I. Background

In accordance with the Privacy Act of 1974, 5 U.S.C. 552a, DHS/CBP proposes to concurrently modify the DHS System of Records titled, “DHS/CBP-022 Electronic Visa Update System (EVUS) System of Records” and issue this notice of proposed rulemaking to exempt portions of the system of records from one or more provision of the Privacy Act of 1974 because of criminal, civil, and administrative enforcement requirements.

This system of records notice (SORN) describes the collection, use, maintenance, and dissemination of records pertaining to eligible international travelers who: (1) Hold a passport that was issued by an identified country approved for inclusion in the EVUS program, and (2) have been issued a U.S. nonimmigrant visa of a designated category seeking to travel to the United States. The system of records will also cover records of other persons, including U.S. citizens and lawful permanent residents, whose names are provided to DHS as part of a nonimmigrant alien's EVUS enrollment. DHS/CBP ensures a visa holder's information remains current by requiring nonimmigrant aliens holding passports of identified countries containing U.S. nonimmigrant visas of a designated category with multiple year validity to update their EVUS information. After issuance of a visa, nonimmigrant aliens subject to EVUS requirements need to successfully enroll in EVUS online every two years to ensure their visa remains valid for travel to the United States.

DHS/CBP vets the EVUS applicant's information against selected DHS and other federal agency databases to enhance DHS's ability to determine whether the applicant poses a security risk to the United States or is otherwise ineligible to travel and enter the United States. For instance, DHS/CBP vets against the following DHS databases, and their associated SORNs: TECS (not an acronym) (DHS/CBP-011 U.S. Customs and Border Protection TECS, December 19, 2008, 73 FR 77778), and the Automated Targeting System (ATS) (DHS/CBP-006 Automated Targeting System, May 22, 2012, 77 FR 30297). ATS retains a copy of EVUS enrollment data to identify EVUS enrollees who may pose a security risk to the United States. All EVUS vetting results, and derogatory information, are stored in ATS and covered by the ATS SORN.

Further, as explained in the concurrent notice of the updated EVUS SORN, DHS/CBP is modifying this SORN to (1) clarify that the EVUS enrollment information includes questions necessary to evaluate whether a covered alien's travel to the United States poses a law enforcement or security risk, and to make administrative changes to remove references to the specific EVUS application questions and data elements; (2) provide additional transparency that vetting results are retained in ATS; (3) expand the previously issued exemptions to clarify that DHS/CBP is exempting certain portions of records in this system from provisions of the Privacy Act of 1974 because of criminal, civil, and administrative enforcement requirements; and (4) to add new Routine Uses and clarify previously issued ones.

Due to the expansion of exemptions previously published for this system of records, DHS is issuing this Notice of Proposed Rulemaking (NPRM) concurrent with the SORN to exempt the system of records from certain provisions of the Privacy Act of 1974. These records are exempt from 5 U.S.C. 552a(c)(3) and (4); (d)(1), (2), (3), and (4); (e)(1), (2), (3), (4)(G) through (I), (5), and (8); (f); and (g) of the Privacy Act of 1974, as amended, pursuant 5 U.S.C. 552a(j)(2). Additionally, the Secretary of Homeland Security has exempted this system from the following provisions of the Privacy Act, pursuant to 5 U.S.C. 552a(k)(1) and (k)(2): 5 U.S.C. 552a(c)(3); (d)(1), (d)(2), (d)(3), and (d)(4); (e)(1), (e)(4)(G), (e)(4)(H), (e)(4)(I); and (f). Such exempt records or information may be law enforcement or national security investigation records, law enforcement activity and encounter records, or terrorist screening records. DHS needs these exemptions in order to protect information relating to law enforcement investigations from disclosure to subjects of investigations and others who could interfere with investigatory and law enforcement activities. Specifically, the exemptions are required to: Preclude subjects of investigations from frustrating the investigative process; avoid disclosure of investigative techniques; protect the identities and physical safety of confidential informants and of law enforcement personnel; ensure DHS's and other federal agencies' ability to obtain information from third parties and other sources; protect the privacy of third parties; and safeguard sensitive information.

Despite the exemptions taken on this system of records, DHS/CBP is not taking any exemption from subsection (d) with respect to information maintained in the system as it relates to data submitted by or on behalf of a person who travels to visit the United States and crosses the border, nor shall an exemption be asserted with respect to the resulting determination (authorized to travel, pending, or not authorized to travel). However, pursuant to 5 U.S.C. 552a(j)(2), DHS/CBP plans to exempt such information in this system from sections (c)(3), (e)(8), and (g) of the Privacy Act of 1974, as amended, as is necessary and appropriate to protect this information. Further, DHS will claim exemption from section (c)(3) of the Privacy Act of 1974, as amended, pursuant to 5 U.S.C. 552a(k)(2) as is necessary and appropriate to protect this information. CBP will not disclose the fact that a law enforcement or intelligence agency has sought particular records because it may affect ongoing law enforcement activities. Nonetheless, DHS will examine each request on a case-by-case basis, and, after conferring with the appropriate component or agency, may waive applicable exemptions in appropriate circumstances and where it would not appear to interfere with or adversely affect the law enforcement or national security investigation.

DHS/CBP previously issued a Final Rule to exempt this system of records from certain provisions of the Privacy Act of 1974 on November 25, 2016 (81 FR 85105). These regulations remain in effect until a new Final Rule becomes effective. Once a Final Rule becomes effective, DHS will add this exemption to Appendix C to 6 CFR part 5, DHS Systems of Records Exempt from the Privacy Act.

The Privacy Act of 1974 embodies fair information practice principles in a statutory framework governing the means by which Federal Government agencies collect, maintain, use, and disseminate individual's records. The Privacy Act of 1974 applies to information that is maintained in a “system of records.” A “system of records” is a group of any records under the control of an agency from which information is retrieved by the name of the individual or by some identifying number, symbol, or other identifying particular assigned to the individual. In the Privacy Act of 1974, an individual is defined to encompass U.S. citizens and lawful permanent residents. Additionally, the Judicial Redress Act (JRA) provides a statutory right to covered persons to make requests for access and amendment to covered records, as defined by the JRA, along with judicial review for denials of such requests. In addition, the JRA prohibits disclosures of covered records, except as otherwise permitted by the Privacy Act of 1974.

The Privacy Act of 1974 allows government agencies to exempt certain records from the access and amendment provisions. If an agency claims an exemption, however, it must issue a Notice of Proposed Rulemaking to make clear to the public the reasons why a particular exemption is claimed.

For the reasons stated in the preamble, DHS proposes to amend Chapter I of Title 6, Code of Federal Regulations, as follows:

In accordance with the Privacy Act of 1974, 5 U.S.C. 552a, DHS/CBP proposes to concurrently modify the DHS System of Records titled, “DHS/CBP-009 Electronic System for Travel Authorization (ESTA) System of Records” and issue this notice of proposed rulemaking to exempt portions of the system of records from one or more provision of the Privacy Act because of criminal, civil, and administrative enforcement requirements. This system of records notice (SORN) describes DHS/CBP's collection and maintenance of records that pertain to eligible international travelers who wish to travel to the United States under the Visa Waiver Program (VWP) and have applied for an ESTA travel authorization and persons whose information is provided in response to an ESTA application or Form I-94W questions. DHS/CBP developed ESTA, a web-based system, in 2008 to determine the eligibility of foreign nationals to travel to the United States under the VWP. Using the ESTA website, applicants submit biographic information and answer questions that permit DHS to determine eligibility for travel under the VWP, including whether the applicant poses a law enforcement or security risk.

DHS/CBP vets the ESTA applicant's information against selected DHS and other Federal agency databases to enhance DHS's ability to determine whether the applicant poses a security risk to the United States or is otherwise eligible to travel to and enter the United States under the VWP. The ESTA eligibility determination is made prior to an alien arriving for inspection in the United States. All ESTA vetting results and derogatory information are stored in the Automated Targeting System (ATS), and covered by the ATS SORN, DHS/CBP-006 Automated Targeting System, 77 FR 30297 (May 22, 2012). Further, as explained in the concurrent notice of the updated ESTA SORN, DHS/CBP is expanding the categories of individuals to clarify the use of ESTA at all ports of entry. In addition, DHS/CBP has modified the ESTA SORN to clarify and expand several previously issued routine uses. Thus, to account for the expanded categories of individuals, record source categories and routine uses described in the concurrently issued SORN, and to clarify that this system contains records or information recompiled from or created from information contained in other systems of records that are exempt from certain provision of the Privacy Act, DHS/CBP is reissuing a Notice of Proposed Rulemaking (NPRM) to expand the applicability of the previously issued exemptions from the Privacy Act.

Additionally, this new NPRM makes clear that this system could cover law enforcement and other derogatory records or information recompiled from or created from information contained in other systems of records that are exempt from certain provisions of the Privacy Act. These records are exempt from 5 U.S.C. 552a(c)(3) and (4); (d)(1), (2), (3), and (4); (e)(1), (2), (3), (4)(G) through (I), (5), and (8); (f); and (g) of the Privacy Act of 1974, as amended, pursuant 5 U.S.C. 552a(j)(2). Additionally, the Secretary of Homeland Security has exempted this system from the following provisions of the Privacy Act, pursuant to 5 U.S.C. 552a(k)(1) and (k)(2): 5 U.S.C. 552a(c)(3); (d)(1), (d)(2), (d)(3), and (d)(4); (e)(1), (e)(4)(G), (e)(4)(H), (e)(4)(I); and (f). Such exempt records or information may be law enforcement or national security investigation records, law enforcement activity and encounter records, or terrorist screening records. DHS needs these exemptions in order to protect information relating to law enforcement investigations from disclosure to subjects of investigations and others who could interfere with investigatory and law enforcement activities. Specifically, the exemptions are required to: Preclude subjects of investigations from frustrating the investigative process; avoid disclosure of investigative techniques; protect the identities and physical safety of confidential informants and of law enforcement personnel; ensure DHS's and other federal agencies' ability to obtain information from third parties and other sources; protect the privacy of third parties; and safeguard sensitive information.

Despite the exemptions taken on this system of records, DHS/CBP is not taking any exemption from subsection (d) with respect to information maintained in the system as it relates to data submitted by or on behalf of a person who travels to visit the United States and crosses the border, nor shall an exemption be asserted with respect to the resulting determination (authorized to travel, pending, or not authorized to travel). However, pursuant to 5 U.S.C. 552a(j)(2), DHS/CBP plans to exempt such information in this system from sections (c)(3), (e)(8), and (g) of the Privacy Act of 1974, as amended, as is necessary and appropriate to protect this information. Further, DHS will claim exemption from section (c)(3) of the Privacy Act of 1974, as amended, pursuant to 5 U.S.C. 552a(k)(2) as is necessary and appropriate to protect this information. CBP will not disclose the fact that a law enforcement or intelligence agency has sought particular records because it may affect ongoing law enforcement activities. Nonetheless, DHS will examine each request on a case-by-case basis, and, after conferring with the appropriate component or agency, may waive applicable exemptions in appropriate circumstances and when it would not appear to interfere with or adversely affect the law enforcement or national security investigation.

DHS/CBP previously issued a Final Rule to exempt this system of records from certain provisions of the Privacy Act on August 31, 2009 (74 FR 45069). These exemptions remain in effect until a new Final Rule becomes effective. Once a Final Rule becomes effective, DHS will add this exemption to Appendix C to 6 CFR part 5, DHS Systems of Records Exempt from the Privacy Act.

The Privacy Act embodies fair information practice principles in a statutory framework governing the means by which Federal Government agencies collect, maintain, use, and disseminate individual's records. The Privacy Act applies to information that is maintained in a “system of records.” A “system of records” is a group of any records under the control of an agency from which information is retrieved by the name of the individual or by some identifying number, symbol, or other identifying particular assigned to the individual. In the Privacy Act, an individual is defined to encompass U.S. citizens and lawful permanent residents. Additionally, and similarly, the Judicial Redress Act (JRA) provides a statutory right to covered persons to make requests for access and amendment to covered records, as defined by the JRA, along with judicial review for denials of such requests. In addition, the JRA prohibits disclosures of covered records, except as otherwise permitted by the Privacy Act.

The Privacy Act allows government agencies to exempt certain records from the access and amendment provisions. If an agency claims an exemption, however, it must issue a Notice of Proposed Rulemaking to make clear to the public the reasons why a particular exemption is claimed.

For the reasons stated in the preamble, DHS proposes to amend Chapter I of Title 6, Code of Federal Regulations, as follows:

Comments Invited

We invite you to send any written relevant data, views, or arguments about this proposal. Send your comments to an address listed under the ADDRESSES section. Include “Docket No. FAA-2019-0486; Product Identifier 2019-NM-061-AD” at the beginning of your comments. We specifically invite comments on the overall regulatory, economic, environmental, and energy aspects of this NPRM. We will consider all comments received by the closing date and may amend this NPRM based on those comments.

We will post all comments we receive, without change, to http://www.regulations.gov, including any personal information you provide. We will also post a report summarizing each substantive verbal contact we receive about this NPRM.

The EASA, which is the Technical Agent for the Member States of the European Union, has issued EASA AD 2019-0069, dated March 28, 2019 (“EASA AD 2019-0069”) (also referred to as the Mandatory Continuing Airworthiness Information, or “the MCAI”), to correct an unsafe condition for certain Airbus SAS Model A318-112, -121, and -122; A319-111, -112, -115, -131, -132, and -133; A320-214, -216, -232, -233, -251N, and -271N; and A321-211, -212, -213, -231, -232, -251N, -253N, -271N, and -272N airplanes. The MCAI states:

EASA AD 2019-0069 describes procedures for modification of the OHSC and POHSC attachments. EASA AD 2019-0069 also describes an inspection for discrepancies (additional work) and corrective actions. The inspection includes checks of the dimensions of the threaded pins against tolerances and checks for damage. Corrective actions include replacing threaded pins and nuts and repairing damage. This material 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 our bilateral agreement with the State of Design Authority, we have been notified of the unsafe condition described in the MCAI referenced above. We are proposing this AD because we evaluated all pertinent information and determined an unsafe condition exists and is likely to exist or develop on other products of the same type design.

This proposed AD would require accomplishing the actions specified in EASA AD 2019-0069 described previously, as incorporated by reference, except for any differences identified as exceptions in the regulatory text of this AD.

In the FAA's ongoing efforts to improve the efficiency of the AD process, the FAA worked with Airbus and EASA to develop a process to use certain EASA ADs as the primary source of information for compliance with requirements for corresponding FAA ADs. As a result, EASA AD 2019-0069 will be incorporated by reference in the FAA final rule. This proposed AD would, therefore, require compliance with the provisions specified in EASA AD 2019-0069, through that incorporation, except for any differences identified as exceptions in the regulatory text of this proposed AD. Service information specified in EASA AD 2019-0069 that is required for compliance with EASA AD 2019-0069 will be available on the internet at http://www.regulations.gov by searching for and locating Docket No. FAA-2019-0486 after the FAA final rule is published.

We estimate that this proposed AD affects 1,464 airplanes of U.S. registry. We estimate the following costs to comply with this proposed AD:

We estimate the following costs to do any necessary on-condition actions that would be required based on the results of any required or optional actions. We have no way of determining the number of aircraft that might need these on-condition actions:

According to the manufacturer, some or all of the costs of this proposed AD may be covered under warranty, thereby reducing the cost impact on affected individuals. We do not control warranty coverage for affected individuals. As a result, we have included all known costs in our cost estimate.

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.

We are 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.

This proposed AD is issued in accordance with authority delegated by the Executive Director, Aircraft Certification Service, as authorized by FAA Order 8000.51C. In accordance with that order, issuance of ADs is normally a function of the Compliance and Airworthiness Division, but during this transition period, the Executive Director has delegated the authority to issue ADs applicable to transport category airplanes and associated appliances to the Director of the System Oversight Division.

We 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. Is not a “significant rule” under the DOT Regulatory Policies and Procedures (44 FR 11034, February 26, 1979);

3. Will not affect intrastate aviation in Alaska; and

4. Will 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:

1. Pursuant to section 215(d)(2) of the Federal Power Act (FPA), the Commission proposes to approve Reliability Standard TPL-001-5 (Transmission System Planning Performance Requirements). 1 The North American Electric Reliability Corporation (NERC), the Commission-certified Electric Reliability Organization (ERO), submitted proposed Reliability Standard TPL-001-5 for Commission approval to address: reliability issues concerning the study of single points of failure of protection systems discussed in Order No. 754; and directives from Order No. 786 regarding planned maintenance outages and stability analysis for spare equipment strategy. 2

2. Proposed Reliability Standard TPL-001-5 is one of two transmission planning Reliability Standards containing requirements for planning authorities and transmission planners to develop studies of their portions of the bulk electric system. Proposed Reliability Standard TPL-001-5 establishes transmission system planning performance requirements within the planning horizon to promote a bulk electric system that will operate reliably over a broad spectrum of system conditions and following a wide range of probable contingencies. NERC states that the revisions in the proposed Reliability Standard are intended to enhance requirements for the study of protection system single points of failure. 3

3. Proposed Reliability Standard TPL-001-5 requires each planning authority and transmission planner to perform an annual planning assessment of its portion of the bulk electric system considering a number of system conditions and contingencies. The proposed Reliability Standard employs a risk-based approach to the study of contingencies and the types of corrective action that are required if the entity's system cannot meet the specified performance requirements. 4 For scenarios considered to be more commonplace ( i.e., planning events), the planning entity must develop a corrective action plan if it determines through studies that its system would experience performance issues. For the scenarios considered to be less commonplace, but which could result in potentially severe impacts such as cascading ( i.e., extreme events), the planning entity must conduct a comprehensive analysis to understand both the potential impacts on its system and the types of actions that could reduce or mitigate those impacts. 5

4. Proposed Reliability Standard TPL-001-5 contains revisions to both the planning event (Category P5) and extreme events (Stability 2.a-h)—identified in Table 1 (Steady State and Stability Performance Planning Events and Steady State and Stability Performance Extreme Events) and the associated footnote 13—to provide for more comprehensive study of the potential impacts of protection system single points of failure. 6 Planning entities would be required to take action, consistent with currently-effective Reliability Standard TPL-001-4 requirements, to address system performance issues identified as a result of these studies. Additionally, the proposed Reliability Standard addresses the two Commission directives in Order No. 786. Accordingly, pursuant to section 215(d)(2) of the FPA, the Commission proposes to approve proposed Reliability Standard TPL-001-5 because it is responsive to the Commission's directives and improves upon the currently-effective Reliability Standard by enhancing requirements for the study of protection system single points of failure.

5. Non-redundant protection systems can also misoperate when faced with a three-phase fault. Because three-phase faults are more serious than single-phase-to-ground faults, the consequences can be more severe, including cascading. However, rather than require a corrective action plan to address such events, proposed Reliability Standard TPL-001-5 only requires an evaluation of possible actions designed to reduce the likelihood or mitigate their consequences and adverse impacts. 7 NERC has not adequately justified categorizing protection system single points of failure in combination with a three-phase fault as an “extreme event” that only requires study, but not a corrective action plan, when there is the potential for cascading. We are not persuaded that such events do not necessitate corrective action plans because of their alleged rarity, particularly because their potential impacts may result in cascading. Thus, pursuant to section 215(d)(5) of the FPA, we also propose to direct that NERC develop modifications to the Reliability Standards to require corrective action plans for protection system single points of failure in combination with three-phase faults if planning studies indicate potential cascading. 8

6. Section 215 of the FPA requires a Commission-certified ERO to develop mandatory and enforceable Reliability Standards, subject to Commission review and approval. Reliability Standards may be enforced by the ERO, subject to Commission oversight, or by the Commission independently. 9 Pursuant to section 215 of the FPA, the Commission established a process to select and certify an ERO, 10 and subsequently certified NERC. 11

7. In Order No. 754, which approved an interpretation of Reliability Standard TPL-002-0, Requirement R1.3.10, the Commission determined that “there may be a system protection issue that merits further exploration by technical experts” and that there is “an issue concerning the study of the non‐operation of non‐redundant primary protection systems; e.g., the study of a single point of failure on protection systems.”  12 To address this concern, the Commission directed “Commission staff to meet with NERC and its appropriate subject matter experts to explore the reliability concern, including where it can best be addressed, and identify any additional actions necessary to address the matter.”  13 The Commission also directed NERC “to make an informational filing . . . explaining whether there is a further system protection issue that needs to be addressed and, if so, what forum and process should be used to address that issue and what priority it should be accorded relative to other reliability initiatives planned by NERC.”  14

8. In October 2011, Commission staff hosted a technical conference on single points of failure, which resulted in four consensus points and the following problem statement: “The group perceives a reliability concern regarding the comprehensive assessment of potential protection system failures by registered entities. The group agrees on the need to study if a [reliability] gap exists regarding the study and resolution of a single point of failure on protection systems.”  15 One outcome of the 2011 technical conference, as described in the 2012 Informational Filing, was that NERC would issue a data request to aid in assessing whether single points of failure in protection systems pose a reliability concern. To that end, the NERC Board of Trustees subsequently approved a request for data under the NERC Rules of Procedure. 16 Over the next two years, NERC collected data from transmission planners. Using the collected data, two subcommittees of the NERC Planning Committee, the System Protection and Control Subcommittee (SPCS) and the System Analysis and Modeling Subcommittee (SAMS), conducted an assessment of protection system single points of failure. The study examined in detail the protection systems related to nearly 4,000 buses. The findings were presented in a September 2015 report that concluded that single points of failure on protection systems posed a reliability risk that warranted further action. 17 The SPCS/SAMS Report recommended, after considering a variety of alternatives, that NERC modify Reliability Standard TPL-001-4 to best align with the Order No. 754 directives and maximize reliability of protection system performance. In particular, the SPCS/SAMS Report recommended that three-phase faults involving protection system failures be assessed as an extreme event in Reliability Standard TPL-001-4, as follows:

9. In Order No. 786, the Commission approved the currently-effective version of the transmission system planning standard, Reliability Standard TPL-001-4. In that Order, the Commission also issued several directives to NERC, including two relating to future standard modifications that are addressed in proposed Reliability Standard TPL-001-5. First, the Commission expressed concern that the six-month outage duration threshold in Reliability Standard TPL-001-4, Requirement R1 could exclude planned maintenance outages of significant facilities from future planning assessments. 19 The Commission determined that planned maintenance outages of less than six months in duration may result in relevant impacts during one or both of the seasonal off-peak periods, and that prudent transmission planning should consider maintenance outages at those load levels when planned outages are performed to allow for a single element to be taken out of service for maintenance without compromising the ability of the system to meet demand without loss of load. The Commission further determined that a properly planned transmission system should ensure the known, planned removal of facilities ( i.e., generation, transmission or protection system facilities) for maintenance purposes without the loss of nonconsequential load or detrimental impacts to system reliability such as cascading, voltage instability or uncontrolled islanding. The Commission directed NERC to modify the Reliability Standards to address this concern.

10. Second, while stating that NERC had met the Commission's Order No. 693 directive to include a spare equipment strategy for steady state analysis in Reliability Standard TPL-001-4, the Commission determined that a spare equipment strategy for stability analysis was not addressed in the standard. The Commission stated that a similar spare equipment strategy for stability analysis should exist that requires studies to be performed for P0, P1, and P2 categories with the conditions that the system is expected to experience during the possible unavailability of the long lead time equipment. Rather than direct a change at that time, however, the Commission directed NERC to consider the issue during the next review cycle of Reliability Standard TPL-001-4. 20

11. On December 7, 2018, NERC submitted proposed Reliability Standard TPL-001-5 for Commission approval. 21 NERC maintains that the proposed Reliability Standard addresses potential system contingencies including the protection system single point of failure issue and Order No. 786 directives. With regard to protection system single points of failure, NERC indicates that Table 1 of the proposed Reliability Standard describes system performance requirements for a range of potential system contingencies required to be evaluated by the planner. Table 1 includes three parts: (1) Steady State & Stability Performance Planning Events, (2) Steady State & Stability Performance Extreme Events, and (3) Steady State & Stability Performance Footnotes. Table 1 describes system performance requirements for a range of potential system contingencies required to be evaluated by the planner. The table categorizes the events as either “planning events” or “extreme events.” The table lists seven contingency planning events (P1 through P7) that require steady-state and stability analysis as well as five extreme event contingencies: three for steady-state and two for stability. NERC asserts that proposed Reliability Standard TPL-001-5 also includes certain modifications to better ensure that planning entities are performing a more complete analysis of potential protection system single points of failure on their systems and taking appropriate action to address these concerns. NERC explains that the proposed Reliability Standard contains revisions to both the Table 1 planning event (Category P5) and extreme events (Stability 2.a-h) and the associated footnote 13 to provide for more comprehensive study of the potential impacts of protection system single points of failure.

12. NERC states that if the study of a protection system single point of failure for a single-line-to-ground fault ( i.e., Category P5 event) results in cascading, a corrective action plan is required. 22 NERC considers this a relatively commonplace scenario, and it explains that an entity would be required to develop a corrective action plan if it determines that its system would be unable to meet the performance requirements of Table 1 for the Category P5 event.

13. In contrast, NERC proposes revisions to Table 1 to include the study of a protection system single point of failure in combination with a three-phase fault as an extreme event, which does not require a corrective action plan. NERC avers in its petition that the three-phase fault scenario is much rarer (compared to the single-line-to-ground fault). According to NERC, like the other extreme events in the proposed Reliability Standard, this scenario, while rare, could result in more significant impacts to an entity's system. 23 Under this approach, NERC asserts that, if an entity determines that its system will experience cascading as a result of a three-phase fault scenario, an evaluation of possible actions designed to reduce the likelihood or mitigate the consequences of the event will be conducted but a corrective action plan is not required.

14. Based on a historical analysis of NERC data on protection system misoperations, NERC asserts that the expected likelihood of a three-phase fault event occurring and resulting in the most severe impacts would be small. NERC states that it reviewed over 12,000 protection system misoperations in its Misoperation Information Data Analysis System (MIDAS) database reported since 2011, of which only 28 involved three-phase faults. Of those, NERC states that 10 involved breakers that failed to operate, and the remaining 18 involved breakers that were slow to operate. 24 NERC explains that a failure to operate potentially indicates instances of a protection system single point of failure. While the potential for severe impacts from such events remains, NERC states that none of the 10 failure to trip scenarios reported since 2011 resulted in events that reached the threshold for reporting under Reliability Standard EOP-004 (Event Reporting). 25 With regard to the Order No. 786 directives, NERC states that proposed Reliability Standard TPL-001-5 provides for a more complete consideration of factors for selecting which known outages will be included in near-term transmission planning horizon studies.

15. Pursuant to section 215(d)(2) of the FPA, the Commission proposes to approve proposed Reliability Standard TPL-001-5 as just, reasonable, not unduly discriminatory or preferential, and in the public interest. The proposed Reliability Standard will improve Bulk-Power System reliability by requiring enhanced transmission system planning with regard to the study of protection system single points of failure in combination with a single-line-to-ground fault, as discussed in Order No. 754. The Commission also proposes to approve the associated violation risk factors, violation severity levels and implementation plan.

16. With respect to the Order No. 786 directives, regarding planned maintenance outages and stability analysis for spare equipment strategy, the Commission proposes to determine that the revisions satisfy the directives. First, proposed Reliability Standard TPL-001-5 provides for a more complete consideration of factors for selecting which known outages will be included in near-term transmission planning horizon studies. In particular, the modifications reflected in proposed Reliability Standard TPL-001-5 address the Commission's concern that the exclusion of known outages of less than six months in currently-effective Reliability Standard TPL-001-4 could result in outages of significant facilities not being studied. Second, the proposed Reliability Standard modifies requirements for stability analysis to require an entity to assess the impact of the possible unavailability of long lead time equipment, consistent with the entity's spare equipment strategy.

17. In addition, the Commission, pursuant to section 215(d)(5) of the FPA, proposes to direct that NERC develop modifications to the Reliability Standards because certain protection system single points of failure may not be fully addressed even with the implementation of proposed Reliability Standard TPL-001-5. As discussed below, the Commission is concerned that the proposed Reliability Standard does not require responsible entities to develop corrective action plans to address protection system single points of failure in combination with a three-phase fault if planning studies indicate potential cascading. Accordingly, the Commission proposes to direct that NERC develop modifications to the Reliability Standards to require corrective action plans for protection system single points of failure in combination with three-phase faults if planning studies indicate potential cascading.

18. While protection system single points of failure in combination with a three-phase fault must be studied under the proposed Reliability Standard to determine the impact of failure, the Commission believes that the record may not support NERC's contention that corrective action plans should not be required even when studies of the event indicate the potential for cascading. Specifically, NERC asserts that protection system single points of failure in combination with a three-phase fault is an extreme event that does not require a corrective action plan, even in cases where the study results indicate potential cascading. NERC claims that protection system single points of failure in combination with a three-phase fault are rare and, “[l]ike all of the `extreme events' scenarios in this [TPL-001 Standard risk-based] framework, the impacts of a protection system single point of failure in combination with a three phase fault could be severe in some cases, but are very unlikely.”  26 Based on the present record, it is unclear whether such contingencies are as rare as NERC maintains.

19. A 2009 NERC Industry Advisory reported three system disturbances that occurred during a five-year period that were initiated by a protection system single point of failure in combination with a single-line-to-ground fault. 27 According to the Industry Advisory and supporting documentation, all three events evolved into either a multi-phase fault or a three-phase fault with cascading. 28 Moreover, in the 2012 Informational Filing, NERC reported that it is not uncommon for a single-line-to-ground fault to evolve into a multi-phase fault, and NERC stated that studies solely on single-line-to-ground faults may understate the reliability risk of single points of failure of protection systems. 29 As mentioned below, the NERC standard drafting team pointed to the likelihood of a single-line-to-ground fault evolving into a multi-phase fault when responding to stakeholder comments that a single-line-to-ground fault was a rare event.

20. NERC indicates that it reviewed over 12,000 protection system misoperations and determined that only 28 involved three-phase faults from 2011 through 2018. However that averages to approximately one three-phase fault event every three months. NERC, moreover, indicates that ten of those 28 misoperations involved breakers that failed to operate that could reasonably be assumed to be representative of protection system single points of failure, which averages to about one event every 8 months. 30 Although we recognize that three-phase faults constitute a relatively small subset of all protection system operations, under the following measure of one protection system single point of failure every 8 months, the occurrence of three-phase faults with misoperations could reasonably be viewed as regular occurrences. Thus, based on the information currently before us, we are not persuaded by NERC's analysis that three-phase faults are rare events that should be categorized with other extreme events in proposed Reliability Standard TPL-001-5 and should be studied but not have corrective action plans.

21. The record of development for proposed Reliability Standard TPL-001-5 also supports our concerns with the absence of a corrective action plan requirement. The development record evidences a standard drafting team repeatedly expressing concerns regarding the reliability risks of three-phase faults involving protection system single points of failure. Indeed, the standard drafting team evaluated and initially adopted more robust options to mitigate protection system single points of failure in combination with three-phase faults if studies indicated cascading, including requiring a corrective action plan or some variation of a corrective action plan.

22. In the first draft of proposed Reliability Standard TPL-001-5, the standard drafting team included a draft requirement (Requirement R4.6) that would have addressed protection system single points of failure in combination with a three-phase fault, including a specific requirement for the development of a corrective action plan. 31 After reviewing the unofficial comments on the proposal, the standard drafting team provided the following response:

While the standard drafting team agreed to remove the corrective action plan provision in response to the stakeholder comments, the following language from the standard drafting team's response stressed the reliability concerns posed by protection system single points of failure in combination with a three-phase fault, and suggested that the related risks are “underappreciated”:

The standard drafting team's above response acknowledged the importance of a corrective action plan and noted conclusive findings of the SPCS/SAMS report that the reliability risk associated with protection system single points of failure warrants further action. The standard drafting team, nonetheless, indicated that “lacking a FERC directive” it would remove the corrective action plan provision.

23. The standard drafting team then developed a second draft of proposed Reliability Standard TPL-001-5. The second draft did not require a corrective action plan by name. Rather, the standard drafting team developed and submitted for ballot a new provision requiring that, when system studies show that a protection system single points of failure in combination with a three-phase fault results in system cascading, the entity must take specific actions, namely “listing system deficiencies, the associated actions needed to prevent the system from Cascading and the associated timetable for implementation.”  34 Further, the proposed provision would require follow-up in annual planning assessments for “continued validity and implementation status.”

24. The standard drafting team developed a technical rationale document that accompanied the second draft of the proposed Reliability Standard. 35 In the draft technical rationale document, the standard drafting team explained the technical basis for draft Requirement R4.2.2:

Again, the standard drafting team expressed its concerns regarding the reliability risks associated with a protection system single point of failure in combination with a three-phase fault. The standard drafting team addressed the stakeholder comments regarding the perceived low risk of such conditions by pointing out that “[w]hile less probable than single-phase-to-ground faults, three-phase faults typically initiate as single-phase-to-ground and often evolve into three-phase faults, leading to Delayed Fault Clearing scenarios more severe than the Table 1 P5 event.”  37 Further, the standard drafting team noted the inadequacy of simply conducting an “evaluation” as set forth in the relevant provision of the current Reliability Standard. 38

25. The standard drafting team developed a third draft of the proposed Reliability Standard. This third draft removed the more robust provision (proposed Requirement R4.2.2) in favor of the currently proposed language in Requirement 4.2, which requires that “[i]f the analysis concludes there is Cascading caused by the occurrence of extreme events, an evaluation of possible actions designed to reduce the likelihood or mitigate the consequences of the event(s) shall be conducted.” Significantly, however, in the draft technical rationale document associated with the second draft of the proposed Reliability Standard, the standard drafting team stated that merely requiring that “an evaluation of possible mitigating actions be conducted if analysis concludes there is cascading caused by the occurrence of this extreme event, is inadequate to address the risk of Protection System component SPF to the reliability of the BES.”   39

26. The standard development history discussed above therefore supports our concern that there is a potential reliability gap with respect to the proposed Reliability Standard's treatment of protection system single points of failure in combination with a three-phase fault. 40

27. The Commission, pursuant to section 215(d)(5) of the FPA, proposes to direct that NERC develop modifications to require corrective action plans for protection system single points of failure in combination with three-phase faults if planning studies indicate potential cascading. While we do not propose to prescribe how NERC should respond to the proposed directive, we discuss below certain possible alternatives.

28. NERC could address the proposed directive by modifying the current Category P5 proposal for single-line-to-ground faults (that already includes a P5 corrective action plan) to include language, such as, a footnote stating that the simulation of Delayed Fault Clearing must consider that a single-line-to-ground faulted condition may evolve to all three-phases before protection system action operates to clear the fault. Alternatively, NERC could modify the Reliability Standard to have a new Category planning event that would require a corrective action plan for the study of a protection system single point of failure in combination with a three-phase fault if the study indicates cascading. 41

29. In addition, we recognize that during the standard drafting process for proposed Reliability Standard TPL-001-5 some stakeholders were concerned with incurring significant costs to mitigate protection system single points of failure in combination with a three-phase fault, while others stated that such actions do not usually incur significant costs. 42 While we are aware of the potential for increased cost under this proposal, we understand that there are likely cost-effective actions that could be taken to mitigate a protection system single point of failure in combination with a three-phase fault. For example, a corrective action plan to eliminate a single point of failure of protection system could add a redundant lockout relay in the control circuitry of a protection system, which would eliminate occurrence of those events reported in the 2009 NERC Industry Advisory. 43 As another option, an entity could add control center monitoring and reporting functions to a DC battery bank or to a communication system of a communication-aided protection scheme so that system operators are aware of their failure. 44 To better understand the potential for increased costs and other implementation issues, the Commission seeks comment on how many corrective action plans are expected for protection system single points of failure in combination with a three-phase fault if study results indicate cascading.

30. To ensure no delay and to align the effective date of the proposed directive with the current implementation plan of proposed Reliability Standard TPL-001-5, the Commission proposes to direct that NERC address the directive within one year of the effective date of a final rule. 45 The Commission seeks comments on its proposals.

31. The FERC-725N information collection requirements contained in this notice of proposed rulemaking are subject to review by the Office of Management and Budget (OMB) under section 3507(d) of the Paperwork Reduction Act of 1995. 46 OMB's regulations require approval of certain information collection requirements imposed by agency rules. 47 Upon approval of a collection of information, OMB will assign an OMB control number and expiration date. Respondents subject to the filing requirements of this rule will not be penalized for failing to respond to these collections of information unless the collections of information display a valid OMB control number. The Commission solicits comments on the Commission's need for this information, whether the information will have practical utility, the accuracy of the burden estimates, ways to enhance the quality, utility, and clarity of the information to be collected or retained, and any suggested methods for minimizing respondents' burden, including the use of automated information techniques.

32. The Commission bases its paperwork burden estimates on the changes in paperwork burden presented by proposed Reliability Standard TPL-001-5. The NERC Compliance Registry, as of May 10, 2019, identifies approximately 144 planning coordinators and transmission planners in the United States that are subject to mandatory compliance with this proposed Regulatory Standard. Of the 144 entities 62 of the entities are registered as both transmission planners and planning coordinators. The register indicates there are seven entities registered as planning coordinators and 137 entities registered as transmission planners.

33. Burden Estimate:   48 The estimated burden and cost for the requirements contained in this proposed rule follows:

This notice of proposed rulemaking will not significantly change existing burdens on an ongoing basis. The Commission estimates a one-time burden increase for Year 1 only because Year 1 represents a one-time task not repeated in subsequent years.

The one-time burden for FERC-725N information collection can be averaged over three years:

• 7,416 hours ÷ 3 = 2,472 (rounded) hours/year over three years.

34. Title: FERC-725N, Mandatory Reliability Standards: Transmission Planning (TPL) Reliability Standards.

Action: Proposed revision to FERC-725N information collection.

OMB Control No.: 1902-0264.

Respondents: Businesses or other for-profit institutions; not-for-profit institutions.

Frequency of Responses: One Time.

Necessity of the Information: This notice of proposed rulemaking proposes to approve the requested modifications to a Reliability Standard pertaining to transmission planning. As discussed above, the Commission proposes to approve proposed Reliability Standard TPL-001-5 pursuant to section 215(d)(2) of the FPA because it improves upon the currently-effective Reliability Standard TPL-001-4.

Internal Review: The Commission has reviewed proposed Reliability Standard TPL-001-5 and made a determination that its action is necessary to implement section 215 of the FPA. The Commission has assured itself, by means of its internal review, that there is specific, objective support for the burden estimates associated with the information requirements.

35. Interested persons may obtain information on the reporting requirements by contacting the following: Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director, email: DataClearance@ferc.gov, phone: (202) 502-8663, fax: (202) 273-0873].

36. For submitting comments concerning the collection(s) of information and the associated burden estimate(s), please send your comments to the Commission, and to the Office of Management and Budget, Office of Information and Regulatory Affairs, 725 17th Street NW, Washington, DC 20503, [Attention: Desk Officer for the Federal Energy Regulatory Commission, phone: (202) 395-0710, fax: (202) 395-7285]. For security reasons, comments to OMB should be submitted by email to: oira_submission@omb.eop.gov. Comments submitted to OMB should include Docket Number RM19-10-000 and FERC-725N (OMB Control No. 1902-0264).

37. The Commission is required to prepare an Environmental Assessment or an Environmental Impact Statement for any action that may have a significant adverse effect on the human environment. 52 The Commission has categorically excluded certain actions from this requirement as not having a significant effect on the human environment. Included in the exclusion are rules that are clarifying, corrective, or procedural or that do not substantially change the effect of the regulations being amended. 53 The actions proposed herein fall within this categorical exclusion in the Commission's regulations.

38. The Regulatory Flexibility Act of 1980 (RFA)  54 generally requires a description and analysis of proposed rules that will have significant economic impact on a substantial number of small entities. 55 The Small Business Administration's (SBA) Office of Size Standards develops the numerical definition of a small business. 56 The SBA revised its size standard for electric utilities (effective January 22, 2014) to a standard based on the number of employees, including affiliates (from the prior standard based on megawatt hour sales). 57

39. Proposed Reliability Standard TPL-001-5 is expected to impose an additional burden on 206 entities  58 (planning coordinators and transmission planners).

40. Of the 206 affected entities discussed above, we estimate that approximately 10 percent of the affected entities are small entities. We estimate that each of the 21 small entities to whom the proposed modifications to proposed Reliability Standard TPL-001-5 apply will incur one-time costs of approximately $1,980 per entity to implement the proposed Reliability Standard. We do not consider the estimated costs for these 21 small entities to be a significant economic impact. Accordingly, we propose to certify that proposed Reliability Standard TPL-001-5 will not have a significant economic impact on a substantial number of small entities.

41. The Commission invites interested persons to submit comments on the matters and issues proposed in this notice to be adopted, including any related matters or alternative proposals that commenters may wish to discuss. Comments are due August 26, 2019. Comments must refer to Docket No. RM19-10-000, and must include the commenter's name, the organization they represent, if applicable, and address.

42. The Commission encourages comments to be filed electronically via the eFiling link on the Commission's website at http://www.ferc.gov. The Commission accepts most standard word processing formats. Documents created electronically using word processing software should be filed in native applications or print-to-PDF format and not in a scanned format. Commenters filing electronically do not need to make a paper filing.

43. Commenters that are not able to file comments electronically must send an original of their comments to: Federal Energy Regulatory Commission, Secretary of the Commission, 888 First Street NE, Washington, DC 20426.

44. All comments will be placed in the Commission's public files and may be viewed, printed, or downloaded remotely as described in the Document Availability section below. Commenters on this proposal are not required to serve copies of their comments on other commenters.

45. In addition to publishing the full text of this document in the Federal Register , the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the internet through the Commission's Home Page ( http://www.ferc.gov ) and in the Commission's Public Reference Room during normal business hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE, Room 2A, Washington, DC 20426.

46. From the Commission's Home Page on the internet, this information is available on eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in eLibrary, type the docket number of this document, excluding the last three digits, in the docket number field.User assistance is available for eLibrary and the Commission's website during normal business hours from the Commission's Online Support at (202) 502-6652 (toll free at 1-866-208-3676) or email at ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-8371, TTY (202) 502-8659. Email the Public Reference Room at public.referenceroom@ferc.gov.

The purpose of this regulatory action is to make miscellaneous technical corrections, clarifications, and improvements to several Pension Benefit Guaranty Corporation (PBGC) regulations. These changes are based on PBGC's ongoing retrospective review of the effectiveness and clarity of its rules, which includes input from stakeholders on PBGC's programs.

Legal authority for this action comes from section 4002(b)(3) of the Employee Retirement Income Security Act of 1974 (ERISA), which authorizes PBGC to issue regulations to carry out the purposes of title IV of ERISA. It also comes from section 4006 of ERISA, which give PBGC the authority to prescribe schedules of premium rates and bases for the application of those rates; section 4010 of ERISA, which gives PBGC authority to prescribe information to be provided and the timing of reports; section 4041 of ERISA (Termination of Single-Employer Plans); and section 4043 of ERISA, which gives PBGC authority to define reportable events and waive reporting.

The major provisions of this proposed rulemaking would amend PBGC's regulations on:

• Reportable Events and Certain Other Notification Requirements, by eliminating possible duplicative reporting of active participant reductions, clarifying when a liquidation event occurs and providing additional examples for active participant reduction, liquidation, and change in controlled group events.

• Annual Financial and Actuarial Information Reporting, by eliminating a requirement to submit individual financial information for each controlled group member, adding a new reporting waiver and clarifying others, and providing guidance on assumptions for valuing benefit liabilities for cash balance plans.

• Termination of Single-Employer Plans, by providing more time to submit a complete PBGC Form 501 in the standard termination process.

• Premium Rates, by expressly stating that a plan does not qualify for the variable rate premium exemption for the year in which it completes a standard termination if it engages in a spinoff in the same year, clarifying the participant count date special rule for transactions ( e.g., mergers and spinoffs), and by modifying the circumstances under which the premium is prorated for a short plan year resulting from a standard termination.

The Pension Benefit Guaranty Corporation (PBGC) administers two insurance programs for private-sector defined benefit pension plans under title IV of the Employee Retirement Income Security Act of 1974 (ERISA)—one for single-employer pension plans, and one for multiemployer pension plans. The amendments proposed in this rulemaking apply primarily to the single-employer program.

This proposed rulemaking comes out of PBGC's ongoing retrospective review program to identify and ameliorate inconsistencies, inaccuracies, and requirements made irrelevant over time. It also responds to suggestions and questions from stakeholders that PBGC receives on an ongoing basis and through public outreach, such as PBGC's July 2017 “Regulatory Planning and Review of Existing Regulations” Request for Information. 1

The proposed technical and clarifying amendments and improvements to PBGC's regulations are discussed below. PBGC invites comment on these proposals.

The proposed rule would amend the general “Definitions” section (29 CFR 4001.2) for terms used in regulations under title IV of ERISA to include the terms “Ultimate parent” and “U.S. entity.” Those terms are currently defined in PBGC's “Reportable Events and Certain Other Notification Requirements” regulation (29 CFR part 4043), “reportable events regulation,” at §§ 4043.2 and 4043.81(c) respectively. Because proposed amendments to PBGC's Annual Financial and Actuarial Information Reporting regulation (29 CFR part 4010), “4010 reporting regulation,” would use those same two terms, it is appropriate to move them to the common definitions section in § 4001.2.

Section 4043 of ERISA requires that PBGC be notified of the occurrence of certain “reportable events” that may signal financial issues with the plan or a contributing employer. The statute provides for both post-event and advance reporting. PBGC's reportable events regulation implements section 4043 of ERISA.

Reportable events include such plan events as missed contributions, insufficient funds, large pay-outs, and such sponsor events as loan defaults and controlled group changes—events that may present a risk to a sponsor's ability to continue a plan. When PBGC has timely information about a reportable event, it can take steps to encourage plan continuation. Without timely information about a reportable event, PBGC typically learns that a plan is in danger only when most opportunities for protecting participants and the pension insurance system have been lost.

On September 11, 2015, PBGC issued a final rule, 2 the “2015 Final Rule,” implementing changes to the reportable events regulation. The rule revised longstanding procedures governing when administrators and sponsors of single-employer defined benefit pension plans are required to report certain events to PBGC. The major changes in the 2015 Final Rule tied reporting waivers more closely to situations where a contributing sponsor is at risk of not being able to continue to maintain a plan ( i.e., risk of default), revisions to definitions and descriptions of several reportable events, and new requirements on electronic filing. The goal of the 2015 Final Rule was to ease reporting requirements where notice to PBGC is unnecessary but to allow for possible earlier PBGC intervention where there is an opportunity to help sponsors maintain a plan or otherwise preserve benefits for participants.

Since publication of the 2015 Final Rule, PBGC has further identified some opportunities to improve the reportable events and notification requirements by filling in gaps where guidance is needed, simplifying or removing language, codifying policies, and providing examples.

Section 4043.9(e) of the reportable events regulation describes the commercial measures waiver that is available for certain events. 3 This waiver is available where a company that is a contributing sponsor of a plan has adequate capacity to meet its obligations as evidenced by satisfying a combination of certain criteria. Among the criteria listed, the commercial measures criterion requires that the company's probability of default on its financial obligations be no more than 4 percent over the next 5 years or 0.4 percent over the next year, as “determined on the basis of widely available financial information on the company's credit quality.”

The preamble to the 2015 Final Rule made clear that the commercial measures criterion was to be met by looking to third party information and not, for example, information that a company itself generates but that might be considered “widely available” because the information is posted on the company's website. 4 However, the regulatory text in the 2015 Final Rule did not explicitly mention third party information. To remove any ambiguity, the proposed rule would amend § 4043.9 to make clear that a plan must use third party financial information to satisfy the criterion for the company financial soundness safe harbor.

Under § 4043.23 of the reportable events regulation, an active participant reduction reportable event generally occurs when, as a result of a single-cause event or through normal attrition of employees (described below), the number of active participants in a plan is reduced below 80 percent of the number at the beginning of the year (one-year lookback) or below 75 percent of the number at the beginning of the prior year (two-year lookback). The regulation distinguishes between reductions caused by single cause events and normal attrition events. If active participants cease to be members of a plan's controlled group due to a single cause event, such as a reorganization or layoff, the plan administrator and contributing sponsor must file a notice with PBGC within 30 days after the threshold is breached, unless a waiver applies. Conversely, if the active participant reduction is caused by the normal comings and goings of employees or other smaller scale reductions ( i.e., normal attrition), notice of the event is extended until the premium filing due date for the plan year following the event year.

Since publication of the 2015 Final Rule, PBGC has received questions from practitioners, including in a comment to its 2017 RFI on Regulatory Planning and Review of Existing Regulations (see the “Background” section of this preamble), about whether a plan administrator or contributing sponsor that files a single-cause event notice must also file an attrition event notice at a later date due to the same active participant reduction. Upon review, PBGC recognizes that § 4043.23 could be interpreted in this manner, though this was not PBGC's intent.

To address this issue, PBGC proposes to amend § 4043.23(a)(2) by altering the current method of counting active participants after the end of the plan year in determining whether an attrition event has occurred by taking into account the number of active participants that had already been the subject of a single-cause event report in the same plan year. Thus, to determine whether an attrition event has occurred, the number of active participants who ceased to be active and were covered by a single-cause event reported in the same year would be included in the year-end count. This proposed new method of counting would prevent duplicative reporting by disregarding the earlier single-cause event if already reported to PBGC.

The proposed rule also would make clear that multiple single-cause events during the plan year must be reported separately. Thus, each time a new single-cause event results in an active participant reduction greater than 20 percent over the number of active participants at the beginning of the plan year, a new Form 10 would be required to be filed. PBGC is making this clarification because PBGC believes that dramatic reductions due to different events in the same year could signal that the plan sponsor's ability to maintain the plan is rapidly deteriorating.

For further explanation, the proposed rule includes examples in the regulatory text of the interplay between single-cause and attrition events, as well as a single-cause event that occurs over a period of time.

The proposed rule would make non-substantive changes to the formula for counting a single-cause event in § 4043.23(a)(1) that PBGC believes is clearer, more aligned to the proposed language in § 4043.23(a)(2) described above, and easier to use.

To further reduce burden, the proposed rule would eliminate the two-year lookback requirement. With a few years' experience under the 2015 Final Rule, PBGC has concluded that the one-year/80 percent test provides sufficient information and undertaking the additional burden of conducting the two-year/75 percent lookback is not necessary. Thus, the language regarding the two-year lookback in § 4043.23(a)(1) and (2) would be removed under the proposed rule. To address the statutory requirement, the proposed rule would waive notice of the two-year lookback provided under section 4043(c)(3) of ERISA.

Other proposed changes to § 4043.23 include amending the current definition of “active participant.” The current definition provides that an active participant means, among other things, a participant who “is receiving compensation for work performed,” but does not address whether a participant becomes inactive if the participant leaves a controlled group member for employment by another member of the same controlled group. The proposed rule would clarify that a participant is active if the participant receives compensation from any member of the plan's controlled group for work performed for any member of the plan's controlled group. The proposal thus would remove any ambiguity in the determination rules if the participant is employed by any member within the same controlled group.

Finally, PBGC proposes to clarify that reporting an active participant reduction under § 4043.23 would be disregarded if the reduction was already reported under section 4062(e) and/or 4063(a) of ERISA. The current regulation provides that a reduction in the number of active participants may be disregarded if the reduction is timely reported to PBGC under section 4063(a) of ERISA but does not specify when the report must be made in relation to a Form 10 Report under § 4043.23 for the disregard provision to be available. PBGC's intent in providing the waiver was to prevent duplicative reporting for the same event where notice had previously been filed. To codify PBGC's intent, the proposed rule would clarify that reporting a reduction in the number of active participants under § 4043.23 may be disregarded if the reduction is reported under section 4062(e) and/or 4063(a) of ERISA before the filing of a notice is due under § 4043.23.

In general, a reportable event occurs under § 4043.26 of the reportable events regulation when a plan fails to make a benefit payment timely or when a plan's liquid assets fall below the level needed for paying benefits for six months. The 2015 Final Rule modified § 4043.26(a)(1)(iii) so that a plan is not treated as having a “current inability” to pay benefits when due if, among other things, the failure to pay is caused solely by “any other administrative delay, including the need to verify a person's eligibility for benefits, to the extent that the delay is for less than the shorter of two months or two full benefit payment periods.” In modifying the regulation, the 2015 Final Rule inadvertently imposed a time limit for verification of a person's eligibility for benefits. PBGC recognizes that employers may need more than the specified time limit to verify a person's eligibility for benefits and that such a circumstance is not indicative of a possible need for plan termination.

To resolve this issue, PBGC proposes to amend § 4043.26 to clarify that an inability to pay benefits when due caused by the need to verify eligibility is not subject to the time limit imposed for other administrative delays.

Under § 4043.29 of the reportable events regulation, a reportable event occurs for a plan when there is a transaction that results, or will result, in one or more persons' ceasing to be members of the plan's controlled group. PBGC has continued to receive inquiries about when a reportable event is triggered under § 4043.29. For instance, although the heading of § 4043.29 includes “a change in contributing sponsor,” the regulatory text does not. A 1996 rulemaking added a new reportable event for transactions that result in any person ceasing to be a member of the plan's controlled group, amending the then existing regulation that required reporting only if there was a change in the contributing sponsor. 5 The 1996 rule, a product of negotiated rulemaking, left out a specific reference to contributing sponsors, though PBGC did not intend that changes in contributing sponsors would no longer be reportable.

Thus, PBGC proposes to modify the event definition to make clear that reporting would be required when a transaction results in one or more persons ceasing to be either a contributing sponsor of a plan, or a member of the plan's controlled group (other than by merger involving members of the same controlled group). The current exception to the reporting requirement for transactions that will solely result in a reorganization involving a mere change in identity, form, or place or organization (however effected), would apply under the proposed rule to only “change in controlled group” transactions. A reorganization such as this that involves a controlled group member that is not a contributing sponsor does not pose a significant risk to the pension insurance system. However, PBGC does need to know about any change to a contributing sponsor, since it is a contributing sponsor that primarily supports the pension plan.

The proposed rule also would revise the first example in the existing regulation to provide greater clarity on the timing of, and responsibility for, filing a report. In addition, the proposed rule would add two new examples—one regarding dissolution of a controlled group member and one describing a merger of controlled group members. These examples illustrate some common situations implicated by the requirements in § 4043.29. 6

Section 4043.30(a)(1) of the reportable events regulation states that a reportable event occurs for a plan when a member of the plan's controlled group “is involved in any transaction to implement its complete liquidation (including liquidation into another controlled group member).” In discussing this provision with practitioners over the years, it has become clear that this event description could benefit from greater clarity and precision, particularly with respect to what “involved in any transaction to implement” a liquidation means and when the event was triggered.

One liquidation scenario that commonly causes confusion involves a company that ceases operations and sells substantially all of its assets over a period of time. The company continues to sponsor a plan but with no business income, benefits stop accruing and no further plan contributions from the company are made. The result is a “wasting trust” where assets are depleted over time to make pension payments but no new contributions are made for future payment obligations. PBGC observes that because the plan has not been terminated, the company does not realize a reportable event has occurred. Although a cessation of business operations is not in and of itself a liquidation, because the cessation is tied to a sale of substantially all of the business' assets, with the intent to settle remaining obligations, PBGC views a cessation in this context as part of the liquidation process.

When a company fails to notify PBGC that the company ceased business operations and began a liquidation, PBGC encounters greater difficulties in effectively intervening to protect plan assets and participant benefits, thereby increasing the potential for decreased employer funding for the plan and greater potential strain on the pension insurance system. In some cases, PBGC did not become aware of the process of liquidation until years later, when the best opportunity for protecting plan assets and participant benefits had passed. Liquidations of the type that concern PBGC may take a myriad of forms and be implemented over long periods of time.

To alleviate confusion and improve precision, PBGC proposes to clarify the definition of liquidation to state that a liquidation event occurs when a member of the plan's controlled group “resolves to cease all revenue-generating business operations, sell substantially all its assets, or otherwise effect or implement its complete liquidation (including liquidation into another controlled group member) by decision of the member's board of directors (or equivalent body such as the managing partners or owners) or other actor with the power to authorize such cessation of operations or a liquidation.” Hence, a cessation of operations, such as the example above, would trigger a reportable event under § 4043.30. The proposed rule includes the word “revenue-generating” to qualify a cessation of business operations in acknowledgement of the fact that various administrative activities may continue during the winding down of a business. The use of the word “revenue-generating” is therefore designed to capture the fact that a company is not earning revenue to enable it to support the pension plan.

The decision to liquidate can have serious implications for participants and the pension insurance system. Given that PBGC's success in such cases is often directly correlated with reporting an event when there is still time to preserve plan assets, PBGC believes triggering a reporting obligation to the time a decision by the person(s) or body (such as a board of directors) that has the authority to determine that a company will liquidate will be most protective of participants and the pension insurance system. Since a liquidation may or may not involve a formal plan, a written agreement to sell assets to a single buyer, or a series of sales over time to maximize proceeds, the language in the proposed rule represents as close as possible to a uniform trigger for reporting of liquidation events. PBGC believes that in the vast majority of cases, the decision to liquidate must go through a formal approval or authorization process. Even in cases where the plan sponsor is a company owned by a single person and board formalities do not exist, a moment occurs when that owner has made the decision to move forward with a liquidation. This decision is the common point of departure for liquidations to move forward. For reference and further clarity, PBGC has included in the proposed rule three additional examples, regarding a liquidation within a controlled group, occurring by cessation of operations, and through an asset sale.

Companies that liquidate as a result of insolvency are required to report both events to PBGC under §  4043.30 and §  4043.35 of the reportable events regulation. However, given the similarities between the two events, PBGC believes that reporting to PBGC under either section (instead of both) would be sufficient notification. Thus, PBGC is proposing an additional waiver that would provide relief from the possibility of duplicative reporting under a §  4043.30 liquidation or a §  4043.35 insolvency. The proposed rule would provide parallel waivers in both §  4043.30 and §  4043.35 to clarify that notice would be waived if notice has already been provided to PBGC for the same event under the former section.

PBGC does not intend to compel public company sponsors to disclose liquidations on a Form 10 before notifying the public. Thus, the proposed rule includes an extension under § 4043.30(c) to file the post-event reportable events notice until the earlier of the timely filing of an SEC Form 8-K disclosing the event or the issuance of a press release discussing it.

PBGC specifically requests comment on whether PBGC should make this extension available for foreign private issuers and if so, how. For example, should the regulation allow an extension to file a reportable events notice involving a foreign private issuer that is a plan sponsor until the earlier of the timely filing of a Form 6-K disclosing the event or the issuance of a press release discussing it, even if the country of incorporation for the foreign private issuer would not require reporting as timely as is required on a Form 8-K for the same event had the issuer been a U.S. filer?  7

Five reportable events  8 may be waived if any contributing sponsor of the plan (before the transaction that caused the event) is a public company, and the contributing sponsor timely files a SEC Form 8-K disclosing the event under an item of the Form 8-K, except under Item 2.02 (Results of Operations and Financial Condition) or in financial statements under Item 9.01 (Financial Statements and Exhibits). As explained in the 2015 Final Rule, PBGC found that SEC filings provide timely and adequate information to PBGC with respect to the five events because these events are either required to be reported under a specific Form 8-K item or because they are material information for investors. Therefore, PBGC didn't need to compel reporting of these events under the reportable events regulation.

The proposed rule does not make any changes to the public company waiver. However, in response to questions from practitioners since publication of the 2015 Final Rule, PBGC requests comment on whether the waiver should be expanded to apply in situations where a parent company timely files a Form 8-K but is not a contributing sponsor to the plan. Specifically, would the Form 8-K filing by a parent company that isn't a contributing sponsor provide adequate information to PBGC with respect to each of the five events to which the waiver applies?

Section 4010 of ERISA requires the reporting of actuarial and financial information by controlled groups with single-employer pension plans that have significant funding problems. It also requires PBGC to provide an annual summary report to Congress containing aggregate information filed with PBGC under that section. PBGC's “4010 reporting regulation” (29 CFR part 4010) implements section 4010 of ERISA.

Section 4010.2 of PBGC's 4010 reporting regulation contains the terms used in part 4010 and their definitions. The proposed rule would amend this “Definitions” section to include the term “Foreign entity,” which is used in proposed amendments to § 4010.9 describing the financial information a filer is required to provide to PBGC. The proposed definition is similar to the definition of “Foreign entity” in § 4043.2 of PBGC's reportable events regulation. The only difference is that “information year” replaces “date the reportable event occurs” in part (3) of the definition so that part (3) is satisfied for 4010 purposes if one of three tests are met for the fiscal year that includes the information year.

The proposed rule also would add to the list of common terms referenced in § 4010.2 the two terms it would define in the general definitions section of PBGC's regulations (§ 4001.2). As explained above, under “Terminology—29 CFR part 4001,” those terms would be “Ultimate parent,” and “U.S. entity.”

Section 4010.4 of the 4010 reporting regulation prescribes who is a filer. Paragraph (e) of this section explains how reporting is applicable to plans to which special funding rules apply. This paragraph provides that except in connection with the actuarial valuation report, the special funding rules under sections 104 and 402(b) of PPA (applicable to multiple employer plans of cooperatives and charities, and plans of commercial passenger airlines and airline caterers, respectively) and under the Cooperative and Small Employer Charity Pension Flexibility Act of 2013, are disregarded for all other 4010 purposes. The proposed rule would remove from paragraph (e) the reference to PPA section 104 because it has expired.

Section 4010.7 of the 4010 reporting regulation describes what types of identifying information each filer must provide as part of its reporting. Paragraph (a)(1) of this section specifies what information is required to be included about current members of the filer's controlled group, such as identifying the legal relationships of each controlled group member to the other members. Filers identify the legal relationships by manually entering a description, e.g., parent, subsidiary, for each member. Identifying the legal relationships of controlled group members in this way can be burdensome to filers in larger controlled groups and does not provide a clear picture of the controlled group structure, frustrating the intent of this information.

The proposed rule would provide a simple method for filers in larger controlled groups to satisfy the requirement in paragraph (a) of this section. Instead of entering “parent,” “subsidiary,” or other relationship, filers with more than 10 controlled group members would submit with their filing an organizational chart or other diagram showing the relationship of the controlled group members to each other. PBGC's understanding is that most filers have such diagrams. Also, filers may already include such diagrams in reportable events filings (29 CFR part 4043) to satisfy the requirement specified in those instructions for a description of the controlled group structure. PBGC believes that requiring a diagram for these larger groups would be less burdensome to provide and would more clearly show the controlled group structure.

Section 4010.8 of the 4010 reporting regulation prescribes the plan actuarial information a filer must provide. Paragraph (d)(2) of this section sets the actuarial assumptions and methods to use for determining a plan's benefit liabilities. PBGC has heard from practitioners that the assumptions in paragraph (d)(2) as they apply to cash balance pension plans are not clear and don't specify how these plans should convert a lump sum payment (which is the assumption used by most cash balance plans) to an annuity form. The proposed rule would provide needed guidance with respect to cash balance plans on these assumptions and make a change in the paragraph's overall structure to improve clarity.

The proposed rule would reorganize § 4010.8(d)(2) and combine the actuarial assumptions under paragraphs (d)(2)(i) through (ii) of this section into a table. The table would include as number (5) the assumptions to use for valuing benefit liabilities for cash balance plans. Cash balance plan filers must convert account balances to annuity forms of payment using the rules under section 411(b)(5)(B)(vi) of the Code and 26 CFR 1.411(b)(5)-1(e)(2) that specify the interest crediting rate and annuity conversion rate upon plan termination. In other words, for purposes of reporting benefit liabilities, a cash balance plan would be treated as if terminated and lump sums converted to annuity payments using the assumptions in the applicable U.S. Department of the Treasury regulation cited to above.

The proposed edits to paragraph (d)(3) of this section focus on improved readability and conformed citations to ERISA and the Code.

Section 4010.9 of the 4010 reporting regulation prescribes the financial information a filer must submit to PBGC for each member of the filer's controlled group. Paragraph (b) of this section permits a filer to submit consolidated financial statements if the financial information of a controlled group member is combined with the information of other members in a consolidated statement. However, if consolidated information is reported, paragraph (b)(2) requires that revenues, operating income, and net assets for each controlled group member also be reported.

In PBGC's 2017 Request for Information (RFI) on Regulatory Planning and Review of Existing Regulations (noted in the “Background” section of this preamble), a commenter stated that some filers have difficulty trying to identify and collect the three types of information under § 4010.9(b)(2) for each controlled group member and recommended that PBGC modify the regulation to request this detailed information only when necessary as part of reviewing the plan and controlled group financial statements. PBGC considered the comment, and after reviewing the information it collects for 4010 purposes, PBGC believes it can adequately assess risks to participants and plans without this detailed information, and by using additional “off-the-shelf” information as noted in the following paragraph. Therefore, the proposed rule would eliminate that requirement in paragraph (b)(2) of § 4010.9.

PBGC proposes to make another change to paragraph (b) of this section to clarify what financial information must be provided for controlled group members that are U.S. entities where the ultimate parent is a foreign entity. In addition to the consolidated statements for the whole controlled group, the filer must submit financial information on only the U.S. entities that are members of the controlled group. This information could be submitted in consolidated statements. Otherwise, the filer must provide the separate audited (or unaudited) financial statements (or tax returns if financial statements are not available) for controlled group members that are U.S. entities.

Lastly, § 4010.9 allows filers to direct PBGC to where PBGC can find required financial information that is publicly available (in lieu of submitting that information to PBGC). Paragraph (d) of this section on “submission of public information” provides that a filer may submit a statement indicating when the financial information was made available to the public and where PBGC may obtain it. In PBGC's experience, these statements have led to general websites, but not specific web pages where the information required to be reported can be found. Therefore, the proposed rule would clarify how to indicate where public financial information is located. The clarification would state that filers provide the web address (URL) and title of the web page. The example in paragraph (d) of a Securities and Exchange Commission filing is clarified accordingly.

Reporting under section 4010 of ERISA is required if any one of three conditions is met. However, PBGC can waive reporting under its 4010 reporting regulation and does so in three situations (with discretion to waive in others) under § 4010.11 of the regulation.

A condition triggering reporting is that the funding target attainment percentage (FTAP) at the end of the preceding plan year, of a plan maintained by the contributing sponsor or any member of its controlled group, is less than 80 percent (the “80-percent FTAP Gateway Test”). Section 303(d)(2) of ERISA and section 430(d)(2) of the Code provide that in determining the FTAP of a plan for a plan year, plan assets are reduced by the amount of the plan's funding balance. Plan sponsors are permitted under section 303(f) of ERISA and section 430(f) of the Code to make certain elections to use, increase, or reduce a funding balance effective at the beginning of the plan year. Because of timing, a funding balance election that is made late may be the sole cause of a plan having a 4010 FTAP of less than 80 percent. Practitioners have asked if PBGC would recognize for purposes of the 80-percent FTAP Gateway Test an untimely funding balance election.

In response, and based on a review of its experience, PBGC proposes to recognize a late funding balance election for this purpose. The proposed waiver would clarify that reporting is not required where a plan makes a late election to reduce a funding balance, and the plan's FTAP for 4010 purposes would have been greater than or equal to 80 percent had the election been timely made.

PBGC also proposes to modify two of the existing three reporting waivers in § 4010.11 of the regulation. PBGC automatically waives reporting where: (a) The aggregate funding shortfall is not in excess of $15 million; (b) the aggregate participant count is less than 500; or (c) the sole reason filing would otherwise be required is because of either a statutory lien resulting from missed contributions over $1 million or outstanding minimum funding waivers exceeding the same amount, provided the missed contributions or applications for minimum funding waivers were previously reported to PBGC.

Practitioners have raised with PBGC that, while it is clear under the 80-percent FTAP Gateway Test that only plans maintained by the controlled group on the last day of the information year are considered in determining whether that test is met, the same is not clear under § 4010.11 in determining whether either of the first two waivers apply. Without specifying “on the last day of the information year,” the language of the aggregate funding shortfall waiver in paragraph (a) and the waiver for smaller plans in paragraph (b) of § 4010.11, could be interpreted to mean that plans maintained at any time during the plan year must be included in the determination of whether the waiver applies. This is not the interpretation that PBGC intended or believes is reasonable in light of the standard in the 80-percent FTAP Gateway Test. PBGC agrees that a clarification would be helpful. Therefore, the proposed rule would modify paragraphs (a) and (b) of § 4010.11 to insert “on the last day of the information year.”

Practitioners have also asked when at-risk assumptions are to be used to calculate the funding target (see section 303(i) of ERISA and section 430(i) of the Code for special rules for at-risk plans) for purposes of the 4010 funding shortfall and waiving reporting where a plan's aggregate funding shortfall is $15 million or less. In response, the proposed rule would revise paragraph (a)(1)(i) of § 4010.11 to provide that a plan is not required to use at-risk retirement and form of payment assumptions to determine the funding target used to calculate the 4010 funding shortfall unless the plan is in “at-risk status” for funding purposes. This follows a similar clarification that had been made to the rules describing assumptions for determining the premium funding target under PBGC's premium rates regulation, § 4006.4(b)(3).

A single-employer plan covered by PBGC's insurance program may be voluntarily terminated only in a standard or distress termination. The rules governing voluntary terminations are in section 4041 of ERISA and PBGC's regulation on Termination of Single-Employer Plans (29 CFR part 4041), “termination of single-employer plans regulation.”

ERISA requires the plan administrator of a plan terminating in a standard termination to certify to PBGC that the plan's assets have been distributed to pay all benefits under the plan. Certification under section 4041(b)(3)(B) of ERISA must be made within 30 days after the final distribution of assets is completed.

Section 4041.29 of the termination of single-employer plans regulation requires plans to submit by the 30-day statutory deadline a “post-distribution certification” ( i.e., PBGC Form 501). PBGC has heard from practitioners that it is sometimes challenging to collect all of the information required to be submitted as an attachment to Form 501 within the prescribed timeframe ( e.g., documentation that benefit obligations were settled for all participants including copies of cancelled checks in the case of lump sum distributions) and have asked whether PBGC could extend the certification deadline.

While PBGC cannot extend a statutory deadline, the proposed rule would amend paragraph (a) of § 4041.29 to provide an alternative filing option for plan administrators who need more time to complete the PBGC Form 501. This proposed alternative would permit a plan administrator to submit a completed PBGC Form 501 within 60 days after the last distribution date for any affected party if the plan administrator certifies to PBGC that all assets have been distributed in accordance with section 4044 of ERISA and 29 CFR part 4044 (in an email or otherwise, as would be described in the instructions to the Form 501) within 30 days after the last distribution date for any affected party.

Paragraph (b) of this section and paragraph (d)(2) of § 4041.30 (requests for deadline extensions) would be revised accordingly to account for the proposed changes to § 4041.29(a).

Under sections 4006 and 4007 of ERISA, plans covered by the termination insurance program under title IV of ERISA must pay premiums to PBGC. Section 4006 of ERISA deals with premium rates, including the computation of premiums, and PBGC's regulation on Premium Rates in 29 CFR part 4006, “premium rates regulation,” implements section 4006 of ERISA.

Section 4006.4 of the premium rates regulation, which provides rules for determining unfunded vested benefits, states in paragraph (f) that plans subject to special funding rules must disregard those rules and determine unfunded vested benefits for premium purposes in the same manner as all other plans. Section 4006.4(f) refers to the special funding rules under sections 104, 105, 106, and 402(b) of the Pension Protection Act of 2006, Public Law 109-280 (PPA), that are applicable to multiple employer plans of cooperatives and charities, PBGC settlement plans, plans of government contractors, and plans of commercial passenger airlines and airline caterers.

The proposed rule would remove references to PPA sections 104, 105, and 106 because those provisions have expired. It would add a reference to subsequent law that permanently established special funding rules for multiple employer plans maintained by certain cooperatives and charities (the Cooperative and Small Employer Charity Pension Flexibility Act of 2013, Pub. L. 113-97).

In general, a single-employer plan pays a variable-rate premium (VRP) for the plan year ten-and-a-half months after the plan year begins based on the level of the plan's underfunding at the beginning of the plan year. In 2014, as part of PBGC's regulatory review process, PBGC amended its premium rates regulation to provide for a VRP exemption for the year in which a plan completes a standard termination. PBGC adopted this exemption because it did not seem appropriate to require a terminating plan to pay a VRP based on the underfunding at the beginning of the year when, by the time the premium was due (or shortly thereafter), the sponsor had fully funded the plan and distributed all accrued benefits ( i.e., purchased annuities or paid lump sums) and PBGC coverage had ceased. 9

PBGC has received questions from practitioners as to whether a plan qualifies for this “final year” exemption if a large number of participants are spun off to a new plan or transferred to another existing plan during the year in which the termination is completed. It has been suggested that, if the exemption applies, a plan sponsor could significantly reduce its VRP because the transferor plan would not owe any VRP for its final year and the transferee plan would owe, at most, a pro-rata VRP for the plan year in which the transfer occurs. 10 However, the VRP exemption does not apply in this type of transaction because the benefits of most of the participants who were in the plan at the beginning of the year would not be fully funded or paid in full, and for those participants, PBGC coverage would still be in effect. PBGC added language to the 2018 premium filing instructions to highlight to filers that the VRP exemption does not apply in such cases.

In light of these questions, PBGC is proposing to amend § 4006.5(a)(3) of the premium rates regulation to expressly state that a plan does not qualify for the VRP exemption for the year in which a plan completes a standard termination if the plan engages in a spinoff during the premium payment year. The proposed rule would make an exception where the spinoff is de minimis pursuant to the regulations under section 414(l) of the Internal Revenue Code (the Code), i.e., generally fewer than 3 percent of the assets are spun off.

To distinguish cases where the termination has not yet been completed, the proposed changes would move the exemption for certain plans in the process of completing a standard termination initiated in a prior year from § 4006.5(a)(3) to § 4006.5(a)(4) of the premium rates regulation.

To determine the flat-rate premium for a plan year, participants are counted on the “participant count date,” generally the day before the plan year begins. Changes in the participant count during the plan year do not affect that year's flat-rate premium. Under the premium rates regulation, a special rule (§ 4006.5(e)) shifts the participant count date to the first day of the plan year in specified situations that take place at the beginning of a plan year so that the change in participant count is recognized immediately (rather than a year later). Situations where the special rule applies include:

• The first plan year a plan exists.

• A plan year in which a plan is the transferor plan in the case of a beginning of year non-de minimis spinoff.

• A plan year in which a plan is the transferee plan in the case of a beginning of year non-de minimis merger.

For example, consider a scenario where Plan A, a calendar year plan, spins off a group of participants (and the corresponding assets and liabilities) into new Plan B at the beginning of Plan A's 2018 plan year (assume the spinoff is not de minimis). Because of the special rule, both plans count participants on the first day of the year which means Plan B owes a 2018 flat-rate premium on behalf of the transferred participants, but Plan A does not.

PBGC has received questions from practitioners as to whether the special rule applies to the transferee plan in a situation where spun off participants are transferred to an existing plan instead of a new plan. These practitioners believed the premium filing instructions could be interpreted to provide that the special rule does not apply to the transferee plan in this plan-to-plan transfer. However, that interpretation would lead to an inconsistent result.

For example, assume that instead of spinning off participants into a new plan, Plan A (in the above example) had transferred those participants to a pre-existing Plan C (also a calendar year plan) at the beginning of Plan C's 2018 plan year. As noted above, the special rule would apply to Plan A, so Plan A would not include the transferred participants in its participant count. But, if the special rule does not apply to Plan C ( i.e., to the transferee plan), Plan C would count participants on the day before the transfer. That would mean that neither Plan A nor Plan C would owe flat-rate premiums on behalf of the transferred participants for 2018.

PBGC is proposing to amend the special rule in paragraph (e) of § 4006.5 to clarify that, in such plan-to-plan transfers, the participant count date of the transferee plan shifts to the first day of its plan year. As a result, it is clear that the transferee plan would owe flat-rate premiums on behalf of the transferred participants. This provision generally would operate where both plans have the same plan year and the transfer takes place at the beginning of the plan year.

As noted above, the special rule also applies where a plan is the transferee plan in the case of a beginning-of-year non-de minimis merger. For example, if two calendar year plans merge at the beginning of 2018, the surviving plan's participant count date is shifted to January 1, 2018. As a result, the surviving plan owes 2018 flat-rate premiums on behalf of the participants who were previously in the transferor plan.

PBGC exempted de minimis mergers from this special rule because PBGC felt the burden resulting from shifting the participant count date was not justified in the case of a de minimis merger because the number of participants for whom neither plan would owe a flat-rate premium would be relatively small ( i.e., the regulations under section 414(l) of the Code provide that a merger is de minimis where the liabilities of the smaller plan are less than 3 percent of the assets of the larger plan).

PBGC has received questions from practitioners as to whether this de minimis exemption applies where the surviving plan is the smaller plan. It has been suggested that, if the exemption applies, a plan sponsor could avoid paying flat-rate premiums on behalf of the large plan participants simply by merging it into a much smaller plan. In one case, a consultant reported that a plan sponsor was considering a strategy to establish a new plan covering only a few employees so that it could merge a large plan into the new small plan at the beginning of the next year and avoid paying flat-rate premiums on behalf of the large plan participants. These results are inconsistent with the intent of the special rule and de minimis exception.

Because of these questions, PBGC is proposing to clarify that the special rule in paragraph (e) of this section applies in the case of a beginning-of-year merger where a large plan is merged into a smaller plan. This clarification maintains the de minimis exception where a smaller plan merges into a larger plan.

The special rule in § 4006.5(f) of PBGC's premium rates regulation allows plan administrators to pay prorated VRP and flat-rate premiums for a short plan year and lists the four circumstances that would create a short year. One of those circumstances is where the plan's assets are distributed pursuant to the plan's termination. For example, if a plan distributed its assets in a standard termination with a final short plan year covering nine months ( i.e., 75 percent of a full year), the calculated premium would be reduced by 25 percent.

This rule makes sense where all accrued benefits are distributed ( i.e., purchased annuities or paid lump sums) and PBGC's coverage ends. However, where a completed termination is preceded in the same year by a spinoff of a group of the plan's participants to another plan, the transferred participants remain in the insurance program and PBGC coverage of their benefits is still in effect. It has been suggested that a plan sponsor could use this rule to significantly reduce its premium obligation for the year simply by transferring most of its participants to another plan early in the plan year and then terminating what's left of the transferor plan (and, thus, owing only a pro-rata premium for its final short plan year).

In view of these considerations, PBGC is proposing to change the circumstances under which the premium is prorated for a short plan year resulting from a standard termination. The proposed rule would provide that premiums are not prorated for the year in which the plan completes a final distribution of assets in a standard termination if the plan engages in a spinoff in that same year, unless the spinoff is de minimis pursuant to the regulations under section 414(l) of the Code, i.e., generally fewer than 3 percent of the assets are spun off.

In the same paragraph, the proposed rule replaces the words “excess assets” with “residual assets under section 4044(d) of ERISA” to be consistent with the statutory language.

PBGC has determined that this rule is not a “significant regulatory action” under Executive Order 12866. Accordingly, this proposed rule is exempt from Executive Order 13771, and the Office of Management and Budget has not reviewed it under Executive Order 12866.

Executive Order 12866 directs 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).

Although this is not a significant regulatory action under Executive Order 12866, PBGC has examined the economic and policy implications of this proposed rule. Most of the proposed amendments clarify regulations and remove outdated provisions, which are neutral in their impact. A few would minimally affect the time and cost of reporting for plans and sponsors, which is discussed in the Paperwork Reduction Act section below.

Section 6 of Executive Order 13563 requires agencies to rethink existing regulations by periodically reviewing their regulatory program for rules that “may be outmoded, ineffective, insufficient, or excessively burdensome.” These rules should be modified, streamlined, expanded, or repealed as appropriate. PBGC has identified technical corrections, clarifications, and improvements to some of its regulations and have included those amendments in this proposed rulemaking. PBGC expects to propose periodic rulemakings of this nature to revise its regulations as necessary for minor technical corrections and clarifications to rules.

The Regulatory Flexibility Act  11 imposes certain requirements with respect to rules that are subject to the notice and comment requirements of section 553(b) of the Administrative Procedure Act and that are likely to have a significant economic impact on a substantial number of small entities. Unless an agency determines that a final rule is not likely to have a significant economic impact on a substantial number of small entities, section 603 of the Regulatory Flexibility Act requires that the agency present a final regulatory flexibility analysis at the time of the publication of the final rule describing the impact of the rule on small entities and seeking public comment on such impact. Small entities include small businesses, organizations, and governmental jurisdictions.

For purposes of the Regulatory Flexibility Act requirements with respect to this proposed rule, PBGC considers a small entity to be a plan with fewer than 100 participants. This is substantially the same criterion PBGC uses in other regulations  12 and is consistent with certain requirements in title I of ERISA  13 and the Code, 14 as well as the definition of a small entity that the Department of Labor has used for purposes of the Regulatory Flexibility Act. 15

Thus, PBGC believes that assessing the impact of this final rule on small plans is an appropriate substitute for evaluating the effect on small entities. The definition of small entity considered appropriate for this purpose differs, however, from a definition of small business based on size standards promulgated by the Small Business Administration  16 under the Small Business Act. Therefore, PBGC requests comments on the appropriateness of the size standard used in evaluating the impact of the amendments in this proposed rule on small entities.

Throughout this document whenever “we,” “us,” or “our” is used, we mean EPA. This supplementary information section is arranged as follows:

Under CAA section 110(a)(2)(D)(i)(I), called the good neighbor provision, states are required to address interstate transport of air pollution. Specifically, the good neighbor provision provides that each state's SIP must contain provisions prohibiting emissions from within that state from contributing significantly to nonattainment of the National Ambient Air Quality Standards (NAAQS), or interfering with maintenance of the NAAQS, in any other state.

On October 27, 1998, EPA published the NO X SIP Call, which required eastern states, including Ohio, to submit SIPs that prohibit excessive emissions of ozone season NO X by implementing statewide emissions budgets (63 FR 57356). The NO X SIP Call addressed the good neighbor provision for the 1979 ozone NAAQS and was designed to mitigate the impact of transported NO X emissions, one of the precursors of ozone. EPA developed the NO X Budget Trading Program, an allowance trading program that states could adopt to meet their obligations under the NO X SIP Call. This trading program allowed certain sources to participate in a regional cap and trade program: EGUs with capacity greater than 25 megawatts; and large non-EGUs, such as boilers and turbines, with a rated heat input greater than 250 million British thermal units per hour (MMBtu/hr). The NO X SIP Call also identified potential reductions from Portland cement kilns and stationary internal combustion engines. In fulfillment of the requirements of the NO X SIP Call, Ohio EPA promulgated OAC Chapter 3745-14 which, among other things, required EGUs and large non-EGUs in the state to participate in the NO X Budget Trading Program. On August 5, 2003, EPA published an action approving this initial version of OAC Chapter 3745-14 into the Ohio SIP (68 FR 46089). EPA has subsequently approved revised portions of OAC Chapter 3745-14 into the SIP, with the most recent revision published on November 14, 2013 (78 FR 68367).

On May 12, 2005, EPA published CAIR, which required eastern states, including Ohio, to submit SIPs that prohibited emissions consistent with annual and ozone season NO X budgets and annual sulfur dioxide (SO 2 ) budgets (70 FR 25152). CAIR addressed the good neighbor provision for the 1997 ozone NAAQS and 1997 fine particulate matter (PM 2.5 ) NAAQS and was designed to mitigate the impact of transported NO X emissions, a precursor of ozone as well as PM 2.5 , as well as transported SO 2 emissions, another precursor of PM 2.5 . Like the NO X SIP Call, CAIR also established several trading programs that states could use as mechanisms to comply with the budgets. When the CAIR trading program for ozone season NO X was implemented beginning in 2009, EPA discontinued administration of the NO X Budget Trading Program, but the requirements of the NO X SIP Call continued to apply. To meet the requirements of CAIR, Ohio EPA promulgated OAC Chapter 3745-109, which required EGUs to participate in the CAIR annual SO 2 and annual and ozone season NO X trading programs. Participation by EGUs in the CAIR trading program for ozone season NO X addressed the state's obligation under the NO X SIP Call for those units. Ohio EPA also opted to incorporate large non-EGUs previously regulated under OAC Chapter 3745-14 into OAC Chapter 3745-109, to meet the obligations of the NO X SIP Call with respect to those units through the CAIR trading program as well. On September 25, 2009, EPA published an action approving OAC Chapter 3745-109 into the Ohio SIP (74 FR 48857).

The United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) initially vacated CAIR in 2008, but ultimately remanded the rule to EPA without vacatur to preserve the environmental benefits provided by CAIR. North Carolina v. EPA, 531 F.3d 896, modified, 550 F.3d 1176 (2008). The ruling allowed CAIR to remain in effect temporarily until a replacement rule consistent with the court's opinion was developed. While EPA worked on developing a replacement rule, the CAIR program continued as planned with the NO X annual and ozone season programs beginning in 2009 and the SO 2 annual program beginning in 2010.

On August 8, 2011, acting on the D.C. Circuit's remand, EPA published the Cross-State Air Pollution Rule (CSAPR) to replace CAIR and to address the good neighbor provision for the 1997 ozone NAAQS, the 1997 PM 2.5 NAAQS, and the 2006 PM 2.5 NAAQS (76 FR 48208). Through Federal Implementation Plans (FIPs), CSAPR required EGUs in eastern states, including Ohio, to meet annual and ozone season NO X budgets and annual SO 2 budgets implemented through new trading programs. CSAPR also contained provisions that would sunset CAIR-related obligations on a schedule coordinated with the implementation of the CSAPR compliance requirements. Participation by a state's EGUs in the CSAPR trading program for ozone season NO X generally addressed the state's obligation under the NO X SIP Call for EGUs. However, CSAPR did not initially contain provisions allowing states to incorporate large non-EGUs into that trading program to meet the requirements of the NO X SIP Call for non-EGUs.

CSAPR was intended to become effective January 1, 2012; however, the timing of CSAPR's implementation was impacted by subsequent litigation in which the D.C. Circuit stayed implementation of the rule pending judicial review. See Per Curium Order, EME Homer City Generation, L.P. v. EPA, No. 11-1302 (December 30, 2011), ECF No. 1350421. After subsequent litigation, 1 the court granted EPA's motion to lift the stay  2 and, on December 3, 2014, EPA issued an interim final rule, setting the updated effective date of CSAPR as January 1, 2015 (79 FR 71663). In accordance with the interim final rule, EPA stopped administering the CAIR trading programs with respect to emissions occurring after December 31, 2014, and EPA began implementing CSAPR on January 1, 2015. 3

On October 26, 2016, EPA published the CSAPR Update, which established a new ozone season NO X trading program for EGUs in eastern states, including Ohio, to address the good neighbor provision for the 2008 ozone NAAQS (81 FR 74504). As under CSAPR, participation by a state's EGUs in the new CSAPR trading program for ozone season NO X generally addressed the state's obligation under the NO X SIP Call for EGUs. The CSAPR Update also expanded options available to states for meeting NO X SIP Call requirements for large non-EGUs by allowing states to incorporate those units into the new trading program.

After evaluating the various options available following CSAPR Update, Ohio EPA chose to meet the ongoing NO X SIP Call requirements for existing and new large non-EGUs by modifying its existing regulations at OAC Chapter 3745-14 to make the portion of the budget assigned to large non-EGUs under that program enforceable without an allowance trading mechanism.

Specifically, while Ohio rescinded portions of its NO X Budget Trading Program rules under OAC Chapter 3745-14 pertaining to individual unit allowance allocations and trading, the state retained and amended the provisions of those rules pertaining to applicability, the statewide emissions budgets for EGUs and large non-EGUs, and monitoring and reporting under 40 CFR part 75. Ohio also retained a provision of the trading program rules exempting EGUs covered by a more recent ozone season NO X trading program from coverage under the state's amended program, but updated the provision to base the exemption on participation in the CSAPR Update trading program for ozone season NO X instead of the corresponding CAIR trading program. In addition, Ohio retained other rules under OAC Chapter 3745-14 addressing NO X emissions from cement kilns and stationary internal combustion engines outside the NO X Budget Trading Program. Finally, Ohio also rescinded its CAIR trading program rules in OAC Chapter 3745-109 in full.

As described in its February 5, 2018 submission, Ohio EPA invited public comments regarding its changes to OAC Chapter 3745-14 and OAC Chapter 3745-109. Ohio EPA received one supportive comment, as well as one adverse comment regarding Ohio's retention of part 75 monitoring requirements.

On March 8, 2019, EPA finalized updates to the NO X SIP Call rules to allow states to meet the NO X SIP Call's monitoring requirements using approaches other than part 75 monitoring (84 FR 8422). Ohio's February 5, 2018, submission predates EPA's updates to the NO X SIP Call's monitoring requirements, and, therefore, does not include changes that allow its sources to meet the NO X SIP Call's monitoring requirements using approaches other than part 75 monitoring. EPA is assisting Ohio EPA with preparing a revised submission that would make other monitoring approaches available to Ohio sources, and EPA will address such a submission in a future rulemaking.

Ohio's February 5, 2018 submission requests that EPA update Ohio's SIP to reflect the revised rules at OAC Chapter 3745-14 and the rescission of rules at OAC Chapter 3745-109. Additionally, this submission includes a demonstration under Section 110(l) of the CAA intended to show that this SIP revision does not interfere with any applicable CAA requirement.

Given EPA's replacement of CAIR with CSAPR and EPA's discontinuation of administration of the NO X Budget Trading Program, Ohio updated its NO X SIP Call rules at OAC Chapter 3745-14 to address the NO X SIP Call's requirements with respect to existing and new large non-EGUs in a manner that does not rely on the administration of a trading program. Ohio also rescinded its CAIR rules at OAC Chapter 3745-109. Both sets of rule changes have a state-effective date of January 28, 2018. Ohio's February 5, 2018, submission includes a request that EPA approve these updated rules into its SIP.

The state regulations addressing the NO X SIP Call were formerly established at OAC rules 3745-14-01 through 3745-14-12. Because EPA discontinued administration of this trading program in 2009, Ohio has rescinded certain portions of these rules that can no longer be implemented. Specifically, Ohio rescinded OAC rules 3745-14-02, 3745-14-05, 3745-14-06, 3745-14-07, 3745-14-09, and 3745-14-10 pertaining to individual unit allowance allocations, trading, opt-in, and other non-implementable provisions under the NO X Budget Trading Program. However, for purposes of continued compliance with the requirements of the NO X SIP Call, Ohio retained and amended OAC rules 3745-14-01, 3745-14-03, 3745-14-04, and 3745-14-08 pertaining to applicability, the statewide emissions budgets for EGUs and large non-EGUs, and part 75 monitoring and reporting under the former trading program. Ohio also retained OAC rules 3745-14-11 and 3745-14-12 regarding cement kilns and stationary internal combustion engines outside the former trading program. The state's amendments to OAC rule 3745-14-01 require Ohio EPA to ensure that the statewide budget for large non-EGUs will continue to be met in the absence of a trading program mechanism. Table 1 presents a summary of Ohio's revisions to OAC Chapter 3745-14.

Specifically, these amendments include: Moving the statewide NO X budgets for large EGUs and large non-EGUs from OAC rule 3745-14-05, which is being rescinded, to OAC rule 3745-14-01; adding provisions requiring Ohio EPA to conduct an annual review to determine if the statewide budget for large non-EGUs is met, and providing procedures should the budget be exceeded; removing unit allowance allocation and trading provisions; specifying non-EGU NO X budget units subject to OAC Chapter 3745-14; updating the applicability exception for EGUs to reference CSAPR instead of CAIR; removing the retired unit exemption, as it is no longer applicable; removing unnecessary definitions; adding a definition for “designated representative”; replacing “NO X budget trading program” with “NO X budget program” to reflect the absence of trading; replacing “NO X Authorized Account Representative” with “designated representative”, the term used in part 75 monitoring; updating referenced material; eliminating requirements for a NO X budget permit to be included as a complete and segregable portion of a title V or non-title V permit; requiring the owner or operator of a NO X budget unit to submit an application for a title V or non-title V operating permit for each subject source; revising compliance certification provisions to remove unnecessary provisions; eliminating the requirement for the compliance certification to be submitted to EPA; updating monitoring and reporting provisions, most notably to remove unnecessary references to opt-in permits and early reduction credits; and eliminating NO X budget opt-in provisions, as they are no longer applicable.

Further, the state's regulations for participation in the CAIR trading programs for SO 2 and annual and ozone season NO X were formerly established at OAC Chapter 3745-109. Because EPA discontinued administration of the CAIR trading programs after 2014, Ohio has rescinded these rules that can no longer be implemented.

First, EPA proposes to approve the rescission of the trading program-related portions of Ohio's NO X Budget Trading Program rules and all of Ohio's CAIR trading program regulations. Because EPA no longer administers the NO X Budget Trading Program and the CAIR trading programs, and therefore Ohio's own regulations related to these trading programs cannot be implemented, removing the trading program provisions of Ohio's NO X SIP Call rules and all of the CAIR rules from the state's SIP will have no consequences for any source's operations or emissions or for the attainment and maintenance of the NAAQS in any area, now or in the future. Accordingly, removal of these rules does not impact the state's continued compliance with section CAA 110(a)(2)(D)(i)(I) for any NAAQS.

Further, EPA proposes to find that Ohio's revisions to OAC rules 3745-14-01, 3745-14-03, 3745-14-04, and 3745-14-08 are consistent with Ohio's obligation to demonstrate continued compliance with NO X SIP Call requirements for large non-EGUs and EPA's discontinuation of the trading program under the NO X SIP Call. Under the ongoing requirements of the NO X SIP Call, the Ohio SIP must: (1) Include enforceable control measures for ozone season NO X mass emissions from existing and new large EGUs and large non-EGUs and (2) require those sources to monitor and report ozone season NO X emissions, which may be in accordance with part 75. See 40 CFR 51.121(f)(2) and (i).

With respect to the NO X SIP Call requirement that the state have enforceable control measures to limit ozone season NO X , Ohio is currently subject to the Federal CSAPR Update trading program for ozone season NO X that addresses these requirements for existing and new EGUs, but because Ohio's non-EGUs are not subject to that CSAPR trading program, the state must meet this requirement for non-EGUs through other SIP provisions. Ohio's revisions to OAC rule 3745-14-01 prohibit ozone season NO X emissions from existing and new large non-EGUs from exceeding 4,028 tons, the portion of the state's NO X SIP Call budget assigned to large non-EGUs. Under the revisions at OAC rule 3745-14-01, Ohio will conduct an annual review to ensure that the most recent ozone season emissions from large non-EGUs remain below the statewide budget. Emissions reported to EPA from the state's large non-EGUs for the 2018 ozone season were 543 tons, well below this limit.

As to the requirement for sources to monitor and report ozone season NO X emissions under the NO X SIP Call, these SIP revisions would preserve the state's current requirements for existing and new EGUs and non-EGUs to monitor and report their ozone season NO X emissions, as required under the NO X SIP Call. Ohio's revisions at OAC Chapter 3745-14 continue to require that non-EGUs monitor and report ozone season NO X emissions under part 75, and the state's EGUs are subject to equivalent monitoring requirements under the CSAPR federal trading programs. Thus, the revisions to OAC Chapter 3745-14 and removal of OAC Chapter 3745-109 proposed for approval into the SIP in this action will not substantively alter the current monitoring requirements for any EGUs or large non-EGUs in the state covered by the NO X SIP Call. If, as anticipated, Ohio EPA submits to EPA a SIP revision that would make other monitoring approaches available to large non-EGUs, the monitoring requirements under the NO X SIP Call will be the subject of a future rulemaking.

As revised, OAC rules 3745-14-01, 3745-14-03, 3745-14-04 and 3745-14-08 meet the state's ongoing obligations under the NO X SIP Call with respect to existing and new large non-EGUs. Specifically, the revised rules meet the requirement under 40 CFR 51.121(f)(2) for enforceable limits on the units' collective emissions of ozone season NO X mass emissions and the requirement under 40 CFR 51.121(i)(1) for monitoring sufficient to ensure compliance with those limits. The state's EGUs are currently complying with their analogous NO X SIP Call requirements through participation in the CSAPR Update trading program for ozone season NO X .

EPA is proposing to find that Ohio EPA's revisions at OAC Chapter 3745-14 and removal of OAC Chapter 3745-109 are consistent with applicable requirements under the CAA and the NO X SIP Call, and EPA is therefore proposing to approve these changes into the Ohio SIP.

Additionally, the revisions at OAC rules 3745-14-01, 3745-14-03, and 3745-14-08 include minor amendments that were effective in 2015 and 2018 but were not submitted for SIP approval because they were not substantive changes. EPA's approval of Ohio's revised rules with state-effective date January 28, 2018, would also approve these minor amendments into the SIP. These revisions include: Updating hyperlinks and references, correcting typographical and formatting errors, and clarifying procedures for permit applications.

Ohio EPA's submission includes a demonstration intended to show that its SIP revision is approvable under Section 110(l) of the CAA; such a demonstration is sometimes called an anti-backsliding demonstration. Section 110(l) provides that EPA cannot approve a SIP revision if the revision would interfere with any applicable CAA requirement. EPA will approve a SIP revision that removes or modifies control measures in the SIP only after the state has demonstrated that such removal or modification would not interfere with attainment and maintenance of the NAAQS, reasonable further progress (RFP), or any other applicable requirement of the CAA. EPA generally considers whether the SIP revision would preserve or improve the status quo in air quality.

In this action, EPA is proposing to approve Ohio's request to approve updated rules related to the NO X SIP Call into its SIP and to approve removal of CAIR rules from its SIP. This proposed action would remove from the SIP certain provisions relating to the NO X Budget Trading Program and replace those provisions with new rules at OAC Chapter 3745-14 that address the NO X SIP Call's requirements with respect to existing and new large non-EGUs in a manner that does not rely on the administration of a trading program. It would also remove the CAIR rules at OAC Chapter 3745-109.

For the reasons explained below, EPA's proposed action to update the provisions relating to the NO X Budget Trading Program and NO X SIP call is in accordance with CAA section 110(l). As explained above, EPA has not implemented the NO X Budget Trading Program since 2009 and it could not be implemented in the future. Moreover, this action would only remove the provisions that implement the trading program. It would neither alter the NO X SIP Call emission budgets that limit emissions in the state nor alter the requirement for sources to monitor and report ozone season NO X emissions under the NO X SIP Call. This action would also add to the SIP a new enforceable measure to replace the defunct NO X Budget Trading Program and ensure compliance with the NO X SIP Call budgets. This new measure is quantifiable, permanent, enforceable and contemporaneous. Importantly, the new measure ensures compliance with the existing NO X SIP Call budgets and thus will preserve the status quo in air quality. For these reasons, we conclude that the revisions will not interfere with attainment and maintenance of the NAAQS, RFP, or any other applicable requirement of the CAA.

Additionally, EPA's proposed action to remove the CAIR rules at OAC Chapter 3745-109 is consistent with the requirements of CAA 110(l). As explained above, EPA has not administered the CAIR trading programs since 2015, when the CSAPR trading programs replaced the CAIR trading programs. Likewise, the related provisions in Ohio's SIP have not been implemented since 2015 and cannot be implemented now or in the future. As such, removing the CAIR rules from the state's SIP will have no consequences for any source's operations or emissions.

Current emission levels in Ohio further demonstrate that the CAIR trading programs are not influencing and would not influence affected sources' operations. As shown in Table 2 below, current emissions levels are significantly below the CAIR budgets even while the CAIR trading programs are no longer being implemented.

Importantly, EPA was obligated by the D.C. Circuit remand of CAIR to promulgate a new rule to replace CAIR. EPA addressed this judicial remand with the promulgation of CSAPR. EGUs in Ohio are subject to FIPs requiring the sources to participate in annual NO X , annual SO 2 , and ozone season NO X 4 Federal trading programs under CSAPR and the CSAPR Update that limit emissions from such sources in the state. EGUs continue to be subject to part 75 monitoring requirements under the current CSAPR trading program rules.

For the reasons explained above, EPA is proposing to approve Ohio EPA's SIP submission under section 110(l) of the CAA.

EPA is proposing to approve Ohio EPA's request to modify its SIP to include the revisions at OAC Chapter 3745-14 and to remove OAC Chapter 3745-109.

In this rule, EPA is proposing to include in a final EPA rule regulatory text that includes incorporation by reference. In accordance with requirements of 1 CFR 51.5, EPA is proposing to incorporate by reference OAC rules 3745-14-01, 3745-14-03, 3745-14-04, and 3745-14-08, with a state effective date of January 28, 2018. EPA has made, and will continue to make, these documents generally available through www.regulations.gov and at the EPA Region 5 Office (please contact the person identified in the For Further Information Contact section of this preamble for more information).

Also in this document, as described in the proposed amendments to 40 CFR part 52 set forth below, the EPA is proposing to remove provisions of the EPA-Approved Illinois Regulations and Statutes from the Illinois State Implementation Plan, which is incorporated by reference in accordance with the requirements of 1 CFR part 51.

Under the CAA, the Administrator is required to approve a SIP submission that complies with the provisions of the CAA and applicable Federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a). Thus, in reviewing SIP submissions, EPA's role is to approve state choices, provided that they meet the criteria of the CAA. Accordingly, this action merely approves state law as meeting Federal requirements and does not impose additional requirements beyond those imposed by state law. For that reason, this action:

• Is not a significant regulatory action subject to review by the Office of Management and Budget under Executive Orders 12866 (58 FR 51735, October 4, 1993) and 13563 (76 FR 3821, January 21, 2011);

• Is not an Executive Order 13771 (82 FR 9339, February 2, 2017) regulatory action because SIP approvals are exempted under Executive Order 12866;

• Does not impose an information collection burden under the provisions of the Paperwork Reduction Act (44 U.S.C. 3501 et seq. );

• Is certified as not having a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601 et seq. );

• Does not contain any unfunded mandate or significantly or uniquely affect small governments, as described in the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4);

• Does not have Federalism implications as specified in Executive Order 13132 (64 FR 43255, August 10, 1999);

• Is not an economically significant regulatory action based on health or safety risks subject to Executive Order 13045 (62 FR 19885, April 23, 1997);

• Is not a significant regulatory action subject to Executive Order 13211 (66 FR 28355, May 22, 2001);

• Is not subject to requirements of Section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) because application of those requirements would be inconsistent with the CAA; and

• Does not provide EPA with the discretionary authority to address, as appropriate, disproportionate human health or environmental effects, using practicable and legally permissible methods, under Executive Order 12898 (59 FR 7629, February 16, 1994).

In addition, the SIP is not approved to apply on any Indian reservation land or in any other area where EPA or an Indian tribe has demonstrated that a tribe has jurisdiction. In those areas of Indian country, the rule does not have tribal implications and will not impose substantial direct costs on tribal governments or preempt tribal law as specified by Executive Order 13175 (65 FR 67249, November 9, 2000).

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

On June 3, 2010 (75 FR 31514), the EPA published a final rule, known as the GHG Tailoring Rule, which, with respect to the CAA PSD permitting program, phased in permitting requirements for GHG emissions from stationary sources. Under its interpretation of the CAA at the time, the EPA determined it was necessary to avoid an unmanageable increase in the number of sources that would be required to obtain PSD permits under the CAA because the sources emitted or had the potential to emit GHGs at or above the applicable major source and major modification thresholds. In Step 1 of the GHG Tailoring Rule, the EPA limited application of PSD requirements to sources only if they were subject to PSD “anyway” due to the emissions of other non-GHG pollutants. These sources were referred to as “anyway” sources. In Step 2 of the GHG Tailoring Rule, the EPA applied the PSD permitting requirements under the CAA to sources that were classified as major based solely on their GHG emissions or potential to emit GHGs, and to modifications of otherwise major sources that require a PSD permit because they increased only GHG emissions above the level in the EPA regulations.

On June 23, 2014, the United States Supreme Court addressed the application of PSD and Title V permitting requirements to GHG emissions. Utility Air Regulatory Group v. Environmental Protection Agency, 134 S.Ct. 2427 (2014). The Supreme Court held that the EPA may not treat GHGs as an air pollutant for purposes of determining whether a source is a major source (or a modification thereof) and thus required to obtain a PSD or title V permit. With respect to PSD, the Court also held that the EPA could continue to require that PSD permits, otherwise required based on emissions of pollutants other than GHGs (anyway sources), contain limitations on GHG emissions based on the application of Best Available Control Technology (BACT).

In accordance with the Supreme Court decision, on April 10, 2015, the U.S. Court of Appeals for the District of Columbia Circuit (the D.C. Circuit) issued an amended judgment effectively vacating the regulations that implemented Step 2 of the EPA's GHG Tailoring Rule. Coalition for Responsible Regulation v. EPA, 606 F. App'x. 6, at 7-8 (D.C. Cir. April 10, 2015) (Amended Judgment). With respect to PSD, Step 2 applied to sources that emitted only GHGs at or above the thresholds triggering the requirement to obtain a PSD permit. The Amended Judgment preserves, without the need for additional rulemaking by the EPA, the application of the BACT requirement to GHG emissions from Step 1 or “anyway sources.” With respect to PSD Step 2 sources, the D.C. Circuit's Amended Judgment vacated the regulations at issue in the litigation, including 40 CFR 51.166(b)(48)(v) and 52.21(b)(49)(v), “to the extent they require a stationary source to obtain a PSD permit if greenhouse gases are the only pollutant (i) that the source emits or has the potential to emit above the applicable major source thresholds, or (ii) for which there is a significant emission increase from a modification.” The Amended Judgment further ordered that: “the regulations under review be vacated to the extent they require a stationary source to obtain a title V permit solely because the source emits or has the potential to emit greenhouse gases above the applicable major source thresholds.”

In accordance with the D.C. Circuit's Amended Judgment, on August 19, 2015 (80 FR 50199), the EPA published a final rulemaking titled: “Prevention of Significant Deterioration and Title V Permitting for Greenhouse Gases: Removal of Vacated Elements.” In this rulemaking, the EPA removed GHG Tailoring Rule Step 2 PSD permitting requirements in 40 CFR 51.166(b)(48)(v) and 40 CFR 52.21(b)(49)(v) from the CFR.

As mentioned, the Amended Judgment specifically ordered that certain EPA regulations under review (including 40 CFR 51.166(b)(48)(v) and 52.21(b)(49)(v)) be vacated. In the EPA's final rulemaking titled “Prevention of Significant Deterioration and Title V Permitting for Greenhouse Gases: Removal of Certain Vacated Elements,” which was published on August 19, 2015 (80 FR 50199), we state:

EPA further states:

South Dakota's PSD preconstruction permitting program consists of sections 74-36-09-01 through 74-36-09-03. The State's submittal incorporated by reference as of October 23, 2015, the revisions to remove the GHG Tailoring Rule Step 2 PSD permitting requirements in 40 CFR 52.21(b)(49)(v) from their state implementation plan (SIP) in 74:36:09:02(7)-(9) (removing 40 CFR 52.21(b)(49)(v) as well as the references to 40 CFR 52.21(b)(49)(v)). These revisions were approved in 81 FR 70626 and published on October 13, 2016 (see docket).

In this action we propose to approve two additional revisions contained in the State's 2015 submittal: South Dakota's revision to the definition of “subject to regulation” in 74:36:01:01(73)  1 and the addition of the new provision in 74:36:09-02(10). 2 In our October 13, 2016 action, we did not act on South Dakota's revisions in 74:36:01:01(73) because it revises the definition of “regulated NSR pollutant” and 74:36:09(02)(10) revises language in § 52.21(b)(49)(iv)(b) related to “regulated NSR pollutant.” The EPA determined that it was not appropriate to act on any revisions related to definitions as a result of the court's decision at that time because, as mentioned above, the EPA's final rulemaking titled “Prevention of Significant Deterioration and Title V Permitting for Greenhouse Gases: Removal of Certain Vacated Elements” stated that a future rulemaking will include revisions to additional definitions in the PSD regulations.

On October 3, 2016, the EPA proposed the additional definition revisions in “Revisions to the Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas (GHG) Permitting Regulations and Establishment of a Significant Emissions Rate (SER) for GHG Emissions Under the PSD Program.” 81 FR 68110. In the 2016 action, the EPA proposed to revise certain definitions in the PSD permitting regulations to fully implement the Amended Judgment. Specifically, we proposed the following.

• The first revision would revise the definitions of “major stationary source” and “major modification” by repealing all parts of the definition of “subject to regulation”, except for the first paragraph, which simply serves to codify our interpretation of the term “subject to regulation.” Thus, this rulemaking simply proposed retention of the first paragraph in the definition of “subject to regulation” at 40 CFR 51.166(b)(48) and 52.21(b)(49) and proposed adding a sentence explaining that pollutants subject to regulation include, but are not limited to, greenhouse gases.

• The second revision would establish a freestanding definition of the term “greenhouse gases” at 40 CFR 51.166(b)(31) and 52.21(b)(32). Previously, the definition of this pollutant was located within the definition of “subject to regulation” and the EPA simply proposed to move the language that defined GHGs into an independent definition for the term “greenhouse gases,” including the method to compute tons per year CO 2 equivalent emissions (CO 2 e). We explained that this proposed change to the EPA's definition of GHG in the PSD permitting rules does not change the meaning of the term, as it will be the exact same language as in the existing regulations. 3

Because South Dakota's revisions are consistent with the D.C. Circuit's amended judgement, the EPA's October 3, 2016, proposed rulemaking does not need to be finalized in order for us to approve South Dakota's revisions.

We are proposing approval to the changes in 74:36:01:01(73). Chapter 74:36:01:01 defines the terms used throughout Article 74:36—Air Pollution Control Program. The State updated 74:36:01:01(73) to reflect the D.C. Circuit's Amended Judgment. In particular, South Dakota modified the definition of “subject to regulation” by striking the reference to the definition of “subject to regulation” in the part 70 rules (40 CFR 70.2) and replacing it with: “Subject to regulation means, for any air pollutant, that the pollutant is subject to either a provision in the Clean Air Act, or a nationally-applicable regulation codified by the Administrator in subchapter C of this chapter, that requires actual control of the quantity of emissions of that pollutant, and that such a control requirement has taken effect and is operative to control, limit or restrict the quantity of emissions of that pollutant released from the regulated activity. Greenhouse gases are not subject to regulation unless a PSD preconstruction permit is issued regulating greenhouse gases in accordance with chapter 74:36:09.”

The State's definition of “subject to regulation” retains the first paragraph in § 52.21(b)(49), which codifies the interpretation of the term “subject to regulation,” which has the effect of revising the definitions of “major stationary source” and “major modification.” In adopting only the first paragraph of § 52.21(b)(49), the State's definition excludes the exceptions to the definition of “subject to regulation” provisions in 40 CFR 52.21(b)(49)(i)-(iv). Those provisions are relevant for the PSD program and are found elsewhere in the State's PSD rules. 4 The State also added the following sentence to the end of the definition of “subject to regulation”: “[g]reenhouse gases are not subject to regulation unless a PSD preconstruction permit is issued regulating greenhouse gases accordance with chapter 74:36:09.” We propose to approve this additional sentence because we do not believe it would reduce the stringency of the SIP definition of “subject to regulation,” as compared to the revised definitions in our “Prevention of Significant Deterioration and Title V Permitting for Greenhouse Gases: Removal of Vacated Elements” rulemaking, and because it is consistent with the Amended Judgment.

Additionally, the State's revision to 74:36:01:01(73) removed and replaced the reference in that section to the definition of “subject to regulation” in 40 CFR 70.2, which we propose to approve in light of the Amended Judgment, which, in effect, ordered the vacatur of the requirement in the part 70 regulations that a stationary source obtain a title V permit solely because it emits or has the potential to emit GHGs above the title V major source threshold. This modification is approvable because it is consistent with the Amended Judgment, which describes the CAA permitting authority regarding GHG emissions, and thus we do not believe it would reduce the stringency of the definition in the SIP compared with the federal definitions of “subject to regulation” found in § 51.166(b)(48), § 52.21(b)(49), and § 70.2.

We are proposing approval to the addition of 74:36:09:02(10). Chapter 74:36:09 is South Dakota's PSD preconstruction program for major sources located in areas of the State that are designated attainment for the federal national ambient air quality standards (NAAQS) identified in 74:36:02, which adopts the EPA's PSD rules in 40 CFR 52.21 by reference, noting certain differences. The EPA approved the PSD preconstruction permitting program in South Dakota's SIP. South Dakota's October 23, 2015 submittal added 74:36:09:02(10) as an additional difference from the federal rules, which states that for the purposes of this section, 40 CFR 52.21(b)(49)(iv)(b), the term “also will have an emissions increase of a regulated NSR pollutant” means “also will have a major modification of a regulated NSR pollutant that is not GHGs.” This provision amends one of the exceptions to the definition of “subject to regulation” in the State's PSD rules (“Beginning January 2, 2011, the pollutant GHGs is subject to regulation if: . . . [t]he stationary source is an existing major stationary source for a regulated NSR pollutant that is not GHGs, and also will have an emissions increase of a regulated NSR pollutant, and an emissions increase of 75,000 tpy CO 2 e or more”). The State's change was not included in either of the EPA's recent actions to amend the PSD applicability rules for GHG emissions (80 FR 50199 and 81 FR 68110, described above). Nevertheless, we propose to approve the change because it is consistent with the intent of our federal rules since the regulatory definition of “major modification” found at [insert either 40 CFR 52.21(b)(2)(i) or South Dakota's equivalent rule provision] is essentially equivalent in meaning to the term “emissions increase” as it is defined at 40 CFR 52.21(b)(49)(iii). This change reflects the D.C. Circuit's Amended Judgment in that 74:36:09:02(10) merely emphasizes that a source has to trigger PSD for a non-GHG pollutant before GHGs can become subject to regulation. This modification is approvable because it does not reduce the stringency of the federal definition of “subject to regulation” found in § 51.166(b)(48) and § 52.21(b)(49).

For the reasons described in section II of this proposed rulemaking, the EPA is proposing to approve the revisions submitted by South Dakota on October 23, 2015, which were not acted on in 81 FR 70626. Our action is based on an evaluation of South Dakota's revisions against the requirements of CAA sections 110(a)(2)(c) and 502(b), and regulatory requirements under 40 CFR 51.160-164, 40 CFR 51.166, 40 CFR 52.21, 40 CFR part 70 and the D.C. Circuit's Amended Judgment.

Under section 110(l) of the CAA, the EPA cannot approve a SIP revision if the revision would interfere with any applicable requirements concerning attainment and reasonable further progress (RFP) toward attainment of the NAAQS, or any other applicable requirement of the Act. In addition, section 110(l) requires that each revision to an implementation plan submitted by a state shall be adopted by the state after reasonable notice and public hearing.

The South Dakota SIP revisions that the EPA proposes to approve do not interfere with any applicable requirements of the Act. The revisions to the Administrative Rules of South Dakota (ARSD) 74:36:09:02(10) and 74:36:01(73) submitted by South Dakota on October 23, 2015, ensure South Dakota's PSD program is in compliance with the federal PSD requirements. Therefore, CAA section 110(l) requirements are satisfied.

In this rule, the EPA proposes to include in a final EPA rule regulatory text that includes incorporation by reference. In accordance with requirements of 1 CFR 51.5, the EPA proposes to incorporate by reference the ARSD rules promulgated in 74:36, as described in section II of this preamble. The EPA has made, and will continue to make, these materials generally available through www.regulations.gov and/or at the EPA Region 8 Office (please contact the person identified in the For Further Information Contact section of this preamble for more information).

Under the CAA, the Administrator is required to approve a SIP submission that complies with the provisions of the Act and applicable federal regulations. 42 U.S.C. 7410(k); 40 CFR 52.02(a). Thus, in reviewing SIP submissions, the EPA's role is to approve state choices, provided that they meet the criteria of the CAA. Accordingly, this action merely proposes to approve state law as meeting federal requirements and does not impose additional requirements beyond those imposed by state law. For that reason, this action:

• Is not a “significant regulatory action” subject to review by the Office of Management and Budget under Executive Orders 12866 (58 FR 51735, October 4, 1993) and 13563 (76 FR 3821, January 21, 2011);

• Is not an Executive Order 13771 (82 FR 9339, February 2, 2017) regulatory action because SIP approvals are exempted under Executive Order 12866;

• Does not impose an information collection burden under the provisions of the Paperwork Reduction Act (44 U.S.C. 3501 et seq. );

• Is certified as not having a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601 et seq. );

• Does not contain any unfunded mandate or significantly or uniquely affect small governments, as described in the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-4);

• Does not have federalism implications as specified in Executive Order 13132 (64 FR 43255, August 10, 1999);

• Is not an economically significant regulatory action based on health or safety risks subject to Executive Order 13045 (62 FR 19885, April 23, 1997);

• Is not a significant regulatory action subject to Executive Order 13211 (66 FR 28355, May 22, 2001);

• Is not subject to requirements of section 12(d) of the National Technology Transfer and Advancement Act of 1995 (15 U.S.C. 272 note) because application of those requirements would be inconsistent with the CAA; and

• Does not provide the EPA with the discretionary authority to address, as appropriate, disproportionate human health or environmental effects, using practicable and legally permissible methods, under Executive Order 12898 (59 FR 7629, February 16, 1994).

In addition, the SIP is not approved to apply on any Indian reservation land or in any other area where the EPA or an Indian tribe has demonstrated that a tribe has jurisdiction. In those areas of Indian country, the proposed rule does not have tribal implications and will not impose substantial direct costs on tribal governments or preempt tribal law as specified by Executive Order 13175 (65 FR 67249, November 9, 2000).