80 FR 73647 - Revisions to Emergency Operations Reliability Standards; Revisions to Undervoltage Load Shedding Reliability Standards; Revisions to the Definition of “Remedial Action Scheme” and Related Reliability Standards
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission Federal Register Volume 80, Issue 227 (November 25, 2015)
Federal Energy Regulatory Commission
Federal Register Volume 80, Issue 227 (November 25, 2015)
| Page Range | 73647-73658 | |
| FR Document | 2015-29971 |
[Federal Register Volume 80, Number 227 (Wednesday, November 25, 2015)] [Rules and Regulations] [Pages 73647-73658] From the Federal Register Online [www.thefederalregister.org] [FR Doc No: 2015-29971] ======================================================================= ----------------------------------------------------------------------- DEPARTMENT OF ENERGY Federal Energy Regulatory Commission 18 CFR Part 40 [Docket Nos. RM15-7-000, RM15-12-000, and RM15-13-000 Order No. 818] Revisions to Emergency Operations Reliability Standards; Revisions to Undervoltage Load Shedding Reliability Standards; Revisions to the Definition of ``Remedial Action Scheme'' and Related Reliability Standards AGENCY: Federal Energy Regulatory Commission, Department of Energy. ACTION: Final rule. ----------------------------------------------------------------------- SUMMARY: The Commission approves Reliability Standards and definitions of terms submitted in three related petitions by the North American Electric Reliability Corporation (NERC), the Commission-approved Electric Reliability Organization. The Commission approves Reliability Standards EOP-011-1 (Emergency Operations) and PRC-010-1 (Undervoltage Load Shedding). The proposed Reliability Standards consolidate, streamline and clarify the existing requirements of certain currently- effective Emergency Preparedness and Operations (EOP) and Protection and Control (PRC) standards. The Commission also approves NERC's revised definition of the term Remedial Action Scheme as set forth in the NERC Glossary of Terms Used in Reliability Standards, and modifications of specified Reliability Standards to incorporate the revised definition. Further, the Commission approves the implementation plans, and the retirement of certain currently-effective Reliability Standards. DATES: This rule will become effective January 25, 2016. FOR FURTHER INFORMATION CONTACT: Juan Villar (Technical Information), Office of Electric Reliability, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (772) 678-6496, [email protected]. Nick Henery (Technical Information), Office of Electric Reliability, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-8636, [email protected]. Mark Bennett (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-8524, [email protected]. SUPPLEMENTARY INFORMATION: Order No. 818 Final Rule (Issued November 19, 2015) 1. Pursuant to section 215 of the Federal Power Act (FPA),\1\ the Commission approves Reliability Standards and definitions of terms submitted in three related petitions by the North American Electric Reliability Corporation (NERC), the Commission-approved Electric Reliability Organization (ERO). In particular, the Commission approves Reliability Standards EOP-011-1 (Emergency [[Page 73648]] Operations) and PRC-010-1 (Undervoltage Load Shedding). The Commission finds that the Reliability Standards consolidate, streamline, and clarify the existing requirements of several currently-effective Emergency Preparedness and Operations (EOP) and Protection and Control (PRC) standards, and address certain Commission directives set forth in Order No. 693.\2\ --------------------------------------------------------------------------- \1\ 16 U.S.C. 824o. \2\ Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, FERC Stats. and Regs. ] 31,242, order on reh'g, Order No. 693-A, 120 FERC ] 61,053 (2007). --------------------------------------------------------------------------- 2. Further, the Commission approves NERC's revised definition of the term Remedial Action Scheme as set forth in the NERC Glossary of Terms Used in Reliability Standards (NERC Glossary), and modifications of specified Reliability Standards to incorporate the revised definition. Also, the Commission approves the associated implementation plans and assigned violation risk factors and violation severity levels for Reliability Standard EOP-011-1 and Reliability Standard PRC-010-1, as well as the retirement of certain currently-effective Reliability Standards. I. Background 3. Section 215 of the FPA requires a Commission-certified ERO to develop mandatory and enforceable Reliability Standards, subject to Commission review and approval. Once approved, the Reliability Standards may be enforced by the ERO subject to Commission oversight or by the Commission independently. In 2006, the Commission certified NERC as the ERO pursuant to FPA section 215.\3\ --------------------------------------------------------------------------- \3\ North American Electric Reliability Corp., 116 FERC ] 61,062, order on reh'g & compliance, 117 FERC ] 61,126 (2006), aff'd sub nom. Alcoa, Inc. v. FERC, 564 F.3d 1342 (D.C. Cir. 2009). --------------------------------------------------------------------------- 4. On March 16, 2007, the Commission issued Order No. 693, approving 83 of the 107 Reliability Standards filed by NERC, including initial versions of EOP-001, EOP-002, and EOP-003.\4\ In addition, the Commission directed NERC to develop certain modifications to the EOP standards. In Order No. 693, the Commission also approved several Undervoltage Load Shedding (UVLS)-related Reliability Standards, including PRC-010-0, PRC-021-1 and PRC-022-1.\5\ Further, the Commission directed NERC to modify Reliability Standard PRC-010-0 to develop an ``integrated and coordinated'' approach to all protection systems.\6\ In Order No. 693, the Commission approved the NERC Glossary, including NERC's currently-effective Special Protection System and Remedial Action Scheme definitions. --------------------------------------------------------------------------- \4\ Order No. 693, FERC Stats. and Regs. ] 31,242. \5\ Id. PP 1509, 1560, and 1565. The Commission neither approved nor rejected proposed Reliability Standard PRC-020-1, explaining that the standard only applied to Regional Reliability Organizations. Id. P 1555. \6\ Id. P 1509. --------------------------------------------------------------------------- II. NERC Petitions 5. NERC submitted three related petitions that we address together in this Final Rule.\7\ --------------------------------------------------------------------------- \7\ Reliability Standards EOP-011-1 and PRC-010-1 are not attached to this Final Rule, nor are the additional Reliability Standards that NERC proposes to modify to incorporate the term Remedial Action Scheme. The Reliability Standards are available on the Commission's eLibrary document retrieval system in the identified dockets and on the NERC Web site, www.nerc.com. --------------------------------------------------------------------------- A. NERC EOP Petition--Reliability Standard EOP-011-1 (Docket No. RM15- 7-000) 6. On December 29, 2014, NERC filed a petition seeking Commission approval of Reliability Standard EOP-011-1, a revised definition of ``Energy Emergency'' and the associated violation risk factors and violation severity levels, effective date and implementation plan. NERC stated that the purpose of Reliability Standard EOP-011-1 is ``to address the effects of operating Emergencies by ensuring each Transmission Operator and Balancing Authority has developed Operating Plans to mitigate operating Emergencies, and that those plans are coordinated within a Reliability Coordinator area.'' \8\ NERC explained that Reliability Standard EOP-011-1 consolidates the requirements of three existing standards: EOP-001-2.1b, EOP-002-3.1 and EOP-003-2 ``into a single Reliability Standard that clarifies the critical requirements for Emergency Operations while ensuring strong communication and coordination across the functional entities.'' \9\ NERC also asserted that Reliability Standard EOP-011-1 satisfies seven Commission directives set forth in Order No. 693.\10\ --------------------------------------------------------------------------- \8\ NERC EOP Petition at 2. \9\ Id. at 3. \10\ Id. at 12-18. --------------------------------------------------------------------------- 7. NERC noted that Reliability Standard EOP-011-1, Requirements R2 and R6 incorporate Attachment 1, which describes three Energy Emergency levels used by the reliability coordinator and the process for communicating the condition of a balancing authority experiencing an Energy Emergency.\11\ --------------------------------------------------------------------------- \11\ Attachment 1 describes three alert levels: Energy Emergency Alert Level 1 (all available generation resources in use, concern about sustaining required contingency reserves); Energy Emergency Alert Level 2 (load management procedures in effect, energy deficient balancing authority implements its emergency Operating Plan but maintains minimum contingency reserve requirements); and Energy Emergency Alert Level 3 (firm load interruption is imminent or in process, energy deficient balancing authority unable to maintain minimum contingency reserve requirements). --------------------------------------------------------------------------- 8. Reliability Standard EOP-011-1 includes six requirements, and is applicable to balancing authorities, reliability coordinators and transmission operators. Requirement R1 requires transmission operators to develop, maintain and implement reliability coordinator-reviewed operating plans to mitigate operating emergencies in its ``transmission operating area.'' \12\ Requirement R1 provides that, ``as applicable,'' operating plans must: (1) Describe the roles and responsibilities for activating the operating plan; and (2) include processes to prepare for and mitigate emergencies, such as Reliability Coordinator notification, transmission system reconfiguration, and redispatch of generation. NERC explained that Requirement R1 uses the phrase ``as applicable'' to provide ``flexibility to account for regional differences and pre- existing methods for mitigating emergencies.'' \13\ NERC added that an entity's decision to omit an element as not ``applicable'' must include an explanation in its plan. NERC further explained that the requirement for transmission operators to maintain operating plans includes the expectation that the plans are current and up-to-date.\14\ --------------------------------------------------------------------------- \12\ Operating Plan is defined in the NERC Glossary as a ``document that identifies a group of activities that may be used to achieve some goal. An Operating Plan may contain Operating Procedures and Operating Processes . . .'' \13\ NERC EOP Petition at 9. \14\ Id. at 8-9. --------------------------------------------------------------------------- 9. Requirement R2 requires balancing authorities to develop, maintain and implement reliability coordinator-reviewed operating plans to mitigate capacity and energy emergencies in its ``balancing authority area.'' Similar to the operating plans developed by transmission operators pursuant to the first requirement, the elements of the operating plans developed by balancing authorities allow for flexibility, provided an explanation is provided for omitted elements.\15\ --------------------------------------------------------------------------- \15\ Id. --------------------------------------------------------------------------- 10. Requirement R3 requires reliability coordinators to review the operating plans submitted by transmission operators and balancing authorities and is designed to ensure that there is appropriate coordination of reliability risks identified in the operating plans. In reviewing operating plans, reliability coordinators shall consider compatibility, coordination [[Page 73649]] and inter-dependency with other entity operating plans and notify transmission providers and balancing authorities if revisions to their operating plans are necessary.\16\ --------------------------------------------------------------------------- \16\ Id. at 10-11. --------------------------------------------------------------------------- 11. Requirement R4 requires transmission operators and balancing authorities to resolve any issues identified by the reliability coordinator and resubmit their revised operating plans within a time period specified by the reliability coordinator. Requirement R5 requires reliability coordinators to notify balancing authorities and transmission operators in its area, and neighboring reliability coordinators, within 30 minutes of receiving an emergency notification. Requirement R6 requires a reliability coordinator with a balancing authority experiencing a potential or actual Energy Emergency to declare an Energy Emergency alert in accordance with Attachment 1. 12. Proposed Reliability Standard EOP-011-1 also includes the following revised definition of Energy Emergency: Energy Emergency--A condition when a Load-Serving Entity or Balancing Authority has exhausted all other resource options and can no longer meet its expected Load obligations. NERC explained that the revised definition is intended to clarify that an Energy Emergency is not limited to a load-serving entity and, based on a review of the impact on the body of NERC Reliability Standards, ``does not change the reliability intent of other requirements of Definitions.'' \17\ \17\ Id. at 18. --------------------------------------------------------------------------- 13. NERC proposed an effective date for Reliability Standard EOP- 011-1 that is the first day of the first calendar quarter that is 12 months after the date of Commission approval, and a retirement date for currently-effective Reliability Standards EOP-001-2.1b, EOP-002-3.1 and EOP-003-2 of midnight of the day immediately prior to the effective date of Reliability Standard EOP-011-1. B. NERC PRC Petition--Proposed Reliability Standard PRC-010-1 (Docket No. RM15-12-000) 14. On February 6, 2015, NERC filed a petition seeking approval of Reliability Standard PRC-010-1 (Undervoltage Load Shedding), a revised definition of Undervoltage Load Shedding Program (UVLS Program) for inclusion in the NERC Glossary, and the associated violation risk factors, violation severity levels, effective date and implementation plan. NERC also proposed the retirement of four PRC Reliability Standards.\18\ NERC stated that the purpose of Reliability Standard PRC-010-1 is to ``establish an integrated and coordinated approach to the design, evaluation, and reliable operation of Undervoltage Load Shedding Programs'' as directed by the Commission in Order No. 693.\19\ --------------------------------------------------------------------------- \18\ Reliability Standards PRC-010-0 (Assessment of the Design and Effectiveness of UVLS Program); PRC-020-1 (Under-Voltage Load Shedding Program Database); PRC-021-1 (Under-Voltage Load Shedding Program Data); and PRC-022-1 (Under-Voltage Load Shedding Program Performance). \19\ NERC PRC Petition at 14 (citing Order No. 693, FERC Stats & Regs ] 31,242 at P 1509). --------------------------------------------------------------------------- 15. NERC explained that Reliability Standard PRC-010-1 is a single, comprehensive standard that addresses the same reliability principles outlined in the four currently-effective UVLS-related Reliability Standards.\20\ Reliability Standard PRC-010-1 replaces the applicability to and involvement of ``Regional Reliability Organization'' in Reliability Standards PRC-020-1 and PRC-021-1 and improves upon and consolidates the four currently-effective UVLS- Related Standards into one comprehensive standard. NERC explained that Reliability Standard PRC-010-1 ``reflects consideration of the 2003 Blackout Report recommendations,'' \21\ particularly, Recommendation 21 for NERC to ``make more effective and wider use of system protection measures'' \22\ and Recommendation 21C for NERC to ``determine the goals and principles needed to establish an integrated approach to relay protection for generators and transmission lines, as well as of UFLS and UVLS programs.'' \23\ --------------------------------------------------------------------------- \20\ Id. \21\ Id. at 2 (citing the U.S.-Canada Power System Outage Task Force, Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations, April, 2004 (2003 Blackout Report)). \22\ Id. at 4 (citing 2003 Blackout Report at 3, 158). \23\ Id. at 6. --------------------------------------------------------------------------- 16. Reliability Standard PRC-010-1 incorporates a new definition of UVLS Program, which reads: Undervoltage Load Shedding Program (UVLS Program): An automatic load shedding program, consisting of distributed relays and controls, used to mitigate undervoltage conditions impacting the Bulk Electric System (BES), leading to voltage instability, voltage collapse, or Cascading. Centrally controlled undervoltage-based load shedding is not included. NERC explained that ``to ensure that the applicability of the proposed Reliability Standard covers undervoltage[hyphen]based load shedding systems whose performance has an impact on system reliability, a UVLS Program must mitigate risk of one or more of the following: Voltage instability, voltage collapse, or Cascading impacting the Bulk Electric System. By focusing on the enumerated risks, the definition is meant to exclude locally[hyphen]applied relays that are not designed to mitigate wide[hyphen]area voltage collapse.'' \24\ NERC stated that the UVLS Program definition ``clearly identifies and separates centrally controlled undervoltage-based load shedding, which is now addressed by the proposed definition of Remedial Action Scheme.'' \25\ \24\ Id. at 16. \25\ Id. at 15. NERC's petition for approval of the proposed definition of Remedial Action Scheme (Docket No. RM15-13-000) is discussed below. --------------------------------------------------------------------------- 17. Reliability Standard PRC-010-1 applies to planning coordinators and transmission planners because ``either may be responsible for designing and coordinating the UVLS Program . . . [and] also applies to Distribution Providers and Transmission Owners responsible for the ownership, operation and control of UVLS equipment as required by the UVLS Program established by the Transmission Planner or Planning Coordinator.'' \26\ NERC explained that the planning coordinator or transmission planner that establishes a UVLS Program is responsible for identifying the UVLS equipment and the necessary distribution provider and transmission owner (referred to as ``UVLS entities'' in the Applicability section) that performs the required actions. --------------------------------------------------------------------------- \26\ Id. --------------------------------------------------------------------------- 18. NERC stated that Reliability Standard PRC-010-1 ``applies only after an entity has determined the need for a UVLS Program as a result of its own planning studies.'' \27\ NERC explained that the eight requirements in Reliability Standard PRC-010-1 meet four primary objectives: (1) The Reliability Standard requires applicable entities to evaluate a UVLS Program's effectiveness prior to implementation, including coordination with other protection systems and generator voltage ride-through capabilities; (2) applicable entities must comply with UVLS program specifications and implementation schedule; (3) applicable entities must perform periodic assessment and performance analysis; and (4) applicable entities must maintain and share UVLS Program data.\28\ --------------------------------------------------------------------------- \27\ Id. at 14. \28\ Id. at 17. --------------------------------------------------------------------------- 19. Requirement R1 requires each planning coordinator or transmission planner to evaluate the viability and effectiveness of its UVLS program before implementation to confirm its effectiveness in resolving the undervoltage conditions for which it [[Page 73650]] was designed, and that it is integrated through coordination with generator ride-through capabilities and other protection and control systems. Also, the planning coordinator or transmission planner must provide the UVLS Program specifications and implementation schedule to the applicable UVLS entities. Requirement R2 requires UVLS entities to meet the UVLS Program's specifications and implementation schedule provided by the planning coordinator or transmission planner or address any necessary corrective actions in accordance with Requirement R5. 20. Requirement R3 requires each planning coordinator or transmission planner to perform periodic comprehensive assessments at least every 60 calendar months to ensure continued effectiveness of the UVLS program, including whether the program resolves identified undervoltage issues and that it is integrated and coordinated with generator voltage ride-through capabilities and other specified protection and control systems. Requirement R4 requires each planning coordinator or transmission planner to commence a timely assessment of a voltage excursion subject to the UVLS Program, within 12 calendar months of the event, to evaluate whether the UVLS Program resolved the undervoltage issues associated with the event. Requirement R5 requires a corrective action plan for any program deficiencies identified during an assessment performed under either Requirement R3 or R4, and provide an implementation schedule to UVLS entities within three calendar months of its completion. 21. Pursuant to Requirement R6, a planning coordinator must update the data necessary to model its UVLS Program for use in event analyses and program assessments at least each calendar year. Requirement R7 requires each UVLS entity to provide data to its planning coordinator, according to the planning coordinator's format and schedule, to support maintenance of the UVLS Program database. Requirement R8 requires a planning coordinator to provide its UVLS Program database to other planning coordinators and transmission planners within its Interconnection, and other functional entities with a reliability need, within 30 calendar days of a written request. 22. NERC proposed an effective date for Reliability Standard PRC- 010-1 and the definition of UVLS Program of the first day of the first calendar quarter that is 12 months after the date that the standard and definition are approved by the Commission. NERC proposed to retire PRC- 010-0, PRC-020-1, PRC-021-1, and PRC-022-1 at midnight of the day immediately prior to the effective date of PRC-010-1.\29\ Further, NERC explained that Reliability Standard PRC-010-1 addresses reliability obligations that are set forth in Requirements R2, R4 and R7 of currently-effective Reliability Standard EOP-003-2.\30\ Since NERC has proposed to retire EOP-003-2 in the petition seeking approval of Reliability Standard EOP-011-1 (Docket No. RM15-7-00, discussed above), concurrent Commission action on the two petitions will prevent a possible reliability gap. --------------------------------------------------------------------------- \29\ Id. Ex. B (Implementation Plan). \30\ Id. at 23. --------------------------------------------------------------------------- C. NERC RAS Petition--Revisions to the Definition of ``Remedial Action Scheme'' (Docket No. RM15-13-000) 23. On February 3, 2015, NERC filed a petition seeking approval of a revised definition of Remedial Action Scheme in the NERC Glossary, as well as modified Reliability Standards that incorporate the new Remedial Action Scheme definition and eliminate use of the term Special Protection System, and the associated implementation plan.\31\ NERC stated that the defined terms Special Protection System and Remedial Action Scheme are currently used interchangeably throughout the NERC Regions and in various Reliability Standards. NERC explained that ``[a]lthough these defined terms share a common definition in the NERC Glossary of Terms today, their use and application have been inconsistent as a result of a lack of granularity in the definition and varied regional uses of the terms. The proposed revisions add clarity and granularity that will allow for proper identification of Remedial Action Schemes and a more consistent application of related Reliability Standards.'' \32\ --------------------------------------------------------------------------- \31\ NERC RAS Petition at 1-2. NERC requested approval of the following Reliability Standards to incorporate the proposed definition of Remedial Action Scheme and eliminate use of the term Special Protection System: EOP-004-3, PRC-005-3(ii), PRC-023-4, FAC- 010-3, TPL-001-0.1(i), FAC-011-3, TPL-002-0(i)b, MOD-030-3, TPL-003- 0(i)b, MOD-029-2a, PRC-015-1, TPL-004-0(i)a, PRC-004-WECC-2, PRC- 016-1, PRC-001-1.1(i), PRC-005-2(ii), PRC-017-1. NERC did not propose any changes to the Violation Risk Factors or Violation Severity Levels for the modified standards. \32\ Id. at 4-5. --------------------------------------------------------------------------- 24. NERC explained that the revised Remedial Action Scheme definition consists of a ``core'' definition, including a list of objectives and a separate list of exclusions for certain schemes or systems not intended to be covered by the revised definition.\33\ NERC stated that a broad definition is needed because of ``all the possible scenarios an entity may develop'' for its Remedial Action Scheme and a ``very specific, narrow definition may unintentionally exclude schemes that should be covered.'' \34\ Accordingly, NERC proposed the following revised ``core'' definition of Remedial Action Scheme: --------------------------------------------------------------------------- \33\ Id. at 16. NERC noted that ``for each exclusion, the scheme or system could still classify as a Remedial Action Scheme if employed in a broader scheme that meets the definition of Remedial Action Scheme.'' \34\ Id. at 17. A scheme designed to detect predetermined system conditions and automatically take corrective actions that may include, but are not limited to, adjusting or tripping generation (MW and Mvar), tripping load, or reconfiguring a System(s). (sic) RAS accomplish objectives such as:Meet requirements identified in the NERC Reliability Standards; Maintain Bulk Electric System (BES) stability; Maintain acceptable BES voltages; Maintain acceptable BES power flows; Limit the impact of Cascading or extreme events. The definition then lists fourteen exclusions, describing specific schemes and systems that do not constitute a Remedial Action Scheme, because each is either a protection function, a control function, a combination of both, or used for system configuration.\35\ --------------------------------------------------------------------------- \35\ Id. at 18. --------------------------------------------------------------------------- 25. In the implementation plan, NERC proposed an effective date for the revised Reliability Standards and the revised definition of Remedial Action Scheme on the first day of the first calendar quarter that is 12 months after Commission approval.\36\ NERC also proposed that, for entities with existing schemes that become newly classified as ``Remedial Action Schemes'' resulting from the application of the revised definition, the entities will have additional time of up to 24 months from the effective date to be fully compliant with all applicable Reliability Standards.\37\ Further, NERC asked the Commission to take final action concurrently with the NERC petition on proposed Reliability Standard PRC-010-1 (Docket No. RM15-12-000) because ``[t]he proposed definitions of UVLS Program and Remedial Action Scheme in each project have been coordinated to cover centrally controlled UVLS as a Remedial Action Scheme. Final action by the Commission is needed [[Page 73651]] contemporaneously on both petitions to facilitate implementation and avoid a gap in coverage of centrally controlled UVLS.'' \38\ --------------------------------------------------------------------------- \36\ NERC RAS Petition, Ex. C (Implementation Plan) at 4. \37\ Id. \38\ NERC RAS Petition at 3-4. --------------------------------------------------------------------------- III. Notice of Proposed Rulemaking 26. On June 18, 2015, the Commission issued a Notice of Proposed Rulemaking (NOPR) proposing to approve the Reliability Standards and NERC Glossary definitions set forth in NERC's three petitions pertaining to EOP-011-1, PRC-010-1 and a revised definition of Remedial Action Scheme as just, reasonable, not unduly discriminatory or preferential and in the public interest. \39\ The Commission also proposed to approve the related violation risk factors, violation severity levels and implementation plans. --------------------------------------------------------------------------- \39\ Revisions to Emergency Operations Reliability Standards; Revisions to Undervoltage Load Shedding Reliability Standards; Revisions to the Definition of ``Remedial Action Scheme'' and Related Reliability Standards, Notice of Proposed Rulemaking, 80 FR 36,293 (June 24, 2015), 151 FERC ] 61,230 (2015) (NOPR). --------------------------------------------------------------------------- 27. The Commission proposed to approve the retirement of Reliability Standards EOP-001-2.1b, EOP-002-3.1, EOP-003-2, PRC-010-0, PRC-020-1 and PRC-021-1. However, the Commission expressed concerns about whether it was appropriate to retire PRC-022-1 before a replacement Reliability Standard is approved and implemented to address the potential misoperation of UVLS equipment. Accordingly, the Commission proposed to deny NERC's request to retire Reliability Standard PRC-022-1 concurrent with the effective date of PRC-010-1. 28. In the NOPR, the Commission stated that Reliability Standards EOP-011-1 and PRC-010-1 provide greater clarity and that the consolidation of currently-effective EOP and PRC standards provides additional efficiencies for responsible entities. The Commission also agreed with NERC that the new definition of Remedial Action Scheme will improve reliability by eliminating ambiguity and encouraging the consistent identification of Remedial Action Schemes and a more consistent application of related Reliability Standards. 29. While the Commission proposed to approve Reliability Standard PRC-010-1, the Commission raised questions and sought clarification regarding an example of a ``BES subsystem'' that NERC provided in the ``Guidelines for UVLS Program Definition.'' The Commission indicated that, depending on the response from NERC and others, a directive for further modification may be appropriate.\40\ --------------------------------------------------------------------------- \40\ NOPR, 151 FERC ] 61,230 at P 27. --------------------------------------------------------------------------- 30. In response to the NOPR, the Commission received comments from: NERC, Edison Electric Institute (EEI), Peak Reliability, Transmission Access Policy Study Group (TAPS), International Transmission Company (ITC), Louisville Gas and Electric Company and Kentucky Utilities Company (LG&E/KU) and Idaho Power Company (Idaho Power). IV. Discussion 31. Pursuant to FPA section 215(d)(2), we approve Reliability Standards EOP-011-1 and PRC-010-1, the revised definition of Remedial Action Scheme and NERC Glossary definitions, and associated violation risk factors and violation severity levels and implementation plans as just, reasonable, not unduly discriminatory or preferential and in the public interest. The Commission believes that the modified Reliability Standards provide greater clarity, and the consolidated EOP and PRC standards will provide additional efficiencies for responsible entities. We also determine that Reliability Standard EOP-011-1 adequately addresses seven Order No. 693 directives, and that Reliability Standard PRC-010-1 establishes an integrated and coordinated approach to the design, evaluation and reliable operation of UVLS Programs, and therefore satisfies the Commission directive issued in Order No. 693.\41\ Further, we approve the retirement of certain Reliability Standards as identified by NERC.\42\ --------------------------------------------------------------------------- \41\ Order No. 693, FERC Stats & Regs. ] 31,242 at P 1509. \42\ As noted above, the Commission in Order No. 693 did not approve or remand proposed Reliability Standard PRC-020-1 but, rather, took no action on the Reliability Standard pending the receipt of additional information. Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1555. Our approval of NERC's request renders PRC-020-1 ``retired,'' i.e., withdrawn, and no longer pending before the Commission. --------------------------------------------------------------------------- 32. We discuss below the following issues raised in the NOPR and comments: (1) The deregistration of load-serving entities and Reliability Standard EOP-011-1; (2) the scheduling and scope of reliability coordinator reviews of Operating Plans under Reliability Standard EOP-011-1; (3) the retirement of Reliability Standard PRC-022- 1; (4) the term ``BES subsystem'' and related diagram in NERC's PRC Petition; and (5) other issues raised by commenters. A. Reliability Standard EOP-011-1 1. The Deregistration of Load-Serving Entities NOPR 33. In the NOPR, while proposing to approve Reliability Standard EOP-011-1 and a new Energy Emergency definition, the Commission stated that the removal of load-serving entities from the Reliability Standard raises questions about who would perform the roles traditionally performed by load-serving entities.\43\ The NOPR explained that the Commission's decision concerning NERC's compliance filing in Docket No. RR15-4-000 related to NERC's Risk-Based Registration initiative would guide the Commission's action on this question in this proceeding. --------------------------------------------------------------------------- \43\ NOPR, 151 FERC ] 61,230 at P 24, n.36. Currently effective EOP-002-3.1 applies, inter alia, to load-serving entities. Reliability Standard EOP-011-1 replaces EOP-002-3.1, and applies to balancing authorities, reliability coordinators and transmission operators, but not load-serving entities. --------------------------------------------------------------------------- Comments 34. NERC, EEI, TAPS, ITC and Idaho Power support the Commission's proposed approval of Reliability Standard EOP-011-1. Further, NERC, EEI and TAPS state that excluding load-serving entities from the Reliability Standard will not create a reliability gap. NERC states that currently-effective Reliability Standard EOP-002-3.1 Requirement R9 is the only requirement in the three Reliability Standards being replaced by Reliability Standard EOP-011-1 that applies to load-serving entities. NERC explains that the North American Energy Standards Board (NAESB) has modified the process for E-tag specifications, removing the load-serving entities' role in making changes to the priority of transmission service requests. Therefore, the ``Standard Drafting Team did not incorporate Requirement R9 into Reliability Standard EOP-011-1, because Requirement R9 has become obsolete due to technological changes.'' \44\ --------------------------------------------------------------------------- \44\ NERC Comments at 4. --------------------------------------------------------------------------- 35. Additionally, NERC explains that, due to the Real-time nature of energy emergencies, balancing authorities and distribution providers will handle responsibilities related to Reliability Standard EOP-002- 3.1 that have been performed by load-serving entities. Referring to the Mapping Document and Application Guidelines for Reliability Standard EOP-011-1, NERC states that ``LSEs have no Real-time reliability [[Page 73652]] functionality with respect to EEAs [Energy Emergency Alerts].'' \45\ --------------------------------------------------------------------------- \45\ Id. at 5-6. --------------------------------------------------------------------------- 36. TAPS and EEI agree with NERC's analysis of the roles and responsibilities of load-serving entities and that excluding them will not create any reliability gaps. TAPS states that ``there is no reliability benefit to retaining EOP-002-3.1's Requirement R9, and thus no reliability risk from eliminating the LSE obligation to comply with it.'' \46\ EEI asserts that ``NERC is correct that `tasks currently assigned to the LSE function under NERC Reliability Standards would continue to be performed by other functions subject to currently applicable LSE Reliability Standard Requirements or by market participants (including LSEs) pursuant to existing tariffs, market rules, market protocols and other market agreements.' '' \47\ Regarding Operating Plans that transmission operators and balancing authorities are to develop under Reliability Standard EOP-011-1 Requirements R1 and R2, EEI states that ``it is clear that the responsible entities required to perform the activities attributed to the LSE function necessary to aid in arresting an Energy Emergency must be identified to ensure necessary mitigation can be accomplished in order to ensure reliable operation of the BES.'' \48\ --------------------------------------------------------------------------- \46\ TAPS Comments at 4. \47\ EEI Comments at 5-6, quoting NERC's compliance filing in RR15-4-000 at 1. \48\ Id. at 6. --------------------------------------------------------------------------- 37. LG&E/KU seeks clarification on two questions pertaining to the exclusion of load-serving entities from Reliability Standard EOP-011-1 ``to ensure that even if NERC's EOP proposal is accepted, [balancing authorities] will have a meaningful way of addressing any operational gaps with Energy Emergencies and LSEs.'' \49\ First, LG&E/KU seeks clarification that an Energy Emergency can be isolated to a load- serving entity's inability to meet its own load obligations, as indicated in NERC's revised definition of Energy Emergency. Second, LG&E/KU seeks clarification that Operating Plans developed by balancing authorities may describe the role for load-serving entities in responding to an Energy Emergency, and may include such Operating Plans in applicable tariffs. --------------------------------------------------------------------------- \49\ LG&E/KU Comments at 2. --------------------------------------------------------------------------- Commission Determination 38. Consistent with our determination in the ``risk-based registration'' proceeding, we find that the elimination of load-serving entities from Reliability Standard EOP-011-1 will not prevent the Reliability Standard from achieving its stated purposes or otherwise create reliability gaps.\50\ We find that Reliability Standard EOP-011- 1 enhances reliability by requiring that actions necessary to mitigate capacity and energy emergencies are focused in single operating plans, and ensures communication and coordination among relevant entities during emergency operations. We are persuaded by NERC's explanation that excluding load-serving entities will not adversely impact reliability due to technological changes concerning NAESB tagging specifications, and that load-serving entities ``have no Real-time reliability functionality with respect to EEAs [Energy Emergency Alerts].'' \51\ Further, as both NERC and EEI have stated, ``tasks currently assigned to the LSE function under NERC Reliability Standards would continue to be performed by other functions subject to currently applicable LSE Reliability Standard Requirements or by market participants (including LSEs) pursuant to tariffs, market rules, market protocols and other market agreements.'' \52\ --------------------------------------------------------------------------- \50\ See North American Electric Reliability Corp., 153 FERC ] 61,024, at P 20 (2015) (RBR Compliance Order) (approving the proposed elimination of the load-serving entity function). \51\ NERC Comments at 5, quoting the EOP-011-1 Mapping Document and Application Guidelines. \52\ EEI Comments at 5-6. --------------------------------------------------------------------------- 39. We disagree with LG&E/KU's suggestion that the reference to load-serving entities in NERC's revised definition of Energy Emergency indicates the possibility of an ``operational gap.'' NERC revises the definition of ``Energy Emergency,'' approved in this Final Rule, as ``[a] condition when a Load-Serving Entity or Balancing Authority has exhausted all other resource options and can no longer meet its expected Load obligations.'' \53\ Based on a plain reading of this definition, we agree with LG&E/KU that a load-serving entity's inability to meet its own load obligations could result in an Energy Emergency. Moreover, consistent with our findings in the RBR Compliance Order, we agree with LG&E/KU that operating plans developed by balancing authorities--including operating plans contained in applicable tariffs--may describe the role for load-serving entities in responding to an Energy Emergency.\54\ EEI's observation regarding Reliability Standard EOP-011-1 Requirements R1 and R2 for transmission operators and balancing authorities to develop Operating Plans to mitigate Energy Emergencies reinforces this determination: ``[a]lthough these requirements do not specifically identify the `who' or `what' actions to be taken, it is clear that the responsible entities required to perform the activities attributed to the LSE function necessary to aid in arresting an energy emergency must be identified to ensure necessary mitigation can be accomplished in order to ensure reliable operation of the BES.'' \55\ Accordingly, we conclude that elimination of the load-serving entity function from Reliability Standard EOP-011-1 does not result in an operational gap and, rather, provides a reasonable means of addressing Energy Emergencies. --------------------------------------------------------------------------- \53\ NERC EOP Petition, Ex. B (Implementation Plan) at 1. \54\ RBR Compliance Order, 153 FERC ] 61,024 at 21. \55\ EEI Comments at 6. --------------------------------------------------------------------------- 2. The Scheduling and Scope of Reliability Coordinator Reviews of Operating Plans 40. Reliability Standard EOP-011-1, Requirement R3 obligates a reliability coordinator to review the Operating Plan(s) to mitigate operating emergencies submitted by a transmission operator or a balancing authority. Pursuant to Requirement R3.1, a reliability coordinator must, within 30 days of receipt, (i) review each Operating Plan for compatibility and inter-dependency with other transmission operator or balancing authority Operating Plans, (ii) review each Operating Plan for coordination to avoid risk to ``Wide Area'' reliability, and (iii) notify each transmission operator and balancing authority of the results of the review. Comments 41. Peak Reliability asserts that the ``inflexible'' 30 day period for reliability coordinator reviews of operating plans in Reliability Standard EOP-011-1 Requirement R3.1 is not reasonable. According to Peak Reliability, because transmission operators have an ``open ended'' opportunity to submit operating plans under the provision, reliability coordinators cannot schedule in advance the needed resources to perform a proper review in the 30-day window. Peak Reliability notes that, in its experience, many entities update their plans at the end of the year, creating a large spike in review work at that time. Peak Reliability, therefore, recommends revising Requirement R3.1 to include language requiring ``a mutually agreed predetermined schedule'' to ensure that the reliability coordinator can efficiently allocate its [[Page 73653]] resources and provide a thorough review of submitted operating plans.\56\ --------------------------------------------------------------------------- \56\ Peak Reliability Comments at 6-7. --------------------------------------------------------------------------- 42. Peak Reliability also seeks clarification regarding the scope of reliability coordinator review of operating plans, and whether a reliability coordinator must review each required element of an operating plan specified in Requirement R2 for ``compatibility and interdependency'' with other balancing authority and transmission operator operating plans, or ``evaluate these elements on a higher level.'' \57\ Peak Reliability asserts that the ``appropriate level of review'' by reliability coordinators is ``for coordination to avoid risk to Wide Area reliability.'' Based on this assertion, Peak Reliability recommends that Reliability Standard EOP-011-1 require balancing authorities and transmission operators to identify and coordinate possible operating plan discrepancies before submission for reliability coordinator review, as currently required under Reliability Standard EOP-001-2.1b Requirement R6.\58\ --------------------------------------------------------------------------- \57\ Id. at 7. \58\ Id. at 7-8. --------------------------------------------------------------------------- Commission Determination 43. We are not persuaded by Peak Reliability's comments that the 30 day review period in Requirement R3.1 is unduly onerous. No reliability coordinator other than Peak Reliability expressed concern about the 30 day review period for operating plans in Requirement R3.1. NERC explains that transmission operators and balancing authorities must update their operating plans on an ``ongoing and as-needed basis.'' \59\ The need for registered entities to update operating plans to address evolving bulk electric system conditions should prevent reliability coordinators from being overwhelmed or unduly burdened by operating plan submissions. However, if Peak Reliability experiences an ``end of the year spike in workload,'' \60\ as a reliability coordinator, Peak Reliability can adjust its resource allocation to accommodate such known ``spikes'' in activity. Accordingly, we conclude the 30 day review period in Requirement R3.1 is reasonable and reject Peak Reliability's recommendation for language requiring a ``mutually agreed predetermined schedule.'' --------------------------------------------------------------------------- \59\ See NERC EOP Petition at 9. \60\ See Peak Reliability Comments at 5-6. --------------------------------------------------------------------------- 44. Additionally, we believe that Peak Reliability's concern regarding the extent of reliability coordinator Operating Plan review for ``compatibility and interdependency'' under Reliability Standard EOP-011-1 Requirement 3.1.1 is misplaced. Based on the record before us, particularly the Standard Drafting Team's decision to require reliability coordinators to review rather than approve operating plans, and the ongoing nature of emergency planning, we conclude that Requirement R3.1.1 contemplates high level assessments focused on the coordination of operating plans between and among transmission operators and balancing authorities.\61\ Moreover, while Peak Reliability may request that NERC (e.g., through a standard authorization request or ``SAR'') include a provision in EOP-011-1 to require coordination among transmission operators and balancing authorities prior to submitting an operating plan for reliability coordinator review, we are not persuaded to direct NERC to develop such a provision. --------------------------------------------------------------------------- \61\ See NERC EOP Petition, Exhibit G (Summary of Development History and Complete Record of Development) at 1166 (the Standard Drafting Team indicates that the provision is intended to require the reliability coordinator review of deficiencies, inconsistencies or conflicts between operating plans that would cause further system degradation during emergency conditions). --------------------------------------------------------------------------- B. Reliability Standard PRC-010-1 1. Retirement of Reliability Standard PRC-022-1 NOPR 45. In the NOPR, while proposing to approve Reliability Standard PRC-010-1 and the retirement of PRC-010-0, PRC-020-1 and PRC-021-1, the Commission was not persuaded that Reliability Standard PRC-010-1, Requirement R4 is an adequate replacement for currently-effective PRC- 022-1, which contains requirements specifically addressing misoperations. Rather, the Commission proposed that Reliability Standard PRC-022-1 would remain in effect until an acceptable replacement Reliability Standard is in place to address the potential misoperation of UVLS equipment. Comments 46. NERC states that, on June 9, 2015, it filed proposed Reliability Standards PRC-010-2 and PRC-004-5 as part of its UVLS Phase II Petition (Project 2008-02.2), which includes requirements and applicability criteria related to UVLS misoperations.\62\ NERC explains that its filing requests that the Commission approve Reliability Standards PRC-004-5 and PRC-010-2 concurrently with the Commission's action on Reliability Standard PRC-010-1 ``to ensure an integrated and coordinated approach to UVLS Programs and fill the gap in Reliability Standard coverage that might be perceived through retirement of PRC- 022-1.'' \63\ EEI agrees, stating that NERC's filing of proposed Reliability Standards PRC-004-5 and PRC-010-2 address the Commission's concerns expressed in the NOPR.\64\ --------------------------------------------------------------------------- \62\ Petition of the North American Electric Reliability Corporation for Approval of Proposed Reliability Standards PRC-004-5 and PRC-010-2, (Docket No. RD15-5-000). \63\ NERC Comments at 8. \64\ EEI Comments at 7. --------------------------------------------------------------------------- Commission Determination 47. We agree with NERC and EEI that the Delegated Letter Order approval of Reliability Standards PRC-004-5 and PRC-010-2 in Docket No. RD15-5-000 concurrent with this Final Rule precludes the need to retain currently-effective Reliability Standard PRC-022-1.\65\ Accordingly, we find that Reliability Standard PRC-022-1 can be retired without creating a gap in coverage with regard to UVLS protective relay misoperations and equipment performance evaluations. --------------------------------------------------------------------------- \65\ See Delegated Letter Order issued November 19, 2915. --------------------------------------------------------------------------- 2. The Term ``BES Subsystem'' and Related Diagram NOPR 48. In the NOPR, the Commission sought clarification of the meaning of NERC's use of the term ``BES subsystem'' in a diagram illustrating a UVLS system that would not be included in the definition of UVLS Program if the consequences of the contingency do not impact the bulk electric system, and whether it would be considered a Remedial Action Scheme.\66\ --------------------------------------------------------------------------- \66\ See NOPR, 151 FERC ] 61,230 at P 27 (including diagram). --------------------------------------------------------------------------- Comments 49. NERC comments that the term ``BES subsystem'' and accompanying diagram are ``intended to demonstrate that whether PRC-010-1 applies to a UVLS system depends on whether the UVLS system is used to mitigate undervoltage conditions impacting areas of the BES, leading to voltage instability, voltage collapse or Cascading.'' \67\ NERC also states that ``the term `BES subsystem' is a shorthand reference to an area of the BES that a Registered Entity is responsible for, consistent with its obligations under mandatory Reliability Standards. This reference does not revise the Commission- [[Page 73654]] approved definition of `Bulk Electric System' or create a new term.'' \68\ --------------------------------------------------------------------------- \67\ NERC Comments at 6-7. \68\ Id. at 7. --------------------------------------------------------------------------- 50. NERC explains that the diagram ``is not intended to necessarily illustrate a centrally controlled UVLS (considered a [Remedial Action Scheme]), but to illustrate how Registered Entities should evaluate whether the term UVLS Program and proposed Reliability Standard PRC- 010-1 applies to a UVLS system.'' \69\ NERC points out that, if a UVLS system in the ``BES subsystem'' is used to mitigate undervoltage conditions impacting the BES (leading to voltage instability, voltage collapse, or Cascading), the system would fall under the new definition of UVLS Program (or RAS if centrally controlled) and thus in the scope of Reliability Standard PRC-010-1.\70\ --------------------------------------------------------------------------- \69\ Id. \70\ Id. --------------------------------------------------------------------------- 51. EEI states that the example of ``BES subsystem'' in the ``Guidelines for UVLS Program Definition'' does not represent a centrally controlled UVLS and therefore would not be considered a Remedial Action Scheme. EEI explains that the term UVLS Program ``is for a scheme that consists of distributed relays and controls, not for a scheme that is centrally controlled. The key point is that for a UVLS system to fall under the definition of Undervoltage Load Shedding Program, it must be used to protect the BES against voltage instability, voltage collapse, or Cascading.'' \71\ EEI also notes that the term ``BES subsystem'' is not intended to be a new NERC term, but rather ``was used in the example to illustrate a possible localized undervoltage contingency on a very small portion of the BES but not a contingency that impacts a larger area of the BES that could result in voltage instability, voltage collapse, or Cascading.'' \72\ --------------------------------------------------------------------------- \71\ EEI Comments at 8. \72\ Id. --------------------------------------------------------------------------- Commission Determination 52. Based on the explanations provided above, we determine that a directive for further modification of the example of ``BES subsystem'' and related diagram in NERC's ``Guidelines for UVLS Program Definition'' to ensure consistency with the Commission-approved definition of ``bulk electric system'' proposed in the NOPR is not necessary. Rather, we are persuaded that EEI's concern with the diagram is addressed by NERC's explanation that, depending on the role of a particular UVLS system, the diagram could illustrate an example of a UVLS Program or a centrally-controlled Remedial Action Scheme.\73\ --------------------------------------------------------------------------- \73\ Id. --------------------------------------------------------------------------- C. Other Issues Raised By Commenters 1. Reliability Standard PRC-010-1--Applicability 53. Peak Reliability asserts that Reliability Standard PRC-010-1 ``does not adequately address the operation of UVLS Programs, as it does not apply to the NERC functional entities that operate the Bulk Electric System,'' particularly, reliability coordinators, transmission operators, and balancing authorities.\74\ Peak Reliability contends that UVLS Programs should be included in operational planning and real- time assessments, and that all entities responsible for operating the bulk electric system must be given access to UVLS Program databases.\75\ Further, Peak Reliability requests that the Commission direct NERC to explain why Reliability Standard PRC-010-1 and Reliability Standard IRO-009-1 apply to different functional entities (since the purpose of both is to prevent instability, uncontrolled separation or cascading outages), and recommends that the treatment of UVLS in operations planning and real-time assessments be addressed.\76\ --------------------------------------------------------------------------- \74\ Peak Reliability Comments at 9. \75\ Id. at 9-10. \76\ Id. at 11-12. --------------------------------------------------------------------------- 54. We are not persuaded by Peak Reliability's assertion that Reliability Standard PRC-010-1 should apply to reliability coordinators, transmission operators, and balancing authorities. Rather, as NERC explains ``[t]he applicability includes both the Planning Coordinator and Transmission Planner because either may be responsible for designing and coordinating the UVLS Program. Reliability Standard PRC-010-1 also applies to Distribution Providers and Transmission Owners responsible for the ownership, operation and control of UVLS equipment as required by the UVLS Program established by the Transmission Planner and Planning Coordinator.'' \77\ As NERC's rationale above indicates, the applicability section of the Reliability Standard identities the functional entities responsible for the design, operation and control of UVLS Programs and related equipment. --------------------------------------------------------------------------- \77\ NERC EOP Petition at 15, and id. Ex. D (Order No. 672 Criteria) at 2-3. --------------------------------------------------------------------------- 55. While Peak Reliability seeks to expand applicability to functional entities so that UVLS Program databases would be shared with reliability coordinators, transmission operators, and balancing authorities, we believe that this need to expand applicability is unfounded. Reliability Standard PRC-010-1, Requirement R8, provides that other functional entities with a reliability need can request UVLS data, and that such requests must be answered in 30 days. 56. Nor are we persuaded by Peak Reliability's argument that UVLS programs should be considered in operations planning and real-time operations. We understand that Peak Reliability refers to the consideration of UVLS programs in the derivation of Interconnection Reliability Operating Limits (IROLs) for Category B contingencies as defined in the currently-effective transmission planning standard TPL- 002-0b (commonly known as N-1 contingencies under normal system operation).\78\ With this understanding, we disagree with Peak Reliability on the relevance of using UVLS in the derivation of IROLs for N-1 contingencies. The 2003 Canada-United States Blackout Report stated that ``[s]afety nets should not be relied upon to establish transfer limits.'' \79\ This statement is consistent with the performance criteria established in TPL-002-0b and TPL-001-4, which generally prohibit the loss of non-consequential load for certain N-1 contingencies.\80\ We conclude that UVLS programs under PRC-010-1 are examples of such ``safety nets'' and should not be tools used by bulk electric system operators to calculate operating limits for N-1 contingencies. Likewise, with this understanding, there is no imperative to make PRC-010-1 applicable to reliability coordinators, transmission operators, and balancing authorities. --------------------------------------------------------------------------- \78\ The Commission-approved Version 4 standard, TPL-001-4, will replace TPL-002-0b on January 1, 2016. See Transmission Planning Reliability Standards, Order No. 786, 145 FERC ] 61,051 (2013). \79\ 2003 Blackout Report at 109. \80\ See TPL-002-0b, Table 1, footnote b and TPL-001-4, Table 1, Footnote 12. --------------------------------------------------------------------------- 57. Peak Reliability comments that Reliability Standard PRC-010-1 ``creates some confusion of the applicability of UVLS Programs due to the similarities, and apparent overlap, in the definitions of UVLS Programs and IROLs.'' \81\ We disagree. Peak Reliability's comparison of UVLS Programs with establishing and operating within IROLs is misplaced because UVLS Programs and IROLs represent separate and distinct approaches to system security. UVLS Programs act as safety nets for contingencies more severe than N-1 contingencies, such as the simultaneous [[Page 73655]] loss of two single circuits or a double-circuit line which are both Category C contingencies permitting loss of non-consequential firm load.\82\ In contrast, the NERC Glossary defines IROLs as ``[a] System Operating Limit that, if violated, could lead to instability, uncontrolled separation, or cascading outages that adversely impact the reliability of the Bulk Electric System.'' This corresponds with the TPL-004-1 provisions requiring that the system must remain stable when experiencing an N-1 contingency (such as Category B or P1 contingencies).\83\ In sum, we disagree with Peak Reliability's premise regarding similarities, and overlaps, in the definition of UVLS programs and IROLs. --------------------------------------------------------------------------- \81\ Peak Reliability Comments at 11. \82\ The TPL Standards require that the system remain stable and that cascading and uncontrolled islanding shall not occur for any Category B or C contingency (i.e., currently-effective TPL Standards, N-1 and N-2 contingencies) or for any Category P1 through P7 contingency (i.e., TPL-001-4, N-1 and N-2 contingencies.) See Table 1 of any of the TPL Standards. \83\ See TPL Standards, Table 1. --------------------------------------------------------------------------- 2. Reliability Standard PRC-010-1 --Appropriate Level of Detail in UVLS Program Assessment 58. Reliability Standard PRC-010-1, Requirements R3, R4, and R5 obligate planning coordinators and transmission planners to perform an assessment of their UVLS program in various circumstances. Idaho Power contends that Reliability Standard PRC-010-1, Requirements R3, R4, and R5, do not ``specifically state what must be included in the assessment, as was included in PRC-022-1 R1.1-4'' and, therefore, do not sufficiently explain what applicable entities must include in UVLS Program assessments.\84\ --------------------------------------------------------------------------- \84\ Idaho Power Comments at 2. --------------------------------------------------------------------------- 59. We disagree with Idaho Power. Reliability Standard PRC-022-1 requires applicable entities to ``analyze and document all UVLS operations and misoperations,'' and specifically mentions set points and tripping times and a summary of the findings. In contrast, Reliability Standard PRC-010-1 Requirement R3, requires planning coordinators and transmission planners to perform comprehensive assessments of their UVLS Programs at least once every 5 years. Each assessment ``shall include, but is not limited to, studies and analyses that evaluate whether . . . the UVLS Program resolves the identified undervoltage issues for which the UVLS Program is designed [and] the UVLS Program is integrated through coordination with generator voltage ride-through capabilities and other protection and control systems.'' Requirement R4 requires applicable entities to assess whether UVLS programs resolve undervoltage issues associated with voltage excursions triggering UVLS programs. Pursuant to Requirement R5, planning coordinators and transmission planners must develop a corrective action plan to address UVLS program deficiencies identified during assessments performed under Requirements R3 and R4. We conclude that the comprehensive nature of the assessments required under Reliability Standard PRC-010-1 is sufficient, and precludes the need to include the specific items listed in PRC-022-1, Requirement R1. 3. Definition of Special Protection System 60. ITC supports the approval of the revised definition of Remedial Action Scheme. ITC points out that NERC proposes to move to a single definition, Remedial Action Scheme, to eliminate the use of two terms, i.e., Special Protection System.\85\ Thus, ITC requests that the Commission direct NERC to remove the definition of Special Protection System from the NERC Glossary to eliminate any potential for confusion. --------------------------------------------------------------------------- \85\ ITC Comment at 3. --------------------------------------------------------------------------- 61. We deny ITC's request that the Commission direct NERC to remove the definition of ``Special Protection System'' from the NERC Glossary. In its RAS Petition, NERC states that it ``will continue to modify the NERC Reliability Standards until all of them reference only the defined term Remedial Action Scheme. At that time, the definition of Special Protection System will be retired.'' \86\ We are satisfied with NERC's approach of retiring the term ``Special Protection System'' once the Reliability Standards are fully updated to reference the revised definition of Remedial Action Scheme. --------------------------------------------------------------------------- \86\ NERC RAS Petition at 5. --------------------------------------------------------------------------- V. Information Collection Statement 62. The collection of information contained in this Final Rule is subject to review by the Office of Management and Budget (OMB) regulations under section 3507(d) of the Paperwork Reduction Act of 1995 (PRA).\87\ OMB's regulations require approval of certain informational collection requirements imposed by agency rules.\88\ Upon approval of a collection(s) of information, OMB will assign an OMB control number and an expiration date. Respondents subject to the filing requirements of a 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. --------------------------------------------------------------------------- \87\ 44 U.S.C. 3507(d). \88\ 5 CFR 1320.11. --------------------------------------------------------------------------- 63. The Commission is submitting these reporting and recordkeeping requirements to OMB for its review and approval under section 3507(d) of the PRA. The NOPR solicited comments on the Commission's need for this information, whether the information will have practical utility, the accuracy of the provided burden estimate, ways to enhance the quality, utility, and clarity of the information to be collected, and any suggested methods for minimizing the respondent's burden, including the use of automated information techniques. No comments were received. A. Proposed Reliability Standard EOP-011-1 64. Public Reporting Burden: As of March 2015, there are 105 balancing authorities, 11 reliability coordinators and 329 transmission operators registered with NERC. These registered entities will have to comply with 6-8 new requirements in the new proposed Reliability Standard EOP-011-1. As proposed, each registered balancing authority will have to comply with Requirements R2, R4, and, under certain circumstances, R5. Each reliability coordinator will have to comply with Requirements R1 and its subparts, R2 and its subparts, R3 and its subparts, R5 and R6. Each transmission operator will have to comply with Requirements R1 and its subparts and R4. 65. Reliability Standard EOP-011-1 replaces a combined total of 40 requirements or subparts that are found in Reliability Standards EOP- 001-2.1b, EOP-003.1 and EOP-003-2. These three Reliability Standards are to be retired, concurrent with the effective date of Reliability Standard EOP-011-1. Accordingly, the requirements in Reliability Standard EOP-011-1 do not create any new burdens for applicable balancing authorities or transmission operators because the requirements in Reliability Standard EOP-011-1 are already burdens or tasks imposed on this set of registered entities by Reliability Standards EOP-001-2.1b, EOP-003.1 and EOP-003-2 under FERC-725A (1902- 0244). 66. Reliability Standard EOP-011-1 requires reliability coordinators to perform the additional tasks of reviewing, correcting, and coordinating their balancing authorities' and transmission operators' operating procedures for emergency conditions. The Commission estimates that this will add approximately 1,500 man-hours per [[Page 73656]] year for each reliability coordinator as described in detail in the following table: RM15-7-000 (Mandatory Reliability Standards: Reliability Standard EOP-011-1) -------------------------------------------------------------------------------------------------------------------------------------------------------- Average Number of Annual number burden Total annual applicable of responses Total number of (hours) and burden hours Cost per registered per respondent responses cost per and total respondent ($) entities response annual cost (1) (2) (1) * (2) = (3) (4) (3) * (4) = (5) / (1) (5) -------------------------------------------------------------------------------------------------------------------------------------------------------- RC tasks necessary for EOP-011-1 compliance......... 11 1 21 1,500 16,500 $92,387 \89\ $92,387 $1,016,257 -------------------------------------------------------------------------------------------------------------------------------------------------------- B. Proposed Reliability Standard PRC-010-1 Public Reporting Burden: As of April 2015, there are 467 registered distribution providers and 50 transmission providers that are not overlapping in their registration with the distribution provider registration. We estimate that five percent of all distribution providers (23) and transmission providers (3) have under voltage load shedding programs that fall under the Reliability Standard. The Reliability Standard is applicable to planning coordinators and transmission planners, distribution providers, and transmission owners. However, only distribution providers and transmission owners would be responsible for the incremental compliance burden under Reliability Standard PRC-010-1, Requirement R2, as described in detail in the following table: --------------------------------------------------------------------------- \89\ The 1,500 hour figure is broken into 1300 hours at the engineer wage rate and 200 hours at the clerk wage rate. These estimates assume that the engineer's wage rate will be $66.35 and the clerk's wage rate will be $30.66. These figures are taken from the Bureau of Labor Statistics at http://www.bls.gov/oes/current/naics2_22.htm; Occupation Code: 17-2071 (engineer) and 43-4071 (clerk). RM15-12-000 (Mandatory Reliability Standards: Reliability Standard PRC-010-1) \90\ -------------------------------------------------------------------------------------------------------------------------------------------------------- Average Number of Annual number burden Total annual Cost per applicable of responses Total number (hours) and burden hours respondent registered per of responses cost per and total ($) entities respondent response annual cost (1) (2) (1) * (2) = (4) (3) * (4) = (5) / (1) (3) (5) -------------------------------------------------------------------------------------------------------------------------------------------------------- DP--Requirement 2....................................... 23 1 23 \91\ 36 828 1,960 $1,960.32 $45,087.36 TP--Requirement 2....................................... 3 1 3 \92\ 36 108 1,960 $1,960.32 $5,880.96 DP--R2 Data Retention................................... 23 1 23 12 276 368 \93\ $367.92 $8,462.16 TP--R2 Data Retention................................... 3 1 3 12 36 368 $367.92 $1,103.76 ----------------------------------------------------------------------------------------------- Total............................................... .............. .............. .............. .............. $60,534.24 .............. -------------------------------------------------------------------------------------------------------------------------------------------------------- C. Remedial Action Scheme Revisions 67. Public Reporting Burden: The Commission approved the definition of Special Protection System (Remedial Action Scheme) in Order No. 693. We approve a revision to the previously approved definition. The revisions to the Remedial Action Scheme definition and related Reliability Standards are not expected to result in changes to the scope of systems covered by the Reliability Standards and other Reliability Standards that include the term Remedial Action Scheme. Therefore, the Commission does not expect the revisions to affect applicable entities' current reporting burden. --------------------------------------------------------------------------- \90\ DP = distribution provider and TP = transmission provider. \91\ The 36 hour figure is broken into 24 hours at the engineer wage rate and 12 hours at the clerk wage rate. These estimates assume that the engineer's wage rate will be $66.35 and the clerk's wage rate will be $30.66. These figures are taken from the Bureau of Labor Statistics at http://www.bls.gov/oes/current/naics2_22.htm; Occupation Code: 17-2071 (engineer) and 43-4071 (clerk). \92\ Id. \93\ Clerk's wage rate is used for managing data retention. --------------------------------------------------------------------------- FERC-725G4, Mandatory Reliability Standards: Reliability Standard PRC-010-1 (Undervoltage Load Shedding). FERC-725S, Mandatory Reliability Standards: Reliability Standard EOP-011-1 (Emergency Operations). Action: Proposed Collection of Information. OMB Control No: OMB Control No. 1902-0270 (FERC-725S); OMB Control No. 1902-XXXX (FERC-725G4). Respondents: Business or other for-profit and not-for-profit institutions. Frequency of Responses: One time and on-going. Necessity of the Information: The revision to NERC's definition of the term bulk electric system implements the Congressional mandate of the Energy Policy Act of 2005 to develop mandatory and enforceable Reliability Standards to better ensure the reliability of the nation's Bulk-Power System. Specifically, the Reliability Standards consolidate, streamline and clarify the existing requirements of certain currently- effective Emergency Preparedness and Operations and [[Page 73657]] Protection and Control Reliability Standards. 68. Internal review: The Commission has reviewed the requirements pertaining to Reliability Standards PRC-010-1 and EOP-011-1 and made a determination that the requirements of these Reliability Standards are necessary to implement section 215 of the FPA. These requirements conform to the Commission's plan for efficient information collection, communication and management within the energy industry. 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. 69. Interested persons may obtain information on the reporting requirements by contacting the Federal Energy Regulatory Commission, Office of the Executive Director, 888 First Street NE., Washington, DC 20426 [Attention: Ellen Brown, email: [email protected], phone: (202) 502-8663, fax: (202) 273-0873]. 70. Comments concerning the information collections in this Final Rule and the associated burden estimates, should be sent to the Commission in this docket and may also be sent to the Office of Management and Budget, Office of Information and Regulatory Affairs [Attention: Desk Officer for the Federal Energy Regulatory Commission]. For security reasons, comments should be sent by email to OMB at the following email address: [email protected]. Please reference the docket number of this Final Rule (Docket Nos. RM15-13-000, RM15-12- 000, and RM15-7-000) in your submission. VI. Regulatory Flexibility Act Certification 71. The Regulatory Flexibility Act of 1980 (RFA) \94\ generally requires a description and analysis of Proposed Rules that will have significant economic impact on a substantial number of small entities. --------------------------------------------------------------------------- \94\ 5 U.S.C. 601-12. --------------------------------------------------------------------------- 72. Reliability Standard EOP-011-1 is expected to impose an additional burden on 11 entities (reliability coordinators). The remaining 434 entities (balancing authorities and transmission operators and a combination thereof) will maintain the existing levels of burden. Comparison of the applicable entities with FERC's small business data indicates that approximately 7 of the 11 entities are small entities, or 63.63 percent of the respondents affected by this Reliability Standard.\95\ --------------------------------------------------------------------------- \95\ The Small Business Administration sets the threshold for what constitutes a small business. Public utilities may fall under one of several different categories, each with a size threshold based on the company's number of employees, including affiliates, the parent company, and subsidiaries. For the analysis in this NOPR, we are using a 500 employee threshold for each affected entity. Each entity is classified as Electric Bulk Power Transmission and Control (NAICS code 221121). --------------------------------------------------------------------------- 73. On average, each small entity affected may have a one-time cost of $92,387 representing a one-time review of the program for each entity, consisting of 1,500 man-hours at $66.35/hour (for engineer wages) and $30.66/hour (for record clerks), as explained above in the information collection statement. 74. Reliability Standard PRC-010-1 is expected to impose an additional burden on 26 entities (distribution providers and transmission providers or a combination thereof). Comparison of the applicable entities with FERC's small business data indicates that approximately 8 of the 26 entities are small entities, or 30.77 percent of the respondents affected by this Reliability Standard. 75. On average, each small entity affected may have a cost of $1,960, representing a one-time review of the program for each entity, consisting of 36 man-hours at $66.35/hour (for engineer wages) and $30.66/hour (for record clerks), as explained above in the information collection statement. Regarding the revisions to the Remedial Action Scheme definition and the related Reliability Standards including the revised definition, as discussed above, the Commission estimates that proposals will have no cost impact on applicable entities, including any small entities. 76. The Commission estimates that Reliability Standards EOP-011-1 and PRC-010-1 in this Final Rule impose an additional burden on a total of 37 entities. FERC's small business data indicates that 15 of the 37 respondents are small entities, or 40.54 percent of the respondents affected by these proposed Reliability Standards. On average, each small entity affected may have a cost of $92,387 and $1,960 (EOP-011-1 and PRC-010-1 respectively), representing a one-time review of the program for each entity. We do not consider these costs to be a significant economic impact on small entities. Accordingly, the Commission certifies that Reliability Standards EOP-011-1 and PRC-010-1 will not have a significant economic impact on a substantial number of small entities. VII. Environmental Analysis 77. 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.\96\ 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.\97\ The actions proposed herein fall within this categorical exclusion in the Commission's regulations. --------------------------------------------------------------------------- \96\ Regulations Implementing the National Environmental Policy Act of 1969, Order No. 486, FERC Stats. & Regs. ] 30,783 (1987). \97\ 18 CFR 380.4(a)(2)(ii). --------------------------------------------------------------------------- VIII. Document Availability 78. 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. 79. 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 excluding the last three digits of this document in the docket number field. 80. User assistance is available for eLibrary and the Commission's Web site during normal business hours from the Commission's Online Support at 202-502-6652 (toll free at 1-866-208-3676) or email at [email protected], or the Public Reference Room at (202) 502- 8371, TTY (202) 502-8659. Email the Public Reference Room at [email protected]. IX. Effective Date and Congressional Notification 81. This Final Rule is effective January 25, 2016. The Commission has determined, with the concurrence of the Administrator of the Office of Information and Regulatory Affairs of OMB, that this rule is not a ``major rule'' as defined in section 351 of the Small Business Regulatory Enforcement [[Page 73658]] Fairness Act of 1996.\98\ The Commission will submit the final rule to both houses of Congress and to the General Accountability Office. --------------------------------------------------------------------------- \98\ See 5 U.S.C. 804(2). --------------------------------------------------------------------------- By the Commission. Issued: November 19, 2015. Nathaniel J. Davis, Sr., Deputy Secretary. [FR Doc. 2015-29971 Filed 11-24-15; 8:45 am] BILLING CODE 6717-01-P
![Federal Register / Vol. 80, No. 227 / Wednesday, November 25, 2015 / Rules and Regulations 73647
List of Subjects in 7 CFR Part 989 SUPPLEMENTARY INFORMATION: In the rule SUMMARY: The Commission approves
Grapes, Marketing agreements, that is the subject of this correction, the Reliability Standards and definitions of
Raisins, Reporting and recordkeeping Agency revised 7 CFR 1956.101 as terms submitted in three related
requirements. intended, but the Agency inadvertently petitions by the North American Electric
did not make the correct conforming Reliability Corporation (NERC), the
For the reasons set forth in the change in 7 CFR 1956.147. To correct Commission-approved Electric
preamble, 7 CFR part 989 is amended as this oversight, the Agency is ‘‘reserving’’ Reliability Organization. The
follows: 7 CFR 1956.147 in its entirety. This Commission approves Reliability
PART 989—RAISINS PRODUCED correction has no substantive effect on Standards EOP–011–1 (Emergency
FROM GRAPES GROWN IN how debts are settled under this part. Operations) and PRC–010–1
CALIFORNIA (Undervoltage Load Shedding). The
Need for Correction
proposed Reliability Standards
■ 1. The authority citation for 7 CFR As published, the text that remains in consolidate, streamline and clarify the
part 989 continues to read as follows: 7 CFR 1956.147 after the March 13, existing requirements of certain
2015, rule may be misleading and cause currently-effective Emergency
Authority: 7 U.S.C. 601–674.
confusion as a result of the changes Preparedness and Operations (EOP) and
■ 2. Section 989.347 is revised to read made to 7 CFR 1956.101 in the March Protection and Control (PRC) standards.
as follows: 13, 2015, rule. The Commission also approves NERC’s
List of Subjects in 7 CFR Part 1956 revised definition of the term Remedial
§ 989.347 Assessment rate.
Action Scheme as set forth in the NERC
On and after August 1, 2015, an Loan programs—agriculture, Loan Glossary of Terms Used in Reliability
assessment rate of $17.00 per ton is programs—housing and community Standards, and modifications of
established for assessable raisins development. specified Reliability Standards to
produced from grapes grown in Accordingly, 7 CFR 1956.147 is incorporate the revised definition.
California. corrected by making the following Further, the Commission approves the
Dated: November 20, 2015. correcting amendment: implementation plans, and the
Rex A. Barnes, retirement of certain currently-effective
Associate Administrator, Agricultural PART 1956—DEBT SETTLEMENT Reliability Standards.
Marketing Service. DATES: This rule will become effective
■ 1. The authority citation for part 1956
[FR Doc. 2015–30013 Filed 11–24–15; 8:45 am] January 25, 2016.
continues to read as follows:
BILLING CODE P FOR FURTHER INFORMATION CONTACT:
Authority: 5 U.S.C. 301; and 7 U.S.C. Juan Villar (Technical Information),
1989. Office of Electric Reliability, Federal
DEPARTMENT OF AGRICULTURE § 1956.147 [Removed and Reserved] Energy Regulatory Commission, 888
First Street NE., Washington, DC
Rural Housing Service ■ 2. Remove and reserve § 1956.147. 20426, (772) 678–6496,
Dated: November 12, 2015. Juan.Villar@ferc.gov.
Rural Business-Cooperative Service Lisa Mensah, Nick Henery (Technical Information),
Under Secretary, Rural Development. Office of Electric Reliability, Federal
Rural Utilities Service Energy Regulatory Commission, 888
Dated: November 17, 2015.
First Street NE., Washington, DC
Farm Service Agency Michael Scuse,
20426, (202) 502–8636,
Under Secretary, Farm and Foreign
Nick.Henery@ferc.gov.
7 CFR Part 1956 Agricultural Services.
Mark Bennett (Legal Information), Office
[FR Doc. 2015–29781 Filed 11–24–15; 8:45 am]
RIN 0570–AA88 of the General Counsel, Federal
BILLING CODE 3410–XY–P Energy Regulatory Commission, 888
Rural Development Loan Servicing; First Street NE., Washington, DC
Correction 20426, (202) 502–8524,
DEPARTMENT OF ENERGY Mark.Bennett@ferc.gov.
AGENCY: Rural Housing Service, Rural
Federal Energy Regulatory SUPPLEMENTARY INFORMATION:
Business-Cooperative Service, Rural
Utilities Service, and Farm Service Commission Order No. 818
Agency USDA. Final Rule
ACTION: Direct final rule; correction. 18 CFR Part 40
[Docket Nos. RM15–7–000, RM15–12–000, (Issued November 19, 2015)
SUMMARY: This document contains and RM15–13–000 Order No. 818] 1. Pursuant to section 215 of the
corrections to the published rule in the
Federal Register of March 13, 2015, Federal Power Act (FPA),1 the
Revisions to Emergency Operations Commission approves Reliability
entitled ‘‘Rural Development Loan Reliability Standards; Revisions to
Servicing.’’ Standards and definitions of terms
Undervoltage Load Shedding submitted in three related petitions by
DATES: Effective November 25, 2015. Reliability Standards; Revisions to the the North American Electric Reliability
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FOR FURTHER INFORMATION CONTACT: Definition of ‘‘Remedial Action Corporation (NERC), the Commission-
Melvin Padgett, Rural Development, Scheme’’ and Related Reliability approved Electric Reliability
Business Programs, U.S. Department of Standards Organization (ERO). In particular, the
Agriculture, 1400 Independence Avenue AGENCY: Federal Energy Regulatory Commission approves Reliability
SW., STOP 3226, Washington, DC Commission, Department of Energy. Standards EOP–011–1 (Emergency
20250–3225; telephone (202) 720–1495;
ACTION: Final rule.
email melvin.padgett@wdc.usda./gov. 1 16 U.S.C. 824o.
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and inter-dependency with other entity Reliability Standards.18 NERC stated following: Voltage instability, voltage
operating plans and notify transmission that the purpose of Reliability Standard collapse, or Cascading impacting the
providers and balancing authorities if PRC–010–1 is to ‘‘establish an integrated Bulk Electric System. By focusing on the
revisions to their operating plans are and coordinated approach to the design, enumerated risks, the definition is
necessary.16 evaluation, and reliable operation of meant to exclude locally-applied relays
11. Requirement R4 requires Undervoltage Load Shedding Programs’’ that are not designed to mitigate
transmission operators and balancing as directed by the Commission in Order wide-area voltage collapse.’’ 24 NERC
authorities to resolve any issues No. 693.19 stated that the UVLS Program definition
identified by the reliability coordinator 15. NERC explained that Reliability ‘‘clearly identifies and separates
and resubmit their revised operating Standard PRC–010–1 is a single, centrally controlled undervoltage-based
plans within a time period specified by comprehensive standard that addresses load shedding, which is now addressed
the reliability coordinator. Requirement the same reliability principles outlined by the proposed definition of Remedial
R5 requires reliability coordinators to in the four currently-effective UVLS- Action Scheme.’’ 25
notify balancing authorities and related Reliability Standards.20 17. Reliability Standard PRC–010–1
transmission operators in its area, and Reliability Standard PRC–010–1 applies to planning coordinators and
neighboring reliability coordinators, replaces the applicability to and transmission planners because ‘‘either
within 30 minutes of receiving an involvement of ‘‘Regional Reliability may be responsible for designing and
emergency notification. Requirement R6 Organization’’ in Reliability Standards coordinating the UVLS Program . . .
requires a reliability coordinator with a PRC–020–1 and PRC–021–1 and [and] also applies to Distribution
balancing authority experiencing a improves upon and consolidates the Providers and Transmission Owners
potential or actual Energy Emergency to four currently-effective UVLS-Related responsible for the ownership, operation
declare an Energy Emergency alert in Standards into one comprehensive and control of UVLS equipment as
accordance with Attachment 1. standard. NERC explained that required by the UVLS Program
12. Proposed Reliability Standard Reliability Standard PRC–010–1 established by the Transmission Planner
EOP–011–1 also includes the following ‘‘reflects consideration of the 2003 or Planning Coordinator.’’ 26 NERC
revised definition of Energy Emergency: Blackout Report recommendations,’’ 21 explained that the planning coordinator
particularly, Recommendation 21 for or transmission planner that establishes
Energy Emergency—A condition when a a UVLS Program is responsible for
Load-Serving Entity or Balancing Authority NERC to ‘‘make more effective and
has exhausted all other resource options and wider use of system protection identifying the UVLS equipment and
can no longer meet its expected Load measures’’ 22 and Recommendation 21C the necessary distribution provider and
obligations. for NERC to ‘‘determine the goals and transmission owner (referred to as
principles needed to establish an ‘‘UVLS entities’’ in the Applicability
NERC explained that the revised section) that performs the required
definition is intended to clarify that an integrated approach to relay protection
for generators and transmission lines, as actions.
Energy Emergency is not limited to a 18. NERC stated that Reliability
load-serving entity and, based on a well as of UFLS and UVLS programs.’’ 23
16. Reliability Standard PRC–010–1 Standard PRC–010–1 ‘‘applies only after
review of the impact on the body of an entity has determined the need for a
NERC Reliability Standards, ‘‘does not incorporates a new definition of UVLS
Program, which reads: UVLS Program as a result of its own
change the reliability intent of other planning studies.’’ 27 NERC explained
requirements of Definitions.’’ 17 Undervoltage Load Shedding Program that the eight requirements in Reliability
13. NERC proposed an effective date (UVLS Program): An automatic load Standard PRC–010–1 meet four primary
for Reliability Standard EOP–011–1 that shedding program, consisting of distributed
relays and controls, used to mitigate
objectives: (1) The Reliability Standard
is the first day of the first calendar requires applicable entities to evaluate a
undervoltage conditions impacting the Bulk
quarter that is 12 months after the date Electric System (BES), leading to voltage UVLS Program’s effectiveness prior to
of Commission approval, and a instability, voltage collapse, or Cascading. implementation, including coordination
retirement date for currently-effective Centrally controlled undervoltage-based load with other protection systems and
Reliability Standards EOP–001–2.1b, shedding is not included. generator voltage ride-through
EOP–002–3.1 and EOP–003–2 of capabilities; (2) applicable entities must
NERC explained that ‘‘to ensure that the
midnight of the day immediately prior comply with UVLS program
applicability of the proposed Reliability
to the effective date of Reliability specifications and implementation
Standard covers undervoltage-based
Standard EOP–011–1. schedule; (3) applicable entities must
load shedding systems whose
B. NERC PRC Petition—Proposed performance has an impact on system perform periodic assessment and
reliability, a UVLS Program must performance analysis; and (4) applicable
Reliability Standard PRC–010–1 (Docket
mitigate risk of one or more of the entities must maintain and share UVLS
No. RM15–12–000)
Program data.28
14. On February 6, 2015, NERC filed 18 Reliability Standards PRC–010–0 (Assessment
19. Requirement R1 requires each
a petition seeking approval of Reliability of the Design and Effectiveness of UVLS Program); planning coordinator or transmission
Standard PRC–010–1 (Undervoltage PRC–020–1 (Under-Voltage Load Shedding Program planner to evaluate the viability and
Load Shedding), a revised definition of Database); PRC–021–1 (Under-Voltage Load effectiveness of its UVLS program before
Undervoltage Load Shedding Program Shedding Program Data); and PRC–022–1 (Under- implementation to confirm its
Voltage Load Shedding Program Performance).
(UVLS Program) for inclusion in the 19 NERC PRC Petition at 14 (citing Order No. 693, effectiveness in resolving the
NERC Glossary, and the associated FERC Stats & Regs ¶ 31,242 at P 1509). undervoltage conditions for which it
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violation risk factors, violation severity 20 Id.
levels, effective date and 21 Id. at 2 (citing the U.S.-Canada Power System 24 Id. at 16.
implementation plan. NERC also Outage Task Force, Final Report on the August 14, 25 Id. at 15. NERC’s petition for approval of the
2003 Blackout in the United States and Canada: proposed definition of Remedial Action Scheme
proposed the retirement of four PRC Causes and Recommendations, April, 2004 (2003 (Docket No. RM15–13–000) is discussed below.
Blackout Report)). 26 Id.
16 Id. at 10–11. 22 Id. at 4 (citing 2003 Blackout Report at 3, 158). 27 Id. at 14.
17 Id. at 18. 23 Id. at 6. 28 Id. at 17.
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was designed, and that it is integrated retire PRC–010–0, PRC–020–1, PRC– covered by the revised definition.33
through coordination with generator 021–1, and PRC–022–1 at midnight of NERC stated that a broad definition is
ride-through capabilities and other the day immediately prior to the needed because of ‘‘all the possible
protection and control systems. Also, effective date of PRC–010–1.29 Further, scenarios an entity may develop’’ for its
the planning coordinator or NERC explained that Reliability Remedial Action Scheme and a ‘‘very
transmission planner must provide the Standard PRC–010–1 addresses specific, narrow definition may
UVLS Program specifications and reliability obligations that are set forth unintentionally exclude schemes that
implementation schedule to the in Requirements R2, R4 and R7 of should be covered.’’ 34 Accordingly,
applicable UVLS entities. Requirement currently-effective Reliability Standard NERC proposed the following revised
R2 requires UVLS entities to meet the EOP–003–2.30 Since NERC has ‘‘core’’ definition of Remedial Action
UVLS Program’s specifications and proposed to retire EOP–003–2 in the Scheme:
implementation schedule provided by petition seeking approval of Reliability A scheme designed to detect
the planning coordinator or Standard EOP–011–1 (Docket No. predetermined system conditions and
transmission planner or address any RM15–7–00, discussed above), automatically take corrective actions that
necessary corrective actions in concurrent Commission action on the may include, but are not limited to, adjusting
accordance with Requirement R5. two petitions will prevent a possible or tripping generation (MW and Mvar),
20. Requirement R3 requires each tripping load, or reconfiguring a System(s).
reliability gap.
planning coordinator or transmission (sic) RAS accomplish objectives such as:
C. NERC RAS Petition—Revisions to the • Meet requirements identified in the
planner to perform periodic
Definition of ‘‘Remedial Action NERC Reliability Standards;
comprehensive assessments at least • Maintain Bulk Electric System (BES)
every 60 calendar months to ensure Scheme’’ (Docket No. RM15–13–000)
stability;
continued effectiveness of the UVLS 23. On February 3, 2015, NERC filed • Maintain acceptable BES voltages;
program, including whether the a petition seeking approval of a revised • Maintain acceptable BES power flows;
program resolves identified definition of Remedial Action Scheme • Limit the impact of Cascading or extreme
undervoltage issues and that it is in the NERC Glossary, as well as events.
integrated and coordinated with modified Reliability Standards that The definition then lists fourteen
generator voltage ride-through incorporate the new Remedial Action exclusions, describing specific schemes
capabilities and other specified Scheme definition and eliminate use of and systems that do not constitute a
protection and control systems. the term Special Protection System, and Remedial Action Scheme, because each
Requirement R4 requires each planning the associated implementation plan.31 is either a protection function, a control
coordinator or transmission planner to NERC stated that the defined terms function, a combination of both, or used
commence a timely assessment of a Special Protection System and Remedial for system configuration.35
voltage excursion subject to the UVLS Action Scheme are currently used 25. In the implementation plan, NERC
Program, within 12 calendar months of interchangeably throughout the NERC proposed an effective date for the
the event, to evaluate whether the UVLS Regions and in various Reliability revised Reliability Standards and the
Program resolved the undervoltage Standards. NERC explained that revised definition of Remedial Action
issues associated with the event. ‘‘[a]lthough these defined terms share a Scheme on the first day of the first
Requirement R5 requires a corrective common definition in the NERC calendar quarter that is 12 months after
action plan for any program deficiencies Glossary of Terms today, their use and Commission approval.36 NERC also
identified during an assessment application have been inconsistent as a proposed that, for entities with existing
performed under either Requirement R3 result of a lack of granularity in the schemes that become newly classified as
or R4, and provide an implementation definition and varied regional uses of ‘‘Remedial Action Schemes’’ resulting
schedule to UVLS entities within three the terms. The proposed revisions add from the application of the revised
calendar months of its completion. clarity and granularity that will allow definition, the entities will have
21. Pursuant to Requirement R6, a additional time of up to 24 months from
for proper identification of Remedial
planning coordinator must update the the effective date to be fully compliant
Action Schemes and a more consistent
data necessary to model its UVLS with all applicable Reliability
application of related Reliability
Program for use in event analyses and Standards.37 Further, NERC asked the
Standards.’’ 32
program assessments at least each Commission to take final action
24. NERC explained that the revised
calendar year. Requirement R7 requires concurrently with the NERC petition on
Remedial Action Scheme definition
each UVLS entity to provide data to its proposed Reliability Standard PRC–
planning coordinator, according to the consists of a ‘‘core’’ definition,
including a list of objectives and a 010–1 (Docket No. RM15–12–000)
planning coordinator’s format and because ‘‘[t]he proposed definitions of
schedule, to support maintenance of the separate list of exclusions for certain
schemes or systems not intended to be UVLS Program and Remedial Action
UVLS Program database. Requirement Scheme in each project have been
R8 requires a planning coordinator to 29 Id. coordinated to cover centrally
Ex. B (Implementation Plan).
provide its UVLS Program database to 30 Id. controlled UVLS as a Remedial Action
at 23.
other planning coordinators and 31 NERC RAS Petition at 1–2. NERC requested Scheme. Final action by the
transmission planners within its approval of the following Reliability Standards to Commission is needed
Interconnection, and other functional incorporate the proposed definition of Remedial
entities with a reliability need, within Action Scheme and eliminate use of the term 33 Id. at 16. NERC noted that ‘‘for each exclusion,
Special Protection System: EOP–004–3, PRC–005–
30 calendar days of a written request. the scheme or system could still classify as a
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3(ii), PRC–023–4, FAC–010–3, TPL–001–0.1(i),
22. NERC proposed an effective date FAC–011–3, TPL–002–0(i)b, MOD–030–3, TPL– Remedial Action Scheme if employed in a broader
for Reliability Standard PRC–010–1 and 003–0(i)b, MOD–029–2a, PRC–015–1, TPL–004– scheme that meets the definition of Remedial
Action Scheme.’’
the definition of UVLS Program of the 0(i)a, PRC–004–WECC–2, PRC–016–1, PRC–001–
34 Id. at 17.
first day of the first calendar quarter that 1.1(i), PRC–005–2(ii), PRC–017–1. NERC did not
35 Id. at 18.
propose any changes to the Violation Risk Factors
is 12 months after the date that the or Violation Severity Levels for the modified 36 NERC RAS Petition, Ex. C (Implementation
standard and definition are approved by standards. Plan) at 4.
the Commission. NERC proposed to 32 Id. at 4–5. 37 Id.
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functionality with respect to EEAs the Reliability Standard from achieving Operating Plans to mitigate Energy
[Energy Emergency Alerts].’’ 45 its stated purposes or otherwise create Emergencies reinforces this
36. TAPS and EEI agree with NERC’s reliability gaps.50 We find that determination: ‘‘[a]lthough these
analysis of the roles and responsibilities Reliability Standard EOP–011–1 requirements do not specifically
of load-serving entities and that enhances reliability by requiring that identify the ‘who’ or ‘what’ actions to be
excluding them will not create any actions necessary to mitigate capacity taken, it is clear that the responsible
reliability gaps. TAPS states that ‘‘there and energy emergencies are focused in entities required to perform the
is no reliability benefit to retaining single operating plans, and ensures activities attributed to the LSE function
EOP–002–3.1’s Requirement R9, and communication and coordination necessary to aid in arresting an energy
thus no reliability risk from eliminating among relevant entities during emergency must be identified to ensure
the LSE obligation to comply with it.’’ 46 emergency operations. We are necessary mitigation can be
EEI asserts that ‘‘NERC is correct that persuaded by NERC’s explanation that accomplished in order to ensure reliable
‘tasks currently assigned to the LSE excluding load-serving entities will not operation of the BES.’’ 55 Accordingly,
function under NERC Reliability adversely impact reliability due to we conclude that elimination of the
Standards would continue to be technological changes concerning load-serving entity function from
performed by other functions subject to NAESB tagging specifications, and that Reliability Standard EOP–011–1 does
currently applicable LSE Reliability load-serving entities ‘‘have no Real-time not result in an operational gap and,
Standard Requirements or by market reliability functionality with respect to rather, provides a reasonable means of
participants (including LSEs) pursuant EEAs [Energy Emergency Alerts].’’ 51 addressing Energy Emergencies.
to existing tariffs, market rules, market Further, as both NERC and EEI have
protocols and other market stated, ‘‘tasks currently assigned to the 2. The Scheduling and Scope of
agreements.’ ’’ 47 Regarding Operating LSE function under NERC Reliability Reliability Coordinator Reviews of
Plans that transmission operators and Standards would continue to be Operating Plans
balancing authorities are to develop performed by other functions subject to
currently applicable LSE Reliability 40. Reliability Standard EOP–011–1,
under Reliability Standard EOP–011–1
Standard Requirements or by market Requirement R3 obligates a reliability
Requirements R1 and R2, EEI states that
participants (including LSEs) pursuant coordinator to review the Operating
‘‘it is clear that the responsible entities
to tariffs, market rules, market protocols Plan(s) to mitigate operating
required to perform the activities
and other market agreements.’’ 52 emergencies submitted by a
attributed to the LSE function necessary
39. We disagree with LG&E/KU’s transmission operator or a balancing
to aid in arresting an Energy Emergency
must be identified to ensure necessary suggestion that the reference to load- authority. Pursuant to Requirement
mitigation can be accomplished in order serving entities in NERC’s revised R3.1, a reliability coordinator must,
to ensure reliable operation of the definition of Energy Emergency within 30 days of receipt, (i) review
BES.’’ 48 indicates the possibility of an each Operating Plan for compatibility
37. LG&E/KU seeks clarification on ‘‘operational gap.’’ NERC revises the and inter-dependency with other
two questions pertaining to the definition of ‘‘Energy Emergency,’’ transmission operator or balancing
exclusion of load-serving entities from approved in this Final Rule, as ‘‘[a] authority Operating Plans, (ii) review
Reliability Standard EOP–011–1 ‘‘to condition when a Load-Serving Entity each Operating Plan for coordination to
ensure that even if NERC’s EOP or Balancing Authority has exhausted avoid risk to ‘‘Wide Area’’ reliability,
proposal is accepted, [balancing all other resource options and can no and (iii) notify each transmission
authorities] will have a meaningful way longer meet its expected Load operator and balancing authority of the
of addressing any operational gaps with obligations.’’ 53 Based on a plain reading results of the review.
Energy Emergencies and LSEs.’’ 49 First, of this definition, we agree with LG&E/ Comments
LG&E/KU seeks clarification that an KU that a load-serving entity’s inability
Energy Emergency can be isolated to a to meet its own load obligations could 41. Peak Reliability asserts that the
load-serving entity’s inability to meet its result in an Energy Emergency. ‘‘inflexible’’ 30 day period for reliability
own load obligations, as indicated in Moreover, consistent with our findings coordinator reviews of operating plans
NERC’s revised definition of Energy in the RBR Compliance Order, we agree in Reliability Standard EOP–011–1
Emergency. Second, LG&E/KU seeks with LG&E/KU that operating plans Requirement R3.1 is not reasonable.
clarification that Operating Plans developed by balancing authorities— According to Peak Reliability, because
developed by balancing authorities may including operating plans contained in transmission operators have an ‘‘open
describe the role for load-serving applicable tariffs—may describe the role ended’’ opportunity to submit operating
entities in responding to an Energy for load-serving entities in responding plans under the provision, reliability
Emergency, and may include such to an Energy Emergency.54 EEI’s coordinators cannot schedule in
Operating Plans in applicable tariffs. observation regarding Reliability advance the needed resources to
Standard EOP–011–1 Requirements R1 perform a proper review in the 30-day
Commission Determination and R2 for transmission operators and window. Peak Reliability notes that, in
38. Consistent with our determination balancing authorities to develop its experience, many entities update
in the ‘‘risk-based registration’’ their plans at the end of the year,
proceeding, we find that the elimination 50 See North American Electric Reliability Corp.,
creating a large spike in review work at
of load-serving entities from Reliability 153 FERC ¶ 61,024, at P 20 (2015) (RBR Compliance
Order) (approving the proposed elimination of the that time. Peak Reliability, therefore,
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Standard EOP–011–1 will not prevent load-serving entity function). recommends revising Requirement R3.1
51 NERC Comments at 5, quoting the EOP–011–1 to include language requiring ‘‘a
45 Id. at 5–6. Mapping Document and Application Guidelines. mutually agreed predetermined
46 TAPS Comments at 4. 52 EEI Comments at 5–6.
47 EEI Comments at 5–6, quoting NERC’s 53 NERC EOP Petition, Ex. B (Implementation
schedule’’ to ensure that the reliability
compliance filing in RR15–4–000 at 1. Plan) at 1.
coordinator can efficiently allocate its
48 Id. at 6. 54 RBR Compliance Order, 153 FERC ¶ 61,024 at
49 LG&E/KU Comments at 2. 21. 55 EEI Comments at 6.
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![73654 Federal Register / Vol. 80, No. 227 / Wednesday, November 25, 2015 / Rules and Regulations
approved definition of ‘Bulk Electric Program or a centrally-controlled that this need to expand applicability is
System’ or create a new term.’’ 68 Remedial Action Scheme.73 unfounded. Reliability Standard PRC–
50. NERC explains that the diagram 010–1, Requirement R8, provides that
C. Other Issues Raised By Commenters
‘‘is not intended to necessarily illustrate other functional entities with a
a centrally controlled UVLS (considered 1. Reliability Standard PRC–010–1— reliability need can request UVLS data,
a [Remedial Action Scheme]), but to Applicability and that such requests must be
illustrate how Registered Entities should 53. Peak Reliability asserts that answered in 30 days.
evaluate whether the term UVLS Reliability Standard PRC–010–1 ‘‘does 56. Nor are we persuaded by Peak
Program and proposed Reliability not adequately address the operation of Reliability’s argument that UVLS
Standard PRC–010–1 applies to a UVLS UVLS Programs, as it does not apply to programs should be considered in
system.’’ 69 NERC points out that, if a the NERC functional entities that operations planning and real-time
UVLS system in the ‘‘BES subsystem’’ is operate the Bulk Electric System,’’ operations. We understand that Peak
used to mitigate undervoltage particularly, reliability coordinators, Reliability refers to the consideration of
conditions impacting the BES (leading transmission operators, and balancing UVLS programs in the derivation of
to voltage instability, voltage collapse, authorities.74 Peak Reliability contends Interconnection Reliability Operating
or Cascading), the system would fall that UVLS Programs should be included Limits (IROLs) for Category B
under the new definition of UVLS in operational planning and real-time contingencies as defined in the
Program (or RAS if centrally controlled) assessments, and that all entities currently-effective transmission
responsible for operating the bulk planning standard TPL–002–0b
and thus in the scope of Reliability
electric system must be given access to (commonly known as N–1 contingencies
Standard PRC–010–1.70
UVLS Program databases.75 Further, under normal system operation).78 With
51. EEI states that the example of this understanding, we disagree with
‘‘BES subsystem’’ in the ‘‘Guidelines for Peak Reliability requests that the
Commission direct NERC to explain Peak Reliability on the relevance of
UVLS Program Definition’’ does not using UVLS in the derivation of IROLs
represent a centrally controlled UVLS why Reliability Standard PRC–010–1
and Reliability Standard IRO–009–1 for N–1 contingencies. The 2003
and therefore would not be considered Canada-United States Blackout Report
a Remedial Action Scheme. EEI explains apply to different functional entities
(since the purpose of both is to prevent stated that ‘‘[s]afety nets should not be
that the term UVLS Program ‘‘is for a relied upon to establish transfer
scheme that consists of distributed instability, uncontrolled separation or
cascading outages), and recommends limits.’’ 79 This statement is consistent
relays and controls, not for a scheme with the performance criteria
that is centrally controlled. The key that the treatment of UVLS in operations
planning and real-time assessments be established in TPL–002–0b and TPL–
point is that for a UVLS system to fall 001–4, which generally prohibit the loss
under the definition of Undervoltage addressed.76
54. We are not persuaded by Peak of non-consequential load for certain N–
Load Shedding Program, it must be used 1 contingencies.80 We conclude that
Reliability’s assertion that Reliability
to protect the BES against voltage UVLS programs under PRC–010–1 are
Standard PRC–010–1 should apply to
instability, voltage collapse, or examples of such ‘‘safety nets’’ and
reliability coordinators, transmission
Cascading.’’ 71 EEI also notes that the should not be tools used by bulk electric
operators, and balancing authorities.
term ‘‘BES subsystem’’ is not intended system operators to calculate operating
Rather, as NERC explains ‘‘[t]he
to be a new NERC term, but rather ‘‘was limits for N–1 contingencies. Likewise,
applicability includes both the Planning
used in the example to illustrate a with this understanding, there is no
Coordinator and Transmission Planner
possible localized undervoltage imperative to make PRC–010–1
because either may be responsible for
contingency on a very small portion of applicable to reliability coordinators,
designing and coordinating the UVLS
the BES but not a contingency that transmission operators, and balancing
Program. Reliability Standard PRC–010–
impacts a larger area of the BES that authorities.
1 also applies to Distribution Providers
could result in voltage instability, 57. Peak Reliability comments that
and Transmission Owners responsible
voltage collapse, or Cascading.’’ 72 Reliability Standard PRC–010–1
for the ownership, operation and control
Commission Determination of UVLS equipment as required by the ‘‘creates some confusion of the
UVLS Program established by the applicability of UVLS Programs due to
52. Based on the explanations Transmission Planner and Planning the similarities, and apparent overlap,
provided above, we determine that a Coordinator.’’ 77 As NERC’s rationale in the definitions of UVLS Programs and
directive for further modification of the above indicates, the applicability IROLs.’’ 81 We disagree. Peak
example of ‘‘BES subsystem’’ and section of the Reliability Standard Reliability’s comparison of UVLS
related diagram in NERC’s ‘‘Guidelines identities the functional entities Programs with establishing and
for UVLS Program Definition’’ to ensure responsible for the design, operation operating within IROLs is misplaced
consistency with the Commission- and control of UVLS Programs and because UVLS Programs and IROLs
approved definition of ‘‘bulk electric related equipment. represent separate and distinct
system’’ proposed in the NOPR is not 55. While Peak Reliability seeks to approaches to system security. UVLS
necessary. Rather, we are persuaded that expand applicability to functional Programs act as safety nets for
EEI’s concern with the diagram is entities so that UVLS Program databases contingencies more severe than N–1
addressed by NERC’s explanation that, would be shared with reliability contingencies, such as the simultaneous
depending on the role of a particular coordinators, transmission operators,
UVLS system, the diagram could 78 The Commission-approved Version 4 standard,
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and balancing authorities, we believe TPL–001–4, will replace TPL–002–0b on January 1,
illustrate an example of a UVLS
2016. See Transmission Planning Reliability
73 Id.
Standards, Order No. 786, 145 FERC ¶ 61,051
68 Id. at 7. 74 Peak Reliability Comments at 9. (2013).
69 Id. 75 Id.at 9–10. 79 2003 Blackout Report at 109.
70 Id. 76 Id. at 11–12. 80 See TPL–002–0b, Table 1, footnote b and TPL–
71 EEI Comments at 8. 77 NERC EOP Petition at 15, and id. Ex. D (Order 001–4, Table 1, Footnote 12.
72 Id. No. 672 Criteria) at 2–3. 81 Peak Reliability Comments at 11.
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loss of two single circuits or a double- Requirement R4 requires applicable penalized for failing to respond to these
circuit line which are both Category C entities to assess whether UVLS collections of information unless the
contingencies permitting loss of non- programs resolve undervoltage issues collections of information display a
consequential firm load.82 In contrast, associated with voltage excursions valid OMB control number.
the NERC Glossary defines IROLs as ‘‘[a] triggering UVLS programs. Pursuant to 63. The Commission is submitting
System Operating Limit that, if violated, Requirement R5, planning coordinators these reporting and recordkeeping
could lead to instability, uncontrolled and transmission planners must develop requirements to OMB for its review and
separation, or cascading outages that a corrective action plan to address approval under section 3507(d) of the
adversely impact the reliability of the UVLS program deficiencies identified PRA. The NOPR solicited comments on
Bulk Electric System.’’ This corresponds during assessments performed under the Commission’s need for this
with the TPL–004–1 provisions Requirements R3 and R4. We conclude information, whether the information
requiring that the system must remain that the comprehensive nature of the will have practical utility, the accuracy
stable when experiencing an N–1 assessments required under Reliability of the provided burden estimate, ways
contingency (such as Category B or P1 Standard PRC–010–1 is sufficient, and to enhance the quality, utility, and
contingencies).83 In sum, we disagree precludes the need to include the clarity of the information to be
with Peak Reliability’s premise specific items listed in PRC–022–1, collected, and any suggested methods
regarding similarities, and overlaps, in Requirement R1. for minimizing the respondent’s burden,
the definition of UVLS programs and including the use of automated
3. Definition of Special Protection information techniques. No comments
IROLs.
System were received.
2. Reliability Standard PRC–010–1 60. ITC supports the approval of the
—Appropriate Level of Detail in UVLS A. Proposed Reliability Standard EOP–
revised definition of Remedial Action 011–1
Program Assessment Scheme. ITC points out that NERC
58. Reliability Standard PRC–010–1, proposes to move to a single definition, 64. Public Reporting Burden: As of
Requirements R3, R4, and R5 obligate Remedial Action Scheme, to eliminate March 2015, there are 105 balancing
planning coordinators and transmission the use of two terms, i.e., Special authorities, 11 reliability coordinators
planners to perform an assessment of Protection System.85 Thus, ITC requests and 329 transmission operators
their UVLS program in various that the Commission direct NERC to registered with NERC. These registered
circumstances. Idaho Power contends remove the definition of Special entities will have to comply with 6–8
that Reliability Standard PRC–010–1, Protection System from the NERC new requirements in the new proposed
Requirements R3, R4, and R5, do not Glossary to eliminate any potential for Reliability Standard EOP–011–1. As
confusion. proposed, each registered balancing
‘‘specifically state what must be
61. We deny ITC’s request that the authority will have to comply with
included in the assessment, as was
Commission direct NERC to remove the Requirements R2, R4, and, under certain
included in PRC–022–1 R1.1–4’’ and,
definition of ‘‘Special Protection circumstances, R5. Each reliability
therefore, do not sufficiently explain
System’’ from the NERC Glossary. In its coordinator will have to comply with
what applicable entities must include in
RAS Petition, NERC states that it ‘‘will Requirements R1 and its subparts, R2
UVLS Program assessments.84
continue to modify the NERC Reliability and its subparts, R3 and its subparts, R5
59. We disagree with Idaho Power.
Standards until all of them reference and R6. Each transmission operator will
Reliability Standard PRC–022–1
only the defined term Remedial Action have to comply with Requirements R1
requires applicable entities to ‘‘analyze
Scheme. At that time, the definition of and its subparts and R4.
and document all UVLS operations and 65. Reliability Standard EOP–011–1
misoperations,’’ and specifically Special Protection System will be
retired.’’ 86 We are satisfied with NERC’s replaces a combined total of 40
mentions set points and tripping times requirements or subparts that are found
and a summary of the findings. In approach of retiring the term ‘‘Special
in Reliability Standards EOP–001–2.1b,
contrast, Reliability Standard PRC–010– Protection System’’ once the Reliability
EOP–003.1 and EOP–003–2. These three
1 Requirement R3, requires planning Standards are fully updated to reference
Reliability Standards are to be retired,
coordinators and transmission planners the revised definition of Remedial
concurrent with the effective date of
to perform comprehensive assessments Action Scheme.
Reliability Standard EOP–011–1.
of their UVLS Programs at least once V. Information Collection Statement Accordingly, the requirements in
every 5 years. Each assessment ‘‘shall Reliability Standard EOP–011–1 do not
include, but is not limited to, studies 62. The collection of information
contained in this Final Rule is subject create any new burdens for applicable
and analyses that evaluate whether . . . balancing authorities or transmission
the UVLS Program resolves the to review by the Office of Management
and Budget (OMB) regulations under operators because the requirements in
identified undervoltage issues for which Reliability Standard EOP–011–1 are
the UVLS Program is designed [and] the section 3507(d) of the Paperwork
Reduction Act of 1995 (PRA).87 OMB’s already burdens or tasks imposed on
UVLS Program is integrated through this set of registered entities by
coordination with generator voltage regulations require approval of certain
informational collection requirements Reliability Standards EOP–001–2.1b,
ride-through capabilities and other EOP–003.1 and EOP–003–2 under
protection and control systems.’’ imposed by agency rules.88 Upon
approval of a collection(s) of FERC–725A (1902–0244).
82 The TPL Standards require that the system information, OMB will assign an OMB 66. Reliability Standard EOP–011–1
remain stable and that cascading and uncontrolled control number and an expiration date. requires reliability coordinators to
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islanding shall not occur for any Category B or C Respondents subject to the filing perform the additional tasks of
contingency (i.e., currently-effective TPL Standards,
requirements of a rule will not be reviewing, correcting, and coordinating
N–1 and N–2 contingencies) or for any Category P1 their balancing authorities’ and
through P7 contingency (i.e., TPL–001–4, N–1 and
N–2 contingencies.) See Table 1 of any of the TPL 85 ITC Comment at 3. transmission operators’ operating
Standards. 86 NERC RAS Petition at 5. procedures for emergency conditions.
83 See TPL Standards, Table 1. 87 44 U.S.C. 3507(d). The Commission estimates that this will
84 Idaho Power Comments at 2. 88 5 CFR 1320.11. add approximately 1,500 man-hours per
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![Federal Register / Vol. 80, No. 227 / Wednesday, November 25, 2015 / Rules and Regulations 73657
Protection and Control Reliability respondents affected by this Reliability VII. Environmental Analysis
Standards. Standard.95
73. On average, each small entity 77. The Commission is required to
68. Internal review: The Commission prepare an Environmental Assessment
has reviewed the requirements affected may have a one-time cost of
$92,387 representing a one-time review or an Environmental Impact Statement
pertaining to Reliability Standards PRC– for any action that may have a
010–1 and EOP–011–1 and made a of the program for each entity,
consisting of 1,500 man-hours at $66.35/ significant adverse effect on the human
determination that the requirements of environment.96 The Commission has
these Reliability Standards are hour (for engineer wages) and $30.66/
hour (for record clerks), as explained categorically excluded certain actions
necessary to implement section 215 of from this requirement as not having a
the FPA. These requirements conform to above in the information collection
statement. significant effect on the human
the Commission’s plan for efficient environment. Included in the exclusion
74. Reliability Standard PRC–010–1 is
information collection, communication are rules that are clarifying, corrective,
expected to impose an additional
and management within the energy or procedural or that do not
burden on 26 entities (distribution
industry. The Commission has assured substantially change the effect of the
providers and transmission providers or
itself, by means of its internal review, regulations being amended.97 The
a combination thereof). Comparison of
that there is specific, objective support actions proposed herein fall within this
the applicable entities with FERC’s
for the burden estimates associated with categorical exclusion in the
small business data indicates that
the information requirements. approximately 8 of the 26 entities are Commission’s regulations.
69. Interested persons may obtain small entities, or 30.77 percent of the VIII. Document Availability
information on the reporting respondents affected by this Reliability
requirements by contacting the Federal Standard. 78. In addition to publishing the full
Energy Regulatory Commission, Office 75. On average, each small entity text of this document in the Federal
of the Executive Director, 888 First affected may have a cost of $1,960, Register, the Commission provides all
Street NE., Washington, DC 20426 representing a one-time review of the interested persons an opportunity to
[Attention: Ellen Brown, email: program for each entity, consisting of 36 view and/or print the contents of this
DataClearance@ferc.gov, phone: (202) man-hours at $66.35/hour (for engineer document via the Internet through the
502–8663, fax: (202) 273–0873]. wages) and $30.66/hour (for record Commission’s Home Page (http://
70. Comments concerning the clerks), as explained above in the www.ferc.gov) and in the Commission’s
information collections in this Final information collection statement. Public Reference Room during normal
Rule and the associated burden Regarding the revisions to the Remedial business hours (8:30 a.m. to 5:00 p.m.
estimates, should be sent to the Action Scheme definition and the Eastern time) at 888 First Street NE.,
Commission in this docket and may also related Reliability Standards including Room 2A, Washington, DC 20426.
be sent to the Office of Management and the revised definition, as discussed 79. From the Commission’s Home
Budget, Office of Information and above, the Commission estimates that Page on the Internet, this information is
Regulatory Affairs [Attention: Desk proposals will have no cost impact on available on eLibrary. The full text of
Officer for the Federal Energy applicable entities, including any small this document is available on eLibrary
Regulatory Commission]. For security entities. in PDF and Microsoft Word format for
reasons, comments should be sent by 76. The Commission estimates that viewing, printing, and/or downloading.
email to OMB at the following email Reliability Standards EOP–011–1 and To access this document in eLibrary,
address: oira_submission@omb.eop.gov. PRC–010–1 in this Final Rule impose an type the docket number excluding the
Please reference the docket number of additional burden on a total of 37 last three digits of this document in the
this Final Rule (Docket Nos. RM15–13– entities. FERC’s small business data docket number field.
000, RM15–12–000, and RM15–7–000) indicates that 15 of the 37 respondents 80. User assistance is available for
in your submission. are small entities, or 40.54 percent of eLibrary and the Commission’s Web site
the respondents affected by these during normal business hours from the
VI. Regulatory Flexibility Act proposed Reliability Standards. On Commission’s Online Support at 202–
Certification average, each small entity affected may 502–6652 (toll free at 1–866–208–3676)
have a cost of $92,387 and $1,960 (EOP– or email at ferconlinesupport@ferc.gov,
71. The Regulatory Flexibility Act of 011–1 and PRC–010–1 respectively),
1980 (RFA) 94 generally requires a or the Public Reference Room at (202)
representing a one-time review of the 502–8371, TTY (202) 502–8659. Email
description and analysis of Proposed program for each entity. We do not
Rules that will have significant the Public Reference Room at
consider these costs to be a significant public.referenceroom@ferc.gov.
economic impact on a substantial economic impact on small entities.
number of small entities. Accordingly, the Commission certifies IX. Effective Date and Congressional
72. Reliability Standard EOP–011–1 is that Reliability Standards EOP–011–1 Notification
expected to impose an additional and PRC–010–1 will not have a 81. This Final Rule is effective
burden on 11 entities (reliability significant economic impact on a January 25, 2016. The Commission has
coordinators). The remaining 434 substantial number of small entities. determined, with the concurrence of the
entities (balancing authorities and
Administrator of the Office of
transmission operators and a 95 The Small Business Administration sets the
Information and Regulatory Affairs of
combination thereof) will maintain the threshold for what constitutes a small business.
OMB, that this rule is not a ‘‘major rule’’
jstallworth on DSK7TPTVN1PROD with RULES
existing levels of burden. Comparison of Public utilities may fall under one of several
different categories, each with a size threshold as defined in section 351 of the Small
the applicable entities with FERC’s based on the company’s number of employees, Business Regulatory Enforcement
small business data indicates that including affiliates, the parent company, and
approximately 7 of the 11 entities are subsidiaries. For the analysis in this NOPR, we are
96 Regulations Implementing the National
small entities, or 63.63 percent of the using a 500 employee threshold for each affected
entity. Each entity is classified as Electric Bulk Environmental Policy Act of 1969, Order No. 486,
Power Transmission and Control (NAICS code FERC Stats. & Regs. ¶ 30,783 (1987).
94 5 U.S.C. 601–12. 221121). 97 18 CFR 380.4(a)(2)(ii).
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![73658 Federal Register / Vol. 80, No. 227 / Wednesday, November 25, 2015 / Rules and Regulations
Fairness Act of 1996.98 The Commission and quality of the product. The Alcohol • A narrative description of the
will submit the final rule to both houses and Tobacco Tax and Trade Bureau features of the proposed AVA affecting
of Congress and to the General (TTB) administers the FAA Act viticulture, such as climate, geology,
Accountability Office. pursuant to section 1111(d) of the soils, physical features, and elevation,
By the Commission. Homeland Security Act of 2002, that make the proposed AVA distinctive
codified at 6 U.S.C. 531(d). The and distinguish it from adjacent areas
Issued: November 19, 2015.
Secretary has delegated various outside the proposed AVA boundary;
Nathaniel J. Davis, Sr., • The appropriate United States
authorities through Treasury
Deputy Secretary. Department Order 120–01, dated Geological Survey (USGS) map(s)
[FR Doc. 2015–29971 Filed 11–24–15; 8:45 am] December 10, 2013, to the TTB showing the location of the proposed
BILLING CODE 6717–01–P Administrator to perform the functions AVA, with the boundary of the
and duties in the administration and proposed AVA clearly drawn thereon;
enforcement of this law. and
DEPARTMENT OF THE TREASURY Part 4 of the TTB regulations (27 CFR • A detailed narrative description of
part 4) authorizes TTB to establish the proposed AVA boundary based on
Alcohol and Tobacco Tax and Trade definitive viticultural areas and regulate USGS map markings.
Bureau the use of their names as appellations of Eagle Foothills Petition
origin on wine labels and in wine TTB received a petition from Martha
27 CFR Part 9 advertisements. Part 9 of the TTB Cunningham, owner of the 3 Horse
[Docket No. TTB–2015–0006; T.D. TTB–131; regulations (27 CFR part 9) sets forth Ranch Vineyards, on behalf of the local
Ref: Notice No. 150] standards for the preparation and grape growers and vintners, proposing
RIN 1513–AC18 submission of petitions for the the establishment of the ‘‘Eagle
establishment or modification of Foothills’’ AVA in Gem and Ada
Establishment of the Eagle Foothills American viticultural areas (AVAs) and Counties, Idaho. The proposed AVA is
Viticultural Area lists the approved AVAs. immediately north of the city of Eagle
AGENCY: Alcohol and Tobacco Tax and Definition and is approximately 10 miles
Trade Bureau, Treasury. northwest of the city of Boise. The Eagle
Section 4.25(e)(1)(i) of the TTB Foothills AVA is located entirely within
ACTION: Final rule; Treasury decision. regulations (27 CFR 4.25(e)(1)(i)) defines the established Snake River Valley AVA
a viticultural area for American wine as (27 CFR 9.208) and does not overlap
SUMMARY: The Alcohol and Tobacco Tax
a delimited grape-growing region having with any other existing or proposed
and Trade Bureau (TTB) establishes the
distinguishing features, as described in AVA. The original proposed name for
approximately 49,815-acre ‘‘Eagle
part 9 of the regulations, and a name the AVA was ‘‘Willow Creek Idaho.’’
Foothills’’ viticultural area in Gem and
and a delineated boundary, as However, TTB determined that the
Ada Counties in Idaho. The viticultural
established in part 9 of the regulations. petition did not sufficiently demonstrate
area lies entirely within the established
These designations allow vintners and that the region is known by that name.
Snake River Valley viticultural area.
consumers to attribute a given quality, Therefore, the petitioner submitted a
TTB designates viticultural areas to
reputation, or other characteristic of a request to change the proposed AVA
allow vintners to better describe the
wine made from grapes grown in an area name to ‘‘Eagle Foothills.’’
origin of their wines and to allow
to the wine’s geographic origin. The The proposed Eagle Foothills AVA
consumers to better identify wines they
establishment of AVAs allows vintners contains approximately 49,815 acres,
may purchase.
to describe more accurately the origin of with 9 commercially-producing
DATES: This final rule is effective
their wines to consumers and helps vineyards covering a total of 67 acres
December 28, 2015. consumers to identify wines they may distributed throughout the proposed
FOR FURTHER INFORMATION CONTACT: purchase. Establishment of an AVA is AVA. The petition states that an
Dominique Christianson, Regulations neither an approval nor an endorsement additional 4 acres will soon be added to
and Rulings Division, Alcohol and by TTB of the wine produced in that an existing vineyard and that an
Tobacco Tax and Trade Bureau, 1310 G area. additional 7 commercial vineyards
Street NW., Box 12, Washington, DC
Requirements covering approximately 472 acres are
20005; phone 202–453–1039, ext. 278.
planned within the next few years.
SUPPLEMENTARY INFORMATION: Section 4.25(e)(2) of the TTB According to the petition, the
Background on Viticultural Areas regulations (27 CFR 4.25(e)(2)) outlines distinguishing features of the proposed
the procedure for proposing an AVA Eagle Foothills AVA are its topography,
TTB Authority and provides that any interested party climate, and soils. The proposed AVA is
Section 105(e) of the Federal Alcohol may petition TTB to establish a grape- located within the Unwooded Alkaline
Administration Act (FAA Act), 27 growing region as an AVA. Section 9.12 Foothills ecoregion of Idaho. This
U.S.C. 205(e), authorizes the Secretary of the TTB regulations (27 CFR 9.12) ecoregion is defined as an arid, sparsely
of the Treasury to prescribe regulations prescribes standards for petitions for the populated region of rolling foothills,
for the labeling of wine, distilled spirits, establishment or modification of AVAs. benches, and alluvial fans underlain by
and malt beverages. The FAA Act Petitions to establish an AVA must alkaline lake bed deposits. A network of
provides that these regulations should, include the following: seasonal creeks flowing southwesterly
jstallworth on DSK7TPTVN1PROD with RULES
among other things, prohibit consumer • Evidence that the area within the through the proposed AVA have created
deception and the use of misleading proposed AVA boundary is nationally deep gulches and a rugged terrain that
statements on labels and ensure that or locally known by the AVA name has a variety of slope aspects favorable
labels provide the consumer with specified in the petition; to the vineyard owners. The elevation
adequate information as to the identity • An explanation of the basis for within the proposed AVA ranges from
defining the boundary of the proposed 2,490 feet to approximately 3,400 feet,
98 See 5 U.S.C. 804(2). AVA; with an average elevation of 2,900 feet.
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Document Created: 2018-03-01 11:15:45
Document Modified: 2018-03-01 11:15:45
| Category | Regulatory Information | |
| Collection | Federal Register | |
| sudoc Class | AE 2.7: GS 4.107: AE 2.106: | |
| Publisher | Office of the Federal Register, National Archives and Records Administration | |
| Section | Rules and Regulations | |
| Action | Final rule. | |
| Dates | This rule will become effective January 25, 2016. | |
| Contact | Juan Villar (Technical Information), Office of Electric Reliability, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (772) 678-6496, [email protected] Nick Henery (Technical Information), Office of Electric Reliability, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-8636, [email protected] Mark Bennett (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426, (202) 502-8524, [email protected] | |
| FR Citation | 80 FR 73647 |
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