
[Federal Register Volume 80, Number 227 (Wednesday, November 25, 2015)]
[Rules and Regulations]
[Pages 73647-73658]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[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, Juan.Villar@ferc.gov.
Nick Henery (Technical Information), Office of Electric Reliability, 
Federal Energy Regulatory Commission, 888 First Street NE., Washington, 
DC 20426, (202) 502-8636, Nick.Henery@ferc.gov.
Mark Bennett (Legal Information), Office of the General Counsel, 
Federal Energy Regulatory Commission, 888 First Street NE., Washington, 
DC 20426, (202) 502-8524, Mark.Bennett@ferc.gov.

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: DataClearance@ferc.gov, 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: oira_submission@omb.eop.gov. 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 
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. Email the Public Reference Room at 
public.referenceroom@ferc.gov.

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


