72910 Federal Register / Vol. 75, No. 227 / Friday, November 26, 2010 / Rules and Regulations 

1 16 U.S.C. 824o. 2Revision to Electric Reliability Organization 

Definition of Bulk Electric System, Notice of 

Proposed Rulemaking, 75 FR 14097 (Mar. 24, 2010), 

FERC Stats. & Regs. ¶ 32,654 (2010). 

DEPARTMENT OF ENERGY 

Federal Energy Regulatory 

Commission 

18 CFR Part 40 

[Docket No. RM09–18–000; Order No. 743] 

Revision to Electric Reliability 

Organization Definition of Bulk Electric 

System 

Issued November 18, 2010. 

AGENCY: Federal Energy Regulatory 

Commission. 

ACTION: Final rule. 

SUMMARY: In this Final Rule, pursuant to 

section 215 of the Federal Power Act 

(FPA),1 the Federal Energy Regulatory 

Commission (Commission) adopts, with 

modifications, the proposal outlined in 

its March 18, 2010 Notice of Proposed 

Rulemaking to require the Electric 

Reliability Organization (ERO) to revise 

its definition of the term ‘‘bulk electric 

system.’’ 2 The Commission directs the 

ERO, through the ERO’s Reliability 

Standards Development Process, to 

revise the definition to address the 

Commission’s technical concerns, as 

discussed fully below, and ensure that 

the definition encompasses all facilities 

necessary for operating an 

interconnected electric transmission 

network. The Commission believes that 

the best way to accomplish these goals 

is to eliminate the regional discretion in 

the current definition, maintain a brightline threshold that includes all facilities 

operated at or above 100 kV except 

defined radial facilities, and establish an 

exemption process and criteria for 

excluding facilities that are not 

necessary for operating the 

interconnected transmission network. 

However, this Final Rule allows the 

ERO, in accordance with Order No. 693, 

to develop an alternative proposal for 

addressing the Commission’s concerns 

with the present definition with the 

understanding that any such alternative 

must be as effective as, or more effective 

than, the Commission’s proposed 

approach in addressing the identified 

technical and other concerns, and may 

not result in a reduction in reliability. 

DATES: Effective Date: This Final Rule 

will become effective January 25, 2011. 

FOR FURTHER INFORMATION CONTACT: 

Robert V. Snow (Technical Information), 

Office of Electric Reliability, Division 

of Reliability Standards, Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 

20426, Telephone: (202) 502–6716. 

Patrick A. Boughan (Technical 

Information), Office of Electric 

Reliability, Division of Reliability and 

Engineering Services, Federal Energy 

Regulatory Commission, 888 First 

Street, NE., Washington, DC 20426, 

Telephone: (202) 502–8071. 

Jonathan E. First (Legal Information), 

Office of the General Counsel, Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 

20426, Telephone: (202) 502–8529. 

Mindi Sauter (Legal Information), Office 

of the General Counsel, Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 

20426, Telephone: (202) 502–6830. 

SUPPLEMENTARY INFORMATION: 

Table of Contents 

Paragraph 

No. 

I. Background ............................................................................................................................................................................................ 3 

A. Section 215 of the FPA .................................................................................................................................................................... 3 

B. Order No. 693 ................................................................................................................................................................................... 5 

C. NERC’s June 14, 2007 Filing ........................................................................................................................................................... 8 

D. NPCC’s Identification of Bulk Electric System Facilities .............................................................................................................. 11 

E. Notice of Proposed Rulemaking ...................................................................................................................................................... 13 

II. Discussion ............................................................................................................................................................................................ 16 

A. Overview .......................................................................................................................................................................................... 16 

1. Definition of Bulk Electric System ............................................................................................................................................... 17 

(a) Commission Authority ............................................................................................................................................................. 17 

(1) Comments ............................................................................................................................................................................. 18 

(i) NERC Standards Development Process and Deference to NERC and the Regional Entities ........................................ 19 

(ii) Bulk-Power System .......................................................................................................................................................... 24 

(iii) Distribution Facilities ...................................................................................................................................................... 26 

(2) Commission Determination .................................................................................................................................................. 29 

(i) Overview ............................................................................................................................................................................ 29 

(ii) NERC Standards Development Process and Deference to NERC and the Regional Entities ....................................... 34 

(iii) Bulk-Power System ......................................................................................................................................................... 36 

(iv) Distribution Facilities ...................................................................................................................................................... 37 

(b) Scope of the Definitional Change of ‘‘Bulk Electric System’’ ................................................................................................ 42 

(1) NOPR Proposal ..................................................................................................................................................................... 42 

(2) Comments ............................................................................................................................................................................. 43 

(3) Commission Determination .................................................................................................................................................. 52 

(c) Technical and Historical Justification for Modification ........................................................................................................ 56 

(1) NOPR Proposal ..................................................................................................................................................................... 56 

(2) Comments ............................................................................................................................................................................. 58 

(3) Commission Determination .................................................................................................................................................. 72 

(i) Impact-Based Methodology and Regional Variation ....................................................................................................... 76 

(ii) FRCC Event ....................................................................................................................................................................... 87 

(iii) ReliabilityFirst Event ....................................................................................................................................................... 88 

(iv) Astoria West Event .......................................................................................................................................................... 89 

(v) Relevance of TLR .............................................................................................................................................................. 90 

(vi) International Concerns .................................................................................................................................................... 91 

(4) Summary ............................................................................................................................................................................... 96 

(d) Usage and Definition of ‘‘Bulk-Power System’’ ...................................................................................................................... 97 

(1) Comments ............................................................................................................................................................................. 97 

(2) Commission Determination .................................................................................................................................................. 100 


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Federal Register / Vol. 75, No. 227 / Friday, November 26, 2010 / Rules and Regulations 72911 

3 16 U.S.C. 824o. 

4Revision to Electric Reliability Organization 

Definition of Bulk Electric System, Notice of 

Proposed Rulemaking, 75 FR 14097 (Mar. 24, 2010), 

FERC Stats. & Regs. ¶ 32,654 (2010). 

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

¶ 31,242, at P 31 (2007), order on reh’g, Order No. 

693–A, 120 FERC ¶ 61,053 (2007). 

6See, e.g., Version One Regional Reliability 

Standard for Resource and Demand Balancing, 133 

FERC ¶ 61,063, at P 14 (2010) (Noting the 

Commission’s concern that approving a proposed 

Reliability Standard may result in reduced 

reliability). In addition, as a general matter, any 

proposed regional difference must be: (1) More 

stringent than the continent-wide definition, 

including a regional difference that addresses 

matters that the continent-wide Reliability Standard 

does not, or (2) necessitated by a physical difference 

in the Bulk-Power System. See Rules Concerning 

Certification of the Electric Reliability Organization; 

and Procedures for the Establishment, Approval, 

and Enforcement of Electric Reliability Standards, 

Order No. 672, FERC Stats. & Regs. ¶ 31,204, at P 

291 (2006), order on reh’g, Order No. 672–A, FERC 

Stats. & Regs. ¶ 31,212 (2006). 

7Public Law 109–58, Title XII, Subtitle A, 119 

Stat. 594, 941 (2005) (codified at 16 U.S.C. 824o). 

8See 16 U.S.C. 824o(e)(3). 

Paragraph 

No. 

2. Exemption Process ........................................................................................................................................................................ 101 

(a) Comments ................................................................................................................................................................................. 102 

(b) Commission Determination ..................................................................................................................................................... 111 

3. Transition Process ......................................................................................................................................................................... 122 

(a) Comments ................................................................................................................................................................................. 123 

(b) Commission Determination ..................................................................................................................................................... 131 

4. Cost Recovery ................................................................................................................................................................................ 133 

(a) Comments ................................................................................................................................................................................. 133 

(b) Commission Determination ..................................................................................................................................................... 134 

5. Issues Regarding the Western Interconnection ........................................................................................................................... 135 

(a) Comments ................................................................................................................................................................................. 135 

(b) Commission Determination ..................................................................................................................................................... 139 

6. Impact on Generation Owners and Operators ............................................................................................................................. 142 

(a) Comments ................................................................................................................................................................................. 142 

(b) Commission Determination ..................................................................................................................................................... 144 

7. Clarifying Terms ............................................................................................................................................................................ 146 

(a) Comments ................................................................................................................................................................................. 146 

(b) Commission Determination ..................................................................................................................................................... 149 

III. Information Collection Statement ...................................................................................................................................................... 151 

IV. Environmental Analysis ..................................................................................................................................................................... 158 

V. Regulatory Flexibility Act Analysis .................................................................................................................................................... 161 

A. NOPR Proposal ................................................................................................................................................................................. 166 

B. Comments ......................................................................................................................................................................................... 167 

C. Commission Determination ............................................................................................................................................................. 169 

VI. Document Availability ....................................................................................................................................................................... 170 

VII. Effective Date and Congressional Notification ................................................................................................................................ 173 

Before Commissioners: Jon Wellinghoff, 

Chairman; Marc Spitzer, Philip D. 

Moeller, John R. Norris, and Cheryl 

A. LaFleur. 

1. In this Final Rule, pursuant to 

section 215 of the FPA,3 the 

Commission adopts, with modifications 

described below, the proposal set forth 

in its March 18, 2010 Notice of 

Proposed Rulemaking (NOPR) requiring 

the Electric Reliability Organization 

(ERO) to revise its definition of the term 

‘‘bulk electric system.’’ 4 The 

Commission directs the ERO, through 

the ERO’s Reliability Standards 

Development Process, to revise the 

definition to address the Commission’s 

technical concerns, as discussed fully 

below, and ensure that the definition 

encompasses all facilities necessary for 

operating an interconnected electric 

transmission network. The Commission 

believes that the best way to accomplish 

these goals is to eliminate the regional 

discretion in the current definition, 

maintain a bright-line threshold that 

includes all facilities operated at or 

above 100 kV except defined radial 

facilities, and establish an exemption 

process and criteria for excluding 

facilities that are not necessary for 

operating the interconnected 

transmission network. However, this 

Final Rule allows the ERO, in 

accordance with Order No. 693, to 

develop an alternative proposal for 

addressing the Commission’s concerns 

with the present definition with the 

understanding that any such alternative 

must be as effective as, or more effective 

than,5 the Commission’s proposed 

approach in addressing the identified 

technical and other concerns, and may 

not result in a reduction in reliability.6

2. In Order No. 693, the Commission 

noted its concern that the current ‘‘bulk 

electric system’’ definition has the 

potential for gaps in coverage of 

facilities, and indicated that it would 

revisit the issue. This Final Rule is the 

next step towards addressing the 

Commission’s concerns. The approved 

changes will help ensure reliability and 

consistency in the bulk electric system 

classification throughout the 

interconnected United States. The 

Commission takes this action as a 

continuation of Order No. 693’s efforts 

to ensure that the mandatory Reliability 

Standards fulfill the intent of Congress 

in enacting section 215 of the FPA to 

protect reliability of the nation’s BulkPower System. The aim of the Final 

Rule is to eliminate inconsistencies 

across regions, eliminate the ambiguity 

created by the current discretion in 

NERC’s definition of bulk electric 

system, provide a backstop review to 

ensure that any variations do not 

compromise reliability, and ensure that 

facilities that could significantly affect 

reliability are subject to mandatory 

rules. The Commission is not adding 

any new or modified text to its 

regulations. 

I. Background 

A. Section 215 of the FPA 

3. On August 8, 2005, the Energy 

Policy Act of 2005 (EPAct 2005) was 

enacted into law. Title XII of EPAct 

2005 added a new section 215 to the 

FPA,7 which requires a Commissioncertified ERO to develop mandatory and 

enforceable Reliability Standards, 

subject to Commission review and 

approval. Once approved, the Reliability 

Standards may be enforced by the ERO, 

subject to Commission oversight, or by 

the Commission independently.8


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72912 Federal Register / Vol. 75, No. 227 / Friday, November 26, 2010 / Rules and Regulations 

9Order No. 672, FERC Stats. & Regs. ¶ 31,204, 

order on reh’g, Order No. 672–A, FERC Stats. & 

Regs. ¶ 31,212. 

10North American Electric Reliability Corp., 116 

FERC ¶ 61,062, order on reh’g and compliance, 117 

FERC ¶ 61,126 (2006) (certifying NERC as the ERO 

responsible for the development and enforcement of 

mandatory Reliability Standards), aff’d sub nom. 

Alcoa Inc. v. FERC, 564 F.3d 1342 (D.C. Cir. 2009). 

11 See Order No. 693, FERC Stats. & Regs. 

¶ 31,242 (directing improvements to 56 of the 83 

approved Reliability Standards and leaving 24 

Reliability Standards as pending until further 

information is provided), order on reh’g, Order No. 

693–A, 120 FERC ¶ 61,053 (2007). 

12Order No. 693, FERC Stats. & Regs. ¶ 31,242 at 

P 76. 

13Order No. 693, FERC Stats. & Regs. ¶ 31,242 at 

P 75 n.47 (quoting NERC’s definition of ‘‘bulk 

electric system’’). 

14 Id. P 75; see also Order No. 693–A, 120 FERC 

¶ 61,053 at P 19 (‘‘the Commission will continue to 

rely on NERC’s definition of bulk electric system, 

with the appropriate regional differences, and the 

registration process until the Commission 

determines in future proceedings the extent of the 

Bulk-Power System’’). 

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

P 77 (footnotes omitted). For example, the 

Commission noted that some regional definitions of 

bulk electric system exclude facilities below 230 kV 

and transmission lines that serve Washington, DC 

and New York City and the Commission stated its 

intent to address this matter in a future proceeding. 

Id. 

16NERC Informational Filing in Response to 

Paragraph 77 of Order No. 693, Docket No. RM06– 

16–000 (Jun. 14, 2007) (June 2007 Filing). 

17 Id. at 7. NERC also noted that the Texas 

Regional Entity, Florida Reliability Coordinating 

Council (FRCC), Midwest Reliability Organization, 

and SERC Reliability Corporation use the NERC 

definition of bulk electric system without 

modification. In a supplemental filing, NERC 

informed the Commission that Western Electricity 

Coordinating Council (WECC) uses the NERC 

definition alone in its implementation of Regional 

Entity activities. See NERC Supplemental 

Informational Compliance Filing, Docket No. 

RM06–16–000 (Mar. 6, 2009). Three other Regional 

Entities, ReliabilityFirst Corporation 

(ReliabilityFirst), Southwest Power Pool (SPP 

Regional Entity), and Northeast Power Coordinating 

Council, Inc. (NPCC), stated that they use the NERC 

definition supplemented with additional criteria. 

For example, SPP Regional Entity indicated that it 

uses the criteria specified in the NERC Statement 

of Registry Criteria (with one exception). 

ReliabilityFirst supplemented the NERC definition 

with specific voltage-based inclusions and 

exclusions. For example, ReliabilityFirst includes 

‘‘lines operated at voltage of 100 kV or higher.’’ June 

2007 Filing at 10. ReliabilityFirst excludes certain 

radial facilities, balance of generating plant control 

and operation functions, and ‘‘all other facilities 

operated at voltages below 100 kV.’’ 

18 June 2007 Filing at 7. 

19 ‘‘The interconnected electrical systems within 

northeastern North America comprised of system 

elements on which faults or disturbances can have 

a significant adverse impact outside of the local 

area.’’ Id., Attachment 1 (NPCC Document A–10, 

Classification of Bulk Power System Elements (Apr. 

28, 2007)). 

20 Id. 

21North American Electric Reliability Corp., 125 

FERC ¶ 61,295 (2008) (December 2008 Order). 

22NERC and NPCC Compliance Filing at 5, 

Docket No. RC09–3–000 (Feb. 20, 2009). The 

February 20 Compliance Filing also indicated that 

the NPCC approved list of bulk electric system 

elements was not developed pursuant to NPCC’s 

Document A–10, Classification of Bulk Power 

System Elements, identified in the June 2007 Filing. 

4. In February 2006, the Commission 

issued Order No. 672 9 in which the 

Commission certified one organization, 

the North American Electric Reliability 

Corporation (NERC), as the ERO.10

B. Order No. 693 

5. On March 16, 2007, in Order No. 

693, pursuant to section 215(d) of the 

FPA,11 the Commission approved 83 of 

107 proposed Reliability Standards, six 

of the eight proposed regional 

differences, and the Glossary of Terms 

Used in Reliability Standards developed 

by NERC, the Commission-certified 

ERO. In addition, Order No. 693 

addressed the applicability of 

mandatory Reliability Standards to the 

statutorily defined Bulk-Power System. 

6. In Order No. 693, the Commission 

explained that section 215(a) of the FPA 

broadly defines the Bulk-Power System 

as: 

Facilities and control systems necessary for 

operating an interconnected electric energy 

transmission network (or any portion thereof) 

[and] electric energy from generating 

facilities needed to maintain transmission 

system reliability.12

The Commission also approved 

NERC’s definition of ‘‘bulk electric 

system,’’ which is an integral part of the 

NERC Reliability Standards and is 

included in the NERC Glossary of Terms 

Used in Reliability Standards (NERC 

Glossary): 

As defined by the Regional Reliability 

Organization, the electrical generation 

resources, transmission lines, 

interconnections with neighboring systems, 

and associated equipment, generally operated 

at voltages of 100 kV or higher. Radial 

transmission facilities serving only load with 

one transmission source are generally not 

included in this definition.13

7. The Commission approved NERC’s 

definition of ‘‘bulk electric system’’ with 

reservations. The Commission stated in 

Order No. 693 that, ‘‘at least for an 

initial period, the Commission will rely 

on the NERC definition of ‘bulk electric 

system’ and NERC’s registration process 

to provide as much certainty as possible 

regarding the applicability to and the 

responsibility of specific entities to 

comply with the Reliability 

Standards.’’ 14 In approving the use of 

NERC’s definition of ‘‘bulk electric 

system,’’ the Commission stated that ‘‘[it] 

remains concerned about the need to 

address the potential for gaps in 

coverage of facilities.’’ 15

C. NERC’s June 14, 2007 Filing 

8. In a June 14, 2007 filing, NERC 

submitted the regional definitions of 

‘‘bulk electric system.’’ 16 NERC 

represented that ‘‘[e]ach Regional Entity 

utilizes the definition of bulk electric 

system in the [NERC Glossary of Terms 

Used in Reliability Standards]; however, 

as permitted by that definition * * * 

several Regional Entities define specific 

characteristics or criteria that the 

Regional Entity uses to identify the bulk 

electric system facilities for its 

members.[17] In addition, the Reliability 

Standards apply to load shedding and 

special protection relay facilities below 

100 kV, which are monitored by 

Regional Entities, in compliance with 

NERC’s Reliability Standards.’’ 18

9. As noted in the NOPR, NERC’s June 

2007 Filing indicated that NPCC uses 

the NERC definition of ‘‘bulk electric 

system’’ supplemented by additional 

criteria. Unlike the supplemental 

criteria of other Regional Entities, 

however, NPCC utilizes a significantly 

different approach to identifying bulk 

electric system elements. According to 

NERC, NPCC identifies elements of the 

bulk electric system using an impactbased methodology, as opposed to a 

voltage-based methodology. Further, as 

part of its approach to defining the ‘‘bulk 

electric system,’’ NPCC includes its own 

definition of ‘‘bulk power system.’’ 19

10. According to NERC, NPCC 

analyzes all system elements within its 

footprint regardless of size (voltage) to 

determine their impact based on its 

‘‘bulk electric system’’ definition. NPCC 

also utilizes a guidance document, 

which provides further information on 

the NPCC definition of ‘‘bulk power 

system’’ and how it is applied.20

D. NPCC’s Identification of Bulk Electric 

System Facilities 

11. In a December 2008 Order, the 

Commission directed NERC and NPCC 

to submit to the Commission a 

comprehensive list of bulk electric 

system facilities located within the 

United States portion of the NPCC 

region.21 The Commission explained 

that there appeared to be conflicting 

lists of bulk electric system elements 

developed by one of the balancing 

authorities in the United States portion 

of the NPCC region and it was not clear 

which, if any, of the lists were 

submitted to NPCC or approved by 

NPCC’s Task Force on System Studies. 

In a compliance filing, NERC and NPCC 

indicated that the ‘‘NPCC Approved 

Bulk Electric System List’’ of June 2007 

was the only listing of bulk electric 

system facilities approved by NPCC and 

is the current list of facilities within the 

U.S. portion of NPCC to which the 

NERC Reliability Standards apply.22


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Federal Register / Vol. 75, No. 227 / Friday, November 26, 2010 / Rules and Regulations 72913 

Rather, the approved NPCC list was developed 

pursuant to an earlier version of the NPCC impactbased methodology. 23 In addition, NPCC excludes approximately 

seven higher voltage (e.g., 230 kV, 345 kV and 500 

kV) transmission facilities, some connecting to 

nuclear power plants. 24NERC and NPCC Compliance Filing and 

Assessment of Bulk Electric System Report, Docket 

No. RC09–3–000 (Sep. 21, 2009). NPCC would 

define ‘‘radial portions of the transmission system 

to include (1) an area serving load that is connected 

to the rest of the network at a single transmission 

substation at a single transmission voltage by one 

or more transmission circuits; (2) tap lines and 

associated facilities which are required to serve 

local load only; (3) transmission lines that are 

operated open for normal operation; or (4) 

additionally as an option, those portions of the 

NPCC transmission system operated at 100 kV or 

higher not explicitly designated as a bulk electric 

system path for generation which have a one 

percent or less participation in area, regional or 

inter regional power transfers. Id. at 11. 

25 Id. at 7–8; see also id. at 14 (‘‘If directed by the 

Commission to adopt the developed [bulk electric 

system] definition for U.S. Registered Entities 

within the NPCC footprint, NPCC would need 

additional time to carefully consider and develop 

a more extensive and detailed implementation 

plan.’’). 

26See 75 FR 14097 (Mar. 24, 2010). 

27A list of commenters appears in Appendix A. 

28See, e.g., APPA/NRECA, NYPSC, NYSRC, EEI, 

Joint Western Commenters, NERC, Snohomish, 

Tacoma Power, and PGE. Note that although the 

parties we have identified as the ‘‘Joint Western 

Commenters’’ submitted separate comments, the 

comments were virtually identical. Consequently, 

we cite their comments as a single group. 

The filing indicated that a majority of 

the 115 kV and 138 kV transmission 

facilities in the NYISO Balancing 

Authority Area of the NPCC region are 

excluded from the NPCC list of bulk 

electric system facilities, including 

those associated with nuclear power 

plants, and thus are excluded from 

compliance with mandatory Reliability 

Standards.23 The information provided 

by NPCC also indicated that numerous 

transmission lines at 100 kV or above 

that interconnect with registered 

generation facilities are excluded from 

NPCC’s list of bulk electric system 

facilities. 

12. In September 2009, NERC and 

NPCC submitted a compliance filing in 

which NPCC evaluated the impact and 

usefulness of a 100 kV ‘‘bright-line’’ 

‘‘bulk electric system’’ definition as well 

as another optional method, which 

utilizes Transmission Distribution 

Factor calculations to determine 

reliability impacts. The NPCC definition 

would exclude radial network portions 

of the transmission system, as opposed 

to radial lines.24 However, NPCC stated 

that it continues to believe that its 

current impact-based approach provides 

an adequate level of reliability and, 

therefore, intends to continue to apply 

the impact-based approach in 

classifying its bulk electric system 

elements.25

E. Notice of Proposed Rulemaking 

13. On March 18, 2010, the 

Commission issued a NOPR proposing 

to direct NERC to revise the definition 

of ‘‘bulk electric system’’ in the NERC 

Glossary. The current ‘‘bulk electric 

system’’ definition provides Regional 

Entities discretion to define ‘‘bulk 

electric system,’’ including the ability to 

exclude facilities 100 kV or above, 

without ERO or Commission oversight. 

The Commission’s proposed revised 

definition would continue to include all 

facilities rated above 100 kV and 

eliminate regional variations, providing 

a consistent identification of bulk 

electric system facilities across the 

nation’s reliability regions. The proposal 

called for Commission and NERC 

approval for exempting facilities that 

would otherwise qualify as part of the 

bulk electric system on a facility-byfacility basis. 

14. The NOPR identified 

inconsistencies between regions that 

resulted from the existing definition, 

such as NPCC not including two 115 kV 

transmission lines as part of the bulk 

electric system in its region even though 

the sections of these same lines that 

connect to PJM’s balancing authority 

area are considered bulk electric system 

elements within the ReliabilityFirst 

footprint. As an additional example, 

seven higher voltage (e.g., 230 kV, 345 

kV, and 500 kV) transmission facilities 

(some connecting to nuclear power 

plants) excluded from the list of bulk 

electric system facilities in NPCC would 

be included in other regions. Further, 

the NOPR provided several examples of 

disturbances that either began on or 

were propagated by 100–200 kV 

facilities including a February 26, 2008 

event in FRCC originating at a 138 kV 

facility that resulted in the loss of 24 

transmission lines and 4,300 MW of 

generation. 

15. The Commission issued the NOPR 

on March 18, 2010, and required that 

comments be filed within 45 days after 

publication in the Federal Register.26

More than eighty comments and reply 

comments to the NOPR proposal were 

submitted to the Commission.27 Upon 

consideration of the comments, the 

Commission modifies certain proposals 

from the NOPR in this Final Rule, as 

described below. 

II. Discussion 

A. Overview 

16. After consideration of the 

comments submitted, the Commission 

adopts the NOPR’s proposal with some 

modifications. The Commission directs 

the ERO to revise the definition of ‘‘bulk 

electric system’’ through the NERC 

Standards Development Process to 

address the Commission’s concerns 

discussed herein. The Commission 

believes the best way to address these 

concerns is to eliminate the Regional 

Entities’ discretion to define ‘‘bulk 

electric system’’ without ERO or 

Commission review, maintain a brightline threshold that includes all facilities 

operated at or above 100 kV except 

defined radial facilities, and adopt an 

exemption process and criteria for 

excluding facilities that are not 

necessary to operate an interconnected 

electric transmission network. However, 

NERC may propose a different solution 

that is as effective as, or superior to, the 

Commission’s proposed approach in 

addressing the Commission’s technical 

and other concerns so as to ensure that 

all necessary facilities are included 

within the scope of the definition. 

1. Definition of Bulk Electric System 

(a) Commission Authority 

17. In the NOPR, the Commission 

proposed, pursuant to section 215(d)(5) 

of the FPA and § 39.5(f) of our 

regulations, to require NERC to submit 

a revised NERC definition of ‘‘bulk 

electric system’’ that provides a 100 kV 

threshold for facilities that are included 

in the bulk electric system and 

eliminates the currently-allowed 

discretion of a Regional Entity to define 

‘‘bulk electric system’’ within its system 

without NERC or Commission oversight. 

(1) Comments 

18. Several commenters argue that the 

Commission’s proposal exceeds its 

statutory authority.28 Other commenters 

contend that the Commission’s proposal 

is inconsistent with the statutory regime 

envisioned in section 215 of the FPA, 

requiring the Commission to defer to the 

ERO on technical issues and for the ERO 

to have primary responsibility for 

developing specific Reliability 

Standards. 

(i) NERC Standards Development 

Process and Deference to NERC and the 

Regional Entities 

19. NERC supports the Commission’s 

objectives of ensuring a common 

understanding and consistent 

application of ‘‘bulk electric system’’ 

across the regions, while allowing 

variations to the definition based on 

reliability. However, NERC objects to 

the Commission making unilateral 

decisions with respect to the definition, 

as it did in the NOPR, rather than 

allowing this issue to be addressed 

through the NERC Reliability Standards 


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72914 Federal Register / Vol. 75, No. 227 / Friday, November 26, 2010 / Rules and Regulations 

29NERC at 8–11. 

30TAPS at 4; see also Snohomish at 22–28. 

31NYSRC at 7–8. 

32See, e.g., NYPSC, NYSRC, Duke Energy, 

Indicated New York Transmission Owners, 

Snohomish and Joint Western Commenters. 

33NYSRC at 7. 

34See, e.g., Constellation/CENG, Dow, Duke 

Energy, GTC/GSOC, Hydro-Que ́bec, Indicated New 

York Transmission Owners, Joint Western 

Commenters, NARUC, NV Energy, NYSRC, PGE, 

Public Power Council, Snohomish Tacoma Power, 

TIEC. 

35See, e.g., Snohomish at 20–22; PGE at 3–6; 

Tacoma Power at 2–3. 

36Snohomish at 20–21 (citing Order No. 693, 

FERC Stats. and Regs. ¶ 31,242 at P 23 n.20). 

Development Process.29 NERC states 

that the NERC Glossary of Terms is partand-parcel of the Reliability Standards 

and therefore falls under the same 

section 215 process. NERC argues that 

the Commission may order the ERO, 

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

FPA, to submit a proposed Reliability 

Standard or modification to a Reliability 

Standard to the Commission. Following 

this submission, NERC continues, the 

Commission may then approve the 

proposal or remand it to the NERC 

Reliability Standards Development 

Process for further consideration. 

20. NERC states that by directing this 

change, the Commission is bypassing 

the NERC Reliability Standards 

Development Process, and the 

Commission will not have the 

opportunity to consider NERC’s 

guidance in developing an equally 

effective and perhaps superior 

alternative. NERC states that the 

approach in the Commission’s NOPR 

would accomplish indirectly that which 

it is prohibited from doing directly, in 

contravention of well-established 

judicial precedent. NERC notes that the 

Commission refrained from taking 

similar unilateral action in Order No. 

693. NERC requests the Commission 

clarify in the Final Rule that any 

modification to the definition of bulk 

electric system be accomplished 

through the NERC Reliability Standards 

Development Process. 

21. Similarly, EEI, Duke Energy, 

APPA/NRECA, and other commenters 

assert that the Commission should defer 

to the NERC Reliability Standards 

Development Process, and allege that 

the proposal unreasonably departs from 

the Commission’s precedent in Order 

No. 693. 

22. Snohomish also asserts that the 

proposed rule fails to defer to the 

technical expertise of the regional 

reliability organizations and 

inappropriately interferes in the local 

work of Snohomish’s Board regarding 

decisions on levels of service. 

23. TAPS states that Congress did not 

intend for the Commission to undertake 

a facility-by-facility review of all 

facilities above 100 kV, and that the 

proposed rule is contrary to section 

215’s apportionment of primary 

responsibility for reliability 

administration to the ERO.30

Additionally, TAPS states that the 

Commission’s proposed facility-by 

facility review would not satisfy section 

215’s goal of effective and efficient 

reliability administration. 

(ii) Bulk-Power System 

24. NYSRC argues that section 215 

does not provide a ‘‘bright-line’’ test for 

Bulk-Power System facilities and states 

that the statutory intent of section 215 

limits the Commission’s jurisdiction to 

facilities that are necessary for the 

reliable operation of the Bulk-Power 

System.31 Several commenters state that 

the Commission’s proposal exceeds its 

statutory authority as described in the 

definition of ‘‘Bulk-Power System’’ 

because the proposed definition of bulk 

electric system would likely encompass 

facilities not necessary for operating the 

interconnected network,32 and that the 

statutory definitions of ‘‘Reliability 

Standard’’ and ‘‘Reliable Operation’’ refer 

to protecting the system from instability, 

uncontrolled separation, or cascading 

failures, not local-area outages.33 The 

commenters contend that a functional 

test, such as NPCC’s current material 

impact assessment would be more 

appropriate since it is tailored to 

include facilities that are necessary for 

operation of an interconnected electric 

energy transmission network. 

25. GTC/GSOC add that the proposed 

change would make the definition of 

‘‘bulk electric system’’ broader than the 

statutory definition of ‘‘Bulk-Power 

System,’’ and therefore would exceed 

the Commission’s authority. 

(iii) Distribution Facilities 

26. Several other parties assert that 

the proposed rule will inappropriately 

include distribution facilities as part of 

the bulk electric system, and argue that 

the Commission’s proposal is contrary 

to Congress’s definition of ‘‘Bulk-Power 

System’’ and the Commission’s own 

precedent regarding transmission versus 

local distribution.34 Several parties state 

that FPA section 215 specifically 

excludes distribution facilities and that 

they therefore should be excluded from 

the definition of ‘‘bulk electric system.’’ 

Constellation/CENG argues that the 

Commission’s proposal to exclude from 

the definition of ‘‘bulk electric system’’ 

‘‘[r]adial transmission facilities serving 

only load with one transmission source’’ 

is too limiting. Constellation/CENG 

believes that this approach will include 

local distribution facilities in a manner 

contrary to section 215 of the FPA. 

27. The NYPSC contends that the 

Commission’s proposal exceeds its 

jurisdiction by encompassing local 

distribution facilities that are not 

necessary for operating the 

interconnected transmission network. It 

states that 138 kV facilities in New York 

City operate above 100 kV but do not 

serve a bulk system function due to the 

high concentration of load served by 

these lines. It asserts that transmission 

facilities such as these that move power 

between Bulk-Power System and 

distribution facilities do not affect the 

reliable operation of the bulk system. 

The New York Transmission Owners 

contend that the Long Island Power 

Authority’s (LIPA) system east of the 

Northport system is composed of 138 kV 

lines with limited connections to other 

areas that is not affected by other 

regional flows, but instead mirrors a 

radial system feeding local load. 

28. Snohomish, Consumers Energy, 

PGE, Tacoma Power and other 

commenters argue that the 

Commission’s proposal, unless clarified 

to exclude distribution facilities, is 

contrary to statute because section 215 

directs that distribution facilities should 

be excluded on a functional basis 

regardless of voltage.35 Snohomish 

argues that the Commission’s proposal 

departs from its previous 

determinations in Order No. 693 

regarding the difference between 

transmission and distribution systems.36

Further, it states that section 215 

emphasizes how facilities are used 

rather than their voltage level, and 

asserts that the NOPR’s definition runs 

counter to the statutory definition. 

(2) Commission Determination 

(i) Overview 

29. We disagree that the Commission 

exceeded its statutory authority by 

directing the ERO to revise the 

definition of bulk electric system in its 

Glossary of Terms. We agree with NERC 

that the NERC Glossary is part of the 

Reliability Standards and therefore falls 

under the same section 215 process. 

Pursuant to section 215(d)(5), the 

Commission may order the ERO to 

submit a proposed Reliability Standard 

or a modification to a Reliability 

Standard that addresses a specific 

matter. Here, by directing a revision to 

the definition of bulk electric system, 

the Commission orders a modification 

to a definition of a term contained in a 


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37See, e.g., CIP–002–2, COM–001–1.1, EOP–004– 

1, EOP–005–1, FAC–008–1, FAC–009–1, FAC–010– 

2, FAC–011–2, FAC–013–1, FAC–014–2, IRO–001– 

1.1, IRO–002–1, IRO–003–2, IRO–004–1, IRO–005– 

2, IRO–006–4.1, NUC–001–2, PER–001–0.1, PER– 

002–0, PER–003–0, PRC–004–1, PRC–005–1, PRC– 

021–1, PRC–022–1, PRC–023–1, TOP–001–1, TOP– 

002–2, TOP–008–1, TPL–002–0, TPL–003–0, TPL– 

004–0. 

38 16 U.S.C. 824o(d)(5). 

39We note that all regions except NPCC currently 

utilize 100 kV as a general threshold. 

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

P 31. 

41 See, e.g., Version One Regional Reliability 

Standard for Resource and Demand Balancing, 133 

FERC ¶ 61,063, at P 14 (2010); North American 

Electric Reliability Corporation Reliability 

Standards Development and NERC and Regional 

Entity Enforcement, 132 FERC ¶ 61,217, at P 112 

(2010). 

42Order No. 693 FERC Stats. & Regs. 31,242 at P 

31. 

43See Order No. 672, FERC Stats. & Regs. 31,204 

at P 325. 

44See id. P 331. 

45 Id. P 291. 

46Order No. 693, FERC Stats. & Regs. ¶ 31,242 at 

P 185. 

47 Id. P 186 (citing 16 U.S.C. 824o(d)(5)). 

48 16 U.S.C. 824o(d)(2); see also Order No. 672, 

FERC Stats. & Regs. ¶ 31,204 at P 345 (‘‘We do not 

agree that giving due weight means a rebuttable 

presumption that the Reliability Standard meets the 

statutory requirement of being just, reasonable, not 

unduly discriminatory or preferential, and in the 

public interest.’’). 

49Order No. 693, FERC Stats. & Regs. ¶ 31,242 at 

P 186. 

number of Commission-approved 

Reliability Standards.37 Because this 

term is contained within Commissionapproved Reliability Standards, the 

Commission has the authority to direct 

the ERO to develop a modification of 

the definition of a defined term 

contained in the Reliability Standards 

under the process delineated in section 

215 of the FPA. 

30. For the reasons discussed more 

fully below, the Commission finds that 

the current definition of bulk electric 

system is insufficient to ensure that all 

facilities necessary for operating an 

interconnected electric energy 

transmission network are included 

under the ‘‘bulk electric system’’ rubric. 

Therefore, pursuant to section 215(d)(5) 

of the FPA,38 the Commission directs 

the ERO to modify, through the 

Standards Development Process, the 

definition of ‘‘bulk electric system’’ to 

address the Commission’s technical and 

policy concerns described more fully 

herein. The Commission believes the 

best way to address these concerns is to 

eliminate the regional discretion in the 

ERO’s current definition, maintain the 

bright-line threshold that includes all 

facilities operated at or above 100 kV 

except defined radial facilities, and 

establish an exemption process and 

criteria for excluding facilities the ERO 

determines are not necessary for 

operating the interconnected 

transmission network. It is important to 

note that the Commission is not 

proposing to change the threshold value 

already contained in the definition, but 

rather seeks to eliminate the ambiguity 

created by the current characterization 

of that threshold as a general 

guideline.39

31. In accordance with Order No. 693, 

the ERO may develop an alternative 

proposal for addressing the 

Commission’s concerns with the present 

definition with the understanding that 

any such alternative must be as effective 

as, or more effective than, the 

Commission’s proposed approach in 

addressing the identified technical and 

other concerns,40 and may not result in 

a reduction in reliability.41 If the ERO 

decides to propose an alternative 

approach, it must explain in detail, and 

with a technical record sufficient 

enough for the Commission to make an 

informed decision, how its alternative 

addresses each of the Commission’s 

concerns in a manner that is as effective 

as, or more effective than, the 

Commission’s identified solution.42

Additionally, the ERO would need to 

address the factors the Commission will 

consider in determining whether a 

proposed Reliability Standard is just 

and reasonable, as outlined in Order No. 

672. In particular, Order No. 672 states 

that proposed Reliability Standards 

‘‘should be clear and unambiguous 

regarding what is required and who is 

required to comply.’’ 43 Another factor 

indicates that a ‘‘proposed Reliability 

Standard should be designed to apply 

throughout the interconnected North 

American Bulk-Power System, to the 

maximum extent this is achievable with 

a single Reliability Standard.’’ 44 As 

Order No. 672 further requires, any 

proposed regional difference must be: 

(1) More stringent than the continentwide definition, including a regional 

difference that addresses matters that 

the continent-wide definition does not; 

or (2) necessitated by a physical 

difference in the Bulk-Power System.45

32. The Commission further finds that 

revising the definition to address the 

identified concerns is a significant step 

toward improving the reliability of the 

Bulk-Power System in North America 

because it protects the reliability of the 

bulk electric system and provides clarity 

and consistency across the nation’s 

reliability regions in identifying bulk 

electric system facilities. 

33. The Commission directs the ERO 

to submit these modifications no later 

than one year from the effective date of 

this Final Rule. We will address each 

proposal and the specific comments 

received on each proposal in the 

remainder of this Final Rule. 

(ii) NERC Standards Development 

Process and Deference to NERC and the 

Regional Entities 

34. With regard to the concerns raised 

by some commenters about the 

prescriptive nature of the Commission’s 

proposed modifications, we agree that, 

consistent with Order No. 693, a 

direction for modification should not be 

so overly prescriptive as to preclude the 

consideration of viable alternatives that 

may produce an equally effective or 

efficient solution. However, some 

guidance is necessary, as the 

Commission explained in Order No. 

693: 

[I]n identifying a specific matter to be 

addressed in a modification * * * it is 

important that the Commission provide 

sufficient guidance so that the ERO has an 

understanding of the Commission’s concerns 

and an appropriate, but not necessarily 

exclusive, outcome to address those 

concerns. Without such direction and 

guidance, a Commission proposal to modify 

a Reliability Standard might be so vague that 

the ERO would not know how to adequately 

respond.46

35. Thus, due to the importance of the 

bulk electric system definition to our 

overall ability to carry out the mandates 

of section 215, and the problems we 

have identified with the current 

definition, we provide specific details 

regarding the Commission’s 

expectations. We intend by doing so to 

provide useful direction to assist in the 

Reliability Standards Development 

Process, not to impede it. As we 

explained in Order No. 693, we find that 

this is consistent with statutory 

language that authorizes the 

Commission to direct the ERO to submit 

a modification ‘‘that addresses a specific 

matter’’ if the Commission considers it 

appropriate to carry out section 215 of 

the FPA.47 Although some commenters’ 

contend that we should ‘‘defer to 

regional expertise,’’ we note that the 

statute specifies that we should ‘‘give 

due weight’’ to the ERO’s technical 

expertise.48 The Commission’s action 

here does not conflict with that 

statutory requirement. In this Final 

Rule, we have considered commenters’ 

concerns and, although we have 

identified a proposed approach, the 

Commission provides flexibility by 

directing the ERO to address the 

underlying issue through the Reliability 

Standards Development Process.49

Consequently, consistent with Order 

No. 693, we clarify that where the Final 


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50 Id. 

51 Id. P 76. 

52See id. P 76; Order No. 693–A, 120 FERC 

¶ 61,053 at P 17–18. 

53Order No. 693–A, 120 FERC ¶ 61,053 at P 19. 

54 16 U.S.C. 824o(a)(1). 

55Order No. 672, FERC Stats. & Regs. ¶ 31,204 at 

P 71. 

56This example illustrates one of the deficiencies 

of the NPCC impact-based approach for identifying 

bulk electric system facilities, discussed more fully 

below. 

57See http://www.nyiso.com/public/webdocs/

services/planning/reliability_assessments/AppxE.

pdf and http://www.nyiso.com/public/webdocs/

services/planning/planning_data_reference_

documents/2010_GoldBook_Public_Final_

033110.pdf. 

58Order No. 693, FERC Stats. & Regs. ¶ 31,242 at 

P 75. 

59 In accepting NERC’s definition of ‘‘bulk electric 

system,’’ the Commission explained: ‘‘Although we 

are accepting the NERC definition of bulk electric 

system and NERC’s registration process for now, the 

Rule identifies a concern and offers a 

specific approach to address that 

concern, we will consider an equivalent 

alternative approach provided that the 

ERO demonstrates that the alternative 

will adequately address the 

Commission’s underlying concern or 

goal as efficiently and effectively as the 

Commission’s proposal.50

(iii) Bulk-Power System 

36. With regard to the alleged conflict 

between ‘‘bulk electric system’’ and 

‘‘Bulk-Power System,’’ the Commission 

noted in Order No. 693 that Congress 

chose to create a new term, ‘‘Bulk-Power 

System,’’ with a definition that is 

distinct from the term of art (‘‘bulk 

electric system’’) used by industry, and 

thus there is an intentional distinction 

between the Bulk-Power System and the 

bulk electric system.51 The Commission 

further noted that the statutory term 

‘‘Bulk-Power System’’ has not been 

definitively defined but does not 

establish a voltage threshold limit of 

applicability or configuration as does 

the NERC definition of ‘‘bulk electric 

system,’’ and therefore may reach more 

facilities than NERC’s definition of 

‘‘bulk electric system.’’ 52

(iv) Distribution Facilities 

37. The Commission has stated that 

the statutory term ‘‘Bulk-Power System’’ 

defines the jurisdiction of the 

Commission.53 The Commission noted 

that it has not defined the extent of the 

facilities covered by the Bulk-Power 

System, but that Congress specifically 

exempted ‘‘facilities used in the local 

distribution of electric energy’’ from the 

definition. FPA section 215 defines the 

term ‘‘Bulk-Power System’’ as 

encompassing the ‘‘facilities and control 

systems necessary for operating an 

interconnected electric energy 

transmission network (or any portion 

thereof).’’ 54 In ascertaining the extent of 

the facilities included in the ‘‘BulkPower System’’ definition, the 

Commission’s prior discussion 

regarding the inclusion of generation 

facilities as part of the Bulk-Power 

System is instructive. In the discussion, 

the Commission stated that, ‘‘if electric 

energy from a generating facility is 

needed to maintain a reliable 

transmission system, that facility is part 

of the Bulk-Power System with respect 

to the energy it generates that is needed 

to maintain reliability.’’ 55 Similarly, 

several 115 and 138 kV facilities that 

some entities term as ‘‘distribution’’ may 

be needed to reliably operate the 

interconnected transmission system. 

Determining where the line between 

‘‘transmission’’ and ‘‘local distribution’’ 

lies, which includes an inquiry into 

which lower voltage ‘‘transmission’’ 

facilities are necessary to operate the 

interconnected transmission system, 

should be part of the exemption process 

the ERO develops. 

38. The Commission disagrees with 

comments that appear to assert that the 

Commission’s jurisdiction extends only 

to facilities that could, if improperly 

operated, singularly cause cascading 

outages, uncontrolled separation or 

instability. By this narrow metric, the 

facilities that caused the 2003 Blackout 

would not be viewed as critical since 

not one of the individual facilities 

caused the outage. In defining 

jurisdictional facilities, section 215(a)(1) 

focuses on whether facilities are 

necessary to operate the interconnected 

transmission system, not solely on the 

consequences of unreliable operation of 

those facilities. Lower voltage facilities 

needed to reliably operate the grid tend 

to operate in parallel with other high 

voltage and extra high voltage facilities, 

interconnect significant amounts of 

generation sources and may operate as 

part of a defined flow gate. These 

parallel facilities operated at 100–200 

kV will experience similar loading as 

higher voltage facilities at any given 

time. Additionally, the lower voltage 

facilities will be relied upon during 

contingency scenarios. 

39. For example, we are not 

persuaded by the NYPSC’s argument 

that the 138 kV system in New York, 

and specifically the 138 kV system 

including those facilities in the Astoria 

area, are all distribution facilities. We 

do not believe that most of these 

facilities are local distribution because: 

the facilities are not primarily radial in 

character, as they are connected to the 

345 kV network in the Astoria area at 

over six different points; the 138 kV 

system is networked amongst itself; 

power flows both in and out of the 

system into both NYISO and PJM 

facilities depending on time of day and 

loading; and the system is not 

constrained to a comparatively 

restricted geographical area due to 

multiple interconnections. The 138 kV 

system in the Astoria area includes six 

major substations that are 

interconnected at 345 kV to both NYISO 

and PJM facilities that are integral parts 

of the Eastern Interconnection. There 

are ten 138 kV phase angle regulators 

connecting the 345 kV stations to the 

138 kV network, which are necessary to 

control the appropriate distribution of 

power flows between the 345 kV and 

138 kV systems to accommodate power 

transfers from upstate New York and 

PJM into southeastern New York. In 

addition, there are approximately 9,000 

MW of capacity resources directly 

connected to the 138 kV network in the 

New York City area at different points, 

2,000 MW of which is connected in the 

Astoria area. Similarly over 10,000 MW 

of customer firm demand in the area is 

supplied from the 138 kV to lower 

voltage levels via step-down 

transformers. None of these 

characteristics is consistent with any 

reasonable definition of local 

distribution.56 To the extent that any 

individual line would be considered to 

be local distribution, that line would not 

be considered part of the bulk electric 

system. 

40. Nor are we persuaded by the 

Indicated New York Transmission 

Owners’ statement that LIPA’s service 

territory—which includes a majority of 

Long Island, identified as Zone K by 

NYISO and, as reported in the NYISO 

‘‘Load & Capacity Data,’’ had a 2010 

summer peak load of 5,300 MW— 

‘‘mirrors a radial system feeding local load.’’ 

As with the 138 kV network in New York 

City discussed above, the LIPA system 

contains significant capacity resources (5,700 

MW), is interconnected with other portions of 

NYISO, ISO–NE, and PJM, and its 

operations affect and depend on operations in 

other portions of New York, as well as New 

Jersey and Connecticut.57

41. Some commenters allege that the 

proposal is an unexpected departure 

from the Commission’s previous actions 

regarding the bulk electric system in 

Order No. 693. To the contrary, the 

Commission was very clear about its 

reservations in accepting the NERC bulk 

electric system definition in Order No. 

693 and expressly accepted the 

definition for an ‘‘initial period’’ 58

subject to subsequent review.59 The 


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Commission remains concerned about the need to 

address the potential for gaps in coverage of 

facilities. For example, some current regional 

definitions of bulk electric system exclude facilities 

below 230 kV and transmission lines that serve 

major load centers such as Washington, DC and 

New York City. The Commission intends to address 

this matter in a future proceeding.’’ 

Id. P 77 (footnotes omitted). 

60While the Commission seeks to ensure that the 

definition of ‘‘bulk electric system’’ includes all 

facilities 100 kV or above that are necessary for 

reliable operation, our action here is not intended 

to determine the extent of the facilities included in 

the Bulk-Power System. As stated in Order No. 

693–A, the Commission believes that the BulkPower System reaches farther than those facilities 

that are included in NERC’s definition of the bulk 

electric system, but we have not definitively 

defined the extent of the facilities covered by the 

Bulk-Power System, and we are not doing so here. 

See Order No. 693–A at P 17–18. 

61NOPR, FERC Stats. & Regs. ¶ 32,654 at P 1. 

62See, e.g., EEI, Dominion Power, National Grid, 

and Southern Company. 

63 Joint Western Commenters at section IV.B. 

64 Id. 

65See, e.g., id. at section III.C. 

66APPA/NRECA at 19–23. 

67National Grid at 10. 

68Operating voltage usually encompasses a small 

range of voltages around the expected or normal 

operating value while rated voltage depends on the 

design of the facilities. 

Commission’s action here will ensure 

that all facilities necessary to maintain 

a reliable transmission system are 

included as part of the bulk electric 

system and thus will be subject to ERO 

and Commission oversight.60

(b) Scope of the Definitional Change of 

‘‘Bulk Electric System’’ 

(1) NOPR Proposal 

42. In the NOPR, the Commission 

proposed to direct the ERO to revise its 

definition of the term ‘‘bulk electric 

system’’ to include all electric 

transmission facilities with a rating of 

100 kV or above.61 The Commission’s 

proposal further states that a Regional 

Entity must seek ERO and Commission 

approval before exempting any facility 

rated at 100 kV or above from 

compliance with mandatory Reliability 

Standards. 

(2) Comments 

43. NERC argues that the proposed 

definitional change would have a much 

broader impact than acknowledged by 

the Commission. Among other things, 

NERC states that the proposed change to 

‘‘rated at’’ from the current ‘‘operated at’’ 

will dramatically expand the scope of 

facilities and entities affected by the 

change. NERC states that the proposal 

will unnecessarily include some 

facilities that entities built at higher 

voltage levels (i.e., 138 kV) to 

accommodate future load growth while 

presently operating the facilities at 

lower voltages (i.e., 69 kV). 

44. Several commenters seek 

clarification that the definition of ‘‘bulk 

electric system’’ is not intended to 

supersede voltage thresholds specified 

in specific Reliability Standards.62 For 

example, Reliability Standard FAC–003 

generally applies to transmission lines 

200 kV and above. 

45. Joint Western Commenters and 

Bay Area Municipal argue that the 

definition of ‘‘bulk electric system’’ that 

the Commission ultimately accepts 

should clarify that if an element is 

determined to be part of the bulk 

electric system, such an element is not 

necessarily a transmission asset. 

46. Joint Western Commenters state 

that an entity should be able to deregister as a Distribution Provider and 

Load-Serving Entity if it does not own 

any bulk electric system elements.63

They state that an entity with no 

elements in the bulk electric system 

cannot be considered an owner or 

operator of the bulk electric system, and 

because operation of that entity’s 

distribution assets has no material 

impact on the bulk electric system, it 

should be exempt from regulation as 

transmission and the need to register 

and participate in the regulatory 

framework for transmission facilities. 

These commenters also state that 

requiring an entity with no bulk electric 

system elements to comply with the 

mandatory Reliability Standards would 

be an unnecessary burden on the entity, 

and a diversion of resources by the 

Regional Entity, NERC, and the 

Commission.64

47. Although EEI supports the 

Commission’s proposal not to change 

the ERO treatment of radials under the 

ERO definition of bulk electric system, 

several commenters raise concerns 

about the scope of the exemption going 

forward. 

48. Several commenters believe that 

the statement in the NOPR that radial 

lines would not be part of the bulk 

electric system is not enough to remove 

ambiguity.65 APPA/NRECA notes that 

the NOPR leaves a question open as to 

whether radial lines would be 

automatically exempt under the bulk 

electric system definition or whether 

entities would have to go through the 

multi-tiered exemption process.66 Other 

commenters point out that certain 

Regional Entities currently provide a 

clearer and more valid approach to 

determining whether facilities should be 

classified as exempt radial facilities. 

They state for example that the WECC 

process includes additional detail 

regarding demarcation points and 

system characteristics that are important 

in defining ‘‘radial.’’ Commenters also 

state that the WECC transmission 

system includes radial lines, where a 

backup feed is possible, but is normally 

open, and a utility should not be 

penalized for having a secondary feed 

via a normally open line by requiring it 

to automatically become part of the bulk 

electric system. The bright line 100 kV 

threshold would encourage small 

utilities to choose not to provide backup 

service options, reducing overall 

customer service. 

49. Arguing that NERC’s current 

definition of radial transmission 

facilities, defined as ‘‘facilities serving 

only load with one transmission 

source,’’ is too narrow, National Grid 

supports adoption of a broader 

definition that includes tap lines and 

associated facilities used to serve local 

load only, and transmission lines that 

are operated in an open position for 

normal operations.67

50. ELCON states that the Final Rule 

should specify that radial lines do not 

have to go through the exemption 

process. 

51. FRCC states the Commission 

should afford the Regional Entities 

sufficient time to complete their efforts 

to define the scope of the bulk electric 

system, since they are in the process of 

establishing criteria for the exclusion of 

facilities as ‘‘radial transmission 

facilities.’’ 

(3) Commission Determination 

52. We grant the clarification sought 

by commenters that the 100 kV 

threshold will not modify thresholds 

established in individual Reliability 

Standards such as FAC–003. 

53. In response to comments, 

although the NOPR used the term ‘‘rated 

at,’’ the Commission did not intend to 

require NERC to utilize that term rather 

than the term ‘‘operated at’’ which is 

reflected in the current definition of 

bulk electric system. While the 

Commission does not have firm data on 

the number of facilities that operate at 

a voltage significantly lower than the 

rated voltage, we find that the term 

‘‘rated at’’ could generate confusion.68

54. We believe that the issues of 

whether a distribution provider or loadserving entity may de-register if it is 

shown not to own any bulk electric 

system elements, and whether the 

inclusion of a facility as part of the bulk 

electric system is or is not determinative 

of that facility’s status as a transmission 

asset, are addressed by the NERC 

Registry Criteria and beyond the scope 

of this proceeding. 


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69NOPR, FERC Stats. & Regs. ¶ 32,654 at P 13– 

14. 

70See NERC/NPCC, compliance filing, Docket No. 

RC09–3 (filed Feb. 20, 2009). 

71NERC at 2. 

72ReliabilityFirst at 2; SCE at 2; WECC at 3. 

73See, e.g., FRCC, NARUC, NYSRC, Redding, 

GTC/GSOC. 

74See, e.g., NARUC, NYPSC, FRCC, Dow, GTC/ 

GSOC, Hydro-Que ́bec, Ontario Power, NV Energy, 

Snohomish, Southern. 75See, e.g., NARUC, NYSRC. 76APPA/NRECA at 15–16. 

77 Id. at 30–31. 

78 Id. at 32. 

79CMUA at 5. 

55. As we stated in the NOPR, we do 

not seek to modify the second part of 

the definition through this Final Rule, 

which states that ‘‘[r]adial transmission 

facilities serving only load with one 

transmission source are generally not 

included in this definition.’’ While 

commenters would like to expand the 

scope of the term ‘‘radial’’ to exclude 

certain transmission facilities such as 

tap lines and secondary feeds via a 

normally open line, we are not 

persuaded that such categorical 

exemption is warranted. For example, 

when the normally ‘‘open’’ line is 

‘‘closed,’’ it becomes part of the 

transmission network and therefore 

should be subject to mandatory 

Reliability Standards. Commenters also 

argued that the bright line 100 kV 

threshold would encourage small 

utilities to choose not to provide backup 

service options, reducing overall 

customer service. We acknowledge 

these concerns, and direct the ERO to 

consider these comments regarding 

radial facilities in crafting an exemption 

methodology. 

(c) Technical and Historical Justification 

for Modification 

(1) NOPR Proposal 

56. In the NOPR, the Commission 

stated its concern that if it does not 

clarify the ‘‘bulk electric system’’ 

definition to apply a stricter 100 kV 

threshold, it would not be fulfilling 

Congress’s intent in enacting section 

215. The NOPR stated that the 

Commission believes there is an 

adequate technical and reliabilityrelated justification, discussed further 

below, for the proposed 100 kV 

operating threshold for identifying bulk 

electric system facilities. Additionally, 

the NOPR noted that NERC already 

applies a general 100 kV threshold.69

Further, at present all regions, with the 

exception of NPCC, also apply a 100 kV 

threshold. 

57. The NOPR identified 

inconsistencies between regions, such 

as two transmission lines that are 

classified as bulk electric system in 

ReliabilityFirst but not in NPCC.70 The 

NOPR also offered examples of 

disturbances that either began on or 

were propagated by 100–200 kV 

facilities, including a February 26, 2008 

event in FRCC originating at a 138 kV 

facility that resulted in the loss of 24 

transmission lines and 4,300 MW of 

generation, and a June 27, 2007 event on 

138 kV transmission lines in the NPCC 

region that included sequential tripping 

of four 138 kV cable-circuits without a 

contingency. The June 27, 2007 NPCC 

event (the ‘‘Astoria West event’’) resulted 

in the interruption of service to about 

137,000 customers as well as the loss of 

five generators and six 138 kV 

transmission lines. Further, the NOPR 

pointed to Transmission Loading Relief 

(TLR) issuances on non-bulk electric 

system elements in New York and the 

historical basis for a 100 kV threshold 

as justification. 

(2) Comments 

58. Several commenters including 

ISO–NE, BGE, Northeast Utilities, 

ReliabilityFirst, Manitoba Hydro, and 

Dominion Power support the proposed 

change, arguing that the increased 

consistency and applicability of NERC 

Reliability Standards will ensure 

reliability. Moreover, a number of other 

commenters who ultimately suggest that 

other processes are more appropriate for 

undertaking a modification to the 

definition of ‘‘bulk electric system’’ agree 

with the overriding goal to develop a 

more consistent definition of ‘‘bulk 

electric system.’’ For example, NERC 

notes that it ‘‘supports the Commission’s 

objectives of ensuring a common 

understanding and consistent 

application of the definition of ‘bulk 

electric system’ across the regions,’’ with 

variations justified on the basis of 

reliability.71 Likewise, ReliabilityFirst 

supports the creation of a bright-line 

rule for determining which facilities are 

subject to Reliability Standards (with 

appropriate process for refinement or 

exemption), and both SCE and WECC 

generally support a rebuttable 

presumption that transmission facilities 

above 100 kV should be initially 

classified as ‘‘bulk electric system’’ 

facilities, as long as appropriate 

mechanisms for exclusion are in 

place.72

59. Several other commenters contend 

that the proposal does not explain how 

the proposed changes to bulk electric 

system classification would have 

prevented the discussed events or 

improved reliability.73 They argue that 

the NOPR did not describe whether 

these events took place on facilities 

classified as ‘‘bulk electric system’’ or 

non-‘‘bulk electric system.’’ Similarly, 

commenters contend that the NOPR 

does not show the connection between 

regional inconsistencies and reliability 

concerns.74 Commenters also assert the 

proposal will be expensive and lengthy 

to implement without improving 

reliability. 

60. Additionally, several commenters 

state that a material impact assessment 

should be used instead of a ‘‘bright-line’’ 

test, thus deferring to the Regional 

Entities’ technical expertise.75

Commenters also contend that the 

Commission has not shown how the 

current NPCC method is flawed or how 

it has harmed reliability. They conclude 

that a material impact assessment is 

preferable to a ‘‘bright-line’’ test because 

they believe it will focus limited 

resources towards critical facilities that 

have the largest impact. 

61. APPA/NRECA, NARUC, CMUA, 

CPUC, and TANC state that the specific 

examples cited by the Commission of 

outages on lower voltage lines in one 

region do not support making sweeping 

changes to the definition of bulk electric 

system as proposed in the NOPR. 

APPA/NRECA notes that the 

Commission’s stated concerns about 

facilities inappropriately excluded from 

the bulk electric system definition are 

limited to the NPCC region, while the 

Commission’s proposed solution is 

directed at and would affect all 

regions.76 APPA/NRECA asserts that the 

Commission’s limited examples of 

outages on lines excluded from the bulk 

electric system definition in NPCC 

cannot support imposing the Reliability 

Standards on all lower-voltage facilities, 

regardless of the function and impact of 

such facilities.77 Finally, APPA/NRECA 

notes that the Commission’s attempt to 

justify the proposal based on the total 

amount of 100 kV facilities in service is 

inapposite, as it has no bearing on 

whether or not those facilities function 

as part of the bulk electric system.78

Similarly, CMUA asserts that it is 

inappropriate to draw conclusions 

regarding the effect of disturbances on 

lower-voltage facilities based on a 

limited number of cases in one region, 

without consideration of the nature of 

the facilities and particular features of 

that region.79 NARUC also contends that 

a key part of the historical approach to 

the ‘‘bulk electric system’’ definition was 

the Regional Entities’ ability to define 

the bulk electric system for its own 

region. Further, NARUC states that the 

NOPR does not identify any excluded 

lines critical to reliability. Additionally, 


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80NYSPC at 10. 81Tacoma Power at 6. 

82Utah Municipal at 8. 

83WPSC at 2–3. 

NARUC believes NPCC’s estimated $280 

million cost to comply with the new 

ruling will outweigh the expected 

minimal to negligible benefit. 

62. The Joint Canadian Parties assert 

that the impact-based methodology 

ensures that all facilities critical to 

wide-area reliability, independent of 

voltage level, are covered by the bulk 

electric system definition. Similarly, 

they argue that the NERC Reliability 

Standards should apply only to facilities 

that, if lost, would have the potential for 

a wide-area reliability impact. 

63. The Indicated New York 

Transmission Owners and NYSRC state 

that the NOPR does not sufficiently 

account for the time and cost required 

to implement the proposed rule change. 

Further, they contend that the TLR 

events cited in the NOPR were issued in 

order to mitigate an unanticipated 

clockwise flow around Lake Erie, and 

that classification of lower voltage 

facilities as part of the ‘‘bulk electric 

system’’ would not have affected the 

need for the TLR. The NYPSC and Duke 

Energy contend that the 115 kV facility 

in the Central East ties flowgate 

constitutes a minor element of the 

flowgate that would not result in a 

cascading event on the bulk system. 

64. NYSRC also contends that the 

February 26, 2008 and the June 13, 2008 

events cited in the NOPR occurred in 

regions that already use a 100 kV 

threshold and therefore do not show 

that the 100 kV threshold is more 

effective at protecting reliability than 

the impact-based approach. 

Additionally, NYSRC believes that the 

current methodology appropriately 

defers to regional expertise. 

65. NYPSC also states that the June 

27, 2007 event ‘‘was caused by lighting 

[sic] strikes on the telecommunications 

system over which several relay signals 

were carried,’’ and that the utility 

involved has since ensured separate 

paths are provided for 

telecommunications beyond the fence of 

the electric utility’s facilities.80

Additionally, the NPCC Working Group 

concluded that the event was confined 

to the Astoria West load pocket and that 

no other portions of the Consolidated 

Edison (ConEd) system were affected. 

Separately, the NYPSC states that the 

Commission has not provided evidence 

as to how the regional inconsistencies 

identified in the NOPR jeopardize 

reliability. 

66. Alcoa states that it supports 

NPCC’s current material impact 

assessment because it believes most of 

the facilities not included in the bulk 

electric system are accurately excluded. 

Alcoa further contends that the 

Commission has not shown how 

inclusion of lines like these will 

improve reliability and that the 

reliability benefit is only presumed. 

Dow likewise argues that it does not 

believe that the applicability of NERC 

Reliability Standards is a sufficient basis 

to assume that reliability will improve 

and argues that the NOPR does not 

provide any additional evidence. 

67. Constellation/CNEG supports 

continued use of Regional Reliability 

Organizations’ technical discretion as 

opposed to the Commission’s proposal. 

Constellation/CNEG states that current 

proposals from WECC utilizing a Short 

Circuit Megavolt Ampere methodology, 

or a three-phase fault with delayed 

clearing analysis, demonstrate the 

proper regional discretion and technical 

expertise. Similarly, Tacoma Power 

requests that the WECC Bulk Electric 

System Definition Task Force (BESDTF) 

be allowed to complete its work, and 

states that the Commission has not 

provided sufficient technical support for 

requiring a bright-line voltage-based 

standard.81 The Joint Western 

Commenters state that the Final Rule 

should be consistent with the WECC 

BESDTF’s efforts that will utilize an 

impact based approach. Further, if the 

Commission has issues with the NPCC 

method, Constellation/CNEG state that 

the Commission should address its 

concerns with NPCC specifically rather 

than through an across the board 

proposal. The Joint Western 

Commenters similarly state that the 

Western entities should not be 

penalized for NPCC’s actions, which 

actions are the apparent impetus for 

issuance of the NOPR. 

68. Hydro-Que ́bec and Ontario Power 

state that application of the NERC 

Reliability Standards should be limited 

to facilities with a material impact on 

reliability, based on regional variances 

and expertise. The proposed change 

would divert needed resources from 

more important facilities. 

69. NESCOE requests the Commission 

study the impact of the proposal more 

before implementing the rule. 

70. Bay Area Municipal agrees that 

115 kV and 138 kV facilities have either 

caused or contributed to significant bulk 

system disturbances and cascading 

outages. Utah Municipal also concedes 

that some facilities rated at 100 kV and 

above may have been improperly 

excluded from classification in the bulk 

electric system, at least in the NPCC. 

However, Utah Municipal also states 

that unless the facilities described were 

not included in the bulk electric system 

of the applicable Regional Entities, the 

cited events do not show a flaw in the 

existing definition.82 Utah Municipal 

also disputes the NOPR’s claim of a 

historical precedent supporting the 100 

kV threshold since the previous 

threshold was presumptive rather than 

a ‘‘bright-line.’’ Utah Municipal 

recommends that the Commission allow 

WECC’s BESDTF to complete its work 

on a hybrid definition that utilizes a 

presumptive 100 kV threshold and a 

material impact assessment. Utah 

Municipal suggests that this model be 

used as a template for other Regional 

Entities’ bulk electric system 

definitions. 

71. The WPSC and Consumers Energy 

state that without substantial 

refinement, the proposal will cause 

public utilities to experience significant 

but unnecessary compliance costs. 

Additionally, the WPSC anticipates that 

utilities would elect to build facilities 

below the 100 kV threshold to avoid 

‘‘bright-line’’ oversight, which will in 

turn result in a lower voltage, less 

technically capable system and will 

therefore adversely affect reliability.83

(3) Commission Determination 

72. The Commission finds sufficient 

justification for the action in this Final 

Rule. The current definition has failed 

to ensure that all facilities necessary for 

operation of the interconnected 

transmission network are covered by the 

Reliability Standards. As discussed 

above, the current definition allows 

broad regional discretion without ERO 

or Commission oversight, which has 

resulted in reliability issues such as the 

exclusion of transmission serving bulk 

electric generators (including nuclear 

plants), inconsistency in classification 

at the seams that compromises the 

effectiveness of the Reliability 

Standards, routine TLR events on nonbulk electric system facilities, and the 

exclusion of elements necessary to 

operate the interconnected transmission 

network. Given the inconsistency of the 

application among regions and the 

reliability issues created as a result of 

the current definition, we conclude that 

it is necessary to direct the ERO to 

revise the definition of ‘‘bulk electric 

system’’ to ensure that all facilities 

necessary to operate the interconnected 

transmission network are included and 

to address the concerns noted herein. 

We believe that the Commission’s 

proposed approach of adopting a brightline, 100 kV threshold, along with a 

NERC-developed, Commissionapproved exemption process, as well as 


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72920 Federal Register / Vol. 75, No. 227 / Friday, November 26, 2010 / Rules and Regulations 

84See Order No. 672, FERC Stats. & Regs. 

¶ 31,204 at P 291. 

85See NERC Petition, Docket No. RM08–013–000, 

at 18 (filed July 30, 2008). There NERC indicated 

that the PRC–023 standard drafting team selected a 

voltage threshold for the Reliability Standard’s 

applicability because the bulk electric system 

definition has too many variances to be effective for 

defining a Reliability Standard’s applicability: ‘‘This 

conclusion [to use a voltage-specific-threshold] was 

reached by considering the potential variances in 

the facilities included as the bulk power system in 

different Regional Entities, together with an 

observation that the effects of the proposed 

reliability standard are not constrained to Regional 

boundaries. For example, if one Region has a purely 

performance-based criteria and an adjoining Region 

has a voltage-based criteria, these criteria may not 

permit consideration of the effects of protective 

relay operation in one Region upon the behavior of 

facilities in the adjoining Region.’’ 

86NPCC Document A–10 defines the term bus as 

‘‘a junction with sensing or protection equipment 

within a substation or switching station at which 

the terminals of two or more elements are 

connected, regardless of whether circuit breakers 

are provided.’’ See NPCC Document A–10 at 

page 2. 

87See NPCC Document A–10 at 4. 

88See NPCC Glossary of Terms, NPCC Document 

A–7 at 13–14 (‘‘Local area—An electrically confined 

or radial portion of the system. The geographic size 

and number of system elements contained will vary 

based on system characteristics. A local area may 

be relatively large geographically with relatively 

few buses in a sparse system, or be relatively small 

geographically with a relatively large number of 

buses in a densely networked system.’’). 

eliminating regional variations unless 

approved by the Commission as 

provided in Order No. 672,84 is an 

appropriate action to ensure bulk 

electric system reliability. 

73. As discussed in this Final Rule, 

many facilities operated at 100 kV and 

above have a significant effect on the 

overall functioning of the grid. The 

majority of 100 kV and above facilities 

in the United States operate in parallel 

with other high voltage and extra high 

voltage facilities, interconnect 

significant amounts of generation 

sources and operate as part of a defined 

flow gate, which illustrates their parallel 

nature and therefore their necessity to 

the reliable operation of the 

interconnected transmission system. 

Parallel facilities operated at 100–200 

kV will experience similar loading as 

higher voltage parallel facilities at any 

given time and the lower voltage 

facilities will be relied upon during 

contingency scenarios. Further, as 

illustrated by the Commission’s 

examples and as Bay Area Municipal 

states, 115 kV and 138 kV facilities have 

either caused or contributed to 

significant bulk system disturbances 

and cascading outages. Additionally, the 

current definition’s broad regional 

discretion has allowed classification 

inconsistencies to develop within and 

along the borders of Regional Entities, as 

discussed in further detail herein.85 The 

proposed 100kV threshold is intended 

to ensure facilities necessary for reliable 

operation are captured by the definition 

and to avoid entities exempting their 

facilities by any means other than 

through a Commission-approved 

exemption process. 

74. While the Commission believes 

the solution described above is the best 

way to address the identified problems 

with the current definition, the ERO has 

the discretion to develop an alternate 

solution that is as effective as, or 

superior to, the Commission’s proposed 

approach in addressing the identified 

technical and other concerns, and may 

not result in a reduction in reliability. 

If the ERO chooses to propose a 

different solution, it must demonstrate 

that its proposal is equally effective or 

more effective at ensuring that all 

facilities necessary to operate the 

interconnected transmission network 

are captured by the definition and that 

the proposal will not produce the 

inconsistencies and inaccuracies that 

result from the current definition, as 

described in this Final Rule. The ERO 

must support any alternate proposal 

with a technical analysis that 

demonstrates and explains, with a 

technical record sufficient for the 

Commission to make an informed 

decision, how its proposal provides the 

same level of reliability as the 

Commission’s proposal, and reflects the 

reality of how entities use and rely on 

their 100 kV and above facilities. 

75. Finally, we believe use of the term 

‘‘operated at’’ rather than ‘‘rated at’’ 

together with the exemption 

methodology that NERC will develop as 

discussed in this Final Rule addresses 

the WPSC’s concern that utilities may 

elect to build facilities below 100 kV to 

avoid oversight. 

(i) Impact-Based Methodology and 

Regional Variation 

76. Several commenters argue that the 

Commission did not adequately justify 

the proposed changes to the ‘‘bulk 

electric system’’ definition and that the 

technical examples provided similarly 

do not justify the proposed changes. In 

their opinion, an impact-based 

methodology is superior to the proposed 

approach. The Commission does not 

support using the material impact tests 

proffered by commenters as a basis for 

determining a facility’s importance. 

Section 215 states that the Reliability 

Standards apply to facilities that are 

necessary for operating an 

interconnected electric energy 

transmission network (or any portion 

thereof). The material impact tests that 

either are under development or 

implemented appear to exclude 

facilities without regard to whether they 

are necessary to operate the system, and 

instead seek to determine the impact of 

the loss of an element. The Commission 

is not aware of any consistent and 

comprehensive material impact test that 

the industry has implemented to date. 

The scale and magnitude of generation 

and load loss during the Astoria West 

event described herein further 

demonstrates the shortcomings of 

NPCC’s material impact assessment in 

determining bulk electric system 

elements necessary to ensure reliable 

operation. We disagree with assertions 

that the Astoria West event was an 

invalid example, as the commenters did 

not provide sufficient evidence 

supporting their assertions. 

77. We disagree with commenters 

who assert that NPCC’s current material 

impact assessment, referred to as NPCC 

Document A–10, ensures that the proper 

facilities are included in the bulk 

electric system. Although the NPCC 

Document A–10 provides a test 

methodology to identify elements of the 

bulk electric system, the tests prescribed 

are subjective. In the test, a specific bus 

is subjected to a three-phase fault and 

the impacts on other buses are 

determined.86 NPCC Document A–10 

states that ‘‘a transient stability test may 

be done first to identify buses at which 

faults may cause a significant adverse 

impact outside of the ‘local area.’ ’’ 87

The term ‘‘local area’’ is broadly defined 

and is open to interpretation.88 Thus, 

under NPCC Document A–10, if an 

entity chooses a large geographical area 

for its ‘‘local area,’’ the impact resulting 

from a fault at a specific bus could be 

considered a ‘‘significant adverse 

impact,’’ but since the impact falls 

within the large ‘‘local area,’’ the bus 

may not be declared part of the bulk 

electric system. For example, if one 

entity defines the ‘‘local area’’ as the 

boundary of the balancing authority, 

while another entity defines the local 

area as adjacent buses, the outcome of 

the two tests could vary significantly. In 

particular, this likely could result in an 

exclusion of a large number of facilities 

from the purview of the bulk electric 

system for the first entity that applies a 

broader view of ‘‘local area.’’ 

78. NPCC Document A–10 does not 

assess whether the facilities within the 

‘‘local area’’ are necessary for reliable 

operation of the interconnected 

transmission network and also does not 

discuss system performance or any 

‘‘significant adverse impact’’ on the 

facilities within the ‘‘local area.’’ 

Therefore, facilities within a local area 

could operate in an unstable manner or 

violate emergency operating limits, and 

as long as these adverse effects are 


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89See, e.g., APPA, NRECA, CMUA, CPUC, and 

TANC. 

90TOP–002, Requirement R7 provides that ‘‘each 

Balancing Authority shall plan to meet capacity and 

energy reserve requirements, including the 

deliverability/capability for any single 

Contingency.’’ 

91Order No. 672, FERC Stats. & Regs. ¶ 31,204 at 

P 290. 

92See, e.g., Mandatory Reliability Standards for 

the Bulk Power System, Notice of Proposed 

Rulemaking, FERC Stats. & Regs., Proposed 

Regulations 2004–2007 ¶ 32,608, at P 280 (2006); 

U.S.-Canada Power System Outage Task Force, 

Final Report on the August 14, 2003 Blackout in the 

United States and Canada: Causes and 

Recommendations 107 (2004) (Blackout Report), 

available at http://www.ferc.gov/industries/electric/ 

indus-act/reliability.asp. 

93See WECC BESDTF Proposal V5 Appendix B, 

at B–11–B–12, available at http://www.wecc.biz/ 

Standards/Development/BES/ 

Shared%20Documents/WECC058%20BES%20Comments%20Posting%205/ 

P5%20Appendix%20B%20FINAL%20CLEAN.doc: 

‘‘The BESDTF considered the Northeast Power 

Coordinating Council’s Transfer Distribution Factor 

(TDF) approach to determining which networked 

Elements and facilities are used to distribute 

electricity locally and do not provide meaningful 

flow-through capability for the BES. In general, the 

TDF approach increases generation on one side of 

a transmission interface, decreases generation on 

the other side of the transmission interface, and 

measures the resulting change in flow across the 

interface. NPCC proposed that an Element with a 

TDF of less than 1% would not be part of the BES. 

WECC staff expressed concern that the results of 

the TDF studies subjectively depended on which 

generating units had their output increased and 

which generating units had their output decreased. 

The results would also depend on the location, and 

what kind, of slack bus [a designated generator bus 

without a real power injection setting used in 

power system modeling for the purpose of 

producing or absorbing real power such as change 

in real losses, loss of generation or interchange] 

used in the power flow simulation. As a result, the 

BESDTF did not propose to adopt the TDF method 

to determine which networked facilities could be 

Continued 

contained within the defined ‘‘local 

area,’’ NPCC’s Document A–10 

assessment would deem those facilities 

outside the scope of the bulk electric 

system. For these reasons, we believe 

NPCC’s Document A–10 assessment has 

resulted in an inconsistent process that 

excludes facilities from the bulk electric 

system. 

79. NARUC and other commenters 

contend that the Commission has not 

demonstrated any reliability issues 

created by NPCC’s current 

methodology.89 To the contrary, the 

NOPR noted that seven high and extrahigh voltage lines in NPCC are not 

included in the bulk electric system 

under the current definition, including 

some serving nuclear power plants, and 

pointed to several events that occurred 

in other regions on facilities that may 

not have been included in the bulk 

electric system if they were under 

NPCC’s current methodology. 

Additionally, thousands of megawatts of 

capacity resources are connected to 

these excluded transmission facilities. 

80. Further, there is even 

inconsistency within NPCC in that a 345 

kV tie-line between ISO–NE and NYISO 

is classified as part of the ‘‘bulk electric 

system’’ in one ISO but not the other. 

Regional classification inconsistencies 

can also lead to issues under TOP–002, 

Requirement R7.90 If one Regional 

Entity or balancing authority within a 

region complies with TOP–002, 

Requirement R7 by ensuring system 

deliverability during a single 

contingency along its portion of an 

intra-regional tie-line while the other 

Regional Entity or the other balancing 

authority within the same region on the 

other end of the tie-line does not, during 

a contingency, deliverability is not 

ensured, which could lead to loss of 

load and undermine reliability. 

81. Moreover, one of the main 

justifications for the Final Rule is to 

reduce inconsistencies across regions in 

order to increase the effectiveness of the 

NERC Reliability Standards. Some 

commenters challenge the supposition 

that regional inconsistency is a 

drawback of the current definition. 

Commenters state that regional variation 

allows regional entities to use their 

technical expertise to adopt a tailored 

regional bulk electric system definition. 

NARUC and Utah Municipal contend 

that a key part of the historical approach 

was the discretion of the Regional 

Entities. 

82. In response, as the Commission 

stated in Order No. 672, uniform 

Reliability Standards, and uniform 

implementation, should be the goal and 

the practice, the rule rather than the 

exception, absent a showing that a 

regional variation is superior or 

necessary due to regional differences.91

Consistency is important as it sets a 

common bar for transmission planning, 

operation, and maintenance necessary 

to achieve reliable operation. As noted, 

we have found several reliability issues 

with allowing Regional Entities broad 

discretion without ERO or Commission 

oversight. The Commission’s proposed 

approach to addressing these concerns 

will enable affected entities to pursue 

exemptions for facilities they believe 

should not be included in the bulk 

electric system, and also will allow 

Regional Entities to add facilities below 

100 kV they believe should be included. 

83. Additionally, Requirement R4 of 

PRC–001–1 (System Protection 

Coordination) requires that ‘‘[e]ach 

Transmission Operator shall coordinate 

protection systems on major 

transmission lines and interconnections 

with neighboring Generator Operators, 

Transmission Operators and Balancing 

Authorities.’’ If the protection systems 

on one end of the tie line that are not 

classified as bulk electric system are not 

coordinated with protection systems on 

the other end or with those protection 

systems on the major transmission lines 

connected to the same end, the 

protection system will not operate as 

desired and cascading outages are likely 

to occur. This could lead to a significant 

system event. Deficiencies and lack of 

coordination in protection systems have 

been and remain a major cause of power 

outages since the Reliability Standards 

became effective in June 2007.92 These 

are but a few examples of how uniform 

application of the Reliability Standards 

to lines operated at 100 kV or above 

results in improved reliability. These 

examples demonstrate that NPCC’s 

current methodology does not 

necessarily accurately assess situations 

that warrant exclusion of facilities from 

the bulk electric system definition. 

84. Separately, the NPCC impactbased test has excluded elements that 

interconnect generators, including 

multiple nuclear facilities. Nuclear 

facilities generally are significantly 

larger than other power plants, serve as 

base load, and often are critical to 

meeting capacity demand. They require 

external interconnections to provide 

power to auxiliary equipment within 

the plant under normal and emergency 

conditions, which includes issues 

related to black starts and system 

restoration. Additionally, many nonnuclear generators representing over 

10,000 MW of capacity resources that 

are subject to reliability rules and which 

provide needed capacity are 

interconnected to the network through 

facilities that are not classified as bulk 

electric system facilities under NPCC’s 

rules, which may undermine the 

reliability of the capacity provided. The 

facilities that these generators connect 

to tend to be 100 kV and above facilities 

that are operated in parallel with extra 

high voltage facilities and have 

numerous interconnections to the extra 

high voltage network while also serving 

some distribution facilities. 

85. Given the questionable and 

inconsistent exclusions of facilities from 

the bulk electric system by the material 

impact assessment and the variable 

results of the Transmission Distribution 

Factor test proposed in NPCC’s 

compliance filing in Docket No. RC09– 

3, there are no grounds on which to 

reasonably assume that the results of the 

material impact assessment are accurate, 

consistent, and comprehensive.93


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72922 Federal Register / Vol. 75, No. 227 / Friday, November 26, 2010 / Rules and Regulations 

classified as Local Distribution Networks and 

excluded from the BES.’’ 

94NOPR, FERC Stats. & Regs. ¶ 32,654 at 22. 

95See, e.g., WTOP story ‘‘Friday the 13th’’ 

Blackout hits DC (June 13, 2008), available at 

http://www.wtop.com/?sid=1421434&nid=25; CBS 

News story ‘‘Power Outage Knocks Out D.C.’’ (June 

13, 2008) (‘‘ ‘The White house had been running on 

generator power,’ said deputy press secretary Tony 

Fratto.’’) available at http://www.cbsnews.com/ 

stories/2008/06/13/national/main4178695.shtml. 

96See, e.g., New York Times article, ‘‘Brief Power 

Failure Is Long Enough to Unsettle’’ (June 28, 2007), 

available at http://query.nytimes.com/gst/ 

fullpage.html?res=9A02E0DB163EF93

BA15755C0A9619C8B63&sec=&spon=

&&scp=1&sq=Brief%20Power%

20Failure%20Is%20Long%

20Enough%20to%20Unsettle&st=cse; ABC News 

story ‘‘Power Back on in NYC after Outages’’ (June 

27, 2007), available at http://abclocal.go.com/wabc/ 

story?section=weather&id=5428326. 

97NYPSC at 10–11. The NYPSC’s comments do 

not specify whether ConEd took any action besides 

the telecommunications fixes. 

Additionally, we have noted how the 

results of multiple material impact tests 

can vary depending on how the test is 

implemented. In contrast, the proposed 

‘‘bright-line’’ test would continue the 

100 kV threshold currently in use 

throughout much of the industry 

without allowing entities to vary this 

definition outside a Commissionapproved exemption process. Further, 

since most regions currently use the 100 

kV general threshold, most regions 

should have little difficulty maintaining 

a 100 kV bright-line threshold. If NERC 

proposes an alternate methodology, it 

must ensure that the method is 

consistent, repeatable, and verifiable, 

which the material impact tests we have 

discussed are not. 

86. With respect to the comments 

about the relevance of the FRCC, 

ReliabilityFirst and Astoria West events, 

and statements that they do not provide 

an adequate basis for our action here, 

the Commission emphasizes that for the 

Reliability Standards to have their 

intended outcome of protecting the 

system from instability, uncontrolled 

separation, or cascading failures, the 

bulk electric system definition must 

include the facilities necessary for 

reliable operation of the system and the 

registered entities must comply with the 

requirements of the Reliability 

Standards applicable to those facilities. 

If the definition excludes facilities that 

are necessary for reliable operation, the 

result is that more system events may 

occur, the impact of such events may be 

broader, and NERC and the Commission 

may have little or no authority to 

require the entities to mitigate the issues 

going forward. The FRCC, 

ReliabilityFirst and Astoria West 

examples demonstrate that, had all the 

relevant requirements in the Reliability 

Standards been adhered to, such as 

those in the PRC, IRO and TOP 

categories, the impacts of the events 

could have been minimized, if not 

avoided all together. The examples also 

illustrate that, because FRCC and 

ReliabilityFirst classify the facilities at 

issue as part of the bulk electric system, 

NERC and the Commission could 

require mitigation or take other action to 

ensure that the entities comply with the 

Reliability Standards in the future, thus 

enhancing system reliability. On the 

other hand, NERC and the Commission 

were unable to require mitigation with 

respect to the NPCC event because 

NPCC’s definition excluded the 

facilities involved from the bulk electric 

system. We will address our specific 

concerns with each event in turn, 

below. 

FRCC Event 

87. The FRCC event originated from a 

single fault on a 138 kV facility, which 

is included in the ‘‘bulk electric system’’ 

according to FRCC’s definition. This 

single 138 kV fault led to the loss of 22 

transmission lines, 4,300 MW of 

generation, and 3,650 MW of customer 

service or load distributed over the 

lower two thirds of Florida. It is clear 

from the facts that this was a wide-scale 

cascading outage, which deserves the 

Commission’s attention. Subsequent to 

this event, Florida Power & Light 

implemented mitigation plans that 

would preclude similar problems. The 

Commission notes that if this same 

event had occurred in NPCC, the 

Commission or NERC would not have 

had the chance to require mitigation of 

the issue because these facilities would 

not be considered part of the bulk 

electric system. 

(iii) ReliabilityFirst Event 

88. Similarly, the June 13, 2008 event 

in ReliabilityFirst demonstrates how 

problems on 100–200 kV facilities can 

cascade into significant outages. As 

noted in NOPR, ‘‘the inappropriate 

operation of the relay on a 138 kV 

facility contributed to the loss of three 

138 kV–13 kV transformers, three 138 

kV transmission lines, and estimated 

loss of approximately 150 MW of firm 

load in a critical high population 

density area,’’ 94 that includes the White 

House, for over four hours.95 Because 

ReliabilityFirst classifies these facilities 

as part of the bulk electric system, the 

circumstances are covered by the 

Reliability Standards. Thus, 

ReliabilityFirst, NERC and the 

Commission are able to require 

mitigation, which can be informed by 

the mandatory Reliability Standards. 

Facilities similar to those involved in 

this example would not, in NPCC, be 

included under the bulk electric system 

definition. Thus those facilities would 

not have to be operated pursuant to the 

Reliability Standards and, if a problem 

occurred, neither the Commission nor 

NERC could require a mitigation plan to 

be developed and completed. 

(iv) Astoria West Event 

89. On the other hand, the ConEd 

Astoria West facilities are not part of the 

bulk electric system according to 

NPCC’s impact-based criteria. 

Nonetheless, as reported by the news 

media, the event resulted in widespread 

loss of load affecting around 385,000 

people in parts of Manhattan and the 

Bronx.96 The NYPSC identified the 

cause of the outage as a lightning strike 

not to any ConEd transmission facilities, 

but a communications facility. The 

Commission understands that this 

communication disruption to a 

protection system by itself did not cause 

any faults on the 138 kV facilities. 

However, as explained earlier, this nonfault (N–0) event resulted in the 

interruption of service to about 137,000 

customers, affecting portions of two 

boroughs in New York City, as well as 

the loss of five generators and six 138 

kV transmission lines. Unlike the FRCC 

event, ConEd was not required to 

mitigate, under section 215, the root 

cause of the Astoria event because the 

facilities are not included under the 

bulk electric system definition. We note 

that these facilities are not included in 

the definition despite the fact that the 

138 kV network is heavily 

interconnected to the extra-high voltage 

network through ten 138 kV phase angle 

regulators in 345 kV stations. 

Additionally, approximately 2,000 MW 

of capacity resources and a similarly 

large quantity of customer firm demand 

in the Astoria area is directly connected 

to the 138 kV network or supplied from 

the 138 kV to lower voltage levels via 

step-down transformers. While the 

NYPSC stated that ConEd did mitigate 

the communication issue at the cited 

location, it is not clear if ConEd 

addressed similar vulnerabilities at 

other locations or if other underlying 

root cause items were identified or 

addressed.97

(v) Relevance of TLR 

90. Reliability Standard IRO–006– 

4.1—Reliability Coordination— 

Transmission Loading Relief has the 

purpose of providing ‘‘Interconnectionwide transmission loading relief 


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98The NERC Glossary defines System Operating 

Limit as: ‘‘The value (such as MW, MVar, Amperes, 

Frequency or Volts) that satisfies the most limiting 

of the prescribed operating criteria for a specified 

system configuration to ensure operation within 

acceptable reliability criteria.’’ 

99The NERC Glossary defines Interconnection 

Reliability Operating Limit as ‘‘A System Operating 

Limit that, if violated, could lead to instability, 

uncontrolled separation, or Cascading Outages that 

adversely impact the reliability of the Bulk Electric 

System.’’ 

100See IRO–006–4.1, Requirement R1. 

101Flowgate 7004 in NPCC, which contains nonbulk electric system facilities, had 31 TLR events 

totaling 484 hours in 2009 and 44 TLR events 

totaling 798 hours to date in 2010. Additionally, 

three other NPCC flowgates that contain non-bulk 

electric system facilities had TLR events called in 

2009 and 2010. Specifically, flowgates 7001, 7002, 

and 7010 were collectively subject to 11 TLR events 

totaling 91 hours during that period. See NERC 

Transmission Loading Relief Procedure Logs 

(October 28, 2010) available at http:// 

www.nerc.com/filez/Logs/tlrlogs.html. 102Ontario Power at 4. 

103Order No. 672, FERC Stats. & Regs. ¶ 31,204 

at P 290. 

procedures that can be used to prevent 

or manage potential or actual [System 

Operating Limit] and [Interconnection 

Reliability Operating Limit] violations 

to maintain reliability of the Bulk 

Electric System.’’ The only time that 

transmission loading relief (TLR) 

procedures can be used is when a 

Reliability Coordinator is experiencing a 

potential or actual System Operating 

Limit (SOL) 98 or Interconnection 

Reliability Operating Limit (IROL) 99 on 

the bulk electric system within its 

Reliability Coordinator area.100 The 

Commission understands that TLR 

procedures used to curtail firm and nonfirm transactions 101 have been activated 

in NPCC on flowgates that contain 

facilities that are not part of the bulk 

electric system under NPCC’s definition, 

but were needed to prevent or manage 

potential or actual SOL or IROL 

violations on the NPCC-defined bulk 

electric system. Since a flowgate 

generally defines facilities that operate 

in parallel and collectively respond to a 

transmission loading relief event as if it 

were a single transmission facility, it is 

logical that these 115 and 138 kV 

parallel facilities are included in these 

flowgates. Therefore, we disagree with 

ICNU’s and NYSRC’s claims that these 

facilities can be dismissed as 

unimportant. If a flowgate contains 

facilities that are needed to prevent or 

manage SOL or IROL violations, they 

should be included in the bulk electric 

system. Since the material impact test 

did not show this, this is another 

indication that the test does not 

adequately identify bulk electric system 

elements. 

(vi) International Concerns 

91. Ontario Power contends that the 

Commission must explicitly state that 

the proposed change applies only to 

those jurisdictions within the United 

States. Ontario Power argues that 

although the Commission indicates that 

the proposal seeks to increase 

consistency across reliability regions by 

imposing a bright line definition, 

Ontario Power believes that 

implementation of the Order as 

currently proposed will not achieve this 

goal. Specifically, Ontario Power argues 

that the proposed modification ‘‘will 

simply move the point of demarcation 

from one methodology to the other (i.e., 

100 kV threshold versus a performancebased approach) from Regional Entity 

borders to National borders.’’ 102 Ontario 

Power reiterates that it is not aware of 

any significant reliability issues 

attributable to the use of NPCC’s 

performance-based methodology. 

Accordingly, Ontario Power does not 

believe that Canadian jurisdictions 

maintaining the performance-based 

approach would suffer reduced 

reliability as compared to those who are 

required to adopt the 100 kV threshold. 

92. Hydro-Que ́bec contends that the 

NOPR’s proposal does not take into 

account the characteristics of the 

Que ́bec Interconnection, particularly 

that it is asynchronous with the other 

systems that make up the Eastern 

Interconnection and thus is not freely 

influenced by power flows in other 

balancing areas. According to HydroQue ́bec, application of the NERC 

Reliability Standards should be limited 

to facilities with a material impact on 

reliability, and this decision is best left 

to the Regional Entities. 

93. The Joint Canadian Parties argue 

that the NOPR’s proposal would result 

in the Reliability Standards being 

applied to the majority of facilities 100 

kV and above, a significant number of 

which only impact the local area in the 

event of a contingency, and often under 

the purview of different regulatory 

authorities. Additionally, they state that 

the proposed ‘‘one-size fits all’’ approach 

does not give due consideration to 

either regional variations or the 

technical expertise of the regions. 

According to the Joint Canadian Parties, 

the impact-based methodology ensures 

that all facilities critical to wide-area 

reliability are included in the bulk 

electric system definition. 

94. The Commission acknowledges 

that it does not have jurisdiction to 

enforce a modified definition with 

respect to non-U.S. entities. However, as 

Ontario Power correctly notes, the 

problems discussed above with respect 

to transmission lines classified as ‘‘bulk 

electric system’’ in one region but not 

classified as such in a connected region 

also can occur when lines cross the 

international border. Thus, we will, and 

we encourage NERC to, work with the 

Canadian authorities to ensure 

consistent treatment of transmission 

lines that cross the border. 

95. In response to Ontario Power’s 

statement that it is not aware of any 

significant reliability issues attributable 

to use of NPCC’s material impact test, 

and the Joint Canadian Parties’ 

argument that the NOPR proposal 

would result in Reliability Standards 

being applied to facilities that only 

impact the local area, we have discussed 

elsewhere in this order our concerns 

with the NPCC methodology including 

the reliability concerns arising from that 

test’s inconsistent results and our 

concerns with the subjective nature of 

the term ‘‘local area’’ as defined in NPCC 

Document A–10. We also note that the 

Final Rule directs the ERO to consider 

adopting an exemption process that 

would help alleviate the Joint Canadian 

Parties’ concerns about a ‘‘one-size fits 

all’’ approach. Finally, because this 

Final Rule directs the ERO to develop a 

revised bulk electric system definition 

through the Standards Development 

process, the Canadian commenters will 

be able to raise and address a number 

of their substantive concerns in that 

forum. 

(4) Summary 

96. In general, the Final Rule 

identifies the reliability concerns 

created by the current definition and a 

method to ensure that certain facilities 

needed for the reliable operation of the 

nation’s bulk electric system are subject 

to mandatory and enforceable 

Reliability Standards, and that 

exemption methodologies would be 

developed by NERC and subject to 

Commission review. From the 

Commission’s review, the material 

impact assessments implemented by 

NPCC are subjective in nature, and 

results from such tests are inconsistent 

in application, as shown through the 

exclusion of facilities that clearly are 

needed for reliable operation. Further, 

we find that the vast majority of 100 kV 

and above facilities are part of parallel 

networks with high voltage and extra 

high voltage facilities and are necessary 

for reliable operation. As a result, and 

consistent with our previous statements 

in Order No. 672,103 we find it is best 

for the ERO to establish a uniform 

definition that eliminates subjectivity 

and regional variation in order to ensure 

reliable operation of the bulk electric 

system. We further find that the existing 


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104As noted previously, any alternative proposal 

must be as effective as, or superior to, the 

Commission’s proposed approach in addressing the 

identified technical and other concerns, and may 

not result in a reduction in reliability. 

105ReliabilityFirst at 10. 

106NOPR, FERC Stats. & Regs. ¶ 32,654 at P 18. 

107See, e.g., Alcoa, BPA, CMUA, Palo Alto, 

Redding, Constellation/CENG, ICNU, APPA/ 

NRECA, National Grid, NERC, NESCOE, NCPA, NV 

Energy, Public Power Council, SWTDUG, NYSRC, 

SCE, State Utility Commissions and Consumer 

Counsel, TANC, TAPS, Utah Municipal, Wells, 

WPSC. 

108See, e.g., EEI, BPA, Utility Services, Inc., 

NPCC, WECC, TAPS, Santa Clara, NUSCO, 

Indicated New York Transmission Owners, 

SWTDUG. 

109See, e.g., GTC/GSOC, Redding, Dow, NV 

Energy, PGE, TIEC. 

110APPA/NRECA at 19–23. 

111 Id. at 25–27. 

NPCC impact test is not a consistent, 

repeatable, and comprehensive 

alternative to the bright-line, 100 kV 

definition we prefer. By directing the 

ERO to revise the definition of ‘‘bulk 

electric system,’’ through the approach 

proposed by the Commission, or 

through an equally effective alternative 

proposed approach, the Commission is 

fulfilling its responsibility to ensure 

reliable operation of the grid.104 Any 

alternative proposal from the ERO must 

be as effective as, or more effective than 

the 100 kV threshold at ensuring 

facilities necessary for reliable operation 

are captured in the definition while also 

addressing the issues outlined in this 

Final Rule. 

(d) Usage and Definition of ‘‘Bulk-Power 

System’’ 

(1) Comments 

97. Anaheim states that the 

Commission’s observation that the term 

‘‘Bulk-Power System’’ is somehow 

broader than the term ‘‘bulk electric 

system,’’ coupled with its refusal to 

define, explain, or otherwise implement 

the statutory term, creates substantial 

uncertainty within the industry 

concerning the scope of the Reliability 

Standards going forward. 

98. ReliabilityFirst states the use of 

the terms ‘‘bulk electric system’’ and 

‘‘Bulk-Power System’’ at times has 

created confusion within the industry 

and in compliance enforcement matters. 

Therefore, ReliabilityFirst believes that 

NERC should formally document the 

use of both terms and, going forward, 

use a single term and definition for all 

compliance and enforcement of the 

Reliability Standards.105

99. SCE states that the industry has 

been seeking final resolution of the 

statutory term ‘‘Bulk-Power System’’ and 

requests that the Commission act now 

and through this Final Rule to resolve 

the statutory term ‘‘Bulk-Power System.’’ 

It requests that the Commission’s Final 

Rule recognize that the definition of 

‘‘bulk electric system’’ developed under 

this Final Rule is identical to the 

statutory term ‘‘Bulk-Power System’’ and 

no further definitional change will take 

place. 

(2) Commission Determination 

100. In the NOPR, the Commission 

addressed the definition of ‘‘bulk 

electric system’’ and not the definition 

of the statutory term ‘‘Bulk-Power 

System.’’ Although the statutory term 

Bulk-Power System defines our 

jurisdiction, the Commission believes 

more clarity and certainty is achieved in 

this context by focusing on whether 

facilities are part of the bulk electric 

system. Ensuring that the bulk electric 

system definition encompasses all 

facilities necessary to reliably operate an 

interconnected electric transmission 

system will not cause the application of 

the Reliability Standards to extend 

beyond the jurisdiction prescribed in 

section 215. The Commission, the ERO, 

and the Regional Entities will continue 

to enforce Reliability Standards for 

facilities that are included in the bulk 

electric system. 

2. Exemption Process 

101. The NOPR proposed that a 

Regional Entity must seek ERO and 

Commission approval before exempting 

any transmission facility rated at 100 kV 

or above from compliance with 

mandatory Reliability Standards.106

Pursuant to the NOPR proposal, a 

Regional Entity would submit proposed 

facility exclusions to the ERO and then, 

in turn, the ERO would submit to the 

Commission for review on a facility-byfacility basis any ERO-approved 

exception to the proposed threshold of 

all transmission facilities at 100 kV or 

above, except for radial transmission 

facilities serving only load with one 

transmission source. Any such 

submission would also include 

adequate supporting information 

explaining why it is appropriate to 

exempt a specific transmission facility 

that would otherwise satisfy the 

proposed 100 kV threshold. Only after 

Commission approval would the 

proposed exclusion take effect. 

(a) Comments 

102. Most commenters disagree with 

the exemption process outlined in the 

NOPR, and several requested that the 

Commission abandon the NOPR’s 

proposal or adopt a more streamlined 

process. NERC and other commenters 

characterize the Commission’s proposal 

as costly, time consuming, and 

potentially unworkable.107 Some parties 

suggested alternatives, such as the 

Commission reviewing and approving a 

Regional Entity’s exemption 

methodology rather than reviewing each 

individual’s exemption application. 

Other commenters argue that the 

Commission should approve a 

methodology that allows the Regional 

Entities or ERO to perform a facility-byfacility review rather than the 

Commission.108 Several commenters 

requested that the Commission adopt a 

blanket exemption for distribution 

facilities, as defined by the Regional 

Entities, or clarification that the 

Commission did not intend to include 

distribution facilities within the scope 

of the definition of bulk electric 

system.109 Commenters also request that 

the Commission suspend enforcement 

of Reliability Standards to newlyclassified bulk electric system facilities 

while the Regional Entities evaluate 

exemption requests. 

103. APPA/NRECA argues that the 

NOPR’s approach represents an extreme 

departure from current practice with 

respect to allowing appropriate 

exemptions from the Reliability 

Standards requirements. APPA/NRECA 

notes that entities seeking an exemption 

for even radial line facilities may 

require NERC and Commission approval 

before that exemption would take effect, 

and that these entities would not only 

have the burden of obtaining the 

necessary approvals for the exemption 

but also would have to comply with the 

Reliability Standards while those 

approvals are pending.110 APPA/ 

NRECA contends that the proposal 

could impose significant burdens on 

many smaller utilities, some of which 

have never been subject to Reliability 

Standards, without affording them any 

procedural protections and without 

imposing on Regional Entities the 

appropriate and parallel burden of 

demonstrating that expanded authority 

over low-voltage (less than 100 kV) 

facilities is necessary to preserve 

reliability.111

104. Alcoa points out that the 

proposal would increase the costs 

associated with their facilities in the 

NPCC region either through additional 

compliance measures associated with 

mandatory Reliability Standards or by 

obtaining approvals for an exemption 

from such requirements. EEI believes 

that NERC should determine whether to 

grant or deny a specific request for an 

exemption and that Commission 

approval should not be required in 

every case. Instead, an appeal to the 


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112See, e.g., NERC, NPCC, and Utility Services. 113ERCOT at 2. 

Commission should be available as an 

option. 

105. GTC/GSOC proposes that the 

definition for a blanket exemption of 

localized and load-serving lines include: 

An area serving load that is connected 

to the rest of that network at a single 

transmission substation at a single 

transmission voltage by one or more 

transmission circuits; tap lines and 

associated facilities that are required to 

serve local load only; and transmission 

lines that are operated open for normal 

operation. 

106. On the other hand, Manitoba 

Hydro supports the Commission’s 

proposal to require a Regional Entity to 

obtain NERC and Commission approval 

prior to exempting any facility rated at 

100 kV or above, except for radial 

transmission facilities serving only load. 

Manitoba Hydro also believes regulatory 

review provides a wider opportunity for 

stakeholder review. 

107. Several commenters argue that 

the Commission should direct 

modifications to section 500 of the 

NERC Rules of Procedure, which 

governs NERC’s business practices, 

including its operation and review 

processes.112 For example, NPCC 

proposes minimal revision to the NERC 

Rules of Procedure, Section 500 to 

include a process for evaluating bulk 

electric system exclusions 

recommended to NERC by the Regional 

Entities. NERC states that changes likely 

will be necessary in the NERC Rules of 

Procedure and the NERC Statement of 

Compliance Registry Criteria. 

108. TIEC states that many industrial 

sites are interconnected to the grid 

through lines rated at or above 100 kV, 

or otherwise contain lines rated at 100 

kV or above within a private use 

network. TIEC notes that although these 

lines are operated at a high voltage due 

to the size of the industrial loads, they 

are used to provide electric service to 

end-use industrial customers and do not 

serve a ‘‘transmission’’ function for the 

interconnected grid within the meaning 

of the Commission rules and NERC 

Reliability Standards. Instead, these 

facilities deliver electricity from the grid 

or a cogeneration facility to the 

consuming loads within a plant site. 

TIEC states that the Commission should 

clarify that customer-owned facilities 

that are used to distribute electricity to 

consuming facilities on the customer’s 

premises, which do not therefore serve 

a ‘‘transmission’’ function for the 

interconnected grid, are not part of the 

bulk electric system. Alcoa contends 

that its industrial facilities are 

connected to the grid using 115 kV lines 

for efficiency purposes, but that they 

have no practical impact on the grid, 

and therefore would be improperly 

included in the bulk electric system by 

the proposal. 

109. ExxonMobil suggests modifying 

the definition of the bulk electric system 

to include ‘‘those facilities rated at 100 

kV or above intended for the 

transmission of power within an 

interconnected grid,’’ i.e., ExxonMobil 

suggests that the Commission draw a 

distinction between facilities that could 

under limited circumstances transmit 

power but were not intended or 

designed to be a transmission path. 

ExxonMobil notes that in order to meet 

the reliability target requirements to 

safely and economically operate 

manufacturing and production facilities, 

many industrial facilities are fed by two 

or more utility transmission lines that 

originate at different utility substations. 

Due to the magnitude of an industrial 

site’s load, these transmission lines are 

typically designed to operate at levels in 

excess of 100 kV at the request of the 

utility company. These transmission 

lines typically terminate into an 

interconnection facility, owned by the 

industrial facility, that networks the 

transmission lines together within the 

industrial facility’s private use network 

in order to serve the load of the facility’s 

private use network. ExxonMobil states 

that its proposed approach is consistent 

with the Commission’s stated goal of 

requiring the Regional Entities to 

register transmission lines that are 

operated at the 100 kV level and above; 

while at the same time clearly excluding 

end user facilities rated 100 kV or 

above. 

110. ERCOT suggests that the 

Commission should consider imposing 

a parallel process for including facilities 

that are below 100 kV in the bulk 

electric system. ERCOT notes that 

presently, facilities below 100 kV 

generally are not considered part of the 

bulk electric system, but the Regional 

Entities can explicitly include facilities 

below 100 kV if they are deemed 

‘‘critical facilities.’’ ERCOT states that 

‘‘Regional Entities should not have 

unbounded unilateral discretion to 

make such designations given the 

potential impact to affected parties.’’ 113

Thus, consistent with the Commission’s 

proposal to subject all 100 kV and above 

exemptions to due process, ERCOT asks 

the Commission to consider imposing a 

similar process for the inclusion of 

facilities below 100 kV. 

(b) Commission Determination 

111. As mentioned above, the NOPR 

proposed an exemption process 

pursuant to which a Regional Entity 

would seek ERO and Commission 

approval before exempting a 

transmission facility rated at 100 kV or 

above from compliance with the 

Reliability Standards. In response to the 

NOPR proposal, we received numerous 

comments that the proposed exemption 

process would be costly, timeconsuming and potentially unworkable. 

Other commenters expressed concern 

that the proposal was unduly 

burdensome, particularly on smaller 

entities. We continue to believe that an 

exemption process is appropriate and is 

complementary to our directive, 

discussed earlier, that the ERO develop 

a revised definition of the term bulk 

electric system that addresses the 

concerns resulting from the current 

discretion of Regional Entities to 

develop alternative regional definitions 

of the term. However, we are persuaded 

by the commenters’ concerns and the 

Final Rule does not adopt the 

exemption model proposed in the 

NOPR. 

112. Rather than devising a revised 

exemption process in the Final Rule, we 

direct the ERO to develop a proposed 

exemption process. We believe that it is 

appropriate that NERC develop the 

process in its function as the ERO. 

Further, allowing the ERO to develop an 

appropriate exemption process should 

provide interested stakeholders an 

opportunity to participate in the 

development of the process, as 

requested by some commenters. This 

stakeholder participation should result 

in a process with practical application 

that is less burdensome than the NOPR 

proposal. 

113. The ERO must submit the 

proposed exemption process within one 

year of the effective date of this Final 

Rule. After notice and opportunity for 

comment, the Commission will act on 

the ERO’s proposal. 

114. We will not dictate the substance 

or content of the exemption process in 

this Final Rule. Rather, we identify 

below several matters or concerns that 

should be addressed in an acceptable 

exemption process. 

115. NERC should develop an 

exemption process that includes clear, 

objective, transparent, and uniformly 

applicable criteria for exemption of 

facilities that are not necessary for 

operating the grid. The ERO also should 

determine any related changes to its 

Rules of Procedures that may be 

required to implement the exemption 

process, and file the proposed 


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114Order No. 672, FERC Stats. & Regs ¶ 31,204 at 

P 140, 654. 

115See, e.g., Order No. 693, FERC Stats. & Regs. 

¶ 31,242 at P 77. 

116Mandatory Reliability Standard for Nuclear 

Plant Interface Coordination, Order No. 716, 125 

FERC ¶ 61,065, at P 51–53 (2008), order on reh’g, 

Order No. 716–A, 126 FERC ¶ 61,122 (2009). 

117Transmission Relay Loadability Reliability 

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

P 20–25, 47, 60, 62 (2010). 

118NOPR, FERC Stats. & Regs. ¶ 32,654 at P 27. 

119See, e.g., APPA/NRECA and Bay Area 

Municipal. 

120APPA/NRECA at 4. 

121 Id. at 35. 

122National Grid at 5. 

123 Id. at 3, 8 (estimating compliance costs for 

transmission planning standards alone to be $75 

million to $125 million). 

124 Id. at 5–6. 

125 See, e.g., APPA/NRECA, EEI, FRCC, NERC, 

NPCC, National Grid, NYISO, Northeast Utilities, 

Indicated New York Transmission Owners, and 

Utah Municipal. 

exemption process and rule changes 

with the Commission. 

116. As indicated above, since we are 

not adopting the exemption model 

proposed in the NOPR, we no longer 

contemplate a process that requires 

Commission review of each request for 

exemption. However, in order to avoid 

an inconsistent application of the 

exemption process, NERC should 

oversee the facility-by-facility 

exemption process to ensure an 

objective and uniform application of the 

exemption criteria that it develops. 

NERC may consider delegating 

responsibilities for the exemption 

process to Regional Entities, so long as 

the process is clear and capable of being 

applied consistently, objectively and 

uniformly across all regions. However, 

consistent with our statements in Order 

No. 672 regarding the need for a strong 

ERO, NERC should maintain oversight 

of any Regional Entity activity.114 We 

believe ERO oversight is also vital in 

ensuring consistent application of any 

nation-wide exemption criteria that the 

ERO develops. 

117. While the Commission will not 

require that we review each exemption 

on a facility-by-facility basis, we would 

maintain the authority to conduct audits 

to determine the appropriateness of a 

particular exemption. We contemplate 

that a Commission staff audit would 

review the application of the exemption 

criteria developed by NERC in NERC’s 

or a Regional Entity’s determination to 

approve an exemption for a particular 

facility. However, to facilitate such 

audits, the ERO should maintain a list 

of exempted facilities that can be made 

available to the Commission upon 

request. NERC can decide how best to 

maintain the list, including determining 

whether or not to post it on the NERC 

Web site. 

118. Additionally, the ERO should 

consider developing criteria for 

revoking an exemption if a particular 

transmission facility no longer qualifies 

for such an exemption. This may be 

appropriate, for example, when a 

transmission system in the vicinity 

undergoes a significant change. 

119. A number of comments raised 

concerns that the Commission’s 

directive that the ERO revise the 

definition of bulk electric system would 

result in the erroneous inclusion of 

distribution facilities within the 

definition. As we explained above, these 

arguments are unconvincing because the 

majority of facilities operated at or 

above 100 kV are parallel paths that are 

necessary for the reliable operation of 

the transmission system. In addition, 

the exemption process provides a means 

of ensuring that relatively high voltage 

distribution facilities are excluded from 

compliance with mandatory Reliability 

Standards. In this light, we believe that 

it would be beneficial for the ERO, in 

maintaining a list of exempted facilities, 

to consider including a means to track 

and review facilities that are classified 

as local distribution to ensure accuracy 

and consistent application of the 

definition. Similarly, the ERO could 

track exemptions for radial facilities. 

120. In response to comments seeking 

a blanket exemption for industrial 

facilities, the Commission is not 

inclined to grant categorical exemptions 

of any kind. However, NERC should 

consider the parties’ concerns regarding 

exemption categories in developing an 

exemption process and criteria. Entities 

can submit specific facilities for 

exemption through the NERC-developed 

exemption process. As previously 

discussed, radial facilities, as well as 

facilities used in the local distribution 

of electric energy as provided in section 

215, will continue to be excluded. 

121. We agree with ERCOT’s 

suggestion that the ERO should develop 

a parallel process for including as part 

of the bulk electric system ‘‘critical’’ 

facilities, operated at less than 100 kV, 

that the Regional Entities determine are 

necessary for operating the 

interconnected transmission network. 

Currently, Regional Entities have the 

ability to include ‘‘critical’’ facilities 

operated below 100 kV.115 We believe 

that it would be worthwhile for NERC 

to consider formalizing the criteria for 

inclusion of critical facilities operated 

below 100 kV in developing the 

exemption process. Additionally, we 

note that Order No. 716 creates a 

process to include critical facilities 

under NUC–001–1.116 Similarly, we 

note that Order No. 733 creates an 

additional ‘‘add in’’ approach to sub-100 

kV facilities that Regional Entities and 

planning coordinators have identified as 

critical to the reliability of the bulk 

electric system.117

3. Transition Process 

122. In the NOPR, the Commission 

proposed to allow a Regional Entity 

affected by the Commission’s Final Rule 

to submit a transition plan that allows 

a reasonable period of time for affected 

entities within that region to achieve 

compliance with respect to facilities 

that are subject to Commissionapproved Reliability Standards for the 

first time.118

(a) Comments 

123. Certain commenters argue that 

the NOPR fails to clearly detail a 

transition process for bringing 

additional facilities into compliance 

with Commission-approved Reliability 

Standards.119 APPA/NRECA believe 

that if the definition of bulk electric 

system is ultimately modified, NERC 

should be responsible for developing a 

clear and achievable transition plan to 

bring new facilities (and entities) into 

compliance.120 APPA/NRECA further 

note that the NOPR is somewhat 

inconsistent in its discussion of a 

transition plan and required 

compliance, recognizing at one point 

that a transition plan for newly-affected 

facilities would be appropriate while 

elsewhere stating that facilities falling 

within the broad definition of bulk 

electric system would only be exempt 

after Commission approval.121

124. National Grid requests that the 

Commission allow entities affected by 

the new rule the opportunity to develop 

a reasonable transition plan for bringing 

existing facilities into compliance with 

newly-applicable Commission-approved 

Reliability Standards, through a 

collaborative process involving NERC, 

Regional Entities, state commissions 

and other affected parties.122 National 

Grid notes that the process for bringing 

all of its and its subsidiaries’ newlyaffected facilities into compliance could 

take several years and would require 

significant increases in operations and 

maintenance costs as well as capital 

expenditures.123 National Grid suggests 

a transition period of 24–36 months 

would be necessary to study and to 

begin to implement compliance 

programs.124

125. Several commenters state that the 

Final Rule should include a sufficient 

transition period, and many propose 

specific minimum transition time 

periods.125 For example, FRCC 


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126FRCC at 9. 

127NPCC at 5. 

128NYISO at 8–9. 

129 Id. 

130See, e.g., Utility Services, Dow, and ELCON. 

131Utility Services at 5. 

132ELCON at 5. 

133 Dow at 7. 

134Order No. 693, FERC Stats. and Regs. ¶ 31,242 

at P 221–222. 135 Indicated New York Transmission Owners at 

11. 

136See, e.g., Northeast Utilities at 6. 

137NYISO at 11. 

138 16 U.S.C. 824s(b)(4)(A); see also 18 CFR 

35.35(f)(2010). 

139See, e.g., WECC, State Utility Commissions 

and Consumer Counsel, WPSC, Joint Western 

Commenters, Snohomish. 

140 Id. 

141See, e.g., Bay Area Municipal, Joint Western 

Commenters, Redding, NV Energy, Snohomish, 

Tacoma Power, Utah Municipal. 

recommends a transition period of 24 

months for Registered Entities to phase 

in compliance of additional facilities 

with Commission-approved Reliability 

Standards.126

126. NPCC recommends that the 

effective date of any new bulk electric 

system definition be 24 months 

following the Commission’s Final Rule 

and that within 90 days of the Final 

Rule, all Registered Entities be required 

to submit implementation plans to bring 

all newly identified bulk electric system 

facilities into compliance and submit 

any needed changes in registration by 

the effective date of the bulk electric 

system definition.127

127. Likewise, NYISO recommends 

that the effective date of any new 

definition should be no sooner than 24 

months following the effective date of a 

Commission order requiring compliance 

with that definition.128 NYISO further 

argues that during the transition period, 

no parties should be required to selfreport or be deemed non-compliant by 

NPCC.129

128. Several commenters request that 

the Commission provide for temporary 

waivers from enforcement of 

Commission-approved Reliability 

Standards while entities wait for initial 

exemption requests to be processed.130

For example, Utility Services argues that 

the Commission must grant a temporary 

waiver for audit, certification, or other 

compliance requirements to any 

requesting Registered Entity while its 

application is pending at the regional, 

NERC, or Commission levels, as this 

process has already been deemed 

acceptable by the Commission in the 

technical feasibility exemptions for 

cyber security.131 Similarly, ELCON 

argues that the Commission should 

clarify that a facility will not be subject 

to the obligations of registered status 

until the notification and any review 

process, followed by the transition 

period, is completed.132

129. Dow argues that the Commission 

must afford companies an opportunity 

to secure facility-specific exemptions 

before the Commission-approved 

Reliability Standards become applicable 

to those facilities.133

130. NYISO further argues that during 

the transition period no parties should 

be required to self-report or be deemed 

non-compliant by a Regional Entity. 

(b) Commission Determination 

131. As discussed above, we are 

directing the ERO to revise the 

definition through the Standards 

Development Process. We direct NERC 

to work with the Regional Entities 

affected by this Final Rule to submit for 

Commission approval transition plans 

that allow a reasonable period of time 

for the affected entities within each 

region to achieve compliance with 

respect to facilities that are subject to 

Commission-approved Reliability 

Standards for the first time based on a 

revised bulk electric system definition. 

The Commission expects that NPCC is 

the only region that will be significantly 

affected. Based on ReliabilityFirst’s 

experience in adopting a ‘‘bright-line’’ 

definition for bulk electric system 

facilities, we expect transition periods 

not to exceed 18 months from the time 

the Commission approves a revised 

definition and exemption process, 

unless the Commission approves a 

longer transition period based on 

specific justification. The Commission 

directs NERC to file the proposed 

transition plans within one year of the 

effective date of this Final Rule. 

132. While the Commission is 

sensitive to commenters’ concerns 

regarding non-compliance during the 

transition period, the Commission will 

not provide a trial period, as we 

declined to do in Order No. 693,134 with 

respect to those facilities that are subject 

to Commission-approved Reliability 

Standards for the first time. We expect 

that the transition periods will be long 

enough for exemption requests to be 

processed and to allow entities to bring 

newly-included facilities into 

compliance prior to the mandatory 

enforcement date. Additionally, the 

ERO and Regional Entities may exercise 

their enforcement discretion during the 

transition period. 

4. Cost Recovery 

(a) Comments 

133. The Indicated New York 

Transmission Owners requested that the 

Commission provide a new process to 

ensure recovery for costs incurred by 

NPCC members to comply with 

implementation of the new definition of 

bulk electric system.135 While not 

seeking a specific cost recovery 

mechanism, other commenters noted 

their concern that the transition period 

established by the Commission must be 

sufficient to allow affected companies to 

recover any one-time or annual 

compliance costs incurred.136 NYISO 

states that implementing the 100 kV 

‘‘bulk electric system’’ definition in the 

New York Control Area will cause it to 

incur increased capital costs and staff 

additions for which cost recovery will 

be required.137

(b) Commission Determination 

134. We note that the Commission has 

adopted an explicit rule, as required 

under Section 219(b)(4) of EPAct 2005, 

allowing the recovery of ‘‘all prudently 

incurred costs necessary to comply with 

mandatory reliability standards issued 

pursuant to section 215,’’ 138 and that 

the proposed modifications to the 

definition of bulk electric system do not 

raise any new issues with respect to cost 

recovery of reliability compliance costs. 

Finally, the transition plan that we 

direct herein will facilitate an 

opportunity for transmission owners 

and any other affected entities to 

recover any one-time or annual costs of 

compliance that result from any changes 

to the definition of ‘‘bulk electric 

system’’ as ultimately adopted by NERC. 

5. Issues Regarding the Western 

Interconnection 

(a) Comments 

135. Several entities from the Western 

Interconnection state that the proposal 

should not apply to the Western 

Interconnection because the West is 

built and operated differently.139 The 

parties argue that 100–200 kV facilities 

in the West are often used for 

distribution of power and have a limited 

or no impact on reliability over the 

wider area.140 Multiple entities 

supported utilizing a technical test to 

differentiate which facilities should be 

included, such as the material impact 

assessment methodology currently being 

developed by the WECC BESDTF.141

Several commenters also argue that the 

proposal would be expensive to 

implement while providing minimal 

reliability benefits. 

136. State Utility Commissions and 

Consumer Counsel state that facilities 

ranging from 100–199 kV in the West 

are typically used for radial distribution 

or local area distribution networks, and 

not necessarily for bulk power 


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142State Utility Commissions and Consumer 

Counsel at 2. 

143 Id. 

144 Id. 

145WPSC at 2–3. 

146 Id. at 2–3, 5; Utah Municipal at 6–7. 

147Utah Municipal at 5–7. 

148 Id. at 8. 

149 Id. at 13. 

150See WECC Rated Path Catalog. 

151 In the Western Interconnection, 59 percent of 

the total circuit miles of transmission lines above 

100 kV also are above 200 kV, compared to 43 

percent in the Eastern Interconnection. See NOPR, 

FERC Stats. & Regs. ¶ 32,654 at n. 36. 

152See http://www.wecc.biz/Standards/ 

Development/BES/default.aspx. 

153 June 2007 Filing at 13–14. 

154Order No. 672, FERC Stats. & Regs. ¶ 31,204 

at P 331. 

155 Id. at P 325. 

156See, e.g., Version One Regional Reliability 

Standard for Resource and Demand Balancing, 133 

FERC ¶ 61,063, at P 14 (2010); North American 

Electric Reliability Corporation Reliability 

Standards Development and NERC and Regional 

Entity Enforcement, 132 FERC ¶ 61,217 at P 112 

(2010). 

157NERC at 12–14; see also Palo Alto at 6–7, 

NCPA at 6–10. 

158NERC has undertaken an initiative to address 

the special circumstances associated with 

generators and to determine which Reliability 

Standards might be inappropriate for such limited 

facilities. The GOTO task force was formed in 

February 2009, and included a broad array of 

participants across regions and industry segments, 

transmission.142 They believe that a 200 

kV bulk electric system threshold 

reflects the usage and history of the 

Western Interconnection.143 They 

further argue that nearly all new 

transmission in the West is being built 

at 500 and 230 kV and that the average 

line capacity of 100–199 kV lines makes 

up a very small percentage of the overall 

network capacity in the West.144

137. The WPSC notes that certain 

utilities within its service area have 

elected to build distribution facilities 

above 100 kV, and such utilities could 

become subject to substantial 

compliance costs without measurable 

benefits under the proposed bright-line 

rule.145 Moreover, if the 100 kV 

threshold is adopted, certain 

commenters are concerned that utilities 

will elect to build facilities below 100 

kV in order to avoid complying with the 

Commission-approved Reliability 

Standards.146

138. Likewise, Utah Municipal argues 

that any proposal to classify facilities in 

excess of 100 kV as part of the bulk 

electric system may be appropriate for 

the Eastern Interconnection, but that 

such an approach is inappropriate and 

extremely burdensome for entities in the 

Western Interconnection.147 Utah 

Municipal further notes that the NOPR 

does not address the ‘‘demonstrable 

differences between the Western and 

Eastern Interconnections,’’ i.e., that the 

spread out nature of the West makes use 

of lines over 100 kV appropriate for use 

as distribution lines.148 Rather than 

adopting an across the board change in 

each region’s approach to determining 

‘‘bulk electric system’’ facilities, Utah 

Municipal recommends letting the 

WECC BESDTF finish work on its 

hybrid threshold and material impact 

assessment classification, and requests 

that the Commission defer to the 

technical experts at Regional Entities 

such as WECC regarding any bulk 

electric system definition change.149

(b) Commission Determination 

139. The Commission does not agree 

with the commenters’ arguments that 

100–199 kV facilities in the Western 

Interconnection should be treated 

differently than facilities in the Eastern 

Interconnection as a threshold matter. 

The bulk electric system definition 

should include all facilities that are 

necessary for operating an 

interconnected electric transmission 

network. While commenters have 

implied that not all 100–199 kV 

facilities are needed for reliable 

operation, the Commission notes that 

100 kV and some lower voltage facilities 

are included in some of the WECC Rated 

Paths. Clearly, these facilities are 

operationally significant and needed for 

reliable operation as identified by 

certain WECC documents.150 Any entity 

wishing to seek exemption of non-radial 

facilities from compliance with 

Commission-approved Reliability 

Standards may utilize the exemption 

process NERC will develop. While the 

Western Interconnection has a higher 

percentage of transmission facilities 

above 200 kV compared to the Eastern 

Interconnection,151 it is how the lines 

below 200 kV are interconnected with 

higher voltage facilities that determines 

their significance. 

140. Therefore, commenters have not 

provided adequate explanation in this 

proceeding, supported by data and 

analysis, as to why there is a physical 

difference upon which to treat the 

Western Interconnection differently. In 

fact, the present WECC definition uses 

100 kV as the threshold for classifying 

bulk electric system facilities.152 The 

Commission understands that the audits 

performed by WECC and self-reporting 

by entities includes all facilities 100 kV 

and above.153

141. Further, the suggestion that the 

modifications should not apply to the 

West contradicts guidance regarding 

Reliability Standards from Order No. 

672. Order No. 672 details several 

factors the Commission will consider in 

determining whether a proposed 

Reliability Standard is just and 

reasonable. One of the factors indicates 

that a ‘‘proposed Reliability Standard 

should be designed to apply throughout 

the interconnected North American 

Bulk-Power System, to the maximum 

extent this is achievable with a single 

Reliability Standard.’’ 154 Moreover, and 

particularly compelling with respect to 

the definition of bulk electric system, 

Order No. 672 indicates that proposed 

Reliability Standards ‘‘should be clear 

and unambiguous regarding what is 

required and who is required to 

comply.’’ 155 Eliminating broad regional 

discretion without ERO or Commission 

oversight and maintaining a 100 kV 

bright-line definition, coupled with an 

exemption process, removes any 

ambiguity regarding who is required to 

comply and accomplishes the goal of 

reducing inconsistencies across regions. 

Commenters have not provided 

compelling evidence that the proposed 

definition should not apply to the 

United States portion of the Western 

Interconnection as a threshold matter. 

As Order No. 672 detailed, however, the 

regions may propose: (1) A regional 

difference that is more stringent than 

the continent-wide definition, including 

a regional difference that addresses 

matters that the continent-wide 

definition does not; or (2) a regional 

definition that is necessitated by a 

physical difference in the Bulk-Power 

System. Should a region decide to 

propose a regional difference, in 

addition to the criteria above, such a 

proposal must address the 

Commission’s concerns with the present 

definition with the understanding that 

any such alternative must be as effective 

as, or more effective than, the 

Commission’s proposed approach in 

addressing the identified technical and 

other concerns, and may not result in a 

reduction in reliability.156

6. Impact on Generation Owners and 

Operators 

(a) Comments 

142. NERC and several other 

commenters raise the concern that the 

revised definition could bring a large 

number of generator owners and 

generator operators within the ambit of 

the Reliability Standards for the first 

time, and could result in an extremely 

large number of exemption requests 

despite the fact that the relevant 

facilities can have limited or no impact 

on the Bulk-Power System.157 NERC 

and other commenters generally request 

that the Ad Hoc Group for Generator 

Requirements at the Transmission 

Interface (the ‘‘GOTO task force’’) 158


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with representatives from operating and planning 

perspectives. The GOTO task force developed a 

Final Report, issued in November 2009, and has 

submitted a Standards Authorization Request to 

NERC to implement its proposed recommendations. 

See Final Report from the Ad Hoc Group for 

Generator Requirements at the Transmission 

Interface and related materials, available at http:// 

www.nerc.com/filez/standards/Project2010- 

07_GOTO_Project.html. 

159NERC at 14; Palo Alto at 7, NCPA at 9–10. 

160U.S. Department of Interior at 1–2 (suggesting 

that small generators be defined as set out in the 

NERC Statement of Compliance Registry Criteria, 

Section III(c)). 

161The GOTO task force was formed in February 

2009, and included a broad array of participants 

across regions and industry segments, with 

representatives from operating and planning 

perspectives. The GOTO task force developed a 

Final Report, issued in November 2009, and has 

submitted a Standards Authorization Request to 

NERC to implement its proposed recommendations. 

NERC and other commenters generally request that 

the GOTO task force findings and process be taken 

into account as part of any final Commission rule, 

and/or that any new ‘‘bulk electric system’’ 

definition otherwise adopted be developed in 

concert with the GOTO task force findings. 

162See, e.g., North Carolina Independent 

Cooperatives, SWTDUG. 

163ReliabilityFirst at 6. 

164 44 U.S.C. 3507(d). 

165 ‘‘NPPC Registered Entities as of January 13, 

2010,’’ available on the NPCC Web site: http:// 

www.npcc.org/. 

findings and process be taken into 

account as part of any final Commission 

rule, and/or that any new ‘‘bulk electric 

system’’ definition otherwise adopted be 

developed in concert with the GOTO 

task force findings.159

143. A few other parties request 

additional clarification with respect to 

the proposed rule’s applicability to 

generation facilities. The U.S. 

Department of the Interior suggests that 

the Commission clarify its policy 

regarding the exclusion of radial lines 

from the bulk electric system definition, 

such that transmission facilities linking 

small generators are also treated as 

excluded radial lines.160 WECC notes 

that the Commission’s proposed brightline standard is somewhat unclear, in 

that parts of the NOPR suggest that the 

100 kV standard would apply only to 

transmission facilities, while the current 

‘‘bulk electric system’’ definition used by 

NERC applies to transmission, 

generation, and interconnection 

facilities. 

(b) Commission Determination 

144. We expect that our decision to 

direct NERC to develop a uniform 

modified definition of ‘‘bulk-electric 

system’’ will eliminate regional 

discretion and ambiguity. The change 

will not significantly increase the scope 

of the present definition, which applies 

to transmission, generation and 

interconnection facilities. The proposed 

exemption process will provide 

sufficient means for entities that do not 

believe particular facilities are necessary 

for operating the interconnected 

transmission system to apply for an 

exemption. 

145. As noted above, NERC has 

undertaken an initiative to address the 

special circumstances associated with 

such generators.161 Although the NERC 

Board of Trustees has not approved any 

action arising from the GOTO task force 

at this time, the task force members may 

submit their comments and report to 

NERC for its consideration as NERC 

develops an exemption process. 

7. Clarifying Terms 

(a) Comments 

146. Several commenters seek 

clarification on the definitions and 

implications of specific terms and 

concepts such as ‘‘integrated 

transmission element’’ and ‘‘material 

impact.’’ 162

147. For example, the North Carolina 

Independent Cooperatives request that 

the Commission clarify the terms 

‘‘integrated transmission element’’ and 

‘‘material impact.’’ They state that unless 

these terms are clarified there is a real 

danger that very small facilities will be 

unnecessarily included in the bulk 

electric system and their owners 

subjected to unreasonable compliance 

costs. The North Carolina Independent 

Cooperatives propose that the 

Commission adopt additional factors to 

determine the types of facilities that fall 

within or outside of the scope of these 

terms. 

148. ReliabilityFirst requests 

clarification on whether transformers 

with a high side winding above 100 kV 

and a low side winding below 100 kV 

are included in the bulk electric system 

definition. It argues that, to eliminate 

uncertainty, ‘‘any and all’’ facilities that 

operate at 100 kV or above should be 

considered bulk electric system 

facilities, even if, for example, one 

transformer winding operates below 100 

kV.163

(b) Commission Determination 

149. With regard to ReliabilityFirst’s 

comments, we agree with its developed 

delineation point with regard to ‘‘stepdown’’ transformers, but note that these 

kinds of refinements can and should be 

addressed as part of NERC’s exemption 

process. 

150. We disagree with commenters 

that definitions of ‘‘integrated 

transmission elements’’ and ‘‘material 

impact’’ are needed to implement this 

Final Rule. These terms are not defined 

by the present bulk electric system 

definition, and defining these terms is 

not necessary to revise the definition as 

directed herein. Whether specific 

facilities have a material impact is not 

dispositive with respect to whether they 

are needed for reliable operation. These 

questions are more appropriately 

addressed through development of an 

exemption process at NERC. 

III. Information Collection Statement 

151. The information collection 

requirements in this Final Rule are 

identified under the Commission data 

collection, FERC–725–A ‘‘Revision of 

Definition of Bulk Electric System.’’ 

Under section 3507(d) of the Paperwork 

Reduction Act of 1995,164 the proposed 

reporting requirements in the subject 

rulemaking will be submitted to OMB 

for review. Interested persons may 

obtain information on the reporting 

requirements by contacting the Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 20426 

(Attention: Michael Miller, Office of the 

Executive Director, 202–502–8415) or 

from the Office of Management and 

Budget (Attention: Desk Officer for the 

Federal Energy Regulatory Commission, 

fax: 202–395–7285, e-mail: 

oira_submission@omb.eop.gov). 

152. The ‘‘public protection’’ 

provisions of the Paperwork Reduction 

Act of 1995 require each agency to 

display a currently valid control number 

and inform respondents that a response 

is not required unless the information 

collection displays a valid OMB control 

number on each information collection 

or provides a justification as to why the 

information collection number cannot 

be displayed. In the case of information 

collections published in regulations, the 

control number is to be published in the 

Federal Register. 

153. Public Reporting Burden: In the 

NOPR, the Commission based its 

estimate of the Public Reporting Burden 

on its belief that only one Regional 

Entity, NPCC, would be immediately 

affected by the Commission’s proposal. 

In particular the Commission stated that 

the transmission owners, transmission 

operators and transmission service 

providers in the U.S. portion of the 

NPCC region would be affected by the 

Commission’s proposal. Based on 

registration information available on 

NPCC’s Web site, it appeared that 

approximately 33 transmission owners, 

transmission operators and transmission 

service providers in the U.S. portion of 

the NPCC region would potentially be 

affected by the Commission’s 

proposal.165 These entities are currently 

responsible for complying with 

applicable mandatory Reliability 


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166APPA/NRECA at 37–40. 

167Regulations Implementing the National 

Environmental Policy Act, Order No. 486, 52 FR 

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

Preambles 1986–1990 30,783 (1987). 

168 18 CFR 380.4(a)(5). 

169 Greenburgh at 2. 

Standards approved by the Commission 

in Order No. 693 and subsequent orders. 

Given these parameters, the 

Commission estimated the Public 

Reporting Burden as follows: 

Data collection Numbers of 

respondents 

Numbers of 

responses 

Hours per 

respondent Total annual hours 

FERC–725–A 

Transmission Owners, Transmission Operators and Transmission Service Providers in the 

U.S. portion of the NPCC Region.

33 1 Reporting: 0 ................................... Reporting: 0. 

Recordkeeping: 500 ....................... Recordkeeping: 16,500. 

Total ......................................... ........................ ........................ ........................................................ 16,500. 

154. Based on the available 

information, the Commission estimated 

that 33 entities would be affected by the 

proposal. The Commission also 

estimated that it would require 16,500 

total annual hours for collection 

(reporting and recordkeeping) and that 

the average annualized cost of 

compliance would be $660,000 ($40/ 

hour for 16,500 hours; the Commission 

based the $40/hour estimate on $17/ 

hour for a file/record clerk and $23/hour 

for a supervisor). 

155. Commenters argue that the 

Commission has severely 

underestimated the potential impact of 

the change in the definition of bulk 

electric system and the exemption 

process as proposed in the NOPR. 

APPA/NRECA asserts that the NOPR is 

deficient in its assessment of the public 

reporting burden.166 APPA/NRECA 

argues that the burden of compliance 

and/or of obtaining exempt status is 

significant and reaches far beyond 

entities in NPCC. Moreover, APPA/ 

NRECA notes that the Commission has 

used underlying assumptions about the 

kind and cost of work needed to comply 

with the change in rules that 

significantly underestimate the costs 

associated with compliance. Finally, 

APPA/NRECA argues that the NOPR is 

deficient in failing to make any 

assessment of the increased burden 

related to the change in the 

Commission’s approach to allowing 

lower-voltage (less than 100 kV) 

facilities to be included as part of the 

bulk electric system by a Regional 

Entity. 

156. Snohomish argues that the NOPR 

does not reflect the existing practice 

outside NPCC and that the Commission 

is simply wrong in asserting that the 

NOPR proposal would not substantially 

increase regulatory compliance burdens. 

Snohomish asserts that the 

Commission’s stated basis for 

compliance with the Paperwork 

Reduction Act and associated 

regulations is incorrect. 

157. Given the Commission’s decision 

to direct NERC to develop a revised bulk 

electric system definition, rather than 

implement the NOPR’s proposal, and by 

granting certain clarifications, some of 

the comments are no longer relevant 

and the remainder are best responded to 

in a future order addressing the revised 

definition developed by NERC. By 

directing NERC to develop a revised 

definition, the Commission is 

maintaining the status quo (i.e., the 

current bulk electric system definition) 

until the Commission approves a 

revised definition. Thus, the 

Commission’s action does not add to or 

increase entities’ reporting burden. 

IV. Environmental Analysis 

158. 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.167 The Commission has 

categorically excluded certain actions 

from this requirement as not having a 

significant effect on the human 

environment. The actions proposed here 

fall within the categorical exclusion in 

the Commission’s regulations for rules 

that are clarifying, corrective or 

procedural, for information gathering, 

analysis, and dissemination.168

Accordingly, neither an environmental 

impact statement nor environmental 

assessment is required. 

159. Greenburgh Environmental 

Forum LORAX Working Group 

(Greenburgh) states that the Commission 

must address the environmental impact 

of the NOPR on the human 

environment.169

160. We disagree with Greenburgh. 

Any revised bulk electric system 

definition the ERO develops will not 

modify thresholds established in 

individual Reliability Standards such as 

FAC–003 with respect to vegetation 

management. The Final Rule requires 

the ERO to clarify which facilities will 

be included within the definition of 

‘‘bulk electric system’’ and 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. 

V. Regulatory Flexibility Act Analysis 

161. The Regulatory Flexibility Act of 

1980 (RFA) generally requires a 

description and analysis of any final 

rule that will have significant economic 

impact on a substantial number of small 

entities. The RFA does not mandate any 

particular outcome in a rulemaking, but 

rather requires consideration of 

alternatives that are less burdensome to 

small entities and an agency 

explanation of why alternatives were 

rejected. 

162. In drafting a rule, an agency is 

required to: (1) Assess the effect that its 

regulation will have on small entities; 

(2) analyze effective alternatives that 

may minimize a regulation’s impact; 

and (3) make the analyses available for 

public comment. In its NOPR, the 

agency must either include an Initial 

Regulatory Flexibility Act Analysis 

(Initial Analysis) or certify that the 

proposed rule will not have a 

‘‘significant impact on a substantial 

number of small entities.’’ 

163. If, in preparing the NOPR, an 

agency determines that the proposal 

could have a significant impact on a 

substantial number of small entities, the 

agency shall ensure that small entities 

will have an opportunity to participate 

in the rulemaking procedure. 

164. In its Final Rule, the agency must 

also either prepare a Final Regulatory 

Flexibility Act Analysis (Final Analysis) 

or make the requisite certification. 

Based on the comments the agency 

receives on the NOPR, it can alter its 


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Federal Register / Vol. 75, No. 227 / Friday, November 26, 2010 / Rules and Regulations 72931 

170APPA/NRECA at 41–42. 

171TAPS at 12. 

original position as expressed in the 

NOPR but it is not required to make any 

substantive changes to the proposed 

regulation. 

165. The statute provides for judicial 

review of an agency’s final RFA 

certification or Final Analysis. An 

agency must file a Final Analysis 

demonstrating a ‘‘reasonable, good-faith 

effort’’ to carry out the RFA mandate. 

However, the RFA is a procedural, not 

a substantive, mandate. An agency is 

only required to demonstrate a 

reasonable, good faith effort to review 

the impact the proposed rule would 

place on small entities, any alternatives 

that would address the agency’s and 

small entities’ concerns and their 

impact, provide small entities the 

opportunity to comment on the 

proposals, and review and address 

comments. An agency is not required to 

adopt the least burdensome rule. 

Further, the RFA does not require an 

agency to assess the impact of a rule on 

all small entities that may be affected by 

the rule, only on those entities that the 

agency directly regulates and that are 

subject to the requirements of the rule. 

A. NOPR Proposal 

166. In the NOPR, the Commission 

stated that the immediate effect of the 

proposed directive that the ERO revise 

its current definition of bulk electric 

system to establish a 100 kV threshold 

would likely be limited to certain 

transmission owners, transmission 

operators and transmission service 

providers in the U.S. portion of the 

NPCC region. Most transmission 

owners, transmission operators and 

transmission service providers do not 

fall within the definition of small 

entities. The Commission estimated that 

approximately four of the 33 

transmission owners, transmission 

operators and transmission services 

providers may fall within the definition 

of small entities. The Commission 

determined that this rule will not have 

a significant economic impact on a 

substantial number of small entities. 

Accordingly, no regulatory flexibility 

analysis is required. 

B. Comments 

167. APPA/NRECA state that the 

Commission’s RFA statement is flawed, 

in that the likely impacts of the 

proposed rule will reach far beyond 

entities in NPCC. APPA/NRECA argues 

that it is a substantial possibility that a 

substantial number of entities outside of 

NPCC will be affected by the proposal. 

As such, it asks for a delay in 

implementing the proposal in order to 

avoid impacting a broader group of 

smaller entities.170

168. TAPS generally supports the 

APPA/NRECA comments on the 

Commission’s RFA analysis. TAPS 

argues that the NOPR’s RFA 

Certification, which states that only a 

few (presumably already-registered) 

transmission owners, transmission 

operators, and transmission service 

providers in the NPCC footprint would 

be affected by this rulemaking, is fatally 

flawed.171

C. Commission Determination 

169. The Commission disagrees with 

commenters that challenge the 

Commission’s conclusion that the rule 

will not have a significant economic 

impact on a substantial number of small 

entities. Commenters have not made 

specific assertions regarding how the 

Commission’s analysis is erroneous or 

in what ways the Final Rule will have 

a significant economic impact on a 

substantial number of small entities. As 

the Commission stated in its NOPR, 

most transmission owners, transmission 

operators and transmission service 

providers do not fall within the 

definition of small entities. Further, the 

Commission has suggested that the ERO 

create an appropriate exemption process 

and this will further ensure that the 

Final Rule minimally affects small 

entities. In addition, the ability of 

Regional Entities to identify ‘‘critical’’ 

facilities, operated at less than 100 kV, 

and require these facilities to comply 

with mandatory Reliability Facilities is 

not new. Our direction here that the 

ERO formalize the process for including 

such facilities will provide additional 

protections to small entities. Based on 

this analysis, we certify that this Final 

Rule will not have a significant 

economic impact on a substantial 

number of small entities. Accordingly, 

no further RFA analysis is required. 

VI. Document Availability 

170. In addition to publishing the full 

text of this document in the Federal 

Register, the Commission provides all 

interested persons an opportunity to 

view and/or print the contents of this 

document via the Internet through the 

Commission’s Home Page (http:// 

www.ferc.gov) and in the Commission’s 

Public Reference Room during normal 

business hours (8:30 a.m. to 5 p.m. 

Eastern time) at 888 First Street, NE., 

Room 2A, Washington, DC 20426. 

171. From the Commission’s Home 

Page on the Internet, this information is 

available on eLibrary. The full text of 

this document is available on eLibrary 

in PDF and Microsoft Word format for 

viewing, printing, and/or downloading. 

To access this document in eLibrary, 

type the docket number excluding the 

last three digits of this document in the 

docket number field. 

172. User assistance is available for 

eLibrary and the Commission’s Web site 

during normal business hours from 

FERC Online Support at (202) 502–6652 

(toll free at 1–866–208–3676) or e-mail 

at ferconlinesupport@ferc.gov, or the 

Public Reference Room at (202) 502– 

8371, TTY (202) 502–8659. E-mail the 

Public Reference Room at 

public.referenceroom@ferc.gov. 

VII. Effective Date and Congressional 

Notification 

173. These regulations are effective 

January 25, 2011. The Commission has 

determined, with the concurrence of the 

Administrator of the Office of 

Information and Regulatory Affairs of 

OMB, that this rule is not a ‘‘major rule’’ 

as defined in section 351 of the Small 

Business Regulatory Enforcement 

Fairness Act of 1996. 

List of Subjects in 18 CFR Part 40 

Electric power, Electric utilities, 

Reporting and recordkeeping 

requirements. 

By the Commission. 

Nathaniel J. Davis, Sr., 

Deputy Secretary. 

APPENDIX A 

Commenter Abbreviation 

Alcoa Inc. and Alcoa Power Generating Inc ................................................................................... Alcoa 

American Public Power Association and the National Rural Electric Cooperative Association ..... APPA/NRECA 


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72932 Federal Register / Vol. 75, No. 227 / Friday, November 26, 2010 / Rules and Regulations 

APPENDIX A—Continued 

Commenter Abbreviation 

Baltimore Gas and Electric Company ............................................................................................. BGE 

Bay Area Municipal Transmission Group ........................................................................................ Bay Area Municipal 

Bonneville Power Administration ..................................................................................................... BPA 

California Municipal Utilities Association ......................................................................................... CMUA 

California Public Utilities Commission ............................................................................................. CPUC 

Central Hudson Gas & Electric Corporation, Consolidated Edison Company of New York, Inc., 

Long Island Power Authority, New York Power Authority, New York State Electric & Gas Corporation, Orange and Rockland Utilities, Inc. and Rochester Gas and Electric Corporation.

Indicated New York Transmission Owners 

City of Anaheim, California .............................................................................................................. Anaheim 

City of Palo Alto, California ............................................................................................................. Palo Alto 

City of Redding, California .............................................................................................................. Redding 

City of Santa Clara, California d/b/a Silicon Valley Power ............................................................. Santa Clara 

Constellation Energy Commodities Group, Inc., Constellation Energy Control and Dispatch, 

LLC, Constellation Energy Nuclear Group, LLC, Constellation NewEnergy, Inc. and Constellation Power Source Generation, Inc.

Constellation/CENG 

Consumers Energy Company ......................................................................................................... Consumers Energy 

Dow Chemical Company ................................................................................................................. Dow 

Duke Energy Corporation ................................................................................................................ Duke Energy 

Edison Electric Institute ................................................................................................................... EEI 

Electric Reliability Council of Texas, Inc ......................................................................................... ERCOT 

Electricity Consumers Resource Council ........................................................................................ ELCON 

ExxonMobil Research and Engineering .......................................................................................... ExxonMobil 

Florida Reliability Coordinating Council .......................................................................................... FRCC 

Georgia Transmission Corporation and Georgia System Operations Corporation ........................ GTC/GSOC 

Greenburgh Environmental Forum LORAX Working Group ........................................................... Greenburgh 

Hydro-Que ́bec TransE ́ nergie ........................................................................................................... Hydro-Que ́bec 

Independent Electricity System Operator, Hydro One Networks Inc., Ontario Power Generation 

Inc., Five Nations Energy Inc., Brookfield Renewable Power Inc., New Brunswick System 

Operator, and Nova Scotia Power Inc.

Joint Canadian Parties 

Industrial Customers of Northwest Utilities ..................................................................................... ICNU 

ISO New England Inc. ..................................................................................................................... ISO–NE 

Large Public Power Council 

Manitoba Hydro 

National Association of Regulatory Utility Commissioners ............................................................. NARUC 

National Grid USA ........................................................................................................................... National Grid 

Nevada Power Company and Sierra Pacific Power Company, d/b/a NV Energy .......................... NV Energy 

New England States Committee on Electricity ............................................................................... NESCOE 

New York Independent System Operator, Inc ................................................................................ NYISO 

New York State Public Service Commission .................................................................................. NYPSC

New York State Reliability Council, L.L.C. ...................................................................................... NYSRC 

North American Electric Reliability Corporation .............................................................................. NERC 

North Carolina Independent Cooperatives 

Northeast Power Coordinating Council, Inc .................................................................................... NPCC 

Northeast Utilities Service Company ............................................................................................... Northeast Utilities 

Northern California Power Agency .................................................................................................. NCPA 

Ontario Power Generation Inc ......................................................................................................... Ontario Power 

Joint Western Commenters ............................................................................................................. Joint Western Commenters 

Benton Rural Electric Association 

Big Bend Electric Cooperative 

Blachley-Lane Electric Cooperative 

Central Electric Cooperative 

Central Lincoln People’s Utility District 

City of Ellensburg, Washington 

City of Richland, Washington 

Clearwater Power Company 

Consumers Power 

Coos-Curry Electric Cooperative 

Douglas Electric Cooperative 

Eugene Water & Electric Board 

Fall River Rural Electric Cooperative 

Fergus Electric Cooperative, Inc. 

Idaho Falls Power 

Inland Power and Light Company 

Lane Electric Cooperative 

Lincoln Electric Cooperative 

Lost River Electric Cooperative 

Northern Lights 

Northwest Public Power Association 

Northwest Requirements Utilities 

Okanogan Electric Cooperative 

Pacific Northwest Generating Cooperative 

Public Utility District No. 1 of Douglas County, Washington 


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Federal Register / Vol. 75, No. 227 / Friday, November 26, 2010 / Rules and Regulations 72933 

APPENDIX A—Continued 

Commenter Abbreviation 

Public Utility District No. 1 of Klickitat County, Washington 

Raft River Rural Electric Cooperative 

Salmon River Electric Cooperative 

Tillamook PUD 

Umatilla Electric Cooperative 

Wells Rural Electric Company 

West Oregon Electric Cooperative 

Western Montana Electric Generating and Transmission Cooperative, Inc 

Portland General Electric Company ................................................................................................ PGE 

Public Power Council 

Public Utility District No. 1 of Snohomish County, Washington ...................................................... Snohomish 

ReliabilityFirst Corporation .............................................................................................................. ReliabilityFirst 

Southern California Edison Company ............................................................................................. SCE 

Southern Company Services, Inc .................................................................................................... Southern Company 

Southwest Transmission Dependent Utility Group ......................................................................... SWTDUG 

State Utility Commissions and Consumer Counsel 

Idaho Public Utilities Commission 

Montana Public Service Commission 

Montana Consumer Counsel 

Oregon Public Utility Commission 

Utah Public Service Commission 

Washington Utilities and Transportation Commission 

Tacoma Power ................................................................................................................................

Texas Industrial Energy Consumers ............................................................................................... TIEC 

Transmission Access Policy Study Group ...................................................................................... TAPS 

Transmission Agency of Northern California .................................................................................. TANC 

U.S. Department of the Interior 

Utah Associated Municipal Power Systems .................................................................................... Utah Municipal 

Utility Services, Inc .......................................................................................................................... Utility Services 

Virginia Electric and Power Company, d/b/a Dominion Virginia Power ......................................... Dominion Power 

Western Electricity Coordinating Council ........................................................................................ WECC 

Wyoming Public Service Commission ............................................................................................. WPSC 

[FR Doc. 2010–29570 Filed 11–24–10; 8:45 am] 

BILLING CODE 6717–01–P 


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