Federal Register / Vol. 77, No. 55 / Wednesday, March 21, 2012 / Rules and Regulations 16435 

necessary to keep them operationally 

current. Therefore, this regulation: (1) Is 

not a ‘‘significant regulatory action’’ 

under Executive Order 12866; (2) is not 

a ‘‘significant rule’’ under Department of 

Transportation (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. Since 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 I, 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 I, Section 

40103. Under that section, the FAA is 

charged with prescribing regulations to 

assign the use of the airspace necessary 

to ensure the safety of aircraft and the 

efficient use of airspace. This regulation 

is within the scope of that authority as 

it removes Domestic, Alaskan, and 

Hawaiian Reporting Points contained in 

the NAS. 

Environmental Review 

The FAA has determined that this 

action qualifies for categorical exclusion 

under the National Environmental 

Policy Act in accordance with 311a, 

FAA Order 1050.1E, ‘‘Environmental 

Impacts: Policies and Procedures.’’ This 

airspace action is not expected to cause 

any potentially significant 

environmental impacts, and no 

extraordinary circumstances exist that 

warrant preparation of an 

environmental assessment. 

List of Subjects in 14 CFR Part 71 

Airspace, Incorporation by reference, 

Navigation (air). 

Adoption of the Amendment 

In consideration of the foregoing, the 

Federal Aviation Administration 

amends 14 CFR part 71 as follows: 

PART 71—DESIGNATION OF CLASS A, 

B, C, D, AND E AIRSPACE AREAS; AIR 

TRAFFIC SERVICE ROUTES; AND 

REPORTING POINTS 

■ 1. The authority citation for 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 FAA Order 7400.9V, 

Airspace Designations and Reporting 

Points, signed August 9, 2011, and 

effective September 15, 2011, is 

amended as follows: 

Paragraph 7003 Other domestic reporting 

points. 

ABACO: [Removed] 

* * * * * 

ALLBA: [Removed] 

BACUS: [Removed] 

* * * * * 

BRIMS: [Removed] 

CARPS: [Removed] 

CATFI: [Removed] 

* * * * * 

CRABI: [Removed] 

* * * * * 

EARNS: [Removed] 

FLASH: [Removed] 

FLORI: [Removed] 

GATES: [Removed] 

* * * * * 

OHIOS: [Removed] 

* * * * * 

SMELT: [Removed] 

SQUID: [Removed] 

* * * * * 

Paragraph 7004 Alaskan low altitude 

reporting points. 

* * * * * 

NESSY: [Removed] 

* * * * * 

SAVRY: [Removed] 

* * * * * 

Paragraph 7005 Alaskan high altitude 

reporting points. 

* * * * * 

AUGIN: [Removed] 

* * * * * 

ENCOR: [Removed] 

* * * * * 

KILLA: [Removed] 

* * * * * 

NESSY: [Removed] 

* * * * * 

SAVRY: [Removed] 

* * * * * 

Paragraph 7006 Hawaiian reporting points. 

* * * * * 

SHILA: [Removed] 

* * * * * 

Issued in Washington, DC, March 12, 2012. 

Gary A. Norek, 

Acting Manager, Airspace, Regulations and 

ATC Procedures Group. 

[FR Doc. 2012–6744 Filed 3–20–12; 8:45 am] 

BILLING CODE 4910–13–P 

DEPARTMENT OF ENERGY 

Federal Energy Regulatory 

Commission 

18 CFR Parts 39 and 40 

[Docket No. RM11–16–000; Order No. 759] 

Transmission Relay Loadability 

Reliability Standard 

AGENCY: Federal Energy Regulatory 

Commission, Energy. 

ACTION: Final rule. 

SUMMARY: Pursuant to section 215 of the 

Federal Power Act, the Commission 

approves Reliability Standard PRC–023– 

2 (Transmission Relay Loadability) 

submitted by the North American 

Electric Reliability Corporation (NERC), 

the Electric Reliability Organization 

certified by the Commission. The 

Reliability Standard requires 

transmission owners, generation 

owners, and distribution providers to 

set load-responsive phase protective 

relays according to specific criteria to 

ensure that the relays reliably detect— 

and protect the electric network from— 

fault conditions, but do not limit 

transmission loadability or interfere 

with system operators’ ability to protect 

system reliability. The Commission also 

approves NERC Rules of Procedure 

Section 1700—Challenges to 

Determinations, which provides 

registered entities a means to challenge 

determinations made by planning 

coordinators under Reliability Standard 

PRC–023. 

DATES: Effective Date: This rule will 

become effective May 7, 2012. 

FOR FURTHER INFORMATION CONTACT: 

Kevin Ryan (Legal Information), Office 

of the General Counsel, Federal 

Energy Regulatory Commission, 888 

First Street NE., Washington, DC 

20426, (202) 502–6840. 

Kenneth U. Hubona (Technical 

Information), Office of Electric 

Reliability, Division of Reliability 

Standards, Federal Energy Regulatory 

Commission, 13511 Label Lane, Suite 

203, Hagerstown, MD 21740, (301) 

665–1608. 

SUPPLEMENTARY INFORMATION: 


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16436 Federal Register / Vol. 77, No. 55 / Wednesday, March 21, 2012 / Rules and Regulations 

1 16 U.S.C. 824o (2006). 

2 In the context of the proposed Reliability 

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

protective relays to refrain from operating under all 

permissible loading conditions on all applicable 

transmission lines and transformers. 

3A ‘‘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, broken wire, or an intermittent connection.’’ 

4Pursuant to section 40.3 of the Commission’s 

regulations, all Commission-approved Reliability 

Standards are available on NERC’s Web site at 

www.nerc.com. See 18 CFR 40.3. 

5Transmission Relay Loadability Reliability 

Standard, Order No. 733, 130 FERC ¶ 61,221 

(2010), order on reh’g and clarification, Order No. 

733–A, 134 FERC ¶ 61,127 (2011); clarified, Order 

No. 733–B, 136 FERC ¶ 61,185 (2011). 

6Order No. 733, 130 FERC ¶ 61,221, at P 186. 

7 Id. P 203. 

8 Id. P 224. 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY 

COMMISSION 

Before Commissioners: Jon Wellinghoff, 

Chairman; Philip D. Moeller, John R. 

Norris, and Cheryl A. LaFleur. 

Transmission Relay Loadability 

Reliability Standard 

Docket No. RM11–16–000 

Order No. 759 

Final Rule 

(Issued March 15, 2012) 

1. Pursuant to section 215 of the 

Federal Power Act (FPA),1 the 

Commission approves Reliability 

Standard PRC–023–2 (Transmission 

Relay Loadability) submitted by the 

North American Electric Reliability 

Corporation (NERC), the Electric 

Reliability Organization (ERO) certified 

by the Commission. The Reliability 

Standard requires transmission owners, 

generation owners, and distribution 

providers to set load-responsive phase 

protective relays according to specific 

criteria to ensure that the relays reliably 

detect—and protect the electric network 

from—fault conditions, but do not limit 

transmission loadability or interfere 

with system operators’ ability to protect 

system reliability.2 The Commission 

also approves NERC Rules of Procedure 

Section 1700—Challenges to 

Determinations, which provides 

registered entities a means to challenge 

determinations made by planning 

coordinators under Reliability Standard 

PRC–023. 

I. Background 

A. Relay Protection Systems 

2. Protective relays are devices that 

detect and initiate the removal of faults 

on an electric system.3 They are 

designed to read electrical 

measurements, such as current, voltage, 

and frequency, and can be set to 

recognize certain measurements as 

indicating a fault. When a protective 

relay detects a fault on an element of the 

system under its protection, it sends a 

signal to an interrupting device(s) (such 

as a circuit breaker) to disconnect the 

element from the rest of the system. 

Impedance relays, which are the most 

common type of relays used to protect 

transmission lines, continuously 

measure voltage and current on the 

protected transmission line and operate 

when the measured magnitude and 

phase angle of the impedance (voltage/ 

current) falls within the settings of the 

relay. 

B. Reliability Standard PRC–023–1 and 

Order No. 733 

3. Currently effective Reliability 

Standard PRC–023–1 applies to relay 

settings on (1) all transmission lines and 

transformers with low-voltage terminals 

operated or connected at or above 200 

kV; 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.4

The Reliability Standard consists of 

three Requirements and an Attachment 

A. Requirement R1 requires entities 

with certain transmission facilities to set 

their relays according to one of thirteen 

specific settings (sub-parts R1.1 through 

R1.13) designed to maximize loadability 

while maintaining Reliable Operation of 

the bulk electric system for all fault 

conditions. Requirement R2 provides 

additional obligations for entities that 

elect certain settings. Requirement R3 

requires planning coordinators to 

designate 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. Attachment A specifies the 

protection systems that are subject to 

and excluded from the Standard’s 

Requirements. 

4. On March 18, 2010, the 

Commission issued a Final Rule 

approving Reliability Standard PRC– 

023–1 (Transmission Relay Loadability), 

that requires transmission owners, 

generator owners, and distribution 

providers set load-responsive phase 

protection relays according to specific 

criteria to ensure that the relays reliably 

detect and protect the electric network 

from all fault conditions, but do not 

operate during non-fault load 

conditions.5 In addition, under section 

215(d)(5) of the FPA, the Commission 

directed the ERO to develop 

modifications to the Standard to address 

certain issues identified by the 

Commission. 

1. Currently Effective Requirement R1 

5. Requirement R1 states that each 

transmission owner, generator owner, 

and distribution provider subject to 

Reliability Standard PRC–023–1 shall 

use one of the criteria prescribed in subparts R1.1 through R1.13 for any 

specific circuit terminal to prevent its 

phase protective relay setting from 

limiting transmission system loadability 

while maintaining reliable protection of 

the bulk electric system for all fault 

conditions. 

6. In Order No. 733, the Commission 

directed the ERO, under section 

215(d)(5) of the FPA, to develop 

modifications to Requirement R1 to: 

(1) Require that transmission owners, 

generator owners, and distribution 

providers give their transmission 

operators a list of transmission facilities 

that implement sub-part R1.2; 6 (2) 

require entities that have protective 

relays set pursuant to sub-part R1.10 to 

verify that the limiting piece of 

equipment is capable of sustaining the 

anticipated overload for the longest 

clearing time associated with a fault; 7

and (3) require the ERO to document, 

subject to audit by the Commission, and 

to make available for review to users, 

owners, and operators of the BulkPower System, by request, a list of those 

facilities that have protective relays set 

pursuant to sub-part R1.12.8

2. Currently Effective Requirement R2 

7. 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 specified R1 sub-parts 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. Currently Effective Requirement R3 

8. 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-part R3.1 requires 

planning coordinators to have a process 

to identify critical facilities. Sub-part 

R3.1.1 specifies that the process must 


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Federal Register / Vol. 77, No. 55 / Wednesday, March 21, 2012 / Rules and Regulations 16437 

9 Id. P 60. 

10 Id. P 69. 

11 Id. P 237. 

12 Id. P 97. 

13 ‘‘Out-of-step blocking’’ refers to a protection 

system that is capable of 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. 

14Order No. 733 at 244. 

15 Id. P 264. 

16 Id. P 283. 

17 Id. P 284. 

18March 18 Petition at 42. 

19 Id. at 5. 

20Reliability Standard PRC–023–2, Section A.3 

(Purpose). 

21March 18 Petition at 30. 

consider input from adjoining planning 

coordinators and affected reliability 

coordinators. Sub-parts R3.2 and R3.3 

require planning coordinators to 

maintain a list of critical facilities and 

provide it to reliability coordinators, 

transmission owners, generator owners, 

and distribution providers within 30 

days of initially establishing it, and 

within 30 days of any subsequent 

change. 

9. In Order No. 733, the Commission 

directed the ERO to modify 

Requirement R3 to: (1) Apply an ‘‘add 

in’’ approach to sub-100 kV facilities 

that are owned or operated by currently 

registered entities or entities that 

become registered entities in the future, 

and are associated with a facility that is 

included on a critical facilities list 

defined by the Regional Entity; 9 (2) 

specify the test that planning 

coordinators must use to determine 

whether a sub-200 kV facility is critical 

to the reliability of the Bulk-Power 

System; 10 and (3) add the Regional 

Entity to the list of entities that receive 

a list of sub-200 kV facilities determined 

by the planning coordinator to be 

critical to the reliability of the bulk 

electric system.11 In addition, the 

Commission directed the ERO to 

develop an appeals process for entities 

to challenge a criticality 

determination.12

4. Currently Effective Attachment A 

10. Attachment A to Reliability 

Standard PRC–023–1 specifies which 

protection systems are subject to and 

excluded from the Standard’s 

Requirements. Section 1 of Attachment 

A provides that the Reliability Standard 

applies to any protective functions that 

can operate with or without time delay, 

on load current, including but not 

limited to: (1) Phase distance; (2) out-ofstep tripping; (3) switch-on-to-fault; (4) 

overcurrent relays; and (5) 

communication-aided protection 

applications. Section 2 states that the 

Reliability Standard requires evaluation 

of out-of-step blocking schemes 13 to 

ensure that they do not operate for faults 

during the loading conditions defined in 

the Standard’s Requirements. Finally, 

section 3 expressly excludes certain 

relay elements and protection systems 

from the Reliability Standard’s 

Requirements. 

11. The Commission, in Order No. 

733, directed the ERO to modify 

Attachment A to: (1) include section 2 

as an additional Requirement with the 

appropriate violation risk factor and 

violation severity level in the Reliability 

Standard; 14 and (2) include supervising 

relay elements on the list of relays and 

protection systems that are specifically 

subject to the reliability Standard.15

5. Currently Effective Implementation 

Plan 

12. Reliability Standard PRC–023–1 

established staggered effective dates for 

various Requirements and facilities. The 

Standard also included a footnote 

(exceptions footnote) to the ‘‘Effective 

Dates’’ section honoring temporary 

exceptions from enforcement actions 

approved by the NERC Planning 

Committee before NERC proposed the 

Reliability Standard. 

13. In Order No. 733, the Commission 

directed the ERO, under section 

215(d)(5), to modify the Reliability 

Standard to include an implementation 

plan for sub-100 kV facilities 16 and to 

remove the exceptions footnote from the 

‘‘Effective Dates’’ section of the 

Reliability Standard.17

II. NERC Petition: Proposed Reliability 

Standard PRC–023–2 and Rule of 

Procedure, Section 1700—Challenges to 

Determinations 

14. In a March 18, 2011 Filing (March 

18 Petition), NERC requests Commission 

approval of Reliability Standard PRC– 

023–2 (Transmission Relay Loadability) 

and NERC Rules of Procedure Section 

1700—Challenges to Determinations. 

15. In support of the March 18 

Petition, NERC states that the proposed 

Reliability Standard requires 

transmission owners, generator owners, 

and distribution providers to verify 

relay loadability using methods that 

achieve ‘‘the reliability goal of this 

Standard in an effective and efficient 

manner familiar to the responsible 

entities.’’ 18 In addition, NERC 

specifically identifies the benefits of 

proposed Reliability Standard PRC– 

023–2 as including (a) consistent 

identification of operationally critical 

circuits operated below 200 kV that 

must comply with the Requirements of 

the Standard, and (b) providing 

transmission operators, planning 

coordinators, reliability coordinators, 

and the ERO with more information 

regarding the criteria selected by entities 

for verifying relay loadability.19

A. Reliability Standard PRC–023–2 

16. Reliability Standard PRC–023–2 

contains six requirements with the 

stated purpose of ensuring that 

protective relay settings do not limit 

transmission loadability, do not 

interfere with system operators’ ability 

to take remedial action to protect system 

reliability, and are set to reliably detect 

all fault conditions and protect the 

electrical network from these faults.20

The proposed Reliability Standard also 

includes two attachments. Attachment 

A specifies the protection systems that 

are subject to and excluded from the 

Standard’s Requirements. Attachment B 

specifies the criteria for determining the 

circuits which must comply with 

Requirements R1 through R5. 

Requirement R1 

17. NERC describes Reliability 

Standard PRC–023–2 Requirement R1 as 

follows: 

Requirement R1 mandates that each 

Transmission Owner, Generator Owner, and 

Distribution Provider shall use any one of the 

identified criteria (Requirement R1, criteria 1 

through 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. 

Each Transmission Owner, Generator Owner, 

and Distribution Provider shall evaluate relay 

loadability at 0.85 per unit voltage and power 

factor angle of 30 degrees[.] 21

18. With the exception of clarifying 

language and the addition of criterion 

10.1, proposed Requirement R1 retains 

the same criteria as currently existing 

PRC–023–1. Criteria 1 through 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. 

19. Criterion 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. 

Criterion 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. Criterion 3 allows 


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16438 Federal Register / Vol. 77, No. 55 / Wednesday, March 21, 2012 / Rules and Regulations 

22 Id. at 20. 

23The mechanical withstand capability is 

determined on the basis of the transformer’s design 

and the periodic transformer maintenance to 

preserve that capability by the owner. The 

withstand capability could be compromised, for 

example, if the moisture level in a transformer is 

allowed to increase above the design value but 

remains within dielectric acceptance. 

24March 18 Petition at 20–21. 

25 Id. at 24. 

26 Id. at 20, 23. 

27 Id. at 24. 

28 Id. at 25. 

29 Id. 

transmission line relays to be set so that 

they do not operate at or below 115 

percent of the maximum theoretical 

power capability. Criterion 4 may be 

applied where series capacitors are used 

on long transmission lines to increase 

power transfer. Criterion 5 applies in 

cases where the maximum end-of-line 

three-phase fault current is small 

relative to the thermal loadability of the 

conductor. Criterion 6 may be used for 

system configurations where generation 

is remote from load busses or main 

transmission busses. 

20. Criterion 7 is appropriate for 

system configurations that have load 

centers that are remote from the 

generation center. Criterion 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. Criterion 9 applies to 

the same system configuration, but 

applies to the load end. Criterion 10 is 

specific to transmission transformer 

fault protective relays and transmission 

lines terminated only with a 

transformer. Criterion 11 may be used 

for transformer overload protection 

relays when criterion 10 cannot be met. 

Criterion 12 may be used when the 

circuits have three or more terminals. 

The limited circuit loading capability 

established by this criterion will become 

the facility rating of the circuit. Finally, 

criterion 13 is intended to apply when 

otherwise supportable situations and 

practical limitations are not identified 

under criteria 1 through 12. 

21. NERC explains that Reliability 

Standard PRC–023–2 modifies PRC– 

023–1 by adding criterion 10.1 to 

address the Commission’s directive that 

entities with protective relays set 

pursuant to Requirement R1.10 of PRC– 

023–1, which is criterion 10 of 

Requirement 1 of PRC–023–2, must 

verify that the limiting piece of 

equipment is capable of sustaining the 

anticipated overload for the longest 

clearing time associated with a fault.22

The criterion requires coordination so 

that settings on a transformer’s load 

responsive relay do not expose the 

transformer to a fault level and duration 

that exceeds the transformer’s 

mechanical withstand capability.23

NERC further states in the March 18 

Petition that it believes Requirement 

10.1 is equally effective and efficient as 

the approach directed in Order No. 

733.24

Requirement R2 

22. Proposed Reliability Standard 

PRC–023–2 adds a new Requirement R2 

that requires each transmission owner, 

generation owner, and distribution 

provider to set its out-of-step blocking 

elements to allow tripping of phase 

protective relays for faults that occur 

during the loading conditions modeled 

under Requirement R1. NERC states in 

the March 18 Petition that Requirement 

R2 has been added to proposed 

Reliability Standard PRC–023–2 to 

address the Commission’s directive to 

include section 2 of PRC–023–1 

Attachment A as an additional 

Requirement with the appropriate 

violation risk factor and violation 

severity level.25 NERC has assigned this 

proposed Requirement a high violation 

risk factor and a severe violation 

severity level reflecting the impact to 

reliability of violating the Requirement. 

Requirements R3, R4, and R5 

23. Requirement R3 in Reliability 

Standard PRC–023–2 renumbers and 

makes conforming edits to Requirement 

R2 from PRC–023–1. Requirement R4 

requires an entity that chooses to use 

Requirement R1 criterion 2 as the basis 

for verifying transmission line relay 

loadability to provide its planning 

coordinator, transmission operator, and 

reliability coordinator with an updated 

list of circuits associated with those 

transmission line relays at least once 

each calendar year. Similarly, 

Reliability Standard PRC–023–2 adds a 

new Requirement R5 that requires 

entities that set transmission line relays 

according to Requirement R1 criterion 

12 to provide an updated list of the 

circuits associated with those relays to 

its Regional Entity at least once each 

calendar year, to allow the ERO to 

compile a list of all circuits that have 

protective relays settings that limit 

circuit capability. In the March 18 

Petition, NERC states that new 

Requirements R4 and R5, respectively, 

address the Commission’s directives 

relating to providing transmission 

operators a list of transmission facilities 

that implement criterion 2 and directing 

that the ERO create a list of those 

facilities that have protective relays set 

pursuant to criterion 12.26

Requirement R6 

24. Requirement R6 of Reliability 

Standard PRC–023–2 requires each 

planning coordinator to conduct an 

assessment at least once each calendar 

year (but no less frequently than every 

15 months) by applying the criteria in 

Attachment B to determine the circuits 

in its planning coordinator area for 

which entities must comply with 

Requirements R1 through R5. Sub-part 

6.1 requires the planning coordinator to 

maintain a list of circuits subject to 

PRC–023–2 per application of 

Attachment B identifying the year in 

which any criterion in Attachment B 

applies. Sub-part 6.2 requires the 

planning coordinator to provide the list 

to all Regional Entities, reliability 

coordinators, transmission owners, 

generators owners, and distribution 

providers within its planning 

coordinator area within 30 calendar 

days of establishing the initial list, and 

30 days of any subsequent change 

thereto. NERC states in the March 18 

Petition that the proposed sub-part 6.2, 

formerly Requirement R3.3 in PRC–023– 

1, modifies the Requirement in order to 

address the Commission’s directive to 

add the Regional Entity to the list of 

entities that receive the list of critical 

facilities.27

Attachment A 

25. Attachment A to Reliability 

Standard PRC–023–2 includes a new 

section 1.6 that extends the Standard’s 

applicability to include phase 

overcurrent supervisory elements (i.e., 

phase fault detectors) associated with 

current-based, communication-assisted 

schemes (i.e., pilot wire, phase 

comparison, and line current 

differential) where the scheme is 

capable of inadvertent tripping for loss 

of communications, even if there is no 

fault on the line. In addition, 

conforming changes are made to 

proposed section 2.1, formerly section 

3.1 of the PRC–023–1, to recognize that 

elements described in new section 1.6 

are no longer excluded from the 

proposed Standard’s scope. NERC states 

in the March 18 Petition that these 

changes have been made to address the 

Commission’s directives to include 

supervising relay elements on the list of 

relays and protection systems that are 

specifically subject to the Reliability 

Standard.28 NERC further states that it 

believes section 1.6 of Attachment A is 

equally effective and efficient in 

addressing the Commission’s concern as 

the approach directed in Order No. 

733.29


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Federal Register / Vol. 77, No. 55 / Wednesday, March 21, 2012 / Rules and Regulations 16439 

30As we stated previously, ‘‘[w]e would expect 

that any [nuclear plant interface requirements] 

agreed to between a nuclear plant generator 

operator and transmission entity would include all 

facilities needed to transmit offsite power and 

auxiliary power to the nuclear facility. Mandatory 

Reliability Standard for Nuclear Plant Interface 

Coordination, 125 FERC ¶ 61,065, at P 51 (2008). 

31March 18 Petition at 14. 

32 Id. at 13. 

33Order No. 733 at P 80. 

34 Id. P 84. 

35March 18 Petition at 19. With respect to NERC’s 

assertion, the Commission agrees that avoiding 

thermal loading may be appropriate criteria for 

some regions. However, for other regions, such as 

the Western Interconnection, voltage and stability 

criteria considerations would be included as 

appropriate. 

36As explained in the March 18 Petition, the 

system performance measure in this test is less 

rigorous than that required by TPL–003 (System 

Performance Following Loss of Two or More bulk 

electric system Elements) because it ignores voltage 

and stability ratings. NERC points out, however, 

that the contingency condition in Attachment B is 

more stringent than that in TPL–003, and the 

contingency and system performance measure were 

developed together in order to align with the 

reliability objective of the proposed Standard. 

March 18 Petition at 19. 

Attachment B 

26. Attachment B of Reliability 

Standard PRC–023–2 specifies six 

criteria that planning coordinators must 

apply to identify sub-200kV facilities 

that are subject to compliance with the 

Reliability Standard. Specifically, a 

facility is subject to PRC–023–2 if the 

facility meets any one of the following 

six criteria: 

• Is a monitored facility of a 

permanent flowgate in the Eastern 

Interconnection, a major transfer path 

within the Western Interconnection, or 

a comparable monitored facility in the 

Quebec Interconnection, that has been 

included to address reliability concerns 

for loading of that circuit (Criteria B1); 

• Is a monitored facility of an 

interconnection reliability operating 

limit, where the limit was determined in 

the planning horizon pursuant to 

Reliability Standard FAC–010 (System 

Operating Limits Methodology for 

Planning Horizon) (Criteria B2); 

• Forms a path to supply off-site 

power to a nuclear plant as established 

in the nuclear plant interface 

requirements pursuant to Reliability 

Standard NUC–001 (Nuclear Plant 

Interface Coordination) (Criteria B3).30

• Is identified through a sequence of 

power flow analyses specified in 

Attachment B and performed by the 

planning coordinator (Criteria B4); 

• Is selected by the planning 

coordinator based on technical studies 

or assessments other than those 

specified above, in consultation with 

the facility owner (Criteria B5); or 

• Is mutually agreed upon for 

inclusion by the planning coordinator 

and the facility owner (Criteria B6). 

27. NERC states in the March 18 

Petition that while the six criteria 

presented in Attachment B vary from 

some of the guidance provided in Order 

No. 733, they nonetheless identify all 

facilities that must be subject to 

proposed Reliability Standard PRC– 

023–2 in order to achieve the Standard’s 

reliability objective.31 NERC further 

reports that it is in the process of 

applying the test to a representative 

sample of utilities from each of the three 

Interconnections and plans to file the 

results of these tests by February 17, 

2013. NERC states that it plans to revise 

Attachment B, if necessary, pending the 

results of this test and clarifications 

made in Order No. 733–A.32

28. The Commission, in Order No. 

733, provided guidance that a test to 

determine critical sub-200 kV facilities 

should include the same simulations 

and assessments as the Transmission 

Planning (TPL) Reliability Standards.33

While the TPL Standards permit manual 

system adjustments between two 

contingencies, NERC explains in the 

March 18 Petition that it believes it is 

more informative, and in line with the 

reliability objective, to require testing of 

double contingencies without such 

manual adjustments, thereby modeling a 

situation in which an operator fails to, 

or does not have time to, make 

appropriate system adjustments. This 

focused testing exceeds the 

requirements of the TPL Standards and, 

NERC asserts, is an equally efficient and 

effective approach to addressing the 

Commission’s concern that the test must 

be sufficiently robust to provide 

assurance that all appropriate facilities 

are identified and made subject to the 

Reliability Standard for the Standard to 

achieve its purpose. 

29. In Order No. 733, the Commission 

also provided guidance regarding 

elements of a definition of desirable 

system performance that must inform 

any test to determine which sub-200 kV 

circuits are critical to system reliability. 

The Commission’s guidance stated, 

among other things, that the power 

system should maintain all facilities 

within their applicable thermal (i.e., 

current), voltage, or stability ratings 

(short time ratings are applicable).34 In 

the March 18 Petition, NERC asserts that 

it is most appropriate to focus on 

avoiding thermal loading of 

transmission circuits.35 In order to 

achieve its reliability goal, NERC 

believes, Reliability Standard PRC–023– 

2 must apply to circuits whose relays 

will be challenged by excessive thermal 

loading to the point that a relay hampers 

the system operator’s ability to take 

remedial action. NERC believes this test 

is an equally effective and efficient 

approach to addressing the 

Commission’s concern regarding the 

rigorousness of the test.36

Implementation Plan 

30. In the March 18 Petition, NERC 

proposes staggered effective dates for 

Reliability Standard PRC–023–2, i.e., 

the mandatory compliance date after an 

allotted implementation period, for each 

of the Standard’s requirements. The 

implementation plan provides 18 

months for planning coordinators to 

apply the criteria in Attachment B and 

determine which sub-200 kV circuits 

must be subject to the Standard. Those 

entities responsible for compliance on 

circuits identified by a planning 

coordinator pursuant to Requirement R6 

are provided until the first day of the 

first calendar quarter 39 months 

following notification to become 

compliant, or until the first day of the 

first calendar year in which any 

criterion in Attachment B applies if the 

planning coordinator indentifies the 

circuit in an assessment of a future year 

more than 39 months beyond the year 

in which the assessment is conducted. 

Violation Risk Factors/Violation 

Severity Levels 

31. NERC assigns Requirements R1, 

R2, and R6 a ‘‘high’’ violation risk 

factor, Requirement R3 a ‘‘medium’’ 

violation risk factor, and Requirements 

R4 and R5 a ‘‘lower’’ violation risk 

factor. NERC also proposes violation 

severity levels for each of the 

Requirements of Reliability Standard 

PRC–023–2. 

B. NERC Rules of Procedure Section 

1700—Challenges to Determinations 

32. In addition to the Reliability 

Standard, NERC included in its petition 

new Rules of Procedure Section 1700— 

Challenges to Determinations, which 

provides a process for registered entities 

to challenge a planning coordinator’s 

determination made under a Reliability 

Standard that a facility operated below 

200 kV is subject to compliance with the 

standard. Pursuant to Rule 1702, a 

registered entity is encouraged, but not 

required, initially to meet with the 

planning coordinator to resolve any 

dispute. If the matter remains 

unresolved, the registered entity may 

challenge the determination with the 

appropriate Regional Entity. The 

registered entity may appeal the 

Regional Entity’s decision to NERC, and 

the NERC Board of Trustees would 

appoint a panel to review the Regional 


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37Transmission Relay Loadability Reliability 

Standard, 136 FERC ¶ 61,187 (September 15, 2011) 

(September 15 NOPR). 

38 Id. P 38. 

39 Id. PP 41–45. 

40 Id. P. 43. 

41 Id. 

42 Id. P 44. 

43 Id. P 45. 

44 76 FR 58,424 (2011). 

45Section 215(f) of the FPA provides, inter alia, 

that ‘‘[a] proposed rule or proposed rule change 

shall take effect upon a finding by the Commission, 

after notice and opportunity for comment, that the 

change is just, reasonable, not unduly 

discriminatory or preferential, is in the public 

interest and satisfies the requirements of subsection 

(c).’’ 46MISO Comments at 3. 

Entity decision. The Board of Trustees 

has the authority, but not the duty, to 

review the matter upon the request of 

the planning coordinator or registered 

entity. The registered entity may appeal 

the final NERC decision to the 

applicable governmental authority, e.g., 

the Commission for appeals within the 

United States. 

III. Notice of Proposed Rulemaking and 

Comments 

33. On September 15, 2011, the 

Commission issued a Notice of 

Proposed Rulemaking (NOPR) 

proposing to approve Reliability 

Standard PRC–023–2.37 In the NOPR, 

the Commission proposed to approve 

Reliability Standard PRC–023–2. The 

Commission indicated that the Version 

2 standard and new Rule of Procedure 

1700 adequately address the directed 

modifications set forth in Order No. 733. 

The Commission also proposed to 

accept the Attachment B criteria for 

identifying sub-200 kV facilities to 

which the Reliability Standard 

applies.38 Finally, the Commission 

proposed to approve the 

implementation plan, Violation Risk 

Factors, and Violation Severity levels. 

34. In addition, the NOPR set forth 

certain questions regarding the 

Attachment B criteria.39 Specifically, 

the Commission proposed the following 

questions to be addressed in the report 

regarding the application of Attachment 

B criteria NERC intends to file by 

February 17, 2013: 

• Whether the power system 

assessment proposed in criterion B4 

includes the critical system conditions 

utilized under Reliability Standard 

TPL–003–0 Requirement R1.3.2; 40

• Whether applicable entities 

evaluate relay loadability under the B4 

criterion consistent with Requirement 

R1 which requires, in part, that they 

‘‘evaluate relay loadability at 0.85 per 

unit voltage and a power factor angle of 

30 degrees’’ in addition to applicable 

current data; 41

• What ‘‘technical studies or 

assessments’’ will be used by planning 

coordinators to identify critical facilities 

under Criterion B5; 42 and 

• Whether Attachment B is 

sufficiently comprehensive to capture 

all circuits in a planning coordinator’s 

area that could have an operational 

impact on the reliability of the bulk 

electric system.43

35. On September 21, 2011, notice of 

the September 15 NOPR was published 

in the Federal Register with comments 

due on or before November 21, 2011.44

Timely comments were filed by the 

American Public Power Association 

(APPA), ISO New England Inc. (ISO– 

NE), the Midwest Independent System 

Operator, Inc. (MISO), and NERC. 

IV. Discussion 

36. Pursuant to section 215(d)(2) of 

the FPA, the Commission approves 

Reliability Standard PRC–023–2, 

including the Violation Risk Factors and 

Violation Severity Levels, and 

implementation plan. The Reliability 

Standard meets the directives outlined 

in Order No. 733, and further 

contributes to the reliability of the BulkPower System by requiring loadresponsive phase protection relay 

settings that will provide essential 

facility protection for faults while not 

limiting transmission loadability or 

interfering with system operators’ 

ability to protect system reliability. In 

addition, the Reliability Standard 

provides for the consistent 

identification of operationally critical 

circuits operated below 200 kV that 

must comply with the Requirements of 

the Standard. Accordingly, we find that 

the Reliability Standard is just, 

reasonable, not unduly discriminatory 

or preferential, and in the public 

interest. 

37. Also, pursuant to section 215(f) of 

the FPA, the Commission approves 

NERC Rule of Procedure Section 1700— 

Challenges to Determinations as just, 

reasonable, not unduly discriminatory 

or preferential, in the public interest, 

and satisfying the requirements of 

section 215(c) of the FPA.45 Rule of 

Procedure Section 1700 addresses the 

Order No. 733 directive for a 

mechanism by which a registered entity 

can challenge a determination by a 

planning coordinator made pursuant to 

Reliability Standard PRC–023–2. 

38. NERC indicates in its comments 

that it is in the process of applying the 

test set forth in Attachment B of 

Reliability Standard PRC–023–2 to a 

representative sample of utilities from 

each of the three Interconnections and 

will file the results of these tests in a 

report on or before February 17, 2013. 

We adopt the NOPR proposal and direct 

NERC to address in the report several 

specific questions regarding the 

implementation of the applicability 

criteria set forth in Attachment B, as 

discussed below. 

39. Further, commenters raise a 

number of concerns regarding the 

specific substantive Requirements of the 

Reliability Standard, the Standard’s 

Attachment B, and the violation risk 

factor designations. These commenter 

concerns are discussed below. 

A. Reliability Standard PRC–023–2 

1. Requirement R1 

40. Requirement 1 of PRC–023–2 

provides that applicable entities must 

use one of the identified criteria 

(Requirement R1, criteria 1 through 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. 

Requirement R1.13 provides that 

‘‘[w]here other situations present 

practical limitations on circuit 

capability, set the phase protection 

relays so they do not operate at or below 

115% of such limitations.’’ 

41. MISO contends that over-reliance 

on criterion R1.13 would adversely 

impact operations, reliability, flexibility, 

and transmission congestion costs, and 

lead to unnecessary transmission 

expansion in the future to comply with 

transmission planning standards. To 

avoid this result, MISO requests that the 

Commission clarify the applicability of 

the standard by narrowing the scope of 

the protection systems covered by the 

Standard under Attachment A. In 

particular, MISO requests the 

Commission clarify that the following 

protection systems are excluded from 

the standard: (a) Differential current 

relays and negative sequence relays; (b) 

supervisory elements with unanimous 

consent logic; (c) redundant voting 

protective relay schemes; and (d) 

switch-on-to-fault protective relay 

schemes. We address MISO’s request 

below. 

a. Differential Current Relays & Negative 

Sequence Relays 

42. MISO requests that we clarify that 

differential current relay elements and 

negative sequence relay elements 

should not be covered by the standard 

‘‘as they would not trip with or without 

time delay on load current.’’ 46 MISO 

argues that the exclusion of these 


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47 Id. 

48Transmission Relay Loadability Reliability 

Standard, 127 FERC ¶ 61,175, at n. 98 (2009). 

49Order No. 733 at P 264. 

50Order No. 733–B at P 39. 

51March 18 Petition at 25–28. 

52 Id. at 27. 

53MISO Comments at 4. 

54 Id. 

55MISO Comments at 5. 

56 Id. 

57 Id. at 5–6. 

58Order No. 733 at n. 187. 

specific relay elements from the 

proposed standard ‘‘would be consistent 

with the purpose and intent of the 

standard and would prevent an 

inappropriate and unnecessary 

expansion of the standard’s 

applicability.’’ 47

43. We grant MISO’s request for 

clarification in part. As noted by MISO, 

differential current relay elements and 

negative sequence relay elements, by 

their nature, are not load responsive. As 

the Commission noted previously, the 

exclusion of a protection system from 

Reliability Standard PRC–023 appears to 

be unnecessary if the system is not loadresponsive.48 Therefore, we grant 

MISO’s request for clarification to the 

extent that non-load responsive relays 

are not covered by Reliability Standard 

PRC–023–2, however we decline to 

direct NERC to include the assets in the 

exclusion list of Section 3 of 

Attachment A as the exclusion list 

should be limited to protection systems 

that would otherwise be subject to the 

Standard. 

b. Supervisory Relay Elements 

44. In Order No. 733, the Commission 

directed NERC to include supervisory 

relay elements on the list of relays and 

protection systems that are specifically 

subject to the PRC–023 Reliability 

Standard.49 In Order No. 733–B, the 

Commission clarified that its directive 

regarding the applicability of the 

Reliability Standard to supervisory 

relays does not foreclose the 

development of an approach tailored to 

eliminate application of the standard to 

some supervisory relays but not to 

others, where technically justified.50

45. In response to the directive, NERC 

modified Attachment A of Reliability 

Standard PRC–023–2, which identifies 

types of protection systems that are 

subject to, and others that are excluded 

from, the standard. In part, Attachment 

A provides that ‘‘this standard includes 

any protective functions which could 

trip with or without time delay, on load 

current, including but not limited to 

* * * 1.6. Phase overcurrent 

supervisory elements (i.e., phase fault 

detectors) associated with currentbased, communication-assisted schemes 

* * * where the scheme is capable of 

tripping for loss of communications.’’ In 

the March 18 Petition, NERC explained 

that section 1.6, while addressing a 

subset of supervisory relays, is equally 

effective and efficient in addressing the 

Commission’s reliability concern. 

According to NERC, including all 

supervisory relays would have 

unintended negative impacts on system 

reliability by impacting the 

dependability and security of certain 

protection systems.51 NERC explains 

that supervisory overcurrent elements 

used as fault detectors ‘‘by themselves 

cannot trip on load current, with or 

without time delay. Since the trip logic 

requires assertion of the fault detector 

and the supervised protective function 

(which already is required to meet the 

loadability requirements), the overall 

protective function will meet the 

loadability requirement.’’ 52

Comments 

46. In its comments, MISO raises a 

concern that an interpretation of the 

term ‘‘phase overcurrent supervisory 

elements’’ in section 1.6 of Attachment 

A that includes elements in a 

unanimous consent scheme could lead 

to unnecessary facility limit 

reductions.53 MISO asks the 

Commission to clarify that it is 

acceptable to consider ‘‘unanimous 

consent’’ logic when evaluating 

transmission relay loadability. 

According to MISO, ‘‘[i]f a relay scheme 

contains multiple relay elements and 

requires ‘unanimous consent’ among 

two or more of the relay elements in 

order to initiate a tripping action [of a 

circuit breaker], transmission relay 

loadability should be based solely on 

the relay element that is least sensitive 

to load so long as the relay elements 

could never initiate a tripping action 

without the operation of the relay 

element least sensitive to load.’’ 54

Commission Determination 

47. Giving due weight to NERC’s 

technical expertise on this issue, we 

approve NERC’s modification to 

Attachment A and find that NERC has 

developed an equally efficient and 

effective approach to addressing the 

Order No. 733 directive regarding 

supervisory relays. NERC’s proposal 

identifies a subset of supervisory relay 

elements, consistent with the 

Commission’s clarification in Order No. 

733–B. 

48. We deny MISO’s request for 

clarification. There are various types of 

protection schemes. MISO describes a 

specific protection scheme that uses 

unanimous consent logic and asks 

whether elements of the scheme are 

subject to Reliability Standard PRC– 

023–2. This is a fact intensive inquiry, 

and we will not rule on this matter 

based on the information provided in 

MISO’s comments. If MISO seeks 

further clarification of this issue, it 

should pursue the matter with NERC. 

The Commission will not make a 

determination on MISO’s specific 

scenario without a complete record and 

without it going through NERC’s 

Reliability Standards development 

process or interpretation process. 

c. Redundant Voting Schemes—the 

Most Load Sensitive Relay 

49. MISO requests that we clarify how 

entities should handle certain 

redundant voting protective relay 

schemes.55 MISO explains that, in a 

redundant voting protective relay 

scheme for a transmission facility, there 

are three protective relay schemes and 

only two of the three must operate to 

initiate tripping. MISO argues that the 

most load sensitive of these three relay 

schemes should be exempt from the 

standard, ‘‘so long as the most load 

sensitive of the three protective relay 

scheme can never initiate a tripping 

action on its own with[out] a tripping 

output from one of the other two 

protective relay schemes.’’ 56

50. We decline to grant MISO’s 

request on this issue. MISO’s limited 

comments on this issue do not provide 

adequate information or technical 

support for its request. Without 

adequate support, the Commission 

cannot respond to MISO’s request. 

d. Switch-on-to-Fault Protective Relay 

Schemes 

51. MISO requests that the 

Commission clarify that a switch-on-tofault protective relay scheme, which is 

specifically included in section 1.3 of 

Attachment A, may be excluded from 

the requirements of the Reliability 

Standard if it meets each of three stated 

conditions presented by MISO.57

52. Currently effective Reliability 

Standard PRC–023 explicitly addresses 

switch-on-to-fault protective relay 

schemes. Switch-on-to-fault schemes are 

protection systems designed to trip a 

transmission line breaker when the 

breaker is closed into a fault. Because 

the current fault detectors for these 

systems must be set low enough to 

detect ‘‘zero-voltage’’ faults, i.e., closein, three-phase faults, these systems 

may be susceptible to operate on load.58

We note that the System Protection and 

Control Task Force acknowledged, with 


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59NERC Planning Committee, System Protection 

and Control Task Force, ‘‘Switch-on-to-Fault 

Schemes in the Context of Line Relay Loadability,’’ 

at 2 (June 7, 2006). 

60 Id. at 6–7. 

61 Id. 

62Order No. 733 at P 229. 

63 Id. P 228. 

64 Id. 

65 Id. P 229. 

66 Id. 

67MISO Comments at 8. 

68 Id. 

69 Mandatory Reliability Standards for the BulkPower System, Order No. 693 FERC Stats. & Regs. 

¶ 31,242, at P 77 (2007). 

70MISO Comments at 8. 

regard to switch-on-to-fault schemes 

‘‘* * * a concern, based on actual 

events which have occurred in 

connection with blackouts, for the 

undesired operation of [switch-on-tofault] schemes when a breaker is closed 

into a line.’’ 59 Because the relays 

applied in switch-on-to-fault schemes 

are load-responsive, the Commission 

agreed with the ERO’s technical 

decision to make such relays subject to 

the requirements of PRC–023. As noted 

above, MISO proposed a set of 

conditions that would remove an 

otherwise load-responsive relay from 

the requirements of Reliability Standard 

PRC–023. MISO has not, however, 

provided any explanation or technical 

support for its proposed conditions. 

Therefore, we decline to grant the 

requested clarification. 

2. Requirement R3 

53. Requirement R3 of PRC–023–2 

requires a transmission owner, generator 

owner and/or distribution provider to 

obtain the agreement of the planning 

coordinator, transmission operator, and 

reliability coordinator for a calculated 

circuit capacity with the practical 

limitations described in Requirement 

R1, criteria 6, 7, 8, 9, 12, or 13. 

a. Comments 

54. MISO requests that the 

Commission clarify that Requirement R3 

was not intended to create an obligation 

of the planning coordinator, 

transmission operator and reliability 

coordinator to independently verify or 

approve the calculated circuit capability 

provided by the transmission owner, 

generation owner or distribution 

provider.60 MISO argues that this 

obligation to obtain the agreement could 

impute an obligation on the planning 

coordinator, transmission operator and/ 

or reliability coordinator to evaluate the 

calculated circuit capability without 

providing corresponding criteria that 

should be applied in the evaluation.61

MISO also requests that the Commission 

provide guidance on how such entities 

should resolve disputes over calculated 

circuit capabilities. 

b. Commission Determination 

55. We deny MISO’s request for 

clarification. The Commission 

addressed MISO’s concern in Order No. 

733.62 Specifically, in the Order No. 733 

rulemaking, commenters argued that the 

use of the term ‘‘agreement’’ in PRC– 

023–1 simply meant that ‘‘the entity 

calculating the circuit capability is 

required to provide the circuit 

capability to the relevant functional 

entities’’ and that ‘‘planning 

coordinators, transmission operators, 

and reliability coordinators must simply 

agree that they will use the circuit 

capability provided by the transmission 

owner, generator owner, or distribution 

owner.’’ 63 The concerns raised at that 

time mirror the concerns raised by 

MISO; commenters indicated that the 

applicable parties did not want to be 

‘‘responsible for reviewing and 

approving the calculated circuit 

capabilities under Requirement R[3].’’ 64

56. The Commission rejected the 

commenters’ arguments in Order No. 

733, finding that the language ‘‘shall 

obtain the agreement’’ requires that ‘‘the 

entity calculating the circuit capability 

must reach an understanding with the 

relevant functional entity that the 

calculated circuit capability is capable 

of achieving the reliability goal of PRC– 

023–1.’’ 65 In addition, the Commission 

clarified that since the Standard is 

‘‘intended to ensure that protective relay 

settings do not limit transmission 

loadability or interfere with system 

operators’ ability to take remedial action 

to protect system reliability, and to 

ensure that relays reliably detect all 

fault conditions and protect the 

electrical network from these faults,’’ 

the agreement required under 

Requirement R3 should ‘‘center around 

achieving these purposes.’’ 66 Having 

adequately addressed this matter in 

Order No. 733, it is unnecessary to 

elaborate further in response to MISO 

and, accordingly, we deny MISO’s 

request on this issue. 

57. Further, to the extent that a 

dispute arises between responsible 

entities over the determination of a 

calculated circuit capability under 

Requirement R3, nothing precludes the 

responsible entities from raising the 

dispute with the applicable Regional 

Entity. 

3. Requirement R6 

58. Requirement R6 of the Reliability 

Standard requires planning coordinators 

to conduct an assessment applying the 

criteria in Attachment B to determine a 

list of circuits subject to PRC–023–2 

Requirements R1 through R5. Under 

Attachment B, the planning coordinator 

is required to evaluate ‘‘[t]ransmission 

lines operated below 100 kV and 

transformers with low voltage terminals 

connected below 100 kV that are part of 

the [bulk electric system].’’ 

a. Comments 

59. MISO requests clarification 

regarding the application of 

Requirement R6 to sub-100 kV 

facilities.67 Specifically, MISO requests 

clarification ‘‘with regard to what final 

and FERC-approved process is used by 

the Regional Entities to identify sub-100 

kV facilities ‘critical to the reliability of 

the bulk electric system.’ ’’ 68 MISO 

further requests clarification on how 

planning coordinators will be provided 

access to the list of such sub-100 kV 

facilities, and, finally, MISO requests 

clarification whether the use of such a 

list of sub-100 kV facilities is adequate 

to demonstrate compliance with 

Requirement R6. 

b. Commission Determination 

60. With regard to MISO’s request 

concerning the identification of sub-100 

kV facilities, we note that bulk electric 

system facilities are currently identified 

through the application of NERC’s 

definition of bulk electric system and 

NERC’s registration process, as applied 

by the Regional Entities.69 Regional 

Entities should inform planning 

coordinators of such sub-100kV 

facilities that already may have been 

identified so that the planning 

coordinator is able to fulfill its 

responsibilities pursuant to 

Requirement R6. 

61. We deny MISO’s request for 

clarification ‘‘that the use of such a list 

as/if provided by the Regional Entities 

is adequate to demonstrate compliance 

with a requirement to evaluate 

‘Transmission lines operated below 100 

kV and transformers with low voltage 

terminals connected below 100 kV that 

are part of the [bulk electric system].’ ’’70

The identification of facilities is only 

the first step in the process of 

determining whether the Standard 

applies. Once a planning coordinator 

has been provided with a list of sub-100 

kV facilities that are part of the bulk 

electric system, if any, it must apply the 

criteria in Attachment B to determine 

whether Requirements R1 through R5 of 

Reliability Standard PRC–023–2 will 

apply to the individual facilities. 

4. Attachment B 

62. Attachment B specifies which 

circuits must comply with 


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71 ISO–NE Comments at 4. 

72 Id. at 2–3. 

73September 15 NOPR at P 43. 

74MISO Comments at 7–8. 

75Order No. 733 at P 297. 

76 Id. P 69. 

77 Id. 

78 Id. P 43. 

79 Id. 

80 Id. P 44. 

81 Id. P 45. 

Requirements R1 through R5. Criterion 

B4 addresses circuits that are identified 

through a specified sequence of power 

flow analyses performed by the 

planning coordinator, which simulate 

double contingencies without manual 

adjustments between the contingencies. 

a. Comments 

63. IS0–NE requests that the 

Commission direct the ERO to remove 

criterion B4 of Attachment B from PRC– 

023–2.71 ISO–NE argues: (1) That such 

a criterion does not accurately recognize 

how the bulk electric system is 

operated; (2) that the system is neither 

planned nor operated to withstand two 

overlapping outages without intervening 

operator action; and (3) that such testing 

may result in unsolved cases, or 

voltages well below criteria.72 As an 

example, ISO–NE cites a system 

designed to bring on fast start generation 

before the second contingency. ISO–NE 

argues that testing under that scenario 

without the fast start generation 

removes transmission paths into an 

area, thus increasing current flows on 

the remaining circuits and increasing 

reactive losses, resulting in lower 

voltages. In addition, ISO–NE states that 

unsolved cases have no flows to 

evaluate and therefore cannot be 

analyzed as required under criterion B4, 

and that solved cases with belowcriteria voltage and excessive currents 

are unrealistic. ISO–NE concludes that 

such simulations may misidentify 

system conditions as severe cases when 

in reality they are not, thwarting the 

purpose of the testing. 

64. ISO–NE also asserts that criterion 

B4 provides no guidance on how the 

planning coordinator should dispatch 

the system in a model that tests 

overlapping contingencies, potentially 

resulting in different base assumptions 

used by the various planning 

coordinators. 

b. Commission Determination 

65. The Commission recognizes that 

concerns exist regarding the application 

of Attachment B. As discussed below, 

NERC will be providing a summary of 

the base cases used in applying the 

Attachment B criteria and an assessment 

of how the base cases used for the 

analysis relate to TPL–003–0, 

Requirement R1.3.2 in response to our 

Order No. 733 directive. In the NOPR, 

the Commission expressed concern that 

criterion B4 of Attachment B is silent as 

to the rigor of the simulations other than 

requiring planning coordinators to use 

their engineering judgment.73 NERC’s 

additional information regarding the 

base cases used in applying the 

Attachment B criteria will allow the 

Commission and other interested parties 

to evaluate whether further 

modifications to Attachment B may be 

warranted. Accordingly, we deny ISO– 

NE’s request on this issue and will not 

direct the ERO to develop modifications 

to Attachment B at this time. 

66. Therefore, we decline to direct 

NERC to remove criterion B4 from PRC– 

023–2 at this time. 

5. Violation Risk Factors/Violation 

Severity Levels 

67. As noted above, NERC has 

proposed a ‘‘high’’ violation risk factor 

for Requirement R6 of Reliability 

Standard PRC–023–2. 

a. Comments 

68. MISO requests that the 

Commission reject the assignment of a 

high violation risk factor to Requirement 

6, arguing: (1) That a high violation risk 

factor implies there is a direct 

correlation between instability, 

uncontrolled separation and cascading 

outages and the maintenance of a list of 

sub-200 kV circuits to which the 

planning coordinator believes the 

requirements of the standard applies; (2) 

that there is no such direct correlation, 

as evidenced by the fact that NERC has 

created and the Commission is 

proposing to accept a process by which 

entities can dispute the inclusion of 

circuits on the planning coordinator’s 

list; and (3) that appearance on or 

absence from the list in itself will not 

cause or prevent instability, 

uncontrolled separation and cascading 

outages; some other event or Reliability 

Standards violation (i.e., operating 

above System Operating Limits) would 

have to occur to trigger any impact to 

reliability.74

b. Commission Determination 

69. In Order No. 733, we directed 

NERC to assign a ‘‘high’’ violation risk 

factor to Requirement R3 of Reliability 

Standard PRC–023–1.75 The 

Requirement at issue is renumbered 

Requirement R6 in Reliability Standard 

PRC–023–2. NERC’s assignment of a 

‘‘high’’ violation risk factor to 

Requirement R6 is therefore consistent 

with our prior directive. 

70. MISO’s request is an untimely 

argument against an explicit directive 

from Order No. 733. Therefore, we reject 

MISO’s request for a rejection of the 

assignment of a ‘‘high’’ violation risk 

factor to Requirement R6. 

6. NERC Report on Implementation of 

Attachment B 

71. In Order No. 733, the Commission 

directed NERC to specify the test that 

planning coordinators will use to 

determine whether a sub-200 kV facility 

is critical to the reliability of the BulkPower System.76 In addition, the 

Commission directed NERC to file both 

the test and the results of applying the 

test to a representative sample of 

utilities from each of the three 

interconnections.77 Attachment B to 

Reliability Standard PRC–023–2 

represents the test filed in response to 

the above described directive. The 

NOPR set forth questions intended to 

assist the Commission’s understanding 

regarding the implementation of the 

test. Specifically, the Commission 

proposed that NERC address the 

following questions regarding the 

application of Attachment B criteria in 

the report: 

• Whether the power system 

assessment proposed in criterion B4 

includes the critical system conditions 

utilized under Reliability Standard 

TPL–003–0 Requirement R1.3.2; 78

• Whether applicable entities 

evaluate relay loadability under the B4 

criterion consistent with Requirement 

R1 which requires, in part, that they 

‘‘evaluate relay loadability at 0.85 per 

unit voltage and a power factor angle of 

30 degrees’’ in addition to applicable 

current data; 79

• What ‘‘technical studies or 

assessments’’ will be used by planning 

coordinators to identify critical facilities 

under criterion B5; 80 and 

• Whether Attachment B is 

sufficiently comprehensive to capture 

all circuits in a planning coordinator’s 

area that could have an operational 

impact on the reliability of the bulk 

electric system.81

a. Comments 

72. In its November 21, 2011 

Comments, NERC, with APPA 

concurring, responds to the questions 

proposed for inclusion in the report 

NERC intends to file by February 17, 

2013. 

73. With regard to the question 

whether the power system assessment 

proposed in criterion B4 includes the 

critical system conditions utilized under 


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82NERC Comments at 3. 

83 Id. 

84 Id. 

85 Id. at 4–5. 

86 Id. at 5. 

87 Id. 

88 Id. at 12–19. 

89 Id. at 3. 

90 5 CFR 1320.11. 

91 44 U.S.C. 3501–20. 

92 44 U.S.C. 3502(A)(3)(i), 44 U.S.C. 3507(a)(3). 

Reliability Standard TPL–003–0, 

Requirement R1.3.2, NERC states that 

the goal of the power flow analysis is to 

have planning coordinators utilize the 

base cases that are used for 

demonstrating compliance with the TPL 

Reliability Standards.82 NERC proposes 

to include in its report a summary of the 

base cases used in applying the 

Attachment B criteria and an assessment 

of how the base cases used for the 

analysis relate to TPL–003–0, 

Requirement R1.3.2.83

74. In response to the proposed 

question whether applicable entities 

evaluate relay loadability under the B4 

criterion consistent with Requirement 

R1 which requires, in part, that they 

‘‘evaluate relay loadability at 0.85 per 

unit voltage and a power factor angle of 

30 degrees’’ in addition to applicable 

current data, NERC states that, although 

the measures in criterion B4 of 

Attachment B do not explicitly 

reference voltage and power factor, the 

measures were derived from 

Requirement R1 of PRC–023–2; 

specifically, 0.85 per unit voltage and 30 

degree power factor angle.84 NERC 

states, therefore, that it is not necessary 

for it to include in the report a 

comparison of the results obtained using 

criterion B4 to the results that would be 

achieved based on assumptions 

consistent with Requirement R1. 

75. Regarding the question proposed 

in the NOPR concerning what 

‘‘technical studies or assessments’’ will 

be used by planning coordinators to 

identify facilities under criterion B5, 

NERC states that Attachment B does not 

identify a specific list to avoid 

unnecessarily limiting the technical 

studies or assessments a planning 

coordinator may use to identify 

circuits.85 NERC proposes to include a 

discussion in the report on the types of 

studies that planning coordinators may 

use.86

76. Finally, in response to the last 

proposed question of whether 

Attachment B is sufficiently 

comprehensive to capture all circuits in 

a planning coordinator’s area that could 

have an operational impact on the 

reliability of the bulk electric system, 

NERC proposes to include in the report 

an assessment that demonstrates 

whether Attachment B is 

comprehensive enough to capture all 

circuits that could have an operational 

impact on the reliability of the bulk 

electric system in the context of 

transmission relay loadabilty.87

b. Commission Determination 

77. As discussed above, NERC reports 

that it is in the process of applying the 

test set forth in Attachment B to a 

representative sample of utilities from 

each of the three Interconnections and 

will file the results of these tests in a 

report on or before February, 2013. In 

light of the discussion in NERC’s 

November 21 Comments,88 we accept 

NERC’s proposed plan to respond to the 

following three questions and direct 

NERC to include in the report: 

• A summary of the base cases used 

in applying the Attachment B criteria 

and an assessment of how the base cases 

used for the analysis relate to TPL–003– 

0, Requirement R1.3.2; 

• A discussion of the types of studies 

that planning coordinators may use to 

identify circuits under Attachment B; 

and 

• An assessment that demonstrates 

whether Attachment B is 

comprehensive enough to capture all 

circuits that could have an operational 

impact on the reliability of the bulk 

electric system in the context of 

transmission relay loadabilty. 

78. However, we are not persuaded by 

NERC’s statement that it is not 

necessary for NERC to include in the 

report a comparison of the results 

obtained using criterion B4 to the 

results that would be achieved based on 

assumptions consistent with 

Requirement R1. The 0.85 per unit and 

30 degrees power factor criteria in 

Requirement R1 is based on system 

conditions, voltage, current, and angle, 

observed prior to the cascading stage of 

the blackout. Although NERC states that 

criterion B4 was derived from these 

system criteria,89 the Commission is 

concerned that testing, which does not, 

at a minimum, compare whether criteria 

that do not consider voltage or angle 

affect the appropriate identification of 

applicable facilities, is not responsive to 

ensuring the reliability objective of the 

critical facilities test or the reliability 

objective of PRC–023. For these reasons, 

we direct NERC to evaluate, in the 

report, relay loadability under the B4 

criterion consistent with Requirement 

R1, which requires, in part, that NERC 

‘‘evaluate relay loadability at 0.85 per 

unit voltage and a power factor angle of 

30 degrees’’ in addition to applicable 

current data. 

B. NERC Rules of Procedure Section 

1700—Challenges to Determinations 

1. NERC Petition 

79. In its petition, NERC submitted 

new Rules of Procedure Section 1700— 

Challenges to Determinations, which 

sets out the procedure for a registered 

entity to challenge a determination by a 

planning coordinator under Reliability 

Standard PRC–023–2. 

2. NOPR 

80. In the NOPR, we proposed to 

approve NERC Rules of Procedure 

Section 1700, specifically proposed 

Rule 1702, finding that it addresses the 

Order No. 733 directives that NERC 

establish a mechanism for registered 

entities to challenge criticality 

determinations made by a planning 

coordinator. 

3. Comments 

81. No comments were filed 

concerning proposed Rules of Procedure 

Section 1700—Challenges to 

Determinations. 

4. Commission Determination 

82. NERC’s proposal is responsive to 

the Commission’s directive in Order No. 

733. Accordingly, we adopt our NOPR 

proposal and we approve, pursuant to 

section 215(f) of the FPA, NERC Rule of 

Procedure Section 1700—Challenges to 

Determinations as just, reasonable, not 

unduly discriminatory or preferential, 

in the public interest, and satisfying the 

requirements of section 215(c) of the 

FPA. 

V. Information Collection Statement 

83. The Office of Management and 

Budget (OMB) regulations require 

approval of certain information 

collection requirements imposed by 

agency rules.90 Upon approval of a 

collection(s) of information, OMB will 

assign an OMB control number and 

expiration date. Respondents subject to 

the filing requirement 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) 91

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.92

84. The Commission is submitting 

these reporting and recordkeeping 


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93Under its applicability provisions, proposed 

Reliability Standard applies to specified circuits 

such that very few, if any, generator owners that are 

not also a transmission owner and/or a distribution 

provider will be subject to the Standard. 

94The burden hours are based on estimates that 

the Commission has used for similar reporting 

requirements. 95This applies to the portion of R6 that deals with 

testing for sub-100 kV facilities as described in the 

text. In addition it includes burden hours associated 

with adding Regional Entities to the list of entities 

to receive a list of circuits from the planning 

coordinator. 

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. 

85. This Final Rule approves 

Reliability Standard PRC–023–2 

(Transmission Relay Loadability) which 

replaces currently effective Reliability 

Standard PRC–023–1 approved by the 

Commission in Order No. 733. Rather 

than creating entirely new requirements 

regarding the setting of protective 

relays, the revised Reliability Standard 

instead modifies and improves the 

existing Reliability Standard. Thus this 

Final Rule does not impose entirely new 

burdens on the effected entities. For 

example, the currently effective 

Reliability Standard PRC–023–1 

requires transmission owners, 

generation owners, and distribution 

providers to each have evidence to show 

that each of its transmission relays are 

set according to one of the criteria in 

criteria R1.1 through R1.13. Similarly, 

revised Reliability Standard PRC–023–2 

requires transmission owners, 

generation owners, and distribution 

providers to have evidence that each of 

its transmission relays is set according 

to one of the 13 criteria in Requirement 

R1 but adds that each such entity shall 

also have evidence that relays set 

according to criterion 10 do not expose 

the transformer to fault levels and 

durations beyond those indicated in the 

Standard. Thus, the recordkeeping 

obligations for some Requirements are 

more specific but not necessarily more 

expansive than those of currently 

effective Reliability Standard PRC–023– 

1. However, revised PRC–023–2 does 

add new Requirements, each of which 

has new recordkeeping obligations. 

86. Requirement R2 requires each 

transmission owner, generator owner, 

and distribution provider to have 

evidence that its out-of-step blocking 

elements are set in accordance with the 

Standard, and Requirements R4 and R5 

require those same entities to maintain 

evidence that they have informed the 

appropriate parties of their updated lists 

of certain circuits. Under Requirement 

R6, planning coordinators are required 

to execute a test for applicability of the 

Standard as set forth in Attachment B 

and retain analyses, calculation 

summaries, or study reports to evidence 

execution of the test, whereas under the 

currently effective PRC–023–1, a test 

was required but only the results 

needed to be retained. Because an 

unspecified test is currently required to 

be carried out on facilities operated at 

between 100 kV and 200 kV under 

currently effective Reliability Standard 

PRC–023–1, for purposes of this 

analysis, we assume that there is little 

additional cost for planning 

coordinators to implement and 

document that portion of the test. 

However, the Requirement R6 of the 

revised Standard imposes the new 

burdens of performing the test on sub100 kV facilities, maintaining 

appropriate records, and distributing the 

list of circuits identified by the test to 

Regional Entities. 

87. Public Reporting Burden: Our 

estimate below regarding the number of 

respondents is based on the NERC 

compliance registry as of January 26, 

2012. According to the NERC 

compliance registry, there are 337 

transmission owners, 858 generation 

owners, 554 distribution providers, and 

81 planning coordinators. However, 

under NERC’s compliance registration 

program, entities may be registered for 

multiple functions, so these numbers 

incorporate some double counting. The 

net number of entities responding will 

be approximately 660 entities registered 

as a transmission owner, a distribution 

provider, or a generation owner that is 

also a transmission owner and/or a 

distribution owner, and 81 planning 

coordinators.93 The estimated burden 

for the requirements in this Order 

follow: 

Changes to FERC–725G data collection Number of 

respondents 

annually 

Number of 

responses per 

respondent 

Average burden hours per response 94 Total annual 

hours 

(1) (2) (3) (1 × 2 × 3) 

R1 criterion 1.10: TOs, GOs, and DPs must analyze and document criterion 1.10 compliance.660 1 Analysis for compliance 

documents.

8 5,280 

........................ ........................ Record Retention ......... 2 1,320 

R2: TOs, GOs, and DPs must perform analysis 

and retain evidence of compliance.

660 1 Analysis for compliance 

documents.

8 5,280 

........................ ........................ Record Retention ......... 2 1,320 

R4 and R5: TOs, GOs, and DPs must distribute 

updated lists and retain evidence that lists 

were distributed.

660 1 Reporting (dist. of list) .. 10 6,600 

........................ ........................ Record Retention ......... 10 6,600 

R6: PC must perform assessment, distribute list 

of circuits and retain evidence of testing and 

distribution 95.

81 1 Reporting (assessment 

and dist. of list).

20 1,620 

........................ ........................ Record Retention ......... 10 810 

Total ............................................................... ........................ ........................ ....................................... ........................ 28,830 


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96The hourly reporting cost is based on the 

estimated cost of an engineer to implement the 

requirements of the rule. The record retention cost 

comes from Commission staff research on record 

retention requirements. 

97Regulations Implementing the National 

Environmental Policy Act, Order No. 486, 52 FR 

47897 (Dec. 17, 1987), FERC Stats. & Regs. 

Regulations Preambles 1986–1990 ¶ 30,783 (1987). 

98 18 CFR 380.4(a)(5). 

99 5 U.S.C. 601–612. 

100 13 CFR 121.101. 101 13 CFR 121.201, Sector 22, Utilities & n.1. 

Information Collection Costs: The 

Commission seeks comments on the 

costs to comply with these requirements 

and recordkeeping burden associated 

with Reliability Standard PRC–023–2. 

• Total Annual Hours for Collection: 

(Reporting and Record Retention) = 

28,830 hours. 

• Total Estimated Reporting/Analysis 

Cost = 18,780 hours @ $120/hour = 

$2,253,600. 

• Total Estimated Record Retention 

Cost = 10,050 hours @ $28/hour = 

$281,400. 

• Total Estimated Annual Cost 

(Reporting + Record Retention) 96 = 

$2,535,000. 

• Title: Mandatory Reliability 

Standards for the Bulk-Power System 

• Action: FERC 725G, Proposed 

Modification to FERC–725G. 

• OMB Control No: 1902–0252. 

• Respondents: Business or other for 

profit, and/or not for profit institutions. 

• Frequency of Responses: On 

occasion. 

• Necessity of the Information: This 

Final Rule approves a revised Reliability 

Standard that modifies an existing 

requirement regarding setting 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. Reliability 

Standard PRC–023–2 requires entities to 

set transmission relays according to 

specified criteria and to retain evidence 

of compliance. It also requires planning 

coordinators to implement a test to 

determine which sub-200 kV facilities 

are critical to the reliability of the power 

system and subjects such facilities to the 

requirements of the Standard. The 

revised Reliability Standard requires 

entities to maintain records subject to 

review by the Commission and NERC to 

ensure compliance with the Reliability 

Standard. 

• Internal review: The Commission 

has reviewed the requirements 

pertaining to the revised Reliability 

Standard for the Bulk-Power System 

and determined that the 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. 

88. Interested persons may obtain 

information on the reporting 

requirements by contacting: Federal 

Energy Regulatory Commission, 888 

First Street NE., Washington, DC 20426 

[Attention: Ellen Brown, Office of the 

Executive Director, email: 

DataClearance@ferc.gove, Phone: (202) 

502–8663, fax: (202) 273–0873]. 

Comments on the requirements of this 

order 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]. For security 

reasons, comments should be sent by 

email to OMB at 

oira_submission@omb.eop.gov. Please 

reference OMB Control Number 1902– 

0252 and the docket number of this 

Order in your submission. 

VI. Environmental Analysis 

89. 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.97 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.98 Accordingly, neither 

an environmental impact statement nor 

environmental assessment is required. 

VII. Regulatory Flexibility Act Analysis 

90. The Regulatory Flexibility Act of 

1980 (RFA) 99 generally requires a 

description and analysis of proposed 

and final rules that will have significant 

economic impact on a substantial 

number of small entities. The RFA 

mandates consideration of regulatory 

alternatives that accomplish the stated 

objectives of a proposed order and that 

minimize any significant economic 

impact on a substantial number of small 

entities. The Small Business 

Administration’s (SBA) Office of Size 

Standards develops the numerical 

definition of a small business.100 The 

SBA has established a size standard for 

electric utilities, stating that a firm is 

small if, including its affiliates, it is 

primarily engaged in the transmission, 

generation and/or distribution of 

electric energy for sale and its total 

electric output for the preceding twelve 

months did not exceed four million 

megawatt-hours.101

91. Reliability Standard PRC–023–2 

modifies currently existing Reliability 

Standard PRC–023–1 which requires 

applicable entities to set protective 

relays according to specific criteria, to 

communicate about such settings with 

specified entities, and to conduct 

assessments to determine the 

applicability of the Standard to 100–200 

kV facilities. The revised Standard 

modifies PRC–023–1 by (1) increasing 

communication and documentation 

requirements, (2) extending the 

applicability of the Standard to formerly 

excluded relays, and (3) standardizing 

the terms of the assessment whose terms 

were formerly not specified. In addition, 

PRC–023–2 extends the current 

requirement that planning coordinators 

annually assess which 100–200 kV 

circuits must be brought into 

compliance with the Standard and will 

require planning coordinators to carry 

out the assessment with respect to some 

sub-100 kV facilities. 

92. Comparison of the NERC 

compliance registry with data submitted 

to the Energy Information 

Administration on Form EIA–861 

indicates that perhaps as many as 108 

transmission owners, 327 distribution 

providers, 52 generation owners, and 14 

planning coordinators qualify as small 

entities. However, under NERC’s 

compliance registration program, 

entities may be registered for multiple 

functions, so these numbers incorporate 

some double counting. The net number 

of registered entities that qualify as 

small entities responding to this rule 

will be approximately 339 entities 

registered as a transmission owner, a 

distribution provider, or a generation 

owner that is also a transmission owner 

and/or a distribution provider, and 8 

planning coordinators. The Final Rule 

directly affects each of the small 

entities. Therefore, FERC has 

determined that this Final Rule will 

have an impact on a substantial number 

of small entities. However, the 

Commission has determined that the 

impact on entities affected by the Final 

Rule will not be significant. The 

Commission estimates that in order to 

comply with the Standard’s 

modification of existing requirements 

each of the small entities registered as 

planning coordinators will face a cost of 

$2,680 and each of the remaining small 

entities (transmission owners, 

distribution providers, or generation 


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1The table heading was recently revised to read 

‘‘California—NO2 (1971 Annual Standard)’’ in a 

final rule published on February 17, 2012 at 77 FR 

9532, at 9540, effective February 29, 2012. The table 

heading previously had been ‘‘California-NO2.’’ 

owners that are also transmission 

owners and/or distribution providers) 

will face a cost of $3,512. Accordingly, 

the Commission determines that the 

incremental cost of Reliability Standard 

PRC–023–2 (going from PRC–023–1 to 

PRC–023–2) is minimal, and should not 

present a significant operating cost to 

any of the small entities. 

93. Based on this understanding, the 

Commission certifies that this 

Reliability Standard will not have a 

significant economic impact on a 

substantial number of small entities. 

Accordingly, no regulatory flexibility 

analysis is required. 

VIII. Document Availability 

94. 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. 

95. 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. 

96. 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 email at 

ferconlinesupport@ferc.gov, or the 

Public Reference Room at (202) 502– 

8371, TTY (202) 502–8659. Email the 

Public Reference Room at 

public.referenceroom@ferc.gov. 

By the Commission. 

Nathaniel J. Davis, Sr., 

Deputy Secretary. 

[FR Doc. 2012–6758 Filed 3–20–12; 8:45 am] 

BILLING CODE 6717–01–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 81 

[EPA–R09–OAR–2012–0189; FRL–9649–1] 

Approval and Promulgation of 

Implementation Plans; Designation of 

Areas for Air Quality Planning 

Purposes; State of California; Ozone; 

Nitrogen Dioxide; Technical 

Amendments 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule; technical 

amendments. 

SUMMARY: EPA is making technical 

amendments to the Code of Federal 

Regulations (CFR) to reflect the final 

actions published by the Agency on 

October 7, 2003, April 30, 2004, and 

May 5, 2010 in connection with the 

designations and classifications of 

certain areas in California for the 1971 

annual nitrogen dioxide standard and 

the 1997 eight-hour ozone standard 

pursuant to the Clean Air Act. The areas 

that are the subject of these technical 

amendments include Riverside County, 

Western Mojave Desert, South Coast Air 

Basin, Eastern Kern County, and San 

Diego County. 

DATES: These technical amendments are 

effective on March 21, 2012. 

FOR FURTHER INFORMATION CONTACT: 

Doris Lo, EPA Region IX, (415) 972– 

3959, lo.doris@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Technical Amendment for California— 

NO2 Table in 40 CFR 81.305 

In today’s action, we are making a 

technical amendment to correct an 

erroneous codification of our 2003 

boundary change rule with respect to 

the ‘‘California—NO2 (1971 Annual 

Standard)’’ table in 40 CFR 81.305.1 As 

described in our October 7, 2003 final 

rule (68 FR at 57821 and 57824) 

redesignating certain air quality 

planning area boundaries in southern 

California, we intended to revise the 

entry in the table for ‘‘Riverside County 

(portion within SE. Desert AQMD) 

County’’ to ‘‘Riverside County 

(Coachella Valley planning area)’’ and to 

revise the entry for ‘‘Riverside County, 

non-AQMA portion County’’ to 

‘‘Riverside County (portion not within 

South Coast Air Basin or Coachella 

Valley planning area).’’ However, the 

entry for ‘‘Riverside County (Coachella 

Valley planning area),’’ which was to 

become an entry in the table, is not 

found in the current version of the 

‘‘California—NO2 (1971 Annual 

Standard)’’ table whereas the entry for 

‘‘Riverside County, non-AQMA portion 

County,’’ which was intended to be 

replaced, remains in the table. In today’s 

action, we are making a technical 

amendment to ensure that the 

‘‘California—NO2 (1971 Annual 

Standard)’’ table in 40 CFR 81.305 to 

accurately reflect the intent of our 2003 

boundary change action. 

Today’s technical amendment makes 

no change to the substance of our 

October 7, 2003 final rule. 

Technical Amendments for California— 

Ozone (8-Hour Standard) Table in 40 

CFR 81.305 

With respect to the ‘‘California— 

Ozone (8-Hour Standard)’’ table in 40 

CFR 81.305, we are making a number of 

technical amendments that stem from 

previous EPA rulemakings. All of the 

subject areas are located within the 

State of California. 

On April 30, 2004, at 69 FR 23858, we 

published a final rule announcing and 

promulgating designations, 

classifications, and boundaries for areas 

in the country with respect to the 1997 

8-hour ozone National Ambient Air 

Quality Standard (NAAQS) in 

accordance with the requirements of the 

Clean Air Act (CAA). In our April 30, 

2004 final rule, we designated the 

Western Mojave Desert area as a 

moderate nonattainment area for the 

1997 8-hour ozone National Ambient 

Air Quality Standard. See 69 FR 23858, 

at 23884–85 (April 30, 2004). 

Subsequently, on May 5, 2010, EPA 

published a final rule granting 

California’s request for reclassification 

of several areas for the 1997 8-hour 

ozone standard. See 75 FR 24409 (May 

5, 2010). The Western Mojave Desert 

was not among the areas that were the 

subject of EPA’s May 5, 2010 final rule, 

but the changes made to the 

‘‘California—Ozone (8-Hour Standard)’’ 

table to codify our May 5, 2010 final 

rule had the inadvertent effect of 

removing a portion of the definition of 

the Western Mojave Desert 8-hour ozone 

nonattainment area from the 

‘‘California—Ozone (8-Hour Standard)’’ 

table. In today’s action, EPA is making 

a technical amendment to re-insert the 

inadvertently removed portion of the 

definition of the Western Mojave Desert 

area into the ‘‘California—Ozone (8- 

Hour Standard)’’ table in 40 CFR 81.305. 

Second, in codifying the designations 

in EPA’s April 30, 2004 final rule, we 

inadvertently indented the title of the 


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