134 FERC ¶ 61,127 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Transmission Relay Loadability Reliability Standard Docket No. RM08-13-001 

ORDER NO. 733-A 

TABLE OF CONTENTS

(Issued February 17, 2011) 

Paragraph Numbers

Background.................................................................................................................................2.

Procedural Background..........................................................................................................2.

Reliability Standard PRC-023-1 ............................................................................................4.

Order No. 733.........................................................................................................................5.

Request for Rehearing and Clarification of Reliability Standard Directives .............................7.

Authority Under Section 215(d) of the FPA..........................................................................8.

Test for Identifying Critical Facilities....................................................................................14.

Elements of Test for Identifying Critical Facilities ...............................................................39.

Desirable System Performance-Related Rehearing Requests ...........................................40.

Base Cases .........................................................................................................................53.

Other Test Criteria ............................................................................................................70.

Deadline to File Test ..............................................................................................................76.

Applicability to Below 100 kV Facilities ..............................................................................79.

Generator Step-Up Transformer Relays as Back-Up Protection ...........................................89.

Power Swings.........................................................................................................................100.

Requirement R1.10 ................................................................................................................114.

Attachment A Section 3.1 ......................................................................................................125.

Regulatory Flexibility Act of 1980 ........................................................................................135.
le. 

 

134 FERC ¶ 61,127 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Before Commissioners: Jon Wellinghoff, Chairman; 

 Marc Spitzer, Philip D. Moeller, 

 John R. Norris, and Cheryl A. LaFleur. 

Transmission Relay Loadability Reliability Standard Docket No. RM08-13-001 

ORDER NO. 733-A 

ORDER ON REHEARING, CLARIFICATION, AND REQUEST FOR AN 

EXTENSION OF TIME 

(Issued February 17, 2011) 

1. In this order, the Commission grants several requests for clarification and grants 

rehearing, in part, and denies rehearing, in part, of the Final Rule in Order No. 7331

which approved and directed modifications to the Transmission Relay Loadability 

Reliability Standard (PRC-023-1) submitted to the Commission for approval by the North 

American Electric Reliability Corporation (NERC), the Commission-certified Electric 

Reliability Organization (ERO) for the United States.2

 We also grant NERC’s request 

for an extension to allow 24 months from the date of this order for NERC to comply with 

the Final Ru

1

 Transmission Relay Loadability Reliability Standard, Order No. 733, 130 FERC 

¶ 61,221 (2010). 

2

 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 No. RM08-13-001 - 2 - 

Background

Procedural Background

2. On March 18, 2010, the Commission issued a Final Rule in this proceeding that 

approved Reliability Standard PRC-023-1 (Transmission Relay Loadability), a Standard 

that requires transmission owners, generator owners, and distribution providers to set 

load-responsive phase protection relays3

 according to specific criteria in order to ensure 

that the relays reliably detect and protect the electric network from all fault conditions, 

but do not limit transmission loadability4

 or interfere with system operators’ ability to 

protect system reliability. In addition, pursuant to section 215(d)(5) of the Federal Power 

Act (FPA), the Commission directed NERC to develop certain modifications to PRC023-1 to address issues identified by the Commission. 

3. On April 19, 2010, eight petitioners5

 requested rehearing and/or clarification of 

Order No. 733. 

 

(continued...) 

3

 Load-responsive protection relays are a form of protective relays that detect and 

initiate the removal of faults on an electric system. They are designed to read electrical 

measurements, such as current, voltage, and frequency, and can be set to recognize 

certain measurements as indicating a fault. When a protective relay detects a fault on an 

element of the system that it is protecting, it sends a signal to an interrupting device (such 

as a circuit breaker) to disconnect the element from the rest of the system. 

4

 Loadability refers to the ability of protective relays to refrain from operating 

under load conditions. 

5

 NERC, The Edison Electric Institute (EEI), American Public Power Association 

(APPA), National Rural Electric Cooperative Association (NRECA), Transmission 

Access Policy Study Group (TAPS) (collectively, APPA, NRECA; and TAPS are 

referred to as the Trade Associations), Duke Energy Corporation (Duke), and Dominion 
Docket No. RM08-13-001 - 3 - 

Reliability Standard PRC-023-1

4. Reliability Standard PRC-023-1 consists of three Requirements and Attachment 

A.6

 Requirement R1 directs entities with certain transmission facilities to set their relays 

according to one of thirteen specific settings (sub-Requirements R1.1 through R1.13) 

designed to maximize loadability while maintaining Reliable Operation of the bulk 

electric system for all fault conditions. Requirement R2 provides additional directives for 

entities that elect certain settings. Requirement R3 directs planning coordinators to 

designate which facilities operated between 100 kV and 200 kV are critical to the 

reliability of the bulk electric system and are therefore subject to Requirement R1.7

 

Attachment A specifies the protection systems that are subject to and excluded from the 

Standard’s Requirements. 

Order No. 733

5. In addition to approving PRC-023-1, the Commission in Order No. 733 directed 

NERC to develop modifications to the Standard in several significant respects. For 

 

Resources Services, Inc. (Dominion) filed requests for rehearing and/or clarification. 

Exelon Corporation filed supporting the NERC and EEI pleadings. 

6

 Pursuant to section 40.3 of the Commission’s regulations, all Commissionapproved Reliability standards are available on NERC’s website at www.nerc.com. See

18 C.F.R. § 40.3. 

7

 As approved by the Commission, the Standard applies to: (1) all transmission 

lines and transformers with low-voltage terminals operated or connected at 200 kV and 

above; and (2) those transmission lines and transformers with low-voltage terminals 

operated or connected between 100 kV and 200 kV that are designated by planning 

coordinators as critical to the reliability of the bulk electric system. 
Docket No. RM08-13-001 - 4 - 

 

example, the Commission directed NERC to: (1) modify Requirement R3 to include a 

mandatory test for planning coordinators to use to identify which facilities between 100 

kV and 200 kV are critical to the reliability of the bulk electric system (and therefore 

subject to the Standard); (2) make certain sub-100 kV facilities subject to the Standard;8

(3) revise sub-Requirement R1.10 to require entities to verify that the limiting piece of 

equipment is capable of sustaining the overload anticipated by the sub-Requirement’s 

settings; and (4) revise Attachment A to make the Standard applicable to supervisory 

relays. 

6. Additionally, the Commission adopted the proposal in its Notice of Proposed 

Rulemaking9

 to require NERC to develop a new Reliability Standard addressing stable 

power swings.10 The Commission declined, however, to adopt its NOPR proposal to 

(continued...) 

8

 The Commission stated that it expected NERC to use the same test applied to 

100 – 200 kV facilities to identify critical sub-100 kV facilities. 

9

 Transmission Relay Loadability Reliability Standard, Notice of Proposed 

Rulemaking, FERC Stats. & Regs. ¶ 32,642 (2009) (NOPR). 

10 Power swings are oscillations in power flow(s) on an electric system due to an 

event or disturbance such as a fault, loss of generation or load. Transient and stable 

power swings occur most commonly when a fault and faulted facilities are quickly 

removed from the system, typically within 0.1 second of detection, and the system and 

affected generators stabilize within several seconds, typically within 3 seconds. 

Dynamic, but stable power swings can occur when the system recovers from a 

disturbance and achieves transient stability, typically within 0-3 seconds, and then returns 

to a steady state over a longer period of time, typically within 3-30 seconds or even 

minutes. Prior to the system returning to a new steady state operating condition, it may 

exhibit power swings that may decrease rapidly or increase in magnitude. When the 

power swings decrease, the system will be able to achieve a new stable operating 
Docket No. RM08-13-001 - 5 - 

require NERC to modify PRC-023-1 to address generator step-up and auxiliary 

transformer loadability. 

Request for Rehearing and Clarification of Reliability Standard Directives

7. All petitioners offer some variant of the argument that the Commission exceeded 

its statutory authority by failing to give “due weight” to the technical expertise of the 

ERO and by directing NERC to develop a modification that requires entities to satisfy a 

legal standard beyond the statutorily required criteria of “Reliable Operation.” 

Petitioners also challenge the technical reasoning or legal authority behind several of the 

Commission’s directives and interpretations, including: (1) the development of a test to 

identify critical facilities; (2) the modification of the Standard to apply to sub-100 kV 

facilities; (3) the modification of sub-Requirement R1.10; (4) the modification of 

Attachment A; and (5) the development of a Reliability Standard that addresses stable 

power swings. Finally, petitioners argue that the Commission erred in interpreting the 

Standard to apply to relays associated with generator step-up and auxiliary transformers 

that provide backup protection to bulk electric system elements. 

Authority Under Section 215(d) of the FPA

8. Section 215(d)(2) of the FPA requires the Commission to give “due weight” to the 

technical expertise of the ERO when evaluating the content of a proposed Reliability 

 

condition, provided that the relays protecting “healthy” facilities have not operated 

unnecessarily because of the stable power swing(s). 
Docket No. RM08-13-001 - 6 - 

al 

 

Standard or modification to a Standard.11 Petitioners argue that the Commission failed 

on multiple occasions in Order No. 733 to give such “due weight” to NERC’s technic

expertise. 

9. In general, petitioners make two distinct arguments regarding appropriate due 

weight. These arguments appear throughout the rehearing requests and are summarized 

below in the context of the petitioners’ challenge to specific Commission directives. The 

first argument asserts that, rather than giving “due weight” to NERC’s technical 

expertise, the Commission reviewed NERC’s proposals under an unspecified, but less 

deferential criterion. The second argument is that the prescriptive nature of the Final 

Rule results in confusion between the Commission’s obligation to give “due weight” to 

NERC’s technical expertise and the Commission’s authority under section 215(d)(5) to 

direct modifications to a Reliability Standard. Specifically, EEI argues that the 

Commission’s directive to develop a test to identify which facilities will be subject to the 

Reliability Standard violates the “due weight” requirement because it is so prescriptive 

that it denies the ERO the ability to exercise its technical discretion. 

10. In the Final Rule, the Commission emphasized that NERC could comply with the 

Commission’s directives through alternative means than those proposed by the 

11 16 U.S.C. § 824o(d)(2) (2006). 
Docket No. RM08-13-001 - 7 - 

 

Commission.12 The Commission explained that, pursuant to Order No. 693, prescriptive 

directives should be read as providing NERC sufficient guidance so that it “has an 

understanding of the Commission’s concerns and an appropriate, but not necessarily 

exclusive, outcome to address those concerns.”13 The Commission added that where it 

identified a concern and offered a specific approach to address the concern, it “will 

consider an equivalent alternative approach provided that the ERO demonstrates that the 

alternative will address the Commission’s underlying concern or goal as efficiently and 

effectively as the Commission’s proposal.”14 

11. Upon review of Order No. 733, we find that the mandatory nature of some of the 

language setting forth the Commission’s guidance with respect to specific directives 

conflicts with the Commission’s references to Order No. 693 and creates the impression 

that the Commission prohibited NERC from developing an equally effective and efficient 

approach to the approach the Commission laid out in the order. In this order, we 

emphasize and affirm that we do not intend to prohibit NERC from exercising its 

technical expertise to develop a solution to an identified reliability concern that is equally 

12 Order No. 733, 130 FERC ¶ 61,221 at P 17-19, P 68, P 71, n. 82, P 186, P 203, 

P 264. 

13 Id. P 17 (citing Mandatory Reliability Standards for the Bulk-Power System, 

Order No. 693, FERC Stats. & Regs. ¶ 31,242, at P 185, order on reh’g, Order No. 693-

A, 120 FERC ¶ 61,053 (2007)). 

14 Order No. 733, 130 FERC ¶ 61,221 at P 18 (citing Order No. 693, FERC Stats. 

& Regs. ¶ 31,242 at P 186). 
Docket No. RM08-13-001 - 8 - 

 

effective and efficient as the one proposed in Order No. 733. To that end, we here 

attempt to more clearly delineate between the concerns that must be addressed by the 

ERO and the guidance we are providing so that the ERO understands the underlying 

concern. 

12. We also reaffirm that, consistent with Order No. 693, detailed guidance should be 

read as providing the ERO with further elaboration of the Commission’s concerns and 

offering a specific, but not exclusive, approach to addressing those concerns. As Order 

No. 693 states, the ERO has the discretion in how to comply with a Commission directive 

by developing a response that addresses the concern or goal underlying the directive in a 

manner as efficiently and effectively as the Commission’s guidance.15 The ERO is not 

required to adopt the Commission’s guidance into the Reliability Standard, but is 

required to develop its response to the Commissioner’s concerns through the stakeholder 

evaluation process contained within the Reliability Standard development process. That 

process promotes a full vetting of technical issues and solutions, and encourages 

participation by interested entities. The discussion accompanying our directives provides 

guidance to assist the ERO in performing its role in developing Reliability Standards, and 

does not preempt its technical expertise.16 

15 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 186. 

16 See id. P 185; North American Electric Reliability Corp., 132 FERC ¶ 61,218, 

at P 32 (2010). 
Docket No. RM08-13-001 - 9 - 

 

13. As we have stated, we recognize that Order No. 733 may not have been 

sufficiently clear as to what the specific reliability concern was and what was intended to 

be guidance. Thus, in this order we attempt to clarify this issue. We reiterate that, in 

each instance where the Commission directed the ERO to modify PRC-023-1 in a 

specific manner, we will accept an alternative method that addresses the concern 

identified by the Commission, provided that the ERO demonstrates that the alternative 

will adequately address the Commission’s underlying concern or goal as efficiently and 

effectively as the Commission’s proposal. If the ERO decides to propose an alternative 

approach to address a Commission concern, it must explain in detail, and with a technical 

record sufficient enough for the Commission to make an informed decision, how its 

alternative addresses the Commission’s concern.17 Here, while the ERO is required to 

develop a test that will identify all facilities that must be made subject to the Reliability 

Standard in order for the Standard to achieve its purpose, and while we require that test to 

include some specific elements to provide assurance of its utility,18 the ERO may propose 

to comply with this requirement in a different manner than in the specific way set forth 

17 Revision to Electric Reliability Organization Definition of Bulk Electric System, 

Order No. 743, 133 FERC ¶ 61,150, at P 35 (2010). 

18 As stated below, these specific elements are consistency with existing 

Reliability Standards and the system performance levels for all Category of 

Contingencies used in transmission planning, a definition of desirable system 

performance, and a description of the steady state and dynamic base cases that the 

planning coordinator must use in identifying critical facilities. 
Docket No. RM08-13-001 - 10 - 

by the Commission, provided that the ERO can show that its alternative addresses the 

Commission’s concern in an equally efficient and effective manner. 

Test for Identifying Critical Facilities

14. As approved by the Commission, Requirement R3 of PRC-023-1 requires 

planning coordinators to identify which facilities between 100 kV and 200 kV are critical 

to the reliability of the bulk electric system, but does not specify the test that planning 

coordinators must use to make this determination. In the NOPR, the Commission 

described this approach as an “add in” approach because it does not subject any specific 

facilities to the Reliability Standard, but requires planning coordinators to study and “add 

in” facilities they determine to be critical to the reliability of the bulk electric system.19 

The Commission expressed concern that using an “add in” approach could result in an 

under-identification of facilities, and proposed to direct the ERO to revise Requirement 

R3 to require a “rule out” approach that would subject all 100 kV-200 kV facilities to the 

Reliability Standard unless and until the relevant planning coordinator ruled out the 

facility by determining that it was not critical to the reliability of the bulk electric 

system.20 

15. In response to the NOPR, the Commission received numerous comments opposing 

the “rule out” approach and, in the Final Rule, decided against it. The Commission 

 19 NOPR, FERC Stats. & Regs. ¶ 32,642 at P 40. 

20 NOPR, FERC Stats. & Regs. ¶ 32,642 at P 40, P 43. 
Docket No. RM08-13-001 - 11 - 

 

explained that after further consideration it determined that its concerns about the “add 

in” approach could be addressed by directing the ERO to modify Requirement R3 to 

specify a comprehensive and rigorous test that all planning coordinators must use to 

identify all critical facilities.21 The Commission stated that it had proposed the “rule out” 

approach because it was concerned by the absence in Requirement R3 of a mandatory test 

for planning coordinators to use when identifying critical facilities.22 The Commission 

explained that without such a test it had no assurance that planning coordinators would 

identify all facilities that must be subject to the Reliability Standard in order for the 

Standard to achieve its goal.23 Consequently, the Commission found that the absence of 

a test was a specific matter that the ERO needed to address, and directed the ERO to

develop a test that would identify all critical facilities. 

21 Order No. 733, 130 FERC ¶ 61,221 at P 48, P 50 (“After reflecting on the 

rationale behind the “rule out” approach — namely, the goal of ensuring that planning 

coordinators identify all critical facilities between 100 kV and 200 kV — and considering 

the comments, we conclude that, from a reliability standpoint, it should not matter 

whether PRC-023-1 employs an “add in” approach or a “rule out” approach because both 

approaches should ultimately result in the same list of critical facilities. In other words, 

given a uniform and robust test, the facilities that would be “added in” under an “add in” 

approach should be the same as the facilities that would remain subject to the Reliability 

Standard after non-critical facilities are ruled out under the “rule out” approach.”). 

22 Id. P 70. 

23 Id. 
Docket No. RM08-13-001 - 12 - 

 

16. As the Commission explained in both the NOPR and Final Rule, and as NERC 

stated in its petition for approval,24 PRC-023-1 was developed to address 

Recommendation 21A of the Blackout Report.25 Consequently, in both the NOPR and 

Final Rule, the Commission stated that the Reliability Standard must apply to those 

facilities necessary to prevent undesirable system performance like the undesirable 

performance that occurred during the August 2003 Blackout. Since neither the Blackout 

Report nor the Reliability Standard established a test for planning coordinators to use in 

identifying those facilities, the Commission provided the ERO with guidance on how to 

develop a test that would provide assurance that planning coordinators would identify all 

critical facilities necessary to prevent undesirable system performance like the 

undesirable performance that occurred during the August 2003 Blackout. The 

Commission began by stating the basic requirements the test would have to satisfy: 

(1) inclusion of, or consistency with the system simulations and assessments that are 

already required by the existing TPL Reliability Standards; (2) satisfaction of the system 

performance levels for all Category of Contingencies required by the transmission 

planning reliability standards; (3) establishment of some definition of desirable system 

24 NOPR, FERC Stats. & Regs. ¶ 32,642 at P 14, P 42; Order No. 733, 130 FERC 

¶ 61,221 at P 73, P 78. 

25 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 (Apr. 

2004) (Blackout Report), available at http://www.ferc.gov/industries/electric/indusact/blackout.asp. 
Docket No. RM08-13-001 - 13 - 

 

performance; and (4) a description of the steady state and dynamic base cases that the 

planning coordinator must use in identifying facilities.26 The Commission then provided 

its view, based on the Blackout Report, of one possible definition of desirable system 

performance and on one possible description of the steady state and dynamic base cases 

that planning coordinators must use in assessing which facilities are subject to the 

Reliability Standard.27 

17. The Commission also noted that, while NERC did not propose a test to identify 

critical facilities, it included in its NOPR comments the criteria for identifying critical 

sub-200 kV facilities that the NERC System Protection and Control Task Force 

developed for Regional Entities to use during NERC’s voluntary relay review and 

mitigation program.28 The Commission concluded that these criteria, if applied 

appropriately, would identify some, but likely not all, critical sub-200 kV facilities. 

26 Id. at 79-80. The requirements of the Transmission Planning Reliability 

Standards require that entities have studies to show that their portion of the bulk electric 

system is stable and within voltage and thermal limits for a variety of contingencies and 

base cases that cover critical system conditions. Those studies include steady-state and 

dynamic simulations which require specific base cases. Steady-state base cases are used 

to evaluate whether the Bulk-Power System will remain within specified current and 

steady-state voltage limits before and after contingencies in all of the base cases. 

Dynamic refers to the response of the Bulk-Power System following a transient electric 

system event such as a fault, tripping and reclosing (if applicable) of a Bulk-Power 

System element, or planned load shedding. Dynamic base cases evaluate, for example, 

phase angles, currents and voltages before, during, and after the event to determine 

whether the Bulk-Power System will remain stable. 

27 Order No. 733, 130 FERC ¶ 61,221 at P 80-90. 

28 Order No. 733, 130 FERC ¶ 61,221 at P 74. 
Docket No. RM08-13-001 - 14 - 

Consequently, in addition to providing general guidance on what a mandatory test must 

include, the Commission discussed how the voluntary criteria could be revised into a 

fully acceptable test. 

Rehearing Requests

18. Petitioners raise two types of arguments regarding the Commission’s directive to 

the ERO to develop a test to identify critical facilities. First, petitioners raise variations 

of the argument that the Commission failed to give “due weight” to the technical 

expertise of the ERO. Second, petitioners challenge specific elements of the 

Commission’s guidance on desirable system performance and the required base cases. 

“Due Weight” Related Rehearing Requests

19. The Trade Associations argue that the Commission exceeded its authority by 

prescribing the specific technical content of the test that NERC must develop to identify 

operationally significant facilities. The Trade Associations explain that the Commission 

provided NERC with more than 10 pages of specific and complex technical guidance on 

what the test must include, and argue that the specificity of the Commission’s guidance 

leaves NERC with no room to exercise its technical expertise.29 The Trade Associations 

acknowledge that the Commission can require NERC to modify a Reliability Standard to 

address a specific matter, but they argue that the Commission cannot all but draft the 

 29 Trade Associations at 8. 
Docket No. RM08-13-001 - 15 - 

 

technical content of the modification.30 The Trade Associations maintain that the 

Commission should take a more general approach toward modifications and direct NERC 

to develop a test without specifying what the test must include. In the alternative, the 

Trade Associations argue that the Commission should clarify that its guidance is merely a 

list of concerns that NERC should consider in developing the test.31 

20. EEI connects the prescriptive nature of the Commission’s guidance with a 

challenge to the framework for modifications that the Commission established in Order 

No. 693. EEI maintains that, in directing NERC to develop a test, providing specific 

guidance on the test, and requiring NERC to either follow the Commission’s guidance or 

propose an “equally efficient and effective” alternative, the Commission has essentially 

established a rebuttable presumption that its guidance is correct and efficiently and 

effectively addresses the underlying reliability goal.32 EEI argues that this approach fails 

to give due weight to the technical expertise of the ERO because it allows the 

Commission to establish what the content of the Reliability Standard should be and 

requires that any alternative proposed by the ERO address the Commission’s concerns 

and goals “as efficiently and effectively” as the Commission’s proposal. EEI argues that 

this process is inconsistent with both the language and legislative history of section 215. 

30 Id. 

31 Id. at 9. 

32 EEI at 7. 
Docket No. RM08-13-001 - 16 - 

 

21. Duke contends that the Commission failed to give “due weight” to NERC. Duke 

notes that the Commission claimed to provide NERC with flexibility in modifying 

Reliability Standard PRC-023-1 by directing NERC “to address the underlying issue 

through the Reliability Standards development process without mandating a specific 

change to PRC-023-1.” Duke argues, however, that two specific details of the 

Commission’s guidance belie this assurance of flexibility. First, Duke claims that the 

Commission explicitly overruled the guidance provided by the NERC System Protection 

and Control Task Force when it determined that it would identify some, but not all, 

critical sub-200 kV facilities.33 Second, Duke maintains that the Commission mandated 

a specific change to the Reliability Standard by requiring NERC to include the

Commission’s definitions of “desirable system performance” for Category B and 

Category C contingencies as part of the test. Duke requests that the Commission grant 

rehearing to provide NERC with adequate time to: (1) provide its members with 

reasonable notice and opportunity to comment on a modified Standard using the 

Reliability Standards development process; and (2) submit such modified standard to the 

Commission.34 If the Commission does not adopt these changes on rehearing, Duke 

argues that the Commission should fully explain how Order No. 733 satisfies the 

33 Duke at 8. 

34 Id. at 9. 
Docket No. RM08-13-001 - 17 - 

Commission’s statutory obligation to give “due weight” to the technical expertise of the 

ERO.

Commission Determination

22. In the Final Rule, the Commission identified the absence of a test for identifying 

critical 100 kV – 200 kV facilities as a specific matter that the ERO needed to address 

through its Reliability Standards development process. As the Commission explained in 

the Final Rule, its primary reliability concern throughout this proceeding has been that 

Requirement R3 fails to provide assurance that planning coordinators will identify all 

facilities that must be identified and made subject to the Reliability Standard if the 

Standard is to achieve its purpose and prevent a recurrence of the undesirable system 

performance that occurred during the August 2003 Blackout.35 Consequently, the 

Commission directed the ERO to develop a test that would identify all such facilities. 

The Commission further explained that in order to provide the necessary assurance that 

the Standard would achieve its purpose, the test must include or be consistent with the 

system simulations and assessments that are already required by the existing TPL 

Reliability Standards, meet the system performance levels for all Category of 

Contingencies used in transmission planning, set forth some definition of desirable 

system performance, and describe the steady state and dynamic base cases that the 

planning coordinator must use in identifying facilities in the 100 kV to 200 kV range that 

 35 Order No. 733, 130 FERC ¶ 61,221 at P 49-50, 77-78. 
Docket No. RM08-13-001 - 18 - 

 

are subject to PRC-023-1.36 It is these elements that constitute the Commission’s 

reliability concern. 

23. In addition to setting forth its concern,37 the Commission provided guidance on an 

acceptable definition of desirable system performance and on the steady state and 

dynamic base cases that the planning coordinator must use in identifying critical 

facilities. While this may not have been clear in the underlying order, these discussions 

were intended as guidance to inform the ERO and industry as to the technical 

underpinnings of our concerns. As requested by EEI, we clarify that the Commission did 

not intend to require the ERO to adopt the specific content of the Commission’s specific 

guidance on these matters. We want to make clear on rehearing that the ERO remains 

free to exercise its technical expertise during the Reliability Standards development 

process.38

(continued...) 

36 Id. at 79-80. 

37 As discussed previously, the requirements that a test developed by the ERO 

need to satisfy are: (1) inclusion of, or consistency with the system simulations and 

assessments that are already required by the existing TPL Reliability Standards; 

(2) satisfaction of the system performance levels for all Category of Contingencies 

required by the transmission planning reliability standards; (3) establishment of some 

definition of desirable system performance; and (4) a description of the steady state and 

dynamic base cases that the planning coordinator must use in identifying facilities. 

38 It is our view that, given the results we understand it has achieved, the 

methodology PJM Interconnection, L.L.C. (PJM) developed to identify critical facilities 

could be one form of an equally efficient and effective alternative to the Commission’s 

proposal described in the Final Rule. Subsequent to the issuance of the Final Rule, PJM 

developed a test to identify PRC-023-1 critical facilities within its footprint including 
Docket No. RM08-13-001 - 19 - 

 

24. While we clarify the distinction between our reliability concern and our guidance, 

we disagree with EEI’s “rebuttable presumption” argument. EEI maintains that, in 

directing NERC to develop a test, providing specific guidance on the test, and requiring 

NERC to either follow the Commission’s guidance or propose an “equally efficient and 

effective” alternative, the Commission has essentially established a rebuttable 

presumption that its guidance is correct and efficiently and effectively addresses the 

underlying reliability goal. 

25. While EEI focuses on the section 215(d)(2) requirement that the Commission give 

due weight to the technical expertise of the ERO, its reading of this requirement fails to 

account for the Commission’s authority under section 215(d)(5) to direct the ERO to 

develop a new or modified standard that addresses a specific matter. As an initial matter, 

we note that it is a maxim of statutory construction that each part or section of a statute 

should be construed in connection with every other part or section so as to produce a 

transmission assets that PJM is proposing to acquire with the Commission’s approval of 

FirstEnergy’s application to leave Midwest Independent System Operator, Inc. and join 

PJM. PJM describes its critical facilities test under development as a three step process. 

Step 1 uses an N-2 analysis to identify contingency pairs and the overloaded facility, i.e., 

an initial contingency, followed by a second contingency without system adjustments. 

Step 2 applies to an N-3 analysis where an outage is taken of the N-2 contingency pair 

causing the overload and the overloaded facility identified in Step 1 and the system is 

monitored for additional overloads. Step 3 is the identification of critical facilities, i.e., 

any 100 kV – 200 kV facilities that take an outage following the N-2 combination from 

Step 2 and results in additional overloads. See PJM Planning Committee Report, PRC023 (Aug. 11, 2010), available at http://www.pjm.com/~/media/ committeesgroups/committees/pc/20100811/ 20100811-item-12-prc-023.ashx 
Docket No. RM08-13-001 - 20 - 

 

harmonious whole.39 We find no difficulty in reading section 215(d)(2) in harmony with 

section 215(d)(5). Section 215(d)(2) requires the Commission to give due weight to the 

technical expertise of the ERO when the Commission reviews a Standard or modification 

proposed by the ERO. Section 215(d)(5) authorizes the Commission to direct a 

modification to a Standard if it judges that such a modification is necessary. There is no 

contradiction in the Commission giving due weight to the technical expertise of the ERO 

and still finding that there is a “specific matter” that the ERO must address. EEI’s 

argument tends to diminish the significance of the Commission’s authority to direct 

modifications under section 215(d)(5) because it fails to recognize that the Commission, 

and not just the ERO, has the responsibility and authority to identify “specific matters” 

that it considers appropriate to carry out section 215. Section 215 establishes a paradigm 

by which both the Commission and the ERO are responsible for identifying reliability 

gaps—the ERO through its Reliability Standards development process, where it can 

independently identify areas of concern and develop Standards to address them; and the 

Commission through its review of proposed Reliability Standards and authority to direct 

modifications or new Standards that address specific issues necessary to effectuate the 

purposes of section 215. 

39 Shell Oil Company, et al., In the Matter of the Transportation of Liquid and 

Liquefiable Hydrocarbons by Natural Gas Pipelines, 22 FERC ¶ 61,013, at 61,024 

(1983). 
Docket No. RM08-13-001 - 21 - 

 

26. To the extent that EEI claims that the Commission exceeded its statutory authority 

by providing guidance, we note that the Commission has already rejected this argument. 

In Order No. 693, the Commission explained that providing the ERO with “useful 

guidance to assist in the Reliability Standards development process” is consistent with its 

authority under section 215(d)(5) to direct the ERO to submit a modification that 

addresses a “specific matter.”40 As the Commission elaborated, when the Commission 

identifies a specific matter to be addressed in a modification, “it is important that the 

Commission provide sufficient guidance so that the ERO has an understanding of the 

Commission’s concerns and an appropriate, but not necessarily exclusive, outcome to 

address those concerns.”41 Otherwise, a directive to modify a Reliability Standard might 

be so vague that the ERO would not know how to adequately respond. Thus, to the 

extent that EEI challenges the Commission’s right to provide guidance that explains its 

concerns and a potential way to address them, it is actually challenging Order No. 693 

and its settled understanding that section 215(d)(5) permits the Commission to provide 

such guidance. 

27. Although it is not clear from its pleading, it appears that EEI is concerned about 

the prospect of Commission guidance establishing a “rebuttable presumption” because it 

removes any discretion the ERO has to disagree with the Commission about the 

40 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 186. 

41 Id. P 185. 
Docket No. RM08-13-001 - 22 - 

underlying reliability goal or the means to achieve it. To the extent EEI argues that the 

ERO should be able to use the Standards Development Process to challenge the 

Commission’s identification of a concern or goal, or the assumptions underlying that 

concern or goal, we reject such arguments. While the ERO and other parties are free to 

challenge the Commission’s reasoning in identifying its concern or goal, EEI is incorrect 

about the proper venue for these challenges. Should parties disagree with the content or 

underlying assumptions (technical or otherwise) of the Commission’s concern or goal, 

they are free, as they have in this proceeding, to challenge the Commission’s 

determination through a rehearing and, ultimately, judicial review. In short, we do not 

agree that it is appropriate to re-litigate in the ERO Standards Development Process the 

merits of the Commission’s reliability concern or goal. To the extent EEI argues that the 

Commission’s detailed guidance on a possible approach to address its underlying concern 

or goal establishes a “rebuttable presumption” in favor of the Commission’s proposed 

approach, we reiterate that the ERO may develop an alternative approach that is equally 

efficient and effective at addressing the Commission’s underlying reliability concern or 

goal. 

28. Finally, we reject Duke’s claim that the Commission overruled the guidance 

provided by the ERO System Performance and Control Task Force. 

29. NERC included in its NOPR comments the System Performance and Control Task 

Force guidance for identifying operationally significant 100 kV – 200 kV facilities. The 

Commission did not overrule that guidance but found that it contained a gap. The 
Docket No. RM08-13-001 - 23 - 

Commission stated that the NERC guidance focused primarily on identifying facilities 

that are operationally significant between regions or between sub-regions and, therefore, 

would not necessarily identify operationally significant facilities within a sub-region or a 

single transmission owner or generator owner. The Commission specifically 

contemplated that the ERO could refine the System Protection and Control Task Force’s 

guidance into an acceptable mandatory test.42 

Conflicting Understandings of Conclusions of the Blackout 

Report 

30. As the Commission explained in the Final Rule, PRC-023-001 was developed to 

implement Recommendation 21A of the Blackout Report. Consequently, in stating its 

concern that Requirement R3 fails to provide assurance that planning coordinators will 

identify all facilities that must be identified and made subject to the Standard if the 

Standard is to achieve its purpose and prevent a recurrence of what occurred during the 

blackout, the Commission’s notion of the universe of relays that should be identified by 

the test rests on its interpretation of the Blackout Report. 

Requests for Rehearing

31. EEI challenges the Commission’s interpretation as part of its argument that the 

Commission and the ERO may have different views on the reliability goal to be achieved. 

Below, we explain why we disagree with EEI’s narrow reading of the Final Blackout 

Report. 

 42 Order No. 733, 130 FERC ¶ 61,221 at P 76. 
Docket No. RM08-13-001 - 24 - 

32. EEI adds that it may be difficult for the ERO to develop an alternative to the 

Commission’s approach if the ERO and the Commission have different understandings of 

the reliability goal at issue. EEI states, for example, that NERC and the Commission 

appear to differ in how they understand certain aspects of the August 2003 Blackout and 

the subsequent Blackout Report which explains the causes of the blackout and 

recommendations to minimize the risks of future blackouts. According to EEI, the 

Blackout Report concluded that: (1) thirteen important 345 kV and 138 kV transmission 

lines tripped offline during a four minute time span just prior to the rapid and widespread 

geographic acceleration of the cascading event and the system remained thermally stable 

during these four minutes; (2) the lines tripped, without time delay, because of relays that 

operated exactly as programmed, that is, they were not programmed to delay their 

operation; (3) the relays operated so quickly that they impeded the natural ability of the 

system to hold together and did not allow for operator intervention; (4) the relay 

operations were the “common mode of failure” in the acceleration of the cascade; (5) if 

the lines had not disconnected so quickly and this period of deterioration and overloading 

under stable conditions had lasted for as little as 15 minutes or as much as an hour, it is 

possible that problems could have been recognized and action taken; and (6) while relay 

operations did not cause the cascade, they greatly expanded and accelerated its spread. 

EEI maintains that NERC developed PRC-023-1 to address these conclusions. Further, 

while stating that all the facts and analyses of the August 2003 blackout are not publicly 

available, EEI asserts that “it does appear that if PRC-023-1 had been in place and these 
Docket No. RM08-13-001 - 25 - 

relays had been programmed to delay their operations for even a few minutes, system 

operators would likely have had time to consider other operational decisions that could 

have prevented or mitigated the rapid acceleration of the cascade.”43EEI also asserts that, 

at times, Order No. 733 characterizes transmission relay loadability as a non-critical issue 

during the blackout. As examples of the divergence between NERC and the 

Commission, EEI points to both the Commission’s assertion that tree contact rather than 

relays precipitated the cascade and its conclusion that the cascade would not have been 

prevented if PRC-023-1 had been in place prior to the blackout. While conceding that 

tree contact may have precipitated the blackout, EEI focuses on the Blackout Report’s 

finding that relay loadability was a critical component in the blackout because their 

operation “greatly expanded and accelerated the speed of the cascade.”44

Commission Determination

33. While the Commission agrees with some of the six findings that EEI generalizes 

from the Blackout Report, we disagree with others since detailed information that is 

available from the Blackout Report does not support EEI’s conclusions. First, the 

thirteen important 345 kV and 138 kV lines tripped offline during a four minute time 

span while the system remained thermally stable.45 The first 345 kV line to trip after the 

 43 Id. at 9. 

44 Id. (citing Blackout Report at 82). 

45 The chronology of the tripping of the thirteen important 345 kV and 138 kV 

lines that EEI refers to is available at Figure 6.9 in the Blackout Report. 
Docket No. RM08-13-001 - 26 - 

 

Sammis-Star 345 kV outage was the Galion-Ohio Central-Muskingum 345 kV line that 

tripped due to a phase-to-ground fault.46 Therefore, had PRC-023-1 been in place, the 

tripping of the Galion-Ohio Central Muskingum 345 kV line would not have been 

averted because the line tripped due to a phase-to-ground fault, not due to relay 

loadability. 

34. Second, the Blackout Report further concludes that after the Galion-Ohio CentralMuskingum 345 kV line outage and numerous 138-kV line trips in central Ohio, the East 

Lima-Fostoria Central 345- kV line tripped at 16:09:06 EDT on zone 3 relay operation 

due to high current and extremely low voltage (80 percent).47 Reliability Standard PRC023-1 requires evaluation of relay loadability at 0.85 per unit voltage (85 percent of rated 

voltage) – a more favorable voltage than the 80 percent deteriorated voltage that was 

experienced.48 This recorded fact from the Blackout Report fails to support EEI’s 

assertion that tripping of this important 345 kV line would have been avoided had PRC023-1 been in place. 

46 Blackout Report at 79. The Galion-Ohio Central-Muskingum 345-kV line 

tripped first at Muskingum at 16:08:58.5 EDT on a phase-to-ground fault, reclosed and 

tripped again at 16:08:58.6 at Ohio Central, reclosed and tripped again at Muskingum on 

a Zone 3 relay, and finally tripped at Galion on a ground fault. 

47 Id. 

48 PRC-023-1 Requirement R1.12.2 requires transmission owners, generator 

owners, and distribution providers to evaluate relay loadability at 0.85 per unit voltage 

and a power factor angle of 30 degrees. 
Docket No. RM08-13-001 - 27 - 

he 

 

35. As the third basis for disagreement with EEI, we refer to our discussion of the 

cascade of 138 kV lines in the Final Rule. The cascade of 138 kV lines was precipitated 

by faults caused by tree contact, not protective relays, and would not have been prevented 

if PRC-023-1 had been in effect before the blackout.49 

36. We agree with EEI that the 30 degrees evaluation point was not reached. We note 

however, that at the time the 345 kV Sammis-Star line tripped, the power factor angle 

was moving from normal values up to around 27 degrees.50 Additional changes in other 

parts of the system were recorded so it is reasonable to conclude that the power factor 

angle would have continued to increase. In fact, the Blackout Report shows that the 

voltages in the Akron-Cleveland area were declining with each successive trip of the 345 

kV lines into the area. Immediately prior to the 345 kV Sammis-Star line trip, the voltage 

at the Star substation was declining from just below 90 percent voltage to just above 85 

percent at the time of the trip.51 Since Sammis-Star was one of the two remaining 345 

kV lines supplying the Cleveland-Akron area, any further voltage deterioration in t

Cleveland-Akron area would have further increased the reactive power consumption and 

would have increased the reactive power flow on the Sammis-Star line. Therefore, it 

would be reasonable to conclude that the measured power angle of the line would not 

49 Final Rule at P 52 

50 Blackout Report Figure 6.4 at 78. 

51 Blackout Report Figure 5.6 at 57. 
Docket No. RM08-13-001 - 28 - 

 

have stayed at 27 degrees. Rather, it likely would have continued to increase to either 

approaching or exceeding the 30 degrees evaluation angle. 

37. We also offer several responses to EEI’s other assertion that, if PRC-023-1 had 

been in place and these relays had been programmed to delay their operations for even a 

few minutes, system operators likely would have had time to consider other operational 

decisions that could have prevented or mitigated the rapid acceleration of the cascade. 

First, the Commission understands that most zone 3 relays (or zone 2 relays set to operate 

like zone 3 relays) that misoperated during the August 2003 Blackout, including those 

protection relays now covered by Reliability Standard PRC-023-1, have time 

coordination usually ranging from several milliseconds to several seconds, but rarely 

several minutes.52 Second, the Blackout Report concludes that FirstEnergy had no 

automatic load-shedding schemes in place, and did not attempt to begin manual load52 As discussed in the NOPR, zone 3 relays, and zone 2 relays set to operate like 

zone 3 relays (zone 3/zone 2 relays), provide remote circuit breaker failure and backup 

protection for remote distance faults on a transmission line. These relays are typically set 

to reach 100 percent of the protected transmission line with a margin of more than 100 

percent of the longest line (including any series elements such as transformers) that 

emanates from the remote buses. To ensure coordination of protection, zone 3/zone 2 

relays are set with a longer time delay than the zone 2 relay. NOPR, FERC Stats. & 

Regs. ¶ 32,642 at 9. The zone 3/zone 2 relay setting philosophy (reach setting and time 

delay) can vary among entities. For example, the time delay can typically range from 

0.33 seconds to 1 second, to allow for coordination of protection with the zone 1 relay 

(which is set without an intentional time delay) on the faulted line. See Horowitz, 

Stanley H and Phadke, Arun G., Power System Relaying, West Sussex, England, John 

Wiley & Sons, Ltd., 2008, p. 102 (noting that the time delay can be longer if needed for 

coordination). 
Docket No. RM08-13-001 - 29 - 

 

shedding. It further states, as Chapters 4 and 5 have established, that once Sammis-Star 

tripped, the opportunity of averting the coming cascade by shedding load had passed. 

Within six minutes of these overloads, extremely low voltages, big power swings and 

accelerated line tripping would cause separations and blackout within the Eastern 

Interconnection.53 Without an automatic load shedding scheme in the Akron/Cleveland 

area, there were no feasible corrective measures for system operators to return the fast 

deteriorating system conditions to a safe operating state,54 notwithstanding the fact that 

situational awareness was not maintained by these operators. For this reason, it is the 

Commission’s view that recorded facts from the Blackout Report fail to support EEI’s 

assertion that delayed relay programming of several minutes would have been effective in 

averting the August 2003 Blackout after the 345 kV Sammis-Star outage. 

38. In summary, the Commission also does not agree with EEI’s assertion that Order 

No. 733 characterizes transmission relay loadability as a non-critical issue during the 

blackout. To assert, as Order No. 733 does,55 that one cannot definitely conclude on the 

present record that PRC-023-1 would have prevented the spread of the blackout, or to 

recount that the tripping of the 138 kV system was precipitated by faults caused by tree 

53 Blackout Report at 70. 

54 Id.

55 Order No. 733, 130 FERC ¶ 61,221 at P 55. 
Docket No. RM08-13-001 - 30 - 

contact,56 by no means is intended to minimize the significance of relay loadability. We 

simply do not subscribe to the view that PRC-023-1 would have prevented the loss of the 

Sammis-Star line and the loss of the 13 important 345 kV and 138 kV lines during a four 

minute time span. 

Elements of Test for Identifying Critical Facilities

39. In Order No. 733, the Commission concluded that, to achieve its reliability 

objective of ensuring that relay settings do not limit transmission loadability, PRC-023-1 

must apply to all sub-200 kV facilities that could trip on relay loadability and contribute 

to a cascading outage. Accordingly, the Commission directed NERC to modify the 

Standard to include a mandatory test for planning coordinators to apply to identify which 

sub-200 kV facilities are critical to the reliability of the Bulk-Power System.57 In its 

guidance, the Commission stated that NERC needed to develop a test that (a) defines 

desirable system performance and (b) describes the steady state and dynamic base cases 

that the planning coordinator must use as part of its assessments.58 Thus, a facility would 

 

(continued...) 

56 Id. P 52. 

57 Id. P 69. 

58 The requirements of the Transmission Planning Reliability Standards require 

that entities have studies to show that their portion of the bulk electric system is stable 

and within voltage and thermal limits for a variety of contingencies and base cases that 

cover critical system conditions. Those studies include steady-state and dynamic 

simulations which require specific base cases. Steady-state base cases are used to 

evaluate whether the Bulk-Power System will remain within specified current and steadystate voltage limits before and after contingencies in all of the base cases. Dynamic 

refers to the response of the Bulk-Power System following a transient electric system 
Docket No. RM08-13-001 - 31 - 

be deemed operationally significant if, during a simulation with the base cases, its 

removal from service following an initiating event would prevent desirable system 

performance. 

Desirable System Performance-Related Rehearing Requests

40. The Commission specified that the test for identifying critical facilities between 

100 kV and 200 kV must define expectations of desirable system performance for 

Category B and Category C contingencies.59 With respect to Category B contingencies, 

the Commission stated that NERC’s definition of desirable system performance requires: 

“(1) continuity of all firm load supply, except for supply directly served by the faulted 

facility, and no cascading outages; (2) maintenance of all facilities within their applicable 

thermal, voltage, or stability ratings (short time ratings are applicable); and 

(3) continuance of all firm transfers.”60 In discussing these requirements, the 

Commission stated that there should be only loss of consequential load (i.e., load directly 

 

event such as a fault, tripping and reclosing (if applicable) of a Bulk-Power System 

element, or planned load shedding. Dynamic base cases evaluate, for example, phase 

angles, currents and voltages before, during, and after the event to determine whether the 

Bulk-Power System will remain stable. 

59 Order No. 733, 130 FERC ¶ 61,221 at P 81. Table I of Reliability Standard 

TPL-002-1 identifies required system performance during various types of events, 

referred to by “Category.” A Category B contingency is an event resulting in the loss of 

a single element. Category C contingencies are event(s) resulting in the loss of two or 

more (multiple) elements. 

60 Id. P 84. 
Docket No. RM08-13-001 - 32 - 

served by the element removed from service) for Category B contingencies and noted in a 

footnote that Table I, footnote b of Reliability Standard TPL-002-0 (footnote b) allows 

for the interruption of firm load for consequential load loss.61 The Commission also 

stated desirable system performance entails continuity of firm transfers: 

[W]hile the curtailment of firm transfers is permitted to 

prepare for the next contingency, it is generally not the 

desired system performance for single contingencies required 

by Table I of the TPL Reliability Standards. Thus, continuity 

of all firm transfers is the third component of desirable 

system performance.62 

41. On rehearing, parties raise several concerns regarding the Order No. 733 

discussion of desirable system performance. 

Authority to Require the Standard to Define Desirable System 

Performance 

42. Duke argues that the Commission’s directive to define “desirable system 

performance” exceeds the Commission’s authority. Duke explains that “desirable system 

performance” appears to be a criteria for judging the operation of the Bulk-Power System 

that is different from the statutorily defined standard or criteria of “Reliable Operation.”63 

 

(continued...) 

61 Id.

62 Id. P 83. 

63 Section 215(a)(3) of the FPA defines a “Reliability Standard” as a requirement 

to provide for “reliable operation” of the bulk-power system. Section 215(a)(4) defines 

“Reliable Operation” as: 

[O]perating the elements of the bulk-power system within 

equipment and electric system thermal, voltage, and stability 
Docket No. RM08-13-001 - 33 - 

 

Duke argues that the Commission may not unilaterally impose a new legal standard or 

criteria to replace “Reliable Operation.” 

43. Duke also argues that the Commission’s expectation of “desirable system 

performance” for Category B contingencies is more stringent than the statutory standard 

of “Reliable Operation.” Duke explains that “Reliable Operation” requires entities to 

operate the Bulk-Power System to avoid: (1) instability; (2) uncontrolled separation; and 

(3) cascading failure, while the Commission’s definition of “desirable system 

performance” includes the additional requirement that entities operate the system to avoid 

the loss of non-consequential load. Duke claims that planning for the loss of nonconsequential load is often specifically designed to preclude instability, uncontrolled 

separation, and cascading failures. 

44. Further, EEI and Duke maintain that the Commission’s statements about the 

requirements of footnote b and the permissibility of non-consequential load loss are 

inconsistent with footnote b and prejudge the outcome of the proceeding in Docket No. 

RM06-16-009. 

45. EEI explains that, contrary to the Commission’s statements in Order No. 733, 

Table I, footnote b of TPL-002-0 currently allows for certain non-consequential (i.e., 

limits so that instability, uncontrolled separation, or cascading 

failures of such system will not occur as a result of a sudden 

disturbance, including a cybersecurity incident, or 

unanticipated failure of system elements. 
Docket No. RM08-13-001 - 34 - 

 

firm) load loss in a local network.64 In Docket No. RM06-16-009, the Commission 

established a deadline of June 30, 2010, which was subsequently extended to March 31, 

2011, for NERC to comply with the Commission’s directive in Order No. 693 to clarify 

footnote b.65

46. EEI and Duke contend that the Commission’s statements in Order No. 733 reflect 

the Commission’s assumption about how the proceeding in Docket No. RM06-16-009 

will conclude, even though the Commission has not yet issued a final rule in that 

proceeding. EEI also maintains that, since the Commission in Order No. 733 effectively 

prescribed the specific modification to footnote b that NERC must submit in Docket No. 

RM06-16-009, it deprived NERC of its statutory right to develop the modification. 

47. Similarly, EEI argues that rather than specify “continuity of firm transfers” as the 

third component of desirable system performance, the Commission should have required 

64 Footnote b of TPL-002-0 states: 

Planned or controlled interruption of electric supply to radial 

customers or some local Network customers, connected to or 

supplied by the Faulted element or by the affected area, may 

occur in certain areas without impacting the overall reliability 

of the interconnected transmission systems. To prepare for 

the next contingency, system adjustments are permitted, 

including curtailments of contracted Firm (non-recallable 

reserved) electric power Transfers. 

65 Mandatory Reliability Standards for Bulk-Power System, 131 FERC ¶ 61,231, 

at P 26 (2010). 
Docket No. RM08-13-001 - 35 - 

that “continuity of all firm transfers be consistent with the TPL Standards.”66 EEI 

explains that while the Commission’s statement that “curtailment of firm transfers is 

permitted to prepare for the next contingency” is consistent with footnote b, the 

Commission’s assertion that curtailments are “generally not the desired system 

performance for single contingencies” and its conclusion that “continuity of firm 

transfers is the third component of desirable system performance” are not consistent with 

footnote b because they preclude the interruption of firm transmission service to prepare 

for the next contingency. 

Commission Determination

48. First, as explained above, we want to clarify that our underlying reliability concern 

is that an entity subject to the test in PRC-023 know what desirable system performance 

is so that it can identify when it has not met this performance standard. The Commission 

continues to believe that it is appropriate for NERC to define desirable system 

performance in reference to compliance with currently effective Reliability Standards. 

As discussed below, while Order No. 733 provided other specifics on what the 

Commission intended would include in desirable system performance, these specifics 

were intended to be guidance and not strict requirements for the test. 

 66 EEI at 11. 
Docket No. RM08-13-001 - 36 - 

 

49. We disagree with Duke’s assertion that the Commission exceeded its authority by 

imposing a different and more stringent legal standard than Reliable Operation through 

its definition of desired system performance and deny Duke’s request for a rehearing of 

this matter. In defining desirable system performance, the Commission turned to existing 

Reliability Standards relating to transmission system planning since they were developed 

by the ERO specifically to promote the Reliable Operation of the Bulk-Power System. 

50. Reliability Standard PRC-023-1 was developed by NERC to avoid the undesirable 

system performance that Recommendation 21A of the Blackout Report67 sought to 

prevent.68 As stated in Order No. 733: “To achieve this goal, the test to determine which 

sub-200 kV facilities are subject to PRC-023-1 must include or be consistent with the 

system simulations and assessments that are required by the TPL Reliability 

Standards....”69 Accordingly, the Commission relied on the approved Reliability 

Standards developed by NERC through its open stakeholder process to determine the 

67 The Blackout Report Recommendation 21A states: 

 A. Evaluation of Zone 3 Relays 

 NERC: Industry is to review zone 3 relays on lines of 230 kV 

and higher. 

 Task Force: Recommends that NERC broaden the review to 

include operationally significant 115 kV and 138 kV lines, e.g., lines that 

are part of monitored flowgates or interfaces. Transmission owners should 

also look for zone 2 relays set to operate like zone 3s. 

68 NERC July 30, 2008 Petition, Docket No. RM08-13-000, at 7. 

69 Order No. 733, 130 FERC ¶ 61,221 at P 79. 
Docket No. RM08-13-001 - 37 - 

 

appropriate definition of desirable system performance. Our remaining discussion in 

Order No. 733 was intended to provide insight as to the TPL Reliability Standard 

requirements that were relevant to this discussion.70 

51. Further, we disagree with Duke that the Commission’s comments on the terms of 

a test set a performance standard. Unlike the TPL Reliability Standards themselves, the 

test contemplated by the Commission’s directive in PRC-023-1 serves only to identify 

existing system elements that could trip on relay loadability and contribute to cascading 

outages. 

52. We disagree with Duke’s concerns regarding the dropping of non-consequential 

load. Duke misunderstands our discussion of this issue. PRC-023-1 does not prohibit the 

dropping of non-consequential load. When Order No. 733 was issued, the Commission’s 

guidance with respect to desirable system performance was based on the TPL Reliability 

Standards, subject to the Commission’s direction to modify footnote b of TPL Reliability 

Standards Table I issued in 2007 in Order No. 693.71 The ERO is currently developing a 

(continued...) 

70 For example, Reliability Standard TPL-002-0 requires each planning authority 

and transmission planner to “demonstrate through a valid assessment that its portion of 

the interconnected transmission system is planned such that the Network can be operated 

to supply projected customer demands and projected Firm (non-recallable reserved) 

Transmission Services...under the contingency conditions defined in Category B of 

Table I.” Similarly, Reliability Standard TPL-003-0 addresses Category C contingencies. 

Thus, the Commission drew its definition of desirable system performance from TPL 

Reliability Standards Table I (Transmission System Standards – Normal and Emergency 

Conditions). 

71 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1794 (footnotes omitted) 
Docket No. RM08-13-001 - 38 - 

modification to footnote b pursuant to the Commission’s directive. To the extent that 

Order No. 733 can be read as inconsistent with the directive regarding footnote b of TPL 

Reliability Standards Table I in Order No. 693, the Commission grants limited rehearing 

to clarify that the test to determine which sub-200 kV are subject to PRC-023-1 should be 

consistent with the TPL Reliability Standards and the Commission’s directive on footnote 

b of TPL Reliability Standards Table I as set forth in Order No. 693. Once the 

Commission approves a modified footnote b addressing non-consequential load loss or 

the continuance of firm transfers, the definition of desirable system performance should 

be adjusted to be consistent with the modified TPL Reliability Standards. 

Base Cases

53. In addition to defining desirable system performance, the Commission required 

that NERC’s test describe the steady state and dynamic base cases that the planning 

coordinator must use in assessing facilities. In Order No. 733, the Commission stated 

 

states: 

Based on the record before us, we believe that the transmission planning 

Reliability Standard should not allow an entity to plan for the loss of nonconsequential load in the event of a single contingency. The Commission 

directs the ERO to clarify the Reliability Standard. Regarding the 

comments of Entergy and Northern Indiana that the Reliability Standard 

should allow entities to plan for the loss of firm service for a single 

contingency, the Commission finds that their comments may be considered 

through the Reliability Standards development process. However, we 

strongly discourage an approach that reflects the lowest common 

denominator. The Commission also clarifies that an entity may seek a 

regional difference to the Reliability Standard from the ERO for casespecific circumstances. 
Docket No. RM08-13-001 - 39 - 

that the base cases must “bracket all stable operating conditions,”72 represent “all feasible 

types and locations of faults,”73 and include “all stable operating conditions and 

allowable topologies.”74 The Commission also stated that the test must include “the 

effects of the failure of a single component within the as designed Protection Systems, 

consistent with TPL-002-0 Requirement R1.3.10, but with regard to backup and 

redundant protection systems.”75

54. On rehearing, parties raise several concerns regarding the Order No. 733 

discussion of base cases to be run as part of the critical facility test.

Inclusion of Dynamic Studies 

55. EEI and the Trade Associations challenge the requirement that the test include 

dynamic studies. EEI states that PRC-023-1 applies only to steady state loadability of 

 72 Order No. 733, 130 FERC ¶ 61,221 at P 79 (emphasis added). 

73 Id. P 87 (emphasis added). 

74 Id. P 88 (Item 2) (emphasis added). 

Include all stable operating conditions and allowable 

topologies, such as all allowable planned outages. This is 

consistent with TPL-002-0, Requirement R1.3.12. (which 

requires that the planned (including maintenance) outage of 

any bulk electric equipment (including protection systems or 

their components) be included at those demand levels for 

which planned (including maintenance) outages are 

performed); and TOP-004 Requirement R4 (which requires 

operating the actual system in a known operating state). 

75 Id. P 88 (Item 4) (emphasis added). 
Docket No. RM08-13-001 - 40 - 

transmission relays, not to dynamic swings that may entail issues regarding relay 

characteristics. The Trade Associations agree that the Standard is designed for non-fault, 

non-power swing steady state conditions, and add that its purpose is to prevent relays 

from prematurely taking transmission elements out of service, which could prevent 

operators from taking controlled action, when the loss of a parallel element (or elements) 

causes an overload. The Trade Associations point to the Standard’s focus on overloads 

(i.e., non-fault, non-power swing currents) on parallel elements as evidence that load flow 

studies, which reflect steady state conditions, are the only studies that need to be included 

in the test to determine which facilities will be subject to the Standard.

Commission Determination

56. We deny rehearing. By its terms, the purpose of PRC-023-1 is to ensure 

“[p]rotective relay settings shall not limit transmission loadability; not interfere with 

system operators’ ability to take remedial action to protect system reliability and; be set 

to reliably detect all fault conditions and protect the electrical network from these 

faults.”76 

57. Since relays will respond to real-time system conditions, PRC-023-1’s purpose is 

not limited to addressing only steady state loadability conditions. It requires the 

consideration of dynamic loadability conditions, such as the stable but dynamic power 

 76 Reliability Standard PRC-023-1 (Transmission Relay Loadability) at A.3. 

Purpose. 
Docket No. RM08-13-001 - 41 - 

 

swings that occurred during the August 2003 blackout. In Order No. 733, the 

Commission was persuaded by NERC’s request to allow PRC-023-1 to remain focused 

on steady state relay loadability and allow NERC to address stable power swings in a 

different Reliability Standard,77 but this does not mean that dynamic base cases are 

unnecessary for purposes of PRC-023-1. Therefore, because we disagree with EEI and 

the Trade Associations’ assertion that PRC-023-1 applies only to steady state loadability, 

we do not believe the criterion to include dynamic base cases is inconsistent with PRC023-1. 

58. In determining which facilities between 100 and 200 kV are critical to the 

reliability of the bulk electric system and must be subject to this standard, the planning 

coordinator must assess all operating conditions. Otherwise there may be a gap in which 

a facility may be critical under one operating condition, but not subject to the standard 

because this operating condition was not studied. To this end, the test must be informed 

by the other mandatory Reliability Standards. PRC-023-1 interacts with Facilities 

Design, Connections and Maintenance Reliability Standards, Interconnection Reliability 

Operations and Coordination Reliability Standards, and Transmission Operations 

Reliability Standards. These interactions require applicable entities to establish limits for 

all system elements; interconnected systems must be operated within these limits; 

operators must take immediate action to mitigate operation outside of these limits; and 

77 Order No. 733, 130 FERC ¶ 61,221 at P 173. 
Docket No. RM08-13-001 - 42 - 

 

protective relays must refrain from operating until the observed condition on their 

protected element exceeds these limits.78 To ensure that the protective relays set 

according to PRC-023-1 refrain from operating until the observed condition on their 

protected elements exceed system operating limits, dynamic conditions need to be studied 

as part of the required valid assessment required by the TPL Reliability Standards. 

59. The following provides the Commission’s guidance as to how the ERO could 

implement the requirement to study dynamic states. To perform a valid assessment as 

required by the TPL Reliability Standards, a planning authority or transmission planner 

must demonstrate that its network can be operated to supply projected customer demand 

and projected firm transmission service, at all demand levels, over the range of forecast 

system demands, and under the contingency conditions defined in Table I.79 The valid 

assessment includes the performance of the system for all stable operating conditions: 

steady state and dynamic. Because NERC developed PRC-023-1 to address the 

inadvertent tripping of facilities due to loadability that occurred during the August 2003 

Blackout, the test to identify applicable critical facilities must also consider the dynamic 

conditions that resulted in such inadvertent tripping. As previously mentioned, dynamic 

base cases are used to evaluate, for example, phase angles, currents and voltages before, 

during and after contingencies to determine whether the Bulk-Power System will remain 

78 Id. P 164. 

79 Id. P 85. 
Docket No. RM08-13-001 - 43 - 

stable in all of the base cases. Steady state load flow analysis will capture only one 

aspect of the system response characteristics. 

60. Studying steady states alone will not be adequate to ensure that all protection 

relays critical to the reliability of the system will be captured under PRC-023. Only a 

valid assessment that includes the use of steady state load flow and transient stability 

analyses representing the system conditions before and after contingencies will ascertain 

whether the protection relays will not misoperate during the transient or dynamic phase 

during and immediately after a disturbance, or after the system has settled to another 

steady state once the faulted element is removed and should be required to comply with 

PRC-023-1. For this reason, dynamic base cases are not only appropriate, but consistent 

with the study tools and practices utilized by planners, in coordination with protection 

engineers, in accordance with the TPL Reliability Standards. To ignore protection relay 

performance during dynamic conditions, such as those that occurred during the August 

2003 Blackout, would not be consistent with PRC-023-1 which is intended to ensure that 

relays operate reliably for faults but do not limit transmission loadability. 

Requirement to Include All Stable Operating Conditions 

61. EEI and the Trade Associations challenge the requirement that base cases must 

“bracket all stable operating conditions,” represent “all feasible types and locations of 

faults,” and include “all stable operating conditions and allowable topologies.” EEI and 

the Trade Associations argue that these expectations are impractical, unduly burdensome, 

practically impossible, and technically unreasonable. 
Docket No. RM08-13-001 - 44 - 

itical 

ntity.” 

 

62. EEI also claims that the Commission provided contradictory guidance; EEI 

explains that while the Commission indicated that every possible condition and topology 

needs to be studied, some of its statements appear to suggest otherwise. EEI points 

specifically to the Commission’s clarification that it was not requiring planning 

coordinators to use Category D contingencies to determine whether a facility is subject to 

PRC-023-1, and to the Commission’s acknowledgement that “relay settings can not be 

determined with great certainty for extreme multi-contingency conditions,” which are the 

types of conditions consistent with Category D contingencies.80 EEI further observes 

that the Commission acknowledged a second time that “relays cannot be set reliably 

under extreme multi-contingency conditions” and specifically recognized that “it is not 

realistic to expect the ERO to develop Reliability Standards that anticipate every 

conceivable critical operating condition applicable to unknown future configurations for 

regions with various configurations and operating characteristics.”81 EEI argues that the 

Commission should drop the requirement that base cases include all stable operating 

conditions and allowable topologies or, at a minimum, make the requirement consistent

with the TPL Reliability Standards, which require planning coordinators to “cover cr

system conditions and study years as deemed appropriate by the responsible e

80 Id. P 95. 

81 Id. P 168. 
Docket No. RM08-13-001 - 45 - 

Commission Determination

63. We deny rehearing, but will clarify our determination. Our primary concern in 

requiring the planning coordinators to create base cases is to ensure that the study is 

robust enough to capture all facilities between 100 and 200 kV that are critical to the 

operation of the bulk electric system. Protective relays covered by PRC-023-1 are 

expected to operate correctly (i.e., for fault conditions and not due to system or 

transmission loadability) for all stable operating conditions and allowable topologies for 

all feasible types and locations of faults.82 As the Commission stated in Order No. 693, 

the performance of the Bulk-Power System is assessed for a “range of operating 

conditions and contingencies [and] determining those operating conditions and 

contingencies that have an undesirable reliability impact.”83 This is consistent with the 

development of the valid transmission assessment required by TPL Reliability Standards. 

We therefore grant EEI’s request for clarification that the base cases should be consistent 

with those studied under the TPL series of standards. 

64. We intended our statements requiring the test to include a study of all stable 

operating conditions to be consistent with the studies currently carried out pursuant to 

 82 Id. P 87; Reliability Standard PRC-023-1 A.3. 

83 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1683. 
Docket No. RM08-13-001 - 46 - 

 

currently effective Reliability Standards TPL-002-0 and TPL-003-0.84 Much of the rest 

of our discussion in Order No. 733 was intended to provide insight as to the TPL 

Reliability Standard requirements that were relevant to this issue. We note that, if in the 

discretion of the ERO it believes it is more efficient, the identification of operationally 

significant 100 kV – 200 kV facilities could also be identified as part of the assessments 

currently performed by transmission planners based on the performance of the system to 

their operation. 

65. Contrary to what petitioners assert, the Commission did not conclude that the 

applicability of PRC-023-1 should be determined based on Category D contingencies. In 

the Final Rule, the Commission acknowledged that Reliability Standard TPL-004-0 does 

not require corrective plans such that the Bulk-Power System would avoid cascading or 

instability for such contingencies but only requires that the transmission planner has 

evaluated its system for such extreme events.85 For purposes of clarity, the Commission 

affirms that its guidance regarding base cases did not intend to include Category D 

events. Rather, the base cases are meant to be tested for all feasible types and locations 

of faults and include all stable operating conditions and allowable topologies when tested 

84 Reliability Standard TPL-002-0 (System Performance Following Loss of a 

Single Bulk Electric System Element (Category B)), at Requirement R1; Reliability 

Standard TPL-003-0 (System Performance Following Loss of Two or More Bulk Electric 

System Elements (Category C)), at Requirement R1. 

85 Order No. 733, 130 FERC ¶ 61,221 at P 95. 
Docket No. RM08-13-001 - 47 - 

against, consistent with the requirements for studying Category B and Category C 

contingencies. 

TPL-002, Requirement R1.3.10

66. On March 18, 2010, the Commission issued a Notice of Proposed Rulemaking in 

Docket No. RM10-6-000 proposing to reject NERC’s interpretation of Reliability 

Standard TPL-002-0, Requirement R1.3.10. NERC’s proposed interpretation would 

consider protection failure to be studied only as part of Category C contingencies 

addressed in TPL-003-0. Taking a different tack, the Commission proposed to interpret 

Requirement R1.3.10 of TPL-002-0 as requiring assessments that study non-operation of 

primary protection system devices to assess how the backup or redundant protection 

system or device maintains system performance. The Commission’s interpretation 

indicated that non-operation of a primary protection system is not a contingency,86 but 

one of the base cases.87

 86 Interpretation of Transmission Planning Reliability Standard, Notice of 

Proposed Rulemaking, FERC Stats. & Regs. ¶ 32,655, at P 21 (2010) (“The Commission 

proposes to interpret that the non-operation of a non-redundant primary protection system 

is not a contingency and Requirement R1.3.10 requires that the planner model, as a 

condition in the base case, the non-operation of the primary protection system, 

accounting for operation of the redundant protection system or, alternatively, the fact that 

the protection system is not redundant, as appropriate”). 

87 Id. P 10 (“Requirement R1.3 defines the criteria for the ‘base cases’ that must 

be included in the studies to support the assessment. Requirement R1.3.10 provides as a 

base case criteria that the studies must include the effects of existing and planned 

protection systems, including any backup or redundant systems”). 
Docket No. RM08-13-001 - 48 - 

Requests for Rehearing

67. Duke and the Trade Associations argue that the Commission’s expectation that 

base case studies include the effects of the failure of a single component within the as 

designed Protection Systems, “consistent with TPL-002-0 Requirement R1.3.10” 

prejudges the outcome of the proceeding in Docket No. RM10-6-000. In that docket, the 

Commission proposed to reject NERC’s interpretation of TPL-002-0 Requirement 

R1.3.10 and to adopt an alternative interpretation. Duke and the Trade Associations 

maintain that the Commission should not apply an interpretation in this proceeding that is 

the subject of a proposed rulemaking in another proceeding. The Trade Associations 

argue that if the Commission insists on this requirement, it should make it subject to the 

outcome of the proceeding in Docket No. RM10-6-000. 

68. EEI argues that TPL-002-0 does not address system protection failures, as the 

Commission stated when it required that base cases “include the effects of a failure of a 

single component within the as designed Protection Systems, consistent with TPL-002-0 

Requirement R1.3.10.” EEI states that TPL-003-0 and TPL-004-0 address protection 

system failures. 

Commission Determination

69. The Commission grants rehearing of our statements regarding TPL-002-0 

Requirement R1.3.10. As stated above, the Commission believes the test to determine 

which sub-200 kV facilities are subject to PRC-023-1 should be consistent with the 

system simulations and assessments that are required by the TPL Reliability Standards. 
Docket No. RM08-13-001 - 49 - 

Consequently, we grant rehearing to the extent that our guidance in Order No. 733 differs 

from the currently effective language of TPL-002-0 Requirement R1.3.10. Until the 

Commission issues an order approving an interpretation of Requirement R1.3.10 in 

Docket No. RM10-6-000, NERC may use its own interpretation of the Reliability 

Standard as written to formulate the test. And once the Commission approves an 

interpretation of Requirement R1.3.10, the base cases component of the critical facilities 

test should be made consistent with that interpretation. 

Other Test Criteria 

70. Petitioners raise several additional concerns about the clarity and consistency of 

the Commission’s guidance on the test for identifying critical facilities. Both the Trade 

Associations and EEI refer to the Commission’s discussion concerning validating relay 

settings on system conditions that the relays could experience, including acceptable 

margins applied to minimum voltages and power factor angles, as ambiguous and 

incorrect.88 It is the Trade Associations’ view that the Commission misinterprets the 

NERC System Protections and Control Task Force as assuming that relay settings are to 

be validated by operators to reflect changing system conditions. Rather, the Trade 

Associations assert, what the System Protections and Control Task Force contemplated, 

and what PRC-023-1 provides, is the establishment of reasonable margins (e.g., the 115 

 88 Trade Associations at 7 n.3; EEI at 13 (citing Order No. 733, 130 FERC 

¶ 61,221 at P 56). 
Docket No. RM08-13-001 - 50 - 

percent and 150 percent requirements set forth in Requirement R1.10) to encompass the 

system conditions that relays could experience. 

71. EEI asserts the Commission’s statement that radial transmission facilities serving 

load with only one transmission source are not included in NERC’s definition of “bulk 

electric system” conflicts with Requirement R1.10, which applies to transmission lines 

terminated only with a transformer.89 EEI similarly argues that the Commission’s 

statement that the “test set forth above is best implemented uniformly across all regions” 

is inconsistent with the Commission’s acknowledgement that some issues may not affect 

some utilities as a result of physical differences in network design and performance.90 

Commission Determination

72. We deny rehearing and provide the following clarification. First, we clarify in this 

order that our discussion of test criteria other than those incorporating concepts required 

in currently effective Reliability Standards was intended to be guidance for the ERO to 

consider in developing a test to identify the facilities subject to the Standard. While we 

believe including these items identified in Order No. 733 is one way to accomplish the 

goal of identifying the appropriate facilities, we want to make clear that the ERO can 

develop an alternative proposal for addressing the Commission’s concerns with the 

understanding that any such alternative must be as effective as, or more effective than, 

 89 EEI at 14 (citing Order No. 733, 130 FERC ¶ 61,221 at P 94). 

90 Id. (citing Order No. 733, 130 FERC ¶ 61,221 at P 92). 
Docket No. RM08-13-001 - 51 - 

 

the Commission’s proposed approach in addressing the identified technical and other 

concerns. However, to clarify our intention in incorporating these items into our 

guidance in Order No. 733, we will provide some additional discussion in response to the 

rehearing requests. 

73. EEI and the Trade Associations misunderstand Order No. 733 statements 

regarding validating relay settings. By its own terms, Reliability Standard PRC-023-1 

applies only to load-responsive phase protection relays—one of the several types of 

protection relays. The Standard, therefore, cannot be applied in a vacuum; other 

Reliability Standards must be taken into account to ensure that settings contemplated in 

PRC-023-1 do not preclude compliance with other Reliability Standards. In Order No. 

733, the Commission quotes approvingly from the NERC System Protection and Control 

Task Force to reinforce the point that relay engineers need to ensure that all relay settings 

provide appropriate margin with respect to both the particular equipment and the system 

as a whole. 

74. In response to EEI’s concern regarding radial facilities, we believe that EEI 

misunderstood our intention and do not believe that our discussion of radial facilities in 

Order No. 733 is inconsistent with Reliability Standard PRC-023-1 Requirement R1.10.91 

91 By the terms of Reliability Standard PRC-023-1, the requirement applies to 

transformers with low side voltages equal to or above 200 kV and, if identified by the 

planning coordinator, transformers with low side voltages equal to or above 100 kV. 

These are not the type of transformer used to supply load with one radial transmission 

line. 
Docket No. RM08-13-001 - 52 - 

 

In the paragraph petitioners point to, the Commission addressed arguments that 

Reliability Standard PRC-023-1 should not apply to radial transmission lines by referring 

to NERC’s definition of bulk electric system.92 NERC’s definition of “Bulk Electric 

System” states that “[r]adial transmission facilities serving only load with one 

transmission source are generally not included in [the definition of Bulk Electric 

System.]”93 Requirement R1.10 of PRC-023-1 was created by the NERC Reliability 

Standard development process and submitted to us for approval. However, we did not 

read it as being at odds with NERC’s definition of the bulk electric system because, by its 

terms, it only applies to transformers with low voltage terminals of 100 kV or greater. 

Few lines that terminate at such a transformer are radial transmission facilities serving 

only load with one transmission source. As mentioned below, Requirement R1.10 can 

apply to autotransformers between different Bulk-Power System voltages. Accordingly, 

we do not understand our statements regarding the NERC Statement of Criteria Registry 

to be at odds with PRC-023-1 Requirement R1.10. 

75. Lastly, on the advice of the ERO that the effects of Reliability Standard PRC-023-

1 are not constrained to regional boundaries, the Commission stated in Order No. 733 that 

any test to identify critical facilities must be consistent across regions so that the effects 

92 Order No. 733, 130 FERC ¶ 61,221 at P 94. 

93 Glossary of Terms Used in Reliability Standards, (Feb. 2008), available at

http://www.nerc.com/files/Glossary_12Feb08.pdf. 
Docket No. RM08-13-001 - 53 - 

of protection relay operation are consistent.94 The Commission has acknowledged that 

the goal of greater uniformity does not mean that regional differences cannot exist,95 but 

we also believe that uniformity of Reliability Standards should be the goal and the 

practice, the rule rather than the exception.96 Accordingly, we do not consider it to be 

inconsistent to acknowledge in Order No. 733 that some issues may not affect some 

utilities as a result of physical differences in network design and performance, but 

nevertheless direct a uniform approach be taken in testing for critical facilities.

Deadline to File Test

 Rehearing Request

76. The Commission directed NERC to develop the test, apply it to a representative 

sample of utilities from each of the three Interconnections, and file the test and the results 

from the representative sample no later than March 18, 2011, one year from the date of 

Order No. 733. NERC requests that the Commission extend the deadline for filing the 

test to 24 months from the date the Commission issues an order on rehearing in this 

proceeding. NERC argues that an extension of time is necessary to guarantee that it has 

 94 Order No. 733, 130 FERC ¶ 61,221 at P 92. 

95 Order No. 672, FERC Stats. & Regs. ¶ 31,204 at P 291. 

96 Id. P 290. 
Docket No. RM08-13-001 - 54 - 

sufficient time to develop the test through the Reliability Standards development 

process.97 

77. NERC explains that if it follows the Commission’s suggestion and bases the test 

on the voluntary guidelines previously developed by the NERC System Protection and 

Control Task Force, it could use existing study regimes as part of the Reliability Standard 

development process and meet the Commission’s deadline; however, if industry 

determines that the voluntary NERC guidelines are insufficient and that a different, more 

technical analysis is warranted, NERC would have to consult a wide array of industry 

experts and NERC technical committees, and require new studies beyond those currently 

conducted by Planning Coordinators and Transmission Owners.98 NERC adds that the 

test would then need to be vetted through the Reliability Standards development process 

and field tested on a representative sample of utilities. NERC does not believe that it 

would be possible to perform all of these tasks within the one-year timeframe established 

by the Commission in Order No. 733. 

 Commission Determination

78. We grant NERC’s request that the deadline for filing the test and the results from a 

representative sample of utilities in each of the three Interconnections be extended to 

twenty-four months from the date of this order. The Commission believes the ERO 

 97 NERC at 5. 

98 Id.
Docket No. RM08-13-001 - 55 - 

should have sufficient time to utilize its Reliability Standards development process and 

consult with technical experts and its technical committees. We note in the meantime, 

however, entities must comply with the Standard as approved in Order No. 733. 

Applicability to Below 100 kV Facilities

 Order No. 733

79. As approved by the Commission, PRC-023-1 does not apply to any sub-100 kV 

facility. The Commission determined that the failure to apply the Reliability Standard to 

operationally critical facilities, regardless of their size constituted a gap in the enhanced 

reliability program created by PRC-023-1. Order No. 733 stated that facilities such as 

auxiliary power facilities for nuclear plants and the “cranking path” from black start 

generators to the Bulk-Power System are facilities that may have sub-100 kV elements, 

and so would be omitted from the requirements of the Reliability Standard. The order 

found that the loss of such facilities can affect the reliability of the Bulk-Power System. 

Because the ERO had already recognized that sub-100 kV facilities can play a significant 

role in the Reliable Operation of an Interconnection, the Commission directed the ERO to 

modify the Standard to apply to sub-100 kV facilities but sought to limit its application to 

facilities that are: (1) owned or operated by a currently Registered Entity or an entity that 

becomes a Registered Entity in the future; (2) associated with a facility that is included 

on a critical facilities list defined by the Regional Entity; (3) employing load-responsive 
Docket No. RM08-13-001 - 56 - 

 

phase protection relays in its protection system(s); and (4) identified by the critical 

facilities test that the Commission required NERC to develop.99 

80. In response to NOPR comments questioning the technical basis for applying the 

Standard to sub-100 kV facilities, the Commission explained that such facilities should 

be subject to the Standard because their loss can affect the reliability of the Bulk-Power 

System.100 

81. The Commission also rejected NOPR comments arguing that it was required to 

give “due weight” to NERC’s exclusion of sub-100 kV facilities from the Standard.101 

The Commission explained that NERC failed to provide a sufficient technical 

justification for the initial exclusion and offered no technical argument against the 

Commission’s proposal; noting that, in its NOPR comments, NERC stated that applying 

the Standard to sub-100 kV facilities “may have merit” and “would require further 

study.”102 The Commission cited these comments as an indication that NERC did not 

affirmatively consider applying the Standard to sub-100 kV facilities and then reject the 

idea on the basis of its technical expertise. 

99 Order No. 733, 130 FERC ¶ 61,221 at P 62. 

100 Id. P 67. 

101 Id.

102 Id. (citing NERC comments at 18). 
Docket No. RM08-13-001 - 57 - 

82. Finally, with respect to comments arguing that any expansion of the Standard must 

be developed through the Reliability Standards development process, the Commission 

clarified it did not prescribe this specific change as an exclusive solution to its reliability 

concerns regarding sub-100 kV facilities. As with its other directives, the Commission 

stated the ERO could propose an alternative solution that it believes is an equally 

effective and efficient approach to addressing the Commission’s reliability concerns 

about the absence of sub-100 kV facilities from the Standard. Moreover, while the 

Commission stated that it expected planning coordinators to use the same test to identify 

critical sub-100 kV facilities as they use to identify critical 100 kV-200 kV facilities, it 

clarified that the ERO could, pursuant to Order No. 693, propose a modified Standard 

that contains a different test for sub-100 kV facilities, provided that the test represents an 

“equivalent alternative approach.” 

 Rehearing Request

83. EEI and the Trade Associations request rehearing of the Commission’s directive to 

make PRC-023-1 applicable to sub-100 kV facilities. They note that the Blackout 

Report provides no evidence to support extending the Reliability Standard to sub-100 kV 

facilities. EEI further asserts that the failure of the Commission to give a reasoned 

explanation for the extension renders its directive arbitrary and capricious. Additionally, 

EEI notes that the Commission’s failure to identify a specific concern with the failure to 
Docket No. RM08-13-001 - 58 - 

extend the Standard to sub-100 kV facilities means the ERO is unable to develop an 

alternative but equally efficacious approach to addressing the directive.103

84. The Trade Associations argue that NERC’s failure to study the appropriateness of 

extending the Standard to sub-100 kV facilities does not justify subjecting each such 

registered facility to the Standard’s operational significance tests, but merely supports 

directing NERC to study the matter. The Trade Associations also make the “indirect due 

weight” argument stating that while NERC may be free to develop an alternative 

approach to the directive, NERC appears to be denied the ability now to study the matter 

and determine that the extension of PRC-023-1 is not necessary or appropriate to achieve 

reliability of the Bulk-Power System.104

85. The Trade Associations’ request that the Commission direct NERC to study 

whether there is merit to extending PRC-023-1 to facilities below 100 kV and, if so, 

whether already registered sub-100 kV facilities should be evaluated for operational 

significance under the same tests as applied to 100 kV to 200 kV facilities.105 

 Commission Determination

86. We deny rehearing. Critical assets are defined by NERC as facilities, systems, and 

equipment that, if rendered unavailable, would affect the reliability or operability of the 

 103 EEI at 15-16. 

104 Trade Associations at 14-15. 

105 Id. at 15. 
Docket No. RM08-13-001 - 59 - 

 

bulk electric system.106 The Commission believes that there may be critical facilities 

below 100 kV that are also critical to the reliability of the bulk power system under PRC023-1. In order to address what it perceived as a gap in the applicability of PRC-023-1, 

the Commission directed the ERO to modify the Reliability Standard to apply to sub100kV facilities that are associated with a facility that is included on a critical facilities 

list defined by a Regional Entity. We want to emphasize that this determination will 

likely have narrow applicability, but where it applies it will be critical to the reliability of 

the bulk electric system. A sub-100 kV facility will only be subject to PRC-023-1 if it 

both meets the NERC general test for critical assets, and is therefore already registered, 

and is identified as operationally critical in the test directed to be created by Order No. 

733. Because the application was narrowly tailored to demonstrably critical assets, the 

Commission justified the applicability of the Reliability Standard to sub-100 kV facilities 

by stating that “[r]elay settings on such facilities should be subject to PRC-023-1 because 

their loss can also affect the reliability of the Bulk-Power System.”107 

87. The Trade Associations argue that the Commission should have directed no more 

than that NERC study the appropriateness of extending the Standard to sub-100 kV 

facilities and that, in making the directive that it did, the Commission denied NERC the 

106 Glossary of Terms Used in Reliability Standards (Feb. 2008), available at

http://www.nerc.com/files/Glossary_12Feb08.pdf. 

107 Order No. 733, 130 FERC ¶ 61,221 at P 67. 
Docket No. RM08-13-001 - 60 - 

ability to conclude such application of PRC-023-1 is not necessary or appropriate to 

achieve reliability. As we stated above, when the Commission identifies a specific matter 

to be addressed, and gives guidance explaining its concern, it is acting within its statutory 

authority. The Commission’s obligation to give “due weight” to the technical expertise 

of the ERO does not conflict with this authority. As section 215(d)(2) of the FPA makes 

clear, the obligation to give “due weight” arises in the context of a “proposed reliability 

standard or modification to a standard,” in other words, when the Commission reviews 

an ERO proposal. The Commission can give “due weight” to the technical expertise of 

the ERO when reviewing a Standard and nonetheless identify a specific matter to be 

addressed without contradiction. 

88. The Commission directed the ERO to develop a modification that would make 

PRC-023-1 applicable to only those sub-100 kV facilities that are operationally critical. 

While the Commission attempted to tailor the modification so that only critical sub-100 

kV facilities are subject to the Reliability Standard, the ERO is free to comply by 

developing an equally effective and efficient response that addresses the concern or goal 

underlying the directive, namely the detriment to reliability inherent in a failure to apply 

Reliability Standard PRC-023-1 to relay protection systems associated with facilities 

critical to the operation and reliability of the Bulk-Power System. In developing such a 

modification, the ERO Reliability Standards development process allows for such study 

and field tests as are necessary to develop the modification. If the Trade Associations’ 

position is that, in studying this matter, NERC may determine that no operationally 
Docket No. RM08-13-001 - 61 - 

critical sub-100 kV facilities currently exist, NERC is to develop a modification that will 

capture such facilities should they occur in the future, but NERC must be able to show its 

response is no less effective and efficient than the test we proposed in Order No. 733. 

Generator Step-Up Transformer Relays as Back-Up Protection

 Order No. 733

89. In Order No. 733, the Commission distinguished between two roles for protection 

relays physically located at the generator terminal on the low-voltage side of a generator 

step-up transformer. Such relays can provide backup protection for a Bulk-Power 

System element such as a transmission line outside of the generator zone of protection, or 

might provide backup protection for the generator and step-up transformer. In Order No. 

733, the Commission found that the requirements of PRC-023-1 apply to all protection 

systems as described in Attachment A that are intended to provide protection to the 

facilities defined in section 4.1.1 through 4.1.4 of the Reliability Standard, regardless of 

whether the protection systems provide primary or backup protection and regardless of 

their physical location. The Commission stated that those relays that are applied to 

provide backup protection to Bulk-Power System elements sense increased current flow 

due to a fault and, therefore, are subject to Reliability Standard PRC-023-1. 

 Rehearing Request

90. Petitioners disagree with the distinction in purpose and seek rehearing or 

clarification that generator step-up transformer relay loadability shall be addressed in a 

Reliability Standard development process that is separate from PRC-023-1. NERC and 
Docket No. RM08-13-001 - 62 - 

EEI argue that whether a relay is subject to PRC-023-1 or a new Reliability Standard 

should be determined by its location, not its purpose or functionality, because a low-side 

relay will always sense a fault on the transmission side. In addition, the Trade 

Associations note that fault conditions are not the purpose of PRC-023-1, so the 

Commission’s concern with fault conditions is misplaced. The Trade Associations 

further assert the Reliability Standard was designed to prevent over-tripping of parallel 

paths, and because of their radial nature, overloading from parallel flows is not an issue 

with regard to generator equipment. Moreover, generators and their transformers need to 

be able to assist in transient stability and voltage stability events. 

91. Though the Commission stated that the Reliability Standard would apply only to 

those relays providing backup protection to Bulk-Power System elements, NERC and 

EEI state the purpose of backup distance protection relays applied at a generator’s 

terminals is to provide thermal protection for the generator and backup protection for the 

generator step-up transformer, not for the transmission lines. NERC asserts that PRC023-1 settings are inadequate for thermal protection of the generator and raises technical 

arguments that distinguish generator loadability relay challenges from those challenges 

addressed by PRC-023-1. 

92. EEI asserts the Final Rule is confusing in that in one place the Commission allows 

NERC to address generator step-up and auxiliary transformer loadability in a different 

Reliability Standard, but then clarifies later that PRC-023-1 does apply to relays on the 

low-side of a generator step-up transformer that are applied to provide backup protection 
Docket No. RM08-13-001 - 63 - 

to Bulk-Power System elements.108 NERC and the Trade Associations raise the issue of 

whether the Commission gave appropriate weight to NERC’s work on this matter. 

 Commission Determination

93. We deny rehearing and clarify that the Commission does not intend the Reliability 

Standard to apply to back-up protective relays connected to current transformers at the 

neutral end of the generator, as illustrated in Appendix 1. We disagree with NERC and 

the Trade Associations that the location of the relay should govern whether or not PRC023-1 applies to a particular relay. There is nothing in the current Standard to support 

that interpretation. In its Applicability section, PRC-023-1 states that it applies to, among 

others, generation owners with load-responsive phase protection systems described in the 

Standard’s Attachment A and applied to certain facilities.109 Attachment A specifically 

excludes certain protection systems from the requirements of the Standard. One of these 

exclusions is for “[g]enerator protection relays that are susceptible to load.” Attachment 

A does not exclude any other type of relay physically located at the generator terminal on 

the low-voltage side of a generator step-up transformer. Thus, by the Standard’s terms it 

 108 EEI at 5 (citing Order No. 733, 130 FERC ¶ 61,221 at P 104, 113). 

109 These facilities are: (1) Transmission lines operated at 200 kV or above 

(2) transmission lines operated at 200 kV or above as designated by the Planning 

Coordinator as critical to the reliability of the Bulk Electric System, (3) Transformers 

with low voltage terminals connected at 200 kV and above, or (4) Transformers with low 

voltage terminals connected at 100 kV to 200 kV as designated by the Planning 

Coordinator as critical to the reliability of the Bulk Electric System. 
Docket No. RM08-13-001 - 64 - 

 

must apply to generator protection backup relays located at the generator step-up 

transformer. 

94. Petitioners disagree with the Commission’s position described in Order No. 733 

that backup relays located at the generator can be used to protect transmission 

elements.110 They argue that the primary function of all backup distance protection 

applied at the terminals of a generator is to provide thermal protection for the generator 

and backup protection for the generator step-up transformer, and not the connected 

transmission line. As discussed in Order No. 733, however, as drafted, PRC-023-1 

applies to the relays intended to provide either primary or backup protection to 

transmission elements.111 The relays that the Commission described as being subject to 

Reliability Standard PRC-023-1, while they may be connected to current transformers 

located at the generator terminal or on the low-voltage side of the generator step-up 

transformer, are set to provide backup protection for Bulk-Power System elements.112 In 

such instances, the sensing of the relay will be solely in the direction of the Bulk-Power 

System, and such relays should be set in accordance with PRC-023-1. Backup 

110 Order No. 733, 130 FERC ¶ 61,221 at P 113. 

111 For example, the relays can be connected in two ways: (1) connected to 

current transformers at the neutral end of the generator or (2) connected to current 

transformers at the generator terminal or on the low-voltage side of the generator step-up 

transformer. We agree that commenters’ arguments may be appropriate for the former 

connection. 

112 Donald Reimert, Protective Relaying for Power Generation Systems 77 (2005). 
Docket No. RM08-13-001 - 65 - 

 

protection, however, can also be connected to current transformers located at the neutral 

end of the generator, and such relays will sense in the direction of the generator and the 

Bulk-Power System.113 Relays in this second location may operate for faults on the 

generator or the Bulk-Power System, and Order No. 733 does not purport to make such 

protection relays subject to PRC-023-1. With this clarification, the Commission believes 

that it resolves the apparent conflict in Order No. 733 identified by EEI. 

95. The Commission agrees with the Trade Associations that backup relays set 

according to PRC-023-1 should be coordinated with other protection systems to ensure 

that systems protecting the generator and generator step-up transformer operate before 

protection systems that provide backup protection for the Bulk–Power System. We do 

not, however, agree with their assertion that this means that the current PRC-023-1 

should be read not to apply to the loadability of generator step-up transformers because of 

such coordination. As discussed in Order No. 733, the Commission expects that the ERO 

will develop the Reliability Standard addressing generator loadability as a new Reliability 

Standard with its own individual timeline, and not as a revision to an existing 

Standard.114 

96. The Commission does not accept the Trade Associations’ assertion that the 

Reliability Standard was designed to prevent over-tripping of parallel paths and therefore

113 Id.

114 Order No. 733, 130 FERC ¶ 61,221 at P 106. 
Docket No. RM08-13-001 - 66 - 

ue that 

lity and 

n order 

C-001-1 and requires coordination of generation 

ments 

nal 

has no applicability to generator equipment and auxiliaries. While we do not arg

our directive was intended to address anything beyond relays providing backup 

protection for elements of the Bulk-Power System, nothing in PRC-023-1 limits 

applicability to parallel paths or thermal cascading outages. The Standard is general and 

covers all possible topologies for Reliable Operations in real time. 

97. We do agree that generators and their transformers assist in transient stabi

voltage stability events. In the context of Reliability Standard PRC-023-1, loadresponsive phase relays must not trip due to transient stability and voltage events i

to allow operators to take remedial action. Moreover, the assistance provided by 

generators and their transformers, until addressed in other standard development 

activities, is presently addressed by PR

and transmission protection systems. 

98. We agree with NERC that a generator’s higher loading angle and dynamic 

response to local disturbances are not addressed by PRC-023-1 and that the require

of PRC-023-1 are insufficient to provide for secure operation of generator backup 

protection. We also agree with NERC that load-responsive relays applied at the termi

of a generator will respond to a maximum load and the resultant apparent impedance

independent of whether it is set with a shorter reach to protect the generator and the 

generator step-up transformer or with a longer reach to additionally provide backup 

protection from transmission system faults. Our decision in the Final Rule is consistent 

with each of NERC’s assertions. As we discussed previously, the relays at issue, while 
Docket No. RM08-13-001 - 67 - 

e 

nd 

will 

Bulk-Power System, then those 

 

they may be connected to current transformers located at the generator terminal or on th

low-side of the generator step-up transformer, are set to provide backup protection for 

Bulk-Power System elements; not backup protection for the generator. For this reason, 

while the assertions NERC makes are appropriate, they are relevant to considerations a

relays that do not fall within the scope of PREC-023-1. In addition, NERC makes the

case that relays governed by PRC-023-1 on most generators or on transmission lines 

supplied totally or partially from generators will not be able to coordinate since they 

not operate appropriately. Such observations underscore the need for generator and 

transmission protective systems to be coordinated as recommended in the Blackout 

Report.115 In sum, entities must first pick a relay that coordinates with their system. 

Having selected their protection relays, if load-responsive phase protection relays are 

used to provide backup protection to elements of the 

relays should be set in accordance with PRC-023-1. 

99. We know from event analysis that entities use load-responsive phase protection 

relays at the low-side of generator step-up transformers to provide backup protection to 

Bulk-Power System elements one or more buses away from the generator and that such 

relays have misoperated. It is not our intention to mandate a specific protection system,

115 See Blackout Report at 73, “[T]he evidence collected indicates that the relay 

protection settings for the transmission lines, generators and under-frequency loadshedding in the northeast may not be coordinated and integrated...;” and at 159, 

Recommendation No. 21 “establish an integrated approach to relay protection for 

generation and transmission lines....” 
Docket No. RM08-13-001 - 68 - 

ill 

mission’s underlying goal as efficiently and effectively 

as the roposal. 

but we have determined that where an entity selects a phase protection relay to provide 

backup support to Bulk-Power System elements, such relay should be set in accordance 

with PRC-023-1. To do otherwise creates a gap in ensuring the reliability PRC-023-1 is 

intended to establish. If the ERO wishes to address such a gap by another means, we w

accept an alternative method, provided that the ERO demonstrates that the alternative 

will adequately address the Com

Commission’s p

Power Swings

 Order No. 733

100. During the August 2003 Blackout, certain relays were unable to distinguish 

between an actual fault and a dynamic, but stable power swing. In keeping with their 

settings and specifications, the relays operated in response to non-fault power swings and

thereby accelerated the cascade. Reliability Standard PRC-023-1 applies to steady state

relay loadability without regard to dynamic conditions or stable power swings. Rather 

than order the ERO to modify PRC-023-1 to address stable power swings, in Order

733, the Commission directed the ERO to develop a new Reliability Standard that 

requires the use of protective relay systems that can differentiate between faults a

stable power s

 No. 

nd 

wings and, when necessary, phase-out relays that cannot meet this 

requirement. 

 Rehearing Request
Docket No. RM08-13-001 - 69 - 

tion 

se of 

ments that there is no record in the docket nor in the 

systems 

 result 

C seeks 

 

101. EEI states that the directive to develop a Reliability Standard to prevent protec

relays from operating unnecessarily due to stable power swings is inconsistent and 

ambiguous because relays cannot distinguish between actual faults and stable power 

swings. At best, some relays are less susceptible to dynamic power swings, so such a 

standard cannot be developed at this time. NERC asks for clarification between the 

unambiguous mandate in Order No. 733 that the new standard is to require the u

protective relays that can differentiate between faults and stable power swings116 and the 

statement that the Commission recognizes that because of the characteristics of 

impedance relays, the relay may potentially operate regardless of whether a power swing 

is stable or unstable.117 EEI also com

Blackout Report to support the need for such a Reliability Standard and, accordingly, the 

directive is arbitrary and capricious. 

102. Both the Trade Associations and NERC caution that the use of protection 

that differentiate between faults and stable swings may result in less stability as a

of a decreased ability to identify unstable swings. The Trade Associations seek 

clarification that the Commission is not directing the phase-out of all protection 

equipment that cannot differentiate between faults and stable power swings. NER

clarification that it can use its industry technical experts to address the issue appropriately 

116 NERC at 10 (citing Order No. 733, 130 FERC ¶ 61,221 at P 150, 173). 

117 Id. at 11 (citing Order No. 733, 130 FERC ¶ 61,221 at P 168). 
Docket No. RM08-13-001 - 70 - 

s might satisfy. Together NERC, 

ine 

8

 It asserts 

r the complexity of the replacement process 

-out. 

and asks for clarity as to whether the directive was intended to create an absolute 

requirement to highlight a concern that other approache

EEI, and the Trade Associations assert more deference was due to NERC to determ

the nature of the problem and the appropriate solution. 

103. Dominion comments that the Commission did not give the ERO sufficient 

guidance concerning the timing of any phase-out of protection relay systems.11

that the Commission considered only the cost of replacing such relay elements in 

rejecting the arguments that they not be replaced. Dominion believes that the 

Commission and the ERO must also conside

and the potential impact on system reliability in establishing a timetable for a phase

 Commission Determination

104. We deny rehearing and provide the following clarification. We continue to 

believe that not addressing stable power swings constitutes a gap in the current 

Reliability Standards and must be addressed. Therefore, we retain the directive, pursuant 

e 

r 

lan 

 

to section 215(d)(5) to direct the ERO to develop a Reliability Standard addressing stabl

power swings. 

105. The Commission, agreeing with commenters on the NOPR, recognized in Orde

No. 733 that addressing stable power swings is a complex issue.119 But entities must p

118 Dominion at 4. 

119 Order No. 733, 130 FERC ¶ 61,221 at P 153. 
Docket No. RM08-13-001 - 71 - 

ncern 

eptible 

requires the use 

gs 

 or 

and 

operated during the August 2003 Blackout according to their settings, but it was the 

 

and operate their systems taking into account real time operating conditions. If their

portion of the power system, with the existing protection systems, cannot achieve the 

performance identified in various Reliability Standards, such as the TPL Reliability 

Standards, a corrective action plan is required. Because PRC-023-1 is silent with respect

to relays operating unnecessarily because of stable power swings, we expressed co

in the Final Rule that relays set according to the Reliability Standard remain susc

to tripping unnecessarily for expected non-fault loading conditions like those that 

occurred during the August 2003 Blackout. Without specifying the terms of the 

directive, we directed the ERO to develop a new Reliability Standard that 

of protective relay systems that can differentiate between faults and stable power swin

and, when necessary, phase-out relays that cannot meet this requirement. 

106. A power swing is described as “stable” if after a sudden change in power or a 

disturbance on the electric system, (e.g., a fault or loss of generation or transmission

load, etc.) generators remain in synchronism and the system returns to an acceptable 

stable operating condition. As discussed in Order No. 733, zone 3/zone 2 relays120

120 Multiple impedance relays are installed at each end of a transmission line, with 

each used to protect a certain percentage, or zone, of the local line and remote lines. 

Zone 3 relays and zone 2 relays set to operate like zone 3 relays (zone 3/zone 2 relays) 

are relays typically set to reach 100 percent of the protected transmission line and more 

than 100 percent of the longest line (including any series elements such as transformers) 

that emanates from the remote buses. 
Docket No. RM08-13-001 - 72 - 

n 

ting the electric system from returning 

ing 

and 

er swings 

 B and Category C contingencies) that will result in 

ts 

 

inability of these relays to distinguish between a dynamic, but stable, power swing and a

actual fault that contributed to the cascade.121 Unlike a stable power swing, an unstable 

power swing indicates a sudden change in power on the electric system to such a degree 

that generators may go out of synchronism, preven

to an acceptable and stable operating condition. 

107. To be clear, we do not direct the development of a Reliability Standard containing

an absolute obligation to prevent protection relays from operating unnecessarily dur

stable power swings. Many, but not all, zone 3 or zone 2 relays with inappropriate 

settings did operate unnecessarily during the stable power swings portion of the August 

2003 Blackout, which led to propagating the geographic spread of the cascade. We note

that the Blackout Report highlighted the adverse reliability impact of zone 3 relays 

explained why application of zone 3 relays on 230 kV and greater lines have been 

proactively eliminated in many regions to avoid such relay misoperation. We are not 

requiring such across-the-board elimination of all zone 3 relays but only the creation of a 

Reliability Standard that addresses protection systems vulnerable to stable pow

(resulting from Category

inappropriate tripping. 

108. NERC seeks assurance that it can use its industry technical experts and apply i

judgment to address this matter appropriately for the various circumstances existing 

121 Order No. 733, 130 FERC ¶ 61,221 at P 152. 
Docket No. RM08-13-001 - 73 - 

ility 

that the 

h 

s 

 

across the Bulk-Power System and, with the Trade Associations, expresses concern that

the Commission’s directive will reduce reliability. In Order No. 693, the Commission 

stated that “Commission directives are not intended to usurp or supplant the Reliab

Standard development procedure.”122 The ERO’s process allows a full vetting of 

suggestions raised for the first time during the NOPR process and also encourages 

interested entities to participate in developing Reliability Standards and modifications. 

We reaffirm the ERO can use its industry technical experts to address the directive as it 

deems appropriate consistent with its Reliability Standard development process, and we 

will consider properly supported approaches to addressing our directive provided 

ERO demonstrates that the alternative will address the Commission’s concern as 

efficiently and effectively as the Commission’s proposal. Through application of its 

technical expertise, and the balancing of stakeholder interests, the ERO’s Reliability 

Standard development process is the appropriate forum to discover and address any 

unintended consequences arising from the use of protective relay systems. Accordingly, 

we believe a new Reliability Standard can be developed to address stable power swings. 

109. With regard to the Trade Associations’ request for clarification concerning whic

relays the Commission’s directive are to apply to and which non-differentiating relay

must be phased out, we leave this to the discretion of the ERO and will evaluate the 

Reliability Standard at the time it is filed. As stated in Order No. 733, the ERO has the 

122 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 187. 
Docket No. RM08-13-001 - 74 - 

s, 

 it to the 

ur view that 

oss of 

de, 

their 

protective zone even though there was no fault. These relays were not able to 

 

flexibility to propose an alternative solution. Specifically, we stated that “while we direct

the ERO to develop a Reliability Standard that phases out such relays where necessary if 

they do not meet the reliability goal, the ERO is free to develop an alternative solution to 

our reliability concerns regarding undesirable relay operation due to stable power swing

provided that it is an equally effective and efficient approach.”123 Such flexibility also 

applies to the class of protection systems subject to the new standard: “We leave

ERO to determine the appropriate protection systems to be discussed in the new 

Reliability Standard through application of its technical expertise.”124 It is o

these statements provide the clarification that Trade Associations requests. 

110. As reported in the Blackout Report and discussed in the NOPR, despite the l

fourteen key transmission lines, the Task Force found that during the August 2003 

Blackout, the system did not become dynamically unstable until at least the Thetford

Jewell 345 kV line tripped at 16:10:38 EDT.125 Up until this point during the 2003 

blackout, with each dynamic, but stable, power swing, the transmission system recovered

and appeared to stabilize. As the power swings and oscillations increased in magnitu

however, zone 3/zone 2 and other relays reacted as though there was a fault in 

123 Order No. 733, 130 FERC ¶ 61,221 at P 169. 

124 Id. P 167. 

125 Blackout Report at 82-83. 
Docket No. RM08-13-001 - 75 - 

 

differentiate the levels of currents and voltages that the relays measured, because of their 

settings, and consequently operated unnecessarily. 

111. The Commission’s directive pertains to conditions in which relays misoperate due 

to stable power swings that were identified as propagating the cascade during the August 

2003 Blackout. In light of this, we do not agree with EEI’s assertion that the 

Commission’s position to address stable power swings is not supported by findings from 

the Blackout Report. 

112. We also believe that EEI’s claim that relays cannot distinguish between actual 

faults and stable power swings appears to ignore the fact that there are protection system 

applications currently in use for such purposes, i.e., “power swing block” applications 

that are applied to block tripping of distance relay elements during stable power 

swings.126 Therefore, with existing technologies and appropriate applications of 

protective systems, relays can be set to avoid tripping during the predictable, stable 

power swings such as can occur as a result of Category B and Category C events.127 

113. Dominion raises a technical and implementation concern regarding a standard that 

is not yet developed. In the Final Rule, the Commission directed NERC, Dominion, and 

126 Report to the Power System Relaying Committee of the IEEE Power 

Engineering Society, IEEE PSRC WG D6, Power Swing and Out-of-Step Considerations 

on Transmission Lines (2005), available at http://www.pes-psrc.org/Reports/Power 

%20Swing%20and%20OOS%20Considerations%20on%20Transmission%20Lines%20F

..pdf.

127 Id.
Docket No. RM08-13-001 - 76 - 

other affected stakeholders to work together towards a solution to this issue and submit it 

for review by the Commission,128 and we will review the matter at that time. 

Requirement R1.10

 Order No. 733

114. Sub-requirement R1.10 of PRC-023-1, as approved by the Commission, addresses 

transformer fault protection relays and transmission line relays on transmission lines that 

terminate in a transformer. It requires that the transformer fault protection relays and 

transmission line relays do not operate at or below the greater of 150 percent of the 

applicable maximum transformer name-plate rating, including the forced cooled ratings 

corresponding to all installed supplemental cooling equipment, or 115 percent of the 

highest owner-established emergency transformer rating. Such protection relay settings 

would allow the transformer to be subjected to overloads higher than its established 

ratings for unspecified periods. For this reason, the Commission directed the ERO to 

modify sub-Requirement R1.10 so that it requires entities to verify that the limiting piece 

of equipment is capable of sustaining the anticipated overload for the longest clearing 

time associated with the fault. 

 Rehearing Request

115. EEI argues that requiring companies to verify that equipment is capable of 

withstanding an anticipated overload for the longest clearing time associated with that 

 128 Id. P 150. 
Docket No. RM08-13-001 - 77 - 

 

overload suggests both safety and liability issues rather than a reliability issue, and as 

such, is beyond the Commission’s authority.129 It also notes that the Commission offers 

no technical analysis or evidence to support its statement that failure to apply the system 

protections it proposes will result in a degradation of reliability.130 EEI finds the terms of 

the directive to be susceptible to various understandings and hence ambiguous. It 

requests clarification that mitigation of thermal overload is beyond the scope of PRC023-1. 

116. The Trade Associations comment that it is in the TPL Reliability Standards where 

comparisons of facility ratings to reasonable worst case system conditions are made.131 

For this reason, they request that the Commission withdraw its directive, or at least relax 

it so that it can be satisfied through the TPL Reliability Standards, not PRC-023-1. The 

Trade Associations also assert that, instead of deferring to the ERO’s technical expertise, 

the Commission substituted is own judgment and in so doing, reveals flawed analysis. 

For instance, in denying the adequacy of IEEE standards, the Commission offers the 

example of faults on the low side of a transformer in instances where there is no breaker 

on the high side of the transformer. The Trade Associations assert that such a relay, in 

most cases, will be protecting the distribution system, not the Bulk-Power System. In the 

129 EEI at 19. 

130 Id. at 20. 

131 Trade Associations at 25. 
Docket No. RM08-13-001 - 78 - 

few instances where the relay is not protecting the distribution system, there will be a 

transfer trip scheme in place obviating the need for a modification required by Order No. 

733.132 Lastly, the Trade Associations assert that “the longest clearing time associated 

with the fault” may not be the worst case. The worst case is usually the highest fault 

current which has the fastest clearing time.133

 Commission Determination

117. We deny rehearing and provide the following clarification. Sub-requirement 

R1.10 applies to the topology where there is no breaker installed on the high-voltage side 

of the transformer. Because of this configuration, faults within the transformer or at the 

low-voltage side of the transformer are cleared by tripping the remote breaker on the 

transmission line and the transformer low-voltage breaker. Faults on the low-voltage side 

of the transformer will generally be lower in magnitude as measured at the remote 

breaker due to the large impedance of the transformer. Fault protection relays set at 150 

percent of the transformer nameplate rating or 115 percent of the highest operator 

established emergency transformer rating may be set too high to operate for faults on the 

low-voltage side of the transformer. Consequently, delayed clearing of faults (i.e., the 

longest clearing time associated with the faults) from the high-voltage side of the 

transformer may occur and subject the transformer to through-currents higher than the 

 132 Id. at 24. 

133 Id. at 25. 
Docket No. RM08-13-001 - 79 - 

 

transformer’s rating. Overcurrent relays used for transformer protection have a limited 

ability to detect these types of faults because they are set above the maximum load 

current for entities that set these relays following the IEEE Standards.134 

118. EEI’s assertion that the Commission’s directive was motivated by safety and 

liability concerns rather than by reliability issues was explicitly rejected in Order No. 

733.135 The Commission’s concern was not to guard against the thermal overload of 

transmission facilities. Rather, the reliability concern is ensuring that the longest clearing 

time associated with the protection systems respects the facility’s operating limits in 

order to assure that a contingency could not result in additional facilities failing. As 

discussed in the Final Rule, protection systems that do not respect the actual or verified 

capability of the limiting facility will result in a degradation of system reliability. In this 

instance, applying sub-Requirement R1.10 without regard to the topology and capability 

of each transformer could cause the transformer to fail. Failure of the transformer may 

not be limited to only the affected transformer, but may also affect other Bulk-Power 

Systems elements in its vicinity, further degrading the reliability of the Bulk-Power 

System.136 The Commission’s directive seeks to efficiently ensure that elements of the 

Bulk-Power System are operated within their appropriate capabilities. 

134 Order No. 733, 130 FERC ¶ 61,221 at P 206. 

135 Id. P 204. 

136 Id. P 210. 
Docket No. RM08-13-001 - 80 - 

 

119. The Commission also rejects EEI’s assertion that the Final Rule provides no 

support for its statement that failure to follow the Commission’s directive will result in 

the degradation of reliability. As discussed in the Final Rule, Requirement R1.10 is 

applicable to a system configuration with no breaker installed on the high-voltage side of 

the transformer.137 Transformers subject to PRC-023-1 in this configuration would not 

typically include a step-down transformer since the majority of distribution systems are 

not in excess of 100 kV, and the Standard is applicable to transformers with low voltage 

terminals connected at 100 kV to 200 kV if designated by the planning coordinator. With 

the exception of local distribution systems in excess of 100 kV, the applicable 

transformers are autotransformers between different Bulk-Power System voltages, with 

many being rated at 300 MVA or larger. Faults within the autotransformer, or at the lowvoltage side of the autotransformer, are cleared by tripping the remote breaker on the 

transmission line and the transformer lower-voltage breaker.138 Order No. 733 also 

explained that because faults on the lower-voltage side of the transformer will generally 

be lower in magnitude as measured at the remote breaker due to the large impedance of 

the transformer, fault protection relays set applying Requirement R1.10 may be set too 

low to operate for faults on the low-voltage side of the transformer. Consequently, 

137 Id. P 206. 

138 Id.
Docket No. RM08-13-001 - 81 - 

 

delayed clearing of faults from the high-voltage side of the transformer may occur and 

subject the transformer to overloads higher than the transformer’s rating. 

120. In Order No. 733, the Commission stated that “[f]ailure of the transformer may not 

be limited to only the affected transformer, but may also affect other Bulk-Power System 

elements in its vicinity, further degrading the reliability of the Bulk-Power System” as 

would be expected with a failure of a large autotransformer between different BulkPower System voltages.139 In addition, the replacement due to a failure of such a 

transformer could require a long lead-time, prolonging the Bulk-Power System’s return to 

the level of reliability that preceded the failure. 

121. With regard to EEI’s claim that the terms “verify” and “longest clearing time 

associated with a fault” are ambiguous, we understand that protection systems are 

designed to remove faults quickly. However, the Commission’s use of the phrase 

“longest clearing time” is in the context of the design and coordination of protection 

systems, where the “longest clearing time” refers to the longest time that a fault could 

remain on the Bulk-Power System before it is cleared by a protection system. This 

context is not the same as that of a “worst case” that the Trade Associations discuss in 

their argument. Because the directive is in the context of coordination of protection 

systems, the Commission expects the verification to be undertaken in the same context. 

That is to say, the verification that the longest clearing time associated with the protection 

139 Id. P 210. 
Docket No. RM08-13-001 - 82 - 

 

system respects the facility’s operating limits must be done in the context of the design 

and coordination of protection systems. 

122. The Commission addressed its concerns regarding the gaps in reliability created 

by over-reliance on the IEEE Standard C37.91-2008, IEEE Guide for Protecting Power 

Transformers, in the Final Rule.140 The Trade Associations challenge one of the 

Commission’s reservations regarding those standards by asserting that in the very few 

cases where such relays are not protecting the distribution system, there will be a transfer 

trip scheme in place to address the Commission’s concern. We are not persuaded. There 

are no specific requirements for a transfer trip scheme in this or other Reliability 

Standards. The Trade Associations’ assertion also assumes that all entities have 

communications systems installed and are using them for this protection scheme, which 

may not be the case, nor is it a specific requirement of the Reliability Standards.

123. Order No. 733 does not, as the Trade Associations argue, require the development 

of facility ratings; facility ratings are established in the Facilities Design, Connections, 

140 Id. P 206, 208-209. For example, (1) delayed clearing of faults (i.e., the 

longest clearing time associated with the faults) from the high-voltage side of the 

transformer may occur and subject the transformer to overloads, (2) an entity could 

provide a facility rating that was just within the voluntary requirements in the IEEE 

standards, however, when setting protection relays according to sub-Requirement R1.1, 

the transformer could be subject to currents above its capability as previously described, 

(3) the IEEE Standards may not apply to transformers manufactured before 1993 because 

the guidelines established in C57.109-1993 do not apply to transformers manufactured 

before 1993, and (4) a setting of 150 percent of the transformer nameplate rating or 115 

percent of the highest operator established emergency rating may not always be less than 

200 percent of the transformer forced-cooled nameplate rating. 
Docket No. RM08-13-001 - 83 - 

 

and Maintenance (FAC) Reliability Standards. Order No. 733 also does not require the 

comparison of facility ratings that the Trade Associations also claim is covered by the 

TPL Reliability Standards. Order No. 733 requires that the longest clearing time 

associated with the protection systems applied to protect the transmission facility respects 

that facility’s operating limits.141 For example, if the facility has an appropriate duration 

short time rating, that rating could provide the operating limit. 

124. In our review of Reliability Standard PRC-023-1, we identified that subRequirement R1.10 raised the concern that overloading facilities at any time, but 

especially during system faults, could lower reliability.142 To address that gap in the 

standard, the Commission directed the ERO to modify the sub-requirement so that it 

requires entities to verify that the limiting piece of equipment is capable of sustaining the 

anticipated overload for the longest clearing time associated with the fault. We believe 

this to be a reasonable way to address the perceived gap in the Reliability Standard’s goal 

of enhancing reliability. But, as it did here, whenever the Commission directs the ERO to 

modify PRC-023-1 in a specific manner, we will accept an alternative method that 

addresses the concern identified by the Commission provided that the ERO demonstrates 

that the alternative will adequately address the Commission’s underlying concern or goal 

as efficiently and effectively as our own proposal.

141 Id. P 203. 

142 Id. P 191. 
Docket No. RM08-13-001 - 84 - 

Attachment A Section 3.1

 Order No. 733

125. Attachment A of PRC-023-1 specifies which protection systems are subject to, and 

which are excluded from, the Standard’s Requirements. Section 3 of the Attachment 

expressly excludes systems specified in sections 3.1 through 3.9, and specifically 

excludes relay elements that are only enabled when other relays or associated systems 

fail. In Order No. 733, the Commission directed the ERO to remove the exclusion of 

these supervisory relays from section 3 and to revise section 1 of Attachment A to 

include supervisory relay elements on the list of relays and protection systems that are 

specifically subject to PRC-023-1. A supervisory relay acts as a check on the supervised 

protection system because both must operate to trip a facility. The Commission is 

concerned that if supervisory relays are not subject to the Reliability Standard, then they 

may be set below the rating of the protected element. If that were to happen, high 

loading conditions can cause such relays to be continuously energized and ready to 

operate, and the supervisory relays will no longer act as a check on the protections 

systems they are supervising. This threat to reliability underlies our directive on this 

matter. 

 Rehearing Request

126. Petitioners argue that the Commission’s directive to subject all supervisory relays 

to PRC-023-1 is overly broad. The Trade Associations comment that no purpose is 

served by including supervisory relays if the supervised protection system already meets 
Docket No. RM08-13-001 - 85 - 

 

PRC-023-1 loadability requirements.143 They assert the example given by the 

Commission is inappropriate and explain that as long as either the tripping relay or the 

supervisory relay meets PRC-023-1, then the protection system as a whole will meet the 

Standard. The Trade Associations request clarification to allow NERC to add 

supervisory relay elements to section 1 with a caveat that supervisory relay elements only 

need to meet the loadability requirements if the protection system they are supervising is 

responsive to load and does not meet the loadability requirement. 

127. EEI argues that the Commission’s directive would be detrimental to reliability 

because increases to dependability take place largely at the expense of security since 

relays will trip more often.144 As an example, EEI poses the need for an operational 

decision to open breakers for loss of potential, as opposed to the operator likely leaving 

the element in service with fast tripping enabled for a fault as could be the case if section 

3.1 of Attachment A continues to be exempted from Reliability Standard PRC-023-1. In 

complex protective schemes dependability and security tend to be mutually exclusive, so 

EEI requests clarification of the Commission’s statement in Order No. 733 that protective 

relays must be dependable and secure.145 It points out that engineers have been biased 

143 Trade Associations at 26. 

144 EEI at 21. 

145 Id. (citing Order No. 733, 130 FERC ¶ 61,221 at P 269). 
Docket No. RM08-13-001 - 86 - 

toward dependability to ensure the safety of people and equipment and that the 

exclusions in section 3.1 of Attachment A appropriately reflect that bias. 

128. Dominion comments that the Commission’s requirement would include some 

supervisory relay functions for which allowance of the full emergency line loading limit 

is not practical or, in many cases, even attainable.146 It further asserts the application of 

the Reliability Standard to supervisory relays is too complex for a rulemaking proceeding 

by the Commission, and instead the ERO should be directed to consider which 

supervisory relays should be covered by the Standard and to explain the basis for 

excluding any relays from that coverage. 

 Commission Determination

129. We deny the Trade Associations’ request for clarification and disagree with their 

statement that no purpose is served by including supervisory relays if the supervised 

protection system already meets PRC-023-1 loadability requirements. The Commission 

is concerned that reliability is compromised by excluding supervisory relays from the 

requirements of PRC-023-1 as the exclusion can result in supervisory relays set below the 

rating of the protected element. This can result in a relay being energized and ready to 

operate upon high loading conditions and thus no longer serving as a check on the other 

protection system.147 The failure of a communication element during a period of high 

 146 Dominion at 5. 

147 Order No. 733, 130 FERC ¶ 61,221 at P 150. 
Docket No. RM08-13-001 - 87 - 

loadability can result in the protected facility tripping, even when the line continues to 

carry its normal load current. For example, a pilot wire current differential scheme that 

measures the difference of the current entering and exiting a line would not be subject to 

the loadability issues addressed by PRC-023-1 as long as the communications facilities 

are available and operate as designed. However, if the communications facilities fail to 

operate, normal load current would result in the tripping of the current differential 

scheme if the supervisory relays are not set to consider loadability, contrary to the Trade 

Associations’ assertion that, as long as either the tripping relay or the supervisory relay 

meets PRC-023-1, the protection system as a whole will meet the Standard. 

130. We also disagree with EEI that the Commission’s directive would be detrimental 

to reliability. We understand that “dependability” and “security” are not additive features 

of protection relaying, and due considerations are given to both aspects by protection 

engineers in coming up with protection systems without biasing or sacrificing one aspect 

over the other. EEI argues, however, that factors of ensuring the safety of people and 

equipment are biased towards ensuring dependability (i.e., circuits will trip even when no 

fault has occurred) and hence the exclusions in section 3.1 of Attachment A. The 

Commission does not believe there is a need to make a compromise in this instance 

between reliability and the safety of people and equipment. The Commission expects the 

performance of the protection system necessary to achieve Reliable Operation of the 

Bulk-Power System to be accomplished with the operation of the backup protection 

system. Reliable Operation may not be achieved if facilities trip out for a failure of a 
Docket No. RM08-13-001 - 88 - 

 

communication channel or switching or potential sources supplying protection systems. 

When the Commission used the terms “dependable” and “secure” in the Final Rule, we 

used them in the same context as those terms are used in the industry;148 not as absolutes. 

Rather than a protection system that is 100 percent secure and 100 percent dependable, 

the Commission intended to convey a protection system that has a measure of 

dependability and security that collectively ensure reliability. 

131. EEI also argues that because the loss of voltage input or a failed communication 

channel is rare, it would be better to trip for these non-fault conditions rather than risk not 

tripping for another condition because certain elements of the protection system are set 

according to the requirements of PRC-023-1. We disagree. Communication channel 

interruptions can be expected, and such an interruption in communications has resulted in 

multiple outages due to supervisory relays set too low, i.e., not set to consider 

transmission loadability.149 As discussed in Order No. 733, a protection relay, as an 

integral part of the Bulk-Power System, must not operate during non-fault conditions, 

regardless of how few times the relay may actually operate.150 

132. Dominion’s concern with load-responsive phase protective and supervisory relays 

is specific to one of the thirteen criteria established under Requirement R1, specifically 

148 Id. P 269 n.186. 

149 Id. P 268. 

150 Id. P 269. 
Docket No. RM08-13-001 - 89 - 

 

Requirement R1.5. This Requirement establishes relay setting requirements for the 

system configuration for “relays applied on weak source systems so they do not operate 

at or below 170 percent of the maximum end-of-line three phase fault magnitude 

(expressed in amperes).” Dominion identifies, in some parts of its system, the system 

configuration described by Requirement R1.5, i.e., where Dominion has weak sources 

where the range of possible fault currents is close to or below the emergency line loading 

value. While, in general, the Commission’s discussion in the Final Rule referred to relay 

setting criteria as described in Requirement R1.1 (highest seasonal Facility Ratings) and 

Requirement R1.2 (15-minute Facility Rating) the Commission’s use of the phrase 

“rating of the line” is in the context of the specific criteria established in each of the 

requirements and not the “emergency loading limit” of the line as Dominion asserted.151 

As identified by the Commission and stated by Dominion, to achieve Reliable Operation, 

it is essential to have workable settings with both the phase relays and the supervisory 

relays such that they operate as desired, i.e., tripping for faults but not on loadability. 

Therefore, we clarify that the desired performance, as reflected in the setting of the 

supervisory relay, is dependent upon which criteria under Requirement R1 is applicable 

to the specific topology. 

133. Dominion further argues that setting the supervisory overcurrent relay over the 

emergency rating of the line is not necessary because the impedance relay with which it 

151 Dominion, Attachment A, at 3. 
Docket No. RM08-13-001 - 90 - 

works will permit such emergency loading, i.e., not operate and trip the transmission line. 

As discussed in Order No. 733, and previously in this section, the Commission is 

concerned with supervisory relays set below the rating of the line being continuously 

energized and thus no longer able to act as a check on the protection system the relays are 

supervising. The ERO proposed, and the Commission approved, subjecting overcurrent 

relays to the requirements of PRC-023-1. Each of Dominion’s arguments raised here can 

be addressed through the ERO’s Reliability Standards development process. It is our 

expectation that such technical disagreements will either be resolved through that 

process. 

134. The ERO did not provide any technical rationale for excluding any loadresponsive phase protection systems from the requirements of PRC-023-1. Having 

directed the ERO to modify PRC-023-1 in a specific manner, we will accept an 

alternative method that addresses the Commission’s concern provided such alternative is 

demonstrably adequate in addressing the Commission’s underlying concern as efficiently 

and effectively as the Commission’s proposal. 

 
Docket No. RM08-13-001 - 91 - 

Regulatory Flexibility Act of 1980

 Order No. 733

135. The Regulatory Flexibility Act of 1980 (RFA)152 generally requires a description 

and analysis of final rules that will have significant economic impact on a substantial 

number of small entities. The RFA mandates consideration of regulatory alternatives that 

accomplish the stated objectives of a proposed rule and that minimize any significant 

economic impact on a substantial number of small entities. The Small Business 

Administration’s (SBA) Office of Size Standards develops the numerical definition of a 

small business.153 The SBA has established a size standard for electrical utilities, stating 

that a firm is small if, including its affiliates, it is primarily engaged in the transmission, 

generation and/or distribution of electric energy for sale and its total electric output for 

the preceding twelve months did not exceed four million megawatt hours.154 

136. In Order No. 733, the Commission departed from the “rule-out” approach 

proposed in the NOPR to determine the 100 kV to 200 kV facilities that would be subject 

to the Standard in favor of an “add-in” approach.155 To address comments regarding the 

number of small entities affected by PRC-023-1, the Commission stated that, as of the 

 152 5 U.S.C. §§ 601-612 (2006). 

153 13 C.F.R. § 121.101 (2010). 

154 13 C.F.R. § 121.201, Sector 22 Utilities & n.1 (2010). 

155 Order No. 733, 130 FERC ¶ 61,221 at P 340. 
Docket No. RM08-13-001 - 92 - 

November 30, 2009 NERC Compliance Registry, 1,301 registered entities perform 

activities subject to PRC-023-1.156 Of the 1,301 entities, only 80 qualify as “small 

entities.”157 The Commission concluded that the final rule would not have a “significant 

impact on a substantial number of small entities.”158

 Rehearing Requests

137. EEI asserts that the Commission erred in certifying that Order No. 733 will not 

have a significant economic impact on a substantial number of small entities.159 The 

Reliability Standard, EEI argues, will force a substantial number of small entities to 

employ engineers and make capital expenditures, resulting in significant costs to small 

entities. EEI supports its assertion with estimates of the personnel and capital costs that it 

believes will be incurred. It believes that approximately 200 planning and relay 

engineers will be required to perform studies and tests to make determinations regarding 

the applicability of PRC-023-1. It quotes a cost of approximately $33 million for these 

engineering personnel alone, and adds to that another $33 million for expenditures such 

as office space, technical equipment, and supporting personnel. 

 156 Id. P 341. 

157 Id. P 343. 

158 Id. P 344. 

159 EEI at 22. 
Docket No. RM08-13-001 - 93 - 

138. The Trade Associations also take issue with the Commission’s conclusion 

regarding the applicability of the RFA.160 First, the Trade Associations argue that the 

Commission erred in excluding entities that owned only generation facilities from the 

pool of entities that may be subject to PRC-023-1. They argue that the Commission has 

failed to account for its directive to NERC to develop a new loadability standard for 

generator step-up transformers. Second, the Trade Associations assert that approximately 

253 small entities are subject to PRC-023-1, in lieu of the 80 as described in the Final 

Rule. In providing the quantity of 253, they did not name the specific entities included in 

this figure. 

 Commission Determination

139. The Commission rejects the estimates, alleged by EEI, of resources and personnel 

required to comply with PRC-023-1. First, as presented in the Final Rule, only 12 

percent of those entities estimated to be subject to PRC-023-1 are small entities. Second, 

the estimated number of technicians, their salaries, and miscellaneous support costs like 

office space alleged by EEI are, as EEI states, “based upon the collective experience and 

engineering expertise of EEI’s membership,” but EEI fails to provide any specific or 

generally accepted source for this information. Accordingly, EEI has provided no basis 

for us to reconsider our estimates. 

 160 Trade Associations at 28. 
Docket No. RM08-13-001 - 94 - 

 

140. The Commission also rejects the argument made by the Trade Associations that 

the add-in approach will cause a substantial number of small entities to be affected by 

PRC-023-1. The Trade Associations allege that the Commission cannot state that a 

substantial number of small entities will not be affected by PRC-023-1 because “nearly 

all 100+ kV facilities will be deemed operationally significant under appropriate tests.” 

The Trade Associations appear to misunderstand the applicability of the RFA. The RFA 

concerns itself with small entities as that term is defined in the Regulatory Flexibility 

Act,161 not with individual Bulk-Power System facilities. Because the Trade 

Associations are focusing on the size of the Bulk-Power System facility, and not the 

actual entity, we deny the Trade Associations’ request for rehearing on this issue. 

141. Additionally, the Trade Associations argue that the Commission erred when it 

stated that entities that own only generation would not be subject to PRC-023-1. The 

Commission stands by its statement, as found in the Final Rule, that “no generator owner 

that is not also a transmission owner and/or a distribution provider will be subject to 

PRC-023-1.” Accordingly, the Commission was correct in limiting the number of 

entities that could be subject to PRC-023-1. 

161 See Small Business Administration, A Guide for Government Agencies, How 

to Comply with the Regulatory Flexibility Act 1 (Jun. 2010) (“The RFA applies to a wide 

range of small entities, including small businesses, not-for-profit organizations, and small 

governmental jurisdictions”).
Docket No. RM08-13-001 - 95 - 

142. Finally, the Trade Associations allege that the Commission erred in stating that a 

maximum of 80 small entities are listed on the NERC Compliance Registry. The Trade 

Associations, in their comments, provided a figure of 253 small electric utilities. As 

previously explained in the Final Rule, to arrive at the Commission’s quantity of 80, it 

compared the number of electric utility companies that qualify as small electric utilities 

(as found on the EIA-861 Database Year 2007) to the companies listed on the NERC 

Compliance Registry. This comparison revealed that only 80 entities that qualified as 

small entities were found on both lists. Although the Trade Association references EIA 

data, it is unclear which entities it includes in its 253 figure, and, without more 

information, the two numbers cannot be rectified. The Trade Associations have not 

provided a basis for us to reconsider our determination that the relevant number of 

entities is 80. 

143. In conclusion, the Commission reaffirms its Final Rule determination that PRC023-1 will not have a significant economic impact on a substantial number of small 

entities. 

The Commission orders: 

(A) The requests for rehearing are hereby granted, in part, and denied, in part, 

as discussed in the body of this order. 

(B) The requests for clarification are hereby granted, as discussed in the body 

of this order. 
Docket No. RM08-13-001 - 96 - 

(C) The request for an extension of time is hereby granted, as discussed in the 

body of this order. 

By the Commission. 

( S E A L ) 

Nathaniel J. Davis, Sr., 

Deputy Secretary. 
Docket No. RM08-13-001 - 97 - 

Appendix 1 

Generator Step-up and Auxiliary Transformers and Applicability to Backup 

Protection Systems 

 The following diagrams162 illustrate the two types of connections discussed in 

Order No. 733. Commenters’ arguments are in reference to the connection depicted in 

Figure 1. The Commission’s directive is in reference to the connection depicted in 

Figure 2. 

Figure 1 Figure 2 

 

BPS BPS 

GSU GSU 

CT CT 

sensing 

direction PT PT 

(2) Generator Terminal Connected CTs 

sensing 

direction 

(1) Neutral Connected CTs 

 162 Generator Control and Protection, presented at Southern Illinois University 

Edwardsville, available at http://www.ee.siue.edu/~smuren/ ECE%20545% 

20Notes/Ch%2011%20-%20Generator%20Protection.pdf