQS.

As indicated previously, RACT requirements apply to any ozone nonattainment areas classified as Moderate or higher (Serious, Severe, or Extreme) under CAA sections 182(b)(2). Pennsylvania has a number of areas that are designated nonattainment for the 2008 8-hour ozone NAAQS, including Allegheny and Armstrong Counties. Some areas are additionally required to implement RACT nonattainment requirements as anti-backsliding measures for the revoked 1997 8-hour NAAQS. Also, the entire Commonwealth of Pennsylvania is part of the OTR established under section 184 of the CAA and thus subject statewide to the RACT requirements of CAA sections 182(b)(2) and 182(f), pursuant to section 184(b). While RACT must be evaluated and satisfied as separate requirements under each applicable standard, in practice the same RACT requirements are applicable at this time in Pennsylvania for both the 1997 and 2008 8-hour ozone NAAQS.

States were required to make RACT SIP submissions for the 1997 8-hour ozone NAAQS by September 15, 2006. The Pennsylvania Department of Environmental Protection (PADEP) submitted a SIP revision on September 25, 2006, certifying that a number of previously approved VOC CTG and non-CTG major VOC RACT rules continued to satisfy RACT under the 1997 8-hour ozone NAAQS. EPA approved PADEP's September 25, 2006 submittal, so those requirements are not addressed in this action. See 82 FR 31464 (July 7, 2017). RACT control measures addressing all applicable CAA requirements under the 1997 8-hour ozone NAAQS have been implemented and fully approved in the jurisdictions of Allegheny County and Philadelphia County in Pennsylvania and are also not addressed here. See 78 FR 34584 (June 10, 2013) and 81 FR 69687 (October 7, 2016). For the 2008 8-hour ozone NAAQS, states were required to submit RACT SIP revisions by July 20, 2014.

On May 16, 2016, PADEP submitted a SIP revision addressing RACT under both the 1997 and 2008 8-hour ozone NAAQS in Pennsylvania. Specifically, the May 16, 2016 SIP submittal intended to satisfy sections 182(b)(2)(C), 182(f), and 184 of the CAA for both the 1997 and 2008 8-hour ozone NAAQS for Pennsylvania's major NO X and non-CTG major VOC sources, with a few exceptions not relevant to this action. PADEP's SIP revision included newly adopted regulations found at 25 Pennsylvania Code (Pa. Code) sections 129.96-129.100, titled “Additional RACT Requirements for Major Sources of NO X and VOCs” (the RACT II Rule) and amendments to 25 Pa. Code section 121.1, including related definitions, to be incorporated into the Pennsylvania SIP. These regulatory amendments were adopted by PADEP on April 23, 2016, and became effective on the same date upon publication in the Pennsylvania Bulletin.

On May 9, 2019, EPA published a final action fully approving certain provisions of PADEP's RACT II rule, and conditionally approving other provisions of the SIP revision. 84 FR 20274 (May 9, 2019). The Sierra Club commented on EPA's proposed approval of the RACT II rule, and following EPA's final approval, filed a petition for review with the U.S. Third Circuit Court of Appeals (Third Circuit). The petition challenged EPA's approval of only that portion of the RACT II rule applicable to coal-fired EGUs equipped with SCR for control of NO X . Specifically, the petition challenged EPA's approval of the presumptive RACT NO X limit for these EGUs of 0.12 pounds (lb) of NO X per one million British thermal units (MMBtu) of heat input (lb/MMBtu) when the inlet temperature to the SCR was 600 degrees Fahrenheit or above, found at 25 Pa. Code 129.97(g)(1)(viii); the application of the less stringent NO X limits of 25 Pa. Code 129.97(g)(1)(vi) to EGUs with SCR when the inlet temperature to the SCR was below 600 degrees Fahrenheit;  6 and the failure of the RACT II rule at 25 Pa. Code 129.100(d) to specifically require these EGUs to record temperature data for the inlet temperature to the SCRs and report that data to PADEP. At the time of EPA's approval, there were six facilities in Pennsylvania which were subject to the portion of the RACT II rule which was relevant for purposes of the legal challenge: Bruce Mansfield Generating Station in Beaver County (Bruce Mansfield), Cheswick Generating Station in Allegheny County (Cheswick), Conemaugh Generating Station in Indiana County (Conemaugh), Homer City Generating Station in Indiana County (Homer City), Keystone Generating Station in Armstrong County (Keystone), and Montour Generating Station in Montour County (Montour). Subsequently, Bruce Mansfield ceased operations and surrendered their title V operating permit, and therefore is not included in this action. Additionally, Cheswick Generating Station was issued a title V modification which included an enforceable requirement to cease operations on or before April 1, 2022. 7 Because the process of closure is still ongoing during development of this proposed rulemaking action, EPA cannot affirmatively determine at this time that operations at Cheswick have permanently and enforceably ceased. Therefore, EPA is proposing RACT limits for Cheswick. If operations have permanently and enforceably ceased prior to a final rulemaking action, EPA will not finalize RACT limits for Cheswick.

On August 27, 2020, the Third Circuit Court of Appeals found for the Sierra Club on all three issues, vacated the Agency's approval of the SIP submission on each of these three pieces of the Pennsylvania plan as it pertained to coal-fired EGUs equipped with SCRs (which was applicable to the six facilities listed above), and remanded to the Agency. 8 Sierra Club v. EPA, 972 F.3d 290 (3rd Cir. 2020) ( Sierra Club ). The court held that EPA's approval of 25 Pa. Code 129.97(g)(1)(viii) was arbitrary and capricious because the record did not support EPA's finding that the emission rate limit of 0.12 lb/MMBtu was RACT for these EGU sources, particularly in light of submitted evidence that EGUs in Pennsylvania regulated by 25 Pa. Code 129.97(g)(1)(viii) had achieved much lower emission rates for NO X in the past, and that other states had adopted lower RACT NO X limits for coal-fired sources. Sierra Club at 299-303. In addition, the court held that EPA's approval of the less stringent limits (found in 25 Pa Code 129.97(g)(1)(vi)) when the inlet temperature fell below 600-degrees Fahrenheit was arbitrary and capricious because the record failed to support the need for that less stringent limit or explain why 600 degrees was chosen as the threshold for the change in limits. Id. at 303-307. Thus, the court vacated EPA's approval of the 0.12 lb/MMBtu limit, and the 600-degree temperature threshold, both of which are only found in 25 Pa. Code 129.97(g)(1)(viii). 9 See Id. at 309.

Regarding the reporting and record keeping requirement of 25 Pa. Code 129.100(d), the court also found EPA's approval of the specific SIP revisions discussed above to be arbitrary and capricious based upon the lack of a specific record keeping and reporting requirement for the 600-degree inlet temperature alternative limits to the SCR. See Id. Specifically, the court held that “[b]ecause the SIP's 600-degree threshold necessarily depends upon accurate temperature reporting, the EPA's approval of such inadequate requirements on this record was arbitrary and capricious.” Id. at 309. Lacking evidence in the record that more general recordkeeping and reporting requirements contained in the SIP would require sources subject to 25 Pa. Code 129.97(g)(1)(viii) to keep specific SCR temperature inlet data, report that data to PADEP, and make it available to the public, the court agreed with the Sierra Club. Id. at 308. Further, the court explained that “[t]he combination of this lack of mandatory reporting and the temperature waiver created a potent loophole for polluters to walk through.” Id. at 297.

The court further stated that “[o]n remand, the agency must either approve a revised, compliant SIP within two years or formulate a new federal implementation plan.” Id. at 309. On September 15, 2021, EPA proposed disapproval of those portions of the prior approval which were vacated by the Court. See 86 FR 51315. EPA proposed that action in part to ensure that we have authority to promulgate a FIP if Pennsylvania does not submit a timely approvable SIP revision addressing the Third Circuit's decision. EPA is now proposing this FIP to address these deficiencies, in accordance with the Court's directive, should it be necessary to finalize a FIP to fulfill the Court's order. 10

PADEP undertook significant efforts to develop a SIP revision addressing the deficiencies identified by the Third Circuit in the Sierra Club decision. PADEP proceeded to develop source specific (“case-by-case”) RACT determinations for the Cheswick, Conemaugh, Homer City, Keystone, and Montour generating stations. As mentioned above, the Bruce Mansfield facility ceased operation, so there is no longer a need to address that facility. By April 1, 2021 , each of the five facilities had submitted permit applications to PADEP with alternative RACT proposals in accordance with 25 Pa. Code 129.99. There are a total of ten affected EGUs/units at the five facilities: Three at Homer City, two each at Conemaugh, Keystone and Montour, and one at Cheswick. Subsequently, PADEP issued technical deficiency notices to obtain more information needed to support the facilities' proposed RACT determinations. Although additional information was provided in response to these notices, PADEP determined the proposals to be insufficient and began developing its own RACT determination for each facility. The outcome of this process was PADEP's issuance of draft permits for each facility, which were developed with the intention of submitting each case-by-case RACT permit to be incorporated as a federally enforceable revision to the Pennsylvania SIP. Each draft permit underwent a 30-day public comment period, 11 during which EPA provided source-specific comments to PADEP for each permit. The draft permits, technical support memos for each permit drafted by PADEP, and EPA's comments on each draft permit are included in the docket for this proposed action. At this time, it is not known when, or if, PADEP will submit these permits to EPA as SIP revisions to address the Court's decision.

RACT is not defined in the CAA. However, as discussed above, EPA's longstanding definition of RACT is “the lowest emission limit that a particular source is capable of meeting by the application of control technology that is reasonably available considering technological and economic feasibility.”  12 Pennsylvania has adopted a very similar definition of RACT as “[t]he lowest emission limit for VOCs or NO X that a particular source is capable of meeting by the application of control technology that is reasonably available considering technological and economic feasibility.” 25 Pa. Code 121.1. The Third Circuit decision “assume[d] without deciding” that EPA's definition of RACT is correct. Sierra Club at 294. EPA is using its longstanding definition of RACT to determine the limits proposed in this FIP.

The collection of sources addressed by the RACT analysis in this proposed FIP has been determined by the scope of the Third Circuit's order in the Sierra Club case and EPA's subsequent proposed disapproval action. 13 Herein, EPA is proposing RACT control requirements for the five remaining facilities that were subject to the SIP provision which the Court vacated EPA's approval of and which EPA thereafter proposed to disapprove: Cheswick, Conemaugh, Homer City, Keystone, and Montour.

EPA is proposing that the RACT limits in this FIP will apply throughout the year. For reasons explained in the next section, the proposed limits are technologically and economically feasible during the entire year. While other regulatory controls for ozone, such as the Cross State Air Pollution Rule (CSAPR) and its updates, may apply during a defined ozone season, 14 the proposed RACT limits do not authorize seasonal exemptions based on atmospheric conditions or other factors since the RACT emissions rates are technologically and economically feasible year-round. To the degree that the EPA analyses underlying the RACT emissions limits proposed here rely on past performance data, those calculations typically use ozone season data. This is because ozone season data generally represent the time period over which emissions rate performance of these units is the best. Put another way, the ozone season data for the facilities examined here are a reliable indicator of what is technologically and economically feasible for these facilities, and EPA has no reason to believe that achieving the same performance outside the ozone season would be technologically or economically infeasible.

EPA has previously identified several technologically feasible controls for reducing NO X from EGUs. NO X control technologies are typically divided into combustion controls and post-combustion controls. Combustion controls reduce the formation of NO X during the combustion of fuel, and include low-NO X burners (LNBs), over fire air (OFA), and natural gas reburn (NGR). Post-combustion controls “treat” NO X following its formation during combustion, and include Selective Non-Catalytic Reduction (SNCR) and SCR. EPA's Alternative Control Techniques Document for NO X Emissions from Utility Boilers provides technical information for developing and implementing regulatory programs to control NO X emission from fossil fuel-fired boilers (EPA-453/R-94-023, 1994/03). 15 The EPA Air Pollution Control Cost Manual (Cost Manual) contains chapters with more recent information, including that for cost, for these post-combustion controls. 16 The technical support document (TSD) for the Revised CSAPR Update rule also explored several technologies for reducing NO X emissions from EGUs, including SCR and SNCR, and identified the likely cost of these controls. 17

All ten of the EGUs at the five facilities at issue have been equipped with at least low NO X burners and overfire air since the 1990s, and with SCRs beginning in the early 2000s, with the exception of Conemaugh, which installed SCR in 2014. As such, low-NO X burners, overfire air, and SCR are clearly technologically feasible and proven technologies to reduce NO X for the EGUs at these facilities. The specific NO X and other pollutant controls on each EGU are discussed in the TSD for this action (See section B—Facility Details). Having determined that these technologies are technologically feasible, the question shifts to identifying, through the application of some or all of these technologies, what is the lowest NO X emission limitation at these EGUs reasonably available considering technological and economic feasibility.

Section 4 (“NO X Controls”), Chapter 2 (“Selective Catalytic Reduction”) of the Cost Manual contains a thorough description of how SCRs work and the multiple factors affecting the NO X removal efficiency (performance) of SCRs. The major operational and design factors that affect the NO X removal performance of SCRs include: Reaction temperature range; residence time available in the optimum temperature range; degree of mixing between the injected reagent and the combustion gases; molar ratio of injected reagent to inlet NO X ; inlet NO X concentration level; and ammonia slip. Additional factors affecting NO X removal efficiency of SCRs identified in the Cost Manual are: catalyst activity; catalyst selectivity; pressure drop across the catalyst; ash management ( i.e., mitigating large particle ash (LPA) impacts on the catalyst) and dust loading; catalyst pitch; sulfur dioxide (SO 2 ) and sulfur trioxide (SO 3 ) concentrations in gas stream; catalyst deactivation; and catalyst management. 18

The temperature of the flue gas entering the SCR is a critical factor affecting the performance of any SCR. The temperature of the flue gas entering the SCR affects the degree (percentage) of NO X reduction the SCR is capable of achieving, the likelihood of creating unfavorable emissions from the SCR, such as ammonia slip, and the potential for damage or fouling of the SCR catalyst. As stated in the Cost Manual: “The NO X reduction reaction is effective only within a given temperature range. The use of a catalyst in the SCR process lowers the temperature range required to maximize the NO X reduction reaction. At temperatures below the specified range, the reaction kinetics decrease, and ammonia passes through the boiler (ammonia slip), but there is little effect on nitrous oxide (N 2 O) formation. At temperatures above the specified range, N 2 O formation increases and catalyst sintering and deactivation occurs, but little ammonia slip occurs.”  19 The Cost Manual also notes that “In an SCR system, the optimum temperature depends on both the type of catalyst used in the process and the flue gas composition. For the majority of commercial catalysts (metal oxides), the operating temperatures for the SCR process range from 480 to 800 °F (250 to 430 °C). . . . [T]he rate of NO X removal increases with temperature up to a maximum between 700 and 750 °F (370 to 400 °C). As the temperature increases above 750 °F (400 °C), the reaction rate and resulting NO X removal efficiency begin to decrease.”  20

Based in part on this language in the Cost Manual, EPA approved a 600-degree flue gas temperature threshold at which a 0.12 lb/MMBtu NO X rate applied in the Pennsylvania RACT II SIP. However, the Third Circuit found that both EPA's and PADEP's record lacked a reasonable explanation for why 600 degrees was specifically selected by PADEP as the SCR inlet flue gas temperature below which the higher NO X emission rate applied. 21

As part of the approach used to develop the proposed rates for this action, EPA examined data related to the threshold at which these facilities can effectively operate their SCR. Since the date of the Third Circuit decision (August 27, 2020), EPA has obtained from PADEP a few redacted pages of the SCR Operator's Manual for Conemaugh and Keystone, as well as hourly flue gas temperature, reagent injection amounts, and NO X emission data for the years 2017 through 2020 for those same facilities. These were submitted in response to PADEP's technical deficiency letters and are included in the docket for this action. Conemaugh's SCR manual lists 611 degrees Fahrenheit as the minimum temperature for injecting reagent, while Keystone's manual says 612 degrees is the minimum continuous operating temperature for reagent injection, but reagent can be injected for up to 3 hours at temperatures between 582 and 611 degrees before the system automatically shuts off reagent injection. Because these two facilities provided only a few select pages of their SCR manuals, EPA cannot be certain whether there are, or are not, other operating scenarios and/or SCR inlet temperatures at which reagent could be injected. Furthermore, it is unclear whether the operating manual reflects a specific analysis of the injection protocol that would result in the greatest NO X reductions, as RACT requires. However, in comments submitted in response to the Ozone Transport Commission (OTC)'s CAA section 184(c) petition, 22 Conemaugh and Keystone also identified the threshold in Megawatts (MW) at which they could operate their respective SCRs (see Table 1). 23

PADEP also provided 30 days of similar data submitted by Montour, which included the inlet temperature and reagent injection amounts. Montour also provided an apparently complete copy of its SCR Operation and Maintenance Manual to PADEP, but this manual was not included in the information provided to EPA.

Absent more complete temperature data and operating manuals for all facilities, EPA then analyzed historical operating data submitted to EPA by each of these facilities in order to determine the operating threshold at which Cheswick, Montour, and Homer City could inject reagent and run their SCRs to develop the same MW measure for these three facilities as for Conemaugh and Keystone. 24 For Homer City, Montour, and Cheswick, EPA looked at hourly data for these sources in EPA's Power Sector Emissions Data for ozone seasons 2002 through 2020, except for any years when the source did not have SCR installed. 25 (See explanation in the introduction to this section for why these analyses use ozone season data) EPA created scatter plots showing hourly NO X emission rates by gross hourly load (MW/hr) for each unit's three best performing ozone seasons (in terms of overall ozone season average rate), as well as data from its two most recent ozone seasons (which was 2019 and 2020 at the time). 26 From these scatter plots, the SCR threshold was approximated through visual inspection, i.e., by identifying each unit's approximate gross load, above each unit's minimum operating load, at which NO X rates below 0.2 lb/MMBtu were achieved in the years analyzed. The full analysis and methodology are discussed in detail in the TSD. The results of this analysis, as well as the reported values for Conemaugh and Keystone, are shown in Table 1 in this preamble.

Given the role of gas temperature in SCR performance, EPA considered how best to use this information in establishing RACT limits that address the Third Circuit's concerns about allowing less stringent limits when flue gas temperatures went below what it considered to be an arbitrary temperature threshold. This is a challenging factor to consider in cases when the operating temperature varies, and when the units spend some time at temperatures where SCR is very effective, and some time at temperatures where it is not. To assess whether the units in this FIP exhibit this pattern, EPA evaluated years of data submitted by these sources to EPA to characterize their variability in hours of operation or level of operation. 27 In particular, EPA used this information to identify whether, or to what degree, the EGUs have shifted from being “baseload” units ( i.e., a steady-state heat input rate generally within SCR optimal temperature range) to “cycling” units ( i.e., variable heat input rates, possibly including periods below the SCR optimal temperature range). All of these EGUs were designed and built as baseload units, meaning the boilers were designed to be operated at levels of heat input near their design capacity 24 hours per day, seven days per week, for much of the year. As a result, the SCRs installed in the early 2000s were designed and built to work in tandem with a baseload boiler. In particular, the SCR catalyst and the reagent injection controls were designed for the consistently higher flue gas temperatures created by baseload boiler operation. In more recent years, for multiple reasons, these old, coal-fired baseload units have struggled to remain competitive when bidding into the PJM Interconnection (PJM) electricity market. 28 Nationally, total electric generation has generally remained consistent, but between 2010 and 2020, generation at coal-fired utilities has declined by 68%. 29 As a result, many of these units, on a daily basis, more recently have tended to cycle between high heat inputs, when electricity demand is high, and lower heat inputs or complete shutdowns, when demand is low. This cycling behavior can affect the ability of the EGUs to operate their SCRs because at lower heat inputs the temperature of the flue gas can drop below the operating temperature for which the SCR was designed. 30 Accordingly, this proposal seeks to establish limits that account for the technical limits on SCR operation that can result from this cycling behavior.

As alluded to above, PADEP attempted to address this cycling behavior by creating tiered emissions limits for different modes of operation based on the flue gas temperature, which its RACT II rule expressed as a transition from the 0.12 lb/MMBtu rate to much less stringent rates (between 0.35 and 0.4 lb/MMBtu, depending on the type of boiler) based on a temperature cutoff of 600 degrees, with the less stringent rate essentially representing a “no-SCR” mode ( i.e., an emission limit applicable at times when the SCR has been idled or bypassed and is not actively removing NO X ). The Third Circuit rejected this approach because the selection of the cutoff temperature was not sufficiently supported by the record. 31 The Third Circuit decision also questioned the need for a the less stringent rate, noting that nearby states do not have different emission rates based on inlet temperatures. 32

EPA has considered the Court's concerns and has further considered the practical and policy implications in structuring a tiered limit for these cycling EGUs based on operating temperature. As such, EPA has decided against proposing a tiered limit. The effectiveness of SCR does not drop to zero at a single temperature point and defining the minimum reasonable temperature range to begin reducing SCR operation for the purposes of creating an enforceable RACT limit is a highly technical, unit-specific determination that depends on several varying factors. EPA expects that defining a specific mode where SCR cannot or should not operate would be exceedingly complex and require information that EPA does not have, showing, for each unit, complete information on all the effects of varying temperature levels on SCR operation and emissions control performance. Such a tiered limit would also require extensive recordkeeping of the source's relevant operating parameters that form the basis of the tiers in order to be enforceable, as the Court noted in its ruling regarding the need to keep detailed temperature records.

EPA has an additional concern about addressing cycling operation through a tiered RACT limit based on operating temperature. It is reasonable to expect that, to the degree that the heat input of sources during cycling mode is under source control, the creation of a tiered limit that allows no-SCR operation at certain inlet temperatures would create an incentive for the source to cycle to temperatures where SCR is not required, in order to avoid SCR operating costs and potentially gain a competitive advantage. In the case of the Pennsylvania limits addressed by the Third Circuit's decision, there was no limit on how much time the units could spend in no-SCR mode. In section C of the TSD for this action, EPA shows that over the last decade, some affected sources have varied the gross load level to which they cycle down, hovering either just above or just below the threshold at which the SCR can likely operate effectively.

Depending on the unit, this slight change in electricity output could significantly affect SCR operation and the resulting emissions output. Though instances of cycling below SCR thresholds occurred in some cases prior to the implementation of Pennsylvania's tiered RACT limit and thus the limit may not be the sole driver of the behavior following its implementation, the limit certainly allows this behavior to occur. While EPA acknowledges the need for EGUs to operate at times in modes where SCR cannot operate, EPA believes its RACT limit should minimize incentives to do that, and a tiered rate structure that effectively has no limit on no-SCR operation tends to do the opposite.

On the other hand, EPA is also concerned about a RACT limit that treats these EGUs as always operating as baseload units by imposing a NO X emission rate that applies at all times but can technically be achieved only if the boiler is operating at high loads. Recent data indicates that these units are not operating as baseload units and are not likely to do so in the future. 33 Selecting the best baseload rate (the rate reflecting SCR operation in the optimal temperature range) and applying that rate at all times does not account for, and could essentially prohibit, some cycling operation of these units. Cycling has become more common at coal-fired EGUs because they are increasingly outcompeted for baseload power. In the past, these units were among the cheapest sources of electricity and would often run close to maximum capacity. Over time, other EGUs can now generate electricity at lower costs than the coal-fired units. Thus, the coal-fired units now cycle to lower loads during hours with relatively low system demand (often overnight and especially during the spring and fall “shoulder” seasons when space heating and cooling demand is minimized) when their power is more expensive than the marginal supply to meet lower load levels. Hence, they cycle up and down as load, and demand-driven power prices, rise and fall and they operate when the price meets or exceeds their cost to supply power. EPA acknowledges that cycling down to a no-SCR mode may sometimes happen, for example, when electricity demand drops unexpectedly, and other units provide the power at a lower cost. The consideration of the technical and economic feasibility of a given RACT limit should reflect, to the extent possible, consideration of the past, current, and future expected operating environment of a given unit. EPA seeks comment on how best to consider these feasibility issues to establish a rate for each unit that would reflect a reasonable level of load-following (cycling) ( e.g., a level consistent with similar SCR-equipped units) but that also accounts for the lower historic NO X rates that these units have achieved.

Given these concerns, EPA is proposing to express the RACT limits for these units using a weighted rate limit. The weighted rate incorporates both a lower “SCR-on” limit and a higher “SCR-off” limit. Through assignment of weights to these two limits based on the proportion of operation in SCR-on and SCR-off modes during a period of operation that represents a reasonably low amount of SCR-off operation, the SCR-on and SCR-off limits are combined into a single RACT limit that applies at all times. The weight given to the proposed SCR-off limit (established as described later in this section) has the effect of limiting the portion of time a cycling source can operate in SCR-off mode and incentivizes a source to shift to SCR-on mode to preserve headroom under the limit. While driving SCR operation, the weighted limit accommodates the need for an EGU to occasionally cycle down to loads below which SCR can operate effectively and does not prohibit no-SCR operation or dictate specific times when it must occur. In this way, the proposed approach avoids the difficulty of precisely establishing the minimum temperature point at which the no-SCR mode is triggered, effectively acknowledging the more gradual nature of the transition between modes where SCR is or is not effective. Finally, it is readily enforceable through existing Continuous Emission Monitoring Systems (CEMS), without the need for development of recordkeeping for additional parameters that define the SCR-off mode. The approach is described in more detail below.

As a starting point for developing the weighted rates for each unit, EPA calculated both “SCR-on” and “SCR-off” rates using historic ozone season operating data for the unit to determine when the SCR was likely running and when it was likely not running, and then established rates that represent the lowest emission limit that is reasonably available considering economic and technological feasibility. Using the EPA (or source) derived minimum SCR operation threshold as described in section III.A in this preamble, expressed as Megawatts (MW) in Table 1 in this preamble, EPA calculated average “SCR-on” and “SCR-off” rates for each unit based on historic operating data for that unit, when available, from 2003 to 2021. For detail on the development of these rates, see section D of the TSD for this action. The “SCR-on” rate is an average of all hours in which the SCR was likely running (operating above the threshold at which it can run the SCR with an hourly NO X emission rate below 0.2 lb/MMBtu) during each unit's third best ozone season from the period 2003 to 2021. The third best ozone season was identified based on the unit's overall average NO X emission rate during each ozone season from 2003 to 2021. This 18-year time period captures all the years of SCR operation for each facility, with the exception of Conemaugh, which only installed SCR in 2014. 34 EPA included all these years of data because the Third Circuit's decision questioned EPA's review of only certain years of emissions data for these sources in determining whether to approve Pennsylvania's RACT II NO X emission rate for these EGUs. The use of the 3rd-best year accounts for degradation of control equipment over time. EPA used a third best ozone season approach for the Revised CSAPR Update (86 FR 23054, April 30, 2021) and the proposed Good Neighbor Plan for 2015 Ozone NAAQS (87 FR 20036, April 6, 2022) (2015 Good Neighbor Plan). The “SCR-off rate” is an average of all hours in which the unit's SCR was likely not running (operating below the threshold at which it can run the SCR with an hourly NO X rate above 0.2 lb/MMBtu) during all ozone seasons from 2003-2021. All ozone seasons in the time period were used to increase the sample size of this subset of the data, as an individual ozone season likely contains significantly fewer data points of non-SCR operation.

Using the thresholds listed in Table 1 in this preamble, EPA then calculated the SCR-on and SCR-off “weights,” which represent the amount of heat input spent above (SCR-on) or below (SCR-off) the SCR threshold, for each EGU. For the weights, EPA evaluated data from the 2011 to 2021 ozone seasons and selected the year in which the EGU had its third highest proportion of heat input spent above the SCR threshold during this time period, using that year's weight (the “third best weight”) together with the SCR-on/SCR-off rates described previously to calculate the weighted rate. The years 2011-2021 were analyzed because they likely are representative of the time period that encompasses the years when the units began to exhibit a greater cycling pattern, and it is reasonable to expect that this pattern will continue for the foreseeable future.

Using these data, EPA is proposing emissions limitations based on the following equation:

The calculation for each limit is based on the third best weight for each unit over the 2011 to 2021 time period. Using the third best weight will eliminate the weights that represent years with the most frequent “no-SCR” cycling, especially the years in which cycling to just below the SCR threshold became more prevalent, in order to act as a limit on the potential for excessive no-SCR operation and incentivize SCR use. At the same time, using the third best weight will also minimize the weights that represent periods when minimal cycling was occurring ( i.e., baseload operation), in order to ensure that the limit is not forcing cycling to be infeasibly constrained. The third best weight is therefore consistent with the RACT requirement: It represents the lowest rate reflecting SCR application, taking both reasonable technological and economic feasibility into account.

Table 2 in this preamble presents the proposed NO X Emission RACT rate limits for each facility that result from the application of the weighted approach. Table 2 in this preamble also presents the range of rates that would be generated using minimum ( i.e., more baseload) and maximum ( i.e., more cycling) weights over the period. EPA is taking comment on its proposed limits, and is also soliciting comment on all the values in this range as potential alternatives. More details about the weighted rates analysis can be found in section D of the TSD for this action.

The resulting NO X emission rate limits will be based on a 30-day rolling average, and will apply at all times, including during operations when exhaust temperatures are too low for the SCR to operate, or operate optimally. For facilities with more than one unit, the proposed limit will allow facility-wide averaging for compliance, but the average limit will be based on the weighted rate achieved by the best performing unit. Using the best performing unit as the basis for RACT is appropriate, as it would prioritize increased utilization of the best performing units in SCR-on mode. EPA is proposing a 30-operating day, rolling average for this rate-based ( i.e., lb/MMBtu) limit. EPA and many states have used such 30-day average limits for this type of limit, where the measured daily lb/MMBtu rate can vary significantly depending on the way the boilers and SCRs are operated in a day, but the limit is designed to apply at all times. A 30-day average “smooths” this variability by averaging the current value with the prior values over a rolling 30-day period to determine compliance. While some period of lb/MMBtu values over the target rate can occur without triggering a violation, they must be offset by corresponding periods where the lb/MMBtu rate is lower than the target rate ( i.e., the 30-day rolling average rate). Such averaging periods have precedent not only in Federal rulemaking, 35 but in EPA's approval of SIPs. 36 Such a limit can represent RACT so long as it is based on 30-day periods that represent the lowest rate the source is capable of meeting over such period through the application of control technology that is reasonably available considering technological and economic feasibility. When EPA previously provided presumptive RACT limits for coal-fired EGUs, it expressed them as 30-day averages. 37 A 30-day average is similarly appropriate here, as the proposed rate limits here would apply at all times, throughout the year, to units that are expected to exhibit cycling operation as described previously. While there may be periods (typically when cycling down to where the SCR cannot operate effectively) where the lb/MMBtu rate is exceeded, these periods are limited in time by the weighted rate, and must be offset by periods where the lb/MMBtu rate is correspondingly lower to meet 30-day average limit.

EPA is also proposing a unit-specific daily NO X mass emission limit ( i.e., lb/day) to complement the weighted facility-wide 30-day NO X emission rate limit and further ensure RACT is applied continuously. High emissions days are a concern, given the 8-hour averaging time of the underlying 1997 and 2008 ozone NAAQS. This proposed daily NO X mass emission limit was calculated by multiplying the proposed facility-wide 30-day rolling average NO X emission limit (in lb/MMBtu) by each unit's heat input maximum permitted rate capacity (in MMBtu/hr) by 24 hours. While the 30-day average rate limit ensures that SCR is operated where feasible while reasonably accounting for cycling, EPA is concerned that units meeting this limit might still occasionally have higher daily mass emissions on one or more days where no or limited SCR operation occurs, which could trigger exceedances of the ozone NAAQS if these high mass emissions occur on days conducive to ozone formation, such as especially hot summer days. Notably, the OTC also raised the issue of daily emission limits in its CAA section 184(c) petition.

For example, in PADEP's “Technical Evaluation for Case-by-Case RACT, Conemaugh Generating Station,” the performance of Conemaugh Unit 1 during the month of April 2020 was evaluated. PADEP determined that for most of the month, the unit ran at approximately 75% heat capacity, yet no reagent was injected on most days. Daily NO X mass emissions were predictably high. For example, on April 2, 2020, Unit 1 ran at roughly 75% heat capacity for about 20 out of the 24 hours. The NO X emissions rate over that period was roughly 0.275 lb/MMBtu. 38 Twenty hours at 75% heat capacity at 0.275 lb/MMBtu results in approximately 34,000 lbs of NO X emitted. In contrast, twenty hours at 75% heat capacity at the proposed 0.091 lb/MMBtu weighted rate would result in much less NO X being emitted: Approximately 11,260 lbs. The addition of a unit-specific daily mass emission limit at an appropriate level will address concerns that a facility-wide 30-day average emission rate, by itself, may not curtail certain days where higher emission rates result in higher mass emissions of NO X . These foregone emissions reductions could have serious NAAQS implications on days where high ozone levels are likely to occur. A properly operating SCR can reduce NO X emissions by between 50% to 90%. For example, looking at the same Conemaugh Unit 1 data on a different day, September 30, 2017, the unit operated around 50% load for the entire day, but the facility apparently elected to operate the SCR since the NO X emission rate for that day was 0.05 lb/MMBtu, which is 82% lower than the April 2, 2020, NO X rate.

For these reasons, EPA believes it is reasonable to propose an additional unit-specific lb/day mass limit as an additional safeguard. The proposed daily mass limit would be an additional constraint on no-SCR operation within a single day. It provides for some boiler operation without using the SCR, which may be unavoidable during part of any given day, but it constrains such operation because the mass limit will necessitate SCR operation (for example by raising heat input to a level where the SCR can operate) if the unit is to continue to operate while remaining below this limit. This provides greater consistency with the RACT definition. Table 3 in this preamble shows the proposed unit-specific NO X mass limits, which are to be met on a 24-hr basis.

Table 4 in this preamble shows the reductions these proposed limits would realize when compared to 2021 emissions data.

EPA is proposing to determine that the limits discussed in the prior section are technologically feasible, in part because the limits have been met by each of the facilities affected by the proposed FIP. During the process of reviewing PADEP's proposed source specific permits, EPA evaluated past performance of the units in question, as shown in Appendix 1 of the TSD for this action. EPA looked at data from the best and third-best ozone seasons (second best for Conemaugh) over its entire record of operation with SCR, as well as data from just recent ozone seasons (2010-2020), with 2019 shown individually. For each of those time periods, EPA calculated the best daily average, the mean daily average, and the 99th percentile of daily average NO X emissions.

As previously discussed, RACT is not the lowest rate achievable by a particular source (or source category). Nor, as the Third Circuit pointed out, are RACT requirements satisfied by a limit that represents “. . . an average of the current emissions being generated by existing systems.” Sierra Club at 14-15. Rather, as previously discussed, RACT is the lowest emission limit that a particular source is capable of meeting by the application of the control technology that is reasonably available considering technological and economic feasibility. By considering historical data that represent the best performing years, as well as more recent years where the changing realities of electrical generation have presented legitimate technological challenges to meeting those best rates, EPA's weighted rate approach is reasonable, and consistent with the CAA's RACT requirements. It represents a considerable improvement over the status quo, and still allows these sources the flexibility to address fluctuating power demands from the grid operator, so long as operation without SCR is reasonably constrained.

Economic feasibility in the context of RACT is not a “bright-line” or “one-size-fits-all” test with a clearly established threshold between what is and what is not economically feasible. Rather, it involves a case-by-case evaluation, and “. . . is largely determined by evidence that other sources in a source category have in fact applied the control technology in question.”  40 In the case of these five facilities, because the controls are already installed (no costs to install or retrofit control equipment), the economic analysis partially involves comparing the emissions limitations achieved by similar sources which operate under similar electrical dispatch constraints, as well as considering the extent to which all of these units have in fact demonstrated an ability to meet the proposed limits in the past. As discussed in more detail below, EPA's cost analysis was consistent with the national, fleetwide approach applied in the context of the CSAPR rulemakings, and the 2015 Good Neighbor Plan. Additionally, EPA has made clear that economic feasibility should not be conflated with affordability: “Economic feasibility rests very little on the ability of a particular source to `afford' to reduce emissions to the level of similar sources. Less efficient sources would be rewarded by having to bear lower emission reduction costs if affordability were given high consideration.”  41

Furthermore, EPA reviewed operating and emissions data of EGUs in neighboring states which are also contractually obligated to the PJM Interconnection and found that there was nothing unique about the operating patterns of the units in Pennsylvania. EPA performed an analysis comparing certain data for each of the Pennsylvania SCR-equipped EGUs to data for the remaining SCR-equipped coal-fired EGUs in Maryland (Brandon Shores 1,2, Morgantown 1,2, and Wagner 3) and Delaware (Indian River 4). The data were compiled into a spreadsheet which is included in the docket for this action. 42 The data cover the period from 2000 through 2020. The spreadsheet looks at the extent to which changes in units' average ozone season NO X emission rates over time can be explained by changes in their ozone season operating patterns— i.e., operating fewer hours and spending a larger fraction of the remaining operating hours at lower load levels.

EPA identified a multi-year baseline period after installation of each analyzed unit's SCR when operation of the unit seemed fairly stable and the NO X emission rate showed fairly consistent SCR optimization. These periods vary by unit and range from 2 years to 9 years across parts of the 2001-2013 time period. For each unit, EPA then compared the averages of the unit's seasonal average NO X emission rate, seasonal total operating hours, and seasonal average load level per operating hour during the baseline period to the same unit's averages across the 2017-2019 period. EPA did not identify a baseline period or perform the same specific comparisons for Conemaugh units 1 and 2 because these units' SCRs were not installed until 2015. The comparisons support several observations:

• Except for Keystone 1-2, all the units in all three states have experienced moderate to very large decreases in seasonal total operating hours—from 19% to 74%. By comparison, Keystone 1 and 2's operating hours decreased only 3% and 7%. (Conemaugh's pattern of changes in operating hours is similar to Keystone's).

• Except for Keystone 1 and 2 and Conemaugh 1 and 2, all the units in Pennsylvania and Maryland have also experienced moderate to large decreases in seasonal average load levels per operating hour—from 20% to 37%. By comparison, Keystone 1 and 2's average load levels per operating hour decreased only 6% and 9%. (Conemaugh's pattern of changes is similar to Keystone's, and Indian River 4 had a 10% decrease).

• Except for Homer City 3 (and Conemaugh 1 and 2), all the Pennsylvania units experienced large increases in seasonal average NO X emission rates from the baseline period to the 2017-2019 period—from 59% to 130%. Comparison to the Maryland units calls into question whether these emission rate increases can reasonably be attributed to changes in either the units' total operating hours or the units' average load levels per operating hour, because the Maryland units—which had changes in both of these variables much larger than Keystone 1 and 2 and comparable to the other Pennsylvania units—all experienced decreases in average emission rates from −6% to −25% (Indian River 4 experienced an emission rate increase of 21%, but stayed below 0.085 lb/MMBtu, and Homer City 3 experienced an emission rate decrease of −2%.).

In summary, the comparisons show that all five Maryland units (and to a lesser extent the one Delaware unit) have experienced comparable or greater changes in total operating hours and average load levels per operating hour over time than the Pennsylvania units without a deterioration in NO X emission rates comparable to the deterioration shown by most of the Pennsylvania units. 43

Fixed operation and maintenance (FOM) costs, such as operator salaries, are independent of the operation of the control system and are incurred by the operator regardless of variations in control utilization. Variable operation and maintenance (VOM) costs are proportional to the quantity of waste gas processed by the control system. Because the SCRs at each EGU have already been installed and have been operated for years (albeit in a less than optimal fashion), FOM costs for the SCRs have already been incurred. Therefore, the economic feasibility analysis for this proposal need only consider the VOM costs associated with increased use of the SCRs. The most significant of these costs is the cost of the additional reagent needed to meet the proposed NO X limits and the additional cost of more frequent catalyst replacement and maintenance that might occur from greater use of the SCRs (compared to the status quo) to meet the lower proposed NO X limit. EPA has recently evaluated VOM costs associated with increased use of SCRs in a number of national rulemaking actions related to the CAA's interstate transport requirements, including most recently the proposed 2015 Good Neighbor Plan. In the “EGU NO X Mitigation Strategies Proposed Rule TSD” (2015 Good Neighbor Plan TSD) for the proposed rulemaking (included in the docket for this action), EPA used the capital expenses, and operation and maintenance costs for installing and fully operating emission controls based on the cost equations used within the Integrated Planning Model (IPM) that were researched by Sargent & Lundy, a nationally recognized architect/engineering firm with EGU sector expertise. From this research, EPA created a publicly available Excel-based tool called the Retrofit Cost Analyzer (Update 1-26-2022) (Retrofit Cost Analyzer) that implements these cost equations. 44

In the TSD for the 2015 Good Neighbor Plan, EPA used the Retrofit Cost Analyzer to estimate the cost of additional reagent, as well as additional VOM costs, including catalyst replacement and disposal. Based on those calculations EPA estimated a representative marginal cost of optimizing SCR controls to be approximately $1,600 per ton, consistent with its estimation in the Revised CSAPR Update for this technology. Additionally, depending on a unit's control operating status, the representative cost at the 90th percentile unit (among the relevant fleet of coal units with SCR covered in this rulemaking) ranges between $900 and $1,700 per ton. EPA evaluated all coal-fired units with SCR and determined that for those units with SCRs that are already partially operating, the cost of optimizing is often much lower than $1,600 per ton and is often under $900 per ton. (87 FR 20077; April 6, 2022).

EPA notes that while there is not a direct, one-to-one correlation, the cost of reagents is impacted directly by fluctuations in agricultural fertilizer markets. Fertilizer costs have risen considerably since this analysis was performed. In March of 2022, the cost of anhydrous ammonia was listed at roughly $1500/ton, and urea at roughly $900/ton. 45 The analysis performed for the 2015 Good Neighbor Plan to arrive at a reagent cost of $500/ton involved calculations using the cost of urea. 46 However, all of the sources covered by this proposed FIP currently use ammonia for reagent injection.

Using the proposed NO X limits and associated predicted NO X reductions in Table 4 in this preamble, and the assumption from the 2015 Good Neighbor Plan TSD  47 that the chemical reaction requires 0.57 tons of ammonia for each ton of NO X reduced, we calculated an updated $/ton of NO X removed using current (March 2022)  48 ammonia costs for the five facilities:

As previously noted, EPA's general evaluation of the costs of optimizing an existing and already operating SCR in the 2015 Good Neighbor Plan TSD was estimated to be from $900/ton to $1600 per ton of NO X removed in 2016 dollars. This includes reagent costs, as well as other VOM costs. EPA calculated the reagent-only portion of those costs to be $500 per ton of NO X removed. Therefore, the remaining, non-reagent VOM costs were determined to be $400-$1100 per ton. While other VOM costs may also have risen since this analysis was conducted, it is unlikely that they have been as volatile as soaring reagent costs, and EPA currently does not have reliable, updated information beyond what was presented in the 2015 Good Neighbor Plan on how VOM costs may have risen. Nevertheless, EPA believes that it is unnecessary to re-evaluate the non-reagent VOM costs for the purposes of this bounding analysis, aside from converting the figures to 2022 dollars, because EPA predicts that the effects of any change in non-reagent VOM would be minimal on the ultimate conclusion. Converting the higher non-reagent VOM cost of $1100/ton NO X removed to 2022 dollars provides a revised non-reagent VOM cost of $1300/ton of NO X removed. Combining this updated non-reagent cost and the average reagent cost of $854/ton NO X removed based on updated reagent prices (see Table 5 in this document), EPA estimates that the cost of optimizing the existing SCRs in use at each facility covered by this proposed FIP is approximately $2154/ton of NO X removed. EPA finds this cost to be reasonable by any metric, and determine, therefore, that the proposed limits are economically feasible. 49

Additionally, while the $1600/ton of NO X removed cost estimate used in the 2015 Good Neighbor Plan was presented on a fleetwide basis, the Retrofit Cost Analyzer estimated individual costs for Homer City Units 1-3, Keystone Units 1 and 2, Conemaugh Unit 1, and Montour, using $350/ton for a 50% solution of urea. Those costs (in 2021 dollars) ranged from a low of $980/ton of NO X removed for Homer City 3, to a high of $1152/ton of NO X removed for Conemaugh. 50 To assess the impact of the present, historic high reagent costs, EPA re-ran the Retrofit Cost Analyzer with a reagent cost of $1500/ton (of ammonia). 51 EPA notes that we did not modify other parameters in the Retrofit Cost Analyzer to directly convert urea use to ammonia use. Rather, we took the conservative approach of using the highest fertilizer cost in a bounding analysis to evaluate whether past estimates of the cost effectiveness of increased reagent injection were still reasonable. The resulting $/ton of NO X removed estimates ranged from $2590/ton of NO X removed for Homer City 3, to $2757/ton of NO X removed for Conemaugh. 52 Given the likelihood of reagent costs returning to lower, historical levels, and the fact that the remaining costs in the analyses were selected at the 90th percentile, EPA believes this bounding analysis to be reasonable and conservative, and that these cost estimates, though higher than the fleetwide averages discussed above, continue to be economically feasible.

EPA notes that in each of the draft permits submitted by PADEP, a number of additional control technologies were evaluated by PADEP in addition to SCR, but were determined to be either technologically or economically infeasible. For example, in all cases except Montour, PADEP determined that upgraded low NO X burners were economically infeasible. 53 PADEP determined that the costs per ton of NO X removed ranged from $4,077 for Unit 1 at Conemaugh, to $15,129 for Unit 3 at Homer City. EPA is not evaluating PADEP's determinations related to economic feasibility in this action. However, we did review this information for purposes of developing the proposed FIP, and note that PADEP's source-specific analyses for ultra-low NO X burners are higher than the fleet wide estimate of $1600/ton of NO X removed by optimizing SCR use that EPA derived in the 2015 Good Neighbor Plan. 54 Furthermore, neither the facilities nor PADEP considered the potential substantial impact that state of the art combustion controls can have on reducing operating costs of SCRs, including extended catalyst life and reducing reagent consumption: “Installation of front-end low-NO X combustion systems or upgrades can essentially reduce total ammonia consumption by as much as 45% and is a viable, cost-effective option to lowering plant cost over the long term.”  55

Additionally, PADEP also evaluated a number of post combustion technologies in their draft permits for these five facilities. These post-combustion technologies increase the temperature of the flue gas entering the SCR. Such technologies could, in the context of a weighted limit approach, help lower the SCR-off weight by allowing a greater range of SCR-on operating conditions. These include economizer bypass, “V-Temp,” and flue gas reheat. Economizer bypass is installed at Homer City, and the V-Temp system, which similarly reduces heat consumption in the economizer and thus increases inlet temperatures at the SCR, is installed at Conemaugh, but was not used in 2019. PADEP determined that continued operation of V-Temp at Conemaugh was not technically feasible due to cycling operations. In the other cases, PADEP determined installation to be technologically infeasible. Flue gas reheat was not fully analyzed for technological and economic feasibility at any of the sources. Additionally, no analysis was presented to determine whether simply running at moderately higher loads could be an economically feasible method to achieve lower emissions rates. Finally, PADEP also determined in each case that it appeared that the boilers had not been tuned in a manner that would maximize NO X reductions. As part of this proposal, EPA did not evaluate these technologies in the context of our RACT analysis. As stated previously, EPA is proposing that the optimization of the already installed equipment (the SCR) at each of these sources represents RACT. EPA is proposing rates that greatly reduce the 30-day NO X emissions in relation to past performance. Our presumption is that the facilities have the flexibility to change their operations to emit less NO X per unit of heat input, and we identify these technologies as additional ways for the facilities to do so, rather than requiring them as RACT. Moreover, we note that multiple control schemes cannot always be implemented simultaneously and do not always necessarily result in cumulative reductions.

EPA has included proposed recordkeeping and reporting requirements in the regulatory language for this proposed FIP. The purpose of the requirements is to ensure that each of the facilities subject to the FIP can demonstrate compliance with their respective RACT limits as finalized. EPA is proposing to require that each facility submit a report to EPA every six months containing, among other things, the following: Unit-specific daily operating time (hours); unit-specific daily NO X mass emissions (lbs); unit-specific daily heat input (MMBtu); unit-specific daily NO X emission rate (lb/MMBtu); facility-wide 30-day rolling average NO X emission rate (lb/MMBtu). The proposed regulatory language also defines certain terms and specifies the method for calculating the facility-wide 30-day rolling average NO X emission rate. These reports are to be submitted to EPA within 30 days after the end of each six month reporting period. In addition, the proposed regulatory language requires the submission of a report containing certain information to EPA within 10 business days if the source violates its 30-day rolling average NO X limit or daily mass limit three or more times within any 30-day period. The EPA is soliciting comment on whether the six-month reporting period should be shorter (quarterly) and also on other possible ways to improve the proposed recordkeeping and reporting requirements included in this FIP.

Based on the information presented in section III in this preamble, in 2021, NO X emissions would have been reduced 6,361 tons. Using $1600/ton of NO X removed cost estimate as in the 2015 Good Neighbor Plan would result in annual aggregate cost of approximately $10 million dollars for 2021. As discussed in section III in this preamble, EPA believe that a specific analysis of individual plants would result in a lower estimate.

In order to estimate the benefits of this rulemaking, EPA used a “benefit per ton” (BPT) approach. EPA has applied this approach in several previous Regulatory Impact Analyses (RIA)  56 in which the economic value of human health impacts is derived using previously established source-receptor relationships from photochemical air quality modeling. 57 The rule will reduce emissions of NO X , a pollutant that is a precursor to both fine particulate matter (PM 2.5 ) and ground-level Ozone; for this reason, we quantify the benefits of reducing each pollutant. These BPT estimates provide the total monetized human health benefits (the sum of premature attributable deaths and premature morbidity for either PM 2.5 or Ozone) of reducing 1 ton of NO X from a specified source. This analysis draws upon benefit per-ton values quantified for the Electricity Generating Unit (EGU) sector in Pennsylvania. The method used to derive these estimates is described in the “Technical Support Document on Estimating the Benefit per Ton of Reducing Directly-Emitted PM 2.5, PM 2.5 precursors and Ozone Precursors from 21 Sectors and its precursors from 21 sectors.”  58 One limitation of using the BPT approach is an inability to provide estimates of the health benefits associated with exposure to nitrogen dioxide, the ambient concentrations of which may also change as a result of this rulemaking. Another limitation is that the photochemical-modeled emissions of the industrial point source sector-attributable PM 2.5 concentrations used to derive the BPT values may not match the change in air quality resulting from the emissions controls imposed by this FIP. Finally, an additional limitation of this analysis is that we expect in future years that the annual benefits (and cost) estimates will fall because some of these units plan to retire by 2028. Table 6 in this preamble presents the estimated economic value ranges of this proposed action.

Additional information about these statutes and Executive orders can be found at http://www2.epa.gov/laws-regulations/laws-and-executive-orders.

This action is not a significant regulatory action and was therefore not submitted to the Office of Management and Budget (OMB) for review.

This proposed action does not impose an information collection burden under the provisions of the Paperwork Reduction Act (PRA). 59 A “collection of information” under the PRA means “the obtaining, causing to be obtained, soliciting, or requiring the disclosure to an agency, third parties or the public of information by or for an agency by means of identical questions posed to, or identical reporting, recordkeeping, or disclosure requirements imposed on, ten or more persons, whether such collection of information is mandatory, voluntary, or required to obtain or retain a benefit.”  60 Because this proposed rule includes RACT reporting requirements for five facilities, the PRA does not apply.

The Regulatory Flexibility Act (RFA) generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations and small governmental jurisdictions.

For purposes of assessing the impacts of this proposed rule on small entities, small entity is defined as: (1) A small business as defined by the Small Business Administration's (SBA) regulations at 13 CFR 121.201; (2) a small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and (3) a small organization that is any not-for-profit enterprise which is independently owned and operated and is not dominant in its field.

After considering the economic impacts of this proposed rule on small entities, I certify that this action will not have a significant economic impact on a substantial number of small entities under the RFA. This rulemaking does not impose any requirements or create impacts on small entities as no small entities are subject to the requirements of this proposed rule.

Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public Law 104-4, establishes requirements for Federal agencies to assess the effects of their regulatory actions on state, local and tribal governments and the private sector. Under section 202 of UMRA, the EPA generally must prepare a written statement, including a cost-benefit analysis, for final rules with “Federal mandates” that may result in expenditures to state, local, and tribal governments, in the aggregate, or to the private sector, of $100 million or more (adjusted for inflation) in any one year.

The EPA has determined that this proposed rule does not contain a Federal mandate that may result in any expenditures by state, local or tribal governments, and as explained in this document, the cost to the private sector of the requirements will not exceed the inflation-adjusted UMRA threshold of $100 million  61 in any one year. Further, this proposed action will not significantly or uniquely affect small governments.

Executive Order 13132, Federalism, 62 revokes and replaces Executive Orders 12612 (Federalism) and 12875 (Enhancing the Intergovernmental Partnership). Executive Order 13132 requires the EPA to develop an accountable process to ensure “meaningful and timely input by State and local officials in the development of regulatory policies that have federalism implications.”  63 “Policies that have federalism implications” is defined in the Executive order to include regulations that have “substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government.”  64 Under Executive Order 13132, the EPA may not issue a regulation “that has federalism implications, that imposes substantial direct compliance costs, . . . and that is not required by statute, unless [the Federal Government provides the] funds necessary to pay the direct [compliance] costs incurred by the State and local governments,” or the EPA consults with state and local officials early in the process of developing the final regulation. 65 The EPA also may not issue a regulation that has federalism implications and that preempts state law unless the agency consults with state and local officials early in the process of developing the final regulation.

This action does not have federalism implications. The proposed FIP will not have substantial direct effects on the states, on the relationship between the National Government and the states, or on the distribution of power and responsibilities among the various levels of government, as specified in Executive Order 13132. Thus, Executive Order 13132 does not apply to this action.

Executive Order 13175, entitled “Consultation and Coordination with Indian Tribal Governments,” requires the EPA to develop an accountable process to ensure “meaningful and timely input by tribal officials in the development of regulatory policies that have tribal implications.”  66 This proposed rule does not have tribal implications, as specified in Executive Order 13175. It will not have substantial direct effects on tribal governments. Thus, Executive Order 13175 does not apply to this rulemaking.

The EPA interprets Executive Order 13045 as applying only to those regulatory actions that concern environmental health or safety risks that the EPA has reason to believe may disproportionately affect children, per the definition of “covered regulatory action” in section 2-202 of the Executive order. This action is not subject to Executive Order 13045 because it implements a previously promulgated health-based Federal standard. Further, the EPA believes that the ozone-related benefits from this proposed rule will further improve children's health.

This action is not subject to Executive Order 13211 (66 FR 28355 (May 22, 2001)), because it is not a significant regulatory action under Executive Order 12866.

Section 12 of the National Technology Transfer and Advancement Act (NTTAA) of 1995 requires Federal agencies to evaluate existing technical standards when developing a new regulation. Section 12(d) of NTTAA, Public Law 104-113, 12(d) (15 U.S.C. 272 note) directs the EPA to consider and use “voluntary consensus standards” in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards ( e.g., materials specifications, test methods, sampling procedures and business practices) that are developed or adopted by voluntary consensus standards bodies. NTTAA directs the EPA to provide Congress, through OMB, explanations when the agency decides not to use available and applicable voluntary consensus standards.

This proposed rulemaking does not involve technical standards. Therefore, EPA is not considering the use of any voluntary consensus standards.

Executive Order 12898 establishes Federal executive policy on environmental justice. 67 Its main provision directs Federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies and activities on minority populations and low-income populations in the United States.

The EPA believes that this action does not have disproportionately high and adverse human health or environmental effects on minority populations, low-income populations and/or indigenous peoples, as specified in Executive Order 12898. EPA reviewed the Regulatory Impact Analysis (RIA) prepared for the recently proposed 2015 Ozone NAAQS transport FIP, and in particular the Ozone Exposure Analysis at section 7.4 of the RIA. 68 Although that analysis projected reductions in overall AS-MO3 ozone concentrations in each state for all affected demographic groups resulting from newly proposed limits on EGUs and non-EGUs (see Figure 7-3 of the RIA), it also found that emission reductions from only EGUs would result in national reductions in AS-MO3 ozone concentrations for all demographic groups analyzed (see Figure 7-2 of the RIA). In summation, that RIA concluded that the proposed FIP is expected to lower ozone in many areas, including residual ozone nonattainment areas, and thus mitigate some pre-existing health risks of ozone across all populations evaluated (RIA, p. 7-32). Further, EPA reviewed an analysis of vulnerable groups near the Conemaugh, Homer City, and Keystone EGUs found in the TSD for EPA's proposed disapproval of the S0 2 attainment plan for the Indiana, PA S0 2 nonattainment area. 69

Based on EPA's review of those documents, and consideration of the content of this proposed FIP including the proposed NO X limits, EPA believes that this proposed FIP will serve to lower ozone levels in many areas, including residual ozone nonattainment areas, and thus mitigate some pre-existing health risks of ozone.

For the reasons discussed in the preamble, 40 CFR part 52 is proposed to be amended as follows: