153 FERC ¶ 61,228

UNITED STATES OF AMERICA

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

(Issued November 19, 2015)

AGENCY: Federal Energy Regulatory Commission. 

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. 
Docket Nos. RM15-13-000, et al. ii

EFFECTIVE DATES: This rule will become effective [INSERT DATE 60 days after 

publication in the FEDERAL REGISTER].

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:
153 FERC ¶ 61,228

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners: Norman C. Bay, Chairman;

 Cheryl A. LaFleur, Tony Clark,

 and Colette D. Honorable.

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

Docket Nos. RM15-7-000

RM15-12-000

RM15-13-000

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 Operations) and 

PRC-010-1 (Undervoltage Load Shedding). The Commission finds that the Reliability 

Standards consolidate, streamline, and clarify the existing requirements of several

 1 16 U.S.C. 824o. 
Docket Nos. RM15-13-000, et al. - 2 -

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

 

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

 

 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).

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). 
Docket Nos. RM15-13-000, et al. - 3 -

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, EOP002, 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.

II. NERC Petitions

5. NERC submitted three related petitions that we address together in this Final 

Rule.

7

 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.

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 website, www.nerc.com. 
Docket Nos. RM15-13-000, et al. - 4 -

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

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 

 8 NERC EOP Petition at 2.

9 Id. at 3.

10 Id. at 12-18.
Docket Nos. RM15-13-000, et al. - 5 -

reliability coordinator and the process for communicating the condition of a balancing 

authority experiencing an Energy Emergency.

11 

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 

 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). 

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.
Docket Nos. RM15-13-000, et al. - 6 -

requirement for transmission operators to maintain operating plans includes the 

expectation that the plans are current and up-to-date.14

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

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 and inter-dependency with other entity operating plans and notify 

transmission providers and balancing authorities if revisions to their operating plans are 

necessary.16

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

 14 Id. at 8-9.

15 Id.

16 Id. at 10-11.
Docket Nos. RM15-13-000, et al. - 7 -

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

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.

 17 Id. at 18.
Docket Nos. RM15-13-000, et al. - 8 -

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 

15. NERC explained that Reliability Standard PRC-010-1 is a single, comprehensive 

standard that addresses the same reliability principles outlined in the four currentlyeffective 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 

 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 (UnderVoltage Load Shedding Program Performance).

19 NERC PRC Petition at 14 (citing Order No. 693, FERC Stats & Regs ¶ 31,242 

at P 1509). 

20 Id.
Docket Nos. RM15-13-000, et al. - 9 -

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

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 undervoltagebased load shedding is not included.

NERC explained that “to ensure that the applicability of the proposed Reliability 

Standard covers undervoltage‐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‐

 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.
Docket Nos. RM15-13-000, et al. - 10 -

applied relays that are not designed to mitigate wide‐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 

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.

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 

 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.

26 Id.

27 Id. at 14.
Docket Nos. RM15-13-000, et al. - 11 -

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 

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 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 

 28 Id. at 17.
Docket Nos. RM15-13-000, et al. - 12 -

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 
Docket Nos. RM15-13-000, et al. - 13 -

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 EOP003-2.

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.

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 

 29 Id. Ex. B (Implementation Plan).

30 Id. at 23.

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, TPL003-0(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.
Docket Nos. RM15-13-000, et al. - 14 -

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 

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:

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.

 32 Id. at 4-5. 

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.
Docket Nos. RM15-13-000, et al. - 15 -

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

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 contemporaneously on both petitions to facilitate 

implementation and avoid a gap in coverage of centrally controlled UVLS.”38

 35 Id. at 18.

36 NERC RAS Petition, Ex. C (Implementation Plan) at 4.

37 Id.

38 NERC RAS Petition at 3-4. 
Docket Nos. RM15-13-000, et al. - 16 -

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. 

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 

 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).
Docket Nos. RM15-13-000, et al. - 17 -

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

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 

 40 NOPR, 151 FERC ¶ 61,230 at P 27.
Docket Nos. RM15-13-000, et al. - 18 -

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

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-

 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.
Docket Nos. RM15-13-000, et al. - 19 -

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.

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

 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. 

44 NERC Comments at 4.
Docket Nos. RM15-13-000, et al. - 20 -

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 functionality 

with respect to EEAs [Energy Emergency Alerts].”45 

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 

 45 Id. at 5-6. 

46 TAPS Comments at 4.

47 EEI Comments at 5-6, quoting NERC’s compliance filing in RR15-4-000 at 1.
Docket Nos. RM15-13-000, et al. - 21 -

Emergency must be identified to ensure necessary mitigation can be accomplished in 

order to ensure reliable operation of the BES.”48

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.

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 

 48 Id. at 6.

49 LG&E/KU Comments at 2.

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).
Docket Nos. RM15-13-000, et al. - 22 -

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

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 

 51 NERC Comments at 5, quoting the EOP-011-1 Mapping Document and 

Application Guidelines.

52 EEI Comments at 5-6. 

53 NERC EOP Petition, Ex. B (Implementation Plan) at 1.
Docket Nos. RM15-13-000, et al. - 23 -

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 loadserving 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.

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 

 54 RBR Compliance Order, 153 FERC ¶ 61,024 at 21.

55 EEI Comments at 6.
Docket Nos. RM15-13-000, et al. - 24 -

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 resources and provide a thorough review 

of submitted operating plans.56 

42. Peak Reliability also seeks clarification regarding the scope of reliability 

coordinator review of operating plans, and whether a reliability coordinator must review 

 56 Peak Reliability Comments at 6-7.
Docket Nos. RM15-13-000, et al. - 25 -

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

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

 57 Id. at 7.

58 Id. at 7-8.

59 See NERC EOP Petition at 9.
Docket Nos. RM15-13-000, et al. - 26 -

“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.” 

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. 

 60 See Peak Reliability Comments at 5-6.

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).
Docket Nos. RM15-13-000, et al. - 27 -

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 PRC010-2 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 PRC004-5 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 

 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).
Docket Nos. RM15-13-000, et al. - 28 -

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

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.

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

 63 NERC Comments at 8.

64 EEI Comments at 7.

65 See Delegated Letter Order issued November 19, 2915.

66 See NOPR, 151 FERC ¶ 61,230 at P 27 (including diagram).
Docket Nos. RM15-13-000, et al. - 29 -

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-approved 

definition of ‘Bulk Electric System’ or create a new term.”68

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 

 67 NERC Comments at 6-7.

68 Id. at 7.

69 Id.

70 Id.
Docket Nos. RM15-13-000, et al. - 30 -

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

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 Commissionapproved 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

 71 EEI Comments at 8.

72 Id.
Docket Nos. RM15-13-000, et al. - 31 -

illustrate an example of a UVLS Program or a centrally-controlled Remedial Action 

Scheme.

73

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

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 

 73 Id.

74 Peak Reliability Comments at 9.

75 Id. at 9-10.

76 Id. at 11-12.
Docket Nos. RM15-13-000, et al. - 32 -

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. 

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 

 77 NERC EOP Petition at 15, and id. Ex. D (Order No. 672 Criteria) at 2-3.
Docket Nos. RM15-13-000, et al. - 33 -

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.

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 

 78 The Commission-approved Version 4 standard, TPL-001-4, will replace TPL002-0b 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.

81 Peak Reliability Comments at 11.
Docket Nos. RM15-13-000, et al. - 34 -

approaches to system security. UVLS Programs act as safety nets for contingencies 

more severe than N-1 contingencies, such as the simultaneous loss of two single circuits 

or a double-circuit line which are both Category C contingencies permitting loss of nonconsequential 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.

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 

 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. 
Docket Nos. RM15-13-000, et al. - 35 -

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

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. 

 84 Idaho Power Comments at 2. 
Docket Nos. RM15-13-000, et al. - 36 -

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. 

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. 

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 

 85 ITC Comment at 3.

86 NERC RAS Petition at 5.

87 44 U.S.C. 3507(d).
Docket Nos. RM15-13-000, et al. - 37 -

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. 

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 

 88 5 C.F.R. 1320.11.
Docket Nos. RM15-13-000, et al. - 38 -

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 year for 

each reliability coordinator as described in detail in the following table:
Docket Nos. RM15-13-000, et al. - 39 -

RM15-7-000 (Mandatory Reliability Standards: Reliability Standard EOP-011-1)

Number of 

Applicable 

Registered 

Entities

(1)

Annual 

Number of 

Responses 

per 

Respondent

(2)

Total Number 

of Responses 

(1)*(2)=(3)

Average 

Burden 

(Hours) & 

Cost Per 

Response

(4)

Total Annual 

Burden 

Hours & 

Total Annual 

Cost

(3)*(4)=(5)

Cost per 

Respondent

($)

(5)÷(1)

RC tasks 

necessary for 

EOP-011-1 

compliance

11 1 21 1,500

$92,38789

16,500

$1,016,257

$92,387

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).
Docket Nos. RM15-13-000, et al. - 40 -

RM15-12-000 (Mandatory Reliability Standards: Reliability Standard PRC-010-1)90

Number of 

Applicable 

Registered 

Entities

(1)

Annual 

Number of 

Responses 

per 

Respondent

(2)

Total Number 

of Responses 

(1)*(2)=(3)

Average 

Burden 

(Hours) & 

Cost Per

Response

(4)

Total 

Annual 

Burden 

Hours & 

Total 

Annual Cost

(3)*(4)=(5)

Cost per 

Respondent

($)

(5)÷(1)

DP –

Requirement 

2

23 1 23 3691

$1,960.32

828

$45,087.36

$1,960

TP -

Requirement

2

3 1 3 3692

$1,960.32

108

$5,880.96

$1,960

DP - R2

Data 

Retention

23 1 23 12

$367.9293

276

$8,462.16

$368

TP – R2 Data 

Retention

3 1 3 12

$367.92

36

$1,103.76

$368

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 

 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.
Docket Nos. RM15-13-000, et al. - 41 -

include the term Remedial Action Scheme. Therefore, the Commission does not expect 

the revisions to affect applicable entities’ current reporting burden. 

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 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 
Docket Nos. RM15-13-000, et al. - 42 -

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, e-mail: 

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 e-mail to OMB at the 

following e-mail 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. 

72. Reliability Standard EOP-011-1 is expected to impose an additional burden on 

11 entities (reliability coordinators). The remaining 434 entities (balancing authorities 

 94 5 U.S.C. 601-12. 
Docket Nos. RM15-13-000, et al. - 43 -

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

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 

 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). 
Docket Nos. RM15-13-000, et al. - 44 -

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 

 96 Regulations Implementing the National Environmental Policy Act of 1969, 

Order No. 486, FERC Stats. & Regs. ¶ 30,783 (1987).
Docket Nos. RM15-13-000, et al. - 45 -

amended.97 The actions proposed herein fall within this categorical exclusion in the 

Commission’s regulations.

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 website during 

normal business hours from the Commission’s Online Support at 202-502-6652 (toll free 

at 1-866-208-3676) or email at ferconlinesupport@ferc.gov, or the Public Reference 

Room at (202) 502-8371, TTY (202) 502-8659. E-mail the Public Reference Room 

at public.referenceroom@ferc.gov.

 97 18 C.F.R. 380.4(a)(2)(ii).
Docket Nos. RM15-13-000, et al. - 46 -

IX. Effective Date and Congressional Notification

81. This Final Rule is effective [INSERT DATE 60 days after publication in the

FEDERAL REGISTER]. 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 Fairness Act of 1996.98 The Commission will submit the final rule to both 

houses of Congress and to the General Accountability Office.

By the Commission.

( S E A L )

Nathaniel J. Davis, Sr.,

Deputy Secretary.

 98 See 5 U.S.C. 804(2).