Federal Register / Vol. 74, No. 101 / Thursday, May 28, 2009 / Proposed Rules 25461 

Washington, DC 20591 or by calling 

(202) 267–8783. Communications must 

identify both docket numbers for this 

notice. Persons interested in being 

placed on a mailing list for future 

NPRM’s should contact the FAA’s 

Office of Rulemaking, (202) 267–9677, 

to request a copy of Advisory Circular 

No. 11–2A, Notice of Proposed 

Rulemaking Distribution System, which 

describes the application procedure. 

The Proposal 

The FAA is considering an 

amendment to the Code of Federal 

Regulations (14 CFR Part 71), which 

would establish Class E airspace at the 

Quinhagak Airport, in Quinhagak, AK. 

The intended effect of this proposal is 

to create Class E airspace upward from 

700 ft. above the surface to contain 

Instrument Flight Rules (IFR) operations 

at the Quinhagak Airport, Quinhagak, 

AK. 

The FAA Instrument Flight 

Procedures Production and 

Maintenance Branch has created two 

new SIAPs for the Quinhagak Airport 

and one textual ODP. The SIAPs are (1) 

the Area Navigation (RNAV) Global 

Positioning System (GPS) Runway 

(RWY) 12, Original and (2) the RNAV 

(GPS) RWY 30, Original. Textual ODPs 

are unnamed and are published in the 

front of the U.S. Terminal Procedures 

for Alaska. Class E controlled airspace 

extending upward from 700 ft. above the 

surface in the Quinhagak Airport area 

would be established by this action. The 

proposed airspace is sufficient in size to 

contain aircraft executing the 

instrument procedures at the Quinhagak 

Airport, Quinhagak, AK. 

The area would be depicted on 

aeronautical charts for pilot reference. 

The coordinates for this airspace docket 

are based on North American Datum 83. 

The Class E airspace areas designated as 

700/1200 foot transition areas are 

published in paragraph 6005 in FAA 

Order 7400.9S, Airspace Designations 

and Reporting Points, signed October 3, 

2008, and effective October 31, 2008, 

which is incorporated by reference in 14 

CFR 71.1. The Class E airspace 

designations listed in this document 

would be published subsequently in the 

Order. 

The FAA has determined that this 

proposed regulation only involves an 

established body of technical 

regulations for which frequent and 

routine amendments are necessary to 

keep them operationally current. It, 

therefore—(1) Is not a ‘‘significant 

regulatory action’’ under Executive 

Order 12866; (2) is not a ‘‘significant 

rule’’ under DOT Regulatory Policies 

and Procedures (44 FR 11034; February 

26, 1979); and (3) does not warrant 

preparation of a regulatory evaluation as 

the anticipated impact is so minimal. 

Because this is a routine matter that will 

only affect air traffic procedures and air 

navigation, it is certified that this rule, 

when promulgated, will not have a 

significant economic impact on a 

substantial number of small entities 

under the criteria of the Regulatory 

Flexibility Act. 

The FAA’s authority to issue rules 

regarding aviation safety is found in 

Title 49 of the United States Code. 

Subtitle 1, Section 106 describes the 

authority of the FAA Administrator. 

Subtitle VII, Aviation Programs, 

describes in more detail the scope of the 

agency’s authority. 

This rulemaking is promulgated 

under the authority described in subtitle 

VII, part A, subpart 1, section 40103, 

Sovereignty and use of airspace. Under 

that section, the FAA is charged with 

prescribing regulations to ensure the 

safe and efficient use of the navigable 

airspace. This regulation is within the 

scope of that authority because it 

proposes to create Class E airspace 

sufficient in size to contain aircraft 

executing instrument procedures at the 

Quinhagak Airport, AK, and represents 

the FAA’s continuing effort to safely 

and efficiently use the navigable 

airspace. 

List of Subjects in 14 CFR Part 71 

Airspace, Incorporation by reference, 

Navigation (air). 

The Proposed Amendment 

In consideration of the foregoing, the 

Federal Aviation Administration 

proposes to amend 14 CFR part 71 as 

follows: 

PART 71—DESIGNATION OF CLASS A, 

CLASS B, CLASS C, CLASS D, AND 

CLASS E AIRSPACE AREAS; 

AIRWAYS; ROUTES; AND REPORTING 

POINTS 

1. The authority citation for 14 CFR 

part 71 continues to read as follows: 

Authority: 49 U.S.C. 106(g), 40103, 40113, 

40120; E.O. 10854, 24 FR 9565, 3 CFR, 1959– 

1963 Comp., p. 389. 

§ 71.1 [Amended] 

2. The incorporation by reference in 

14 CFR 71.1 of Federal Aviation 

Administration Order 7400.9S, Airspace 

Designations and Reporting Points, 

signed October 3, 2008, and effective 

October 31, 2008, is to be amended as 

follows: 

* * * * * 

Paragraph 6005 Class E Airspace Extending 

Upward from 700 Feet or More Above the 

Surface of the Earth. 

* * * * * 

AAL AK E5 Quinhagak, AK [New] 

Quinhagak, Quinhagak Airport, AK 

(Lat. 59°45′19′′ N., long. 161°50′43′′ W.). 

That airspace extending upward from 700 

feet above the surface within a 6.4-mile 

radius of the Quinhagak Airport, AK. 

* * * * * 

Issued in Anchorage, AK, on May 19, 2009. 

Anthony M. Wylie, 

Manager, Alaska Flight Services Information 

Area Group. 

[FR Doc. E9–12408 Filed 5–27–09; 8:45 am] 

BILLING CODE 4910–13–P 

DEPARTMENT OF ENERGY 

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, DOE. 

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. 

DATES: Comments are due July 27, 2009. 

ADDRESSES: Interested persons may 

submit comments, identified by Docket 

25462 Federal Register / Vol. 74, No. 101 / Thursday, May 28, 2009 / Proposed Rules 

1 16 U.S.C. 824o. 

2Section 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). 

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, NE., Washington, DC 20426. 

FOR FURTHER INFORMATION CONTACT: 

Joshua Konecni (Legal Information), 

Office of the General Counsel, Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 

20426, (202) 502–6291. 

Michael Henry (Legal Information), 

Office of the General Counsel, Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 

20426, (202) 502–8532. 

Cynthia Pointer (Technical 

Information), Office of Electric 

Reliability, Division of Reliability 

Standards, Federal Energy Regulatory 

Commission, 888 First Street, NE., 

Washington, DC 20426, (202) 502– 

6069. 

Robert Snow (Technical Information), 

Office of Electric Reliability, Division 

of Reliability Standards, Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 

20426, (202) 502–6716. 

SUPPLEMENTARY INFORMATION: 

Table of Contents 

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 

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 

1. Pursuant to section 215 of the 

Federal Power Act (FPA),1 the Federal 

Energy Regulatory Commission 

(Commission) proposes to approve 

Reliability Standard PRC–023–1 

(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 

Federal Register / Vol. 74, No. 101 / Thursday, May 28, 2009 / Proposed Rules 25463 

3 In the context of the proposed Reliability 

Standard, ‘‘loadability’’ refers to the ability of 

protective relays to refrain from operating under 

load conditions. 

4The 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 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). 

6A ‘‘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. 

9By 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. 

10There 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. 

11A ‘‘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 specified 

order to minimize customer service interruption 

and power system isolation due to a power system 

disturbance.’’ 

13The ‘‘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. 

15The margin takes into account measurement 

errors of the relay, imprecise line impedance used 

in the relay setting calculation, and changes in 

system conditions. 

16For 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. 

17System planning analysis would identify the 

performance, required by Table 1 of the 

Transmission Planning (TPL) Reliability Standards. 

18 James S. Thorp, Power Systems Engineering 

Research Center, The Protection System in Bulk 

Power Networks 5 (2003). 

from all fault conditions, but do not 

limit transmission loadability 3 or 

interfere with system operators’ ability 

to protect system reliability.4 In 

addition, 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

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 breaker) 11 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 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 

line 14 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 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

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 

25464 Federal Register / Vol. 74, No. 101 / Thursday, May 28, 2009 / Proposed Rules 

19U.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/indus-act/blackout.asp. 

20 Id. at 80. 

21 Id. at 73. 

22 Id. at 80. 

23 Id. 

24 Id. 

25 Id. at 81. 

26August 14, 2003 Blackout: NERC Actions to 

Prevent and Mitigate the Impacts of Future 

Cascading Blackouts 13 (2004) (NERC Report). 

27Final Blackout Report at 158. 

28As 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. 

30See PRC–023–1 Attachment A, Item 1. 

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 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 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. 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 load-responsive 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. 

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 schemes 29 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 

Federal Register / Vol. 74, No. 101 / Thursday, May 28, 2009 / Proposed Rules 25465 

31The 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. 

32NERC 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. 

33Requirement 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. 

34The 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. 

35Special consideration must be made in 

computing the maximum power flow that 

protective relays must accommodate on seriescompensated 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. 

36Such cases exist due to some combination of 

weak sources, long lines, and the topology of the 

transmission system. 

37The 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). 

39Relay loadability must be evaluated at the relay 

trip point at 0.85 per unit voltage and a power 

factor angle of 30 degrees. 

susceptible to load, relay elements used 

only for special protection systems 

applied and approved in 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 low-voltage 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 criteria prescribed in subRequirements 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 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 threephase 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 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, subRequirement 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 Sub-Requirement 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 multi-terminal 

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 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 

25466 Federal Register / Vol. 74, No. 101 / Thursday, May 28, 2009 / Proposed Rules 

40The 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. 

41FAC–008–1 requires that transmission owners 

and generator owners have a Facility Ratings 

methodology. 

42FAC–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 postcontingency element conditions, and have 

mitigation plans to alleviate System Operating 

Limit or Interconnection Reliability Operating Limit 

violations. 

45TOP–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. 

46On 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. 

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

48 16 U.S.C. 824o(d)(4). 

49North 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). 

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 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 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. 

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 non-compliance 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 matter if the Commission 

considers such a modified Reliability 

Standard appropriate to carry out 

section 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 PRC–023–1 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 BulkVerDate Nov<24>2008 16:41 May 27, 2009 Jkt 217001 PO 00000 Frm 00008 Fmt 4702 Sfmt 4702 E:\FR\FM\28MYP1.SGM 28MYP1
Federal Register / Vol. 74, No. 101 / Thursday, May 28, 2009 / Proposed Rules 25467 

50For 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. 

51See 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.’’). 

52PRC–023–1, Requirement R1. 

53See TPL–002–0 and TPL–003–0 Reliability 

Standards, Requirements R1 and R2. 

54See TPL–002–0 through TPL–004–0, 

Requirement R1. 

55See 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). 

56North American Electric Reliability Corp., 119 

FERC ¶ 61,145, order on reh’g and compliance 

filing, 120 FERC ¶ 61,145 (2007) (Violation Risk 

Factor Order). 

57North American Electric Reliability 

Corporation, 123 FERC ¶ 61,284, order on reh’g and 

compliance filing, 125 FERC ¶ 61,212 (2008) 

(Violation Severity Level Order). 

58Section 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. 

Power 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 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 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 PRC–023–1 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 Order 56 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 loadresponsive phase 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: (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 step-up 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 subrequirements 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 

25468 Federal Register / Vol. 74, No. 101 / Thursday, May 28, 2009 / Proposed Rules 

59NERC Petition at 19, 41. 

60 Id. at 19. 

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 consideration of the effects 

of protective relay operation in one Region upon the 

behavior of facilities in the adjoining Region. 

65U.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. 

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 re-do 

their identification process for Critical Assets. 

67NERC Report at 13. 

68Final Blackout Report at 158. 

69NERC Petition at 23. 

70 Id. 

71See 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 dispatches, topologies, and 

maintenance outages, and would consider the effect 

of redundant and backup protection systems. 

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 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

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 ‘‘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, load-responsive 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 

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 believes that such an 

assessment would ensure that for all 

operating configurations, the bulk 

electric system facilities subject to the 

proposed Reliability Standard would 

have the 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. 

Federal Register / Vol. 74, No. 101 / Thursday, May 28, 2009 / Proposed Rules 25469 

72NERC 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 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. 

73NERC 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). 

75The 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 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. 

76Order No. 693, FERC Stats. & Regs. ¶ 31,242, 

at P 77. 

77NERC Petition at 38. 

78 Id. 

79 Id. 

80Like those issues addressed in Reliability 

Standards TPL–002–0, TPL–003–0, and TPL–004–0. 

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. 

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 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, 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. 

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 stepup 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, sub-transient, 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. 

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). 

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 

25470 Federal Register / Vol. 74, No. 101 / Thursday, May 28, 2009 / Proposed Rules 

81Final Blackout Report at 80. 

82 Id. 

83 Id. 

84 Id. 

85NERC Petition at 39. 86Final Blackout Report at 82–83. 

87NERC Petition at 39. 

88 Id. 

89 Id. 

90Non-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. 

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 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 

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 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 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 noncircular operating characteristics.90

Each of these protection applications 

and relays uses existing technology and 

has been tested and applied effectively 

Federal Register / Vol. 74, No. 101 / Thursday, May 28, 2009 / Proposed Rules 25471 

91See 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. 

92NERC 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 15-minute ratings where such ratings 

have been calculated and are used for real-time 

operations. NERC Petition at 37. 

93See Reliability Standard TOP–004–1, 

Requirement R4. 

94NERC states that the Standard Drafting Team 

did not contain any experts on equipment ratings. 

NERC Petition at 31. 

95The 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. 

to mitigate relay susceptibility to power 

swings. 

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 miscoordination 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 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 realtime operations, the 15-minute rating 

can be used to establish the loadability 

requirement for the protective relays.’’ 92

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 PRC–023–1 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 

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 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 

25472 Federal Register / Vol. 74, No. 101 / Thursday, May 28, 2009 / Proposed Rules 

96NERC Petition at 14. 

97 Id. at 27. 

98The exclusion of protection systems intended 

for the detection of ground fault conditions appears 

to be unnecessary because these systems are not 

load-responsive. 

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 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 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 SubRequirements 

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 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 SubRequirement R3.2 to require that the 

planning coordinator maintain a list that 

reflects the Commission’s proposal. 

Moreover, it is the 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 PRC–023–1. The 

Commission has concerns about 

sections (2) and (3). 

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 PRC– 

023–1. Thus, it is not clear to the 

Commission that the exclusions in 

section 3 are justified.98

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 

Federal Register / Vol. 74, No. 101 / Thursday, May 28, 2009 / Proposed Rules 25473 

99Order No. 693–A, FERC Stats. & Regs. ¶ 31,242 

at P 138. 

100The 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 noncompliance 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. 

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 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 lowvoltage terminals connected at 200 kV 

and above (except switch-on-to faultschemes) 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 R3.3) to 

comply with R1 and its subrequirements. For Requirement R3, 

NERC proposes an effective date of 18 

months following applicable regulatory 

approvals. 

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 non-compliance 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 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: 

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 BulkPower 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 BulkPower 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 BulkPower System, but is unlikely to lead to 

Bulk-Power System instability, separation, or 

25474 Federal Register / Vol. 74, No. 101 / Thursday, May 28, 2009 / Proposed Rules 

101 Violation Risk Factor Order, 119 FERC 

¶ 61,145 at P 9. 

102For a complete discussion of each guideline, 

see id. P 19–36. 

103We 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.’’ 

104 Violation Severity Level Order, 123 FERC 

¶ 61,284 at P 3. 

105Requirement 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. 

106See 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 subrequirement of a Reliability Standard and submit a 

compliance filing by March 1, 2008.). 

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 BulkPower 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

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 comingle 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 subrequirements.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. 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 SubRequirements 

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 sub-Requirements R1.1 

through R1.13. 

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 sub-requirements 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 subrequirements, 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. 

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 severity level assignments 

should be based on a single violation, 

Federal Register / Vol. 74, No. 101 / Thursday, May 28, 2009 / Proposed Rules 25475 

107For a complete discussion of each guideline, 

see the Violation Severity Level Order, 123 FERC 

¶ 61,284 at P 19–36. 

108NERC Reliability Standards Development 

Procedure, see descriptions of ‘‘Measure’’ and 

‘‘Violation Severity Level.’’ 

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. 

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 subrequirements. 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 subRequirements 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 subRequirements R1.1 through R1.13 

establish criteria to be used for setting 

phase protective relays. NERC proposes 

violation severity levels that assign 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 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 combine the 

degree or severity of a violation of the 

Requirement (e.g., the relay settings do 

not comply with any of the subrequirements) with an outcome with 

regard to determining compliance with 

the Requirement (e.g., evidence that the 

relay settings comply with the subrequirements). 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 subRequirements R1.1 through R1.13; only 

that the applicable entity use criteria. 

The Commission believes that having 

evidence 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. 

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 subRequirements 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. 

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 

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 

25476 Federal Register / Vol. 74, No. 101 / Thursday, May 28, 2009 / Proposed Rules 

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). 113See 16 U.S.C. 824o(d). 

114See Reliability Standard PRC–023–1, Measure 

M1. 

115 Id., Measure M2. 

affected reliability coordinators. SubRequirements 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 subrequirements, the Commission proposes 

to direct the ERO to assign a violation 

severity level to the revised 

Requirement R3 and its revised subrequirements 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 level 

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. 

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. 

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. 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 loadresponse 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: 

Federal Register / Vol. 74, No. 101 / Thursday, May 28, 2009 / Proposed Rules 25477 

116Order 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. 

119The 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. 

Data collection Number of 

respondents 

Number of 

responses Hours per respondent Total annual hours 

FERC–725G 

M1—TOs, GOs and DPs must ‘‘have evidence’’ to 

show that each of its transmission relays are set according to Requirement R1.

450 1 Reporting: 0 .......................

Recordkeeping: 100 ..........

Reporting: 0. 

Recordkeeping: 

45,000. 

M2—Certain TOs, GOs and DPs must have evidence 

that a facility rating was agreed to by PA, TOP and 

RC.

166 1 Reporting: 0 .......................

Recordkeeping: 10 ............

Reporting: 0. 

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) = 60,485 

hours. 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 = 

$l241,940 ll. 

Labor (file/record clerk @ $17 an hour 

+ supervisory @ $23 an hour) 

• Total costs = $_241,940 ll. 

• 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. 

• 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 BulkPower 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, NE., Washington, DC 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, DC 20503 [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 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 July 27, 2009. 

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 most standard 

word processing formats. Documents 

25478 Federal Register / Vol. 74, No. 101 / Thursday, May 28, 2009 / Proposed Rules 

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, NE., 

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 p.m. Eastern time) at 888 First 

Street, NE., Room 2A, Washington, DC 

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 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 Web site during 

normal business hours from FERC 

Online Support at 202–502–6652 (toll 

free at 1–866–208–3676) or e-mail 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. 

Nathaniel J. Davis, Sr., 

Deputy Secretary. 

[FR Doc. E9–12350 Filed 5–27–09; 8:45 am] 

BILLING CODE 6717–01–P