This proposal is issued under the Order (7 CFR part 1218). The Order is authorized under the Commodity Promotion, Research, and Information Act of 1996 (1996 Act) (7 U.S.C. 7411-7425).

Executive Orders 12866 and 13563 direct agencies to assess all costs and benefits of available regulatory alternatives and, if regulation is necessary, to select regulatory approaches that maximize net benefits (including potential economic, environmental, public health and safety effects, distributive impacts and equity). Executive Order 13563 emphasizes the importance of quantifying both costs and benefits, reducing costs, harmonizing rules and promoting flexibility. This action falls within a category of regulatory actions that the Office of Management and Budget (OMB) exempted from Executive Order 12866 review.

This action has been reviewed in accordance with the requirements of Executive Order 13175, Consultation and Coordination with Indian Tribal Governments. AMS has assessed the impact of this proposed rule on Indian tribes and determined that this rule would not have tribal implications that require consultation under Executive Order 13175. AMS hosts a quarterly teleconference with tribal leaders where matters of mutual interest regarding the marketing of agricultural products are discussed. Information about the proposed changes to the regulations will be shared during an upcoming quarterly call, and tribal leaders will be informed about the proposed revisions to the regulation and the opportunity to submit comments. AMS will work with the USDA Office of Tribal Relations to ensure meaningful consultation is provided as needed with regards to this change to the Order.

This proposal has been reviewed under Executive Order 12988, Civil Justice Reform. It is not intended to have retroactive effect. Section 524 of the 1996 Act (7 U.S.C. 7423) provides that it shall not affect or preempt any other Federal or State law authorizing promotion or research relating to an agricultural commodity.

Under section 519 of the 1996 Act (7 U.S.C. 7418), a person subject to an order may file a written petition with USDA stating that an order, any provision of an order, or any obligation imposed in connection with an order, is not established in accordance with the law, and request a modification of an order or an exemption from an order. Any petition filed challenging an order, any provision of an order, or any obligation imposed in connection with an order, shall be filed within two years after the effective date of an order, provision, or obligation subject to challenge in the petition. The petitioner will have the opportunity for a hearing on the petition. Thereafter, USDA will issue a ruling on the petition. The 1996 Act provides that the district court of the United States for any district in which the petitioner resides or conducts business shall have the jurisdiction to review a final ruling on the petition, if the petitioner files a complaint for that purpose not later than 20 days after the date of the entry of USDA's final ruling.

This proposal invites comments on changes in the Council's membership under the Order. The Council administers the Order with oversight by USDA. Under the program, assessments are collected from domestic producers and importers and used for research and promotion projects designed to increase the demand for highbush blueberries. This proposed action would remove the first-handler member and alternate position and add two exporter member and alternate positions. This would help ensure that the Council reflects the distribution of domestic blueberry production and imports into the United States (U.S.) Conforming changes would be made to the nomination procedures. This proposal would also allow members and alternates to remain in office until a successor is appointed. This change would permit the Council to continue administration of the Order should appointments be delayed beyond the specified term of office. The two actions were unanimously recommended by the Council at its meetings on November 18, 2020 and June 9, 2021.

Section 1218.40(a) of the Order currently specifies that the Council be comprised of no more than 20 members and alternates appointed by the Secretary of Agriculture (Secretary). Twelve of the 20 members and alternates are producers. One producer member and alternate are from each of the following regions within the U.S.: Region #1 Western Region; Region #2 Midwest Region; Region #3 Northeast Region; and Region #4 Southern Region. One producer member and alternate are from each of the top eight blueberry producing states, based upon the average of the total tons produced over the previous three years. Currently, these states include California, Florida, Georgia, Michigan, New Jersey, North Carolina, Oregon, and Washington.

Of the remaining eight Council members and alternates, four members and alternates are importers. Two members and alternates must be an exporter, defined in § 1218.40(a)(4) as a blueberry producer currently shipping blueberries into the U.S. from the two largest foreign blueberry production areas, based on a three-year average (currently Chile and Canada). One member and alternate must be a first handler, defined in § 1218.40(a)(5) as a U.S. based independent or cooperative organization which is a producer/shipper of domestic blueberries. Finally, one member and alternate must represent the public. The public member representation on research and promotion boards is optional as provided for in the 1996 Act.

Section 1218.40(b) of the Order specifies that, at least once every five years, the Council will review the geographical distribution of the production of blueberries in the United States and the quantity of imports. The review is conducted through an audit of state crop production figures and Council assessment records. If warranted, the Council will recommend to the Secretary that its membership be altered to reflect changes in the geographical distribution of domestic blueberry production and the quantity of imports.

The Council met on November 18, 2020 and then again on June 9, 2021, to review domestic production data, import data, and assessment data for the past three years (2017-2019). This data is summarized in Table 1 below:

As shown in Table 1, the quantity of imported blueberries, as well as import assessments collected, has increased in recent years.

In that time, there has been a substantial increase of imported product from both Peru and Mexico, with Peru exports into the U.S. surpassing Canada in 2019, as shown in Table 2.

In 2015, the Council, after reviewing import and domestic production and assessment data, recommended changes to the membership; one such change included adding an additional exporter seat. At that time, data indicated considerable increased imports from Chile. The addition of the second exporter member allowed exporters from both Chile and Canada, the two countries shipping the greatest volume of blueberries into the U.S., to be represented on the Council. The Council took a similar approach when reviewing and recommending this proposed change in membership. It recognized the significant volume of imports from Peru and Mexico, discussing the need to add representatives from those production areas to the Council. Given the decision to try to maintain its current size and based on the data reviewed, it concluded it was important to have foreign producer representation similar to the structure of the state producer representation. Therefore, it recommended the addition of two exporter members. Four exporter member positions would provide the four largest foreign producing areas importing into the U.S., which represents ninety-five percent of the total volume of blueberries imported into the U.S., a voice on the Council. This would realign the Council's membership to better reflect the distribution of domestic production and the quantity of imports into the U.S.

The Council conducts nominations two out of every three years. The Council is currently conducting nominations for seven member and alternate positions (year-one cycle) whose three-year term of office begins January 1, 2022, ending December 31, 2024. These include the four regional producer members, one exporter member, one importer member, the public member, and respective alternates. The Council will conduct nominations in 2022 for 13 member and alternate positions (year-two cycle) whose three-year term of office begins January 1, 2023, ending December 31, 2025. This would include one member from each of the top eight producing states, three importer members, one exporter member, the first-handler member, and respective alternates. To help ensure a smooth transition, while aligning with the Council's nomination schedule, the term of office for the recommended additional exporter member positions would begin January 1, 2023. Therefore, solicitation for the two additional exporter position nominees would be included in the nominations scheduled to be conducted in 2022. Since the first-handler member position is being replaced by one of the exporter positions, nominations for this position would not be conducted during the 2022 solicitation period. The first-handler member and alternate member positions would terminate December 31, 2022.

USDA has recommended that the initial term of office for the two additional exporter positions would be two years, instead of the prescribed three-year term of office for all Council member and alternate positions. The additional two exporter member and alternate term of office would begin January 1, 2023, ending December 31, 2024. As noted above, the Council conducts nominations two out of every three years, with seven positions to be filled in year one, and thirteen in year two. With including the nominations for the exporter positions in the year-two cycle, total positions to be filled would be 14 of the 21-member Council. Having an initial two-year term would align these two additional exporter positions with the year-one nomination cycle, reestablishing the distribution between the two nomination cycles. Year-one nomination cycle would include solicitation for nine positions: Four regional producer member positions, one importer member position, three exporter member positions, one public member position, and respective alternates. The year-two nomination cycle would include solicitation for 12 positions: One member from each of the top eight producing states, three importer members, one exporter member, and respective alternates.

The 2022, 20-member Council would consist of one producer member from each of the four regions (Western, Midwest, Northeast, Southern), one producer member from each of the top eight producing states, four importer members, two exporter members, first-handler member, public member, and respective alternates.

The 2023 and subsequent 21-member Council would consist of one producer member from each of the four regions (Western, Midwest, Northeast, Southern), one producer member from each of the top eight producing states, four importer members, four exporter members, one public member, and respective alternates. 7 CRF 1218.40 would be revised accordingly.

Section 1218.41 establishes the procedures for nominations to obtain Council nominees for appointment by the Secretary. Section 1218.41(c) provides for the nomination process for importer, exporter, first-handler, and public member and alternate positions. Section 1218.41(d) requires producer, handlers, and importer nominees to be compliant with the order provisions regarding payment of assessments and filing of reports. With the replacement of the first-handler position with two exporter positions, references to first-handler member would be removed from these sections.

Section 1218.42 provides that Council nominations and appointments will take place in two out of every three years, with each term of office ending on December 31, and new terms of office beginning January 1. The Council recommended allowing members and their alternates to remain in office until a successor is appointed. Currently, if successors are not appointed by the January 1 date, those positions remain vacant until the successors are named. The Order requires a minimum of 11 members to hold a Council meeting. For the nomination year with 12 positions expiring, if not appointed by the January 1 start date, the Council would be unable to meet until such appointments were made. This could cause a lapse in the Council's ability to properly administer the provisions of the Order. Allowing members to serve until their successor is appointed would allow the Council to continue administration should appointments be delayed beyond the specified term of office. This change is similar to authority provided for in other research and promotion orders.

In accordance with the Regulatory Flexibility Act (RFA) (5 U.S.C. 601-612), AMS is required to examine the impact of the proposed rule on small entities. Accordingly, AMS has considered the economic impact of this action on such entities.

The purpose of the RFA is to fit regulatory actions to the scale of businesses subject to such actions so that small businesses will not be disproportionately burdened. The Small Business Administration defines, in 13 CFR part 121, small agricultural producers as those having annual receipts of no more than $1,000,000 and small agricultural service firms (first handlers and importers) as those having annual receipts of no more than $30 million.

There are approximately 1,547 domestic producers, 71 first handlers and 271 importers of highbush blueberries covered under the program. Dividing the highbush blueberry crop value for 2019, $919 million, 1 by the number of producers (1,547) yields an average annual producer revenue estimate of $594,053. It is estimated that in 2019, about 99 percent of the first handlers shipped under $30 million worth of highbush blueberries. Based on 2019 U.S. Border and Customs (Customs) data, it is estimated that over 99 percent of the importers shipped under $30 million worth of highbush blueberries. Based on the foregoing, the majority of producers, first handlers and importers may be classified as small entities. We do not have information concerning the number of exporters and their size. Comments providing any information or data concerning exporters are requested.

Regarding value of the commodity, as mentioned above, based on 2019 NASS data, the value of the domestic highbush blueberry crop was about $919 million. According to Customs data, the value of 2019 imports was about $1.04 billion.

It is not anticipated that this action would impose additional costs on industry members. Eligible producers, importers and exporters interested in serving on the Council would have to complete a background questionnaire. Those requirements are addressed later in this proposal.

This proposal invites comments on revising §§ 1218.40, 1218.41 and 1218.42 of the Order regarding Council membership, nominations, and term of office, respectively. The Council administers the Order with oversight by USDA. Under the program, assessments are collected from domestic producers and importers and used for research and promotion projects designed to increase the demand for highbush blueberries. The proposed action would remove the first-handler and alternate position and add two exporter member and alternate positions. This would help ensure that the Council reflects the distribution of domestic blueberry production and imports into the U.S. Conforming changes would be made to the nomination procedures. This proposal would also allow members and alternates to remain in office until a successor is appointed. This change would allow the Council to continue administration of the Order should appointments be delayed beyond the specified term of office. Authority for this action is provided in §§ 1218.40(b) and 1218.47(m) of the Order and section 7414 of the 1996 Act.

In accordance with the Paperwork Reduction Act of 1995 (44 U.S.C. Chapter 35), the information collection and recordkeeping requirements that are imposed by the Order have been approved previously under OMB control number 0581-0093 and 0505-0001. Eligible producers, importers, exporters, first-handler, and public members interested in serving on the Council are required to complete a background questionnaire (Form AD-755) to verify their eligibility. Adding an exporter member and alternate member to the Council would require four additional exporters to submit background forms (AD-755) to USDA, once every three years, in order to be considered for appointment to the Council. The Secretary requires two names to be submitted for each open seat on the Council. The public reporting burden is estimated to increase the total burden hours by less than one hour. This additional burden would be included in the existing information collection approved for use under OMB control number 0581-0093. In addition, serving on the Council is optional, and the burden of submitting the background form would be offset by the benefits of additional representation on the Council.

The previously approved background questionnaire would be revised eliminating the first-handler section. It would impose an increase of the total reporting and recordkeeping burden hours by less than one hour on blueberry producers, importers, or exporters.

As with all Federal promotion programs, reports and forms are periodically reviewed to reduce information requirements and duplication by industry and public sector agencies. USDA has not identified any relevant Federal rules that duplicate, overlap, or conflict with this proposed rule.

Regarding alternatives, the Council has been discussing its membership and potential changes to reflect the distribution of domestic production and imports for the past few years. The Council's Executive Committee met to formulate and consider various options. One option was to replace two of the four regional producer positions, with the exporter positions, reallocating the two regions as East and West, with one position for each region. Another option considered was to eliminate the first-handler and public member positions; reallocate the regions to East and West, with one position for each region; and add two importer positions and two exporter positions. The Council also considered maintaining the status quo. It concluded, upon reviewing the domestic production and import statistics, that it was important to have foreign producer representation from the top four countries importing highbush blueberries into the U.S. represented on the Council. Thus, the Council recommended revising the Order to remove the first-handler and alternate position and add two exporter member and alternate positions.

Regarding outreach efforts, this action was discussed by the Council at meetings in October 2018, as well as by the Council and committees in 2019 and 2020. The Council met in November 2020 and in June 2021 and unanimously made its recommendation. All of the Council's meetings are open to the public and interested persons are invited to participate and express their views.

AMS is committed to complying with the E-Government Act, to promote the use of the internet and other information technologies to provide increased opportunities or citizen access to Government information and services, and for other purposes.

We have performed this initial RFA analysis regarding the impact of the proposed action on small entities and we invite comments concerning the potential effects of this action.

USDA has determined that this proposed rule is consistent with and would effectuate the purpose of the 1996 Act.

A 60-day comment period is provided to allow interested persons to respond to this proposal. All written comments received in response to this proposed rule by the date specified will be considered prior to finalizing this action.

For the reasons set forth in the preamble, 7 CFR part 1218 is proposed to be amended as follows:

The following section briefly discusses the statutory authority underlying this proposed rule, as well as some of the relevant historical background related to showerheads, the subject of this NOPR.

Title III of EPCA (42 U.S.C. 6291 et seq. ) sets forth a variety of provisions designed to improve energy efficiency and, for certain products, water efficiency. 1 Part B of Title III  2 establishes the “Energy Conservation Program for Consumer Products Other Than Automobiles,” which includes showerheads (with the exception of safety shower showerheads)—the subject of this proposed rulemaking. (42 U.S.C. 6292(a)(15)) Under EPCA, the energy conservation program consists essentially of four parts: (1) Testing, (2) labeling, (3) Federal energy conservation standards, and (4) certification and enforcement procedures.

EPCA defines a showerhead as “any showerhead (including a handheld showerhead), except a safety shower showerhead.” (42 U.S.C. 6291(31)(D)) In addition to defining “showerhead,” EPCA established a maximum water use threshold of 2.5 gpm applicable to “any showerhead.” (42 U.S.C. 6295(j)(1)). The definition of “showerhead” and the water conservation standard for showerheads were added to EPCA by the Energy Policy Act of 1992 (Pub. L. 102-486 (Oct. 24, 1992)) (“EPAct 1992”). Until 2013, DOE regulations did not contain a separate definition for “showerhead.” ( See 78 FR 62970)

On May 19, 2010, DOE published in the Federal Register a Notice of Availability of a proposed interpretive rule regarding the definition of “showerhead.” 75 FR 27926 (“2010 Draft Interpretive Rule”). In this 2010 Draft Interpretive Rule, available at https://www.regulations.gov/document?D=EERE-2010-BT-NOA-0016-0002, DOE discussed how there was uncertainty about how the EPCA definition of “showerhead” applies to the diversified showerhead product offerings. Id. at 1. To address this uncertainty, DOE proposed to define a “showerhead” as “any plumbing fitting that is designed to direct water onto a bather.” Id. at 2 (footnote omitted). As such, DOE stated it would “find a showerhead to be noncompliant with EPCA's maximum water use standard if the showerhead's standard components, operating in their maximum design flow configuration, taken together use in excess of 2.5 gpm.” Id. at 3.

On March 4, 2011, DOE formally withdrew the draft interpretive rule and issued showerhead enforcement guidance. ( See https://www.energy.gov/sites/prod/files/gcprod/documents/Showerhead_Guidancel.pdf ) (“2011 Enforcement Guidance”) In the 2011 Enforcement Guidance, DOE explained that it had received several complaints alleging that certain showerhead products exceeded EPCA's 2.5 gpm standard. DOE stated that it had learned that some had come to believe that a showerhead that expels water from multiple nozzles constituted not a single showerhead, but rather multiple showerheads and thus could exceed the maximum permitted water use by a multiple equal to the number of nozzles on the showerhead. Id. at 1. Following a review of the record from the 2010 Draft Interpretive Rule, DOE concluded that the term “any showerhead” has been and continues to be sufficiently clear such that no interpretive rule was needed. Id. at 2. Specifically, DOE stated that “multiple spraying components sold together as a single unit designed to spray water onto a single bather constitutes a single showerhead for the purpose of the maximum water use standard.” Id. DOE, in its discretion, addressed the misunderstanding of how to measure compliance with the standard by providing a two-year enforcement grace period to allow manufacturers to sell any remaining noncompliant products. Id. at 2-3.

DOE proposed revising the test procedure for showerheads and other products and to change the regulatory definition of showerheads. 77 FR 31742 (May 30, 2012) (“May 2012 NOPR”). DOE proposed to adopt definitions for four terms related to showerheads—“fitting”, “accessory”, “body spray”, and “showerhead”—in order to address certain provisions of the revised American Society of Mechanical Engineers/American National Standards Institute (“ASME/ANSI”) test procedures that were not contemplated in the versions referenced by the existing DOE test procedure, and to establish greater clarity with respect to product coverage. 77 FR 31742, 31747. 3 Specifically, DOE proposed to define “showerhead” as “an accessory, or set of accessories, to a supply fitting distributed in commerce for attachment to a single supply fitting, for spraying water onto a bather, typically from an overhead position, including body sprays and hand-held showerheads, but excluding safety shower showerheads.” 77 FR 31742, 31755. The proposed definition clarified that DOE considered a “body spray” to be a showerhead for the purposes of regulatory coverage. 77 FR 31742, 31747.

Responding to comments on the May 2012 NOPR, DOE issued on April 8, 2013 a supplemental notice of proposed rulemaking (“SNOPR”) in which DOE proposed a revised definition of “showerhead” and withdrew its proposal to include “body sprays” in the definition of “showerhead” in light of concerns raised by commenters and DOE's need to further study the issue. 78 FR 20832, 20834-20835, 20841 (“April 2013 SNOPR”). The SNOPR's modified definition of “showerhead” removed the term “accessory” from the definition based on comments about the use of the term. 78 FR 20832, 20834. Under the proposed modified definition, a “showerhead” is “a component of a supply fitting, or set of components distributed in commerce for attachment to a single supply fitting, for spraying water onto a bather, typically from an overhead position, including hand-held showerheads, but excluding safety shower showerheads.” 78 FR 20832, 20834. DOE also requested comment on whether to define the term “safety shower showerhead” to address which products qualify for exclusion from coverage under EPCA and DOE regulations. 78 FR 20832, 20835, 20840.

On October 23, 2013, DOE issued a final rule amending test procedures for showerheads and other products and adopting definitions for products including showerheads. 78 FR 62970 (“October 2013 Final Rule”). In this final rule, DOE adopted in substance the modified definition of “showerhead” proposed in the April 2013 SNOPR. 78 FR 62970, 62986. The October 2013 Final Rule defined “showerhead” as “a component or set of components distributed in commerce for attachment to a single supply fitting, for spraying water onto a bather, typically from an overhead position, excluding safety shower showerheads.” 78 FR 62970, 62986. DOE did not finalize the definition of “body spray” proposed in the May 2012 NOPR. 78 FR 62970, 62973. DOE also declined to adopt a definition of “safety shower showerhead” and explained that it was unable to identify a definition that would clearly distinguish these products from the showerheads covered under EPCA. 78 FR 62970, 62974.

On August 13, 2020, DOE proposed revising the definition of a “showerhead” to be consistent with the most recent ASME standard. 85 FR 49284 (“August 2020 NOPR”). DOE also proposed to adopt definitions of “body spray” and “safety shower showerhead” and to clarify whether the current test procedure would apply to the proposed definitional changes. 85 FR 49284, 49285. In addition, DOE proposed to amend the test procedure for showerheads to address the testing of a single showerhead within a multiheaded showerhead. 85 FR 49284, 49292.

Following the consideration of comments received in response to the August 2020 NOPR, DOE issued the December 16, 2020 Final Rule, which amended the definition for “showerhead” and adopted definitions for “body spray” and “safety shower showerhead.” 85 FR 81341. Specifically, the December 2020 Final Rule amended the meaning of “showerhead” in a manner that would incorporate the ASME definition for this term by defining it to mean “an accessory to a supply fitting for spraying onto a bather, typically from an overhead position. 85 FR 81341, 81343, 81359. Under the December 2020 Final Rule's interpretation, each showerhead included in a product with multiple showerheads would separately be required to meet the 2.5 gpm standard established in EPCA. 85 FR 81341, 81342. In addition, DOE established a definition for “body spray”, citing the need to address ambiguity about whether body sprays were considered showerheads under the October 2013 Final Rule. 85 FR 81341, 81342, 81350. DOE defined the term “body spray” as “a shower device for spraying water onto a bather from other than the overhead position. A body spray is not a showerhead.” 85 FR 81341, 81359. Lastly, DOE defined the term “safety shower showerhead” by incorporating by reference the definition of “safety shower showerhead” from the ANSI/International Safety Equipment Association (“ISEA”) Z358.1-2014, 4 such that a “safety shower showerhead” is “a showerhead designed to meet the requirements of ISEA Z358.1.” 85 FR 81341, 81359. The December 2020 Final Rule indicated that leaving the term “safety shower showerhead” undefined would cause confusion. 85 FR 81341, 81351. DOE did not finalize the test procedure amendments that had been proposed in the August 2020 NOPR. 85 FR 81341.

On January 20, 2021, the President issued Executive Order 13990, “Protecting Public Health and the Environment and Restoring Science To Tackle the Climate Crisis.” 86 FR 7037 (Jan. 25, 2021) (“E.O. 13990”). Section 1 of that Order lists a number of policies related to the protection of public health and the environment, including reducing greenhouse gas (“GHG”) emissions and bolstering the Nation's resilience to the impacts of climate change. 86 FR 7037, 7041. Section 2 of the Order instructs all agencies to review “existing regulations, orders, guidance documents, policies, and any other similar agency actions promulgated, issued, or adopted between January 20, 2017, and January 20, 2021, that are or may be inconsistent with, or present obstacles to, [these policies].” Id. Agencies are directed, as appropriate and consistent with applicable law, to consider suspending, revising, or rescinding these agency actions. Id.

While E.O. 13990 triggered the Department's re-evaluation, DOE is relying on the analysis presented below, based upon EPCA, to revise the definition adopted in the December 2020 Final Rule.

In this proposed rule, DOE proposes to withdraw the December 2020 Final Rule's redefinition of “showerhead,” and to reinstate the October 2013 Final Rule's definition of “showerhead.” DOE therefore proposes that the term “showerhead” be defined, as it was defined in DOE's regulations for close to a decade prior to the December 2020 Final Rule, as “a component or set of components distributed in commerce for attachment to a single supply fitting, for spraying water onto a bather, typically from an overhead position, excluding safety shower showerheads.” 78 FR 62970, 62986. As such, DOE also proposes to withdraw December 2020 Final Rule's interpretation that each showerhead included in a product with multiple showerheads would separately be required to meet the 2.5 gpm standard established in EPCA. Whereas in the December 2020 Final Rule DOE changed the definition of “showerhead” because the Department weighed consistency with ASME more heavily than water conservation, DOE has reconsidered this balance and has come to a different policy conclusion that water conservation is a more important EPCA purpose than consistency with ASME (with which DOE has no statutory obligation to align its definition). DOE believes that the steps it is proposing in this proposed rule better effectuate EPCA's water conservation purposes.

DOE also proposes to withdraw the definition of “body spray” adopted in the December 2020 Final Rule. DOE believes that the current definition of “body spray” is inconsistent with the express purpose of EPCA to conserve water by improving the water efficiency of certain plumbing products and appliances as the definition may lead to increased water use and does not best address the relationship between body sprays and showerheads. This is because the only difference between a “body spray” and a “showerhead” is the installation location, as shown by the similar treatment of the two products in the marketplace. DOE does not propose any changes to the definition of “safety shower showerhead” as leaving the term undefined may cause confusion about what products are subject to the energy conservation standards.

DOE has undertaken a review of the December 2020 Final Rule. DOE proposes to withdraw the December 2020 Final Rule's definition of “showerhead” and reinstate the definition of “showerhead” from the October 2013 Final Rule. DOE has tentatively determined that EPCA's definition of showerhead is ambiguous and that the December 2020 Final Rule's definition of “showerhead” is not consistent with EPCA's purposes: To conserve water by improving water efficiency of certain plumbing products and appliances and to improve energy efficiency of major appliances and consumer products. See 42 U.S.C. 6201. DOE has also tentatively determined, upon review and in light of present facts and circumstances, that Congressional intent does not require DOE to adopt the ASME definition for “showerheads;” that the October 2013 Final Rule did not effectively ban multi-headed showerheads from the market; and that the December 2020 Final Rule's definition of “showerhead” is inconsistent with EPCA's purposes and falls within the National Technology Transfer and Advancement Act of 1995 (“NTTAA”) and OMB Circular A-119 exception to the use of voluntary consensus standards. As such, DOE proposes to reinstate the definition of “showerhead” from the October 2013 Final Rule, such that the term would again be defined as “a component or set of components distributed in commerce for attachment to a single supply fitting, for spraying water onto a bather, typically from an overhead position, excluding safety shower showerheads.” See 78 FR 62970, 62986.

EPCA defines the term “showerhead” as “any showerhead (including a handheld showerhead), except a safety shower showerhead.” (42 U.S.C. 6291(31)(D)). Congress adopted this definition of showerhead in 1992 as part of the Energy Policy Act. Thereafter, however, between 1992 and 2010, the designs of showerhead diversified into a myriad of products including waterfalls, shower towers, rainheads, and shower systems. (See https://www.regulations.gov/document?D=EERE-2010-BT-NOA-0016-0002 ) In the 2010 Draft Interpretive Rule, DOE noted that it had become aware of uncertainty in how the EPCA definition and standard applies to such products. Id. As such, DOE issued the draft interpretive rule to “make clear to all stakeholders” DOE's interpretation of the definition of “showerhead” with respect to the 2.5 gpm maximum water use requirement. Id. at 1-2.

Similarly, in the 2011 Enforcement Guidance, DOE explained that it had learned that some had come to believe that a showerhead that expels water from multiple nozzles constituted not a single showerhead, but rather multiple showerheads and thus could exceed the maximum permitted water use. (See https://www.energy.gov/sites/prod/files/gcprod/documents/Showerhead_Guidancel.pdf ) DOE further acknowledged that absence of enforcement could have contributed to that misunderstanding. Id. at 2. While DOE acknowledged such confusion, DOE withdrew the 2010 Draft Interpretive Rule in the enforcement guidance document based on its conclusion that the term “any showerhead” has been, and continues to be, sufficiently clear such that no interpretive rule is needed. Id. In the enforcement guidance, DOE stated that multiple spraying components sold together as a single unit designed to spray water onto a single bather constitute a single showerhead for purposes of the maximum water use standard. Id. DOE provided manufacturers a two-year grace period to sell any remaining noncompliant products and to adjust product designs for compliance with EPCA and DOE regulations. Id. at 3.

The ambiguity of the word “showerhead” in EPCA is underscored by its history. DOE's statements in both the 2010 Draft Interpretive Rule and the 2011 Enforcement Guidance illustrate that confusion existed among manufacturers about what constituted a showerhead under the statutory definition. Since the passing of EPAct 1992 and the establishment of a regulatory definition for “showerhead”, the market diversified into a myriad of products. The diversification of the marketplace as it pertains to “showerheads”, and the confusion about what products are considered a showerhead by manufacturers, illustrate that the statutory definition of “showerhead” is ambiguous. DOE believes that any ambiguity in the statutory meaning should be explicated by a regulatory definition that is consistent with EPCA's purposes.

EPCA sets forth seven purposes that provide a basis for DOE's actions regarding the Energy Conservation Program. One of the most relevant of these purposes is “to conserve energy supplies through energy conservation programs, and, where necessary, the regulation of certain energy uses.” (42 U.S.C. 6201(4); Pub. L. 94-163 ((Dec. 22, 1975)) The EPAct 1992 amended EPCA by adding plumbing products, including showerheads, to the products covered by the Energy Conservation Program. (Pub. L. 102-486 (Oct. 24, 1992)) The EPAct 1992 also added another purpose under EPCA to address plumbing products: “to conserve water by improving the water efficiency of certain plumbing products and appliances.” (42 U.S.C. 6201(8))

DOE has considered the relationship between the definition of “showerhead”, the 2.5 gpm EPCA standard, and EPCA's purposes to conserve water and energy in both the 2010 Draft Interpretive Rule and 2011 Enforcement Guidance. DOE believes that the December 2020 Final Rule is in conflict with EPCA's water-conservation and energy-conservation purposes. That rule allows multiple nozzles each to be subject to a separate standard, and thereby allows water flow at a multiple of that standard and the related increase of energy for water heating.

This belief is consistent with DOE statements before the December 2020 Final Rule. Specifically, in the 2010 Draft Interpretive Rule, DOE explained that all components that are supplied together and function from one inlet form a single showerhead for purposes of the maximum water use standards under EPCA. ( See https://www.regulations.gov/document?D=EERE-2010-BT-NOA-0016-0002 ) DOE stated that neither the statutory definition nor the test procedures for showerheads treat a showerhead differently based upon the shape, size, placement, or number of sprays or openings it may have. Id. at 2. Further, DOE highlighted that the test procedure contemplates that the regulated showerhead fitting may have additional “accessory” water outlets and specifies that all standard accessories must be attached and set at maximum flow during testing. Id. DOE clarified that a showerhead is determined to be noncompliant if the standard components, operating in their maximum design flow configuration, taken together use in excess of 2.5 gpm. Id. at 3. DOE stated that this approach furthers the goal of EPCA to “conserve water by improving the water efficiency” of showerheads. Id. In DOE's 2011 Enforcement Guidance, DOE articulated a modified interpretation of the statutory definition of “showerhead” from the definition proposed in the 2010 Draft Interpretive Rule. DOE stated that multi spraying units sold together as a single unit designed to spray water onto one bather are considered a single showerhead. ( See https://www.energy.gov/sites/prod/files/gcprod/documents/Showerhead_Guidancel.pdf ) DOE explained that all sprays and nozzles should be turned onto the maximum flow setting to determine water use. Id. DOE found this approach is consistent with the industry standard, the statutory language, and Congressional intent to establish a maximum water use requirement. Id. These previous statements by DOE illustrate that a definition of “showerhead” that includes a multi-headed showerhead is consistent with EPCA's purpose of water conservation.

The 2020 rulemaking did not fully account for how its definition of “showerhead” would comport with the purposes of EPCA, but it did acknowledge that water conservation is among EPCA's purposes. 85 FR 81341, 81353. In this proposed rulemaking, DOE reviews the December 2020 Final Rule's definition of “showerhead” as it relates to EPCA's express purposes of water and energy conservation. The purposes of EPCA, as amended, include “to conserve water by improving the water efficiency of certain plumbing products and appliances” and “to provide for improved energy efficiency of motor vehicles, major appliances, and certain other consumer products.” (42 U.S.C. 6201)

DOE received comments in response to the August 2020 NOPR, many of which explained that the then-proposed “showerhead” definition was contrary to the purposes of the Energy Conservation Program and Federal laws, which are to reduce water waste and improve energy efficiency. (Davis, No. 0064 at p.1; Public Interest Research Group (“PIRG”), No. 0082 at p.3; Northwest Power and Conservation Council (“NPCC”), No. 0060 at p.2)  5 For example, PIRG explained that the then-proposed new interpretation was contrary to the 2.5 gpm standard and the goals of EPCA as it would permit higher water usage. PIRG further explained that the then-proposed interpretation would eviscerate the 2.5 gpm standard, because the water flow available in a shower would be simply a matter of choice, between manufacturer and consumer, about how many nozzles to use. PIRG stated that Congress could not have intended this conservation standard to be so illusory. (PIRG, No. 0082 at p.3) The NPCC stated that the proposal, if finalized, would undermine the DOE standards program by establishing revised definitions and an agency interpretation that circumvent the associated standard. The NPCC explained also that this proposal would undercut DOE's appliance program and diminish cost-effective energy savings and benefits contrary to the purpose of EPCA. (NPCC, No. 0060 at p.2) Similarly, ASAP  6 stated that the proposal allowed for unlimited flow because there was no limit on the number of spray units a single product might have and this interpretation undermined the very purpose of the statute. (ASAP, No. 0086 at p.2) Hare also suggested that the aggregate flow rate would be too high to achieve water savings, thereby subverting the purported reason for the existence of the regulation. (Hare, No. 0012)

Other comments that DOE received on the August 2020 NOPR similarly discuss the impacts of the proposal on water and energy consumption. Numerous commenters stated that the proposal would increase water and energy consumption. (California Investor Owned Utilities (“CA IOUs”), Public Meeting Transcript at p. 13; Consumer Federation of America (“CFA”), No. 0029; CFA, Public Meeting Transcript at p.14; Environment America, 7 No. 0069 at p.1) Commenters specified that the proposal would waste water and energy because more energy would be needed to heat and pump the additional water. (Godwin, No. 0042; Hall, No. 0048; Shaw, No. 0059; Gurley, No. 35) The Green Builder Coalition highlighted that the increased water flow and usage would increase energy usage from the municipal side used to pump and treat the increased water demands. (Green Builder Coalition, Public Meeting Transcript at p.35)

Commenters also addressed the current water shortages the country is facing. Numerous stakeholders commented that 40 of the 50 states are already confronting water shortages and that the proposal would increase consumption of drinking water, causing a severe impact on water supplies across the country. (Walnut Valley Water District (“WVWD”), No. 0051 at p.2; Alliance for Water Efficiency, et al. 8 (“AWE, et al.”), No. 0079 at p.3; Santa Clara Valley Water District (“Valley Water”), No. 0076 at p.1; Bay Area Water Supply & Conservation Agency (“BAWSCA”, No. 0050 at p.3) Lish explained that the Southwest was suffering a drought and that event after event illustrated the importance of reducing energy consumption that produces GHG emissions. (Lish, No. 0057) Cohen also commented that the proposed changes would allow wasteful showers in a wide variety of configurations and increase consumption of drinking water at a time that wide regions of the country are already facing severe shortages. (Cohen, No. 0036)

Regarding water consumption, the CA IOUs projected that a single-shower household shifting to a three-spray component product could increase the overall hot water use for that household by as much as 80%. (CA IOUs, No. 0084 at p.6) Further, the CA IOUs estimated that if 10% of current showerheads were converted to three-spray component products, national residential hot water use, the second largest component of residential site energy consumption, could increase by as much as eight percent. (CA IOUs, No. 0084 at p. 6) Similarly, Gary Klein Associates (“GKA”) stated that switching to a 2-headed showering device increases hot water use by 40%, while switching to a 3-headed device increases it by 80%. (GKA, No. 0063 at p.11) Tucson Water also noted that changing the definition of “showerhead” effectively allowed multiple showerheads in the same stall, disregarding the existing federal standard of 2.5 gpm per shower and potentially doubling, or more, the amount of water used per shower. (Tuscan Water, No. 0053 at p. 1) And numerous commenters estimated that increasing the current federal legal standard of 2.5 gpm for the entire shower could result in a national water increase of 161 billion gallons in a single year. (Valley Water, No. 0076 at p. 1; WVWD, No. 0051 at p.2; BAWSCA, No. 0050 at p.3; AWE, et al., No. 0079 at p.2))

Texas Water Development Board (“TWDB”) stated that a change in the definition of “showerhead” would most likely lead to a reduction in the anticipated water savings and an increase in the state's future municipal water demands. If these water savings are not achieved through conservation, future water demands will likely require additional, and more expensive, water management strategies and projects. (TWDB, No. 0074 at p.2)

Commenters also discussed the impact of increased water consumption on energy use. Commenters estimated that for each 1 gpm increase in showerhead flow rate, national annual domestic water use would increase by 55 billion gallons and national annual energy use for that added hot water would increase by 25,000 billion Btu. (WVWD, No. 0051 at p.3; BAWSCA, No. 0050 at p.4; AWE, et al., No. 0079 at p.3) This use would, in turn, increase annual water and energy bills for American consumers by an estimated $1.14 billion. (WVWD, No. 0051 at p.3; BAWSCA, No. 0050 at p.4; AWE, et al., No. 0079 at p.3; Davis, No. 0064 at p.1) The Public Service Commission of Wisconsin (“PSC of Wisconsin”) stated that showerheads affect a customer's energy use as showers represent the number one use of hot water inside the home and a reduction in shower water efficiency would require customers to use additional energy to heat water, increasing customers' energy use and resulting energy bills. (PSC of Wisconsin, No. 0061 at p.2)

NPCC estimated that the Northwest currently has about 10 million showerheads and increasing the water use per shower by a factor of two or more would have a significant impact on the consumption of electricity, natural gas, and water, which would result in increased power supply needs. (NPCC, No. 0060 at p.2) NPCC stated the impacts of the proposed rule include increased electricity or natural gas consumption by the consumer, increased water use by the consumer, decreased utility by the consumer, increased burden and cost on the water utility, increased burden and cost on wastewater treatment facilities, possible changes to plumbing, and needs for larger water heater storage tanks. (NPCC, No. 0060 at p.2) Similarly, the Sierra Club and Earthjustice commented that the proposal would result in greater consumption of hot and cold water, increasing fossil fuel and electricity consumption, and the accompanying emissions of air pollutants that harm the health and welfare of its members. (Sierra Club and Earthjustice, No. 0085 at p.1)

The Los Angeles Department of Water and Power (“LADWP”) discussed how the proposed rulemaking would allow for devices that increase consumption of water, resulting in a greater need for energy, which in turn would generate more GHGs that would not be produced with fixtures that use less water. LADWP stated this increase would be due to the embedded energy and GHG impacts in treating, pumping, and moving water hundreds of miles across the state for delivery to LADWP and other suppliers. (LADWP, No. 0066 at pp.2-3) Shaw also noted that an increase in the amount of energy used to heat water would increase the amount of carbon emitted into the atmosphere, exacerbating global warming. (Shaw, No. 0059) The City of Santa Rosa Water Department (“Santa Rosa Water”) commented that loosening low flow standards would likely increase energy consumption and associated GHGs, which are a contributing factor to climate induced drought. (Santa Rosa Water, No. 0037 at p.2) Additional stakeholders commented that adopting the then-proposed “showerhead” definition would increase energy use from water wasting showerheads and increase GHG emissions because of the need to heat and pump excess water, increasing energy bills. (Hall, No. 0048; Gooch, No. 0043; Shaw, No. 0059)

DOE has fully considered these comments in this rulemaking as they relate to December 2020 Final Rule's definition of “showerhead.” During the 2020 rulemaking, DOE discussed these comments and noted the importance of water conservation, but DOE focused solely on the Congressional reliance on ASME for the definitional changes. See 85 FR 81341, 81353. DOE believes that EPCA's purposes should also be considered when amending the definition of a covered product. DOE agrees with the commenters that the December 2020 Final Rule's “showerhead” definition and interpretation would likely increase water usage, increase associated energy use, and increase GHG emissions. These increases would be contrary to EPCA's purposes of reducing energy and water consumption. As such, DOE has tentatively determined that the December 2020 Final Rule's definition should be withdrawn.

DOE's full consideration of comments received in the response to the August 2020 NOPR and of the purposes of EPCA has also informed this proposed approach of restoring the definition of “showerhead” from the October 2013 Final Rule. In response to the August 2020 NOPR, PIRG noted that DOE's past rules on this topic (in 2011 and in 2013) had clearly taken account of the primary EPCA goal of decreased water use. (PIRG, No. 0082 at p.3) ASAP commented that the definition from the 2013 Final Rule carried out the conservation purpose of EPAct 1992. (ASAP, No. 0086 at p.2)

DOE also received comments on the impacts of the then-existing definition of “showerhead” and EPAct 1992 generally. Ruff explained that the water efficiency mandates in EPAct 1992 have helped drive down and conserve household water use. (Ruff, No. 0010) Hamilton further commented that the then-current rules save consumers and water treatment jurisdictions money. (Hamilton, No. 0028) Cohen estimated that the then-current rule has saved billions of dollars in water and energy bills. (Cohen, No. 0036) The City of Sacramento Department of Utilities (“City of Sacramento”) stated that, in California, as global temperatures rise, reduced winter snowpack will negatively impact local water availability, and drought frequency may increase. Efficient water use is the most cost-effective way to achieve long-term conservation goals and ensure reliable water supply for future generations. (City of Sacramento, No. 0055 at p.3)

Commenters also estimated the water use reductions of cities and states due to water efficiency measures. BAWSCA estimated that since the 1992 federal adoption of the 2.5 gpm showerhead standard, its service area has saved more than 33.1 billion gallons of water with 2.2 billion gallons of water savings in 2020 alone as a result of savings from installing efficient 2.5gpm showerheads. BAWSCA also explained that there are also additional benefits accumulating from the 2.2 billion gallons in avoided wastewater treatment and hot water savings and cost. (BAWSCA, No. 0050 at p.2) The TWDB explained that the replacement of older showerheads with the current 2.5 gpm showerheads, under the October 2013 Final Rule definition of “showerhead”, was expected to save a cumulative 40,000 acre-feet of water in 2020 and 176,000 acre-feet in 2020 and reduce future municipal water demands of the state by approximately 6-10%. (TWDB, No. 0074 at p.1) And the City of Sacramento provided estimated savings from the 2.5 gpm flow rate and noted that in 2020 alone the City had saved 860 million gallons of water. (City of Sacramento, No. 0055 at p.2)

Numerous commenters also cited AWE estimates that 2.5 gpm showerheads provide 11 billion gallons per year in water savings and 5 trillion Btu per year in energy savings. (BAWSCA, No. 0050 at p.4; WVWD, No. 0051 at p.3; AWE, et al., No. 0079 at p.4) In ten years, the savings for 2.5 gpm showerheads at the federal standard alone accumulate to the equivalent of supplying 1 million homes with water and 670,000 homes with energy. (BAWSCA, No. 0050 at p.4; WVWD, No. 0051 at p.3; AWE, et al., No. 0079 at p.4; Davis, No. 064 at p.1)

DOE agrees with the commenters that the definition of “showerhead” from the October 2013 Final Rule and the associated interpretation resulted in significant water and energy savings, protected the environment, and reduced GHG emissions. As discussed above, while DOE focused on ASME in the 2020 rulemaking, DOE believes that the EPCA's purposes should also be considered when amending the definition of a covered product. As such, the definition of “showerhead” from the October 2013 Final Rule is consistent with the purposes of EPCA for water and energy conservation, whereas the December 2020 Final Rule's definition is not. Further, the definition of “showerhead” from the October 2013 Final Rule also corresponds with the general concept of the term “showerhead” in the 2010 Draft Interpretive Rule and 2011 Enforcement Guidance. While the specific language used by DOE has changed between the three documents, each document's definition considered all components attached to a single supply fitting/inlet to be a single showerhead. As explained previously, the October 2013 Final Rule understanding of showerheads better implements the purposes of EPCA than the December 2020 Final Rule's definition. Accordingly, DOE has tentatively determined that the proposed definition of “showerhead” better effectuates the purposes of EPCA. Therefore, DOE proposes that, in withdrawing the definition of “showerhead” from the December 2020 Final Rule, the definition of “showerhead” from the October 2013 Final Rule be reinstated.

DOE thus tentatively departs from the view expressed in the December 2020 Final Rule that it would be more consistent with Congressional intent to rely on ASME for the definition of “showerhead.” 85 FR 81341, 81342. As discussed, that term is ambiguous, and DOE believes that the definition of “showerhead” from the October 2013 Final Rule better comports with the EPCA's purposes.

DOE does not believe Congress required reliance of the ASME definition. Congress adopted the definition of “showerhead” in EPAct 1992, along with the provisions related to definitions, standards, test procedures, and labeling requirements for plumbing products. (Pub. L. 102-486; Oct. 24, 1992 Sec. 123) EPAct 1992 and EPCA define the term “showerhead” as “any showerhead (including a handheld showerhead), except a safety shower showerhead.” (42 U.S.C. 6291(31)(D)) In the same paragraph, Congress provided explicit direction to define the terms “water closet” and “urinal” in accordance with ASME A112.19.2M, but did not do so with respect to “showerhead.” ( Cf. Sec. 123(b)(5) of Pub. L. 102-486) Instead, for showerheads, Congress adopted the ASME standards only for the water conservation standard, test procedures, and labeling requirements. For those, Congress adopted ASME A112.18.1M-1989 as the applicable standard and required DOE to adopt the revised version of the standard, unless it conflicted with the other requirements of EPCA. (42 U.S.C. 6295(j)(1) and (3); 42 U.S.C. 6293(b)(7); 42 U.S.C. 6294(a)(2)(E)) These Congressional actions illustrate Congress' intent in regard to how DOE should define the term “showerhead.” Notably, Congress did not explicitly require that “showerhead” be defined in conformity with the definition in the applicable ASME standard (assuming the definition of showerhead was included in the 1989 standard) as it did with other aspects of the Energy Conservation Program for plumbing products.

In the December 2020 Final Rule, DOE determined that interpreting the term “showerhead” consistent with the ASME definition would be more appropriate than DOE's previous interpretation of “showerhead.” 85 FR 81341, 81342. DOE noted that EPCA relies on ASME standards for the test method, the standards, and the marking and labeling requirements for showerheads. 9 Because these other provisions relate to the ASME standard, the December 2020 Final Rule stated that Congress clearly intended that the “showerhead” definition would also align with the ASME standard. 85 FR 81341, 81345. DOE also highlighted that the definitions immediately preceding showerheads, in the definition section, included definitions of ASME and ANSI. Id. (citing 42 U.S.C. 6291(31)(B)-(C)) DOE explained that, while EPCA does not include an explicit direction regarding the definition of showerhead, DOE has found that reliance on the ASME standard for this final rule is consistent with Congress's reliance on ASME. In particular, DOE stated, if the definition developed by DOE deviated significantly from the ASME definition, it would create confusion in how to apply the standards and test methods that Congress directed be consistent with ASME. 85 FR 81341, 81346.

DOE has fully considered the comments that it received in response to the August 2020 NOPR, regarding the NOPR's suggestion that Congress intended that DOE's actions with regard to showerheads be consistent with ASME. PIRG stated that DOE's reasoning for following the ASME definition of “showerhead” is not consistent with EPCA or with EPAct 1992. Specifically, PIRG noted that Congress did not refer the “showerhead” definition back to the ASME standard even though, in the same paragraph, EPCA provides that certain other terms have “the meaning given such term in ASME A119.19.2M-1990.” PIRG also stated that the references to ASME in the definition, energy conservation standard, and labeling requirements do not have anything to do with what constitutes and does not constitute a showerhead. 10 PIRG explained that Congress's use of ASME standards in EPAct 1992 was surgically precise. (PIRG, No. 0082 at pp.6-7)

Upon further consideration, DOE agrees with the commenters that Congress did not intend that the definition of “showerhead” be required to conform with the definition of “showerhead” in the ASME standard. This interpretation comports with Congress's decision not to align the “showerhead” definition with the ASME standard, and it also better reflects the policies embodied in EPCA. As highlighted by PIRG, EPCA provides explicit direction to define the terms “water closet” and “urinal” in accordance with ASME A112.19.2M, in the same legislation and paragraph, as it adopted the definition of “showerhead”—which did not include a reference to applicable ASME standard. ( See Sec. 123(b)(5) of Pub. L. 102-486) Further, the mere fact that the terms immediately preceding showerhead are “ASME” and “ANSI” does not suggest that Congress intended for DOE to rely on the ASME definition. EPCA directly references ASME A112.18.1M-1989 or a revised version of the standard approved by ANSI for showerhead test procedures, energy conservation standards, and labeling requirements, but noticeably does not provide such a reference for the definition of “showerhead.” Congress clearly illustrated in EPAct 1992 that if it had intended for DOE to apply the definition of “showerheads” from ASME A112.18.1M-1989 (assuming a definition of “showerhead” was include in the 1989 standard), it would have provided the necessary reference. Therefore, DOE believes that Congress intended DOE to have flexibility to define “showerhead” without necessarily conforming with the definition in the applicable ASME standard.

EPCA contains a provision that prevents the Secretary from prescribing an amended or new standard if the Secretary finds that interested persons have established by a preponderance of the evidence that the standard is likely to result in the unavailability in the United States in any covered product type (or class) of performance characteristics (including reliability), features, sizes, capacities, and volumes that are substantially the same as those generally available in the United States at the time of the Secretary's finding. (42 U.S.C. 6295(o)(4))

In the August 2020 NOPR, DOE proposed to adopt an amended definition of “showerhead” that complies with the Congressional directive to preserve performance characteristics and features that were available on the market at the time DOE originally acted to eliminate them. 85 FR 49284, 49291. DOE explained that it cannot regulate or otherwise act to remove products with certain performance characteristics and features from the market given the prohibition in 42 U.S.C. 6295(o)(4). 85 FR 49284, 49290. In the December 2020 Final Rule, DOE further explained that considering two, three or eight showerheads in a given product to be a “feature” is consistent with DOE's previous rulemakings and determinations of what constitutes a feature. 11 85 FR 81341, 81347. DOE stated that following the 2011 Enforcement Guidance, which appeared to effectively ban the vast majority of products with multiple showerheads from the market, DOE codified in DOE regulations its effective ban on products with multiple showerheads from the market. 85 FR 49284, 49291. Further, DOE acknowledged, as is the case with the August 2020 definitional proposed rule, that the 2013 rule was not a standards rulemaking and did not comply with the statutory requirements of a standards rulemaking. DOE stated, however, that the effect was the same in that multi-headed showerhead products, while not entirely eliminated from the market, were significantly reduced in availability as a result of the 2011 Enforcement Guidance. 85 FR 81341, 81347.

As part of DOE's reconsideration of the December 2020 Final Rule, DOE reviewed comments received in response to the August 2020 NOPR's discussion of section 6295(o)(4) of EPCA. The California Energy Commission (“CEC”) explained that, based on the plain language of the statute, section 6295(o)(4) of EPCA applies only to standards and the October 2013 Final Rule did not directly or effectively amend any standards. But CEC also clarified that assuming, arguendo, that section 6295(o)(4) of EPCA is relevant, DOE's own analysis shows that at least 3% of the existing market consists of multi-headed showerheads that meet the current standard. As such, no performance characteristics were eliminated from the market. (CEC, No. 0083 at p.6)

DOE agrees with CEC and DOE's own statement in the December 2020 Final Rule that the October 2013 Final Rule was not a standards rulemaking. Assuming arguendo that DOE did amend the water conservation standard or that the rule had the effect of a water conservation standard, the October 2013 Final Rule did not eliminate multi-headed showerheads from the market. DOE explained in the August 2020 NOPR that 3% of the 7,221 basic models of showerheads are multi-headed showerheads. 85 FR 49284, 49293. DOE has again reviewed its certification database and found that currently there are 7,704 basic models of showerheads, with multi-headed showerheads continuing to account for 3% of all basic models. Therefore, 42 U.S.C. 6295(o)(4) was not applicable in the October 2013 Final Rule as DOE did not amend the standard for showerheads there, nor did the rule eliminate multi-headed showerheads from the market as there are currently over 231 basic models on the market. Further, as multi-headed showerheads have not been eliminated from the market, DOE is not determining whether multi-headed showerheads provide a functionality/performance characteristic. (See 42 U.S.C. 6295(o)(4)) As such, the existing definition complied with the Congressional directive to preserve performance characteristics and features and the directive did not provide a basis for adoption of a new definition.

Section 12(d)(1) of NTTAA requires that Federal departments “use technical standards that are developed or adopted by voluntary consensus standards bodies, except when the use of the technical standards is inconsistent with applicable law or otherwise impractical.” (Pub. L. 104-113, 110 Stat. 783 (Mar. 7, 1996), as amended by Pub. L. 107-107, Div. A, Title XI, section 115, 115 Stat. 1241 ((Dec. 28, 2001) (codified at 15 U.S.C. 272 note)). Similarly, OMB Circular A-119 directs Federal agencies to use voluntary consensus standards unless inconsistent with applicable law or otherwise impractical. (Section 1 of OMB Circular A-119; https://www.whitehouse.gov/wp-content/uploads/2020/07/revised_circular_a-119_as_of_1_22.pdf. )

In the December 2020 Final Rule, DOE stated that the new definition of “showerhead” is consistent with the requirements of the NTTAA and the associated OMB Circular A-1119. 85 FR 81341, 81342. DOE explained that EPCA does not preclude DOE from using industry standards and that the statutory text of EPCA does not make compliance with OMB Circular A-119 inconsistent with applicable law or otherwise impracticable. DOE further stated that it disagrees that the ASME definition frustrates and is inconsistent with the requirements of EPCA. 85 FR 81341, 81348.

As part of DOE's reconsideration of the December 2020 Final Rule, DOE tentatively determined, in light of the comments provided during the August 2020 NOPR, that it is not appropriate to rely on the consensus industry standards as they relate to showerheads in accordance with the NTAA and OMB Circular A-119 because the current “showerhead” definition based on ASME consensus industry standards is inconsistent with EPCA and is impractical.

DOE received comments on the August 2020 NOPR regarding the appropriateness of DOE relying on the voluntary consensus standard developed by ASME in accordance with the NTAA and OMB Circular A-119. NRDC noted that the reference to A-119 and DOE's explanation of it clearly points out the inappropriateness of the proposed change in the definition, because the ASME definition frustrates and is inconsistent with the statutory requirement to establish and maintain an upper bound on the flowrate of showerheads and that adopting the proposed definition would allow multi-nozzle arrays without any upper bound of the combined flowrate of this kind of shower device. (NRDC, Public Meeting Transcript at pp.21-22) Similarly, PIRG commented that the 2.5 gpm standard was not a policy objective determined by DOE; it was a water conservation standard determined by Congress. PIRG further stated that the NTTAA does not instruct DOE to base its interpretation of Congressional policy by referring to industry standards and that even if it did, NTTAA itself states that an agency should not follow an industry standard where that is inconsistent with applicable law. PIRG explained that DOE's proposal is inconsistent with EPAct 1992, and thus NTTAA provides no safe harbor. As discussed, EPAct 1992 described in detail how the showerheads program should interact with ASME standards—NTTAA does not repeal or amend those directives. In regard to OMB Circular A-119, PIRG commented that DOE's reliance on OMB Circular A-119 is misplaced for the same reasons. In particular, as PIRG commented, Congress specified the policy goals that DOE must consider when it makes rules under EPCA; Circular A-119 could not supplant those policy goals with an extra-statutory mandate. (PIRG, No. 0082, pg.8) Sierra Club and Earth Justice highlighted that even if OMB Circular A-119 ordinarily requires agencies to use voluntary consensus standards as described by NTTAA, the Circular contains an expansive exception based on the impracticality of compliance. Sierra Club and Earth Justice cited to Circular A-119's definition of “impractical” as including “circumstances in which such use would fail to serve the agency's program needs; would be infeasible; would be inadequate, ineffectual, inefficient, or inconsistent with agency mission; or would impose more burdens, or would be less useful, than the use of another standard.”  12 Sierra Club and Earth Justice commented also that to the extent adhering to the ASME standard would result in increased showerhead consumption, DOE was within its rights in elevating the fulfillment of EPCA's purpose above the encouragement of consensus industry standards. (Sierra Club and Earthjustice, No. 0085, pp.3-4)

DOE agrees with the commentators that DOE should not adopt an industry standard here, where it would conflict with EPCA's requirements and be impractical. ( See 15 U.S.C. 272 note; OMB Circular A-119 s6.a.2) DOE's determination in the December 2020 Final Rule did not properly weigh the ASME definition of “showerhead” as compared to the purposes of EPCA, as it pertains to the NTTAA and OMB Circular A-119. Upon reconsideration, DOE now believes that adopting the ASME industry standards for the definition of “showerhead” here conflicts with EPCA and is impractical because it would not serve the purposes of water and energy conservation. The “showerhead” definition and interpretation in the December 2020 Final Rule is inconsistent with EPCA and is impractical because it would likely increase water usage, increase associated energy use, and increase GHG emissions, directly contrary to EPCA's purposes. As discussed in section III.A.2 of this document, DOE has tentatively determined that the December 2020 Final Rule's definition of “showerhead” is inconsistent with EPCA's purposes of water and energy conservation. Therefore, the NTTAA and OMB Circular A-119 authorize and comprehend DOE's departure from the use of the voluntary consensus standard developed by ASME in ASME/ANSI A112.18-1-2018 for the definition of “showerhead” because it would be inconsistent with EPCA and impractical.

DOE adopted a definition for “body spray” in the December 2020 Final Rule. DOE defined the term “body spray” as “a shower device for spraying water onto a bather from other than the overhead position. A body spray is not a showerhead.” 85 FR 81341, 81359. After a reconsideration of this definition, DOE proposes to withdraw the definition of “body spray.”

In the December 2020 Final Rule, DOE concluded that the definition of “showerhead” in the October 2013 Final Rule did not specifically include or exclude body sprays and that this omission may have introduced uncertainty for regulated parties and therefore it is appropriate to clarify that body sprays are not showerheads. 85 FR 81341, 81350. DOE also stated that leaving the scope of products not subject to EPCA's energy conservation standard undefined, and potentially subjecting manufacturers of body sprays to DOE standards, causes more confusion than establishing a regulatory definition. As such, DOE determined that it was appropriate to clarify the existing ambiguity following the October 2013 Final Rule that did not include body sprays within the definition of “showerhead,” and also did not define what constituted a “body spray.” 85 FR 81341, 81350.

As part of its review of the definition of “body spray”, DOE has reconsidered comments received in response to the August 2020 NOPR. Several commenters expressed concern that the proposal, to define the term “body spray” to clarify that these products are not subject to the current energy conservation standards, would result in wasteful and unnecessary “deluge” showers, which would also consume much more hot water. (WVWD, No. 0051 at p.2; BAWSCA, No. 0050 at p.3; AWE, et al., No. 0079 at p.2) Further, Valley Water explained that redefining body sprays signals that these products are not subject to the current energy conservation standards and thus can flow at any rate, resulting in an increase in water and energy use and a financial strain for American households. (Valley Water, No. 0076 at p.1)

Other commentators highlighted that the then-proposed definition of “body spray” was unnecessary because there was no technical difference between a showerhead and a body spray to warrant a separate definition. (CEC, No. 0083 at p.3; CA IOUs, Public Meeting Transcript at p.22; CA IOUs, No. 0084 at pp.3-5) CEC noted their concern that the then-proposed definition of “body spray” relied on manufacturer intent and consumer installation decisions, rather than discernable technical differences between products. (CEC, No. 0083 at p.3) The CA IOUs commented that, in their research, they have been unable to identify a technical difference between body sprays and showerheads other than the orientation of installation. (CA IOUs, Public Meeting Transcript at p.22) The CA IOUs conducted a review of retailer websites that indicated that shower units with body spray capability are generally marketed or sold as combination shower systems or shower panels with an overhead showerhead component. The CA IOUs stated that industry considers body sprays a form of showerhead. The CA IOUs further explained that the marketplace does not clearly distinguish stand-alone body sprays from conventional showerheads and that the market tends to include body spray capability in all-in-one shower systems. The CA IOUs found that all stand-alone body sprays and all-in-one shower systems identified in their research complied with the current water conservation standards. (CA IOUs, No. 0084 at pp.3-5)

The CA IOUs also discussed the treatment of body sprays and showerheads in the 2018 ASME Standard. Specifically, the CA IOUs stated that the definitions of “showerhead” and “body spray” in the 2018 ASME Standard suggests that body sprays designed and marketed as a stand-alone product and other showerhead devices differ only based on installation position in the end-use application. As such, the standard treats showerheads and body sprays similarly. (CA IOUs, No. 0084 at p.3) Further, the CA IOUs highlighted a comment made in response to the April 2013 SNOPR by Maximum Performance Testing. In the comment referenced by the CA IOUs, Maximum Performance stated that to create a distinction between showerheads and body sprays fails the reality test. In shower applications where body sprays and an overhead showerhead are present, there is no reason to classify one component as different than the other component. ((CA IOUs, No. 0084 at p.4 citing (Maximum Performance, EERE-2011-BT-TP-0061-0029 at p.1))

After further consideration, DOE agrees with commenters that the current definition of “body spray” and the interpretation that body sprays are not a showerhead does not effectively address the relationship between these two products. As highlighted by the CA IOUs, the 2018 ASME standard, as well as the 2012 ASME standard, treat the products similarly and the only difference between the definitions of “showerhead” and “body spray” is the installation location. Further, the market review conducted by the CA IOUs suggests that these two products are not treated differently in the marketplace. Given the similar treatment by the industry standard and the market, as well as the lack of discernable differences between the products, DOE believes that the current definition does not best address the relationship between these two products.

In addition, DOE agrees that the current definition of “body spray” may result in excessive water use that is inconsistent with EPCA's purposes. While DOE explained in the December 2020 Final Rule that leaving the term “body sprays” undefined introduced uncertainty into the market about whether those products needed to comply with the 2.5 gpm standard, the research done by CA IOUs shows that products with body sprays complied with the energy conservation standard. As such, DOE has tentatively determined that the current definition of “body spray” should be withdrawn.

In the December 2020 Final Rule, DOE established a definition for the term “safety shower showerhead.” 85 FR 81341. Specifically, DOE defined “safety shower showerhead” to mean “a showerhead designed to meet the requirements of ANSI/ISEA Z358.1 (incorporated by reference, see § 430.3)” 10 CFR 430.2. In this proposed rule, DOE does not propose to amend the definition of “safety shower showerhead.” DOE continues to agree with several of the findings in the December 2020 Definition Final Rule: That leaving undefined the scope of products not subject to EPCA's energy conservation standard causes confusion and is inappropriate; that what is meant by a “safety shower showerhead” or emergency shower is understood in the regulated industry; that it is unlikely that manufacturers of showerheads intended for use by residential consumers would design a showerhead to meet the specifications of the ANSI standard in order to avoid compliance with DOE standards; and that the definition and performance criteria in the definition of “safety shower showerhead” addressed concerns noted by the commenters in the 2020 rulemaking and distinguish a showerhead from a safety shower showerhead. See 85 FR 81341, 81350-81351. Accordingly, DOE believes that retaining the definition of “safety shower showerhead” is necessary and appropriate.

The Office of Information and Regulatory Affairs (“OIRA”) in the Office of Management and Budget (“OMB”) waived Executive Order 12866 (“E.O.”) 12866, “Regulatory Planning and Review” review of this proposed rule.

The Regulatory Flexibility Act (5 U.S.C. 601 et seq. ) requires preparation of an initial regulatory flexibility analysis (“IRFA”) for any rule that by law must be proposed for public comment, unless the agency certifies that the rule, if promulgated, will not have a significant economic impact on a substantial number of small entities. As required by E.O. 13272, “Proper Consideration of Small Entities in Agency Rulemaking,” 67 FR 53461 (Aug. 16, 2002), DOE published procedures and policies on February 19, 2003, to ensure that the potential impacts of its rules on small entities are properly considered during the rulemaking process. 68 FR 7990. DOE has made its procedures and policies available on the Office of the General Counsel's website ( https://energy.gov/gc/office-general-counsel ).

DOE reviewed this proposed rule under the provisions of the Regulatory Flexibility Act and the procedures and policies published on February 19, 2003. DOE certifies that the proposed rule, if adopted, would not have significant economic impact on a substantial number of small entities. The factual basis for this certification is set forth in the following paragraphs.

The Small Business Administration (SBA) considers a business entity to be a small business, if, together with its affiliates, it employs less than a threshold number of workers or earns less than the average annual receipts specified in 13 CFR part 121. The threshold values set forth in these regulation use size standards codes established by the North American Industry Classification System (NAICS) that are available at: https://www.sba.gov/document/support-table-size-standards. Plumbing equipment manufacturers are classified under NAICS 332913 “Plumbing Fixture Fitting and Trim Manufacturing,” and NAICS 327110 “Pottery, Ceramics, and Plumbing Fixture Manufacturing.” The SBA sets a threshold of 1,000 employees or fewer for an entity to be considered a small business within these categories.

This proposed rule would withdraw the current definition of showerhead and reinstate the prior definition of showerhead. This proposal would also withdraw the definition of body sprays. Finally, this proposal would retain the definition of safety shower showerhead. DOE has not found any showerheads that have been introduced into the market since the December 2020 Final Rule became effective that would meet the revised definitions in the December 2020 Final Rule. As such, DOE has not found any evidence of a reliance interest on the December 2020 Final Rule. Based on the foregoing, DOE certifies that this proposed rule would not have a significant economic impact on a substantial number of small entities.

Manufacturers of showerheads must certify to DOE that their products comply with any applicable energy conservation standards. To certify compliance, manufacturers must first obtain test data for their products according to the DOE test procedures, including any amendments adopted for those test procedures. DOE has established regulations for the certification and recordkeeping requirements for all covered consumer products and commercial equipment, including showerheads. (See generally 10 CFR part 429.) The collection-of-information requirement for the certification and recordkeeping is subject to review and approval by OMB under the Paperwork Reduction Act (“PRA”). This requirement has been approved by OMB under OMB control number 1910-1400. Public reporting burden for the certification is estimated to average 30 hours per response, including time for reviewing instructions, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing the collection of information.

Notwithstanding any other provision of the law, no person is required to respond to, nor shall any person be subject to a penalty for failure to comply with, a collection of information subject to the requirements of the PRA, unless that collection of information displays a currently valid OMB Control Number.

DOE is analyzing this proposed regulation in accordance with the National Environmental Policy Act (NEPA) and DOE's NEPA implementing regulations (10 CFR part 1021). DOE's regulations include a categorical exclusion for rulemakings interpreting or amending an existing rule or regulation that does not change the environmental effect of the rule or regulation being amended. 10 CFR part 1021, subpart D, appendix A5. DOE anticipates that this rulemaking, which focuses on the narrow question of how to define a particular product and does not otherwise impose any requirements, will qualify for categorical exclusion A5. This interpretive rulemaking would revise the definition of “showerhead” from the December 2020 Rule by reinstating the previous definition and otherwise meets the requirements for application of a categorical exclusion. See 10 CFR 1021.410. DOE has not found any showerheads that have been introduced into the market since the December 2020 Final Rule became effective that would meet the revised definitions in the December 2020 Final Rule. DOE will complete its NEPA review before issuing the final rule.

E.O. 13132, “Federalism,” 64 FR 43255 (Aug. 10, 1999), imposes certain requirements on Federal agencies formulating and implementing policies or regulations that preempt State law or that have Federalism implications. The Executive Order requires agencies to examine the constitutional and statutory authority supporting any action that would limit the policymaking discretion of the States and to carefully assess the necessity for such actions. The Executive Order also requires agencies to have an accountable process to ensure meaningful and timely input by State and local officials in the development of regulatory policies that have Federalism implications. On March 14, 2000, DOE published a statement of policy describing the intergovernmental consultation process it will follow in the development of such regulations. 65 FR 13735. DOE has examined this proposed rule and has tentatively determined that it would not have 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. EPCA governs and prescribes Federal preemption of State regulations as to energy conservation for the products that are the subject of this proposed rule. States can petition DOE for exemption from such preemption to the extent, and based on criteria, set forth in EPCA. (42 U.S.C. 6297) No further action is required by Executive Order 13132.

With respect to the review of existing regulations and the promulgation of new regulations, section 3(a) of E.O. 12988, “Civil Justice Reform,” imposes on Federal agencies the general duty to adhere to the following requirements: (1) Eliminate drafting errors and ambiguity, (2) write regulations to minimize litigation, (3) provide a clear legal standard for affected conduct rather than a general standard, and (4) promote simplification and burden reduction. 61 FR 4729 (Feb. 7, 1996). Regarding the review required by section 3(a), section 3(b) of E.O. 12988 specifically requires that Executive agencies make every reasonable effort to ensure that the regulation: (1) Clearly specifies the preemptive effect, if any, (2) clearly specifies any effect on existing Federal law or regulation, (3) provides a clear legal standard for affected conduct while promoting simplification and burden reduction, (4) specifies the retroactive effect, if any, (5) adequately defines key terms, and (6) addresses other important issues affecting clarity and general draftsmanship under any guidelines issued by the Attorney General. Section 3(c) of Executive Order 12988 requires Executive agencies to review regulations in light of applicable standards in section 3(a) and section 3(b) to determine whether they are met or it is unreasonable to meet one or more of them. DOE has completed the required review and determined that, to the extent permitted by law, this proposed rule meets the relevant standards of E.O. 12988.

Title II of the Unfunded Mandates Reform Act of 1995 (“UMRA”) requires each Federal agency to assess the effects of Federal regulatory actions on State, local, and Tribal governments and the private sector. Public Law 104-4, section 201 (codified at 2 U.S.C. 1531). For a proposed regulatory action likely to result in a rule that may cause the expenditure by State, local, and Tribal governments, in the aggregate, or by the private sector of $100 million or more in any one year (adjusted annually for inflation), section 202 of UMRA requires a Federal agency to publish a written statement that estimates the resulting costs, benefits, and other effects on the national economy. (2 U.S.C. 1532(a), (b)) The UMRA also requires a Federal agency to develop an effective process to permit timely input by elected officers of State, local, and Tribal governments on a proposed “significant intergovernmental mandate,” and requires an agency plan for giving notice and opportunity for timely input to potentially affected small governments before establishing any requirements that might significantly or uniquely affect them. On March 18, 1997, DOE published a statement of policy on its process for intergovernmental consultation under UMRA. 62 FR 12820. DOE's policy statement is also available at https://energy.gov/sites/prod/files/gcprod/documents/umra_97.pdf.

This proposed rule contains neither an intergovernmental mandate nor a mandate that may result in the expenditures of $100 million or more in any one year, so these requirements under the Unfunded Mandates Reform Act do not apply.

Section 654 of the Treasury and General Government Appropriations Act, 1999 (Pub. L. 105-277) requires Federal agencies to issue a Family Policymaking Assessment for any rule that may affect family well-being. This proposed rule would not have any impact on the autonomy or integrity of the family as an institution. Accordingly, DOE has concluded that it is not necessary to prepare a Family Policymaking Assessment.

Pursuant to E.O. 12630, “Governmental Actions and Interference with Constitutionally Protected Property Rights,” 53 FR 8859 (Mar. 15, 1988), DOE has determined that this proposed rule would not result in any takings that might require compensation under the Fifth Amendment to the U.S. Constitution.

Section 515 of the Treasury and General Government Appropriations Act, 2001 (44 U.S.C. 3516 note) provides for Federal agencies to review most disseminations of information to the public under information quality guidelines established by each agency pursuant to general guidelines issued by OMB. OMB's guidelines were published at 67 FR 8452 (Feb. 22, 2002), and DOE's guidelines were published at 67 FR 62446 (Oct. 7, 2002). Pursuant to OMB Memorandum M-19-15, Improving Implementation of the Information Quality Act (April 24, 2019), DOE published updated guidelines which are available at https://www.energy.gov/sites/prod/files/2019/12/f70/DOE%20Final%20Updated%20IQA%20Guidelines%20Dec%202019.pdf. DOE has reviewed this proposed rule under the OMB and DOE guidelines and has concluded that it is consistent with applicable policies in those guidelines.

E.O. 13211, “Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use,” 66 FR 28355 (May 22, 2001), requires Federal agencies to prepare and submit to OIRA at OMB, a Statement of Energy Effects for any proposed significant energy action. A “significant energy action” is defined as any action by an agency that promulgates or is expected to lead to promulgation of a final rule, and that (1) is a significant regulatory action under Executive Order 12866, or any successor order; and (2) is likely to have a significant adverse effect on the supply, distribution, or use of energy, or (3) is designated by the Administrator of OIRA as a significant energy action. For any proposed significant energy action, the agency must give a detailed statement of any adverse effects on energy supply, distribution, or use should the proposal be implemented, and of reasonable alternatives to the action and their expected benefits on energy supply, distribution, and use.

This proposed rule—which would amend the definition of showerhead, withdraw the definition of body spray, and retain the definition of safety shower showerhead—would not have a significant adverse effect on the supply, distribution, or use of energy and, therefore, is not a significant energy action. Accordingly, DOE has not prepared a Statement of Energy Effects on this proposed rule.

The time and date of the webinar are listed in the DATES section at the beginning of this document. Webinar registration information, participant instructions, and information about the capabilities available to webinar participants will be published on DOE's website: https://www1.eere.energy.gov/buildings/appliance_standards/standards.aspx?productid=2&action=viewlive. Participants are responsible for ensuring their systems are compatible with the webinar software.

Any person who has an interest in the topics addressed in this proposed rulemaking, or who is representative of a group or class of persons that has an interest in these issues, may request an opportunity to make an oral presentation at the webinar. Such persons may submit requests to speak by email to: Showerheads2021STD0016@ee.doe.gov. Persons who wish to speak should include with their request a computer file in WordPerfect, Microsoft Word, PDF, or text (ASCII) file format that briefly describes the nature of their interest in this rulemaking and the topics they wish to discuss. Such persons should also provide a daytime telephone number where they can be reached.

Persons requesting to speak should briefly describe the nature of their interest in this proposed rulemaking and provide a telephone number for contact. DOE requests persons selected to make an oral presentation to submit an advance copy of their statements at least two weeks before the webinar. At its discretion, DOE may permit persons who cannot supply an advance copy of their statement to participate, if those persons have made advance alternative arrangements with the Building Technologies Office. As necessary, requests to give an oral presentation should ask for such alternative arrangements.

DOE will designate a DOE official to preside at the webinar and may also use a professional facilitator to aid discussion. The meeting will not be a judicial or evidentiary-type public hearing, but DOE will conduct it in accordance with section 336 of EPCA (42 U.S.C. 6306). A court reporter will be present to record the proceedings and prepare a transcript. DOE reserves the right to schedule the order of presentations and to establish the procedures governing the conduct of the webinar. There shall not be discussion of proprietary information, costs or prices, market share, or other commercial matters regulated by U.S. anti-trust laws. After the webinar and until the end of the comment period, interested parties may submit further comments on the proceedings and any aspect of the rulemaking.

The webinar will be conducted in an informal, conference style. DOE will present summaries of comments received before the webinar, allow time for prepared general statements by participants, and encourage all interested parties to share their views on issues affecting this proposed rulemaking. Each participant will be allowed to make a general statement (within time limits determined by DOE), before the discussion of specific topics. DOE will permit, as time permits, other participants to comment briefly on any general statements.

At the end of all prepared statements on a topic, DOE will permit participants to clarify their statements briefly. Participants should be prepared to answer questions by DOE and by other participants concerning these issues. DOE representatives may also ask questions of participants concerning other matters relevant to this rulemaking. The official conducting the webinar will accept additional comments or questions from those attending, as time permits. The presiding official will announce any further procedural rules or modification of the above procedures that may be needed for the proper conduct of the webinar.

A transcript of the webinar will be included in the docket, which can be viewed as described in the Docket section at the beginning of this NOPR. In addition, any person may buy a copy of the transcript from the transcribing reporter.

DOE will accept comments, data, and information regarding this proposed rule before or after the public meeting, but no later than the date provided in the DATES section at the beginning of this proposed rule. Interested parties may submit comments, data, and other information using any of the methods described in the ADDRESSES section at the beginning of this document.

Submitting comments via https://www.regulations.gov. The https://www.regulations.gov web page will require you to provide your name and contact information. Your contact information will be viewable to DOE Building Technologies staff only. Your contact information will not be publicly viewable except for your first and last names, organization name (if any), and submitter representative name (if any). If your comment is not processed properly because of technical difficulties, DOE will use this information to contact you. If DOE cannot read your comment due to technical difficulties and cannot contact you for clarification, DOE may not be able to consider your comment.

However, your contact information will be publicly viewable if you include it in the comment itself or in any documents attached to your comment. Any information that you do not want to be publicly viewable should not be included in your comment, nor in any document attached to your comment. Persons viewing comments will see only first and last names, organization names, correspondence containing comments, and any documents submitted with the comments.

Do not submit to https://www.regulations.gov information for which disclosure is restricted by statute, such as trade secrets and commercial or financial information (hereinafter referred to as Confidential Business Information (“CBI”)). Comments submitted through https://www.regulations.gov cannot be claimed as CBI. Comments received through the website will waive any CBI claims for the information submitted. For information on submitting CBI, see the Confidential Business Information section.

DOE processes submissions made through https://www.regulations.gov before posting. Normally, comments will be posted within a few days of being submitted. However, if large volumes of comments are being processed simultaneously, your comment may not be viewable for up to several weeks. Please keep the comment tracking number that https://www.regulations.gov provides after you have successfully uploaded your comment.

Submitting comments via email. Comments and documents submitted via email also will be posted to https://www.regulations.gov. If you do not want your personal contact information to be publicly viewable, do not include it in your comment or any accompanying documents. Instead, provide your contact information in a cover letter. Include your first and last names, email address, telephone number, and optional mailing address. The cover letter will not be publicly viewable as long as it does not include any comments.

Include contact information each time you submit comments, data, documents, and other information to DOE. No telefacsimiles (“faxes”) will be accepted.

Comments, data, and other information submitted to DOE electronically should be provided in PDF (preferred), Microsoft Word or Excel, WordPerfect, or text (ASCII) file format. Provide documents that are not secured, that are written in English, and that are free of any defects or viruses. Documents should not contain special characters or any form of encryption and, if possible, they should carry the electronic signature of the author.

Campaign form letters. Please submit campaign form letters by the originating organization in batches of between 50 to 500 form letters per PDF or as one form letter with a list of supporters' names compiled into one or more PDFs. This reduces comment processing and posting time.

Confidential Business Information. Pursuant to 10 CFR 1004.11, any person submitting information that he or she believes to be confidential and exempt by law from public disclosure should submit via email two well-marked copies: One copy of the document marked “confidential” including all the information believed to be confidential, and one copy of the document marked “non-confidential” with the information believed to be confidential deleted. DOE will make its own determination about the confidential status of the information and treat it according to its determination.

It is DOE's policy that all comments may be included in the public docket, without change and as received, including any personal information provided in the comments (except information deemed to be exempt from public disclosure).

The Secretary of Energy has approved publication of this notice of proposed rulemaking.

This document of the Department of Energy was signed on July 15, 2021, by Kelly Speakes-Backman, Principal Deputy Assistant Secretary and Acting Assistant Secretary for Energy Efficiency and Renewable Energy, pursuant to delegated authority from the Secretary of Energy. That document with the original signature and date is maintained by DOE. For administrative purposes only, and in compliance with requirements of the Office of the Federal Register, the undersigned DOE Federal Register Liaison Officer has been authorized to sign and submit the document in electronic format for publication, as an official document of the Department of Energy. This administrative process in no way alters the legal effect of this document upon publication in the Federal Register .

For the reasons set forth in the preamble, DOE proposes to amend part 430 of chapter II, subchapter D, of title 10 of the Code of Federal Regulations, as set forth below:

The credit risk retention regulations are codified at 12 CFR part 43; 12 CFR part 244; 12 CFR part 373; 17 CFR part 246; 12 CFR part 1234; and 24 CFR part 267 (the Credit Risk Retention Regulations). The Credit Risk Retention Regulations require the OCC, Board, FDIC and Commission, in consultation with FHFA and HUD, to commence, and give notice of commencement of, a review of the following provisions of the Credit Risk Retention Regulations no later than December 24, 2019: (1) The definition of qualified residential mortgage (QRM) in section _.13 of the Credit Risk Retention Regulations; (2) the community-focused residential mortgage exemption in section _.19(f) of the Credit Risk Retention Regulations; and (3) the exemption for qualifying three-to-four unit residential mortgage loans in section _.19(g) of the Credit Risk Retention Regulations (collectively, the “subject residential mortgage provisions”). The Credit Risk Retention Regulations also require that, after completion of this review, but no later than six months after publication of the notice announcing the review, unless extended by the agencies, the agencies publish a notice disclosing the determination of their review.

The agencies published a notification announcing the commencement of the review in the Federal Register on December 20, 2019 (84 FR 70073). The agencies published a notification announcing their decision to extend to June 20, 2021, the period for completion of the review and publication of notification disclosing the determination of the review, in the Federal Register on June 30, 2020 (85 FR 39099).

The agencies are providing notification that the agencies have extended the period for completion of their review of the subject residential mortgage provisions and publication of the notice disclosing a determination of this review until December 20, 2021.

The FAA invites you to send any written relevant data, views, or arguments about this proposal. Send your comments to an address listed under ADDRESSES . Include “Docket No. FAA-2021-0197; Project Identifier 2018-SW-107-AD” at the beginning of your comments. The most helpful comments reference a specific portion of the proposal, explain the reason for any recommended change, and include supporting data. The FAA will consider all comments received by the closing date and may amend this proposal because of those comments.

Except for Confidential Business Information (CBI) as described in the following paragraph, and other information as described in 14 CFR 11.35, the FAA will post all comments received, without change, to https://www.regulations.gov, including any personal information you provide. The agency will also post a report summarizing each substantive verbal contact received about this NPRM.

CBI is commercial or financial information that is both customarily and actually treated as private by its owner. Under the Freedom of Information Act (FOIA) (5 U.S.C. 552), CBI is exempt from public disclosure. If your comments responsive to this NPRM contain commercial or financial information that is customarily treated as private, that you actually treat as private, and that is relevant or responsive to this NPRM, it is important that you clearly designate the submitted comments as CBI. Please mark each page of your submission containing CBI as “PROPIN.” The FAA will treat such marked submissions as confidential under the FOIA, and they will not be placed in the public docket of this NPRM. Submissions containing CBI should be sent to Rao Edupuganti, Aerospace Engineer, Dynamic Systems Section, Technical Innovation Policy Branch, Policy & Innovation Division, FAA, 10101 Hillwood Pkwy., Fort Worth, TX 76177; telephone (817) 222-5110; email rao.edupuganti@faa.gov. Any commentary that the FAA receives which is not specifically designated as CBI will be placed in the public docket for this rulemaking.

EASA, which is the Technical Agent for the Member States of the European Union, has issued EASA AD 2018-0263, dated December 7, 2018 (EASA AD 2018-0263), to correct an unsafe condition for Airbus Helicopters Model EC 155 B and EC 155 B1 helicopters. EASA advises that after an accident on a Model EC225 helicopter, an investigation revealed the failure of an MGB second stage planet gear. EASA states that one of the two types of planet gear used in the MGB epicyclic module is subject to higher outer race contact pressures and therefore is more susceptible to spalling and cracking. EASA AD 2018-0263 consequently requires repetitive inspections of the MGB magnetic plugs, the MGB filer, and the oil sump for particles, and depending on the results of those inspections, removing or replacing certain parts. EASA AD 2018-0263 also requires reducing the life limit of Type Z planet gear assemblies. EASA AD 2018-0263 also requires, if certain gear assemblies are installed, either replacing the MGB or replacing the epicyclic reduction gear. Finally EASA AD 2018-0263 prohibits installing a Type Y planet gear assembly or an MGB with a Type Y planet gear assembly on any helicopter.

These helicopters have been approved by EASA and are approved for operation in the United States. Pursuant to the FAA's bilateral agreement with the European Union, EASA has notified the FAA of the unsafe condition described in its AD. The FAA is proposing this AD after evaluating all known relevant information and determining that an unsafe condition is likely to exist or develop on other products of the same type designs.

The FAA reviewed Airbus Helicopters Alert Service Bulletin ASB No. EC155-05A034, Revision 5, dated December 4, 2018 (ASB EC155-05A34 Rev 5) for Model EC 155 helicopters, which specifies periodic inspections of the MGB magnetic plugs, the MGB filter, and the oil sump for particles. ASB EC155-05A34 Rev 5 also specifies identifying the type of gear assembly installed in the MGB and replacing any Type Y planet gear assembly within 50 hours time-in-service (TIS). For Type Z gear assemblies that have logged less than 1,800 hours TIS since new, this service information specifies replacing the gear assembly before exceeding 1,800 total hours TIS, and for Type Z gear assemblies that have logged 1,800 or more total hours TIS, replacing the gear assembly within 600 hours TIS.

The FAA also reviewed Airbus Helicopters Service Bulletin SB No. EC155-63-016, Revision 4, dated July 26, 2018, for Model EC 155 helicopters. This service information specifies procedures for replacing the MGB epicyclic reduction gear without removing the MGB.

This service information is reasonably available because the interested parties have access to it through their normal course of business or by the means identified in the ADDRESSES section.

This proposed AD would require for helicopters with at least one Type Y planet gear assembly with a certain serial number (S/N) installed, or at least one Type Z planet gear assembly with a certain S/N installed, within 10 hours TIS after the effective date of this AD and thereafter at intervals not to exceed 10 hours TIS, inspecting the MGB magnetic plugs for particles. If there are particles, the proposed AD would require further inspections and analyses, and replacing the MGB, depending on the type and the size of the particles.

This proposed AD would also require for helicopters with a Type Y planet gear assembly with a certain S/N installed, within 25 hours TIS after the effective date of this AD, inspecting the MGB filter for particles. If there are particles, this proposed AD would require further inspections and analyses, and replacing the MGB, depending on the type and the size of the particles. This proposed AD would require for helicopters with at least one Type Y planet gear assembly with a certain S/N installed, within 50 hours TIS after the effective date of this AD, replacing the MGB. As an alternative to replacing the MGB, this proposed AD would allow replacing the epicyclic reduction gear in the affected MGB.

Additionally, this proposed AD would require, for helicopters without any Type Y planet gear assembly but at least one Type Z planet gear assembly with a certain S/N installed, replacing the MGB within 50 hours TIS after the effective date of this AD or before any planet gear assembly accumulates 1,800 total hours TIS, whichever occurs later. As an alternative to replacing the MGB, this proposed AD would allow replacing the epicyclic reduction gear in the affected MGB.

This proposed AD would require, for helicopters with at least one Type Z planet gear with a certain S/N installed, within certain compliance times specified in the figures in this AD, inspecting the MGB filter and inspecting the oil sump for particles. If there are particles this proposed AD would require further inspections and analyses, and replacing the MGB, depending on the type and the size of the particles.

This proposed AD would prohibit installing an MGB with a certain serial numbered Type Y planet gear assembly and this proposed AD would also prohibit installing a Type Y planet gear assembly with a certain S/N on any helicopter.

This proposed AD would also prohibit installing certain serial numbered Type Z planet gear assemblies that have accumulated 1,800 or more total hours TIS and prohibit installing an MGB with certain serial numbered Type Z planet gear assemblies that have accumulated 1,800 or more total hours TIS.

Finally, this proposed AD would prohibit installing an MGB if the type of the planet gear assembly cannot be determined and would also prohibit installing any planet gear assembly if the type cannot be determined.

EASA AD 2018-0263 specifies compliance times based on flight hours and calendar dates. This proposed AD would set compliance times based on hours TIS or before further flight. EASA AD 2018-0263 allows a pilot to inspect the MGB magnetic plugs for particles, while this proposed AD would not. For helicopters with at least one affected Type Z planet gear assembly that has accumulated 1,800 or more total hours TIS installed, EASA AD 2018-0263 requires replacing the MGB or epicyclic reduction gear within 600 flight hours after March 16, 2018, whereas this proposed AD would require either of those replacements within 50 hours TIS after the effective date of this proposed AD instead. If 16NCD13 particles are present, EASA AD 2018-0263 requires taking a 1 liter sample of oil and returning it to Airbus Helicopters and removing the MGB for depot-level inspection, whereas this proposed AD would require replacing the MGB instead.

The FAA considers this proposed AD to be an interim action. If final action is later identified, the FAA might consider further rulemaking then.

The FAA estimates that this proposed AD would affect 14 helicopters of U.S. Registry. The FAA estimates that operators may incur the following costs in order to comply with this proposed AD. Labor costs are estimated at $85 per work-hour.

Inspecting the magnetic plugs for particle deposits would take about 1 work-hour for an estimated cost of $85 per helicopter per inspection cycle.

Inspecting the MGB filter and oil sump for particle deposits would take about 1 work-hour for an estimated cost of $85 per helicopter per inspection cycle.

Replacing an MGB would take about 42 work-hours, and parts would cost about $295,000 (overhauled) for an estimated total cost of $298,570 per helicopter.

Replacing the epicyclic reduction gear would take about 56 work-hours and parts would cost about $11,404 for an estimated total cost of $16,164 per helicopter.

Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, section 106, describes the authority of the FAA Administrator. Subtitle VII: Aviation Programs, describes in more detail the scope of the Agency's authority.

The FAA is issuing this rulemaking under the authority described in Subtitle VII, Part A, Subpart III, Section 44701: General requirements. Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.

The FAA determined that this proposed AD would not have federalism implications under Executive Order 13132. This proposed AD would not have 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.

For the reasons discussed, I certify this proposed regulation:

1. Is not a “significant regulatory action” under Executive Order 12866,

2. Would not affect intrastate aviation in Alaska, and

3. Would not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.

Accordingly, under the authority delegated to me by the Administrator, the FAA proposes to amend 14 CFR part 39 as follows:

The FAA invites you to send any written relevant data, views, or arguments about this proposal. Send your comments to an address listed under ADDRESSES . Include “Docket No. FAA-2021-0573; Project Identifier 2018-CE-046-AD” at the beginning of your comments. The most helpful comments reference a specific portion of the proposal, explain the reason for any recommended change, and include supporting data. The FAA will consider all comments received by the closing date and may amend this proposal because of those comments.

Except for Confidential Business Information (CBI) as described in the following paragraph, and other information as described in 14 CFR 11.35, the FAA will post all comments received, without change, to https://www.regulations.gov, including any personal information you provide. The agency will also post a report summarizing each substantive verbal contact received about this NPRM.

CBI is commercial or financial information that is both customarily and actually treated as private by its owner. Under the Freedom of Information Act (FOIA) (5 U.S.C. 552), CBI is exempt from public disclosure. If your comments responsive to this NPRM contain commercial or financial information that is customarily treated as private, that you actually treat as private, and that is relevant or responsive to this NPRM, it is important that you clearly designate the submitted comments as CBI. Please mark each page of your submission containing CBI as “PROPIN.” The FAA will treat such marked submissions as confidential under the FOIA, and they will not be placed in the public docket of this NPRM. Submissions containing CBI should be sent to Richard R. Thomas, Aviation Safety Engineer, Denver ACO Branch, FAA, 26805 E 68th Avenue, Denver, CO 80249. Any commentary that the FAA receives which is not specifically designated as CBI will be placed in the public docket for this rulemaking.

The FAA received a report that an operator found that one of the fuselage strakes was “loose having excess play” on two different Pilatus Model PC-12/47E airplanes. Further inspection found the fuselage main frame at frame station 40 and the strake attachment brackets had cracks extending from the attachment bolt hole at the upper most attachment location. Both airplanes had a SPECTRE Lift Platform System, STC SA00634DE, installed. The deployment of the lift platform causes buffeting of the strakes. This condition, if not addressed, could result in airplane flutter and reduced lateral stability, which may lead to loss of control of the airplane.

The FAA is issuing this NPRM after determining that the unsafe condition described previously is likely to exist or develop on other products of the same type design.

The FAA reviewed Pilatus Service Bulletin PC-12 Series, Report Number 12-1700-64-0000, Revision B, dated August 10, 2018 (Pilatus Report 12-1700-64-0000B), which contains procedures for inspection of all fuselage strake attachment bolts and the surrounding structure. This service information is reasonably available because the interested parties have access to it through their normal course of business or by the means identified in ADDRESSES .

This proposed AD would require inspecting the strake, attachment brackets, and bolts for movement and damage, both internal and external, and replacing or repairing any damaged parts.

Pilatus Report 12-1700-64-0000B specifies a one-time inspection within 10 flight hours of issuance of the SB and recommends repeat inspections without specifying an inspection interval. This proposed AD would require repeating the inspection every 150 flight hours. Pilatus Report 12-1700-64-0000B specifies contacting Pilatus for further instructions. This proposed AD would require using an FAA-approved repair method. Pilatus Report 12-1700-64-0000B applies to Pilatus PC-12 aircraft serial numbers 190 to 1575. This proposed AD would apply to all Pilatus Aircraft Ltd. Models PC-12/45, PC-12/47, and PC-12/47E airplanes, regardless of serial number, if STC SA00634DE is installed.

The FAA considers this AD an interim action. Pilatus is working on a modification with the intent of minimizing, if not eliminating, the buffeting of the strakes. Once this action is developed, approved, and available, the FAA may consider additional rulemaking.

The FAA estimates that this AD, if adopted as proposed, would affect 30 airplanes of U.S. registry.

The FAA estimates the following costs to comply with this proposed AD:

The extent of damage found during the proposed inspections may vary considerably from airplane to airplane. The FAA has no way of knowing how many airplanes may have damage or the extent of damage each airplane may have.

Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, section 106, describes the authority of the FAA Administrator. Subtitle VII: Aviation Programs, describes in more detail the scope of the Agency's authority.

The FAA is issuing this rulemaking under the authority described in Subtitle VII, Part A, Subpart III, Section 44701: General requirements. Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.

The FAA determined that this proposed AD would not have federalism implications under Executive Order 13132. This proposed AD would not have 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.

For the reasons discussed above, I certify this proposed regulation:

(1) Is not a “significant regulatory action” under Executive Order 12866,

(2) Would not affect intrastate aviation in Alaska, and

(3) Would not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.

Accordingly, under the authority delegated to me by the Administrator, the FAA proposes to amend 14 CFR part 39 as follows:

The FAA invites you to send any written relevant data, views, or arguments about this proposal. Send your comments to an address listed under ADDRESSES . Include “Docket No. FAA-2021-0576; Project Identifier 2019-CE-008-AD” at the beginning of your comments. The most helpful comments reference a specific portion of the proposal, explain the reason for any recommended change, and include supporting data. The FAA will consider all comments received by the closing date and may amend this proposal because of those comments.

Except for Confidential Business Information (CBI) as described in the following paragraph, and other information as described in 14 CFR 11.35, the FAA will post all comments received, without change, to https://www.regulations.gov, including any personal information you provide. The agency will also post a report summarizing each substantive verbal contact received about this NPRM.

CBI is commercial or financial information that is both customarily and actually treated as private by its owner. Under the Freedom of Information Act (FOIA) (5 U.S.C. 552), CBI is exempt from public disclosure. If your comments responsive to this NPRM contain commercial or financial information that is customarily treated as private, that you actually treat as private, and that is relevant or responsive to this NPRM, it is important that you clearly designate the submitted comments as CBI. Please mark each page of your submission containing CBI as “PROPIN.” The FAA will treat such marked submissions as confidential under the FOIA, and they will not be placed in the public docket of this NPRM. Submissions containing CBI should be sent to Mike Kiesov, Aviation Safety Engineer, General Aviation & Rotorcraft Section, International Validation Branch, FAA, 901 Locust, Room 301, Kansas City, MO 64106. Any commentary that the FAA receives which is not specifically designated as CBI will be placed in the public docket for this rulemaking.

The Civil Aviation Authority (CAA), which is the aviation authority for New Zealand, has issued AD No. DCA/ 750XL/36, effective date February 7, 2019 (referred to after this as “the MCAI”), to correct an unsafe condition for certain Pacific Aerospace Limited Model 750XL airplanes. The MCAI states:

The MCAI requires inspecting the installation of the fuel pickup assembly and the wing spar web on both wings and, if any defects are found, taking all necessary corrective actions. You may examine the MCAI in the AD docket at https://www.regulations.gov by searching for and locating Docket No. FAA-2021-0576.

The FAA reviewed Pacific Aerospace Mandatory Service Bulletin PACSB/XL/109, Issue 1, dated January 16, 2019. The service information contains procedures for inspecting the wing leading edge tank fuel pickup assembly to determine if the assembly is under stress and for additional inspections and corrective actions if necessary. This service information is reasonably available because the interested parties have access to it through their normal course of business or by the means identified in the ADDRESSES section.

This product has been approved by the aviation authority of another country and is approved for operation in the United States. Pursuant to the FAA's bilateral agreement with this State of Design Authority, it has notified the FAA of the unsafe condition described in the MCAI and service information referenced above. The FAA is issuing this NPRM after determining the unsafe condition described previously is likely to exist or develop on other products of the same type design.

This proposed AD would require accomplishing the actions specified in the service information already described.

The FAA estimates that this AD, if adopted as proposed, would affect 23 airplanes of U.S. registry. The FAA also estimates that it would take about 1 work-hour per airplane to comply with the inspection that would be required by this proposed AD. The average labor rate is $85 per work-hour.

Based on these figures, the FAA estimates the inspection cost of this proposed AD on U.S. operators to be $1,955, or $85 per airplane.

In addition, the FAA estimates that any necessary follow-on actions would take 4 work-hours and require parts costing $500, for a cost of $840 per airplane. The FAA has no way of determining the number of airplanes that may need these actions.

The FAA has included all known costs in its cost estimate. According to the manufacturer, however, some of the costs of this proposed AD may be covered under warranty, thereby reducing the cost impact on affected operators.

Title 49 of the United States Code specifies the FAA's authority to issue rules on aviation safety. Subtitle I, section 106, describes the authority of the FAA Administrator. Subtitle VII: Aviation Programs, describes in more detail the scope of the Agency's authority.

The FAA is issuing this rulemaking under the authority described in Subtitle VII, Part A, Subpart III, Section 44701: General requirements. Under that section, Congress charges the FAA with promoting safe flight of civil aircraft in air commerce by prescribing regulations for practices, methods, and procedures the Administrator finds necessary for safety in air commerce. This regulation is within the scope of that authority because it addresses an unsafe condition that is likely to exist or develop on products identified in this rulemaking action.

The FAA determined that this proposed AD would not have federalism implications under Executive Order 13132. This proposed AD would not have 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.

For the reasons discussed above, I certify this proposed regulation:

(1) Is not a “significant regulatory action” under Executive Order 12866,

(2) Would not affect intrastate aviation in Alaska, and

(3) Would not have a significant economic impact, positive or negative, on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.

Accordingly, under the authority delegated to me by the Administrator, the FAA proposes to amend 14 CFR part 39 as follows:

The FAA's authority to issue rules regarding aviation safety is found in Title 49 of the United States Code. Subtitle I, Section 106, describes the authority of the FAA Administrator. Subtitle VII, Aviation Programs, describes in more detail the scope of the agency's authority. This rulemaking is promulgated under the authority described in Subtitle VII, Part A, Subpart I, Section 40103. Under that section, the FAA is charged with prescribing regulations to assign the use of airspace necessary to ensure the safety of aircraft and the efficient use of airspace. This regulation is within the scope of that authority, as it would amend Class E airspace in Chester, SC; Lancaster, SC; Waxhaw, NC; and Lincolnton, NC, to support IFR operations in the area.

Interested persons are invited to comment on this proposed rulemaking by submitting such written data, views, or arguments, as they may desire. Comments that provide the factual basis supporting the views and suggestions presented are particularly helpful in developing reasoned regulatory decisions on the proposal. Comments are specifically invited on the overall regulatory, aeronautical, economic, environmental, and energy-related aspects of the proposal.

Communications should identify both docket numbers (Docket No. FAA-2021-0532 and Airspace Docket No. 21-ASO-19) and be submitted in triplicate to DOT Docket Operations (see ADDRESSES section for the address and phone number). You may also submit comments through the internet at https://www.regulations.gov.

Persons wishing the FAA to acknowledge receipt of their comments on this action must submit with those comments a self-addressed stamped postcard on which the following statement is made: “Comments to FAA Docket No. FAA-2021-0532; Airspace Docket No. 21-ASO-19.” The postcard will be date/time stamped and returned to the commenter.

All communications received before the specified closing date for comments will be considered before taking action on the proposed rule. The proposal contained in this document may be changed in light of the comments received. All comments submitted will be available for examination in the public docket both before and after the comment closing date. A report summarizing each substantive public contact with FAA personnel concerned with this rulemaking will be filed in the docket.

An electronic copy of this document may be downloaded through the internet at https://www.regulations.gov. Recently published rulemaking documents can also be accessed through the FAA's web page at https://www.faa.gov/air_traffic/publications/airspace_amendments/.

You may review the public docket containing the proposal, any comments received and any final disposition in person in the Dockets Office (see the ADDRESSES section for address and phone number) between 9:00 a.m. and 5:00 p.m., Monday through Friday, except federal holidays. An informal docket may also be examined between 8:00 a.m. and 4:30 p.m., Monday through Friday, except federal holidays, at the office of the Eastern Service Center, Federal Aviation Administration, Room 350, 1701 Columbia Avenue, College Park, GA 30337.

This document proposes to amend FAA Order 7400.11E, Airspace Designations and Reporting Points, dated July 21, 2020, and effective September 15, 2020. FAA Order 7400.11E is publicly available as listed in the ADDRESSES section of this document. FAA Order 7400.11E lists Class A, B, C, D, and E airspace areas, air traffic service routes, and reporting points.

The FAA proposes an amendment to 14 CFR part 71 to amend Class E airspace extending upward from 700 feet above the surface at:

The Chester Catawba Regional Airport, Chester, SC radius would increase to 9.0 miles, (previously 7.0 miles). In addition, this action would update the airport's name to Chester Catawba Regional Airport, (previously Chester Municipal Airport).

The radius of the Lancaster County-McWhirter Field Airport, Lancaster, SC, would increase to 8.3 miles, (previously 7.0 miles) and within 4.0 miles each side of the 059° bearing from the airport extending from the 8.3-mile radius to 10.9 miles northeast of the airport. This action would also update the geographical coordinates of the Lancaster County-McWhirter Field Airport to coincide with the FAA's database.

The radius of the JAARS-Townsend Airport, Waxhaw, NC, would increase to 9.3 miles, (previously 7 miles). In addition, this action would update the name to JAARS-Townsend Airport, (previously Waxhaw, JAARS-Townsend Airport).

The radius of the Lincolnton-Lincoln County Regional Airport, Lincolnton, NC would increase to 8.5 miles, (previously 6.4 miles). In addition, this action would update the airport name to Lincolnton-Lincoln County Regional Airport, (previously Lincolnton, Lincoln County Airport). This action would also update the geographical coordinates of the Lincolnton-Lincoln County Regional Airport to coincide with the FAA's database.

Class E airspace designations are published in Paragraph 6005, of FAA Order 7400.11E, dated July 21, 2020, and effective September 15, 2020, which is incorporated by reference in 14 CFR 71.1. The Class E airspace designations listed in this document will be published subsequently in the Order.

FAA Order 7400.11, Airspace Designations and Reporting Points, is published yearly and effective on September 15.

The FAA has determined that this proposed regulation only involves an established body of technical regulations for which frequent and routine amendments are necessary to keep them operationally current. It, therefore: (1) Is not a “significant regulatory action” under Executive Order 12866; (2) is not a “significant rule” under DOT Regulatory Policies and Procedures (44 FR 11034; February 26, 1979); and (3) does not warrant preparation of a Regulatory Evaluation as the anticipated impact is so minimal. Since this is a routine matter that will only affect air traffic procedures and air navigation, it is certified that this proposed rule, when promulgated, will not have a significant economic impact on a substantial number of small entities under the criteria of the Regulatory Flexibility Act.

This proposal will be subject to an environmental analysis in accordance with FAA Order 1050.1F, “Environmental Impacts: Policies and Procedures”, prior to any FAA final regulatory action.

In consideration of the foregoing, the Federal Aviation Administration proposes to amend 14 CFR part 71 as follows:

All comments received in response to this docket are considered part of the public record. The Drug Enforcement Administration (DEA) will make comments available, unless reasonable cause is given, for public inspection online at http://www.regulations.gov. Such information includes personal identifying information (such as your name, address, etc.) voluntarily submitted by the commenter. The Freedom of Information Act applies to all comments received. If you want to submit personal identifying information (such as your name, address, etc.) as part of your comment, but do not want DEA to make it publicly available, you must include the phrase “PERSONAL IDENTIFYING INFORMATION” in the first paragraph of your comment. You must also place all of the personal identifying information you do not want made publicly available in the first paragraph of your comment and identify what information you want redacted.

If you want to submit confidential business information as part of your comment, but do not want DEA to make it publicly available, you must include the phrase “CONFIDENTIAL BUSINESS INFORMATION” in the first paragraph of your comment. You must also prominently identify the confidential business information to be redacted within the comment.

DEA will generally make available in publicly redacted form comments containing personal identifying information and confidential business information identified as directed above. If a comment has so much confidential business information that DEA cannot effectively redact it, DEA may not make available publicly all or part of that comment. Comments posted to http://www.regulations.gov may include any personal identifying information (such as name, address, and phone number) included in the text of your electronic submission that is not identified as confidential as directed above.

An electronic copy of this document and supplemental information to this proposed rule are available at http://www.regulations.gov for easy reference.

Pursuant to 21 U.S.C. 811(a), this action is a formal rulemaking “on the record after opportunity for a hearing.” Such proceedings are conducted pursuant to the provisions of the Administrative Procedure Act, 5 U.S.C. 551-559. 21 CFR 1308.41-1308.45; 21 CFR part 1316, subpart D. Interested persons may file requests for a hearing or notices of intent to participate in a hearing in conformity with the requirements of 21 CFR 1308.44(a) or (b), and they shall include a statement of interest in the proceeding and the objections or issues, if any, concerning which the person desires to be heard. 21 CFR 1316.47(a). Any interested person may file a waiver of an opportunity for a hearing or to participate in a hearing together with a written statement regarding the interested person's position on the matters of fact and law involved in any hearing as set forth in 21 CFR 1308.44(c).

All requests for hearing and waivers of participation, together with a written statement of position on the matters of fact and law involved in such hearing, must be sent to DEA using the address information provided above.

The United States is a party to the 1971 United Nations Convention on Psychotropic Substances (1971 Convention), February 21, 1971, 32 U.S.T. 543, 1019 U.N.T.S. 175, as amended. Procedures respecting changes in drug schedules under the 1971 Convention are governed domestically by 21 U.S.C. 811(d)(2-4). When the United States receives notification of a scheduling decision pursuant to Article 2 of the 1971 Convention indicating that a drug or other substance has been added to a schedule specified in the notification, the Secretary of the Department of Health and Human Services (HHS), 1 after consultation with the Attorney General, shall first determine whether existing legal controls under subchapter I of the Controlled Substances Act (CSA) and the Federal Food, Drug, and Cosmetic Act meet the requirements of the schedule specified in the notification with respect to the specific drug or substance. 21 U.S.C. 811(d)(3). In the event that the Secretary of HHS (Secretary) did not consult with the Attorney General, and the Attorney General did not issue a temporary order, as provided under 21 U.S.C. 811(d)(4), the procedures for permanent scheduling set forth in 21 U.S.C. 811(a) and (b) control. Pursuant to 21 U.S.C. 811(a)(1), the Attorney General may add to such a schedule any drug or other substance, if he finds that such drug or other substance has a potential for abuse, and makes the findings prescribed by 21 U.S.C. 812(b) for the schedule in which such drug is to be placed. The Attorney General has delegated this scheduling authority to the Administrator of DEA. 28 CFR 0.100.

Amineptine is a synthetic tricyclic antidepressant with central nervous system (CNS) stimulating properties that, according to HHS, has no approved medical use and no known therapeutic application in the United States. Pharmacological studies indicate that amineptine's primary mode of action is to increase extracellular levels of dopamine and norepinephrine as well as inhibit re-uptake of dopamine and norepinephrine within the striatum and limbic areas of the brain.

In 1978, amineptine was approved for use in France as an antidepressant and subsequently marketed in 66 countries throughout Africa, Asia, Europe, and South America. As documented by the World Health Organization's (WHO) Expert Committee on Drug Dependence in its 33rd report (2003) (WHO 2003 report), amineptine has been withdrawn from the market in 49 of the 66 countries. The status of current production of amineptine in other countries is not known, although a small quantity is most likely produced for research purposes.

In April 2003, the United Nations Commission on Narcotic Drugs, on the advice of the Director-General of the WHO, added amineptine to Schedule II of the 1971 Convention, thus notifying all parties to the 1971 Convention. 2 Because the procedures in 21 U.S.C. 811(d)(3) and (4) for consultation and issuance of a temporary order for amineptine, discussed in the above legal authority section, were not followed, DEA is utilizing the procedures for permanent scheduling set forth in 21 U.S.C. 811(a) and (b) to control amineptine. Such scheduling would satisfy the United States' international obligations.

Article 2, paragraph 7(b), of the 1971 Convention sets forth the minimum requirements that the United States must meet when a substance has been added to Schedule II of the 1971 Convention. Pursuant to the 1971 Convention, the United States must require licenses for the manufacture, export and import, and distribution of amineptine. This license requirement is accomplished by the CSA's registration requirement as set forth in 21 U.S.C. 822, 823, 957, 958 and in accordance with 21 CFR parts 1301 and 1312. In addition, the United States must adhere to specific export and import provisions set forth in the 1971 Convention. This requirement is accomplished by the CSA's export and import provisions established in 21 U.S.C. 952, 953, 957, 958 and in accordance with 21 CFR part 1312. Likewise, under Article 13, paragraphs 1 and 2, of the 1971 Convention, a party to the 1971 Convention may notify through the UN Secretary-General another party that it prohibits the importation of a substance in Schedule II, III, or IV of the 1971 Convention. If such notice is presented to the United States, the United States shall take measures to ensure that the named substance is not exported to the notifying country. This requirement is also accomplished by the CSA's export provisions mentioned above. Under Article 16, paragraph 4, of the 1971 Convention, the United States is required to provide annual statistical reports to the International Narcotics Control Board (INCB). Using INCB Form P, the United States shall provide the following information: (1) In regard to each substance in Schedule I and II of the 1971 Convention, quantities manufactured in, exported to, and imported from each country or region as well as stocks held by manufacturers; (2) in regard to each substance in Schedule II and III of the 1971 Convention, quantities used in the manufacture of exempt preparations; and (3) in regard to each substance in Schedule II—IV of the 1971 Convention, quantities used for the manufacture of non-psychotropic substances or products. Lastly, under Article 2 of the 1971 Convention, the United States must adopt measures in accordance with Article 22 to address violations of any statutes or regulations that are adopted pursuant to its obligations under the 1971 Convention. Persons acting outside the legal framework established by the CSA are subject to administrative, civil, and/or criminal action; therefore, the United States complies with this provision.

DEA notes that there are differences between the schedules of substances in the 1971 Convention and the CSA. The CSA has five schedules (schedules I-V) with specific criteria set forth for each schedule. Schedule I is the only possible schedule in which a drug or other substance may be placed if it has high potential for abuse and no currently accepted medical use in treatment in the United States. See 21 U.S.C. 812(b). In contrast, the 1971 Convention has four schedules (Schedules I-IV) but does not have specific criteria for each schedule. The 1971 Convention simply defines its four schedules, in Article 1, to mean the correspondingly numbered lists of psychotropic substances annexed to the Convention, and altered in accordance with Article 2.

Pursuant to 21 U.S.C. 811(b), DEA gathered the necessary data on amineptine and, on August 12, 2008, submitted it to the Assistant Secretary for Health of HHS with a request for a scientific and medical evaluation of available information and a scheduling recommendation for amineptine. On November 8, 2011, HHS provided to DEA a written scientific and medical evaluation and scheduling recommendation entitled “Basis for the Recommendation for Control of Amineptine in Schedule I of the Controlled Substances Act.” In this recommendation, HHS presented its eight-factor analysis as required under 21 U.S.C. 811(b) and recommended that amineptine be added to schedule I of the CSA.

In response, DEA reviewed the scientific and medical evaluation and scheduling recommendation provided by HHS and all other relevant data and conducted its own eight-factor analysis pursuant to 21 U.S.C. 811(c). Included below is a brief summary of each factor as analyzed by HHS and DEA, and as considered by DEA in the scheduling decision. Both DEA and HHS analyses are available in their entirety under “Supporting and Related Material” of the public docket for this rule at http://www.regulations.gov under docket number DEA-371.

1. The Drug's Actual or Relative Potential for Abuse: As reported by HHS, the WHO 2003 report showed strong evidence of abuse in Europe and Asia, where amineptine was approved for use as an antidepressant. Additional HHS findings showed that due to reports of hepatotoxicity and abuse in Europe, Servier (a French pharmaceutical company) voluntarily discontinued the French marketing authorization in France and Spain for amineptine in 1999 (HHS, 2011;  3 WHO, 2002  4 ). However, as documented by the WHO 2003 report, the medical use of amineptine and its abuse in developing countries still existed during 1990 to 2003. Clinical studies used between 100—200 mg of amineptine (Lachatre et al., 1989;  5 Sbarra et al., 1981  6 ); however, case reports from various countries (none in the United States due to its lack of approved medical use or known therapeutic application in the United States) have reported hospitalizations due to amineptine abuse and overdose following the ingestion of 2,000-4,300 mg and even up to 12 g daily. However, adverse effects at prescribed doses of amineptine were still observed (see Factor 6).

Evidence shows that amineptine produces behavioral effects in humans and animals that are similar to amphetamine and cocaine (both in schedule II). Pharmacological studies have demonstrated that amineptine has reinforcing effects as shown by the self-administration test and has locomotor stimulant effects. Studies also have shown that amineptine increases extracellular concentrations of dopamine in the brain, particularly in the striatum and nucleus accumbens, which are structures constituting the reward pathway and are known to be involved in the abuse of drugs, including amphetamine and cocaine. The above data indicate that amineptine has the potential for abuse similar to other CNS stimulants controlled under the CSA, such as cocaine and amphetamine.

2. Scientific Evidence of the Drug's Pharmacological Effects, if Known: As stated by HHS, amineptine increases dopamine levels by inducing the synaptosomal release and inhibition of dopamine re-uptake and, to a lesser extent, increasing norepinephrine levels, a mode of action mechanistically similar to the known schedule II CNS stimulants amphetamine and cocaine. Animal behavioral studies have shown that amineptine, in addition to its CNS stimulant properties, has anti-depressant, locomotor, and anti-narcoleptic activities. Human behavioral studies have demonstrated that amineptine works similarly to other antidepressants, often with an earlier onset of therapeutic effects. Studies have shown that amineptine administration lowers depression rating scales in patients and results in a positive subjective quality of sleep and subsequent increase in attention and concentration upon waking.

3. The State of Current Scientific Knowledge Regarding the Drug or Other Substance: The chemical name of amineptine is 7-[(10,11-dihydro-5 H -dibenzo[ a,d ]cyclohepten-5-yl)amino]heptanoic acid. It is a white, crystalline powder and is soluble in water and in methanol. Humans rapidly absorb amineptine after oral administration, with mean peak plasma concentrations of amineptine and its main metabolite occurring at 1 hour and 1.5 hours, respectively. Amineptine is metabolized in the liver and rapidly excreted and eliminated through the kidneys with mean half-lives of 0.8 hours for amineptine and 2.5 hours for its metabolite. In humans, 70-75 percent of the administered dose of amineptine was excreted in the urine within 48 hours, with most of the elimination occurring within the first 12 hours.

Distribution of 14 C-amineptine was also evaluated in the Macaca fascicularis monkey using whole body autoradiography. Results demonstrated high levels of radio-labeled amineptine in the liver and kidneys, with lower levels of activity in the blood, gastrointestinal tract and spleen. In the brain, radioactivity was observed in the cortex, putamen, caudate nucleus, globus pallidus, pulvinar, and geniculate bodies, with lower levels noted in the hippocampus, substantia nigra, and medulla.

4. Its History and Current Pattern of Abuse: As mentioned by HHS, there are numerous published reports of amineptine abuse, including 186 cases of abuse between 1978 and 1988 reported to the Regional Centers of Pharmacovigilance and the Laboratory Eutherapie in France, and 65 cases of abuse between 1990 and 1998 appearing in the Observation of Illegal Drugs and Misuse of Psychotropic Medications database. Notably, amineptine has not been approved for medical use in the United States nor is there any documented abuse in the United States of amineptine.

At the 16th French Pharmacovigilance meeting in November 1994, the Fernand Widal Pharmacovigilance Centre reviewed 565 cases of amineptine “overconsumption” from 1978 to 1993, and reported multiple characteristics of amineptine abuse including: (1) Amineptine abusers typically had a history of alcoholism, drug abuse, and/or eating disorders; (2) 28 percent of the cases of amineptine abuse resulted in neuropsychiatric disorders; (3) 11 percent of patients developed acne-like lesions from amineptine use; (4) withdrawal from amineptine abuse was described as extremely difficult; (5) only 30 percent were abstinent after one month of withdrawal and long-term abstinence was uncommon; and (6) most patients obtained amineptine from pharmacists by prescription theft or by fraudulent prescriptions. Collectively, these three reports show that there has been a continued pattern of abuse from 1978 to 1998.

DEA noted that in the WHO 2003 report, the WHO's Expert Committee on Drug Dependence stated that the degree of risk to public health associated with the abuse liability of amineptine is substantial, while noting several adverse effects including hepatotoxicity, severe acne, and anxiety. The committee also noted the limited therapeutic usefulness of amineptine due to the availability of safer antidepressants.

Queries of DEA's System to Retrieve Information from Drug Evidence (STRIDE)/STARLiMS  7 and the National Forensic Laboratory Information System (NFLIS)  8 databases on November 17, 2020, did not generate any reports of amineptine, suggesting that it is not trafficked in the United States.

5. The Scope, Duration, and Significance of Abuse: According to the published case reports from 1984 to 2001 in France, Italy, Pakistan, Singapore, and Spain, the majority of the reported cases of amineptine abuse involved patients who were prescribed amineptine for an affective disorder. In these cases, abuse normally began one year after amineptine was prescribed for the treatment of depression by patients independently increasing their dosage, especially in those with a history of alcoholism, intravenous drug abuse, and eating disorders.

Amineptine abuse appears to be due to its psychostimulant effect. Indeed, reasons cited for its abuse were increased energy, joy, work output, alertness, and psychomotor performance. Presently, although internet searches result in websites with purported amineptine for sale, these sites do not list the formulation, purity, price, and quantity for this purported amineptine. In addition, the 1971 Convention currently controls amineptine internationally as a Schedule II substance. Amineptine is also controlled in Belgium, Canada, the Czech Republic, Denmark, Estonia, Germany, Greece, Hungary, Italy, Latvia, Lithuania, the Netherlands, Norway, Poland, Slovenia, and Sweden.

6. What, if Any, Risk There is to the Public Health: As reported by HHS, there are no known fatalities resulting from amineptine use or abuse. Some of the main public health risks of amineptine are related to its serious adverse effects, such as hepatotoxicity, severe acne, and gastrointestinal (acute pancreatitis) effects. In addition, neuropsychiatric symptoms including anxiety, insomnia, nervousness, irritability, dysarthria, acute psychosis, delusions, hallucinations, anorexia, agitation, psychotic disorders, and confusion have resulted from abuse of amineptine.

7. Its Psychic or Physiological Dependence Liability: HHS stated that amineptine has been shown to produce physical and psychological dependence as supported by clinical evidence. While amineptine has no clearly defined withdrawal syndrome, reports of withdrawal symptoms include anxiety, dysphoria, nausea, brief psychotic episodes, tremor, psychomotor agitation, somatic symptoms, and sleep disturbances. In addition, a strong desire to take amineptine was noted in individuals upon withdrawal of the drug, a typical characteristic of psychological dependence.

8. Whether the Substance is an Immediate Precursor of a Substance Already Controlled under the CSA: DEA and HHS find that amineptine is not an immediate precursor of a substance already controlled under the CSA.

Conclusion: Based on consideration of the scientific and medical evaluation and accompanying recommendation of HHS, and based on DEA's consideration of its own eight-factor analysis, DEA finds that these facts and all relevant data constitute substantial evidence of potential for abuse of amineptine. As such, DEA hereby proposes to schedule amineptine as a controlled substance under the CSA.

The CSA establishes five schedules of controlled substances known as schedules I, II, III, IV, and V. The CSA outlines the findings required to place a drug or other substance in any particular schedule. 21 U.S.C. 812(b). After consideration of the analysis and recommendation of the Assistant Secretary for Health of HHS and review of all available data, the Administrator of DEA, pursuant to 21 U.S.C. 812(b)(1), finds that:

(1) Amineptine has a high potential for abuse. Amineptine has stimulant and euphoric effects similar to cocaine and amphetamine, which are both schedule II drugs. Amineptine has a high potential for abuse that is equivalent to cocaine and amphetamine and has been abused throughout Europe and Asia.

(2) Amineptine has no currently accepted medical use in treatment in the United States. There are no approved New Drug Applications for amineptine and no known therapeutic application for amineptine in the United States. Therefore, amineptine has no currently accepted medical use in treatment in the United States. 9

(3) There is a lack of accepted safety for use of amineptine under medical supervision. Clinical experience showed that patients taking amineptine under medical supervision for depression misused and abused the drug by stealing or falsifying prescriptions and taking doses that were 10 to 20 times higher than prescribed. As a result of taking higher doses, many patients developed hepatic, gastrointestinal, cardiovascular, and psychiatric side effects. Amineptine was once marketed in 66 countries throughout Europe, Africa, Asia, and South America. However, amineptine was later withdrawn from the majority of countries due to its abuse potential and lack of safety. Therefore, there is a lack of accepted safety for the use of amineptine under medical supervision.

Although the first finding shows amineptine to have similar effects to schedule II substances such as cocaine and amphetamine, it bears reiterating that there is only one possible schedule in the CSA—schedule I—to place amineptine since it has no currently accepted medical use in treatment in the United States. See the background section for additional discussion.

Based on these findings, the Administrator of DEA concludes that amineptine warrants control in schedule I of the CSA. 21 U.S.C. 812(b)(1). More precisely, because of its stimulant effects, DEA proposes placing substance amineptine, including its salts, isomers, and salts of isomers, in 21 CFR 1308.11(f) (the stimulants category of schedule I).

If this rule is finalized as proposed, amineptine would be subject to the CSA's schedule I regulatory controls and administrative, civil, and criminal sanctions applicable to the manufacture, distribution, reverse distribution, import, export, engagement in research, conduct of instructional activities or chemical analysis with, and possession of schedule I controlled substances, including the following:

1. Registration. Any person who handles (manufactures, distributes, reverse distributes, imports, exports, engages in research, or conducts instructional activities or chemical analysis with, or possesses) amineptine, or who desires to handle amineptine, would need to be registered with DEA to conduct such activities pursuant to 21 U.S.C. 822, 823, 957, 958 and in accordance with 21 CFR parts 1301 and 1312 as of the effective date of a final scheduling action. Any person who currently handles amineptine and is not registered with DEA would need to submit an application for registration and may not continue to handle amineptine as of the effective date of a final scheduling action, unless DEA has approved that application for registration pursuant to 21 U.S.C. 822, 823, 957, 958 and in accordance with 21 CFR parts 1301 and 1312.

2. Disposal of stocks. Any person who does not desire or is not able to obtain a schedule I registration would be required to surrender or to transfer all quantities of currently held amineptine to a person registered with DEA before the effective date of a final scheduling action in accordance with all applicable Federal, State, local, and tribal laws. As of the effective date of a final scheduling action, amineptine would be required to be disposed of in accordance with 21 CFR part 1317, in addition to all other applicable Federal, State, local, and tribal laws.

3. Security. Amineptine would be subject to schedule I security requirements and would need to be handled and stored pursuant to 21 U.S.C. 821 and 823 and in accordance with 21 CFR 1301.71-1301.93, as of the effective date of a final scheduling action. Non-practitioners handling amineptine would also need to comply with the employee screening requirements of 21 CFR 1301.90 -1301.93.

4. Labeling and Packaging. All labels, labeling, and packaging for commercial containers of amineptine would need to be in compliance with 21 U.S.C. 825 and 958(e) and in accordance with 21 CFR part 1302, as of the effective date of a final scheduling action.

5. Quota. Only registered manufacturers would be permitted to manufacture amineptine in accordance with a quota assigned pursuant to 21 U.S.C. 826 and in accordance with 21 CFR part 1303, as of the effective date of a final scheduling action.

6. Inventory. Every DEA registrant who possesses any quantity of amineptine on the effective date of a final scheduling action would be required to take an inventory of amineptine on hand at that time, pursuant to 21 U.S.C. 827 and 958 and in accordance with 21 CFR 1304.03, 1304.04, and 1304.11(a) and (d).

Any person who becomes registered with DEA on or after the effective date of the final scheduling action would be required to take an initial inventory of all stocks of controlled substances (including amineptine) on hand on the date the registrant first engages in the handling of controlled substances, pursuant to 21 U.S.C. 827 and 958 and in accordance with 21 CFR 1304.03, 1304.04, and 1304.11(a) and (b).

After the initial inventory, every DEA registrant would be required to take a new inventory of all controlled substances (including amineptine) on hand every two years, pursuant to 21 U.S.C. 827 and 958 and in accordance with 21 CFR 1304.03, 1304.04, and 1304.11.

7. Records and Reports. Every DEA registrant would be required to maintain records and submit reports for amineptine, or products containing amineptine, pursuant to 21 U.S.C. 827 and 958 and in accordance with 21 CFR parts 1304, 1312, and 1317, as of the effective date of a final scheduling action. Manufacturers and distributors would be required to submit reports regarding amineptine to the Automation of Reports and Consolidated Order System pursuant to 21 U.S.C. 827 and in accordance with 21 CFR parts 1304 and 1312, as of the effective date of a final scheduling action.

8. Order Forms. Every DEA registrant who distributes amineptine would be required to comply with order form requirements, pursuant to 21 U.S.C. 828 and in accordance with 21 CFR part 1305, as of the effective date of a final scheduling action.

9. Importation and Exportation. All importation and exportation of amineptine would need to be in compliance with 21 U.S.C. 952, 953, 957, and 958 and in accordance with 21 CFR part 1312 as of the effective date of a final scheduling action.

10. Liability. Any activity involving amineptine not authorized by, or in violation of, the CSA or its implementing regulations, would be unlawful and may subject the person to administrative, civil, and/or criminal sanctions.

In accordance with 21 U.S.C. 811(a), this proposed scheduling action is subject to formal rulemaking procedures performed “on the record after opportunity for a hearing,” which are conducted pursuant to the provisions of 5 U.S.C. 556 and 557. The CSA sets forth procedures and criteria for scheduling a drug or other substance. Such actions are exempt from review by the Office of Management and Budget pursuant to Section 3(d)(1) of Executive Order (E.O.) 12866 and the principles reaffirmed in E.O. 13563.

This proposed regulation meets the applicable standards set forth in Sections 3(a) and 3(b)(2) of E.O. 12988, Civil Justice Reform, to eliminate drafting errors and ambiguity, minimize litigation, provide a clear legal standard for affected conduct, and promote simplification and burden reduction.

This proposed rulemaking does not have federalism implications warranting the application of E.O. 13132. The proposed rule does not have substantial direct effects on the States, on the relationship between the national government and the States, or the distribution of power and responsibilities among the various levels of government.

This proposed rule does not have tribal implications warranting the application of E.O. 13175. It does not have substantial direct effects 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.

This action does not impose a new collection of information requirement under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3521).

The Administrator of DEA, in accordance with the Regulatory Flexibility Act, 5 U.S.C. 601-612, has reviewed this proposed rule and, by approving it, certifies that it will not have a significant economic impact on a substantial number of small entities.

DEA proposes placing the substance amineptine, including its isomers, salts, and salts of isomers, in schedule I of the CSA. This action is being taken to enable the United States to meet its obligations under the 1971 Convention. If finalized, this action would impose the regulatory controls and administrative, civil, and/or criminal sanctions applicable to schedule I controlled substances on persons who handle (manufacture, distribute, reverse distribute, import, export, engage in research, conduct instructional activities or chemical analysis with, or possess), or propose to handle, amineptine.

According to HHS, amineptine has a high potential for abuse, has no currently accepted medical use in treatment in the United States, and lacks accepted safety for use under medical supervision. DEA's research confirms that there is no commercial market for amineptine in the United States. Additionally, queries of DEA's STRIDE/STARLiMS and the NFLIS databases on November 17, 2020, did not generate any reports of amineptine, suggesting that it is not trafficked in the United States. Therefore, DEA estimates that no United States entity currently handles amineptine and does not expect any United States entity to handle amineptine in the foreseeable future. DEA concludes that no United States entity would be affected by this rule, if finalized. As such, the proposed rule will not have a significant effect on a substantial number of small entities.

On the basis of information contained in the “Regulatory Flexibility Act” section above, DEA has determined pursuant to the Unfunded Mandates Reform Act (UMRA) of 1995 (2 U.S.C. 1501 et seq. ) that this action would not result in any Federal mandate that may result “in the expenditure by State, local, and tribal governments, in the aggregate, or by the private sector, of $100,000,000 or more (adjusted annually for inflation) in any 1 year * * *.” Therefore, neither a Small Government Agency Plan nor any other action is required under provisions of the UMRA of 1995.

For the reasons set out above, 21 CFR part 1308 is proposed to be amended to read as follows:

In accordance with the Federal Information Security Modernization Act of 2014, among other authorities, DOJ is responsible for complying with information security policies and procedures requiring information security protections commensurate with the risk and magnitude of harm resulting from the unauthorized access, use, disclosure, disruption, modification, or destruction of DOJ information and information systems. See, e.g., 44 U.S.C. 3554 (2018). Consistent with these requirements, DOJ must ensure that it maintains accurate audit and activity records of the observable occurrences on its information systems and networks (also referred to as “events”) that are significant and relevant to the security of DOJ information and information systems. These audit and activity records may include, but are not limited to, information that establishes what type of event occurred, when the event occurred, where the event occurred, the source of the event, the outcome of the event, and the identity of any individuals or subjects associated with the event. Additionally, monitored events—whether detected utilizing information systems maintaining audit and activity records, reported to the Department by information system users, or reported to the Department by the cybersecurity research community and members of the general public conducting good faith vulnerability discovery activities—may constitute occurrences that (1) actually or imminently jeopardize, without lawful authority, the integrity, confidentiality, or availability of information or an information system; or (2) constitute a violation or imminent threat of violation of law, security policies, security procedures, or acceptable use policies. The Department has developed a formal process to track and document these reported “incidents,” which may, in limited circumstances, include records of individuals reporting, or otherwise associated with, an actual or suspected event or incident.

The DOJ notice that published in the July 14, 2021 issue of the Federal Register , at 86 FR 37188 has proposed modifications to a Department-wide system of records retitled, “Department of Justice Information Technology, Information System, and Network Activity and Access Records,” JUSTICE/DOJ-002. This system covers the Department's tracking of all DOJ information technology, DOJ information system, and DOJ network activity and access by users. These records assist Department information security professionals in protecting DOJ information, ensuring the secure operation of DOJ information systems, and tracking and documenting incidents reported to the agency. The revisions to this notice reflect changes in technology, including the increased ability of the Department to link individuals to information technology, information system, or network activity, and to better describe the Department's records linking individuals to reported cybersecurity incidents or their access to certain information technologies, information systems, and networks through the internet or other authorized connections.

In this rulemaking, the Department proposes to exempt JUSTICE/DOJ-002 from certain provisions of the Privacy Act in order to avoid interference with the responsibilities of the Department to prevent the unauthorized access, use, disclosure, disruption, modification, or destruction of DOJ information and information systems. Additionally, the Department proposes to exempt JUSTICE/DOJ-002 from certain provisions of the Privacy Act to protect activity and audit log records on DOJ classified networks.

In accordance with 552a(k), this proposed action is subject to formal rulemaking procedures by giving interested persons an opportunity to participate in the rulemaking process “through submission of written data, views, or arguments,” pursuant to 5 U.S.C. 553. This proposed rule will promulgate certain Privacy Act exemptions for a DOJ system of records titled, “Department of Justice Information Technology, Information System, and Network Activity and Access Records,” JUSTICE/DOJ-002. This proposed rule does not raise novel legal or policy issues, nor does it adversely affect the economy, the budgetary impact of entitlements, grants, user fees, loan programs, or the rights and obligations of recipients thereof in a material way. The Department of Justice has determined that this rule is not a “significant regulatory action” under Executive Order 12866, section 3(f), and accordingly this rule has not been reviewed by the Office of Information and Regulatory Affairs within the Office of Management and Budget pursuant to Executive Order 12866.

This proposed rule will only impact Privacy Act-protected records, which are personal and generally do not apply to an individual's entrepreneurial capacity, subject to limited exceptions. Accordingly, the Chief Privacy and Civil Liberties Officer, in accordance with the Regulatory Flexibility Act (5 U.S.C. 605(b)), has reviewed this regulation and by approving it certifies that this regulation will not have a significant economic impact on a substantial number of small entities.

The Small Business Regulatory Enforcement Fairness Act (SBREFA) of 1996, 5 U.S.C. 801 et seq., requires the Department to comply with small entity requests for information and advice about compliance with statutes and regulations within the Department's jurisdiction. Any small entity that has a question regarding this document may contact the person listed in FOR FURTHER INFORMATION CONTACT paragraph, above. Persons can obtain further information regarding SBREFA on the Small Business Administration's web page at https://www.sba.gov/advocacy. This proposed rule is not a major rule as defined by 5 U.S.C. 804 of the Congressional Review Act.

This proposed rule will not have substantial direct effects on the States, on the relationship between the national government and the States, or on distribution of power and responsibilities among the various levels of government. Therefore, in accordance with Executive Order 13132, it is determined that this rule does not have sufficient federalism implications to warrant the preparation of a Federalism Assessment.

This proposed regulation meets the applicable standards set forth in sections 3(a) and 3(b)(2) of Executive Order 12988 to eliminate drafting errors and ambiguity, minimize litigation, provide a clear legal standard for affected conduct, and promote simplification and burden reduction.

This proposed rule will have no implications for Indian Tribal governments. More specifically, it does not have substantial direct effects 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. Therefore, the consultation requirements of Executive Order 13175 do not apply.

This proposed rule will not result in the expenditure by State, local and tribal governments, in the aggregate, or by the private sector, of $100,000,000, as adjusted for inflation, or more in any one year, and it will not significantly or uniquely affect small governments. Therefore, no actions were deemed necessary under the provisions of the Unfunded Mandates Reform Act of 1995.

The Paperwork Reduction Act of 1995, 44 U.S.C. 3507(d), requires the Department to consider the impact of paperwork and other information collection burdens imposed on the public. There are no current or new information collection requirements associated with this proposed rule.

Pursuant to the authority vested in the Attorney General by 5 U.S.C. 552a and delegated to me by Attorney General Order 2940-2008, the Department of Justice proposes to amend 28 CFR part 16 as follows:

This modification will change the submission process of information collection request, Notice to Mediation Agency, (Agency Form F-7) from mail-in to electronic submission. This revision is necessary to increase efficiency of FMCS both by allowing FMCS to receive Agency Form F-7's more quickly, but also to reduce processing time. This will allow the Service to provide its services to the parties more quickly. This revision will also remove the language which includes the verbiage of the Form-F7, to allow for FMCS to modify the form, if necessary, without necessitating additional rule change.

FMCS' authority to issue rules is found in 29 U.S.C. 172 of Taft Harley Act of 1947. This regulation is within the scope of that authority.

FMCS solicits comments to

(i) Evaluate whether the proposed change of submission from mail-in to electronic is necessary, including whether the change will have practical utility.

(ii) Enhance the quality, utility, and clarity of the information collection submission process.

(iii) Minimize the burden of the collections of information on those who are to respond, including the use of appropriate automated, electronic collection technologies or other forms of information technology.

The following describes the specific changes proposed by this rulemaking:

• FMCS revises the language “shall be in writing.” to “electronically via a platform provided by FMCS. If electronic submission creates an undue hardship, the filer may contact the FMCS Notice Processing office to explain the circumstances and receive assistance.”

• FMCS revises the language “The following Form F-7, for use by the parties in filing a notice of dispute, has been prepared by the Service:” to “The Form F-7, for use by the parties in filing a notice of dispute, has been prepared by the Service.”

• FMCS removes the form titled “Notice to Mediation Agencies”.

In consideration of the foregoing, FMCS proposed to amend 29 CFR 1402.1 as follows:

Throughout this document wherever “we,” “us,” or “our” is used, we mean the EPA.

On May 7, 2020, the Secretary of Energy and Environment for the State of Oklahoma submitted for EPA review and approval under section 110 of the CAA and 40 CFR part 51, revisions to the Oklahoma Air Quality SIP. The revisions were included in the state's annual SIP update for 2019 and consisted of revisions to Subchapters 2 and 39 and Appendix Q in the OAC Title 252 Chapter 100, which became effective on September 15, 2019. In this action, we note that we are only proposing to approve revisions to OAC Title 252 Chapter 100 Subchapter 39 (OAC 252:100-39) Sections 4, 16, 40, and 41. We are not taking action on Subchapter 2 and Appendix Q at this time. The EPA plans to propose action on these provisions in a future rulemaking action.

The criteria used to evaluate these SIP revisions are found primarily in section 110 of the Act. Section 110(l) requires that a SIP revision submitted to the EPA be adopted after reasonable notice and public hearing and also requires that the EPA not approve a SIP revision if the revision would interfere with any applicable requirement concerning attainment and reasonable further progress or any other applicable requirement of the Act.

These rules were promulgated in compliance with the Oklahoma Administrative Procedures Act and published in the Oklahoma Register, the official state publication for rulemaking actions.

In this action, we are proposing to approve revisions to OAC Title 252 Chapter 100 Subchapter 39 (OAC 252:100-39). Submittal documents for Subchapter 39 are available in the docket for this action. ODEQ's May 7, 2020 submittal is amending the following sections:

1. 252:100-39-4 to remove an incorrect citation to a revoked state rule;

2. 252:100-39-16 to update the timeframe listed as the non-oxidant season, this revision is intended to ensure that the proper controls are used during scheduled refinery unit turnarounds during Oklahoma's current ozone season;

3. 252:100-39-40 to correct the dates of Oklahoma's non-oxidant season, this revision is intended to ensure that cutback asphalt cannot be used during Oklahoma's ozone season; and,

4. 252:100-39-41 to allow for the use of alternative testing methods for leak inspections, to update references used for pressure and vapor testing to incorporate the most recent EPA regulations, and to update tank truck tag (OAC 252:100-39-41(e)(4)(A)(iv) and (v)) requirements to reflect current practices in Tulsa County.

More information on the proposed changes is available in the Technical Support Document prepared in conjunction with this rulemaking action. This is a is a revision by revision discussion:

OAC 252:100, Subchapter 39, Section 4 revision removes an incorrect cross reference. The revision removes “252:100-48” from a list of rules from which facilities are exempted because 252:100-48 has been revoked. ODEQ provided notice of the proposed change, announced the comment period from December 3, 2018 through January 9, 2019 and posted a notice of public hearing in Volume 36, Number 6, page 44 of the Oklahoma Register on December 3, 2018. The public hearing was held on January 16, 2019, and no comments were received. The revision is ministerial in nature. Examination of the record indicates that the submitted revision to Subchapter 39, Section 4 is proper and provides additional clarity. Thus, we find that the requirements of section 110(l) of the Act have been satisfied. Therefore, we are proposing to approve the submitted revision to Subchapter 39, Section 4.

OAC 252:100, Subchapter 39, Section 16 revisions update the non-oxidant season from November 1 through March 31 to December 1 through the last day of February. This update is consistent 40 CFR part 58, Appendix D, Table D-3 titled “Ozone Monitoring Season by State”. Scheduled refinery unit turnarounds may only be accomplished without the controls specified in OAC 252:100-39-16(b)(1) and OAC 252:100-39-16(b)(2) during non-oxidant seasons. ODEQ provided notice of the proposed change, announced the comment period from December 3, 2018 through January 9, 2019 and notice of a public hearing in Volume 36, Number 6, page 44 of the Oklahoma Register on December 3, 2018. The public hearing was held on January 16, 2019, and no comments were received. The environment will likely benefit from shortening the duration of non-oxidant season from 5 months to 3 months (changing from November 1 through March 31 to December 1 through the last day of February). Examination of the record indicates that the submitted revision to Subchapter 39, Section 16 is proper and the revisions will strengthen the SIP by requiring control of emissions during turnarounds during a time period consistent with the ozone season in Oklahoma. Thus, we find that the Oklahoma SIP that the requirements of section 110(l) of the Act have been satisfied. Therefore, we are proposing to approve the submitted revision to Subchapter 39, Section 16.

OAC 252:100, Subchapter 39, Section 40 revisions are to amend rules regulating the use of cutback asphalt to correct the dates of Oklahoma's non-oxidant season, which should be December 1 through the last day of February. This purpose of this proposed rule is to ensure that cutback asphalt cannot be used during Oklahoma's ozone season. This revision is consistent with 40 CFR part 58, Appendix D, Table D-3 titled “Ozone Monitoring Season by State”. ODEQ provided notice of the proposed change, announced the comment period from September 4, 2018 through October 5, 2018, and notice of a public hearing in Volume 35, Number 24, page 705 of the Oklahoma Register on September 4, 2018. The public hearing was held on October 10, 2018, and no comments were received. The environment will benefit by restricting the time of year cutback asphalt can be used. Examination of the record indicates that the submitted revision to Subchapter 39, Section 40 is proper, the revisions will strengthen the SIP preventing emissions from the application of cutback asphalt during the time of year when ozone formation is most likely. Thus, we find that the Oklahoma SIP that the requirements of section 110(l) of the Act have been satisfied. Therefore, we are proposing to approve the submitted revision to Subchapter 39, Section 40.

Several changes were made to OAC 252:100, Subchapter 39, Section 41. A typographical error was corrected in subsection 41(c)(5). In subsection 41(d)(3), reference was made to a test method in an EPA Control Technique Guideline (CTG) from 1978. This reference was changed to reference the EPA Test Method 27 contained in 40 CFR part 60 as the applicable procedure for the testing requirement for tank leak tightness. Several modifications were made to subsection 41(e). Subsection 41(e) applies to Tulsa County only. Subsections 41(e)(2)(B) and (E) were modified by removing a thirty-year-old effective date that is no longer necessary. Also, an alternative work practice for monitoring equipment for leaks that is consistent with 40 CFR 60.18(g) through 60.18(i) was added. The revision also states that leaks detected by EPA Test Method 21 or by an alternative work practice shall be repaired within 15 days. Revisions to subsection 41(e)(4)(A)(iv) update the reference to the portion of the rule that specifies the proper pressure testing which changed as a result of reorganizing the section. As part of reorganizing the section, subsection 41(e)(4)(A)(vi) was moved to subsection 41(e)(4)(B)(i), and other references in subsection 41(e)(4) were changed to align the references with the reorganization. Subsection 41(e)(4)(B)(ii) was updated to state that the vapor tightness test must be consistent with EPA Test Method 27 and updated what is considered a passing test as defined by EPA Test Method 27.

ODEQ provided notice of the proposed changes, announced the comment period from September 4, 2018 through October 5, 2018, and hearing schedule in Volume 35, Number 24, page 705 of the Oklahoma Register on September 4, 2018. The public hearing was held on October 10, 2018, and no comments were received. The revisions are ministerial in nature, update references consistent with federal regulations or adopt use of EPA Test Methods. Examination of the record indicates that the submitted revision to Subchapter 39, Section 41 is proper and do not relax the SIP. Thus, we find that the requirements of section 110(l) of the Act have been satisfied. Therefore, we are proposing to approve the submitted revision to Subchapter 39, Section 41.

Following the U.S. Supreme Court decision in McGirt v. Oklahoma , 140 S. Ct. 2452 (2020), the Governor of the State of Oklahoma requested approval under Section 10211(a) of the Safe, Accountable, Flexible, Efficient Transportation Equity Act of 2005: A Legacy for Users, Public Law 109-59, 109 Stat. 1144, 1937 (August 10, 2005) (“SAFETEA”), to administer in certain areas of Indian country (as defined at 18 U.S.C. 1151) the State's environmental regulatory programs that were previously approved by the EPA for areas outside of Indian country. The State's request excluded certain areas of Indian country further described below. In addition, the State only sought approval to the extent that such approval is necessary for the State to administer a program in light of Oklahoma Dept. of Environmental Quality v. EPA, 740 F.3d 185 (D.C. Cir. 2014). 1

On October 1, 2020, the EPA approved Oklahoma's SAFETEA request to administer all the State's EPA-approved environmental regulatory programs, including the Oklahoma SIP, in the requested areas of Indian country. As requested by Oklahoma, the EPA's approval under SAFETEA does not include Indian country lands, including rights-of-way running through the same, that: (1) Qualify as Indian allotments, the Indian titles to which have not been extinguished, under 18 U.S.C. 1151(c); (2) are held in trust by the United States on behalf of an individual Indian or Tribe; or (3) are owned in fee by a Tribe, if the Tribe (a) acquired that fee title to such land, or an area that included such land, in accordance with a treaty with the United States to which such Tribe was a party, and (b) never allotted the land to a member or citizen of the Tribe (collectively “excluded Indian country lands”).

EPA's approval under SAFETEA expressly provided that to the extent EPA's prior approvals of Oklahoma's environmental programs excluded Indian country, any such exclusions are superseded for the geographic areas of Indian country covered by the EPA's approval of Oklahoma's SAFETEA request. 2 The approval also provided that future revisions or amendments to Oklahoma's approved environmental regulatory programs would extend to the covered areas of Indian country (without any further need for additional requests under SAFETEA).

As explained above, the EPA is proposing to approve revisions to the Oklahoma SIP that include revisions to OAC Title 252 Chapter 100 Subchapter 39 (OAC 252:100-39) Sections 4, 16, 40, and 41, which will apply in Tulsa and Oklahoma Counties. Consistent with the D.C. Circuit's decision in ODEQ v. EPA and with EPA's October 1, 2020 SAFETEA approval, if this approval is finalized as proposed, these SIP revisions will apply to all Indian country within Tulsa and Oklahoma Counties, other than the excluded Indian country lands, as described above. Because—per the State's request under SAFETEA—EPA's October 1, 2020 approval does not displace any SIP authority previously exercised by the State under the CAA as interpreted in ODEQ v. EPA, the SIP will also apply to any Indian allotments or dependent Indian communities located outside of an Indian reservation over which there has been no demonstration of tribal authority. 3

Throughout this document, “we,” “us,” and “our” means the EPA.

Whenever a new or revised NAAQS is promulgated, the Clean Air Act (CAA) requires states to submit a plan for the implementation, maintenance, and enforcement of the standard, commonly referred to as infrastructure requirements. Section 110(a)(2) lists specific requirements that infrastructure SIPs, or i-SIPs, must include to adequately address such new or revised NAAQS, as applicable. Section 110(a)(2)(D)(i) includes four distinct elements related to interstate transport of air pollution, commonly referred to as prongs, that must be addressed in i-SIP submissions. The first two prongs are codified in section 110(a)(2)(D)(i)(I) and the third and fourth prongs are codified in section 110(a)(2)(D)(i)(II). These four prongs prohibit any source or type of emission activities in one state from:

• Contributing significantly to nonattainment of the NAAQS in another state (prong 1);

• Interfering with maintenance of the NAAQS in another state (prong 2);

• Interfering with measures that prevent significant deterioration of air quality in another state (prong 3); and

• Interfering with measures that protect visibility in another state (prong 4 or “visibility transport”).

We are only addressing the prong 4 element in this proposal. In an effort to assist states in complying with the i-SIP requirements, EPA issued guidance in 2013. 1 In the 2013 i-SIP guidance, EPA discussed its interpretation of prong 4 and its relationship to the Regional Haze program under CAA sections 169A and 169B, which require each state to address its share of emission reductions needed to meet reasonable progress goals (RPGs) for surrounding Class I areas. EPA suggested two options states may have to demonstrate that the requirements of prong 4 are met. One way in which prong 4 may be satisfied for any relevant NAAQS is through confirmation in the state's i-SIP submission that it has an approved regional haze SIP that fully meets the requirements of 40 CFR 51.308 or 51.309. Alternatively, a state may demonstrate in its i-SIP submission that emissions within its jurisdiction do not interfere with other states' plans to protect visibility. The demonstration should show that the state has sufficient measures that have been approved into its SIP to prevent emissions within its jurisdiction from interfering with the visibility protection plans of other states.

EPA has regulated particulate matter (PM) since the first NAAQS for PM were published in 1971. (36 FR 8186 (April 30, 1971)). Most recently, by notice dated January 15, 2013, following a periodic review of the NAAQS for PM 2.5 , EPA revised the primary annual PM 2.5 NAAQS to 12.0 μg/m 3 and retained the secondary annual PM 2.5 standard of 15 μg/m 3 as well as the primary and secondary 24-hour PM 2.5 standards of 35 μg/m 3 (2012 PM 2.5 NAAQS). 2 The primary NAAQS is designed to protect human health, and the secondary NAAQS is designed to protect the public welfare. On June 16, 2016, the Oklahoma Secretary of Energy and Environment submitted a SIP revision to address most of the i-SIP elements for this revised 2012 PM 2.5 NAAQS. On November 21, 2016, we proposed to approve all elements included in the 2012 PM 2.5 i-SIP submission except for the 110(a)(2)(D)(i)(II) prong 4 portion, which we proposed to disapprove. 3 On June 14, 2017, we took final action to approve all elements included in this i-SIP submission, but deferred taking final action on the 110(a)(2)(D)(i)(II) prong 4 portion. 4 In this notice, we are once again proposing to disapprove the prong 4 visibility transport portion of the June 16, 2016 i-SIP submission for the 2012 PM 2.5 NAAQS.

On June 22, 2010, we revised the primary NAAQS for SO 2 to establish a new 1-hour standard at a level of 75 parts per billion (ppb), based on the 3-year average of the annual 99th percentile of 1-hour daily maximum concentrations. 5 On January 28, 2015, the Oklahoma Secretary of Energy and Environment submitted a SIP revision to address i-SIP elements for this revised NAAQS. On November 21, 2016, we proposed to disapprove the 110(a)(2)(D)(i)(II) prong 4 portion of the 2010 SO 2 i-SIP submission, but we did not finalize this disapproval. 6 In this notice, we are once again proposing to disapprove the prong 4 visibility transport portion of the January 28, 2015 i-SIP submission for the 2010 SO 2 NAAQS.

EPA has regulated ozone since 1971, when we published the first NAAQS for Photochemical Oxidants (36 FR 8186 (April 30, 1971)). Most recently, following a periodic review of the 2008 NAAQS for ozone, the EPA promulgated a revision to the ozone NAAQS in 2015 lowering the level of both the primary and secondary standards to 0.070 parts per million. 7 On October 25, 2018, the Oklahoma Secretary of Energy and Environment submitted a SIP revision to address i-SIP elements for this revised NAAQS. On March 30, 2020, we approved most infrastructure elements of the 2015 ozone i-SIP submission but deferred taking final action on the 110(a)(2)(D)(i)(II) prong 4 portion. 8

In this notice, we refer to each of these NAAQS by the year promulgated, e.g., “the 2008 ozone standard.” For more information on these standards, please visit https://www.epa.gov/criteria-air-pollutants.

On February 17, 2010, Oklahoma submitted a regional haze SIP (the 2010 Regional Haze SIP) to the EPA that included best available retrofit technology (BART) requirements for SO 2 , NO X , and PM for Oklahoma sources. On December 28, 2011, we took final action to partially approve and partially disapprove the 2010 Regional Haze SIP. 9 In this final action, we disapproved Oklahoma's SO 2 BART determinations for the Oklahoma Gas and Electric (OG&E) Sooner Units 1 and 2, the OG&E Muskogee Units 4 and 5, and the American Electric Power/Public Service Company of Oklahoma (AEP/PSO) Northeastern Units 3 and 4 because they do not comply with our regional haze regulations under 40 CFR 51.308(e). We approved Oklahoma's remaining SO 2 BART determinations as well as all nitrogen oxide (NO X ) and PM BART determinations. Additionally, we approved all remaining portions of the 2010 Regional Haze SIP, with the exception of (1) the long-term strategy to the extent it relied on the BART emission limits that we disapproved and (2) Oklahoma's 2018 RPGs on the 20% least impaired and 20% most impaired days for the Wichita Mountains Class I area. 10

In the December 28, 2011 final rule, we also evaluated whether Oklahoma's SIP ensures that emissions from sources within Oklahoma do not interfere with the visibility programs of other states with respect to the 1997 8-hour Ozone NAAQS and the 1997 PM 2.5 NAAQS. In developing their respective regional haze SIPs and reasonable progress goals (RPGs), the Central Regional Air Planning Association (CENRAP) states consulted with each other through CENRAP's work groups. As a result of this process, the understanding was that each CENRAP state would take action to achieve the emissions reductions relied upon by other states in their reasonable progress demonstrations. CENRAP states consulted in the development of RPGs, using the products of the technical consultation process to co-develop their RPGs. In developing their visibility projections using photochemical grid modeling, CENRAP states assumed a certain level of emissions from sources within Oklahoma. The CENRAP modeling assumed SO 2 reductions from the OG&E Sooner Units 1 and 2, the OG&E Muskogee Units 4 and 5, and the AEP/PSO Northeastern Units 3 and 4, which Oklahoma did not secure when making its BART determinations for these sources and were thus not required by the 2010 Oklahoma Regional Haze SIP. Since this modeling was used by other states and Oklahoma in establishing their RPGs, we made the finding that the Oklahoma SIP does not ensure that emissions from sources within Oklahoma do not interfere with measures required in the SIP of any other state under Part C of the CAA to protect visibility. 11 In the December 28, 2011 final rule, we finalized a FIP (Oklahoma SO 2 BART FIP) that controls SO 2 emissions from the six units to address the deficiencies identified in our disapproval of these SO 2 BART determinations and the disapproval of the SIP submission addressing its prong 4 visibility transport obligations for the 1997 8-hour Ozone NAAQS and the 1997 PM 2.5 NAAQS. 12

On June 20, 2013, Oklahoma submitted a regional haze SIP revision to replace the FIP's SO 2 BART requirements for the AEP/PSO Northeastern Units 3 and 4 and a related revision to the SIP addressing interstate visibility transport requirements (the 2013 Oklahoma Regional Haze SIP Revision). On March 7, 2014, we approved this SIP revision and concurrently withdrew the FIP's applicability to these two units. 13 In addition to approving the SO 2 BART determinations for the AEP/PSO Northeastern Units 3 and 4 in that final rule, we also approved revised NO X BART requirements for these two units, 14 and approved the portion of the 2013 Oklahoma Regional Haze SIP Revision concerning Oklahoma's interstate visibility transport obligations of CAA section 110(a)(2)(D)(i)(II) with respect to the 1997 8-hour ozone and 1997 PM 2.5 NAAQS as applied to this source and its associated impacts on other states' programs to protect visibility in Class I Areas. 15 The FIP provisions applicable to the OG&E Muskogee and Sooner plants remain in place.

On January 28, 2015, Oklahoma submitted a SIP revision to address the infrastructure requirements for the 2010 1-hour SO 2 NAAQS, including the interstate visibility transport requirements. In its evaluation, Oklahoma stated that the 2010 Regional Haze SIP describes Oklahoma's measures to protect visibility and ensure that emissions do not interfere with any other state's measures to protect visibility. Oklahoma stated that these measures include provisions in the Oklahoma Administrative Code 252:100-8, Part 11. Oklahoma noted that EPA partially approved and partially disapproved Oklahoma's Regional Haze SIP and partially approved and partially disapproved Oklahoma's SIP submission addressing its prong 4 visibility transport requirements for the 1997 8-hour Ozone NAAQS and the 1997 PM 2.5 NAAQS on December 28, 2011. Oklahoma noted that in the same action, EPA promulgated a FIP addressing the disapproved portions of Oklahoma's 2010 Regional Haze SIP and the interstate visibility transport SIP revisions for the 1997 8-hour Ozone NAAQS and the 1997 PM 2.5 NAAQS, and that EPA found that the controls under this FIP, in combination with the controls required by the portion of the Oklahoma Regional Haze SIP submittal approved by EPA, will serve to prevent sources in Oklahoma from emitting pollutants in amounts that will interfere with efforts to protect visibility in other states. Oklahoma also noted that it submitted a revision to its regional haze and interstate visibility transport SIPs (2013 Oklahoma Regional Haze SIP Revision) on June 14, 2013, to replace the FIP as it relates to the AEP/PSO Northeastern Units 3 and 4, and that EPA approved this revision effective April 7, 2014. Oklahoma asserted that any contribution to visibility impairment or interference with any other state's measures to protect visibility attributable to SO 2 emissions are addressed through Oklahoma's 2010 Regional Haze SIP as revised in the 2013 Oklahoma Regional Haze SIP Revision and through EPA's related regional haze actions in Oklahoma. This includes EPA's FIP action that currently addresses the OG&E Sooner Units 1 and 2 and the OG&E Muskogee Units 4 and 5. Oklahoma also noted that although no additional visibility protection obligations are anticipated on Oklahoma's part as a result of the revised 2010 1-hour SO 2 NAAQ, other program actions taken to ensure maintenance of the revised SO 2 NAAQS will indirectly assist in avoiding interference with any other state's measures to protect visibility.

On June 16, 2016, Oklahoma submitted a SIP revision to address the infrastructure requirements for the 2012 PM 2.5 NAAQS, including the transport requirements. In its evaluation, Oklahoma stated that the 2010 Regional Haze SIP describes Oklahoma's measures to protect visibility and ensure that emissions do not interfere with any other state's measures to protect visibility. Oklahoma stated that these measures include provisions in the Oklahoma Administrative Code 252:100-8, Part 11. Oklahoma noted that EPA partially approved and partially disapproved Oklahoma's Regional Haze SIP and partially approved and partially disapproved Oklahoma's SIP submission addressing the visibility prong of interstate transport for the 1997 8-hour Ozone NAAQS and the 1997 PM 2.5 NAAQS on December 28, 2011. Oklahoma noted that in the same action, EPA promulgated a FIP addressing the disapproved portions of Oklahoma's 2010 Regional Haze SIP and the interstate visibility transport SIP submittals for the 1997 8-hour Ozone NAAQS and the 1997 PM 2.5 NAAQS, and that EPA found that the controls under this FIP, in combination with the controls required by the portion of the Oklahoma Regional Haze SIP submittal approved by EPA, will serve to prevent sources in Oklahoma from emitting pollutants in amounts that will interfere with efforts to protect visibility in other states. Oklahoma also noted that it submitted a revision to its regional haze and interstate visibility transport SIPs on June 14, 2013, to replace the FIP as it relates to the AEP/PSO Northeastern Units 3 and 4, and that EPA approved this revision effective April 7, 2014. In its evaluation, Oklahoma asserted that any contribution to visibility impairment or interference with any other state's measures to protect visibility attributable to emission of PM 2.5 or its precursors ( e.g., SO 2 ) are addressed through Oklahoma's 2010 Regional Haze SIP as revised in the 2013 Oklahoma Regional Haze SIP Revision and through EPA's related regional haze actions in Oklahoma. This includes EPA's FIP action that currently addresses the OG&E Sooner Units 1 and 2 and the OG&E Muskogee Units 4 and 5. Oklahoma also noted that although no additional visibility protection obligations are anticipated on Oklahoma's part as a result of the revised 2012 PM 2.5 NAAQS, other program actions taken to assure maintenance of the revised PM 2.5 NAAQS will indirectly assist in avoiding interference with any other state's measures to protect visibility.

On October 25, 2018, Oklahoma submitted a SIP revision to address the CAA section 110(a)(1) and 110(a)(2) infrastructure and transport requirements for the 2015 Ozone NAAQS. In its evaluation, Oklahoma stated that the 2010 Regional Haze SIP describes Oklahoma's measures to protect visibility and ensure that emissions do not interfere with any other state's measures to protect visibility. Oklahoma stated that these measures include provisions in the Oklahoma Administrative Code 252:100-8, Part 11. Oklahoma noted that EPA partially approved and partially disapproved Oklahoma's Regional Haze SIP and partially approved and partially disapproved Oklahoma's SIP submission addressing the visibility prong of interstate transport for the 1997 8-hour Ozone NAAQS and the 1997 PM 2.5 NAAQS on December 28, 2011. Oklahoma noted that in the same action, EPA promulgated a FIP addressing the disapproved portions of Oklahoma's 2010 Regional Haze SIP and the interstate visibility transport SIP submittals for the 1997 8-hour Ozone NAAQS and the 1997 PM 2.5 NAAQS, and that EPA found that the controls under this FIP, in combination with the controls required by the portion of the Oklahoma Regional Haze SIP submittal approved by EPA, will serve to prevent sources in Oklahoma from emitting pollutants in amounts that will interfere with efforts to protect visibility in other states. Oklahoma also noted that it submitted a revision to its regional haze and interstate visibility transport SIPs on June 14, 2013, to replace the FIP as it relates to the AEP/PSO Northeastern Units 3 and 4, and that EPA approved this revision effective April 7, 2014. In its evaluation, Oklahoma asserted that ozone from ozone precursor emissions are not believed to contribute significantly to visibility impairment and that Oklahoma's 2010 Regional Haze SIP demonstrates that Oklahoma's PM 2.5 emissions do not interfere with any other state's measures to protect visibility. Oklahoma noted that this portion of the 2010 Regional Haze SIP was approved by EPA on December 28, 2011. Additionally, the submission includes a technical support document (TSD)  16 intended to address the requirements of CAA section 110(a)(2)(D)(i)(I), which requires a state's SIP to contain adequate provisions prohibiting any source or other type of emissions activity within the state from emitting any air pollutant in amounts which will contribute significantly to nonattainment in, or interfere with maintenance by, any other state with respect to any such national primary or secondary ambient air quality standard ( i.e., prongs 1 and 2). In that document, Oklahoma asserted that the Oklahoma Department of Environmental Quality (ODEQ) has determined that Oklahoma meets the prong 4 visibility transport provisions for the 2015 Ozone NAAQS, as the state is not contributing significantly to nonattainment or maintenance issues in any other state.

In summary, Oklahoma relied on the following points to support its conclusion that Oklahoma meets the prong 4 visibility transport provision for the 2015 Ozone NAAQS: (1) The modeling and technical analysis in the State's interstate transport SIP revision (as to “prongs 1 and 2” under section 110(a)(2)(D)(i)(I)) purportedly demonstrating that Oklahoma does not significantly contribute to nonattainment or maintenance in another state for the 2015 Ozone NAAQS; (2) the fact that ozone formed from ozone precursor emissions is not believed to contribute significantly to visibility impairment; and (3) Oklahoma's 2010 Regional Haze SIP, which Oklahoma says demonstrates that PM 2.5 emissions from Oklahoma do not interfere with any other state's measures to protect visibility.

On December 1, 2020, EPA sent a letter to ODEQ requesting clarification on how the Oklahoma SIP satisfies the prong 4 interstate visibility transport requirement with respect to the 2015 Ozone NAAQS. 17 In a letter dated January 5, 2021, ODEQ pointed out that EPA approved the NO X BART determinations in the 2010 Oklahoma Regional Haze SIP and also clarified that the SIP addressed NO X and VOC emissions, which are ozone precursors, using an approach that is consistent with what was anticipated under the CENRAP process for the first regional haze planning period. 18 In the letter, ODEQ noted that Sections VII and IX of the 2010 Oklahoma Regional Haze SIP explain that the SIP requires NO X reductions resulting from BART and other program requirements, as well as other factors, that are consistent with what was anticipated under the CENRAP consultation process for regional haze SIP development for the first planning period. In the letter, ODEQ further noted that Section VIII of the 2010 Oklahoma Regional Haze SIP explains that the CENRAP modeling used to project the visibility impacts in 2018 as a result of growth and control of emissions from the baseline for Class I areas in CENRAP states included emission adjustments made by ODEQ to reflect presumptive BART controls for the OG&E Sooner Plant, the OG&E Muskogee Plant, and the AEP/PSO Northeastern Plant. For NO X emissions, this presumptive control level is equivalent to 0.15 lb/MMBtu for NO X BART and is consistent with the NO X emission limits required by the 2010 Oklahoma Regional Haze SIP for subject-to-BART units at these three power plants.

In the January 5, 2021 letter, ODEQ also explains that the 2010 Oklahoma Regional Haze SIP did not include additional control requirements to address VOC emissions under regional haze for the first planning period. In the letter, ODEQ points to Section VI(A) of the 2010 Oklahoma Regional Haze SIP, which explains that ODEQ determined that the visibility impairing pollutants in Oklahoma include SO 2 , NO X , PM 10 , and PM 2.5 , while CENRAP modeling showed that anthropogenic VOCs do not significantly impair visibility at the Wichita Mountains. ODEQ also notes that Section IX(E)(4) of the 2010 Oklahoma Regional Haze SIP explains that the emissions inventory associated with the SIP assigns most emissions of VOCs to biogenic sources, which ODEQ considers to be natural and therefore uncontrollable. ODEQ explains that Section IX(E)(4) of the 2010 Oklahoma Regional Haze SIP noted that a minority of VOC emissions in Oklahoma originate from area, industrial, point, and mobile sources, and that most of these sources already employ controls under various federal mandates. The 2010 Oklahoma Regional Haze SIP explained that considering the small and uncertain contribution of anthropogenic sources of VOC to visibility impairment at the Wichita Mountains, ODEQ did not find further VOC controls reasonable. In the letter, ODEQ explains that these determinations similarly apply to the approach taken in the 2010 Oklahoma Regional Haze SIP regarding potential VOC-related impacts of and remedies for visibility impairment at other states' Class I areas, and that this approach is consistent with what was anticipated under the CERNAP process for the first regional haze planning period. Further, ODEQ notes that Section VIII of the 2010 Oklahoma Regional Haze SIP presented model output data that demonstrates that Oklahoma emissions are projected to impair visibility only insignificantly at all Class I areas in other states, and ODEQ therefore concluded that additional emission reduction action was not needed to protect other Class I areas, including for NO X and VOC as ozone precursors.

Thus, ODEQ clarifies in the letter that the EPA-approved portion of the 2010 Oklahoma Regional Haze SIP addressed NO X and VOC emissions using an approach that is consistent with what was anticipated in the CENRAP process for the first regional haze planning period and ODEQ states that it believes that, considering the clarifications in the January 5, 2021 letter, and as certified in the October 25, 2018 submittal, the Oklahoma SIP satisfies the interstate visibility transport CAA requirement of section 110(a)(2)(D)(i)(II) with respect to the 2015 Ozone NAAQS.

Our 2013 i-SIP guidance addresses the requirements for prong 4 and lays out two ways in which a state's infrastructure SIP submittal may satisfy these requirements. 19 The first method is through a state's confirmation in its infrastructure SIP submittal that it has a fully approved regional haze SIP in place. As previously discussed, EPA promulgated a partial approval and partial disapproval of the 2010 Oklahoma Regional Haze SIP in 2011 because the SO 2 BART determinations for the OG&E Sooner Units 1 and 2, the OG&E Muskogee Units 4 and 5, and the AEP/PSO Northeastern Units 3 and 4 did not comply with our regional haze regulations under 40 CFR 51.308(e), and EPA concurrently promulgated a FIP to address these deficiencies. 20 On June 20, 2013, Oklahoma submitted a SIP revision to address this deficiency with respect to the AEP/PSO Northeastern Units 3 and 4, and the FIP with respect to these two units was withdrawn on March 7, 2014. 21 However, the FIP remains in place with SO 2 BART requirements for the OG&E Sooner Units 1 and 2 and the OG&E Muskogee Units 4 and 5. Therefore, Oklahoma cannot rely on a fully approved Regional Haze SIP as the basis for meeting its prong 4 visibility transport obligations for the 2010 SO 2 , 2012 PM 2.5 , and the 2015 Ozone NAAQS.

In the absence of a fully approved Regional Haze SIP, the second method provided by the 2013 i-SIP guidance to meet prong 4 requirements is a demonstration that emissions within a state's jurisdiction do not interfere with other states' plans to protect visibility. 22 EPA interprets prong 4 to be pollutant-specific such that the state need only address the potential for interference with visibility protection caused by the pollutant (including precursors) to which the new or revised NAAQS applies. 23 According to the guidance, such a demonstration for the first planning period should establish or identify the measures in the approved SIP that limit visibility-impairing pollutants and ensure that the resulting reductions conform with any mutually agreed emission reductions under the relevant regional haze regional planning organization (RPO) process. 24 As explained below, Oklahoma did not make such a demonstration in the i-SIP submittals for the 2010 SO 2 and 2012 PM 2.5 NAAQS. The i-SIP submittal for the 2015 Ozone NAAQS as clarified by Oklahoma's January 5, 2021 letter, provides a demonstration identifying the measures in the approved SIP that limit visibility-impairing ozone precursor emissions and clarifies that the resulting reductions conform with mutually agreed emission reductions under the relevant regional haze RPO process with respect to the 2015 Ozone NAAQS. We discuss this in the subsections that follow.

The portion of the 2015 infrastructure SIP submittal for the 2010 1-hour SO 2 NAAQS that addresses interstate visibility transport relied on both Oklahoma's 2010 Regional Haze SIP submittal, as revised in the 2013 Regional Haze SIP revision that addresses the AEP/PSO facility, and EPA's FIP that currently applies to the OG&E Sooner Units 1 and 2 and the OG&E Muskogee Units 4 and 5. As explained above, the prong 4 requirements are pollutant specific. Some portions of the 2010 Oklahoma Regional Haze SIP that address SO 2 emissions have been disapproved and thus cannot be relied upon by Oklahoma to satisfy the prong 4 requirements. Further, the EPA's 2013 i-SIP guidance states, “Under section 110(a)(2)(D(i)(II), an i-SIP submission cannot be approved with respect to prong 4 (visibility transport) until the EPA has issued final approval of SIP provisions that the EPA has found to adequately address any contribution of that state's sources to impacts on visibility program requirements in other states.”  25 Thus, Oklahoma cannot rely on the existing SO 2 BART FIP to satisfy the prong 4 requirements for the 2010 1-hour SO 2 NAAQS. Moreover, the 2015 i-SIP submittal does not provide any additional information to demonstrate that the measures in the SIP are sufficient to prohibit emissions from sources within Oklahoma from interfering with measures that have been developed by other states to protect visibility with respect to the 2010 1-hour SO 2 NAAQS. Therefore, while the FIP provides an appropriate level of SO 2 control to prohibit emissions from sources within Oklahoma from interfering with measures that have been developed by other states to protect visibility (as discussed in Section III.E.), the SIP submittal does not; Thus, we are proposing to disapprove the 110(a)(2)(D)(i)(II) prong 4 portion of Oklahoma's 2015 i-SIP submittal for the 2010 1-hour SO 2 NAAQS.

The portion of the 2016 infrastructure SIP submittal for the 2012 PM 2.5 NAAQS that addresses interstate visibility transport relied on both Oklahoma's 2010 Regional Haze SIP submittal, as revised in the June 20, 2013 SIP revision with respect to the AEP/PSO facility, and EPA's FIP that currently applies to the OG&E Sooner Units 1 and 2 and the OG&E Muskogee Units 4 and 5. The portions of Oklahoma's 2010 Regional Haze SIP that address PM BART have been approved, but portions of the SIP that address PM precursor emissions ( i.e., SO 2 ) have not, and thus cannot be relied upon to satisfy the prong 4 requirements. PM emissions can be emitted directly from sources and can also form in the atmosphere as a result of complex reactions of other pollutants ( i.e., precursors) such as SO 2 and NO X , which are visibility impairing pollutants themselves and are required to be addressed under regional haze. 26 As discussed above, EPA disapproved the SO 2 BART determinations for the OG&E Sooner Units 1 and 2, the OG&E Muskogee Units 4 and 5, and the AEP/PSO Northeastern Units 3 and 4, and promulgated a FIP to address these deficiencies. 27 EPA approved the 2013 Oklahoma Regional Haze SIP Revision that addressed SO 2 BART for the AEP/PSO Northeastern Units 3 and 4, and EPA withdrew the FIP with respect to these two units on March 7, 2014. 28 However, the FIP remains in place with SO 2 BART requirements for the OG&E Sooner Units 1 and 2 and the OG&E Muskogee Units 4 and 5. As explained above, Oklahoma cannot rely upon the portions of the 2010 Oklahoma Regional Haze SIP that address SO 2 emissions that have been disapproved or on the existing SO 2 BART FIP to satisfy the prong 4 requirements for the 2012 PM 2.5 NAAQS. The 2016 i-SIP submittal does not provide any additional information to demonstrate that the measures in the SIP are sufficient to prohibit emissions from sources within Oklahoma from interfering with measures that have been developed by other states to protect visibility with respect to the 2012 PM 2.5 NAAQS. We are therefore proposing to disapprove the 110(a)(D)(2)(i)(II) prong 4 portion of Oklahoma's 2016 infrastructure SIP submittal for the 2012 PM 2.5 NAAQS.

In Oklahoma's 2018 infrastructure SIP submittal for the 2015 Ozone NAAQS, Oklahoma asserted that it meets the visibility transport provisions under section 110(a)(2)(D)(i)(II) for the 2015 Ozone NAAQS given that it has determined the state is not contributing significantly to nonattainment or maintenance issues in any other state under section 110(a)(2)(D)(i)(I). The analysis in the SIP submittal that purports to find that Oklahoma emissions do not significantly contribute to nonattainment or interfere with maintenance in another state under section 110(a)(2)(D)(i)(I) focuses on the potential impact of ozone-precursor emissions at certain ozone monitor locations in other states as related to the attainment and maintenance of the ozone NAAQS ( i.e., prongs 1 and 2), but does not provide an analysis of visibility impacts at Class I areas due to emissions of ozone precursors as visibility pollutants (prong 4). 29 This basis is inadequate for approval of the visibility transport requirements.

In the 2018 submittal, Oklahoma also stated that ozone formed from ozone precursor emissions is not believed to contribute significantly to visibility impairment. Oklahoma asserted that the 2010 Regional Haze SIP demonstrates that PM 2.5 emissions from Oklahoma do not interfere with any other state's measures to protect visibility, and that this portion of the SIP was approved by EPA on December 28, 2011. Here, Oklahoma is referring to EPA's approval of all the PM BART determinations in Oklahoma's 2010 Regional Haze SIP. However, it is unclear in the submittal how the SIP fulfills the prong 4 requirements for the 2015 Ozone NAAQS. 30

The EPA has not established a separate visibility transport standard for ozone because it does not directly impair visibility or substantially produce or contribute to the production of the secondary air contaminants that cause visibility impairment or regional haze. As stated above, section 110(a)(2)(D)(i)(II) prong 4 requirements apply to all pollutants (including precursors) for which EPA has promulgated a NAAQS. As such, Oklahoma is required to demonstrate to EPA that it has approved measures in its SIP that ensure that ozone-precursor emissions within its jurisdiction do not interfere with other states' visibility protection plans. While ozone itself does not directly impair visibility, ozone precursors ( i.e., NO X and in some cases volatile organic compounds) can react to generate visibility impairing pollutants. Thus, the pertinent question is whether Oklahoma's SIP adequately controls emissions of ozone precursors that may contribute to visibility impairment in other states and whether the level of control of these emissions is consistent with mutually-agreed emissions reductions under the CENRAP regional haze planning process for the first planning period.

As explained in Oklahoma's January 5, 2021 clarification letter, EPA approved all NO X BART determinations in Oklahoma's 2010 Regional Haze SIP and these EPA-approved NO X BART determinations conform with the mutually-agreed emission reductions  31 under the CENRAP regional haze planning process that Oklahoma and other Midwestern states participated in for regional haze SIP development for the first regional haze planning period. 32 In the 2013 Oklahoma Regional Haze SIP Revision, Oklahoma revised the NO X BART requirements for the Northeastern Units 3 and 4 that EPA approved in the December 28, 2011 final rule. 33 The revisions require earlier installation and compliance with reduced NO X emission limits prior to the original SIP-imposed deadline. 34 Our December 2011 approval of NO X BART for Units 3 and 4 required that these units meet a NO X emission limit of 0.15 lb/MMBtu (based on a 30-day rolling average) within five years from the effective date of EPA's approval, or by January 27, 2017. 35 However, under the 2013 Oklahoma Regional Haze SIP Revision, which EPA approved on March 7, 2014, both units are required to meet an initial NO X emission limit of 0.23 lb/MMBtu (based on a 30-day rolling average) by December 31, 2013, with additional limits of 1,098 lb/hr per unit on a 30-day rolling average basis and a 9,620 tpy combined cap for both units. 36 By April 16, 2016, one unit is required to be permanently shut down, while the remaining unit is required to meet a NO X emission limit of 0.15 lb/MMBtu (based on a 30-day rolling average), with an additional limit of 716 lb/hr on a 30-day rolling average basis and a cap of 3,137 tpy on a 12-month rolling basis. Finally, this second unit is required to shut down by December 31, 2026. Thus, these revised NO X BART determination for the Northeastern Units 3 and 4 are more stringent than the determinations that we previously approved given that they require compliance with the 0.15 lb/MMBtu limit on a more expeditious schedule. The Oklahoma SIP contains NO X BART determinations for all subject-to-BART sources in Oklahoma, which have been approved by EPA in previous actions and conform with the mutually-agreed emission reductions under the CENRAP regional haze planning process that Oklahoma and other Midwestern states participated in for regional haze SIP development for the first regional haze planning period.

In the January 5, 2021 letter, ODEQ also explained that VOC emissions, which are an ozone precursor, were addressed in the 2010 Oklahoma Regional Haze SIP in a manner consistent with what was anticipated under the CENRAP process for the first regional haze planning period. Specifically, in the 2010 Oklahoma Regional Haze SIP, ODEQ asserted that the emissions inventory associated with that SIP submittal assigns most VOC emissions to biogenic sources, which ODEQ considers to be uncontrollable;  37 The CENRAP modeling shows that anthropogenic VOC emissions do not significantly impair visibility at the Wichita Mountains;  38 And, only a minority of VOC emissions in Oklahoma originate from area, industrial, point, and mobile sources, which ODEQ asserted are sources that are already controlled under various federal mandates. 39 ODEQ stated in the 2010 Oklahoma Regional Haze SIP that considering the small and uncertain contribution of anthropogenic sources of VOC to visibility impairment at the Wichita Mountains, ODEQ did not find further controls for VOC sources to be reasonable. 40 The CENRAP modeling used to project the visibility impacts in 2018 for Class I areas in CENRAP states, which reflects the mutually-agreed emissions reductions in CENRAP states, did not assume additional control of VOC emissions in Oklahoma. In the December 28, 2011 final rule on the 2010 Oklahoma Regional Haze SIP, EPA agreed with ODEQ's decision to not further evaluate or require additional controls for VOC emissions in Oklahoma. 41 Thus, Oklahoma's approach for VOC emissions in the 2010 Oklahoma Regional Haze SIP has been approved by EPA and conforms with the mutually-agreed emission reductions under the CENRAP regional haze planning process that Oklahoma and other Midwestern states participated in for regional haze SIP development for the first regional haze planning period.

Therefore, we are proposing to find that the Oklahoma SIP includes the necessary emission reductions to satisfy the 110(a)(2)(D)(i)(II) prong 4 requirements for the 2015 Ozone NAAQS and are proposing to approve the portion of the 2018 infrastructure SIP submittal that addresses interstate visibility transport for the 2015 Ozone NAAQS.

As discussed earlier in this notice, Oklahoma engaged in a regional planning process with other CENRAP states to develop their regional haze SIP for the first planning period. This regional planning process included a forum in which state representatives built emission inventories that assumed that specific pollution sources would be controlled to specific levels. This included adjustments to projected emissions by ODEQ to reflect the assumption that the OG&E Sooner Units 1 and 2, the OG&E Muskogee Units 4 and 5, and the AEP/PSO Northeastern Units 3 and 4 would each be controlled to presumptive BART emission levels for SO 2 , 42 which is equivalent to 0.15 lb/MMBtu. 43 Visibility modeling projections conducted by CENRAP subsequently included those emission reductions, and other states relied on them as part of their reasonable progress demonstrations. However, Oklahoma, in its subsequent 2010 Regional Haze SIP, did not include these promised reductions on which the other states relied on in developing their own RPGs and regional haze SIPs. Instead, Oklahoma determined that SO 2 BART for these units was no additional control and specified an SO 2 limit of 0.65 lbs/MMBtu on a 30-day rolling average. In a final rule published on December 28, 2011, we disapproved the SIP's SO 2 BART determinations for these six units because they do not comply with our regulations under 40 CFR 51.308(e). 44 In the same final rule, we promulgated a FIP establishing an emission limit of 0.06 lb/MMBtu for each of the six units for purposes of complying with SO 2 BART. 45

On June 20, 2013, Oklahoma submitted a regional haze SIP revision to replace the FIP's SO 2 BART requirements for the AEP/PSO Northeastern Units 3 and 4. On March 7, 2014, we approved this SIP revision and concurrently withdrew the sections of the FIP that applied to those two units. 46 The 2013 Oklahoma Regional Haze SIP Revision requires one of the two Northeastern units to shut down no later than April 16, 2016, while the remaining unit is required to install dry sorbent injection (DSI) to meet an SO 2 emission limit of 0.4 lb/MMBtu. 47 However, the SO 2 emission reductions for the AEP/PSO Northeastern facility contained in the 2013 Oklahoma Regional Haze SIP Revision fall short of the levels assumed in other states' regional haze plans through the CENRAP RPO process. In order to achieve emission levels equivalent to the levels assumed in other states' regional haze plans through the CENRAP RPO process, the remaining Northeastern unit would have to meet an emission limit of 0.3 lb/MMBtu (0.15 + 0.15). 48 To address this, the 2013 Oklahoma Regional Haze SIP Revision also requires the source operators to optimize the performance of DSI on the remaining unit to ensure that the best possible performance is achieved and adjust the limit accordingly. The “AEP/PSO Settlement Agreement” included in the 2013 Oklahoma Regional Haze SIP Revision requires the company to develop and propose a monitoring program to test various operating profiles and other measures in order to determine whether increased SO 2 removal efficiencies can be achieved during normal operations. 49 AEP/PSO was required to implement this monitoring program and to evaluate and report the results to EPA and ODEQ. If the evaluation demonstrated that the technology is capable of sustainably achieving an emission rate of less than 0.37 lbs/MMBtu on a 30-day rolling average basis without (i) altering the unit's fuel supply, (ii) incurring additional capital costs, (iii) increasing operating expenses by more than a negligible amount, and/or (iv) adversely impacting overall unit operations, ODEQ would have to propose to revise the emission rate for the remaining Northeastern unit by 60 percent of the difference between 0.40 and the demonstrated emission rate. 50

If it is determined that the remaining operating unit still cannot meet the emission limit of 0.3 lb/MMBtu, then the 2013 Oklahoma Regional Haze SIP Revision contains an enforceable commitment obligating ODEQ to “obtain and/or identify additional SO 2 reductions within the State of Oklahoma to the extent necessary to achieve the anticipated visibility benefits estimated” by CENRAP. 51 As explained in our March 7, 2014 final rule approving the 2013 Oklahoma Regional Haze SIP Revision, any additional SO 2 emissions reductions that can be obtained or identified from the northeast quadrant of the State will be presumed to count toward the emission reductions necessary to achieve the anticipated visibility benefits associated with a 0.30 lb/MMBtu emission limit at Northeastern Power Station. 52 Emissions reductions obtained outside the northeast quadrant that are technically justified will also be counted. 53 We explained in our March 7, 2014 final rule that if necessary, additional emissions reductions are to be obtained via enforceable emission limits or control equipment requirements where necessary and submitted to EPA as a SIP revision as expeditiously as practicable, but in no event later than the end of the first full Oklahoma legislative session occurring subsequent to AEP/PSO's submission of the evaluation and report for the monitoring program required under the AEP/PSO Settlement Agreement. 54

On June 25, 2019, AEP/PSO submitted to ODEQ the “BART SO 2 Monitoring Program for Northeastern Power Station Unit 3” (SO 2 Monitoring Program), pursuant to one of the requirements in the AEP/PSO Settlement Agreement. 55 Based on the results of the SO 2 Monitoring Program, AEP/PSO concluded that the lowest target emission rate sustainably achieved consistent with the conditions in the AEP/PSO Agreement is 0.35 lb/MMBTU on a 30-day rolling average basis, and that the resulting federally enforceable emission rate should be 0.37 lb/MMBtu on a 30-day rolling average basis. 56 However, an emission limit of 0.37 lb/MMBtu for AEP/PSO Northeastern Unit 3 would still fall short of the 0.3 lb/MMBtu emission limit necessary to achieve emission levels equivalent to the levels assumed in other states' regional haze plans through the CENRAP RPO process.

Following final disapproval of a SIP revision in whole or in part, EPA has an obligation under section 110(c) of the Act to either approve a SIP revision and/or promulgate a FIP to address the disapproval within 24 months. We believe EPA's FIP obligation under section 110(c) could be addressed through a demonstration that the deficiencies in the Oklahoma SIP that form the basis of our proposed disapproval of the interstate visibility transport portions of the Oklahoma i-SIP submissions for the 2010 SO 2 and 2012 PM 2.5 NAAQS are already addressed by the existing FIP in place for the Oklahoma Regional Haze program. As discussed in the next section, we have assessed whether the emissions reductions secured by the existing SO 2 BART emission limits for the OG&E Sooner Units 1 and 2 and the OG&E Muskogee Units 4 and 5, required under the existing FIP, are sufficient to make up for any shortfall to achieve the necessary anticipated visibility benefits associated with a 0.30 lb/MMBtu emission limit at Northeastern Power Station that CENRAP states agreed on and relied upon in their regional haze plans. We discuss our technical analysis in the subsection that follows.

For the reasons explained above, Oklahoma's reliance on both its 2010 Regional Haze SIP submittal as revised in its 2013 Regional Haze SIP revision and EPA's FIP that applies to the OG&E Sooner Units 1 and 2 and OG&E Muskogee Units 4 and 5 is insufficient to satisfy its prong 4 requirements in accordance with EPA's 2013 i-SIP guidance. EPA is thus proposing to disapprove the submissions with regard to CAA section 110(a)(2)(D)(i)(II). EPA's disapproval triggers its obligation to promulgate a FIP under CAA section 111(c)(1) to address the deficiencies in the state's SIP. However, as discussed below, EPA finds that its FIP obligation with respect to prong 4 for these two NAAQS is already satisfied, and no further action is required.

The FIP we published on December 28, 2011, 57 included SO 2 emission limitations for the OG&E Sooner Units 1 and 2, the OG&E Muskogee Units 4 and 5, and the AEP/PSO Northeastern Units 3 and 4 based on EPA's analysis of the five BART statutory factors, and these emission limitations reflected a level of control more stringent than what was assumed in the CENRAP modeling. 58 On June 20, 2013, Oklahoma submitted a regional haze SIP revision to replace the FIP's SO 2 BART requirements for the AEP/PSO Northeastern Units 3 and 4. On March 7, 2014, we approved this SIP revision and concurrently withdrew the FIP's applicability to these two units. 59 The FIP provisions applicable to the OG&E Sooner Units 1 and 2 and the OG&E Muskogee Units 4 and 5 remain in place.

As discussed in the previous subsection, based on the results of the SO 2 Monitoring Program that was required under the AEP/PSO Settlement Agreement and part of the 2013 Regional Haze SIP Revision, AEP/PSO concluded that the federally enforceable emission rate for AEP/PSO Northeastern Unit 3 should be 0.37 lb/MMBtu on a 30-day rolling average basis. However, this level of control falls short of the 0.3 lb/MMBtu emission limit necessary to achieve emission levels equivalent to the levels assumed in other states' regional haze plans through the CENRAP RPO process. To address this issue, EPA assessed whether the SO 2 emissions reductions secured from other facilities under the existing FIP promulgated on December 28, 2011, would be sufficient to make up for the shortfall in emissions reductions and associated visibility benefit from the AEP/PSO Northeastern facility compared to what was assumed in the CENRAP modeling. Under the CENRAP regional haze planning process, CENRAP included emissions for these sources based upon Oklahoma's indications that the OG&E Sooner Units 1 and 2, the OG&E Muskogee Units 4 and 5, and the AEP/PSO Northeastern Units 3 and 4 would each be controlled to presumptive BART emission levels for SO 2 , which is 0.15 lb/MMBtu. 60 Further, the FIP EPA promulgated on December 28, 2011, which continues to apply to the OG&E Sooner Units 1 and 2 and the OG&E Muskogee Units 4 and 5, requires each of these four units to comply with an emission limit of 0.06 lb/MMBtu for purposes of complying with the SO 2 BART requirements. 61

In Table 1 below, we present the controlled SO 2 annual emission levels included in the CENRAP chemical transport modeling using the Comprehensive Air Quality Model with Extensions (CAMx) for the six units and the controlled SO 2 annual emission levels required by both the FIP for 4 units and the 2013 Oklahoma Regional Haze SIP Revision for the AEP/PSO Northeastern facility's 2 units. 62 These SO 2 annual emissions were based on annual firing rate information for the base period (2002) and the appropriate lb/MMBtu emission limit. The CENRAP CAMx modeling assumed that AEP/PSO Northeastern Units 3 and 4 would have combined controlled SO 2 emissions of 5,921 tpy, while the 2013 Oklahoma Regional Haze SIP revision includes control requirements that result in combined controlled SO 2 emissions of 7,895 tpy using the same annual firing rate information used in CENRAP's CAMx modeling. This results in a shortfall of 1,974 tpy between the controlled emission level assumed in the CENRAP CAMx modeling and the level of control required by the 2013 SIP Revision. The CENRAP CAMx modeling also assumed that the OG&E Muskogee Units 4 and 5 would have combined controlled SO 2 emissions of 5,249 tpy, while the FIP requires SO 2 controls that result in combined controlled SO 2 emissions of 2,100 tpy using the same annual firing rate information used in CENRAP's CAMx modeling. The FIP results in SO 2 controlled emissions on Muskogee units that are 3,150 SO 2 tpy lower than the level assumed in the CENRAP modeling, which is greater than the 1,974 tpy shortfall from the AEP/PSO Northeastern facility. Focusing on the OG&E Muskogee Units 4 and 5 alone, the level of SO 2 control required by the FIP at these two units is sufficient to make up for the shortfall in emission reductions from the AEP/PSO Northeastern facility. This is significant because the OG&E Muskogee facility is located in the northeast quadrant of Oklahoma, which is where the AEP/PSO Northeastern facility is located. In our final rule approving the 2013 Oklahoma Regional Haze SIP revision, we explained that any additional SO 2 emissions reductions that can be obtained or identified from the northeast quadrant of the State will be presumed to count toward the emission reductions necessary to achieve the anticipated visibility benefits associated with a 0.30 lb/MMBtu emission limit at Northeastern Power Station. 63 The OG&E Sooner Units 1 & 2 also provide additional surplus emissions (3,304 tpy of SO 2 ) that provide benefit beyond the net surplus of 1,176 tpy of SO 2 from the net of Muskogee units surplus and Northeastern units shortfall (3,150 tpy − 1,974 tpy). The level of SO 2 controls within EPA's FIP is therefore sufficient to make up for the shortfall from the AEP/PSO Northeastern facility.

Since hourly emission estimates for these six units were also used in CALPUFF modeling that was part of the BART analyses in the 2010 Oklahoma Regional Haze SIP, the FIP and the 2013 SIP revision, we also evaluated the difference in modeled emission rates and emissions used in the CALPUFF modeling to compare the estimated hourly emission rates between the 0.15 lb/MMBtu presumptive rate utilized in the CENRAP RPO process and the rates required by the FIP and 2013 SIP revision. The CALPUFF modeling provides visibility impact information for each of the three facilities to further support that the net changes in emissions at these three facilities result in a net surplus of emission reductions and visibility benefits that supports EPA's proposed conclusion that visibility transport is adequately addressed for SO 2 . Below we discuss the difference in emissions followed by a discussion of the modeled visibility impacts.

Single source modeling with the CALPUFF model was conducted for each of these facilities using maximum firing rates (instead of the actual annual firing rate used in CAMx analysis). The use of maximum firing rate rather than the actual annual rate that was utilized in the CENRAP CAMx modeling results in a higher estimate of hourly emission rates and also annual emission rates. Since these maximum hourly emission rates used for CALPUFF modeling give a larger difference (larger potential shortfall) for the Northeastern Units 3 & 4 and also are the emission rates evaluated for individual visibility assessments, we perform our evaluation on these rates as well as the annual CAMx modeled rates discussed above and in Table 1. In Table 2, these controlled SO 2 maximum hourly emission levels were calculated assuming the maximum heat input rate (MMBtu/hr) of each unit, which is also the heat input rate used in EPA's CALPUFF BART modeling for the FIP, multiplied by the applicable emission rate (lb/MMBtu). A comparison of these numbers shows that even though the AEP/PSO Northeastern Unit 3 is required to comply with an emission limit of 0.40 lb/MMBtu under the 2013 Oklahoma Regional Haze SIP Revision, which is higher (less stringent) than the 0.30 lb/MMBtu level (0.15 + 0.15 for Northeastern Units 3 and 4) needed in order to achieve hourly emission levels equivalent to the levels relied upon in other states' regional haze plans through the CENRAP RPO process, the total maximum hourly controlled SO 2 emissions levels for the six units under the FIP and the 2013 Oklahoma Regional Haze SIP Revision are lower than the total controlled maximum hourly SO 2 emissions levels based on the presumptive control level included in the CENRAP RPO consultation and modeling. In other words, the FIP and the 2013 Oklahoma Regional Haze SIP Revision result in greater SO 2 emission reductions for these three facilities for the maximum hourly emissions compared to the maximum hourly emissions based on the 0.15 lb/MMBtu emission limit used in the CENRAP RPO consultation process. Specifically, the combination of the FIP and the 2013 Oklahoma Regional Haze SIP Revision result in combined maximum hourly controlled SO 2 emissions of 3,596.3 lb/hr from the six units, which is 1,293.4 lb/hr less than the levels estimated from the rate (4,889.7 lb/hr) based on the 0.15 lb of SO 2 /MMBtu controlled emission rate that Oklahoma shared in consultation and was used in the CENRAP RPO process, including the CENRAP CAMx modeling. This is because the FIP requires a greater level of SO 2 control for the OG&E Sooner Units 1 and 2 and the OG&E Muskogee Units 4 and 5 than the presumptive rate included in consultation and in the CENRAP CAMx modeling. The more stringent level of SO 2 controls required by EPA's FIP is therefore sufficient to make up for the shortfall from the AEP/PSO Northeastern facility. Using the 0.15 lb/MMBtu controlled emission rate from the CENRAP CAMx modeling, the maximum hourly emission rate using the higher firing rate (maximum firing rate) calculated that AEP/PSO Northeastern Units 3 and 4 would have combined controlled SO 2 emissions of 1710.9 lb/hr, while the 2013 Oklahoma Regional Haze SIP revision includes control requirements that result in combined controlled SO 2 maximum hourly emissions of 2324.8 lb/hr, resulting in a shortfall of 613.9 lb/hr. Using the 0.15 lb/MMBtu from the CENRAP CAMx modeling, the OG&E Muskogee Units 4 and 5 would have combined maximum hourly controlled SO 2 emissions of 1644 lb/hr, while the FIP requires SO 2 controls that result in combined maximum hourly controlled SO 2 emissions of 657.6 lb/hr, a difference of 986.4 lb/hr. This surplus of 986.4 lb/hr of SO 2 is greater than the 613.9 lb/hr shortfall from the AEP/PSO Northeastern facility. Focusing on the OG&E Muskogee Units 4 and 5 alone, the level of SO 2 control required by the FIP at these two units is sufficient to make up for the shortfall from the AEP/PSO Northeastern facility. This is significant because the OG&E Muskogee facility is located in the northeast quadrant of Oklahoma, which is where the AEP/PSO Northeastern facility is located. In our final rule approving the 2013 Oklahoma Regional Haze SIP revision, we explained that any additional SO 2 emissions reductions that can be obtained or identified from the northeast quadrant of the State will be presumed to count toward the emission reductions necessary to achieve the anticipated visibility benefits associated with a 0.30 lb/MMBtu emission limit at Northeastern Power Station. 64 The OG&E Sooner Units 1 & 2 also provide an additional surplus of maximum hourly emission reductions (920.9 lb/hr of SO 2 ) that provide benefit beyond the net surplus of 372.5 lb/hr of SO 2 from Muskogee units surplus and Northeastern units shortfall (986.4 lb/hr−613.9 lb/hr). The level of SO 2 controls within EPA's FIP is therefore sufficient to make up for the shortfall from the AEP/PSO Northeastern facility when comparing maximum hourly emissions. In the spreadsheet in the docket we also evaluated using these maximum hourly emission estimates on an annual basis (tpy) for general comparison and it also indicated that EPA's FIP requirements result in a net surplus of annual emissions. 65

We also assessed whether the visibility benefits resulting from the SO 2 controls for the OG&E Sooner Units 1 and 2 and the OG&E Muskogee Units 4 and 5 under the FIP are estimated to make up for any visibility benefit shortfall from the AEP/PSO Northeastern Units 3 and 4 by scaling modeled visibility improvements from the CALPUFF modeling that was performed as part of the 2011 Oklahoma SO 2 BART FIP. 66 Based on previous modeling performed for these sources and other sources in other Region 6 FIPs and SIPs linear scaling within the ranges performed is a reasonable approach to estimate impacts. We scaled modeled visibility improvements for Wichita Mountains as well as Class I areas in other states affected by Oklahoma: Caney Creek Wilderness Area and Upper Buffalo Wilderness Area in Arkansas and Hercules-Glades Wilderness Area in Missouri. We used the 2001-2003 average of the 98th percentile of daily maximum dv as the visibility impact values for our calculations and assumed linear concentration and linear visibility impairment calculations. Based on our calculations, the SO 2 emission reduction shortfall in the 2013 Oklahoma Regional Haze SIP Revision for the AEP/PSO Northeastern Units 3 and 4 (difference between visibility impacts under the 2013 SIP requirements and the CENRAP consultation and modeling assumptions of 0.15 lb/MMBtu for each unit) is estimated to result in a visibility benefit shortfall of 0.096 dv for the four affected Class I areas combined (See Table 3 below). 67 On the other hand, the FIP's estimated visibility benefits in excess of the assumptions in the CENRAP consultation and modeling ( i.e., comparing 0.15 lb/MMBtu emission limit from the CENRAP consultation and CAMx modeling with 0.06 lb/MMBtu emission limit required under the FIP) with respect to the OG&E Muskogee Units 4 and 5 are 0.332 dv and the OG&E Sooner Units 1 and 2 are 0.190 dv for the four affected Class I areas combined. 68 The excess benefit from OG&E Muskogee Units 4 and 5 alone is enough to more than offset the Northeastern shortfall at each Class I area, including the nearby areas in other states. In addition, the cumulative benefit at all four Class I areas is greater than the cumulative shortfall, resulting in an overall benefit of 0.236 dv (0.332 dv excess−0.096 dv shortfall = 0.236 dv). Including the benefits from the four OG&E Muskogee and Sooner units results in t a net estimated excess visibility benefit of 0.425 dv at the four affected Class I areas combined. These results are summarized in the Table 3 below.

This SUPPLEMENTARY INFORMATION section is arranged as follows:

On June 22, 2010, EPA promulgated a new 1-hour primary SO 2 NAAQS of 75 parts per billion (ppb), which is met at an ambient air quality monitoring site when the 3-year average of the annual 99th percentile of daily maximum 1- hour average concentrations does not exceed 75 ppb, as determined in accordance with appendix T of 40 CFR part 50. See 75 FR 35520, codified at 40 CFR 50.17(a)-(b). On August 5, 2013, EPA designated 29 areas of the country as nonattainment for the 2010 SO 2 NAAQS, including the Rhinelander area within the State of Wisconsin. See 78 FR 47191, codified at 40 CFR part 81, subpart C. These area designations were effective October 4, 2013. Section 191 of the CAA directs states to submit SIPs for areas designated as nonattainment for the SO 2 NAAQS to EPA within 18 months of the effective date of the designation, i.e., by no later than April 4, 2015 in this case. These SIPs are required to demonstrate that their respective areas will attain the NAAQS as expeditiously as practicable, but no later than 5 years from the effective date of designation, which is October 4, 2018.

In response to the requirement for SO 2 nonattainment plan submittals, Wisconsin submitted a nonattainment plan for the Rhinelander area on January 22, 2016, and supplemented it on July 18, 2016, and November 29, 2016. On March 23, 2021, 1 EPA partially approved and partially disapproved Wisconsin's Rhinelander SO 2 plan as submitted and supplemented in 2016. EPA approved the base-year emissions inventory and affirmed that the new source review requirements for the area had previously been met. 2 EPA also approved the SO 2 emission limit for Ahlstrom-Munksjö's Rhinelander facility (Ahlstrom-Munksjö) (formerly Expera Specialty Solutions LLC (Expera)) as SIP-strengthening. At that time, EPA disapproved the attainment demonstration, since the plan relied on credit for more stack height than is creditable under the regulations for good engineering practice (GEP) stack height. Additionally, EPA disapproved the plan for failing to meet the requirements for meeting RFP toward attainment of the NAAQS, RACM/RACT, emission limitations and control measures as necessary to attain the NAAQS, and contingency measures.

Under sections 110(c) and 179(a)-(b) of the CAA, a disapproval in whole or in part of a state submittal initiates a Federal Implementation Plan (FIP) clock and sanctions clocks, respectively, which are terminated by an EPA rulemaking approving a revised plan. On March 29, 2021, Wisconsin submitted a permit containing a revised emission limit and supplemental information in order to remedy the plan's deficiencies specified in EPA's March 23, 2021 rulemaking, along with a request that EPA approve its revised plan for the Rhinelander area.

The remainder of this action describes the requirements that SO 2 nonattainment plans must meet in order to obtain EPA approval, provides a review of Wisconsin's revised plan with respect to these requirements, and describes EPA's proposed action on the plan.

Nonattainment SIPs must meet the applicable requirements of the CAA, and specifically CAA sections 172, 191 and 192. EPA's regulations governing nonattainment SIPs are set forth at 40 CFR part 51, with specific procedural requirements and control strategy requirements residing at subparts F and G, respectively. Soon after Congress enacted the 1990 Amendments to the CAA, EPA issued comprehensive guidance on SIPs, in a document entitled the “General Preamble for the Implementation of Title I of the Clean Air Act Amendments of 1990,” published at 57 FR 13498 (April 16, 1992) (General Preamble). Among other things, the General Preamble addressed SO 2 SIPs and fundamental principles for SIP control strategies. Id., at 13545-49, 13567-68. On April 23, 2014, EPA issued recommended guidance for meeting the statutory requirements in SO 2 SIPs, in a document entitled, “Guidance for 1-Hour SO 2 Nonattainment Area SIP Submissions,” available at https://www.epa.gov/sites/production/files/2016-06/documents/20140423guidance_nonattainment_sip.pdf. In this guidance EPA described the statutory requirements for a complete nonattainment area SIP, which includes: An accurate emissions inventory of current emissions for all sources of SO 2 within the nonattainment area; an attainment demonstration; demonstration of RFP; implementation of RACM (including RACT); NSR; emissions limitations and control measures as necessary to attain the NAAQS; and adequate contingency measures for the affected area. EPA already concluded in its March 23, 2021 rulemaking that Wisconsin has met the emissions inventory and NSR requirements.

In order for EPA to fully approve a SIP as meeting the requirements of CAA sections 110, 172 and 191-192 and EPA's regulations at 40 CFR part 51, the SIP for the affected area needs to demonstrate to EPA's satisfaction that each of the aforementioned requirements have been met. Under CAA sections 110(l) and 193, EPA may not approve a SIP that would interfere with any applicable requirement concerning NAAQS attainment and RFP, or any other applicable requirement, and no requirement in effect (or required to be adopted by an order, settlement, agreement, or plan in effect before November 15, 1990) in any area which is a nonattainment area for any air pollutant, may be modified in any manner unless it ensures equivalent or greater emission reductions of such air pollutant.

CAA section 172(c)(1) directs states with areas designated as nonattainment to demonstrate that the submitted plan provides for attainment of the NAAQS. 40 CFR part 51, subpart G, further delineates the control strategy requirements that SIPs must meet, and EPA has long required that all SIPs and control strategies reflect four fundamental principles of quantification, enforceability, replicability, and accountability. General Preamble at 13567-68. SO 2 attainment plans must consist of two components: (1) Emission limits and other control measures that ensure implementation of permanent, enforceable and necessary emission controls, and (2) a modeling analysis which meets the requirements of 40 CFR part 51, appendix W, which demonstrates that these emission limits and control measures provide for timely attainment of the primary SO 2 NAAQS as expeditiously as practicable, but by no later than the attainment date for the affected area. In all cases, the emission limits and control measures must be accompanied by appropriate methods and conditions to determine compliance with the respective emission limits and control measures and must be quantifiable ( i.e., a specific amount of emission reduction can be ascribed to the measures), fully enforceable (specifying clear, unambiguous and measurable requirements for which compliance can be practicably determined), replicable (the procedures for determining compliance are sufficiently specific and non-subjective so that two independent entities applying the procedures would obtain the same result), and accountable (source specific limits must be permanent and must reflect the assumptions used in the SIP demonstrations).

EPA's April 2014 guidance recommends that the emission limits be expressed as short-term average limits ( e.g., addressing emissions averaged over one or three hours), but also describes the option to utilize emission limits with longer averaging times of up to 30 days so long as the state meets various suggested criteria. See 2014 guidance, pp. 22 to 39. The guidance recommends that, should states and sources utilize longer averaging times, the longer term average limit should be set at an adjusted level that reflects a stringency comparable to the 1-hour average limit at the critical emission value shown to provide for attainment that the plan otherwise would have set.

The April 2014 guidance provides an extensive discussion of EPA's rationale for concluding that appropriately set comparably stringent limitations based on averaging times as long as 30 days can be found to provide for attainment of the 2010 SO 2 NAAQS. In evaluating this option, EPA considered the nature of the standard, conducted detailed analyses of the impact of use of 30-day average limits on the prospects for attaining the standard, and carefully reviewed how best to achieve an appropriate balance among the various factors that warrant consideration in judging whether a state's plan provides for attainment. Id. at pp. 22 to 39. See also id. at appendices B, C, and D.

As specified in 40 CFR 50.17(b), the 1-hour primary SO 2 NAAQS is met at an ambient air quality monitoring site when the 3-year average of the annual 99th percentile of daily maximum 1-hour concentrations is less than or equal to 75 ppb. In a year with 365 days of valid monitoring data, the 99th percentile would be the fourth highest daily maximum 1-hour value. The 2010 SO 2 NAAQS, including this form of determining compliance with the standard, was upheld by the U.S. Court of Appeals for the District of Columbia Circuit in Nat'l Envt'l Dev. Ass'n's Clean Air Project v. EPA, 686 F.3d 803 (D.C. Cir. 2012). Because the standard has this form, a single exceedance does not create a violation of the standard. Instead, at issue is whether a source operating in compliance with a properly set longer term average could cause exceedances, and if so the resulting frequency and magnitude of such exceedances, and in particular whether EPA can have reasonable confidence that a properly set longer term average limit will provide that the average fourth highest daily maximum value will be at or below 75 ppb. A synopsis of how EPA judges whether such plans “provide for attainment,” based on modeling of projected allowable emissions and in light of the NAAQS' form for determining attainment at monitoring sites follows.

For SO 2 plans based on 1-hour emission limits, the standard approach is to conduct modeling using fixed emission rates. The maximum emission rate that would be modeled to result in attainment ( i.e., in an “average year”  3 which shows three days with maximum hourly levels exceeding 75 ppb) is labeled the “critical emission value.” The modeling process for identifying this critical emissions value inherently considers the numerous variables that affect ambient concentrations of SO 2 , such as meteorological data, background concentrations, and topography. In the standard approach, the state would then provide for attainment by setting a continuously applicable 1-hour emission limit at this critical emission value.

EPA recognizes that some sources have highly variable emissions, for example due to variations in fuel sulfur content and operating rate, that can make it extremely difficult, even with a well-designed control strategy, to ensure in practice that emissions for any given hour do not exceed the critical emission value. EPA also acknowledges the concern that longer term emission limits can allow short periods with emissions above the “critical emissions value,” which, if coincident with meteorological conditions conducive to high SO 2 concentrations, could in turn create the possibility of a NAAQS exceedance occurring on a day when an exceedance would not have occurred if emissions were continuously controlled at the level corresponding to the critical emission value. However, for several reasons, EPA believes that the approach recommended in its guidance document suitably addresses this concern. First, from a practical perspective, EPA expects the actual emission profile of a source subject to an appropriately set longer term average limit to be similar to the emission profile of a source subject to an analogous 1-hour average limit. EPA expects this similarity because it has recommended that the longer term average limit be set at a level that is comparably stringent to the otherwise applicable 1-hour limit (reflecting a downward adjustment from the critical emissions value) and that takes the source's emissions profile into account. As a result, EPA expects either form of emission limit to yield comparable air quality.

Second, from a more theoretical perspective, EPA has compared the likely air quality with a source having maximum allowable emissions under an appropriately set longer term limit, as compared to the likely air quality with the source having maximum allowable emissions under the comparable 1-hour limit. In this comparison, in the 1-hour average limit scenario, the source is presumed at all times to emit at the critical emission level, and in the longer term average limit scenario, the source is presumed occasionally to emit more than the critical emission value but on average, and presumably at most times, to emit well below the critical emission value. In an “average year,” compliance with the 1-hour limit is expected to result in three exceedance days ( i.e., three days with hourly values above 75 ppb) and a fourth day with a maximum hourly value at 75 ppb. By comparison, with the source complying with a longer term limit, it is possible that additional exceedances would occur that would not occur in the 1-hour limit scenario (if emissions exceed the critical emission value at times when meteorology is conducive to poor air quality). However, this comparison must also factor in the likelihood that exceedances that would be expected in the 1-hour limit scenario would not occur in the longer term limit scenario. This result arises because the longer term limit requires lower emissions most of the time (because the limit is set well below the critical emission value), so a source complying with an appropriately set longer term limit is likely to have lower emissions at critical times than would be the case if the source were emitting as allowed with a 1-hour limit.

As a hypothetical example to illustrate these points, suppose a source always emits 1,000 pounds of SO 2 per hour (lbs/hr), which results in air quality at the level of the NAAQS ( i.e., results in a design value of 75 ppb). Suppose further that in an “average year,” these emissions cause the 5 highest maximum daily average 1-hour concentrations to be 100 ppb, 90 ppb, 80 ppb, 75 ppb, and 70 ppb. Then suppose that the source becomes subject to a 30-day average emission limit of 700 lbs/hr. It is theoretically possible for a source meeting this limit to have emissions that occasionally exceed 1,000 lbs/hr, but with a typical emissions profile emissions would much more commonly be between 600 and 800 lbs/hr. In this simplified example, assume a zero background concentration, which allows one to assume a linear relationship between emissions and air quality. (A nonzero background concentration would make the mathematics more difficult but would give similar results.) Air quality will depend on what emissions happen on what critical hours, but suppose that emissions at the relevant times on these 5 days are 800 lbs/hr, 1,100 lbs/hr, 500 lbs/hr, 900 lbs/hr, and 1,200 lbs/hr, respectively. (This is a conservative example because the average of these emissions, 900 lbs/hr, is well over the 30-day average emission limit.) These emissions would result in daily maximum 1-hour concentrations of 80 ppb, 99 ppb, 40 ppb, 67.5 ppb, and 84 ppb. In this example, the fifth day would have an exceedance that would not otherwise have occurred (84 ppb under the 30-day average limit compared to 70 ppb under the 1-hour limit). However, the third day would not have an exceedance that otherwise would have occurred (40 ppb under the 30-day average limit compared to 80 ppb under the 1-hour limit). The fourth day would have been below, rather than at, 75 ppb (67.5 ppb under the 30-day average limit compared to 75 ppb under the 1-hour limit). In this example, the fourth highest maximum daily concentration under the 30-day average would be 67.5 ppb.

This simplified example illustrates the findings of a more complicated statistical analysis that EPA conducted using a range of scenarios using actual plant data. As described in appendix B of EPA's April 2014 SO 2 nonattainment planning guidance, EPA found that the requirement for lower average emissions is likely to yield as good air quality as is required with a comparably stringent 1-hour limit. Based on analyses described in appendix B of its 2014 guidance and similar subsequent work, EPA expects that emission profiles with maximum allowable emissions under an appropriately set comparably stringent 30-day average limit are likely to have the net effect of no more exceedances and as good air quality of an emission profile with maximum allowable emissions under a 1-hour emission limit at the critical emission value. 4 This result provides a compelling policy rationale for allowing the use of a longer averaging period, in appropriate circumstances where the facts indicate this result can be expected to occur.

The question then becomes whether this approach, which is likely to produce a lower number of overall exceedances even though it may produce some unexpected exceedances above the critical emission value, meets the requirement in section 110(a)(1) and 172(c)(1) for state implementation plans to “provide for attainment” of the NAAQS. For SO 2 , as for other pollutants, it is generally impossible to design a nonattainment plan in the present that will guarantee that attainment will occur in the future. A variety of factors can cause a well-designed attainment plan to fail and unexpectedly not result in attainment, for example if meteorology occurs that is more conducive to poor air quality than was anticipated in the plan. Therefore, in determining whether a plan meets the requirement to provide for attainment, EPA's task is commonly to judge not whether the plan provides absolute certainty that attainment will in fact occur, but rather whether the plan provides an adequate level of confidence of prospective NAAQS attainment. From this perspective, in evaluating use of a 30-day average limit, EPA must weigh the likely net effect on air quality. Such an evaluation must consider the risk that occasions with meteorology conducive to high concentrations will have elevated emissions leading to exceedances that would not otherwise have occurred, and must also weigh the likelihood that the requirement for lower emissions on average will result in days not having exceedances that would have been expected with emissions at the critical emissions value. Additional policy considerations, such as accommodating real world emissions variability without significant risk of violations, are also appropriate factors for EPA to weigh in judging whether a plan provides a reasonable degree of confidence that the plan will lead to attainment. Based on these considerations, EPA believes that a continuously enforceable limit averaged over as long as 30 days, if determined in accordance with EPA's guidance, can reasonably be considered to provide for attainment of the 2010 SO 2 NAAQS.

The April 2014 guidance offers specific recommendations for determining an appropriate longer term average limit. The recommended method starts with determination of the 1-hour emission limit that would provide for attainment ( i.e., the critical emission value), then applies an adjustment factor to determine the (lower) level of the longer term average emission limit that would be estimated to have a stringency comparable to the 1-hour emission limit. This method uses a database of continuous emission data reflecting the type of control that the source will be using to comply with the SIP emission limits, which (if compliance requires new controls) may require use of an emission database from another source. The recommended method involves using these data to compute a complete set of emission averages, computed according to the averaging time and averaging procedures of the prospective emission limitation. In this recommended method, the ratio of the 99th percentile among these long term averages to the 99th percentile of the 1-hour values represents an adjustment factor that may be multiplied by the candidate 1-hour emission limit to determine a longer term average emission limit that may be considered comparably stringent. 5 The guidance also addresses a variety of related topics, such as the potential utility of setting supplemental emission limits, such as mass-based limits, to reduce the likelihood and/or magnitude of elevated emission levels that might occur under the longer term emission rate limit.

Preferred air quality models for use in regulatory applications are described in appendix A of EPA's Guideline on Air Quality Models (40 CFR part 51, appendix W). In 2005, EPA promulgated AERMOD as the Agency's preferred near-field dispersion modeling for a wide range of regulatory applications addressing stationary sources (for example in estimating SO 2 concentrations) in all types of terrain based on extensive developmental and performance evaluation. Supplemental guidance on modeling for purposes of demonstrating attainment of the SO 2 standard is provided in appendix A to the April 23, 2014 SO 2 nonattainment area SIP guidance document referenced above. Appendix A provides extensive guidance on the modeling domain, the source inputs, assorted types of meteorological data, and background concentrations. Consistency with the recommendations in this guidance is generally necessary for the attainment demonstration to offer adequately reliable assurance that the plan provides for attainment.

As stated previously, attainment demonstrations for the 2010 1-hour primary SO 2 NAAQS must demonstrate future attainment and maintenance of the NAAQS in the entire area designated as nonattainment ( i.e., not just at the violating monitor). This is demonstrated by using air quality dispersion modeling ( see appendix W to 40 CFR part 51) that shows that the mix of sources, enforceable control measures, and emission rates in an identified area will not lead to a violation of the SO 2 NAAQS. For a short-term ( i.e., 1-hour) standard, EPA believes that dispersion modeling, using allowable emissions and addressing stationary sources in the affected area (and in some cases those sources located outside the nonattainment area which may affect attainment in the area) is technically appropriate, efficient and effective in demonstrating attainment in nonattainment areas because it takes into consideration combinations of meteorological and emission source operating conditions that may contribute to peak ground-level concentrations of SO 2.

The meteorological data used in the analysis should generally be processed with the most recent version of AERMET. Estimated concentrations should include ambient background concentrations, should follow the form of the standard, and should be calculated as described in section 2.6.1.2 of the August 23, 2010 clarification memo on “Applicability of appendix W Modeling Guidance for the 1-hr SO 2 National Ambient Air Quality Standard” (U.S. EPA, 2010a).

The following discussion evaluates various features of the modeling that Wisconsin used in its attainment demonstration.

Wisconsin's attainment demonstration used AERMOD, the preferred model for this application. Wisconsin's January 2016 submittal used version 15181 of this model, which was the most recent version at that time. However, the supplemental modeling that Wisconsin submitted in March 2021 used version 19191, which is the current regulatory version of AERMOD. EPA finds this selection appropriate.

Wisconsin's receptor grid and modeling domain for the Rhinelander area followed the recommended approaches from EPA's Guideline on Air Quality Models (40 CFR part 51, appendix W). Receptor spacing for each modeled facility was every 25 meters out to a distance of 500 meters from each source, then every 50 meters to 1,000 meters, every 100 meters out to 3 kilometers, every 250 meters out to 6 kilometers, and every 500 meters out to 10 kilometers.

Wisconsin determined that the Rhinelander area should be modeled with rural dispersion coefficients, as Ahlstrom-Munksjö is surrounded by less than 50% of land classified as industrial, commercial, or dense residential within 3 kilometers, as recommended by EPA's Guideline on Air Quality Models. Therefore, EPA concurs with Wisconsin's determination that this area warrants being modeled with rural dispersion coefficients.

Modeling of emissions from Ahlstrom-Munksjö has historically underpredicted concentrations measured at a nearby monitor. When winds blow from this facility toward the monitor, the emissions traverse a corner of the building. Under these circumstances, the building appears to cause enhanced eddies in the air flow, known as corner vortices, which in certain circumstances appear to result in a substantial enhancement of downwash of emissions to ground level and substantially greater concentrations than are modeled using the standard downwash algorithm in AERMOD.

Recognizing these issues, the company contracted for a wind tunnel study, carried out by Cermak Peterka Petersen (CPP), to assess the magnitude of this effect and to support a more accurate assessment of downwash at this facility. This study supported the conclusion that the discrepancy between modeled and monitored SO 2 concentrations were due to the corner vortex phenomenon, a phenomenon that is described in EPA's “Guideline for Determination of Good Engineering Practice Stack Height (Technical Support Document for the Stack Height Regulations).”  6 The wind tunnel study showed that as the wind approaches the corner of the Ahlstrom-Munksjö building, vortices are created that act to increase the SO 2 concentrations downwind of the building. Analysis of these results suggested that the influence of these corner vortices vary by wind speed. Ahlstrom-Munksjö's consultants, AECOM and CPP, developed an equation estimating a multiplier, varying by wind speed, by which to estimate the impact of downwash in this case, i.e., a multiplier by which to multiply concentrations estimated in absence of downwash to estimate concentrations reflecting the downwash induced by this facility. The wind tunnel study focused on concentrations in the direction with the most enhanced downwash but applied the same adjustment in all directions. Since there is less downwash in directions less influenced by corner vortices, EPA considers this approach conservative in maximizing estimated downwash effects on concentrations.

Wisconsin's 2016 SIP submittal relied on modeling Ahlstrom-Munksjö using a stack height of 90 meters. For this facility, the “formula good engineering practice (GEP) stack height” computed according to the formula in EPA's stack height regulations (defined at 40 CFR 51.100(ii)(2)(ii)) is 75 meters. EPA disapproved the 2016 submittal because EPA's stack height regulations prohibit credit for a stack above formula GEP stack height unless the state meets requirements specified in those regulations for the level of control at the facility. Wisconsin's 2021 submittal meets EPA's stack height regulations by applying a limit demonstrated to provide attainment with a stack at the creditable height of 75 meters.

The wind tunnel studies primarily simulated a stack with a height of 85 meters, with another run simulating a stack with a height of 90 meters. These runs indicated the following equation to estimate the ratio of concentrations expected with the building as compared concentrations without the building:

Throughout this document, “we,” “us,” and “our” refer to the EPA.

Under section 109 of the CAA, the EPA has established NAAQS for certain pervasive air pollutants (referred to as “criteria pollutants”) and conducts periodic reviews of the NAAQS to determine whether they should be revised or whether new NAAQS should be established.

On July 18, 1997, the EPA revised the NAAQS for particulate matter by establishing new NAAQS for particles with an aerodynamic diameter less than or equal to a nominal 2.5 micrometers (PM 2.5 ). 1 The EPA established primary and secondary annual and 24-hour standards for PM 2.5 . 2 The annual primary and secondary standards were set at 15.0 micrograms per cubic meter (μg/m 3 ), based on a three-year average of annual mean PM 2.5 concentrations, and the 24-hour primary and secondary standards were set at 65 μg/m 3 , based on the three-year average of the 98th percentile of 24-hour PM 2.5 concentrations at each monitoring site within an area. 3 Collectively, we refer herein to the 1997 annual and 24-hour PM 2.5 NAAQS as the “1997 PM 2.5 NAAQS” or “1997 PM 2.5 standards.”

On October 17, 2006, the EPA revised the level of the 24-hour PM 2.5 NAAQS to 35 μg/m 3 , 4 and on January 15, 2013, the EPA revised the level of the primary annual PM 2.5 NAAQS to 12.0 μg/m 3 . 5 Even though the EPA has lowered the 24-hour and annual PM 2.5 standards, the 1997 PM 2.5 standards remain in effect.

The EPA established these standards after considering substantial evidence from numerous health studies demonstrating that serious health effects are associated with exposures to PM 2.5 concentrations above these levels. Epidemiological studies have shown statistically significant correlations between elevated PM 2.5 levels and premature mortality. Other important health effects associated with PM 2.5 exposure include aggravation of respiratory and cardiovascular disease (as indicated by increased hospital admissions, emergency room visits, absences from school or work, and restricted activity dates), changes in lung function and increased respiratory symptoms, and new evidence for more subtle indicators of cardiovascular health. Individuals particularly sensitive to PM 2.5 exposure include older adults, people with heart and lung disease, and children. 6

Sources can emit PM 2.5 directly into the atmosphere as a solid or liquid particle (primary PM 2.5 or direct PM 2.5 ), or PM 2.5 can form in the atmosphere (secondary PM 2.5 ) as a result of various chemical reactions from precursor emissions of nitrogen oxides (NO X ), sulfur oxides (SO X ), volatile organic compounds (VOC), and ammonia. 7

Following promulgation of a new or revised NAAQS, the EPA is required under CAA section 107(d) to designate areas throughout the nation as attaining or not attaining the NAAQS. Effective April 5, 2005, the EPA established the initial air quality designations for the 1997 annual and 24-hour PM 2.5 NAAQS, using air quality monitoring data for the three-year periods of 2001-2003 and 2002-2004. 8 The EPA designated the San Joaquin Valley as nonattainment for both the 1997 annual PM 2.5 NAAQS (15.0 μg/m 3 ) and the 1997 24-hour PM 2.5 NAAQS (65 μg/m 3 ). 9

The San Joaquin Valley PM 2.5 nonattainment area encompasses over 23,000 square miles and includes all or part of eight counties: San Joaquin, Stanislaus, Merced, Madera, Fresno, Tulare, Kings, and the valley portion of Kern. 10 The area is home to four million people and is one of the nation's leading agricultural regions. Stretching over 250 miles from north to south and averaging 80 miles wide, it is partially enclosed by the Coast Mountain range to the west, the Tehachapi Mountains to the south, and the Sierra Nevada range to the east. Under State law, the San Joaquin Valley Unified Air Pollution Control District (SJVUAPCD or “District”) has primary responsibility for developing plans to provide for attainment of the NAAQS in this area. The District works cooperatively with the California Air Resources Board (CARB) in preparing attainment plans. Authority for regulating sources under state jurisdiction in the San Joaquin Valley is split under State law between the District, which has responsibility for regulating stationary and most area sources, and CARB, which has responsibility for regulating most mobile sources.

Within three years of the effective date of designations, states with areas designated as nonattainment for the 1997 PM 2.5 NAAQS were required to submit SIP revisions that, among other things, provided for implementation of reasonably available control measures (RACM), RFP, attainment of the standards as expeditiously as practicable but no later than five years from the nonattainment designation (in this instance, no later than April 5, 2010) unless the state justified an attainment date extension of up to five years, and contingency measures. 11

Between 2007 and 2011, California submitted six SIP revisions to address nonattainment area planning requirements for the 1997 PM 2.5 NAAQS in the San Joaquin Valley, 12 which we refer to collectively as the “2008 PM 2.5 Plan.” On November 9, 2011, the EPA approved the portions of the 2008 PM 2.5 Plan, as revised in 2009 and 2011, that addressed attainment of the 1997 PM 2.5 NAAQS in the San Joaquin Valley PM 2.5 nonattainment area, except for the attainment contingency measures, which we disapproved. 13 We also granted the State's request to extend the attainment deadline for the 1997 PM 2.5 NAAQS in the San Joaquin Valley to April 5, 2015. 14

Following a January 4, 2013 decision of the U.S. Court of Appeals for the D.C. Circuit (“D.C. Circuit”) remanding the EPA's 2007 implementation rule for the 1997 PM 2.5 NAAQS, 15 the EPA published a final rule on June 2, 2014, classifying the San Joaquin Valley, among other areas, as a Moderate nonattainment area for the 1997 PM 2.5 NAAQS under subpart 4, part D of title I of the Act. 16

Effective May 7, 2015, the EPA reclassified the San Joaquin Valley as a Serious nonattainment area for the 1997 PM 2.5 NAAQS based on our determination that the area could not practicably attain these NAAQS by the April 5, 2015 attainment date. 17 Upon reclassification as a Serious area, the San Joaquin Valley became subject to a December 31, 2015 deadline under CAA section 188(c)(2) to attain the 1997 PM 2.5 NAAQS. On February 9, 2016, the EPA proposed to grant the State's request for extensions of the December 31, 2015 attainment date under CAA section 188(e), to December 31, 2018, for the 1997 24-hour PM 2.5 NAAQS, and to December 31, 2020, for the 1997 annual PM 2.5 NAAQS in the San Joaquin Valley. 18 However, on October 6, 2016, after considering public comments, the EPA denied California's request for these extensions of the attainment dates. 19 Consequently, on November 23, 2016, the EPA determined that the San Joaquin Valley had failed to attain the 1997 PM 2.5 NAAQS by the December 31, 2015 Serious area attainment date. 20 This determination triggered a requirement for California to submit, by December 31, 2016, a revised PM 2.5 attainment plan for the 1997 PM 2.5 NAAQS for the San Joaquin Valley that satisfies the requirements of CAA section 189(d).

On December 6, 2018, the EPA determined that California had failed to submit a complete Serious area and section 189(d) attainment plan for the 1997 PM 2.5 NAAQS, among other required SIP submissions for the San Joaquin Valley, by the submittal deadline. 21 This finding, which became effective on January 7, 2019, triggered clocks under CAA section 179(a) for the application of emissions offset sanctions 18 months after the finding and highway funding sanctions six months thereafter, unless the EPA affirmatively determines that the State has submitted a complete SIP addressing the identified deficiencies. 22 The finding also triggered the obligation under CAA section 110(c) on the EPA to promulgate a federal implementation plan no later than two years after the finding, unless the State has submitted, and the EPA has approved, the required SIP submittal. 23 CARB submitted a revised attainment plan for the 1997 PM 2.5 NAAQS, among other submissions, on May 10, 2019. 24 This SIP revision is the subject of this proposal. On June 24, 2020, the EPA issued a letter finding the submittal complete and terminating the sanctions clocks under CAA section 179(a). 25