127 FERC ¶ 61,175 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

18 CFR Part 40 

Docket No. RM08-13-000 

Transmission Relay Loadability Reliability Standard 

(May 21, 2009) 

AGENCY: Federal Energy Regulatory Commission. 

ACTION: Notice of Proposed Rulemaking. 

SUMMARY: Pursuant to section 215 of the Federal Power Act, the Federal Energy 

Regulatory Commission proposes to approve Reliability Standard PRC-023-1 

(Transmission Relay Loadability Reliability Standard) developed by the North American 

Electric Reliability Corporation. The proposed Reliability Standard requires certain 

transmission owners, generator owners, and distribution providers to set protective relays 

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 loadability or 

interfere with system operators’ ability to protect system reliability. While all relays 

detect and protect the electric network from fault conditions, the proposed Reliability 

Standard applies only to load-responsive phase protection relays. In addition, pursuant to 

section 215(d)(5) of the Federal Power Act, the Commission proposes to direct NERC to 

develop modifications to the proposed Reliability Standard to address specific concerns 

identified by the Commission. 
Docket No. RM08-13-000 - 2 - 

DATES: Comments are due [insert date that is 60 days after publication in the

FEDERAL REGISTER]. 

ADDRESSES: Interested persons may submit comments, identified by Docket No. 

RM08-13-000, by any of the following methods: 

• Agency Web Site: http://www.ferc.gov. Documents created electronically using 

word processing software should be filed in native applications or print-to-PDF 

format and not in a scanned format. 

• Mail/Hand Delivery. Commenters unable to file comments electronically must 

mail or hand deliver an original and 14 copies of their comments to: Federal 

Energy Regulatory Commission, Secretary of the Commission, 888 First Street, 

N.E., Washington, D.C. 20426. 

FOR FURTHER INFORMATION CONTACT: 

Joshua Konecni (Legal Information) 

Office of the General Counsel 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, D.C. 20426 

(202) 502-6291 

Michael Henry (Legal Information) 

Office of the General Counsel 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, D.C. 20426 

(202) 502-8532 
Docket No. RM08-13-000 - 3 - 

Cynthia Pointer (Technical Information) 

Office of Electric Reliability 

Division of Reliability Standards 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, D.C. 20426 

(202) 502-6069 

Robert Snow (Technical Information) 

Office of Electric Reliability 

Division of Reliability Standards 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, D.C. 20426 

(202) 502-6716 

SUPPLEMENTARY INFORMATION

:
127 FERC ¶ 61,175 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Transmission Relay Loadability Reliability Standard Docket No. RM08-13-000 

NOTICE OF PROPOSED RULEMAKING 

TABLE OF CONTENTS 

Paragraph Numbers

I. Background .................................................................................................................... 2.

 A. Protective Relays ........................................................................................................ 2.

 B. Protective Relays and the August 14, 2003 Blackout............................................... 10.

 C. Task Force Final Blackout Report......................................................................... 11.

 D. NERC and Task Force Recommendations ............................................................... 12.

II. Proposed Reliability Standard PRC-023-1 ................................................................. 15.

 A. Requirements ............................................................................................................ 18.

 1. Requirement R1................................................................................................... 19.

 2. Requirement R2................................................................................................... 23.

 3. Requirement R3................................................................................................... 24.

 B. Interactions with other Standards ............................................................................. 25.

 C. Effective Date ........................................................................................................ 26.

 

III. Discussion................................................................................................................... 28.

 A. Legal Standard.......................................................................................................... 28.

 B. Decision .................................................................................................................... 30.

 C. Applicability .......................................................................................................... 35.

 1. Applicability to Entities with Facilities Operated Between 100 kV and 200 kV 

and to Facilities Operated below 100 kV that Are Critical to the Reliability of the Bulk 

Electric System................................................................................................................. 36.

 2. Generator Step-Up and Auxiliary Transformers .................................................. 46.

 D. Need to Address Additional Issues........................................................................ 49.

 1. Zone 3/Zone 2 Relays Applied as Remote Circuit Breaker Failure and Backup 

Protection.......................................................................................................................... 50.

 2. Protective Relays Operating Unnecessarily due to Stable Power Swings ........... 54.

 E. Concerns with the Implementation of Certain Criteria under Requirement R1 .... 61.

 1. Requirement R1.2................................................................................................ 63.

 2. Requirement R1.10.............................................................................................. 66.

 3. Requirement R1.12.............................................................................................. 70.
Docket No. RM08-13-000 ii 

 F. Requirement R3 and its Sub-Requirements .............................................................. 74.

 G. Attachment A............................................................................................................ 76.

 1. Section (2): Evaluation of Out-of-Step Blocking Schemes................................. 77.

 2. Section (3): List of Protection Systems Excluded from the Standard................. 78.

 H. Effective Date .......................................................................................................... 82.

 I. Violation Risk Factors .............................................................................................. 87.

 1. Requirement R1and its Sub-Requirements ......................................................... 91.

 2. Requirement R3................................................................................................... 93.

 J. Violation Severity Levels ........................................................................................ 95.

 1. Requirement R1................................................................................................... 99.

 2. Requirement R2................................................................................................. 102.

 3. Requirement R3................................................................................................. 105.

IV. Information Collection Statement ............................................................................ 109.

V. Environmental Analysis ........................................................................................... 115.

VI. Regulatory Flexibility Act Analysis.......................................................................... 116

VII. Comment Procedures .............................................................................................. 119.

VIII. Document Availability .......................................................................................... 123.
UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Transmission Relay Loadability Reliability Standard Docket No. RM08-13-000 

NOTICE OF PROPOSED RULEMAKING 

(May 21, 2009) 

1. Pursuant to section 215 of the Federal Power Act (FPA),1

 the Federal Energy 

Regulatory Commission (Commission) proposes to approve Reliability Standard PRC023-1 (Transmission Relay Loadability Reliability Standard), developed by the North 

American Electric Reliability Corporation (NERC) in its capacity as the Electric 

Reliability Organization (ERO).2

 The proposed Reliability Standard requires certain 

transmission owners, generator owners, and distribution providers to set protective relays 

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 loadability3

 or 

interfere with system operators’ ability to protect system reliability.4

 In addition, 

 

1

 16 U.S.C. 824o. 

2

 Section 215(e)(3) of the FPA directs the Commission to certify an ERO to 

develop mandatory and enforceable Reliability Standards, subject to Commission review 

and approval. 16 U.S.C. 824o(e)(3). Following a selection process, the Commission 

selected and certified NERC as the ERO. North American Electric Reliability Corp., 

116 FERC ¶ 61,062 (ERO Certification Order), order on reh’g & compliance, 117 FERC 

¶ 61,126 (ERO Rehearing Order) (2006), aff’d sub nom. Alcoa, Inc. v. FERC, No. 06-

1426, 2009 U.S. App. LEXIS 9905 (D.C. Cir. May 8, 2009). 

3

 In the context of the proposed Reliability Standard, “loadability” refers to the 

ability of protective relays to refrain from operating under load conditions. 

4

 The Commission is not proposing any new or modified text to its regulations. 

Rather, as provided in 18 CFR Part 40, a proposed Reliability Standard will not become 

(continued...) 
Docket No. RM08-13-000 

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pursuant to section 215(d)(5) of the FPA,5

 the Commission proposes to direct the ERO to 

develop modifications to the proposed Reliability Standard to address specific concerns 

identified by the Commission. 

I. Background 

A. Protective Relays 

2. Protection systems are used to detect, operate, and initiate the removal of faults on 

an electric system.6

 Some protection systems use redundancy, measurements, and 

telecommunications facilities to accurately identify and confirm the location of a fault;7

others use a single system that relies only on local information.8

 

 

effective until approved by the Commission, and the ERO must post on its website each 

effective Reliability Standard. 

5

 16 U.S.C. 824(d)(5). 

6

A “fault” is defined in the NERC Glossary of Terms used in Reliability Standards 

as, “[a]n event occurring on an electric system such as a short circuit, a broken wire, or an 

intermittent connection.” 

7

 “Redundancy” means that the primary component has a “twin” component that 

operates to isolate the fault in the same manner at approximately the same time. The 

transmission planner may assume that, at any given time, either the primary component 

or its redundant component will be operable and therefore the system will clear the 

contingency in the time associated with the primary protection. 

8

 “Local information” refers to system measurements obtained at the immediate 

location of the protective relay. Achieving protection coordination and performance are 

required in the present Reliability Standards. Special protection systems and redundancy 

are not required as long as the applied system can achieve the desired performance. 
Docket No. RM08-13-000 

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3. Protective relays, also known as primary relays, are one type of equipment used in 

protection systems.9

 Protective relays read electrical measurements (such as current, 

voltage, and frequency) and remove from service any system element that suffers a fault 

and threatens to damage equipment or interfere with effective operation of the system.10 

Protective relays are applied to protect specific system elements and are set to recognize 

certain electrical measurements as indicating a fault. When a protective relay detects a 

fault, it sends a signal to an interrupting device (such as a circuit breaker11) to disconnect 

the element or elements from the rest of the system. 

4. The sequence in which protective relays operate is important. For example, on a 

transmission line, coordination of protection through distance settings and time delays 

ensures that the relay closest to a fault can operate before a relay farther away from the 

fault.12 If the more distant relay operates first, it will disconnect both the transmission 

 9

 By definition, protection systems include protective relays, associated 

communication systems, voltage and current sensing devices, station batteries, and DC 

control circuitry. See NERC Glossary of Terms Used in Reliability Standards. 

10 There are two generic types of protective relays: those that have fixed 

characteristics (i.e., those that are used similar to a control switch, such as lockout relays) 

and those whose characteristic can be set to vary (i.e., those that are used to detect faults). 

The proposed Reliability Standard is applicable to the latter type of protective relay. 

11 A “circuit breaker” is a power operated switch capable of interrupting current 

(e.g., load, fault, etc.) that is within its rating. 

12 “Coordination of protection” is defined by the Institute of Electrical and 

Electronics Engineers (IEEE) Std. C37.113-1999, “IEEE Guide for Protective Relay 

Applications to Transmission Lines” as “[t]he process of choosing settings or time delay 

characteristics of protective devices, such that operation of the devices will occur in a 

(continued...) 
Docket No. RM08-13-000 

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equipment necessary to remove the fault and “healthy” equipment that should remain in 

service. 

5. Impedance relays are the most common type of relays used to protect transmission 

lines. Impedance relays continuously measure local voltage and current on the protected 

transmission line and operate when the measured magnitude and phase of the impedance 

(voltage/current) falls within the settings or reach of the relay.13 Impedance relays can 

also provide backup protection and protection against remote circuit breaker failure. 

6. Multiple impedance relays are installed at each end of the transmission line14 with 

each typically used to protect a certain percentage, or zone, of the local transmission line 

and remote lines. The purpose of zonal protection is to protect each part of the local and 

remote transmission lines (i.e., no “gaps”) and to disconnect only the equipment 

 

specified order to minimize customer service interruption and power system isolation due 

to a power system disturbance.” 

13 The “reach” of the relay refers to the length of the transmission line for which 

the relay is set to protect and is generally used in reference to impedance relays. 

Proposed Reliability Standard PRC-023-1 establishes criteria to be used for setting phase 

impedance, as well as, overcurrent relays dependent on the system configuration where 

the relay is applied. The system configurations are described in sub-Requirements R1.1 

through R1.13. Further, as impedance relays, also known as distance relays, detect 

changes in currents (I*) and voltages (V*) to determine the apparent impedance (Z*) 

according to the relationship of Z*=V*/I* of the line, impedance are directionally 

sensitive. They are forward looking into the lines that they are protecting, i.e., they 

protect against faults in front of and not behind the relay’s installed location. 

14 Impedance relays are installed at each end of a transmission line and protect it in 

the forward looking direction of the relay, i.e., the impedance relays at the opposite 

terminals of a line “look” toward each other to detect line faults that are within their 

respective reaches and directions. 
Docket No. RM08-13-000 

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necessary to remove a fault even if the closest protection system does not operate as 

desired. Impedance relays may be set to cover one, two, or three protection zones (zone 

1, zone 2, and zone 3 respectively), with appropriate time delays to achieve coordination 

of protection. 

7. Zone 1 relays are typically set to reach 80 percent of the protected transmission 

line. They leave a 20 percent margin at the far end of the line to avoid operating for 

faults for which they are not intended to operate, such as for faults on an adjacent line.15 

Zone 1 relays provide fast primary protection and so are set to operate without an 

intentional time delay. 

8. Zone 2 relays provide backup protection and are typically set to reach 125 percent 

of the protected transmission line, i.e., 100 percent of the protected transmission line and 

25 percent of the adjacent transmission line (i.e., they have a 25 percent margin). 

Because zone 2 relays can operate for faults on both the protected transmission line and 

on parts of adjacent transmission lines connected to the remote terminal,16 they are set 

with a time delay to allow for coordination of protection with the zone 1 relay on the 

faulted line. This time delay is determined or verified through system planning analysis.17 

 15 The margin takes into account measurement errors of the relay, imprecise line 

impedance used in the relay setting calculation, and changes in system conditions. 

16 For example, a zone 2 relay will operate if the impedance on the adjacent line 

and the impedance of the protected line fall within the relay’s setting. 

17 System planning analysis would identify the performance, required by Table 1 

of the Transmission Planning (TPL) Reliability Standards. 
Docket No. RM08-13-000 

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9. Zone 3 relays provide remote circuit breaker failure and backup protection (i.e., 

when the remote circuit breaker fails to open to remove a fault) for remote distance faults 

on a transmission line; they amount to a backup of the zone 2 backup.18 Zone 3 relays 

and zone 2 relays set to operate like zone 3 relays (zone 3/zone 2 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 zone 2 relays. 

B. Protective Relays and the August 14, 2003 Blackout 

10. On August 14, 2003, a blackout that began in Ohio affected significant portions of 

the Midwest and Northeast United States, and Ontario, Canada (2003 blackout). This 

blackout affected an area with an estimated 50 million people and 61,800 megawatts of 

electric load.19 The subsequent investigation and report completed by the U.S.-Canada 

Power System Outage Task Force (Task Force) concluded that a substantial number of 

lines disconnected when backup distance and phase relays operated under non-fault 

conditions. The Task Force determined that the unnecessary operation of these relays 

contributed to cascading outages at the start of the blackout and accelerated the 

 18 James S. Thorp, Power Systems Engineering Research Center, The Protection 

System in Bulk Power Networks 5 (2003). 

19 U.S.-Canada Power System Outage Task Force, Final Report on the August 14, 

2003 Blackout in the United States and Canada: Causes and Recommendations, (April 

2004) (Final Blackout Report), available at http://www.ferc.gov/industries/electric/indusact/blackout.asp. 
Docket No. RM08-13-000 

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geographic spread of the cascade.20 Seeking to prevent or minimize the scope of future 

blackouts, both the Task Force and NERC made recommendations to ensure that 

protective relays do not contribute to future blackouts. 

C. Task Force Final Blackout Report 

11. The Task Force determined that one of the principal reasons why cascading 

outages spread beyond Ohio was the operation of zone 3/zone 2 relays in response to 

overloads rather than true faults.21 The Task Force identified fourteen 345 kV and 138 

kV transmission lines that disconnected because of zone 3/zone 2 relays applied as 

remote circuit breaker failure and backup protection. Among these relays were several 

zone 2 relays in Michigan that were set to overreach their protected lines by more than 

200 percent without any intentional time delay.22 The Task Force stated that although 

these and the other relays operated according to their settings, they operated so quickly 

that they impeded the natural ability of the electric system to hold together and did not 

allow time for operators to try to stop the cascade.23 The Task Force described the 

unnecessary operation of these relays as the “common mode of failure that accelerated 

the geographic spread of the cascade.”24 The Task Force also indicated that as the 

 20 Id. at 80. 

21 Id. at 73. 

22 Id. at 80. 

23 Id. 

24 Id. 
Docket No. RM08-13-000 

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cascade progressed beyond Ohio it spread because of dynamic power swings and the 

resulting instability.25 

D. NERC and Task Force Recommendations 

12. NERC conducted its own investigation into the 2003 blackout and developed 

recommendations to prevent and mitigate future cascades. Recommendation 8A of the 

NERC Report addresses the need to evaluate zone 3 relays to determine whether they will 

operate under extreme emergency conditions: 

All transmission owners shall, no later than September 30, 2004, evaluate 

the zone 3 relay settings on all transmission lines operating at 230 kV and 

above for the purpose of verifying that each zone 3 relay is not set to trip on 

load under extreme emergency conditions[]. In each case that a zone 3 

relay is set so as to trip on load under extreme conditions, the transmission 

operator shall reset, upgrade, replace, or otherwise mitigate the overreach of 

those relays as soon as possible and on a priority basis, but no later than 

December 31, 2005. Upon completing analysis of its application of zone 3 

relays, each transmission owner may no later than December 31, 2004 

submit justification to NERC for applying zone 3 relays outside of these 

recommended parameters. The Planning Committee shall review such 

exceptions to ensure they do not increase the risk of widening a cascading 

failure of the power system.26 

13. In Recommendation No. 21A of the Final Blackout Report, the Task Force 

recommended that NERC go further than it had proposed in its report: 

NERC [should] broaden the review [described in Recommendation 8A of 

the NERC Report] to include operationally significant 115 kV and 138 kV 

lines, e.g., lines that are part of monitored flowgates or interfaces. 

 25 Id. at 81. 

26 August 14, 2003 Blackout: NERC Actions to Prevent and Mitigate the Impacts 

of Future Cascading Blackouts 13 (2004) (NERC Report). 
Docket No. RM08-13-000 

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Transmission owners should also look for zone 2 relays set to operate like 

zone 3 [relays].27

14. NERC states that PRC-023-1 responds to these recommendations. 

II. Proposed Reliability Standard PRC-023-1

15. Reliability Standard PRC-023-1 requires certain transmission owners, generator 

owners, and distribution providers to set certain protective relays according to specific 

criteria to ensure that they detect only faults for which they must operate and do not 

operate unnecessarily during non-fault load conditions. NERC proposes that PRC-023-1 

apply to transmission owners, generator owners, and distribution providers with loadresponsive phase protection systems as described in Attachment A to PRC-023-1, applied 

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. The proposed Reliability Standard also prescribes the settings that should be 

used when it is appropriate to use a 0.85 per unit voltage and a power factor angle of 30 

degrees. NERC states that PRC-023-1 has a broader application than the 

recommendations in the NERC and Task Force final reports, which address only zone 

3/zone 2 relays, because other load-responsive relays were found to have contributed to 

the 2003 blackout. 

 27 Final Blackout Report at 158. 
Docket No. RM08-13-000 

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16. Under the proposed Reliability Standard, protective relay settings must provide 

essential facility protection for faults without preventing operation of the Bulk-Power 

System in accordance with established Facility Ratings.28 If essential facility protection 

imposes a more constraining limit on the system, PRC-023-1 requires that the Facility 

Rating reflect that limit. Proposed Reliability Standard PRC-023-1 applies to any 

protective functions that could operate with or without time delay, on load current, 

including but not limited to: phase distance, out-of-step tripping, switch-on-to-fault, 

overcurrent relays, and communication-aided protection applications. It also requires 

evaluation of out-of-step blocking schemes29 to ensure that they do not operate for faults 

during specified loading conditions.30 

17. The proposed Reliability Standard expressly excludes from its requirements: relay 

elements enabled only when other relays or associated systems fail (e.g., overcurrent 

elements enabled only during abnormal system conditions or a loss of communications), 

protection relay systems intended for the detection of ground fault conditions or for 

protection during stable power swings, generator protective relays susceptible to load, 

relay elements used only for special protection systems applied and approved in 

 28 As defined in NERC’s Glossary of Terms Used in Reliability Standards. 

29 “Out-of-step blocking” refers to a protection system that is capable 

distinguishing between a fault and a power swing. If a power swing is detected, the 

protection system, “blocks,” or prevents the tripping of its associated transmission 

facilities. 

30 See PRC-023-1 Attachment A, Item 1. 
Docket No. RM08-13-000 

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accordance with NERC Reliability Standards PRC-012 through PRC-017,31 protection 

relay systems designed to respond only in time periods that allow operators 15 minutes or 

longer to respond to overload conditions, thermal emulation relays used in conjunction 

with dynamic Facility Ratings, relay elements associated with DC lines, and relay 

elements associated with DC converter transformers. 

A. Requirements 

18. Proposed Reliability Standard PRC-023-1 consists of three compliance 

requirements.32 Requirements R1 and R2 apply to transmission owners, generator 

owners, and distribution providers with transmission lines or transformers with lowvoltage terminals connected at 200 kV and above. Requirement R3 requires planning 

coordinators to identify the facilities operated between 100 kV and 200 kV that are 

critical to the reliability of the bulk electric system, and therefore subject to Requirement 

R1. 

1. Requirement R1

19. Requirement R1 states that each transmission owner, generator owner, and 

distribution provider subject to the proposed Reliability Standard shall use one of the 

 31 The Commission has approved PRC-015-0, PRC-016-0, and PRC-017-0 and has 

not approved or remanded PRC-012-0, PRC-013-0, and PRC-014-0. 

32 NERC has also filed a document entitled: “PRC-023 Reference – 

Determination and Application of Practical Relaying Loadability Ratings.” NERC states 

that this document explains the rationale behind the requirements in the proposed 

Reliability Standard and provides the calculation methodology to help entities comply. 

NERC states that the reference document is presented for information only and does not 

request that the Commission take action on it. 
Docket No. RM08-13-000 

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criteria prescribed in sub-Requirements R1.1 through R1.13 for any specific circuit 

terminal to prevent its phase protective relay settings from limiting transmission system 

loadability while maintaining reliable protection of the bulk electric system for all fault 

conditions.33 

20. Sub-Requirements R1.1 through R1.13 prescribe specific criteria to be used for 

certain transmission system configurations. These criteria account for the presence of 

devices such as series capacitors and address circuit and transformer thermal capability. 

NERC states that the criteria set forth in the sub-requirements reflect the maximum 

circuit loading for various system configurations and allow the protective relays subject 

to the proposed Reliability Standard to be set for optimum protection while carrying that 

load. NERC claims that each criterion balances the need to protect the system with the 

optimization of load carrying capability. 

21. Sub-Requirement R1.1 specifies transmission line relay settings based on the 

highest seasonal Facility Rating using the 4-hour thermal rating of a transmission line, 

plus a design margin of 150 percent. Sub-Requirement R1.2 allows transmission line 

relays to be set so that they do not operate at or below 115 percent of the highest seasonal 

15-minute Facility Rating of a circuit, when a 15-minute rating has been calculated and 

published for use in real-time operations. Sub-Requirement R1.3 allows transmission 

line relays to be set so that they do not operate at or below 115 percent of the maximum 

 33 Requirement R1 also requires each transmission owner, generator owner, and 

distribution provider to evaluate relay loadability at 0.85 per unit voltage and a power 

factor angle of 30 degrees. 
Docket No. RM08-13-000 

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theoretical power capability.34 Sub-Requirement R1.4 may be applied where series 

capacitors are used on long transmission lines to increase power transfer.35 SubRequirement R1.5 applies in cases where the maximum end-of-line three-phase fault 

current is small relative to the thermal loadability of the conductor.36 Sub-Requirement 

R1.6 may be used for system configurations where generation is remote from load busses 

or main transmission busses. Under these conditions, protective relays must be set so that 

they do not operate at or below 230 percent of the aggregated generation nameplate 

capability in the remote area. 

22. NERC states that Sub-Requirement R1.7 is appropriate for system configurations 

that have load centers that are remote from the generation center. The protective relays at 

the load center terminal must be set such that they operate only above 115 percent of the 

maximum current flow from the load to generation source under any system 

configuration. Sub-Requirement R1.8 applies to system configurations that have one or 

more transmission lines connecting a remote, net importing load center to the rest of the 

 34 The power transfer calculation may be performed by using either an infinite 

source with a 1.00 per unit bus voltage at each end of the transmission line or an 

impedance at each end of the line, which reflects the actual system source impedance 

with a 1.05 per unit voltage behind each source impedance. 

35 Special consideration must be made in computing the maximum power flow that 

protective relays must accommodate on series-compensated transmission lines, the 

greater of 115 percent of the highest emergency rating of the series capacitor or 115 

percent of the maximum power transfer on the circuit calculated according to subRequirement R1.3. 

36 Such cases exist due to some combination of weak sources, long lines, and the 

topology of the transmission system. 
Docket No. RM08-13-000 

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system. Under these conditions, the protective relays at the bulk electric system end must 

be set so that they operate only above 115 percent of the maximum current flow to the 

load center under any system configuration. Similarly, sub-Requirement R1.9 applies to 

the load end and requires protective relays to be set so that they operate only above 115 

percent of the maximum current flow to the bulk electric system under any system 

configuration. Sub-Requirement R1.10 is specific to transmission transformer fault 

protective relays and transmission lines terminated only with a transformer.37 SubRequirement R1.11 may be used when sub-Requirement R1.10 cannot be met.38 SubRequirement R1.12 may be used when the circuits have three or more terminals. In these 

cases, line distance relays are still required to provide adequate protection for multiterminal circuits, but their settings (required to be set at 125 percent of the apparent 

impedance with a maximum torque angle at 90 degrees or the highest supported by the 

relay manufacturer)39 will limit the desired circuit loading capability. This limited circuit 

 37 The protective relays must be set so that they operate only above the greater of 

(i) 150 percent of maximum transformer nameplate rating, and (ii) 115 percent of the 

highest operator established emergency transformer rating. 

38 In these cases additional considerations are specified to limit unnecessary 

operation due to load according to one of the following: (i) set the relays to allow 

transformer overload operation at higher than 150 percent of the maximum applicable 

rating, or 115 percent of the highest operator established emergency transformer rating 

whichever is greater, and allows at least 15 minutes for the operator to take controlled 

action to relieve the overload, and (ii) install supervision for the relays using either a top 

oil (setting no less than 100 degrees Celsius) or simulated winding hot spot temperature 

elements (setting no less than 140 degrees Celsius). 

39 Relay loadability must be evaluated at the relay trip point at 0.85 per unit 

voltage and a power factor angle of 30 degrees. 
Docket No. RM08-13-000 

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loading capability will become the Facility Rating of the circuit. Finally, subRequirement R1.13 is intended to apply when otherwise supportable situations and 

practical limitations are identified under sub-Requirements R1.1 through R1.12. In these 

situations, the phase protective relays must be set so that they operate above 115 percent 

of such identified limitations. 

2. Requirement R2

23. Requirement R2 states that transmission owners, generator owners, and 

distribution providers that use a circuit with the protective relay settings determined by 

the practical limitations described in sub-Requirements R1.6 through R1.9, R1.12, or 

R1.13 must use the calculated circuit capability as the circuit’s Facility Rating and must 

obtain the agreement of the planning coordinator, transmission operator, and reliability 

coordinator with the calculated circuit capability. 

3. Requirement R3

24. Requirement R3 requires planning coordinators to designate which transmission 

lines and transformers with low-voltage terminals operated or connected between 100 kV 

and 200 kV are critical to the reliability of the bulk electric system (because they prevent 

a cascade) and therefore subject to Requirement R1.40 Sub-Requirements R3.1 and 

R3.1.1 specify that planning coordinators must identify these facilities through a process 

 40 The Commission notes that “planning coordinator” is an undefined entity in the 

NERC Glossary of Terms Used in Reliability Standards. The Commission understands 

that the ERO has proposed to implement the term “planning coordinator” in its glossary 

in a separate proceeding currently before the Commission. 
Docket No. RM08-13-000 

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that considers input from adjoining planning coordinators and affected reliability 

coordinators. Sub-Requirements R3.2 and R3.3 require planning coordinators to 

maintain a list of these facilities and provide it to reliability coordinators, transmission 

owners, generator owners, and distribution providers within 30 days of its initial 

establishment, and within 30 days of any subsequent change. 

B. Interactions with Other Standards

25. NERC states that proposed Reliability Standard PRC-023-1 interacts with several 

existing Reliability Standards, including: FAC-008-1,41 FAC-009-1,42 IRO-002-1,43

IRO-005-1,44 and TOP-008-1.45 NERC states that the interactions between these 

Reliability Standards and the proposed Reliability Standard require that limits be 

established for all system elements, interconnected systems be operated within these 

 41 FAC-008-1 requires that transmission owners and generator owners have a 

Facility Ratings methodology. 

42 FAC-009-1 requires that transmission owners and generator owners establish 

Facility Ratings for their equipment and distribute them to affected entities. 

43 IRO-002-1 requires that reliability coordinators have sufficient monitoring to 

ensure that potential or actual System Operating Limits or Interconnection Reliability 

Operating Limits are identified. 

44 IRO-005-1 requires that reliability coordinators be aware at all times of the 

current state of the interconnected system (including all pre-contingency element 

conditions) and all post-contingency element conditions, and have mitigation plans to 

alleviate System Operating Limit or Interconnection Reliability Operating Limit 

violations. 

45 TOP-008-1 requires that transmission operators operate their systems to avoid 

System Operating Limit and Interconnection Reliability Operating Limit violations and 

take immediate steps to alleviate the conditions causing the violations when they occur. 
Docket No. RM08-13-000 

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limits, operators take immediate action to mitigate operation outside these limits, and 

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

element exceeds these limits. 

C. Effective Date

26. NERC proposes that PRC-023-1 be made effective consistent with the 

implementation plan specified in proposed Reliability Standard.46 That plan proposes 

that Requirements R1 and R2 be made effective on the beginning of the first calendar 

quarter following applicable regulatory approvals. For smaller facilities deemed critical 

to system reliability that are subject to Requirements R1 and R2, NERC proposes an 

effective date of the beginning of the first calendar quarter 39 months after applicable 

regulatory approvals. NERC also proposes that, upon being notified that a facility 

operated between 100 kV and 200 kV has been added to the critical facilities list 

established in Requirement R3, the facility owner will have 24 months to comply with 

Requirement R1 and its sub-requirements. For Requirement R3, NERC proposes an 

effective date of 18 months following applicable regulatory approvals. NERC states that 

the technical requirements of the proposed Reliability Standard have been voluntarily 

implemented by most applicable entities starting in January 2005. 

 46 On February 2, 2009, NERC filed an erratum to its petition to address an 

inadvertent reference to the requested effective date. NERC requests that the Reliability 

Standard be made effective consistent with the implementation plan accompanying the 

Reliability Standard. 
Docket No. RM08-13-000 

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27. NERC also proposes to include a footnote to the “Effective Dates” section that 

states that entities that have received temporary exceptions approved by the NERC 

Planning Committee (via the NERC System and Protection and Control Task Force) 

before approval of the proposed Reliability Standard shall not be found in noncompliance with the Reliability Standard or receive sanctions if: (1) the approved 

requests for temporary exceptions include a mitigation plan (including schedule) to come 

into full compliance and (2) the non-conforming relay settings are mitigated according to 

the approved mitigation plan. 

III. Discussion

A. Legal Standard

28. Section 215(d)(2) of the FPA states that the Commission may approve, by rule or 

order, a proposed Reliability Standard or modification to a Reliability Standard if it 

determines that the Standard is just, reasonable, not unduly discriminatory or preferential, 

and in the public interest.47 If the Commission disapproves of the proposed Standard in 

whole or in part, it must remand the proposed Standard to the ERO for further 

consideration.48 Section 215(d)(5) grants the Commission authority, upon its own 

motion or upon complaint, to order the ERO to submit to the Commission a proposed 

Reliability Standard or a modification to a Reliability Standard that addresses a specific 

 47 16 U.S.C. 824o(d)(2). 

48 16 U.S.C. 824o(d)(4). 
Docket No. RM08-13-000 

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matter if the Commission considers such a modified Reliability Standard appropriate 

carry out secti

to 

on 215. 

29. Unlike Reliability Standards, which set forth requirements with which applicable 

entities must comply, violation risk factors and violation severity levels do not set forth 

requirements, but instead are factors used in the determination of a monetary penalty for 

a violation of a Reliability Standard requirement.49 The Commission’s authority to revise 

violation risk factors and violation severity levels is not circumscribed by section 215(d). 

B. Decision

30. Pursuant to section 215(d)(2) of the FPA, the Commission proposes to approve 

Reliability Standard PRC-023-1 as just, reasonable, not unduly discriminatory or 

preferential, and in the public interest. The Commission agrees with the ERO that PRC023-1 is a significant step toward improving the reliability of the Bulk-Power System in 

North America because it requires that protective relay settings provide essential facility 

protection for faults, while allowing the Bulk-Power System to be operated in accordance 

with established Facility Ratings. 

31. As stated by NERC, Reliability Standard PRC-023-1 interacts with several 

existing Reliability Standards. Reliability Standards are intended to provide coordinated 

and complementary requirements that ensure reliable operation of the Bulk-Power 

 49 North American Electric Reliability Corp., 123 FERC ¶ 61,284, at P 15 (2008); 

North American Electric Reliability Corp., 119 FERC ¶ 61,145 at P 17, order on reh’g 

and compliance filing, 120 FERC ¶ 61,145 (2007). 
Docket No. RM08-13-000 

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System.50 Consequently, in implementing PRC-023-1, registered entities must comply 

with the requirements of other Reliability Standards. For example, protective relay 

settings determined and applied in accordance with the requirements of PRC-023-1 must 

be included in determining system performance, System Operating Limits, and 

Interconnection Reliability Operating Limits, and must be coordinated with other 

protective relay settings as required by the applicable Reliability Coordination (IRO), 

Transmission Operations (TOP), and TPL Reliability Standards.51 Only in this way can 

the entity satisfy its obligations under other Reliability Standards and comply with the 

requirement in PRC-023-1 to set protective relays while “maintaining reliable protection 

of the bulk electric system for all fault conditions.”52

32. Similarly, Reliability Standards TPL-001-0 through TPL-004-0 require annual 

system assessments to determine if the system meets performance requirements, and if 

not, to determine what corrective action plans must be implemented.53 In the 

 50 For example, the critical clearing time needed to achieve the criteria identified 

in Table 1 of the TPL Reliability Standards would be an input to the coordination of 

protection systems in Reliability Standard PRC-001-1. 

51 See Mandatory Reliability Standards for the Bulk-Power System, Order No. 

693, FERC Stats. & Regs. ¶ 31,242, at P 1435, order on reh’g, Order No. 693-A, 120 

FERC ¶ 61,053 (2007) (“Protection systems on Bulk-Power System elements are an 

integral part of reliable operations . . . . In deriving [System Operating Limits] and 

[Interconnection Reliability Operating Limits], moreover, the functions, settings, and 

limitations of protection systems are recognized and integrated.”). 

52 PRC-023-1, Requirement R1. 

53 See TPL-002-0 and TPL-003-0 Reliability Standards, Requirements R1 and R2. 
Docket No. RM08-13-000 

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Commission’s view, protective relay settings of both primary and backup systems 

implemented in accordance with PRC-023-1 are subject to these requirements and must 

be considered as part of performing a valid assessment.54 

33. The Commission also emphasizes that the requirements of PRC-023-1 apply to all 

protection systems as described in Attachment A that provide protection to the facilities 

defined in sections 4.1.1 through 4.1.4 of PRC-023-1, regardless of whether the 

protection systems provide primary or backup protection and regardless of their physical 

location. This is because protective relays are always applied to protect specific system 

elements,55 such that when PRC-023-1 states that it governs certain protection systems 

“applied to” certain facilities, it means that the specified protection systems must be set 

according to its requirements if they are applied to protect the specified facilities. 

Consequently, transmission owners, generator owners, and distribution providers with 

protective relays applied to protect the facilities defined in sections 4.1.1 through 4.1.4 of 

PRC-023-1 must set the relays according to PRC-023-1’s requirements. For example, a 

protective relay physically installed on the low-voltage side of a generator step-up 

transformer with the purpose of providing backup protection to a transmission line 

operated above 200 kV must be set in accordance with the requirements of PRC-023-1 

 54 See TPL-002-0 through TPL-004-0, Requirement R1. 

55 See e.g. Reliability Standard PRC-001-1, Requirement R1 (requiring that 

“[e]ach Transmission Operator, Balancing Authority, and Generator Operator shall be 

familiar with the purpose and limitations of protection system schemes applied in its 

area.”) (emphasis added). 
Docket No. RM08-13-000 

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because it is applied to protect a facility defined in the PRC-023-1. This is an important 

aspect of PRC-023-1 because it ensures that all protective relays subject to it that protect 

and could therefore disconnect the facilities defined in it are set in accordance with its 

requirements, thereby avoiding a gap in protection that would undermine its goal of 

ensuring reliable operation. 

34. Additionally, pursuant to section 215(d)(5) of the FPA, the Commission proposes 

to direct the ERO to use its Reliability Standards development process to modify PRC023-1 to address specific concerns. The Commission also proposes to direct the ERO to 

revise certain violation risk factors and violation severity levels for PRC-023-1 by 

applying the guidelines set forth in the Violation Risk Factor Order56 and the Violation 

Severity Level Order.

57 As discussed below, the Commission also reminds the ERO that 

there are other concerns identified in the Final Blackout Report that the ERO should 

address and seeks ERO and public comment to gather more information about these 

issues. After being informed by the ERO and public comment, the Commission may, in 

the final rule, direct the ERO to develop further modifications to PRC-023-1. 

C. Applicability 

35. NERC proposes that Reliability Standard PRC-023-1 apply to transmission 

owners, generator owners, and distribution providers with load-responsive phase 

 56 North American Electric Reliability Corp., 119 FERC ¶ 61,145, order on reh’g 

and compliance filing, 120 FERC ¶ 61,145 (2007) (Violation Risk Factor Order). 

57 North American Electric Reliability Corporation, 123 FERC ¶ 61,284, order on 

reh’g and compliance filing, 125 FERC ¶ 61,212 (2008) (Violation Severity Level 

Order). 
Docket No. RM08-13-000 

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protection systems as described in Attachment A to PRC-023-1, applied to all 

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

200 kV and above, and to 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.58 

The Commission seeks comment on PRC-023-1’s applicability with respect to: 

 58 Section 4 (Applicability) of the proposed Standard provides: 

4.1. Transmission Owners with load-responsive phase protection systems as 

described in Attachment A, applied to facilities defined below: 

4.1.1 Transmission lines operated at 200 kV and above. 

4.1.2 Transmission lines operated at 100 kV to 200 kV as designated by 

the Planning Coordinator as critical to the reliability of the Bulk 

Electric System. 

4.1.3 Transformers with low voltage terminals connected at 200 kV and 

above. 

4.1.4 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. 

4.2. Generator Owners with load-responsive phase protection systems as 

described in Attachment A, applied to facilities defined in 4.1.1 through 

4.1.4. 

4.3. Distribution Providers with load-responsive phase protection systems as 

described in Attachment A, applied according to facilities defined in 4.1.1 

through 4.1.4., provided that those facilities have bi-directional flow 

capabilities. 

4.4. Planning Coordinators. 
Docket No. RM08-13-000 

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(1) transmission owners, generator owners, and distribution providers with facilities 

operated between 100 kV and 200 kV and facilities operated below 100 kV that are 

designated as critical to the reliability of the bulk electric system; and (2) generator stepup and auxiliary transformers. 

1. Applicability to Entities with Facilities Operated Between 100 

kV and 200 kV and to Facilities Operated below 100 kV that Are 

Critical to the Reliability of the Bulk Electric System 

36. Requirement R3 and its sub-requirements require the planning coordinator to have 

a process to determine and maintain a list of facilities operated between 100 kV and 200 

kV that are critical to the reliability of the bulk electric system and are therefore subject 

to Requirement R1. There is no similar requirement for facilities operated below 100 kV 

that are designated by Regional Entities as critical to reliability. 

37. In its petition, NERC states that it decided not to make PRC-023-1 applicable to 

all facilities operated above 100 kV because doing so would increase implementation 

costs “by approximately two orders of magnitude” and distract financial, analytical, and 

staff resources from other areas that it claims have a higher effect on reliability.59 NERC 

also claims that making PRC-023-1 applicable to all circuits 100 kV and above (absent a 

determination of criticality as established in the Requirements) would have little 

additional benefit to the reliability of the interconnected system.60 NERC states that the 

protection of circuits above 200 kV is considerably demanding of the most protective 

 59 NERC Petition at 19, 41. 

60 Id. at 19. 
Docket No. RM08-13-000 

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relays, and it is therefore customary that most modern protective relays are applied to 

circuits above 200 kV.61 NERC further states that communications-based relaying, 

which can detect faults over the entire length of a circuit as well as provide 

communications-based backup protection (rather than backup protection based on 

overreaching distance relays) is much more common at 200 kV and above, and that the 

substation bus arrangements at 200 kV and above diminish the need for relays at remote 

locations that will detect faults in the event of protective equipment failure.62 NERC 

states that these factors contributed to its decision to make PRC-023-1 universally 

applicable to all facilities 200 kV and above, and to make it applicable only to facilities 

between 100 kV and 200 kV that are designated as critical to the reliability of the bulk 

electric system.63

38. NERC does not specifically address facilities operated below 100 kV that are 

designated by Regional Entities as critical to reliability, but it explains in general that it 

decided to make PRC-023-1 voltage-level-specific because the definition of what is 

included in the “bulk electric system” varies throughout the eight Regional Entities and 

because the effects of PRC-023-1 are not constrained to regional boundaries.64 

 61 Id. at 23. 

62 Id. 

63 Id. 

64 Id. at 18-19; 39-41. For example, if one Region has purely performance-based 

criteria and an adjoining Region has voltage-based criteria, these criteria may not permit 

(continued...) 
Docket No. RM08-13-000 

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Commission Proposal

39. The Commission expects that the planning coordinator’s process for determining 

the facilities operated between 100 kV and 200 kV that are critical to the reliability of the 

bulk electric system will be robust enough to identify all such facilities and will be 

consistent across regions. With this in mind, the Commission is concerned that the 

approach established in Requirement R3 may not meet these expectations. 

40. Requirement R3 uses an “add in” approach to identify facilities operated between 

100 kV and 200 kV that are critical to the reliability of the bulk electric system and 

therefore subject to Requirement R1 (i.e., initially exclude facilities operated between 

100 kV and 200 kV from the requirements of the Standard, then through study “add in” 

facilities that are determined to be critical to the reliability of the bulk electric system). 

Since approximately 85 percent of circuit miles of electric transmission are operated at 

253 kV and below,65 the Commission believes that the approach in Requirement R3 may 

not result in a comprehensive study to identify applicable facilities and, at the outset, will 

effectively exempt a large percentage of bulk electric system facilities that should 

otherwise be subject to the Reliability Standard. In fact, NERC acknowledged that an 

 

consideration of the effects of protective relay operation in one Region upon the behavior 

of facilities in the adjoining Region. 

65 U.S. Department of Energy, “The Electric System Delivery Report” issued in 

2006 indicates that of the 635,000 miles of U.S. electric transmission, approximately 

538,000 miles (342,000 miles 132 kV and below; 196,000 miles 132 kV - 253 kV) are 

253 kV and below. 
Docket No. RM08-13-000 

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“add in” approach resulted in such an outcome with respect to the identification of 

Critical Cyber Assets.66 

41. In its report on the 2003 blackout, NERC recommended that all transmission 

owners should evaluate the zone 3 relay settings “operating at 230 kV and above.”67 In 

the Final Blackout Report, the Task Force recommended that NERC go further than it 

had proposed and “broaden the review to include operationally significant 115 kV and 

138 kV lines, e.g., lines that are part of monitored flowgates or interfaces.”68 While 

NERC offers a general explanation of why it proposed that PRC-023-1 apply only to 

facilities operated at 200 kV and above,69 it does not provide a technical analysis to 

support the “add in” approach in Requirement R3. During the 2003 blackout, loadresponsive phase protection relays without communications-based relaying operated 

unnecessarily, contributing to cascading outages. This occurred for facilities operated 

above and below 200 kV. While NERC asserts that most facilities operated at 200 kV 

and above have communications-based relaying, it also states that facilities operated at 

 66 In an April 7, 2009 letter to industry stakeholders, NERC commented on the 

results of the self-certification compliance survey for Reliability Standard CIP-002-1 

Critical Cyber Asset Identification. NERC stated that survey results indicate that entities 

may not have taken a comprehensive approach to identifying Critical Assets in all cases, 

and instead relied on an “add in” approach to identify assets. Because of this, NERC 

stated that a “rule out” approach may be more appropriate and requested that entities redo their identification process for Critical Assets. 

67 NERC Report at 13. 

68 Final Blackout Report at 158. 

69 NERC Petition at 23. 
Docket No. RM08-13-000 

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lower voltages generally do not.70 Consequently, facilities operated below 200 kV 

remain vulnerable to the same problems that contributed to cascading during the 2003 

blackout. 

42. Moreover, the Commission is not persuaded by NERC’s unsupported assertion that 

subjecting all facilities operated above 100 kV to PRC-023-1 would increase 

implementation costs “by approximately two orders of magnitude” and distract financial, 

analytical, and staff resources from other areas that might have a greater impact on 

reliability. PRC-023-1 implements a Final Blackout Report recommendation that was 

specifically developed to prevent cascading outages. The Commission believes that there 

is no area that has a greater impact on the reliability of the bulk electric system than 

preventing cascading outages. Consequently, ensuring that PRC-023-1 applies to all 

facilities that are critical to the reliability of the bulk electric system is necessary for it to 

achieve its intended reliability objective. 

43. In order to meet this goal, it is the Commission’s view that the process for 

determining the facilities operated between 100 kV and 200 kV that are critical to the 

reliability of the bulk electric system must include the same system simulations and 

assessments that are required by the TPL Reliability Standards for reliable operation for 

all Category of Contingencies used in transmission planning.71 The Commission 

 70 Id. 

71 See TPL-002-0 and TPL-003-0 Reliability Standards, Requirements R1.3, and 

R1.3.1 through R1.3.12. For example, for PRC-023-1, the Commission expects that the 

base cases used to determine the applicable facilities would include various generation 

(continued...) 
Docket No. RM08-13-000 

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believes that such an assessment would ensure that for all operating configurations, t

bulk electric system facilities subject to the proposed Reliability Standard would have

appropriate settings applied to their protective relays. The Commission expects that a 

comprehensive process to determine which facilities are critical to the reliability of the 

bulk electric system should necessarily identify nearly every facility operated at or above 

100 kV. This is because a large percentage of the bulk electric system not only falls into 

the 100 kV to 200 kV category, but also supports the reliability of the high voltage 

transmission system (200 kV and above). Therefore, the Commission proposes to direct 

the ERO to modify PRC-023-1 to make it applicable to all facilities operated at or above 

100 kV. The Commission recognizes that there might be a few limited examples of 

facilities operated between 100 kV and 200 kV that are not critical to the reliability of the 

bulk electric system. Therefore, the Commission also proposes to consider exceptions on 

a case-by-case basis for facilities operated between 100 kV to 200 kV that demonstrably 

would not result in cascading outages, instability, uncontrolled separation, violation of 

facility ratings, or interruption of firm transmission service. 

he 

 the 

 

44. The Commission also believes that facilities that have been identified as necessary 

for reliable operation of the bulk electric system, as identified in the Compliance 

Registry,72 should be made subject to the proposed Reliability Standard. Although the 

(continued...) 

dispatches, topologies, and maintenance outages, and would consider the effect of 

redundant and backup protection systems. 

72 NERC maintains a registry of entities that are required to comply with approved 

Reliability Standards to the extent that they are owners, operators, and users of the bulk 
Docket No. RM08-13-000 

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proposed Reliability Standard does not apply to transmission owners with facilities 

operated below 100 kV, and such facilities are not included in NERC’s standard 

definition of the bulk electric system, NERC acknowledges that the definition “allows for 

[r]egional variations in the definition of bulk electric system.”73 Thus, NERC’s 

Statement of Compliance Registry Criteria,74 defines entities with transmission facilities 

operated below 100 kV that are designated by a Regional Entity as critical to reliability as 

“transmission owner[s]/operator[s]” subject to the requirements of the compliance 

registry and therefore to the requirements of Reliability Standards.75 In other words, 

 

power system, perform a function listed in the functional types identified in the Statement 

of Compliance Registry Criteria, and are material to the reliable operation of the 

interconnected bulk power system as defined by the Statement of Compliance Registry 

Criteria. 

73 NERC Petition at 40. NERC defines the Bulk Electric System thusly: 

As defined by the Regional Reliability Organization, the electrical 

generation resources, transmission lines, interconnections with neighboring 

systems, and associated equipment, generally operated at voltages of 100 

kV or higher. Radial transmission facilities serving only load with one 

transmission source are generally not included in this definition. 

74 In the Statement of Compliance Registry Criteria, NERC states that it will 

include in its compliance registry each entity that it concludes can materially impact the 

reliability of the bulk power system. NERC Statement of Compliance Registry Criteria 

(Revision 5.0) at 3 (October 16, 2008). See North American Electric Reliability Corp., 

125 FERC ¶ 61,057 (2008) (accepting revisions to NERC’s Registry Criteria). 

75 The Statement of Compliance Registry Criteria defines “transmission 

owner/operator” as: 

 III.d.1 An entity that owns or operates an integrated transmission 

element associated with the bulk power system 100 kV and 

above, or lower voltage as defined by the Regional Entity 

(continued...) 
Docket No. RM08-13-000 

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NERC acknowledges that there are facilities operated below 100 kV that are critical to 

the reliability of the bulk electric system. 

45. In Order No. 693, the Commission accepted the NERC definition of bulk electric 

system but expressed concern about the potential for gaps in coverage of facilities with 

regard to regional definitions.76 In the Commission’s view, NERC has failed to provide a 

sufficient technical record to justify the exemption of facilities operated below 100 kV 

that have been identified by the Regional Entity as necessary to the reliability of the bulk 

electric system. Consequently, the Commission proposes to direct the ERO to modify 

PRC-023-1 to make it applicable to facilities operated below 100 kV that are designated 

by the Regional Entity as critical to the reliability of the bulk electric system. The 

Commission understands that conforming modifications to the requirements of PRC-023-

1 will be necessary to reflect these proposals. The Commission requests comment on 

each of its proposals. 

 

necessary to provide for the reliable operation of the 

interconnected transmission grid; or 

III.d.2 An entity that owns/operates a transmission element below 

100 kV associated with a facility that is included on a critical 

facilities list defined by the Regional Entity. 

76 Order No. 693, FERC Stats. & Regs. ¶ 31,242, at P 77. 
Docket No. RM08-13-000 

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2. Generator Step-Up and Auxiliary Transformers

46. NERC states that generator step-up transformer relay loadability was intentionally 

omitted from PRC-023-1.77 NERC contends that generator step-up relay loadability 

merits particular attention in the area of generator protection, and therefore that it would 

be inappropriate to include it in a transmission relay loadability standard without 

consideration of the overall generator protective system in place. NERC claims that it is 

“imperative” that generator step–up transformer protection settings be coordinated with 

other generator protection functions as well as the associated local transmission system 

protection. 78 NERC states that this requires careful consideration of the transient, subtransient, and steady state generator responses to system conditions, and consideration of 

how the resultant loadings on the generator step-up factor into loadability.79 

47. NERC states that the Standard Drafting Team did not include technical experts 

from the generator industry. NERC explains that to include generation it would have had 

to identify and recruit additional experts, delaying the presentation of PRC-023-1 by six 

months. NERC states that generator protection standards for relay loadability will be 

addressed in future Reliability Standards. 

 77 NERC Petition at 38. 

78 Id. 

79 Id. 
Docket No. RM08-13-000 

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Commission Proposal

48. It is the Commission’s intention that the ERO address in a timely manner the 

reliability objectives relevant to relay loadability, which include generator step-up and 

auxiliary transformers. One way to ensure that this occurs is for the Commission to 

direct the ERO to modify the proposed Reliability Standard to address these issues. This 

approach also has the advantage of placing coordination between generator and 

transmission protection systems in the same Reliability Standard. Consequently, the 

Commission seeks comment on whether it should direct the ERO to modify the proposed 

Reliability Standard to address generator step-up and auxiliary transformer loadability, or 

whether generator step-up and auxiliary transformer loadability should be addressed in a 

separate Reliability Standard, as the ERO intends. The Commission also seeks comment 

as to what is a reasonable timeframe for developing a modification or separate Reliability 

Standard to address generator step-up and auxiliary transformer loadability. 

D. Need to Address Additional Issues

49. It is the Commission’s view that to ensure reliable operation of the system the 

ERO must address both the reach of zone 3/zone 2 relays applied as remote circuit 

breaker failure and backup protection, and issues related to load increases, overload, and 

stable power swings that occur under recognized system conditions.80 As proposed, 

PRC-023-1 addresses only issues related to load increases and overloads (loadability). 

 80 Like those issues addressed in Reliability Standards TPL-002-0, TPL-003-0, and 

TPL-004-0. 
Docket No. RM08-13-000 

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1. Zone 3/Zone 2 Relays Applied as Remote Circuit Breaker 

Failure and Backup Protection 

50. Typically, zone 3/zone 2 relays are 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. If zone 

3/zone 2 relays detect a fault on an adjacent transmission line in their reach, and the 

relays on the faulted line fail to operate, the zone 3/zone 2 relays will operate as backup 

and remove the fault. However, when they operate they will disconnect both the faulted 

transmission line and “healthy” facilities that should have remained in service. To ensure 

coordination of protection and avoid unnecessarily disconnecting “healthy” facilities, 

zone 3/zone 2 relays are typically set to operate after a time delay. 

51. The Task Force identified fourteen 345 kV and 138 kV transmission lines that 

disconnected during the 2003 blackout because of zone 3/zone 2 relays applied as remote 

circuit breaker failure and backup protection.81 Among the relays that operated 

unnecessarily were several zone 2 relays in Michigan that overreached their protected 

lines by more than 200 percent and operated without a time delay.82 The Task Force 

stated that although these and the other relays operated according to their settings, they 

 81 Final Blackout Report at 80. 

82 Id. 
Docket No. RM08-13-000 

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operated so quickly that they impeded the natural ability of the electric system to hold 

together and did not allow time for operators to try to stop the cascade.83 

Commission Proposal

52. The Commission is concerned that zone 3/zone 2 relays will operate because of 

line load or overload in extreme contingency conditions even in the absence of a fault.84 

The large setting of zone 3/zone 2 relays makes them susceptible to operating in the 

absence of a fault under abnormal system conditions. This is because under abnormal 

system conditions, such as very high loading and large, but stable power swings, the 

current and voltage as measured by the impedance relay may fall within the very large 

magnitude and phase setting of the relay. When this occurs, the relay is susceptible to 

operation. 

53. NERC states in its petition that PRC-023-1 is silent on the application of zone 

3/zone 2 relays as remote circuit breaker failure and backup protection because it 

establishes requirements for any load-responsive relay regardless of its protective 

function.85 However, given the Task Force’s conclusions about the role zone 3/zone 2 

played in the spread of the cascade in the 2003 blackout, it is the Commission’s view that 

the ERO should develop a maximum allowable relay reach for zone 3/zone 2 relays 

applied as remote circuit breaker failure and backup protection. The Commission seeks 

 83 Id. 

84 Id. 

85 NERC Petition at 39. 
Docket No. RM08-13-000 

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comment on whether it should direct the ERO to develop a maximum allowable reach, 

and if so, whether it should direct the ERO to develop a modification to PRC-023-1 or a 

new Reliability Standard. 

2. Protective Relays Operating Unnecessarily due to Stable Power 

Swings

54. Despite the loss of fourteen key transmission lines, the Task Force found that 

during the 2003 blackout the system did not become dynamically unstable until at least 

after the Hampton-Pontiac and Thetford-Jewell 345 kV lines disconnected.86 These lines 

disconnected in a phase of the cascade that was caused by dynamic, but stable power 

swings. 

55. 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 power swings can also occur when the system recovers from a 

disturbance and achieves transient stability (typically within a 0 - 3 second time frame) 

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 

 86 Final Blackout Report at 82-83. 
Docket No. RM08-13-000 

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stable operating condition, provided that the relays protecting “healthy” facilities have 

not operated unnecessarily because of the stable power swings. 

56. Each time zone 3/zone 2 relays operated and disconnected facilities because of 

high loading, the power flowing on the transmission system increased in magnitude and 

oscillated, i.e., “swung,” back and forth across a large portion of the interconnected 

systems around Lake Erie. Initially, with each swing the transmission system recovered 

and appeared to stabilize. However, as the power swings and oscillations increased in 

magnitude, zone 3/zone 2 and other relays measured levels of currents and voltages that, 

because of their settings, indicated a fault. Consequently, these relays operated 

unnecessarily and disconnected “healthy” transmission lines. As more “healthy” 

transmission lines were disconnected, power swings and oscillations increased in 

magnitude causing more “healthy” lines to disconnect, thus spreading the cascade. 

57. The proposed Reliability Standard does not address the unnecessary operation of 

protective relays due to stable power swings. NERC states that it did not address power 

swings in PRC-023-1 because the focus of the proposed Standard is on loadability at a 

time when operators can take action to protect the system.87 NERC states that during the 

2003 blackout the power swing time frame was too short for operators to act, which is 

typical for severe power swings.88 NERC states that in the electrical vicinity of severe 

 87 NERC Petition at 39. 

88 Id. 
Docket No. RM08-13-000 

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power swings, relays cannot distinguish power swings from faults that trigger their 

operation.89 

Commission Proposal

58. While zone 3/zone 2 relays operated during the 2003 blackout according to their 

settings and specifications, the inability of these relays to distinguish between a dynamic, 

but stable power swing and an actual fault contributed to the cascade. Because PRC-023-

1 addresses only the unnecessary operation of protective relays caused by high loading 

conditions, and does not address unnecessary operation caused by stable power swings, 

the Commission is concerned that relays set according to PRC-023-1 could still operate 

unnecessarily because of stable power swings. 

59. NERC states that in the electrical vicinity of severe power swings, relays cannot 

distinguish between stable power swings and actual faults. However, there are several 

protection applications and relays that are less susceptible to transient or dynamic power 

swings, including pilot wire differential, phase comparison, and blinder-blocking 

applications and relays, and impedance relays with non-circular operating 

characteristics.90 Each of these protection applications and relays uses existing 

technology and has been tested and applied effectively to mitigate relay susceptibility to 

power swings. 

 89 Id. 

90 Non-circular operating characteristics include, for example, off-set MHO, 

blinder, reactance, and lenticular operating characteristics that while still providing a long 

reach, are less susceptible to power swings. 
Docket No. RM08-13-000 

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60. Because the inability of protective relays to distinguish between actual faults and 

stable power swings contributed to the cascade in the 2003 blackout, and given the 

availability of protection applications and relays that can effectively mitigate this 

problem, it is the Commission’s view that the use of protective relay systems that cannot 

differentiate between faults and stable power swings constitutes mis-coordination of the 

protection system and is inconsistent with entities’ obligations under existing Reliability 

Standards.91 In the Commission’s view, a protective relay system that cannot refrain 

from operating under non-fault conditions because of a technological impediment is 

unable to achieve the performance required for reliable operation. Consequently, the 

Commission seeks comment on whether it should direct the ERO to develop a Reliability 

Standard or a modification that requires applicable entities to use protective relay systems 

that can differentiate between faults and stable power swings and phases out protective 

relay systems that cannot meet this requirement. The Commission may direct a 

Reliability Standard or a modification in response to these comments. 

E. Concerns with the Implementation of Certain Criteria under 

Requirement R1 

61. Requirement R1 establishes criteria (Requirements R1.1 through R1.13) to prevent 

phase protective relay settings from limiting transmission system loadability while 

 91 See supra P 31. As discussed previously, protective relay settings determined 

and applied in accordance with the requirements of PRC-023-1 must be included in 

determining system performance, System Operating Limits, and Interconnection 

Reliability Operating Limits, and must be coordinated with other protective relay settings 

as required by the applicable IRO, TOP, and TPL Reliability Standards. 
Docket No. RM08-13-000 

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maintaining reliable protection of the bulk electric system for all fault conditions. These 

criteria reflect the maximum circuit loading for the various system configurations and 

conditions and permit the relays to be set for optimum protection while carrying that 

load. The criterion to be used depends on the configuration and conditions in the system 

in which the protective relay will be applied. 

62. The Commission is concerned that some criteria established in Requirement R1 

might accommodate the use of protective relays for certain system configurations where 

the protective relays may not be appropriate or help achieve the reliability objective of 

the proposed Reliability Standard. In particular, the Commission is concerned with the 

implementation of criteria established by Requirements R1.2 (Transmission Line 

Established 15-Minute Rating), R1.10 (Transformer Overcurrent Protection), and R1.12 

(Long Line Relay Loadability). 

1. Requirement R1.2

63. Requirement R1.2 directs the transmission owner, generation owner, or 

distribution provider to set transmission line relays so that they do not operate at or below 

115 percent of the highest seasonal 15-minute Facility Rating of a circuit. A footnote 

attached to Requirement R1.2 provides that “[w]hen a 15-minute rating has been 

calculated and published for use in real-time operations, the 15-minute rating can be used 

to establish the loadability requirement for the protective relays.” 92 

 

(continued...) 

92 NERC states in its petition that it modified the footnote in response to 

Commission staff’s concern that 15-minute ratings may be used that are not completely 

reflected as facility ratings. The modification clarified that Requirement R1.2 references 
Docket No. RM08-13-000 

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Commission Proposal

64. The Commission is concerned that Requirement R1.2 might conflict with 

Requirement R4 of existing Reliability Standard TOP-004-1(Transmission Operations), 

which states that “if a transmission operator enters an unknown operating state, it will be 

considered to be in an emergency and shall restore operations to respect proven reliability 

power system limits within 30 minutes.”93 The Commission is concerned that the 

transmission operator (or any other reliability entity affected by the facility) might 

conclude that it has 30 minutes to restore the system to normal when in fact it has only 15 

minutes because the relay settings for certain transmission facilities have been set to 

operate at the 15-minute rating in accordance with Requirement R1.2. This may have an 

adverse impact on system reliability, since the operator might not take Requirement R1.2 

into consideration. 

65. To ensure the reliability of the Bulk-Power System, Reliability Standards PRC023-1 and TOP-004-1 should give a transmission operator the same amount of time to 

restore the system to normal operations. The Commission acknowledges that 

Requirement R1.2 references the “publishing” of a facility’s 15-minute rating; however, 

we are not persuaded that publication of a rating is sufficient to address the potential 

conflict. Consequently, the Commission proposes to direct the ERO to either revise 

 

15-minute ratings where such ratings have been calculated and are used for real-time 

operations. NERC Petition at 37. 

93 See Reliability Standard TOP-004-1, Requirement R4. 
Docket No. RM08-13-000 

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Requirement R1.2 to apply it to Reliability Standard TOP-004-1 or develop a new 

requirement that transmission owners, generation owners, and distribution providers give 

their transmission operators a list of transmission facilities that implement Requirement 

R1.2, or propose an equally effective and efficient approach to avoid the potential 

conflict. The Commission seeks comment on each of these proposals. 

2. Requirement R1.10 

66. Requirement R1.10 establishes criteria for applicable entities to set transformer 

fault protective relays and transmission line relays on transmission lines that terminate in 

a transformer. For this system configuration, protective relays would be set such that the 

transformer fault protective relays and transmission line relays do not operate at or below 

the greater of 150 percent of the applicable maximum transformer name-plate rating 

(expressed in amperes), including the forced cooled ratings corresponding to all installed 

supplemental cooling equipment, or 115 percent of the highest owner-established 

emergency transformer rating.94 

Commission Proposal 

67. The Commission understands that facility owners determine the ratings of their 

facilities based on a number of factors, and that they use verified methodologies to 

 94 NERC states that the Standard Drafting Team did not contain any experts on 

equipment ratings. NERC Petition at 31. 
Docket No. RM08-13-000 

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determine expected temperatures and other parameters needed to establish a rating.95 It is 

the Commission’s view, however, that overloading facilities at any time, but especially 

during system faults, could lower reliability and present a safety concern. 

68. The application of a transmission line terminated in a transformer enables the 

transmission owner to avoid installing a bus and local circuit breaker on both sides of the 

transformer. Protective relay settings implemented according to Requirement R1.10 for 

this topology would allow the transformer to be subjected to overloads higher than its 

established ratings for unspecified periods of time. Transformers that have been 

subjected to currents over their maximum rating have been recorded as failing violently 

and resulted in substantial fires. This negatively impacts reliability and raises safety 

concerns. While safety considerations are outside the jurisdiction of the Commission, 

requirements in a Reliability Standard should not be interpreted as requiring unsafe 

actions or designs. 

69. Consequently, the Commission proposes to direct the ERO to submit a 

modification that requires any entity that implements Requirement R1.10 to verify that 

the limiting piece of equipment is capable of sustaining the anticipated overload current 

for the longest clearing time associated with the fault from the facility owner. If the 

facility owner can not verify that ability, the facility owner should apply either different 

 95 The methodology for determining transformer ratings includes analysis of all 

aspects of the transformer, such as bushings, leads, stray flux heating, core heating, 

winding hot spots, and the formation of bubbles at those hot spots. 
Docket No. RM08-13-000 

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protection systems or change the topology to avoid this configuration to be in compliance 

with PRC-023-1. The Commission seeks comments on this proposal. 

3. Requirement R1.12

70. Requirement R1.12 establishes relay loadability criteria when the desired 

transmission line capability is limited by the requirement to adequately protect the 

transmission line. In these cases, the line distance relays are still required to provide 

adequate protection, but the implemented relay settings will limit the desired loading 

capability of the circuit. NERC states that in the event an essential fault protection 

imposes a more constraining limit on the system, the limit imposed by the fault protection 

is reflected within the facility rating.96

71. NERC claims that PRC-023-1 should cause no undue negative effect on 

competition or restrict the grid beyond what is necessary for reliability.97 It explains that, 

with the exception of those relays that legitimately define and restrict the facility rating, 

PRC-023-1 removes arbitrary limits related to relay loadability that cause transmission 

capability limitations. NERC further points out that no market-based entity is required to 

comply with PRC-023-1. 

Commission Proposal

72. The Commission is concerned that Requirement R1.12 allows entities to 

technically comply with PRC-023-1 but not achieve its stated purpose. Since protective 

 96 NERC Petition at 14. 

97 Id. at 27. 
Docket No. RM08-13-000 

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relay settings are allowed to limit the load carrying capability of a transmission line, that 

line is not being utilized to its full potential in response to sudden increases in line 

loadings or power swings, i.e., the natural response of the Bulk-Power System will be 

less robust in response to system disturbances. 

73. Entities subject to PRC-023-1 must employ a protection system that meets their 

reliability obligations, but a protection system that requires the application of 

Requirement R1.12 may not satisfy this requirement. Consequently, the Commission 

seeks comment on whether use of such a protection system is consistent with the 

reliability objectives of PRC-023-1, and whether the Commission should direct a 

modification that would require that entities that employ such a system use a different 

protection relay system that would meet the reliability objective of the Reliability 

Standard. 

F. Requirement R3 and its Sub-Requirements 

74. Requirement R3 requires planning coordinators to designate which transmission 

lines and transformers with low-voltage terminals operated or connected between 100 kV 

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

to Requirement R1. Sub-Requirements R3.1 and R3.1.1 specify that planning 

coordinators must determine these facilities through a process that considers input from 

adjoining planning coordinators and affected reliability coordinators. Sub-Requirements 

R3.2 and R3.3 require planning coordinators to maintain a list of designated facilities and 

provide it to reliability coordinators, transmission owners, generator owners, and 
Docket No. RM08-13-000 

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distribution providers within 30 days of its initial establishment, and within 30 days of 

any subsequent change. 

Commission Proposal

75. In light of the Commission’s proposal to direct the ERO to modify PRC-023-1 to 

make it applicable to all facilities operated at or above 100 kV, with the possibility of 

case-by-case exceptions, and to all facilities operated below 100 kV that are designated 

by the Regional Entity as critical to the reliability of the bulk electric system, the 

Commission proposes to direct the ERO to revise Requirement R3 and Sub-Requirement 

R3.2 to require that the planning coordinator maintain a list that reflects the 

Commission’s proposal. Moreover, it is Commission’s view that the Regional Entity 

should know which facilities in its area are subject to the Reliability Standard. 

Accordingly, the Commission proposes to direct the ERO to modify Requirement R3.3 to 

add the Regional Entity to the list of entities that receive the list as required by 

Requirement R3.2 

G. Attachment A 

76. Attachment A of PRC-023-1 contains three sections: (1) a list of examples of 

load-responsive relays subject to PRC-023-1, (2) a statement that out-of-step blocking 

protective schemes shall be evaluated to ensure that those applications do not block trip 

for fault during the loading conditions defined within the requirements of PRC-023-1, 

and (3) a list of Protective Systems that are excluded from the requirements of the PRC023-1. The Commission has concerns about sections (2) and (3). 
Docket No. RM08-13-000 

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 1. Section (2): Evaluation of Out-of-Step Blocking Schemes

77. Section (2) of Attachment A states that the “[S]tandard includes out-of-step 

blocking schemes which shall be evaluated to ensure that they do not block trip for fault 

during the loading conditions defined within the requirements.” This obligation, 

however, is not included as a requirement in the proposed Reliability Standard. Instead, 

it is included in Attachment A. Requirements should be in the requirements section of a 

Reliability Standard to ensure compliance. Since the ERO intends to require the 

evaluation of out-of-step blocking applications, language to this effect should be included 

as a requirement and not as a statement in an Attachment. Consequently, the 

Commission proposes to direct the ERO to modify PRC-023-1 by adding the statement in 

section (2) of Attachment A as an additional requirement with the appropriate violation 

risk factor and violation severity level assignments. 

2. Section (3): List of Protection Systems Excluded from the Standard

78. Section (3) lists certain protection systems that are excluded from the requirements 

of PRC-023-1. However, in its petition NERC does not provide a technical rationale for 

excluding any load-responsive phase protection systems from the requirements of PRC023-1. Thus, it is not clear to the Commission that the exclusions in section 3 are 

justified.98 

 98 The exclusion of protection systems intended for the detection of ground fault 

conditions appears to be unnecessary because these systems are not load-responsive. 
Docket No. RM08-13-000 

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79. For example, subsection 3.1 excludes from the requirements of PRC-023-1: 

(1) overcurrent elements that are enabled only during loss of potential conditions and 

(2) elements that are enabled only during a loss of communications. This subsection 

could be interpreted to exclude certain protection systems that use communications to 

compare current quantities and directions at both ends of a transmission line, such as pilot 

wire protection or current differential protection systems supervised by fault detector 

relays. The Commission understands that if supervising fault detector relays are 

excluded from PRC-023-1, and are set below the rating of the protected element, the loss 

of communications and heavy line loading conditions that approach the line rating would 

cause these protective relays to operate and unnecessarily disconnect the line. If adjacent 

transmission lines have similar protection systems and settings, those protection systems 

would also operate unnecessarily, resulting in cascading outages. 

80. The Commission seeks comment on whether the exclusions in section 3 are 

technically justifiable and whether the Commission should direct the ERO to modify 

PRC-023-1 by deleting specific subsections in section 3. The Commission also seeks 

comment on whether it should direct the ERO to modify subsection 3.1 to clarify that it 

does not exclude from the requirements of PRC-023-1 such protection systems as 

described above. 

81. The Commission also notes that subsection 3.5 excludes from the requirements of 

PRC-023-1 “relay elements used only for [s]pecial [p]rotection [s]ystems applied and 

approved in accordance with NERC Reliability Standards PRC-012 through PRC-017.” 

Since PRC-012-0, PRC-013-0 and PRC-014-0 are currently proposed Reliability 
Docket No. RM08-13-000 

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Standards pending with the Commission, subsection 3.5 is not enforceable until approved 

by the Commission.99

H. Effective Date 

82. NERC requests that PRC-023-1 be made effective consistent with the 

implementation plan accompanying the Reliability Standard. For Requirements R1 and 

R2, NERC proposes that transmission lines operated at 200 kV and above and 

transformers with low-voltage terminals connected at 200 kV and above (except switchon-to fault-schemes) be made effective on the beginning of the first calendar quarter 

following applicable regulatory approvals. For transmission lines operated between 100 

kV and 200 kV and transformers with low-voltage terminals connected between 100 kV 

and 200 kV that are designated by planning coordinators as critical to the reliability of the 

bulk electric system (including switch-on-to fault-schemes) in order to prevent a cascade, 

NERC proposes an effective date of the beginning of the first calendar quarter 39 months 

after applicable regulatory approvals. NERC also proposes that each transmission owner, 

generator owner, and distribution provider have 24 months from notification by the 

planning coordinator that a facility has been added to the planning coordinator’s critical 

facilities list (pursuant to Requirement R.3.3) to comply with R1 and its subrequirements. For Requirement R3, NERC proposes an effective date of 18 months 

following applicable regulatory approvals. 

 99 Order No. 693-A, FERC Stats. & Regs. ¶ 31,242 at P 138. 
Docket No. RM08-13-000 

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83. NERC also proposes to include a footnote to the “Effective Dates” section that 

states that entities that have received temporary exceptions approved by the NERC 

Planning Committee (via the NERC System and Protection and Control Task Force) 

before approval of the proposed Reliability Standard shall not be found in noncompliance with the Reliability Standard or receive sanctions if: (1) the approved 

requests for temporary exceptions include a mitigation plan (including schedule) to come 

into full compliance and (2) the non-conforming relay settings are mitigated according to 

the approved mitigation plan.100 

84. NERC contends this implementation plan presents a reasonable time frame to 

allow all entities to be in compliance. NERC states that the technical requirements of 

PRC-023-1 have been implemented by most applicable entities starting in January 2005 

under voluntary activities directed by the NERC Planning Committee and that most 

entities have provided assurances to NERC that they have implemented these technical 

requirements. NERC states that the implementation period established in the 

implementation plan provides an opportunity for those entities that did not participate in 

 100 The footnote states: 

Temporary Exceptions that have already been approved by the NERC 

Planning Committee via the NERC System and Protection and Control 

Task Force prior to the approval of this [Reliability] [S]tandard shall not 

result in either findings of non-compliance or sanctions if all of the 

following apply: (1) the approved requests for Temporary Exceptions 

include a mitigation plan (including schedule) to come into full compliance, 

and (2) the non-conforming relay settings are mitigated according to the 

approved mitigation plan. 
Docket No. RM08-13-000 

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the voluntary activities to comply with PRC-023-1, and for all entities to establish the 

documentation necessary to demonstrate compliance. 

Commission Proposal 

85. The Commission proposes to approve the implementation plan as it relates to 

facilities operated at 200 kV and above. In light of the Commission’s proposal to direct 

the ERO to modify PRC-023-1 to make it applicable to all facilities operated at or above 

100 kV, with the possibility of case-by-case exceptions, and to all facilities operated 

below 100 kV that are designated by the Regional Entity as critical to the reliability of the 

bulk electric system, the Commission proposes an effective date of 18 months following 

applicable regulatory approvals for facilities operated below 200 kV. The Commission 

seeks comment on these proposals. 

86. The Commission proposes not to approve the temporary exemption of certain 

entities from enforcement actions while they come into compliance with PRC-023-1’s 

requirements. In the Commission’s view, it is best that discussions about potential 

enforcement actions are left out of a Reliability Standard and instead handled by NERC’s 

compliance and enforcement program. Consequently, the Commission proposes to direct 

the ERO to modify PRC-023-1 by removing the footnote. 

I. Violation Risk Factors

87. As part of its compliance and enforcement program, NERC assigns a low, 

medium, or high violation risk factor to each requirement of each mandatory Reliability 

Standard to associate a violation of the requirement with its potential impact on the 

reliability of the Bulk-Power System. Violation risk factors are defined as follows: 
Docket No. RM08-13-000 

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High Risk Requirement: (a) is a requirement that, if violated, 

could directly cause or contribute to Bulk-Power System 

instability, separation, or a cascading sequence of failures, or 

could place the Bulk-Power System at an unacceptable risk of 

instability, separation, or cascading failures; or (b) is a 

requirement in a planning time frame that, if violated, could, 

under emergency, abnormal, or restorative conditions 

anticipated by the preparations, directly cause or contribute to 

Bulk-Power System instability, separation, or a cascading 

sequence of failures, or could place the Bulk-Power System 

at an unacceptable risk of instability, separation, or cascading 

failures, or could hinder restoration to a normal condition. 

Medium Risk Requirement: (a) is a requirement that, if 

violated, could directly affect the electrical state or the 

capability of the Bulk-Power System, or the ability to 

effectively monitor and control the Bulk-Power System, but is 

unlikely to lead to Bulk-Power System instability, separation, 

or cascading failures; or (b) is a requirement in a planning 

time frame that, if violated, could, under emergency, 

abnormal, or restorative conditions anticipated by the 

preparations, directly affect the electrical state or capability of 

the Bulk-Power System, or the ability to effectively monitor, 

control, or restore the Bulk-Power System, but is unlikely, 

under emergency, abnormal, or restoration conditions 

anticipated by the preparations, to lead to Bulk-Power System 

instability, separation, or cascading failures, nor to hinder 

restoration to a normal condition. 

Lower Risk Requirement: is administrative in nature and 

(a) is a requirement that, if violated, would not be expected to 

affect the electrical state or capability of the Bulk-Power 

System, or the ability to effectively monitor and control the 

Bulk-Power System; or (b) is a requirement in a planning 

time frame that, if violated, would not, under the emergency, 

abnormal, or restorative conditions anticipated by the 

preparations, be expected to affect the electrical state or 

capability of the Bulk-Power System, or the ability to 

effectively monitor, control, or restore the Bulk-Power 

System.[101] 

 101 Violation Risk Factor Order, 119 FERC ¶ 61,145 at P 9. 
Docket No. RM08-13-000 

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88. In the Violation Risk Factor Order, the Commission addressed violation risk 

factors filed by NERC for Version 0 and Version 1 Reliability Standards. In that order, 

the Commission used five guidelines for evaluating the validity of each violation risk 

factor assignment: (1) consistency with the conclusions of the Final Blackout Report; 

(2) consistency within a Reliability Standard; (3) consistency among Reliability 

Standards with similar Requirements; (4) consistency with NERC’s proposed definition 

of the violation risk factor level; and (5) assignment of violation risk factor levels to those 

requirements in certain Reliability Standards that co-mingle a higher risk reliability 

objective and a lower risk reliability objective.102 

89. In its petition, NERC assigned violation risk factors only to the main requirements 

of the proposed Reliability Standard and did not assign violation risk factors to any of the 

sub-requirements.103 NERC assigns Requirement R1 a high violation risk factor, 

Requirement R2 a medium violation risk factor, and Requirement R3 a medium violation 

risk factor. 

90. As an initial matter, NERC’s compliance and enforcement program requires it to 

assign a violation risk factor to each sub-requirement of a proposed Reliability Standard. 

 102 For a complete discussion of each guideline, see id. P 19-36. 

103 We note that, in Version Two Facilities Design, Connections and Maintenance 

Reliability Standards, Order No. 722, 126 FERC ¶ 61,255 at P 45 (2009), the ERO 

proposed to develop violation risk factors and violation severity levels for Requirements 

but not sub-requirements. The Commission denied the proposal as “premature” and, 

instead, encouraged the ERO to “develop a new and comprehensive approach that would 

better facilitate the assignment of violation severity levels and violation risk factors.” 
Docket No. RM08-13-000 

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In addition, the Violation Severity Level Order stated that each requirement assigned a 

violation risk factor also must be assigned at least one violation severity level.104 As set 

forth in the NERC’s Sanction Guidelines, the intersection of these two factors is the first 

step in the determination of a monetary penalty for a violation of a requirement of a 

Reliability Standard. Therefore, consistent with Commission precedent and NERC’s 

Sanction Guidelines, each requirement must have a violation risk factor and violation 

severity level assignment. 

1. Requirement R1 and its Sub-Requirements 

91. Requirement R1 establishes criteria (sub-Requirements R1.1 – R1.13) to prevent 

phase protective relay settings from limiting transmission system loadability while 

maintaining reliable protection of the bulk electric system for all fault conditions.105 

NERC assigns Requirement R1 a high violation risk factor. The Commission agrees that 

Requirement R1 should be assigned a high violation risk factor because a violation of 

Requirement R1 has the potential to cause cascading outages like those that occurred 

during the 2003 blackout. NERC did not assign violation risk factors to subRequirements R1.1through R1.13. 

 104 Violation Severity Level Order, 123 FERC ¶ 61,284 at P 3. 

105 Requirement R1 also requires each transmission owner, generator owner, and 

distribution provider to evaluate relay loadability at 0.85 per unit voltage and a power 

factor angle of 30 degrees. 
Docket No. RM08-13-000 

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Commission Proposal

92. The Commission agrees that Requirement R1 should be assigned a high violation 

risk factor because a violation of Requirement R1 has the potential to cause cascading 

outages like those that occurred during the 2003 blackout. It is the Commission’s view 

that because the sub-requirements in Requirement R1 set forth criteria for compliance 

with Requirement R1, the reliability risk of a violation of any one of the subrequirements is the same as with a violation of Requirement R1. Therefore, consistent 

with the high violation risk factor assigned to Requirement R1, the Commission proposes 

to direct the ERO to assign a high violation risk factor to each of the sub-Requirements 

R1.1 through R1.13. The Commission seeks comment on this proposal. 

2. Requirement R3

93. Requirement R3 requires planning coordinators to designate which transmission 

lines and transformers with low-voltage terminals operated or connected between 100 kV 

and 200 kV are critical to the reliability of the bulk electric system in order to prevent a 

cascade and therefore should be subject to Requirement R1. NERC assigns Requirement 

R3 a medium violation risk factor. 

Commission Proposal

94. In light of the Commission’s proposal to direct the ERO to modify Requirement 

R3 and its sub-requirements, the Commission proposes to direct the ERO to assign a 

violation risk factor to the revised Requirement R3 and its revised sub-requirements that 

is consistent with the revisions and the Violation Risk Factor Guidelines. 
Docket No. RM08-13-000 

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J. Violation Severity Levels

95. For each requirement of a Reliability Standard, NERC states that it will also define 

up to four violation severity levels – lower, moderate, high and severe – as measurements 

of the degree to which the requirement was violated. For a specific violation of a 

particular requirement, NERC or the Regional Entity will establish the initial value range 

for the base penalty amount by finding the intersection of the applicable violation risk 

factor and violation severity level in the Base Penalty Amount Table in Appendix A of 

the Sanction Guidelines.106 

96. In the Violation Severity Level Order, the Commission addressed violation severity 

level assignments filed by NERC for the 83 Reliability Standards approved in Order No. 

693. In that order, the Commission developed four guidelines for evaluating violation 

severity levels filed by NERC: (1) violation severity level assignments should not have 

the unintended consequence of lowering the current level of compliance; (2) violation 

severity level assignments should ensure uniformity and consistency among all approved 

Reliability Standards in the determination of penalties; (3) violation severity level 

assignments should be consistent with the corresponding requirement; and (4) violation 

 106 See North American Electric Reliability Corp., 119 FERC ¶ 61,248 at P 74, 

order on clarification, 120 FERC ¶ 61,239 (2007) (directing NERC to develop up to four 

violation severity levels (lower, moderate, high, and severe) as measurements of the 

degree of a violation for each requirement and sub-requirement of a Reliability Standard 

and submit a compliance filing by March 1, 2008.). 
Docket No. RM08-13-000 

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severity level assignments should be based on a single violation, not on a cumulative 

number of violations.107 

97. In its petition, NERC proposes violation severity levels for Requirements R1, R2, 

and R3. NERC did not propose violation severity levels for sub-Requirements R1.1 

through R1.13 and R3.1 through R3.3. 

98. The Commission is concerned that the violation severity levels assigned to 

Requirements R1 and R2 may not be consistent with certain guidelines set forth in the 

Violation Severity Level Order. Moreover, NERC did not propose violation severity 

levels for any sub-requirements. As discussed previously, each requirement that is 

assigned a violation risk factor must also be assigned at least one violation severity level. 

Accordingly, the Commission proposes to direct the ERO to revise violation severity 

levels assigned to Requirements R1 and R2 as well as, to submit violation severity levels 

for sub-Requirements R1.1 through R1.13 that are consistent with the guidelines set forth 

in the Violation Severity Order as discussed below. 

1. Requirement R1

99. Requirement R1 and sub-Requirements R1.1 through R1.13 establish criteria to be 

used for setting phase protective relays. NERC proposes violation severity levels that 

assigns a “moderate” severity for a violation when the applicable entity complied with 

the criteria, but its evidence of compliance is incomplete or incorrect for one or more of 

 107 For a complete discussion of each guideline, see the Violation Severity Level 

Order, 123 FERC ¶ 61,284 at P 19–36. 
Docket No. RM08-13-000 

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the criteria and a “severe” violation when the relays settings do not comply with any of 

the criteria or evidence does not exist to support compliance with any one of the criteria. 

Commission Proposal

100. It is the Commission’s view that the violation severity levels NERC assigns to 

Requirement R1 combines the degree or severity of a violation of the Requirement (e.g., 

the relay settings do not comply with any of the sub-requirements) with an outcome with 

regard to determining compliance with the Requirement (e.g., evidence that the relay 

settings comply with the sub-requirements). For example, Guideline 3 ensures that 

assigned violation severity levels are consistent with the corresponding requirement i.e., 

the degrees of non-compliance are based on the text of the requirement. The text of 

Requirement R1 does not explicitly state that the applicable entity have evidence that the 

relay settings comply with the criteria set forth in the sub-Requirements R1.1 through 

R1.13; only that the applicable entity use criteria. The Commission believes that having 

evidence of that the relay settings comply with the criteria is an outcome that is expected 

with compliance with the Requirement. This is consistent with NERC’s description of a 

requirement’s “Measure” and not indicative of the degree to which the Requirement was 

violated.108 As such, since the text of the assigned violation severity level as it is not 

consistent with the corresponding requirement, the assigned violation severity levels are 

not consistent with Guideline 3. 

 108 NERC Reliability Standards Development Procedure, see descriptions of 

“Measure” and “Violation Severity Level.” 
Docket No. RM08-13-000 

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101. The Commission believes that violation severity levels for Requirement R1 and its 

sub-requirements could be assigned applying a binary approach; i.e., either an entity 

applied the criteria or it did not. Consistent with the binary approach, a single violation 

severity level assignment for Requirement R1 and single violation severity level for each 

of the sub-Requirements R1.1 through R1.13 is appropriate. Therefore, the Commission 

proposes to direct the ERO to assign a single violation severity level to Requirement R1 

and a single violation severity level to each of the sub-Requirements R1.1 through R1.13, 

consistent with its Guideline 2a compliance filing in Docket No. RR08-4-004 and seeks 

comment on this proposal.109 

2. Requirement R2

102. Requirement R2 states that transmission owners, generator owners, and 

distribution providers that use a circuit with the protective relays settings determined by 

the practical limitations described in sub-Requirements R1.6 through R1.9, R1.12, or 

R1.13 must use the calculated circuit capability as the circuit’s Facility Rating and must 

obtain the agreement of the planning coordinator, transmission operator, and reliability 

coordinator with the calculated circuit capability. NERC designates the Requirement as a 

binary requirement and assigns a “lower” violation severity level if an applicable entity 

uses the criteria described in sub-Requirements R1.6 through R1.9, R1.12, or R1.13, but 

evidence does not exist that the required agreement was obtained. 

 109 In its Guideline 2a compliance filing in Docket No. RR08-4-004 currently 

before the Commission, NERC proposes to assign the single violation severity level for 

binary Requirements to the “severe” category. 
Docket No. RM08-13-000 

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Commission Proposal

103. It is the Commission’s view that the violation severity level NERC assigns to 

Requirement R2 does not reflect the degree or severity of a violation of the requirement, 

but rather describes an outcome with regard to determining compliance with the 

requirement. As discussed previously, Guideline 3 ensures that assigned violation 

severity levels are consistent with the corresponding requirement. The text of 

Requirement R2 does not explicitly state that the applicable entity have evidence of the 

agreement; only that agreement is obtained. While the Commission agrees that 

Requirement R2 is a binary requirement, the Commission disagrees with the text of the 

assigned violation severity level as it is not consistent with the corresponding 

requirement, and thus not consistent with Guideline 3. As such, the Commission 

proposes that the single violation severity level assigned to Requirement R2 should be for 

the failure of the applicable entity that used the described criteria to calculate circuit 

capability as the Facility rating to obtain agreement on that rating with the required 

entities. The Commission seeks comment on this proposal. 

104. Also, the Commission points out that the single violation severity level NERC 

assigns to this binary requirement appears to be inconsistent with NERC’s Guideline 2a 

compliance filing in Docket No. RR08-4-004. In that docket, NERC assigns the single 

violation severity level for binary requirements to the “severe” category. Here, it assigns 

the single violation severity level to the “lower” category. Consistent with Guideline 2a 

of the Violation Severity Level Order, the Commission expects the single violation 

severity level assigned to binary requirements to be consistent. Consequently, the 
Docket No. RM08-13-000 

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Commission proposes to direct the ERO to revise the violation severity level it assigns to 

Requirement R2 to be consistent with Guideline 2a. 

3. Requirement R3

105. Requirement R3 requires planning coordinators to designate which transmission 

lines and transformers with low-voltage terminals operated or connected between 100 kV 

and 200 kV are critical to the reliability of the bulk electric system in order to prevent a 

cascade and therefore subject to Requirement R1. Sub-Requirements R3.1 and R3.1.1 

specify that planning coordinators must have a process to determine those facilities and 

that this process must consider input from adjoining planning coordinators and affected 

reliability coordinators. Sub-Requirements R3.2 and R3.3 require planning coordinators 

to maintain a list of designated facilities and provide it to reliability coordinators, 

transmission owners, generator owners, and distribution providers within 30 days of its 

initial establishment, and within 30 days of any subsequent change. NERC proposes a 

“severe” violation severity level when the applicable entity has neither a process to 

determine facilities that are critical to the reliability of the bulk-electric system nor a 

current list of critical facilities, and “moderate” and “high” violation severity levels based 

on the number of days that a planning coordinator is late in providing the list to the 

required entities. 

Commission Proposal

106. In light of the Commission’s proposal to direct the ERO to modify Requirement 

R3 and its sub-requirements, the Commission proposes to direct the ERO to assign a 

violation severity level to the revised Requirement R3 and its revised sub-requirements 
Docket No. RM08-13-000 

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that is consistent with the revisions and the guidelines set forth in the Violation Severity 

Level Order. 

Summary

107. Reliability Standard PRC-023-1 appears to be just, reasonable, not unduly 

discriminatory or preferential, and in the public interest. Accordingly, the Commission 

proposes to approve Reliability Standard PRC-023-1 as mandatory and enforceable. In 

proposing to approve PRC-023-1, the Commission emphasizes that (1) protective relay 

settings determined and applied in accordance with its requirements must be included in 

determining system performance, System Operating Limits and Interconnection 

Reliability Operating Limits, and must be coordinated with other protective relay settings 

as required by the applicable IRO, TOP, and TPL Reliability Standards and (2) the 

proposed Reliability Standard’s requirements govern all relays subject to the proposed 

Reliability Standard applied to protect, in any capacity, the applicable facilities defined in 

the proposed Reliability Standard. 

108. In addition, the Commission proposes to direct the ERO to address specific 

concerns and revise violation risk factors and violation severity levels assignments of the 

Reliability Standard as discussed above applying the guidelines set forth in the Violation 

Risk Factor Order and Violation Severity Order 90 days before the effective date of the 

Reliability Standard. 
Docket No. RM08-13-000 

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IV. Information Collection Statement 

109. The Office of Management and Budget (OMB) regulations require approval of 

certain information collection requirements imposed by agency rules.110 Upon approval 

of a collection(s) of information, OMB will assign an OMB control number and an 

expiration date. Respondents subject to the filing requirements of this rule will not be 

penalized for failing to respond to these collections of information unless the collections 

of information display a valid OMB control number. The Paperwork Reduction Act 

(PRA)111 requires each federal agency to seek and obtain OMB approval before 

undertaking a collection of information directed to ten or more persons, or continuing a 

collection for which OMB approval and validity of the control number are about to 

expire.112

110. The Commission is submitting these reporting and recordkeeping requirements to 

OMB for its review and approval under section 3507(d) of the PRA. Comments are 

solicited on the Commission’s need for this information, whether the information will 

have practical utility, the accuracy of provided burden estimates, ways to enhance the 

quality, utility, and clarity of the information to be collected, and any suggested methods 

for minimizing the respondent’s burden, including the use of automated information 

techniques.

 110 5 CFR 1320.11. 

111 44 U.S.C. 3501-20. 

112 44 U.S.C. 3502(3)(A)(i), 44 U.S.C. 3507(a)(3). 
Docket No. RM08-13-000 

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111. This NOPR proposes to approve one new Reliability Standard developed by 

NERC as the ERO. Section 215 of the FPA authorizes the ERO to develop Reliability 

Standards to provide for the operation of the Bulk-Power System. Pursuant to the statute, 

the ERO must submit to the Commission for approval each Reliability Standard that it 

proposes to be made effective.113 

112. Proposed Reliability Standard PRC-023-1 does not require responsible entities to 

file information with the Commission. However, the Reliability Standard requires 

applicable entities to develop and maintain certain information, subject to audit by a 

Regional Entity. In particular, transmission owners, generator owners and distribution 

providers must “have evidence” to show that each of its transmission relays are set 

according to the one of the criteria in Requirement R1 of the Reliability Standard.114 In 

certain circumstances set forth in the Reliability Standard, transmission owners, generator 

owners and distribution providers must have evidence that a facility rating was agreed to 

by the relevant planning authority, transmission operator and reliability coordinator.115 

Further, planning coordinators must have (1) a documented process for the determination 

of facilities that are critical to bulk electric system reliability and (2) a current list of such 

facilities. 

 113 See 16 U.S.C. 824o(d). 

114 See Reliability Standard PRC-023-1, Measure M1. 

115 Id., Measure M2. 
Docket No. RM08-13-000 

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113. Public Reporting Burden: Our estimate below regarding the number of 

respondents is based on the NERC compliance registry as of March 3, 2009 and NERC’s 

July 30, 2008 Petition that is the subject of this proceeding. According to the NERC 

compliance registry, as of March 3, 2009, NERC has registered 568 distribution 

providers, 825 generator owners and 324 transmission owners. Further, NERC has 

registered 79 planning authorities. However, the Reliability Standard does not apply to 

all transmission owners, generator owners and distribution providers. Rather, the 

Reliability Standard applies to transmission owners, generator owners and distribution 

providers with load-response phase protection systems applied to transmission lines 

operated at 200 kV and above - and other criteria set forth in the Applicability section of 

the Standard, and as described in Attachment A of the Standard. Further, some entities 

are registered for multiple functions, so there is some overlap between the entities 

registered as distribution providers, transmission owners, and generator owners. Given 

these additional parameters, the Commission estimates that the Public Reporting burden 

for the requirements contained in the NOPR is as follows: 

Data Collection No. of 

Respondents 

No. of 

Responses 

Hours Per 

Respondent 

Total Annual 

Hours 

FERC-725G

Reporting: 

0 

Reporting: 

0 

M1 - TOs, GOs 

and DPs must 

“have evidence” 

to show that 

each of its 

transmission 

relays are set 

according to 

Requirement R1 

450 1 

Recordkeeping: 

100 

Recordkeeping:

 45,000 
Docket No. RM08-13-000 

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M2 – Certain Reporting: 0 Reporting: 0 

TOs, GOs and 

DPs must have 

evidence that a 

facility rating 

was agreed to by 

PA, TOP and 

RC 

166 1 

Recordkeeping: 

10 

Recordkeeping: 

1,660 

M3 - PC must 

document 

process for 

determining 

critical facilities 

and (2) a current 

list of such 

facilities 

79 1 175 13,825 

Total 60,485 

• Total Annual hours for Collection: (Reporting + recordkeeping )= 60,485hours. 

Information Collection Costs: The Commission seeks comments on the costs to comply 

with these requirements. It has projected the average annualized cost to be the total 

annual hours 

Recordkeeping = 60,485@ $40/hour = $_241,940______. 

Labor (file/record clerk @ $17 an hour + supervisory @ $23 an hour) 

• Total costs = $_241,940___. 

• Title: FERC-725-G Mandatory Reliability Standard for Transmission Relay 

Loadability 

• Action: Proposed Collection of Information 

• OMB Control No: [To be determined.] 

• Respondents: Business or other for profit, and/or not for profit institutions. 
Docket No. RM08-13-000 

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• Frequency of Responses: On Occasion 

• Necessity of the Information: The Transmission Relay Loadability Reliability 

Standard, if adopted, would implement the Congressional mandate of the Energy Policy 

Act of 2005 to develop mandatory and enforceable Reliability Standards to better ensure 

the reliability of the nation’s Bulk-Power System. Specifically, the proposed Reliability 

Standard would ensure that protective relays are set according to specific criteria to 

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

conditions, but do not limit transmission loadability or interfere with system operator’s 

ability to protect system reliability. 

• Internal review: The Commission has reviewed the requirements pertaining to the 

proposed Reliability Standard for the Bulk-Power System and determined that the 

proposed requirements are necessary to meet the statutory provisions of the Energy 

Policy Act of 2005. These requirements conform to the Commission’s plan for efficient 

information collection, communication and management within the energy industry. The 

Commission has assured itself, by means of internal review, that there is specific, 

objective support for the burden estimates associated with the information requirements. 

114. Interested persons may obtain information on the reporting requirements by 

contacting: Federal Energy Regulatory Commission, 888 First Street, N.E., Washington, 

D.C. 20426 [Attention: Michael Miller, Office of the Executive Director, Phone: 

(202) 502-8415, fax: (202) 273-0873, e-mail: michael.miller@ferc.gov]. Comments on 

the requirements of the proposed rule may also be sent to the Office of Information and 

Regulatory Affairs, Office of Management and Budget, Washington, D.C. 20503 
Docket No. RM08-13-000 

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[Attention: Desk Officer for the Federal Energy Regulatory Commission], e-mail: 

oira_submission@omb.eop.gov. 

V. Environmental Analysis

115. The Commission is required to prepare an Environmental Assessment or an 

Environmental Impact Statement for any action that may have a significant adverse effect 

on the human environment.116 The Commission has categorically excluded certain 

actions from this requirement as not having a significant effect on the human 

environment. The actions proposed here fall within the categorical exclusion in the 

Commission's regulations for rules that are clarifying, corrective or procedural, for 

information gathering, analysis, and dissemination.117 Accordingly, neither an 

environmental impact statement nor environmental assessment is required. 

VI. Regulatory Flexibility Act Analysis 

116. The Regulatory Flexibility Act of 1980 (RFA)118 generally requires a description 

and analysis of final rules that will have significant economic impact on a substantial 

number of small entities. Most of the entities, i.e., transmission owners, generator 

owners, distribution providers, and “planning coordinators,” or alternatively “planning 

 116 Order No. 486, Regulations Implementing the National Environmental Policy 

Act, 52 FR 47,897 (Dec. 17, 1987), FERC Stats. & Regs. ¶ 30,783 (1987). 

117 18 CFR 380.4(a)(5) (2008). 

118 5 U.S.C. 601-12. 
Docket No. RM08-13-000 

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authorities,” to which the requirements of this rule would apply do not fall within the 

definition of small entities.119 

117. As indicated above, based on available information regarding NERC’s compliance 

registry, approximately 525 entities will be responsible for compliance with the new 

Reliability Standard. The Commission certifies that the proposed Reliability Standard 

will not have a significant adverse impact on a substantial number of small entities. 

118. Based on this understanding, the Commission certifies that this rule will not have a 

significant economic impact on a substantial number of small entities. Accordingly, no 

regulatory flexibility analysis is required. 

VII. Comment Procedures

119. The Commission invites interested persons to submit comments on the matters and 

issues proposed in this notice to be adopted, including any related matters or alternative 

proposals that commenters may wish to discuss. Comments are due [Insert 30 days 

from publication in the FEDERAL REGISTER]. Comments must refer to Docket No. 

RM08-13-000, and must include the commenter's name, the organization they represent, 

if applicable, and their address in their comments. 

120. The Commission encourages comments to be filed electronically via the eFiling 

link on the Commission's web site at http://www.ferc.gov. The Commission accepts 

 119 The RFA definition of “small entity” refers to the definition provided in the 

Small Business Act (SBA), which defines a “small business concern” as a business that is 

independently owned and operated and that is not dominant in its field of operation. See

15 U.S.C. 632 (2006). According to the SBA, a small electric utility is defined as one 

that has a total electric output of less than four million MWh in the preceding year. 
Docket No. RM08-13-000 

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most standard word processing formats. Documents created electronically using word 

processing software should be filed in native applications or print-to-PDF format and not 

in a scanned format. Commenters filing electronically do not need to make a paper 

filing. 

121. Commenters that are not able to file comments electronically must send an 

original and 14 copies of their comments to: Federal Energy Regulatory Commission, 

Secretary of the Commission, 888 First Street N.E., Washington, DC, 20426. 

122. All comments will be placed in the Commission's public files and may be viewed, 

printed, or downloaded remotely as described in the Document Availability section 

below. Commenters on this proposal are not required to serve copies of their comments 

on other commenters. 

VIII. Document Availability

123. In addition to publishing the full text of this document in the Federal Register, the 

Commission provides all interested persons an opportunity to view and/or print the 

contents of this document via the Internet through FERC's Home Page 

(http://www.ferc.gov) and in FERC's Public Reference Room during normal business 

hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, N.E., Room 2A, 

Washington, D.C. 20426. 

124. From FERC's Home Page on the Internet, this information is available on 

eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft 

Word format for viewing, printing, and/or downloading. To access this document in 
Docket No. RM08-13-000 

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eLibrary, type the docket number excluding the last three digits of this document in the 

docket number field. 

125. User assistance is available for eLibrary and the FERC’s website during normal 

business hours from FERC Online Support at 202-502-6652 (toll free at 1-866-208-3676) 

or email at ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-

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

public.referenceroom@ferc.gov. 

List of subjects in 18 CFR Part 40 

Electric power, Reporting and recordkeeping requirements. 

By direction of the Commission. 

( S E A L ) 

Nathaniel J. Davis, Sr., 

Deputy Secretary.