64770 Federal Register / Vol. 71, No. 213 / Friday, November 3, 2006 / Proposed Rules 

DEPARTMENT OF ENERGY 

Federal Energy Regulatory 

Commission 

18 CFR Part 40 

Docket No. RM06–16–000] 

Mandatory Reliability Standards for the 

Bulk-Power System 

October 20, 2006. 

AGENCY: Federal Energy Regulatory 

Commission, DOE. 

ACTION: Notice of proposed rulemaking. 

SUMMARY: Pursuant to section 215 of the 

Federal Power Act (FPA), the 

Commission is proposing to approve 83 

of 107 proposed Reliability Standards, 

including six of the eight regional 

differences, and the Glossary of Terms 

Used in Reliability Standards developed 

by the North American Electric 

Reliability Council, on behalf of its 

wholly-owned subsidiary, the North 

American Electric Reliability 

Corporation (NERC), which the 

Commission has certified as the Electric 

Reliability Organization (ERO) 

responsible for developing and 

enforcing mandatory Reliability 

Standards. Those Reliability Standards 

meet the requirements of section 215 of 

the FPA and Part 39 of the 

Commission’s regulations. However, 

although we believe it is in the public 

interest to make these Reliability 

Standards mandatory and enforceable 

by June 2007, we also find that much 

work remains to be done. Specifically, 

we believe that many of these Reliability 

Standards require significant 

improvement to address, among other 

things, the recommendations of the 

Blackout Report. We therefore propose, 

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

the ERO to make significant 

improvements to many of the 83 

Reliability Standards that are being 

approved as mandatory and enforceable. 

Appendix D provides a list of the 

Reliability Standards that should be 

given the highest priority when the ERO 

undertakes to make these 

improvements. With respect to the 

remaining 24 Reliability Standards, the 

Commission proposes that they remain 

pending at the Commission until further 

information is provided. The 

Commission is not proposing to remand 

any Reliability Standards. 

The Commission proposes to amend 

the text of its regulation to require that 

each Reliability Standard identify the 

subset of users, owners and operators to 

which that particular Reliability 

Standard applies. The Commission also 

is proposing to amend its regulations to 

require that each Reliability Standard 

that is approved by the Commission will 

be maintained in the Commission’s 

Public Reference Room and on the 

ERO’s Internet Web site for public 

inspection. 

DATES: Comments are due January 2, 

2007. 

ADDRESSES: You may submit comments, 

identified by Docket No. RM06–16–000, 

by one of the following methods: 

• Agency Web site: http://ferc.gov. 

Follow the instructions for submitting 

comments via the eFiling link found in 

the Comment Procedures section of the 

Preamble. 

• Mail: Commenters unable to file 

comments electronically must mail or 

hand deliver an original and 14 copies 

of their comments to: Federal Energy 

Regulatory Commission, Office of the 

Secretary, 888 First Street. NE., 

Washington, DC 20426. Refer to the 

Comment Procedures section of the 

preamble for additional information on 

how to file paper comments. 

FOR FURTHER INFORMATION CONTACT:

Jonathan First (Legal Information), 

Office of the General Counsel, Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 

20426, (202) 502–8529. 

Paul Silverman (Legal Information), 

Office of the General Counsel, Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 

20426, (202) 502–8683. 

Robert Snow (Technical Information), 

Office of Energy Markets and 

Reliability, Division of Reliability, 

Federal Energy Regulatory 

Commission, 888 First Street, NE., 

Washington, DC 20426, (202) 502– 

6716. 

Kumar Agarwal (Technical 

Information), Office of Energy Market 

and Reliability, Division of Policy 

Analysis and Rulemaking, Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 

20426, (202) 502–8923. 

SUPPLEMENTARY INFORMATION: 

Paragraph 

Numbers 

I. Introduction ......................................................................................................................................................................................... 1 

II. Background ......................................................................................................................................................................................... 12 

A. Voluntary Reliability Standards ................................................................................................................................................ 12 

B. EPAct 2005 and Order No. 672 ................................................................................................................................................. 15 

C. The Electric Reliability Organization ........................................................................................................................................ 21 

D. NERC Petition for Approval of Reliability Standards .............................................................................................................. 24 

E. Staff Preliminary Assessment ..................................................................................................................................................... 29 

III. Discussion ......................................................................................................................................................................................... 33 

A. The Commission’s Reliability Standards Proposal .................................................................................................................. 33 

1. Applicability ........................................................................................................................................................................ 35 

2. Mandatory Reliability Standards ........................................................................................................................................ 37 

3. Availability of Reliability Standards .................................................................................................................................. 39 

B. Applicability Issues .................................................................................................................................................................... 42 

1. Definition of User of the Bulk-Power System .................................................................................................................... 42 

2. Use of the NERC Functional Model .................................................................................................................................... 44 

3. Applicability to Small Entities ............................................................................................................................................ 49 

4. Regional Reliability Organizations ...................................................................................................................................... 54 

5. Bulk-Power System v. Bulk Electric System ...................................................................................................................... 60 

C. Mandatory Reliability Standards ............................................................................................................................................... 72 

1. Legal Standard for Approval of Reliability Standards ...................................................................................................... 72 

2. Commission Options When Acting on a Reliability Standard ......................................................................................... 76 

3. Prioritizing Modifications to Reliability Standards ........................................................................................................... 83 

4. Trial Period .......................................................................................................................................................................... 90 

5. International Coordination of Remands ............................................................................................................................. 94 

D. Common Issues Pertaining to Reliability Standards ................................................................................................................ 96 

1. Blackout Report Recommendations .................................................................................................................................... 97 


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1The Energy Policy Act of 2005, Pub. L. No. 109–

58, Title XII, Subtitle A, 119 Stat. 594, 941 (2005), 

to be codified at 16 U.S.C. 824o (2000). 

2Rules Concerning Certification of the Electric 

Reliability Organization; Procedures for the 

Establishment, Approval and Enforcement of 

Electric Reliability Standards, Order No. 672, 71 FR 

8662 (February 17, 2006), FERC Stats. & Regs. 

¶ 31,204 (2006), order on reh’g, Order No. 672–A, 

71 FR 19814 (April 18, 2006), FERC Stats. & Regs. 

¶ 31,212 (2006). 

3The April 4, 2006 filing contained 102 

Reliability Standards, a Glossary of Terms Used in 

Reliability Standards and eight regional differences. 

On August 28, 2006, NERC filed an additional 19 

Reliability Standards and withdrew three of the 102 

Reliability Standards. Eleven of the nineteen 

reliability Standards replace those filed on April 4, 

2006. 

4ERO Certification Order, 116 FERC ¶ 61,062. 

Paragraph 

Numbers 

2. Measures and Levels of Non-Compliance .......................................................................................................................... 103 

3. Ambiguities and Potential Multiple Interpretations .......................................................................................................... 108 

4. Technical Adequacy ............................................................................................................................................................ 113 

5. Fill-in-the-Blank Standards ................................................................................................................................................. 116 

E. Discussion of Each Individual Reliability Standard ................................................................................................................. 124 

1. BAL: Resource and Demand Balancing .............................................................................................................................. 125 

2. CIP: Critical Infrastructure Protection ................................................................................................................................ 217 

3. COM: Communications ....................................................................................................................................................... 232 

4. EOP: Emergency Preparedness and Operations ................................................................................................................. 263 

5. FAC: Facilities Design, Connections, Maintenance, and Transfer Capabilities ............................................................... 343 

6. INT: Interchange Scheduling and Coordination ................................................................................................................ 427 

7. IRO: Interconnection Reliability Operations and Coordination ........................................................................................ 497 

8. MOD: Modeling, Data, and Analysis .................................................................................................................................. 588 

9. PER: Personnel Performance, Training and Qualifications ............................................................................................... 749 

10. PRC: Protection and Control ............................................................................................................................................. 802 

11. TOP: Transmission Operations ......................................................................................................................................... 951 

12. TPL: Transmission Planning ............................................................................................................................................. 1037 

13. VAR: Voltage and Reactive Control .................................................................................................................................. 1129 

14. Glossary of Terms Used in Reliability Standards ............................................................................................................ 1151 

IV. Information Collection Statement ................................................................................................................................................... 1157 

V. Environmental Analysis .................................................................................................................................................................... 1171 

VI. Regulatory Flexibility Act Certification .......................................................................................................................................... 1172 

VII. Comment Procedures ...................................................................................................................................................................... 1177 

VIII. Document Availability ................................................................................................................................................................... 1179 

Appendix A: Proposed Disposition of Standards, Glossary and Regional Differences 

Appendix B: Commenters on Staff Preliminary Assessment 

Appendix C: Abbreviations in this Document 

Appendix D: High Priority List 

I. Introduction 

1. Pursuant to section 215 of the 

Federal Power Act (FPA), the 

Commission is proposing to approve 83 

of 107 proposed Reliability Standards, 

including six of the eight regional 

differences, and the Glossary of Terms 

Used in Reliability Standards (glossary) 

developed by the North American 

Electric Reliability Council, on behalf of 

its wholly-owned subsidiary, the North 

American Electric Reliability 

Corporation (NERC), which the 

Commission has certified as the Electric 

Reliability Organization (ERO) 

responsible for developing and 

enforcing mandatory Reliability 

Standards. Those Reliability Standards 

meet the requirements of section 215 of 

the FPA and Part 39 of the 

Commission’s regulations. However, 

although we believe it is in the public 

interest to make these Reliability 

Standards mandatory and enforceable 

by June 2007, we also find that much 

work remains to be done. Specifically, 

we believe that many of these Reliability 

Standards require significant 

improvement to address, among other 

things, the recommendations of the 

Blackout Report. We therefore propose, 

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

the ERO to make significant 

improvements to many of the 83 

Reliability Standards that are being 

approved as mandatory and enforceable. 

Appendix D provides a list of the 

Reliability Standards that should be 

given the highest priority when the ERO 

undertakes to make these 

improvements. With respect to the 

remaining 24 Reliability Standards, the 

Commission proposes that they remain 

pending at the Commission until further 

information is provided. The 

Commission is not proposing to remand 

any Reliability Standards. 

2. The Commission proposes to 

amend the text of its regulations to 

require that each Reliability Standard 

identify the subset of users, owners, and 

operators to which that particular 

Reliability Standard applies. The 

Commission also is proposing to amend 

its regulations to require that each 

Reliability Standard that is approved by 

the Commission will be maintained in 

the Commission’s Public Reference 

Room and on the ERO’s Internet Web 

site for public inspection. 

3. On August 8, 2005, The Electricity 

Modernization Act of 2005, which is 

Title XII of the Energy Policy Act of 

2005 (EPAct 2005), was enacted into 

law.1 EPAct 2005 adds a new section 

215 to the FPA, which requires a 

Commission-certified ERO to develop 

mandatory and enforceable Reliability 

Standards, which are subject to 

Commission review and approval. Once 

approved, the Reliability Standards may 

be enforced by the ERO, subject to 

Commission oversight. 

4. On February 3, 2006, the 

Commission issued Order No. 672, 

which implements section 215 of the 

FPA and provides specific processes for 

the certification of one entity as the 

ERO, the development and approval of 

mandatory Reliability Standards, and 

the compliance with and enforcement of 

approved Reliability Standards.2 On 

April 4, 2006, NERC made two filings: 

(1) An application for certification of 

NERC Corporation as the ERO and (2) a 

petition for Commission approval of 102 

Reliability Standards, as well as eight 

regional differences and a glossary of 

terms.3 On July 20, 2006, the 

Commission issued an order certifying 

NERC Corporation as the ERO.4 This 

rulemaking proceeding addresses 

NERC’s submission of Reliability 

Standards and represents the next 


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5See NERC Petition at 69. 

6 16 U.S.C. 824o(d)(2). 

7NERC Petition at 25. 

8See id. at 87–90. 

9The ERO is reminded when filling in these 

blanks that a regional difference is generally 

permitted when it is more stringent or when there 

is a geographical/physical reason for the difference. 

Consolidation of regional standards into a single 

continent-wide standard should not result in a 

lowest common denominator. Order No. 672 at P 

291. 

10 In addition, some of the proposed Reliability 

Standards overlap with other Commission 

regulatory initiatives. For example, in a recent 

Notice of Proposed Rulemaking, the Commission 

has proposed to direct public utilities, in 

conjunction with NERC and the North American 

Energy Standards Board to provide for greater 

consistency in Available Transmission Capacity 

(ATC) calculation. See Preventing Undue 

Discrimination and Preference in Transmission 

Service, 71 FR 32636 (June 6, 2006), 71 FR 39251 

(July 12, 2006), FERC Stats. & Regs. ¶ 39,602 (May 

19, 2006) (OATT Reform NOPR). 

11The Electric Power Outages in the Western 

United States, July 2–3, 1996, at 76 (ftp:// 

www.nerc.com/pub/sys/all_updl/docs/pubs/ 

doerept.pdf) and WSCC Disturbance Report, for the 

Power System Outage that Occurred on the Western 

Interconnection August 10, 1996, at 4 (ftp:// 

www.nerc.com/pub/sys/all_updl/docs/pubs/ 

AUG10FIN.pdf). 

significant step toward achieving the 

statutory goal of mandatory and 

enforceable Reliability Standards. 

5. The ERO’s filing is comprehensive, 

and represents a significant effort by 

NERC, the industry representatives who 

serve on NERC’s standards development 

teams, and the entities that participate 

in NERC’s Reliability Standards 

development process. After the August 

2003 cascading blackout that affected 

large portions of the central and eastern 

United States and Canada, NERC 

revised many of the then-existing NERC 

operating policies and planning 

standards to provide greater clarity and 

compliance guidance. These revised 

standards (referred to as ‘‘Version 0’’

and ‘‘Version 1’’) were developed using 

NERC’s American National Standards 

Institute (ANSI)-accredited Reliability 

Standards development process and are 

what has been filed with the 

Commission for approval. 

6. The Commission believes that these 

Reliability Standards will form a solid 

foundation on which to develop and 

maintain the reliability of the North 

American Bulk-Power System. At the 

same time, the Commission recognizes, 

as does NERC,5 that the Version 0 and 

Version 1 standards were developed as 

an initial step in the transition to clear, 

enforceable Reliability Standards. As 

such, some technical, enforceability and 

policy aspects of the 107 proposed 

Reliability Standards submitted by the 

ERO can, and should, be improved. 

7. Therefore, in evaluating NERC’s 

proposal, the Commission recognizes 

that the Reliability Standards are in a 

state of transition and that NERC has 

ongoing plans to improve them. Thus, at 

this juncture, we will approve a 

proposed Reliability Standard that 

needs clarification, improvement, or 

strengthening, provided that we are 

confident that it satisfies the statutory 

requirement that a Reliability Standard 

must be ‘‘just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest.’’ 6 Rather than 

remanding an imperfect Reliability 

Standard, the NOPR generally proposes 

to approve such a Reliability Standard. 

In addition, as a distinct action under 

the statute, the Commission proposes to 

direct that the ERO modify such a 

Reliability Standard, pursuant to section 

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

identified issues or concerns. This 

approach would allow the proposed 

Reliability Standard to be enforceable 

while the ERO develops any required 

modifications. 

8. The Commission believes that, for 

this period of transition from a 

voluntary to a mandatory system of 

compliance, the above course of action 

is appropriate when reviewing the 

ERO’s first set of proposed Reliability 

Standards. This action provides the 

benefit that mandatory and enforceable 

Reliability Standards will be in effect 

prior to the summer of 2007, the next 

anticipated peak season for the nation’s 

Bulk-Power System. Critical to our 

decision to propose to approve such 

Reliability Standards is NERC’s 

representation to the Commission that 

approval of the existing Reliability 

Standards ‘‘will reinforce the 

importance of these standards and will 

have an immediate positive benefit with 

regard to the reliability performance of 

all bulk power system owners, operator 

and users * * *.’’ 7

9. Accordingly, the Commission 

proposes to approve the Reliability 

Standards based on recognizing this 

period of transition, the importance of 

making them mandatory before the 

summer of 2007, and by giving due 

weight to the technical expertise of the 

ERO with the expectation that the 

Reliability Standards will accomplish 

the purpose represented to the 

Commission by the ERO; and that they 

will improve the reliability of the BulkPower System by proactively preventing 

situations that can lead to blackouts. By 

taking this approach, we believe that the 

responsibility for the technical 

adequacy of the proposed Reliability 

Standards falls squarely on the ERO, 

and we expect the ERO to monitor the 

effectiveness of the proposed Reliability 

Standards and inform us if any 

Reliability Standard proves, in practice, 

to be inadequate in protecting and 

improving Bulk-Power System 

reliability. 

10. Further, the Commission proposes 

to request additional information with 

regard to 24 proposed Reliability 

Standards. These proposed Reliability 

Standards would not be approved or 

remanded by the Commission until 

further action is taken by the ERO. This 

group of Reliability Standards includes 

NERC’s so-called ‘‘fill-in-the-blank’’

standards that require regional 

reliability organizations to develop—

and users, owners, or operators to 

comply with—regional criteria.8 Until 

the Commission receives this 

supplemental information to fill in the 

‘‘blanks’’ 9 and assurances that the 

processes to fill in the blanks satisfy our 

procedural requirements, the 

Commission is not in a position to 

approve or remand such Reliability 

Standards. Second, a proposed 

Reliability Standard that would apply 

only to regional reliability organizations 

will not be approved or remanded until 

the ERO identifies a user, owner or 

operator of the Bulk-Power System as 

the applicable entity.10

11. Although the proposed Reliability 

Standards for which the Commission is 

requesting additional information will 

not be enforceable under section 215, 

this does not mean that no standards 

governing a particular matter are in 

place. Rather, in the interim, though not 

enforceable under section 215, 

compliance with these Reliability 

Standards would be expected as a 

matter of good utility practice. 

II. Background 

A. Voluntary Reliability Standards 

12. In the aftermath of the 1965 

blackout in the northeast United States, 

the electric utility industry established 

NERC, a voluntary reliability 

organization. Since its inception, NERC 

has developed Operating Policies and 

Planning Standards that provide 

voluntary guidelines for operating and 

planning the North American BulkPower System. 

13. A common cause of the past three 

major regional blackouts was violation 

of NERC’s then existing Operating 

Policies and Planning Standards. During 

July and August 1996, the west coast of 

the United States experienced two 

cascading blackouts caused by 

violations of voluntary Operating 

Policies.11 In response to the outages, 

the Secretary of Energy convened a task 

force to advise the U.S. Department of 


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12 Maintaining Reliability in a Competitive U.S. 

Electricity Industry, Final Report of the Task Force 

on Electric System Reliability, Secretary of Energy 

Advisory Board, U.S. Department of Energy 

(September 1998), at 25–27, 65–67. 

13The joint team, known as the U.S.-Canada 

Power System Outage Task Force, issued a Final 

Report on the August 14, 2003 Blackout in the 

United States and Canada: Causes and 

Recommendations (Blackout Report) on April 5, 

2004, which presented an in-depth analysis of the 

causes of the blackout and recommendations for 

avoiding future blackouts. 

14See id. at 140–42. 

15Order No. 672, 71 FR 8662 (Feb. 17, 2006), 

FERC Stats. & Regs. ¶ 31,204 (2006), order on reh’g, 

Order No. 672–A, 71 FR 19814 (Apr. 18, 2006), 

FERC Stats. & Regs. ¶ 31,212 (2006). Terms defined 

in Order No. 672 are capitalized in this order. 

16Section 215(a)(3) of the FPA defines the term 

Reliability Standard to mean ‘‘a requirement, 

approved by the Commission under this section, to 

provide for reliable operation of the bulk-power 

system. This term includes requirements for the 

operation of existing bulk-power system facilities, 

including cybersecurity protection, and the design 

of planned additions or modifications to such 

facilities to the extent necessary to provide for the 

reliable operation of the bulk-power system, but the 

term does not include any requirement to enlarge 

such facilities or to construct new transmission 

capacity or generation capacity.’’ 16 U.S.C. 

824o(a)(3). 

Section 215(a)(4) of the FPA defines the term 

‘‘reliable operation’’ broadly to mean, ‘‘* * * 

operating the elements of the bulk-power system 

within equipment and electric system thermal, 

voltage, and stability limits so that instability, 

uncontrolled separation, or cascading failures of 

such system will not occur as a result of a sudden 

disturbance, including a cybersecurity incident, or 

unanticipated failure of system elements.’’ 16 

U.S.C. 824o(a)(4). 

17The Commission can independently enforce 

Reliability Standards. 16 U.S.C. 824o(e)(3). 

18Order No. 672 at P 262, 321–337. 

19Order No. 672 at P 329. 

20Order No. 672 at P 332. 

21 Id. at P 337. 

22 18 CFR 39.5(c)(1), (3). 

Energy (DOE) on issues needed to be 

addressed to maintain the reliability of 

the Bulk-Power System. In a September 

1998 report, the task force 

recommended, among other things, that 

federal legislation should grant more 

explicit authority for the Commission to 

approve and oversee an organization 

having responsibility for bulk-power 

reliability standards.12 Further, the task 

force recommended that such legislation 

provide for Commission jurisdiction 

over reliability of the Bulk-Power 

System and Commission 

implementation of mandatory, 

enforceable reliability standards. 

14. On August 14, 2003, a blackout 

affected significant portions of the 

Midwest and Northeast United States, 

and Ontario, Canada. This blackout 

affected an estimated 50 million people 

and 61,800 megawatts of electric load. A 

joint U.S.-Canada task force studied the 

causes of the August 14, 2003 blackout 

and determined that several entities 

violated NERC’s then-effective 

Operating Policies and Planning 

Standards, and that several of the 

standards contained ambiguities that 

rendered the standards ineffective. 

Those violations and ambiguities 

directly contributed to the blackout.13

The joint task force, in its 

recommendations to prevent or 

minimize the scope of future blackouts, 

identified the need for legislation to 

make reliability standards mandatory 

and enforceable, with penalties for noncompliance and identified specific 

ambiguities within the standards that 

should be corrected to make the 

standards effective.14

B. EPAct 2005 and Order No. 672 

15. EPAct 2005 adds a new section 

215 to the FPA, which provides for a 

system of mandatory and enforceable 

Reliability Standards. On February 3, 

2006, the Commission issued Order No. 

672, implementing section 215 of the 

FPA.15 Pursuant to Order No. 672, the 

Commission certified one organization, 

NERC, as the ERO. The ERO is required 

to develop Reliability Standards, which 

are subject to Commission review and 

approval.16 Once approved, the 

Reliability Standards may be enforced 

by the ERO, subject to Commission 

oversight.17 The Reliability Standards 

will apply to users, owners and 

operators of the Bulk-Power System. 

The ERO must submit each proposed 

Reliability Standard to the Commission 

for approval. 

16. Section 215(d)(2) of the FPA and 

the Commission’s regulations provide 

that the Commission may approve a 

proposed Reliability Standard if it 

determines that the proposal is just, 

reasonable, not unduly discriminatory 

or preferential, and in the public 

interest. The Commission specified in 

Order No. 672 certain general factors it 

would consider when assessing whether 

a particular Reliability Standard is just 

and reasonable.18 According to this 

guidance, a proposed Reliability 

Standard must provide for the Reliable 

Operation of Bulk-Power System 

facilities and may impose a requirement 

on any user, owner, or operator of such 

facilities. It must be designed to achieve 

a specified reliability goal and must 

contain a technically sound means to 

achieve this goal. The proposed 

Reliability Standard should be clear and 

unambiguous regarding what is required 

and who is required to comply. The 

possible consequences for violating a 

proposed Reliability Standard should be 

clear and understandable to those who 

must comply. There should be a clear 

criterion or measure of whether an 

entity is in compliance with a proposed 

Reliability Standard. While a proposed 

Reliability Standard does not 

necessarily need to reflect the optimal 

method for achieving its reliability goal, 

a proposed Reliability Standard should 

achieve its reliability goal effectively 

and efficiently. A proposed Reliability 

Standard must do more than simply 

reflect stakeholder agreement or 

consensus around the ‘‘lowest common 

denominator.’’ It is important that the 

Reliability Standards developed through 

any consensus process be sufficient to 

adequately protect Bulk-Power System 

reliability.19

17. A proposed Reliability Standard 

may take into account the size of the 

entity that must comply and the costs of 

implementation. However, the ERO 

should not propose standards that 

would achieve less than operational 

excellence or otherwise be inadequate to 

support Bulk-Power System reliability. 

A proposed Reliability Standard should 

be a single standard that applies across 

the North American Bulk-Power System 

to the maximum extent this is 

achievable taking into account 

geographic variations in grid 

characteristics, terrain, weather, and 

other factors. It should also account for 

regional variations in the organizational 

and corporate structures of transmission 

owners and operators, variations in 

generation fuel type and ownership 

patterns, and regional variations in 

market design if these affect the 

proposed Reliability Standard. Finally, a 

proposed Reliability Standard should 

have no undue negative effect on 

competition.20 Order No. 672 directs the 

ERO to explain how the proposal 

satisfies the factors the Commission 

identified and how the ERO balances 

any conflicting factors when seeking 

approval of a proposed Reliability 

Standard.21

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

the FPA and section 39.5(c) of the 

Commission’s regulations, the 

Commission is required to give due 

weight to the technical expertise of the 

ERO with respect to the content of a 

Reliability Standard or to a Regional 

Entity organized on an Interconnectionwide basis with respect to a proposed 

Reliability Standard or a proposed 

modification to a Reliability Standard to 

be applicable within that 

Interconnection. However, the 

Commission is not required to defer to 

the ERO or a Regional Entity with 

respect to the effect of a proposed 

Reliability Standard or proposed 

modification to a Reliability Standard 

on competition.22

19. The Commission’s regulations 

require the ERO to file with the 


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23 18 CFR 39.5(a). 

24 18 CFR 39.5(e). 

25Although the ERO Certification Order directs 

NERC to modify the pro forma delegation 

agreement, the pro forma agreement will not be refiled with the Commission before negotiating the 

individual delegation agreements. The pro forma 

agreement will form the basis for the individual 

Regional Entity delegation agreements that will be 

filed with the Commission. ERO Certification 

Order, 116 FERC ¶ 61,062 at P 518. 

26The filed proposed Reliability Standards are 

not attached to this NOPR but are available on the 

Commission’s eLibrary document retrieval system 

in Docket No. RM06–16–000 and are available on 

the ERO’s Web site, http://www.nerc.com/∼filez/ 

nerc_filings_ferc.html. 

27See NERC Petition at 28. 

28NERC Comments at 104. NERC clarified its 

position that Measures did not include metrics after 

the Staff Preliminary Assessment interpreted the 

Measures section as including metrics. 

Commission each new or modified 

Reliability Standard that it proposes to 

be made effective under section 215 of 

the FPA. The filing must include a 

concise statement of the basis and 

purpose of the proposed Reliability 

Standard, a summary of the Reliability 

Standard development proceedings 

conducted by either the ERO or 

Regional Entity, together with a 

summary of the ERO’s Reliability 

Standard review proceedings, and a 

demonstration that the proposed 

Reliability Standard is just, reasonable, 

not unduly discriminatory or 

preferential, and in the public interest.23

20. The Commission will remand to 

the ERO for further consideration a 

proposed new or modified Reliability 

Standard that the Commission 

disapproves in whole or in part.24 When 

remanding a Reliability Standard to the 

ERO, the Commission may order a 

deadline by which the ERO must submit 

a proposed or modified Reliability 

Standard. 

C. The Electric Reliability Organization 

21. NERC is a New Jersey nonprofit 

corporation with a membership 

comprised of the eight regional 

reliability councils covering the 

contiguous 48 States, several provinces 

in Canada and a portion of Baja 

California Norte, Mexico. NERC has 

operated as a voluntary, industrysponsored reliability organization 

formed to ensure the reliability of the 

North American Bulk-Power System. 

22. NERC filed an application with 

the Commission on April, 4, 2006 

seeking certification as the ERO. NERC 

stated that it expects NERC Council and 

NERC Corp. to merge upon being 

certified as the ERO by the Commission. 

NERC Corp. will be the surviving entity 

and will assume the assets and 

liabilities of NERC Council. 

23. In its July 20, 2006 order certifying 

NERC as the ERO, the Commission 

directed NERC to submit a compliance 

filing incorporating various 

clarifications and revisions to its bylaws 

and rules of procedure. Among the 

improvements the Commission has 

directed NERC to undertake as the ERO 

are changes to expedite the existing 

process for developing new Reliability 

Standards in response to a Commission 

deadline to deal with an urgent 

situation. The order also directs NERC 

to modify its proposed pro forma 

delegation agreement for delegating 

enforcement authority to a Regional 

Entity.25

D. NERC Petition for Approval of 

Reliability Standards 

24. On April 4, 2006, as modified on 

August 28, 2006 NERC submitted to the 

Commission a petition seeking approval 

of the 107 proposed Reliability 

Standards that are the subject of this 

NOPR (NERC Petition).26 NERC states 

that 90 of these Reliability Standards, 

known as ‘‘Version 0’’ standards, 

became effective on a voluntary basis on 

April 1, 2005. It explains that the 

Version 0 standards ‘‘are a translation, 

with certain improvements, of NERC’s 

operating policies that were developed 

over several decades and its planning 

standards, which were approved in 

September 1997.’’ 27 In addition, the 

April 4, 2006 filing includes 12 new 

Reliability Standards that were 

approved by the NERC board of trustees 

for implementation in February 2006. 

According to NERC, the 107 proposed 

Reliability Standards collectively define 

overall acceptable performance with 

regard to operation, planning and design 

of the North American Bulk-Power 

System. Seven of these Reliability 

Standards specifically incorporate one 

or more ‘‘regional differences’’ (which 

can include an exemption from a 

Reliability Standard) for a particular 

region or subregion, resulting in eight 

regional differences. NERC requests that 

the Reliability Standards become 

effective on January 1, 2007, or an 

alternative date determined by the 

Commission. NERC also states that it 

simultaneously filed the proposed 

Reliability Standards with governmental 

authorities in Canada. 

25. Each proposed Reliability 

Standard follows a common format that 

includes five organizational elements: 

a. Introduction 

1. Title: a phrase that describes the 

topic of the Reliability Standard. 

2. Number: A unique identification 

number that starts with three letters to 

identify the group followed by a dash 

and a three digit number, followed by a 

dash and the version number e.g., PRC–

014–0. 

3. Purpose: One or more sentences 

that explicitly states the outcome to be 

achieved by the adoption of the 

Reliability Standard. 

4. Applicability: 

4.1 Each entity, as defined by the 

NERC Functional Model, that must 

comply with the Reliability Standard, 

such as Transmission Owner. 

b. Requirements 

R1. A listing of explicitly stated 

technical, performance and 

preparedness requirements and who is 

responsible for achieving them. 

c. Measures 

M1. A listing of the factors and the 

process NERC will use to assess 

performance and outcomes in order to 

determine non-compliance, and who is 

responsible for achieving the measures. 

Measures are ‘‘the evidence that must be 

presented to show compliance’’ with a 

standard and ‘‘are not intended to 

contain the quantitative metrics for 

determining satisfactory 

performance.’’ 28

d. Compliance 

1. Compliance Monitoring Process 

1.1 Compliance Monitoring 

Responsibility: NERC’s explanation of 

who is responsible for assessing 

performance or outcomes. 

1.2 Compliance Monitoring Period 

and Reset Timeframe: The timeframe for 

each compliance monitoring period 

before it is reset for the next period. 

1.3 Data Retention: How long 

compliance documentation needs to 

remain on file. 

1.4 Additional Compliance 

Information: Any other information 

relating to compliance. 

2. Levels of Non-Compliance: Usually 

four levels of non-compliance are 

identified, with level 1 being used for 

the least severe non-compliance and 

level 4 for the most severe noncompliance. 

e. Regional Differences 

Identification of any regional 

differences that have been approved by 

the applicable NERC Committee 

(including Regions that are exempt). 

Version History: The chronological 

history of changes to the standard. 

26. In its April 4, 2006 petition, NERC 

requested ‘‘unconditional’’ approval of 

77 proposed Reliability Standards and 

the glossary of terms. Further, NERC 


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requested ‘‘conditional’’ approval of 25 

proposed Reliability Standards. 

27. In a June 26 filing, NERC revised 

its recommended action on the 

proposed Reliability Standards: (1) 

Unconditional approval of 51 proposed 

Reliability Standards, to become 

enforceable in the U.S. on a date in 2007 

to be determined by the Commission; (2) 

conditional approval of 26 proposed 

‘fill-in-the-blank’ Reliability Standards, 

to become enforceable in the U.S. on a 

date in 2007 to be determined by the 

Commission. NERC recommends that 

‘‘conditional approval’’ shall mean ‘‘that 

any limitation of the standard caused by 

the presence of a regional ‘fill-in-theblank’ requirement * * * would be 

considered as a factor in the evaluation 

of circumstances surrounding an alleged 

violation of the standard and the 

determination of a violation and setting 

of an appropriate penalty;’’ and (3) 

conditional approval of another 25 

proposed Reliability Standards lacking 

Measures or Levels of Non-Compliance, 

to become enforceable in the U.S. on a 

date in 2007 to be determined by the 

Commission. In addition, NERC plans to 

file modified Reliability Standards in 

early November 2006 that will add 

missing Measures and Levels of Noncompliance elements as well as risk 

factors. NERC recommends that the 

Commission act on the proposed 

modifications to Reliability Standards 

that are currently before the 

Commission in the same proceeding to 

achieve an initial set of Reliability 

Standards. 

28. On August 28, 2006, NERC 

submitted 27 new and revised 

standards. The Commission will address 

these proposed new and revised 

Reliability Standards in this rulemaking 

proceeding, except for eight proposed 

Reliability Standards that relate to cyber 

security. Reliability Standards CIP–002 

through CIP–009 will be addressed in a 

separate rulemaking proceeding in 

Docket No. RM06–22–000. 

E. Staff Preliminary Assessment 

29. On May 11, 2006, Commission 

staff issued a ‘‘Staff Preliminary 

Assessment of the North American 

Electric Reliability Council’s Proposed 

Mandatory Reliability Standards’’ (Staff 

Preliminary Assessment). The Staff 

Preliminary Assessment identified 

staff’s preliminary observations and 

concerns regarding NERC’s then-current 

voluntary reliability standards. The Staff 

Preliminary Assessment describes 

issues common to a number of proposed 

Reliability Standards. It reviewed and 

identified issues regarding each 

individual Reliability Standard but did 

not make specific recommendations 

regarding the appropriate action on a 

particular proposal. 

30. The Staff Preliminary Assessment 

provided a basis for soliciting input 

regarding which of the proposed 

Reliability Standards should be 

approved, approved on an interim basis, 

or remanded to the ERO; established a 

platform from which to identify and 

prioritize potential problems with the 

proposed Reliability Standards; and 

provided a comprehensive and objective 

assessment of NERC’s then-current 102 

Reliability Standards. 

31. Comments on the Staff 

Preliminary Assessment were due by 

June 26, 2006. Entities that filed 

comments are listed in Appendix A to 

this NOPR. Approximately 50 persons 

filed comments in response to the Staff 

Preliminary Assessment. In addition, on 

July 6, 2006, the Commission held a 

technical conference to discuss NERC’s 

proposed Reliability Standards, the Staff 

Preliminary Assessment and other 

related issues. The technical conference 

was transcribed, and is a part of the 

record in this docket. 

32. The written comments as well as 

the panel discussions at the technical 

conference have been very informative, 

and reference to the public comments is 

mentioned throughout the NOPR. 

Moreover, our proposed disposition of 

the Reliability Standards reflects our 

consideration of all comments that were 

submitted. 

III. Discussion 

A. The Commission’s Reliability 

Standards Proposal 

33. The Commission’s proposed 

reliability regulation is entitled 

Mandatory Reliability Standards for the 

Bulk-Power System. Section 215(b) of 

the FPA obligates all users, owners and 

operators of the Bulk-Power System to 

comply with Reliability Standards that 

become effective pursuant to the 

processes set forth in the statute and in 

Part 39 of the Commission’s regulations. 

The complete text of the proposed rule 

is provided in the Attachment to this 

notice of proposed rulemaking. 

34. The proposed regulation is 

organized into three sections: 

40.1—Applicability; 

40.2—Mandatory Reliability 

Standards; and 

40.3—Availability of Reliability 

Standards. 

1. Applicability 

35. Section 40.1(a) of the proposed 

regulations provides that this Part 

applies to all users, owners and 

operators of the Bulk-Power System 

within the United States (other than 

Alaska and Hawaii) including, but not 

limited to, the entities described in 

section 201(f) of the FPA. This 

statement is consistent with § 215(b) of 

the FPA and section 39.2 of the 

Commission’s regulations. 

36. Section 40.1(b) requires each 

Reliability Standard made effective 

under this Part to identify the subset of 

users, owners and operators to whom 

that particular Reliability Standard 

applies. 

2. Mandatory Reliability Standards 

37. Section 40.2 (a) of the proposed 

regulations requires that each applicable 

user, owner or operator of the BulkPower System comply with 

Commission-approved Reliability 

Standards developed by the ERO, and 

provides that the Commission-approved 

Reliability Standards can be obtained 

from the Commission’s Public Reference 

Room at 888 First Street, NE., Room 2A, 

Washington, DC 20426. 

38. Section 40.2(b) of the proposed 

regulations provides that a proposed 

modification to a Reliability Standard 

proposed to become effective pursuant 

to § 39.5 shall not be effective until 

approved by the Commission. 

3. Availability of Reliability Standards 

39. Section 40.3 of the proposed 

regulations would require that the ERO 

maintain in electronic format that is 

accessible from the Internet the 

complete set of effective Reliability 

Standards that have been developed by 

the ERO and approved by the 

Commission. The Commission believes 

that ready access to an electronic 

version of the effective Reliability 

Standards will enhance transparency 

and help avoid confusion as to which 

Reliability Standards are mandatory and 

enforceable. We note that NERC 

currently maintains the existing, 

voluntary reliability standards on the 

NERC Web site. 

40. While the NOPR discusses each 

proposed Reliability Standard and 

identifies the Commission’s proposed 

disposition for each Reliability 

Standard, neither the text nor the title 

of an approved Reliability Standard 

would be codified in the Commission’s 

regulations. Rather, as indicated above, 

each applicable user, owner or operator 

of the Bulk-Power System would be 

required to comply with Commissionapproved Reliability Standards that are 

available in the Commission’s Public 

Reference Room and on the Internet at 

the ERO’s Web site. 

41. This approach would preserve the 

statutory options of approving a 

proposed Reliability Standard or 

modification to a Reliability Standard 


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29See 16 U.S.C. 824o(d)(2). 

30Order No. 672 at P 99. 

31Many of the proposed Reliability Standards 

apply to reliability coordinators and balancing 

authorities and other clearly appropriate entities. 

We believe that such Reliability Standards do not 

raise applicability issues. Thus, in our standard-bystandard analysis, the Commission’s silence as to 

applicability issues means that it agrees with the 

ERO’s proposed applicability of a Reliability 

Standard. 

32See NERC Petition at 80–81. For information 

regarding the Functional Model, see NERC 

Reliability Functional Model, Function Definitions 

and Responsibility Entities, Version 2, February 10, 

2004. NERC is currently developing revisions to the 

Functional Model (referred to as ‘‘Version 3’’) that, 

among other things, changes the name of the 

reliability authority to ‘‘reliability coordinator’’ and 

explains its role in ‘‘wide area’’ reliability oversight. 

Both versions of the Functional Model are available 

on NERC’s Web site at: http://www.nerc.com/∼filez/ 

functionalmodel.html. 

33The functional categories include: (1) 

Reliability coordinator, (2) balancing authority, (3) 

planning authority, (4) transmission planner, (5) 

transmission operator, (6) transmission service 

provider, (7) transmission owner, (8) resource 

planner, (9) distribution provider, (10) generator 

owner, (11) generator operator, (12) load-serving 

entity, (13) purchasing-selling entity, (14) 

compliance monitor. ERO Certification Order, 116 

FERC ¶ 61,062, at n.247. 

34Staff Preliminary Assessment at 24. 

35NERC Comments at 96. In addition to its April 

4, 2006, Petition, NERC filed comments in response 

to the Staff Preliminary Assessment on June 26, 

2006 (NERC Comments). 

36ERO Certification Order, 116 FERC ¶ 61,062, at 

P 689. 

37For example, commenters’ concerns regarding 

applicability to ISOs and RTOs are discussed in 

detail in the chapter on proposed communications 

Reliability Standards. 

38See NERC Rule of Procedure section 501.1.3. 

‘‘by rule or order.’’ 29 While we 

anticipate that the Commission would 

address through the rulemaking process 

most, if not all, new Reliability 

Standards proposed by NERC, certain 

modifications may be appropriately 

addressed by order. 

B. Applicability Issues 

1. Definition of User of the Bulk-Power 

System 

42. In Order No. 672, the Commission 

acknowledged that, generally, a person 

directly connected to the Bulk-Power 

System selling, purchasing or 

transmitting electric energy over the 

Bulk-Power System is a ‘‘User of the 

Bulk-Power System.’’ However, the 

Commission declined to adopt a formal 

definition, explaining that, ‘‘until we 

have proposed Reliability Standards 

before us, we will reserve further 

judgment on whether a definition of 

‘User of the Bulk-Power System’ is 

appropriate or whether the decision of 

who is a ‘User of the Bulk-Power 

System’ should be made on a case-bycase basis.’’ 30

43. We do not propose a generic 

definition of the term ‘‘User of the BulkPower System.’’ Rather, the Commission 

will determine applicability on a 

standard-by-standard basis.31 The 

phrase ‘‘user, owner or operator of the 

Bulk-Power System’’ as used in section 

215(b) of the FPA indicates the scope of 

the Commission’s authority with regard 

to compliance with Reliability 

Standards. The proposed regulations 

would require that the ERO identify in 

each proposed Reliability Standard the 

specific subset of users, owners and 

operators of the Bulk-Power System to 

which the proposed Reliability Standard 

would apply. In fact, this is NERC’s 

current practice, and each of the 107 

proposed Reliability Standards 

submitted by NERC includes an 

‘‘applicability’’ provision that identifies 

the specific categories of applicable 

entities based on NERC’s Functional 

Model.32 Parties concerned that a 

proposed Reliability Standard would 

apply more broadly than the statute 

allows may raise their concern in the 

context of the specific Reliability 

Standard. We believe that this approach 

provides sufficient notice regarding 

which entities are ‘‘users of the BulkPower System’’ that must comply with 

a specific Reliability Standard. 

2. Use of the NERC Functional Model 

44. As mentioned above, each 

Reliability Standard proposed by the 

ERO identifies entities to which the 

Reliability Standard applies based on 

the NERC Functional Model.33 The Staff 

Preliminary Assessment observed that 

the Functional Model omits the 

categories of ‘‘users, owners and 

operators,’’ and includes other 

categories of entities that are not users, 

owners or operators of the Bulk-Power 

System.34

45. NERC states that, while the term 

‘‘users, owners and operators’’ defines 

the statutory applicability of the 

Reliability Standards, the Functional 

Model adds descriptive detail to 

reliability functions so the applicability 

of each Reliability Standard can be 

clearly defined. NERC explains that 

‘‘every entity class described in the 

Reliability Functional Model performs 

functions that are essential to the 

reliability of the bulk power system.’’ 35

Several commenters concur with NERC 

and suggest that the Commission 

approve the Functional Model so that 

future modifications would require 

Commission approval. MISO and 

Allegheny point to specific examples of 

what they consider ambiguities in the 

NERC Functional Model, primarily in 

the context of applicability to RTO or 

ISO functions. 

46. The objective here is to make sure 

that each Reliability Standard is 

sufficiently clear with respect to 

applicability and specifically identifies 

each category of entities to which it 

applies. The NERC Functional Model 

represents a reasonable and practical 

approach to determining the 

applicability of a particular Reliability 

Standard. This approach is consistent 

with the ERO Certification Order, in 

which the Commission, in the context of 

addressing NERC’s proposed 

compliance registry, found that ‘‘NERC’s 

functional approach provides a 

reasonable means to ensure that the 

proper entities are registered and that 

each knows which Commissionapproved Reliability Standard(s) are 

applicable to it.’’ 36 Thus, we agree with 

NERC that identifying specific 

functional categories of entities that 

comprise users, owners and operators of 

the Bulk-Power System provides a 

useful level of detail and appears to be 

more practical than simply identifying 

an applicable entity as a user, owner or 

operator. Accordingly, we propose to 

use the NERC functional model to 

identify the applicable entities to which 

each Reliability Standard applies. 

47. We are mindful of the concerns of 

certain commenters that the Functional 

Model may contain ambiguities and add 

or omit certain entities or functions. 

Elsewhere in the NOPR we are 

proposing to require NERC to 

specifically address these concerns.37

Further we note that NERC’s Rules of 

Procedure pertaining to the NERC 

compliance registry provide that NERC 

will notify an entity before it is formally 

registered and allow an opportunity for 

an entity to challenge its inclusion on 

the compliance registry.38 This process 

should resolve any specific disputes 

that may arise. 

48. Some commenters suggest that 

any future modification to the 

Functional Model could affect the 

categories of entities that must comply 

with a particular Reliability Standard, 

without the benefit of the open, 

stakeholder process required when the 

ERO develops a modification to a 

Reliability Standard. Because the 

Functional Model is so closely linked 

with applicability of the Reliability 

Standards, the Commission proposes to 

require the ERO to submit any future 

modifications to the Functional Model 

that may affect the applicability of the 

Reliability Standards for Commission 

approval. 

3. Applicability to Small Entities 

49. NERC indicates that a Reliability 

Standard may identify limitations on 


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39NERC Petition at 9. 

40 Id. at 82. 

41See, e.g., Alcoa, APPA, BPA and TAPS. 

42For example, a dedicated phone line that 

would remain operative during a power failure may 

suffice for a small cooperative with minimal BulkPower System facilities, while a large investorowned utility may need a sophisticated 

communication system with redundancy and 

diverse routing requirements. 

43NERC states that the regional reliability 

organizations are the same as the existing eight 

regional reliability councils and that ‘‘a regional 

reliability organization may or may not be the same 

organization that is providing statutory functions 

delegated by agreement with a regional entity.’’

NERC Comments at 101. In the order certifying 

NERC as the ERO, the Commission asked that NERC 

provide additional information regarding the 

possible ongoing role of the regional reliability 

organizations and their relationship with Regional 

Entities. ERO Certification Order, 116 FERC 

¶ 61,062, at P 76. 

44Pursuant to NERC’s ERO application, a member 

‘‘accepts the responsibility to promote, support, and 

comply with the Bylaws, Rules of Procedure, and 

Reliability Standards * * *.’’

applicability based on electric facility 

characteristics ‘‘such as generators with 

a nameplate rating of 20 MW or greater, 

or transmission facilities energized at 

200 kV or greater.’’ 39 It explains that, 

‘‘to ensure that the standards are 

applied in a cost effective manner and 

the applicability of the standards is 

focused on entities having a material 

impact on reliability of the bulk power 

system, it is necessary in the future to 

begin providing greater specificity in the 

applicability section of the 

standards.’’ 40 NERC, as the ERO, 

indicates that it plans to develop a set 

of guidelines on such limitations for the 

standard drafting teams and to require 

that a new Reliability Standard or a 

modification to an existing Reliability 

Standard, going forward, include this 

degree of specificity. 

50. A number of commenters advocate 

that a mandatory Reliability Standard 

should not apply to entities that have no 

‘‘material impact’’ on the Bulk-Power 

System.41 These commenters also ask 

that the Commission encourage and 

facilitate contractual arrangements for 

the delegation of compliance obligations 

faced by small entities to Joint Action 

Agencies (JAAs) and other organizations 

that have ongoing relationships with 

NERC. 

51. While NERC has yet to submit a 

specific proposal, the Commission 

agrees that it is important to examine 

the impact a particular entity may have 

on the Bulk-Power System in 

determining the applicability of a 

specific Reliability Standard. However, 

we do not believe that a ‘‘blanket 

waiver’’ approach that would exempt 

entities below a threshold level from 

compliance with all Reliability 

Standards would be appropriate because 

there may be instances where a small 

entity’s compliance is critical to 

reliability. For instance, the reporting of 

a sabotage event required by CIP–001–

0 may be important regardless of the 

size of the entity since such reporting 

helps others by putting them on notice 

of potential attacks to their own 

systems. For purposes of assessing 

compliance with a particular Reliability 

Standard, it may be appropriate to 

differentiate among certain subsets of 

users, owners, and operators. For 

example, the requirement to have 

adequate communications capabilities 

to address real-time emergency 

conditions (COM–001–0 and COM–

002–1) may be necessary for all 

applicable entities regardless of size or 

role, although we understand that the 

implementation of these requirements 

for applicable entities may vary based 

on size or role.42 Therefore, we propose 

to direct NERC to take such factors into 

account in determining applicability, as 

well as compliance requirements, for a 

particular Reliability Standard. 

52. In addition, the Commission 

solicits comment on whether, despite 

the existence of a threshold in a 

particular standard (e.g., generators with 

a nameplate rating of 20 MW or over), 

the ERO or a Regional Entity should be 

permitted to include an otherwise 

exempt facility, e.g., a 15 MW generator, 

on a facility-by-facility basis, if it 

determines that the facility is needed for 

Bulk-Power System reliability. If so, 

what if any process should the ERO or 

Regional Entity provide when making 

such a determination? 

53. NERC has proposed registration of 

joint action agencies or similar 

organizations that would register on 

behalf of their members. APPA asks that 

NERC permit a joint action agency or 

similar organization to accept 

compliance responsibilities on a 

standard-by-standard basis. We propose 

to direct NERC to develop procedures 

which permit a joint action agency or 

similar organization to accept 

compliance responsibility on behalf of 

their members. 

4. Regional Reliability Organizations 

54. NERC has proposed 28 Reliability 

Standards that would apply, in whole or 

in part, to a regional reliability 

organization.43 Many of the 28 

Reliability Standards concern such 

matters as data gathering, data base 

maintenance, preparation of 

assessments and other ‘‘process’’ related 

responsibilities. Others are what have 

been referred to as ‘‘fill-in-the-blank’’

Reliability Standards. Many of the 

proposed Reliability Standards that 

have compliance measures refer to the 

regional reliability organization as a 

compliance monitor. 

55. The Staff Preliminary Assessment 

expressed concern as to whether a 

Reliability Standard that applies to a 

regional reliability organization is 

enforceable pursuant to section 215(e) of 

the FPA, since it is not clear whether a 

regional reliability organization is a 

user, owner or operator of the BulkPower System. NERC contends that 

such Reliability Standards are 

enforceable, and identifies several legal 

theories to support its position. 

Specifically, NERC contends that such 

Reliability Standards are enforceable 

because: (1) Each regional reliability 

organization will voluntarily register as 

a member of NERC and thereby be 

bound to comply; 44 (2) a regional 

reliability organization performs 

functions on behalf of its members that 

are users, owners and operators of the 

Bulk-Power System; and (3) NERC is in 

the process of updating its functional 

model to provide a functional 

description of a regional reliability 

organization that includes functions that 

NERC believes are consistent with a 

system operator. EEI and other 

commenters question whether a 

Reliability Standard can be enforced 

against a regional reliability 

organization. 

56. The Commission is not persuaded 

that a regional reliability organization’s 

compliance with a Reliability Standard 

can be enforced as proposed by NERC. 

Section 215 of the FPA does not appear 

to recognize a regional reliability 

organization as a user, owner or 

operator of the Bulk-Power System. 

Moreover, NERC’s arguments assume 

that each regional reliability 

organization will voluntarily join as a 

member of NERC and be legally bound 

as a member to comply. Further, NERC’s 

claim that a regional reliability 

organization will perform functions on 

behalf of its members that are users, 

owners and operators of the Bulk-Power 

System does not establish a binding 

agency relationship that would create a 

legal basis for requiring regional 

reliability organization compliance with 

Reliability Standards. While it is 

important that the existing regional 

reliability organizations continue to 

fulfill their current roles during the 

transition to a regime where Reliability 

Standards are mandatory and 

enforceable, we do not understand why, 

once the transition is complete, a 

regional reliability organization should 

play a role separate from a Regional 

Entity whose function and 


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45BAL–002, EOP–004, EOP–007, FAC–003, IRO–

001, MOD–001, MOD–002, MOD–003, MOD–004, 

MOD–005, MOD–008, MOD–009, MOD–011, MOD–

013, MOD–014, MOD–015, MOD–016, MOD–024, 

MOD–025, PRC–002, PRC–003, PRC–006, PRC–012, 

PRC–013, PRC–014, PRC–020, TPL–005, and TPL–

006. 46BAL–002, EOP–004, FAC–003, IRO–001, and 

MOD–016. Three of these (EOP–004, FAC–003 and 

MOD–016) are ‘‘data-gathering’’ or ‘‘process-type’’

Reliability Standards. 47EOP–007, MOD–011, MOD–013, MOD–014, 

MOD–015, MOD–024, MOD–025, PRC–002, PRC–

003, PRC–006, PRC–012, PRC–013, PRC–014, PRC–

020, TPL–005, and TPL–006. 48 18 CFR 39.2(d). 

49MOD–001, MOD–002, MOD–003, MOD–004, 

MOD–005, MOD–008, and MOD–009. 

50 Maintaining Reliability in a Competitive U.S. 

Electricity Industry, Final Report of the Task Force 

on Electric System Reliability, Secretary of Energy 

Advisory Board, U.S. Department of Energy 

(September 1998) at 2, 6–7. 

51 16 U.S.C. 824o(a)(1). 

52See NERC Petition, Exhibit A, NERC glossary 

at 2. 

53Staff Preliminary Assessment at 25–26. For 

example, the two 230 kV cables that connect 

Mirant’s Potomac River Plant and the 69 kV 

transmission facilities that supply portions of 

Washington, DC were not included in the MAAC 

definition of bulk electric system. New York City’s 

138 kV system is not included in NPCC’s definition 

of bulk electric system. 

54Staff review of selected Form No. 1 reports filed 

with the Commission indicates that 25 percent or 

more of many public utilities’ total transmission 

responsibility is explicitly recognized 

by section 215 of the FPA. We seek 

comment on whether there is any need 

to maintain separate roles for regional 

reliability organizations with regard to 

establishing and enforcing Reliability 

Standards under section 215. 

57. At present, 28 of the proposed 

Reliability Standards are written to 

apply solely or partially to regional 

reliability organizations.45 We do not 

believe it is necessary or useful to 

remand those Reliability Standards 

simply because they refer to the regional 

reliability organization. For the five 

standards that apply partially to 

regional reliability organizations, the 

Commission proposes action similar to 

other Reliability Standards that need 

improvement, i.e., to approve them and 

direct modification.46 For the other 

Reliability Standards, as an interim 

measure, we propose to direct the ERO 

to use its authority pursuant to § 39.2(d) 

of our regulations to require users, 

owners, and operators to provide to the 

regional reliability organizations the 

information 47 related to data gathering, 

data maintenance, reliability 

assessments and other ‘‘process’’-type 

functions.48 We believe that this 

approach is necessary to ensure that 

there will be no ‘‘gap’’ during the 

transition from the current voluntary 

reliability model to a mandatory system 

in which Reliability Standards are 

enforced by the ERO and Regional 

Entities. In the long run, we propose to 

make the Regional Entities responsible, 

through delegation by the ERO, for the 

functions currently performed by the 

regional reliability organizations. As 

part of this change, the delegation 

agreements to the Regional Entities 

should be modified to bind the Regional 

Entities to assume these duties and 

responsibility for noncompliance. In 

addition, the Reliability Standards 

should be modified to apply through the 

Functional Model, to the users, owners 

and operators of the Bulk-Power System 

that are responsible for providing 

information. 

58. Further, the Commission proposes 

to require that any Reliability Standard 

that references a regional reliability 

organization as a compliance monitor be 

modified to refer to the ERO as the 

compliance monitor. 

59. Finally, for the remaining seven 

Reliability Standards (fill-in-the-blank 

standards),49 we propose to request 

additional information on these 

proposed Reliability Standards pending 

receipt of additional information, as 

detailed below in the discussion on fillin-the-blank standards. 

5. Bulk-Power System v. Bulk Electric 

System 

60. As noted above, Commissionapproved Reliability Standards are to 

provide for the Reliable Operation of the 

Bulk-Power System. Generally speaking, 

the Nation’s Bulk-Power System has 

been described as consisting of 

‘‘generating units, transmission lines 

and substations, and system 

controls.’’ 50 The transmission system 

component of the Bulk-Power System is 

understood to provide for the movement 

of power in bulk to points of 

distribution for allocation to retail 

electricity customers. Essentially, 

whereas transmission lines and other 

parts of the transmission system, 

including control facilities serve to 

transmit electricity in bulk form from 

the generation sources to concentrated 

areas of retail customers, the 

distribution system moves the 

electricity to where these retail 

customers consume it at a home or 

business. 

61. Section 215(b)(1) of the FPA 

provides that all users, owners and 

operators of the Bulk-Power System 

must comply with Commissionapproved Reliability Standards. For 

purposes of section 215, the statute 

defines ‘‘Bulk-Power System’’ to mean: 

(A) Facilities and control systems 

necessary for operating an interconnected 

electric energy transmission network (or any 

portion thereof); and (B) electric energy from 

generating facilities needed to maintain 

transmission system reliability. The term 

does not include facilities used in the local 

distribution of electric energy.51

62. Notably, the statutory definition of 

Bulk-Power System does not establish 

voltage threshold limits on applicable 

transmission facilities or electric energy 

from generating facilities. It does, 

however explicitly exclude facilities 

used in the local distribution of 

electricity. The NERC glossary, in 

contrast, states that Reliability 

Standards apply to the ‘‘bulk electric 

system,’’ which is defined in terms of a 

voltage threshold, as follows: 

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.52

63. While NERC’s definition generally 

excludes transmission facilities 

operated below 100 kV, NERC allows 

each regional reliability organization to 

add specificity to this general 

obligation. 

64. The Staff Preliminary Assessment 

expressed concern that differences 

between the statutory definition of BulkPower System and NERC’s definition of 

bulk electric system create a 

discrepancy that could result in 

reliability gaps.53 Staff also expressed 

concern that allowing a regional 

reliability organization to define what 

facilities are included in the bulk 

electric system could result in 

conflicting definitions—potentially 

subjecting or excluding similar facilities 

from compliance with the Reliability 

Standards. 

65. NERC recommends that, for the 

initial approval of proposed Reliability 

Standards, the continued use of NERC’s 

definition of Bulk Electric System is 

appropriate. In the longer term, NERC 

suggests that change may be appropriate 

but that any global change at this 

juncture will affect many Reliability 

Standards and is best achieved through 

the Reliability Standards development 

process. Some commenters emphasize 

that all facilities necessary for BulkPower System reliability must be 

covered by the Reliability Standards, 

and none should be omitted by a 

discretionary act of a regional reliability 

organization. Many commenters, 

however, state that these excluded 

transmission systems have not been the 

cause of any of the large blackouts and 

therefore should not be considered as 

part of the Bulk-Power System.54


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line miles operate below 100 kV. Yet such facilities 

may well be as much a part of an entity’s portion 

of the nation’s integrated transmission system 

component of the Bulk-Power System as the 

transmission facilities operating at or above 100 kV 

because these lower voltage facilities support the 

higher voltage facilities. Indeed, it is not unusual 

to see outages of 69 kV transmission facilities 

limiting the higher voltage transmission facilities 

with which they are networked. 

55As mentioned earlier, ‘‘Reliable Operation 

means operating the elements of the Bulk-Power 

System within equipment and electric system 

thermal, voltage, and stability limits so that 

instability, uncontrolled separation, or cascading 

failures of such system will not occur as a result 

of sudden disturbance, including a Cybersecurity 

Incident, or unanticipated failure of system 

elements.’’ See Order No. 672 at P 64. See also 18 

CFR 39.1. 

56We note that the regional definitions have not 

been submitted to us and we are not determining 

the appropriateness of any regional definition in 

this proceeding. 

57Order No. 672 at P 262, 321–37. 

58 Id. at P 345. 

59 Id. at P 378. 

60NERC Petition at 6–8. 

61 Id. at 9–12. The benchmarks are: Applicability; 

purpose; performance requirements; measurability; 

technical basis in engineering and operations; 

completeness; consequences for noncompliance; 

clear language; practicality; and consistent 

terminology. 

Furthermore, some commenters, 

including those representing small 

transmission owners, prefer the 

continued use of the NERC definition 

and caution against simply replacing all 

references to bulk electric system with 

Bulk-Power System because (1) the 

latter term as defined in section 215 of 

the FPA is ambiguous and (2) it would 

likely lead to an unintended substantive 

change in various Reliability Standards. 

66. We believe that Congress intended 

that the definitions of Bulk-Power 

System and Reliable Operation 55 in 

section 215 of the FPA to further the 

objective of maintaining the reliability 

of the entire Bulk-Power System, 

including maintaining the reliability of 

all of the elements of the transmission 

component of the Bulk-Power System. 

We believe that the transmission 

elements excluded under NERC’s bulk 

electric system approach, including 

transmission that serves critical load 

centers, are subject to the Commission’s 

jurisdiction under section 215. 

67. The term Bulk-Power System as 

defined in section 215 of the FPA is one 

determinant of the Commission’s 

jurisdiction for reliability purposes (the 

phrase ‘‘user, owner or operator’’ being 

another). While we do not believe that 

it is appropriate to categorically exclude 

any class of facilities from the definition 

of Bulk-Power System, we recognize 

that a particular Reliability Standard 

may appropriately only need to apply to 

a subset of facilities that comprise the 

Bulk-Power System. Thus, the 

Commission may approve a Reliability 

Standard that applies to the bulk 

electric system as defined by NERC 

without limiting the ability of the ERO 

to develop and propose standards 

applicable to the broader set of facilities 

encompassed by the statutory definition 

as may be necessary. 

68. The Commission believes that the 

ERO has suggested a sensible transition 

approach. The Commission proposes 

that, for the initial approval of proposed 

Reliability Standards, the continued use 

of NERC’s definition of bulk electric 

system as set forth in the NERC glossary 

is appropriate.56 However, we interpret 

the term ‘‘bulk electric system’’ to apply 

to all of the ≥ 100 kV transmission 

systems and any underlying 

transmission system (< 100 kV) that 

could limit or supplement the operation 

of the higher voltage transmission 

systems. It would also include 

transmission to all significant local 

distribution systems (but not the 

distribution system itself), load centers, 

and transmission connecting generation 

that supplies electric energy to the 

system. If there is a question concerning 

which underlying transmission system 

limits or supplements the operation of 

the higher voltage transmission system, 

the Commission proposed that the ERO 

would provide the final determination 

on a case by case basis. 

69. Continued reliance on multiple 

regional interpretations of the NERC 

definition of bulk electric system, which 

omits significant portions of the 

transmission system component of the 

Bulk-Power System that serve critical 

load centers, is not appropriate. We 

propose that NERC eventually revise the 

current definition of bulk electric 

system to ensure that all facilities, 

control systems, and electric energy 

from generation resources that impact 

system reliability are included within 

the scope of applicability, and that 

NERC’s revision is consistent with the 

statutory term Bulk-Power System. 

70. While the approach outlined 

above may result initially in a 

Reliability Standard applying to a set of 

Bulk-Power System facilities that is less 

than that of the full reach of the 

Commission’s jurisdiction pursuant to 

section 215 of the FPA (the ‘‘gap’’ to 

which the Staff Preliminary Assessment 

referred), we agree with the commenters 

that a wholesale substitution of one 

term for another could lead to 

unintended substantive changes within 

certain Reliability Standards. 

71. The Commission solicits comment 

on this interpretation and whether the 

Regional Entities should, in the future, 

play a role in either defining the 

facilities that are subject to a Reliability 

Standard or be allowed to determine an 

exception on a case-by-case basis. 

C. Mandatory Reliability Standards 

1. Legal Standard for Approval of 

Reliability Standards 

72. Section 215(d)(2) of the FPA states 

that the Commission may approve a 

Reliability Standard if it determines that 

a Reliability Standard is just, 

reasonable, not unduly discriminatory 

or preferential, and in the public 

interest. In Order No. 672, the 

Commission addressed issues regarding 

the application of the statutory standard 

in our review of a proposed Reliability 

Standard. The Commission identified a 

series of factors it would consider when 

assessing whether to approve or remand 

a Reliability Standard.57 Further, Order 

No. 672 stated that the Commission 

would, consistent with the statute, give 

‘‘due weight’’ to the technical expertise 

of the ERO with respect to the content 

of a proposed Reliability Standard. 

However, due weight does not equate to 

a rebuttable presumption that a 

proposed Reliability Standard meets the 

statutory requirement of being just, 

reasonable, not unduly discriminatory 

or preferential, and in the public 

interest.58 Further, the Commission 

review of a proposed Reliability 

Standard would balance any conflict 

between a proposed Reliability Standard 

and competition on a case-by-case 

basis.59

73. NERC suggests that a proposed 

Reliability Standard that has been 

developed through its Reliability 

Standards development process, which 

has been certified by ANSI as being 

open, inclusive, balanced and fair, is 

assured to be ‘‘just, reasonable, and not 

unduly discriminatory or 

preferential.’’ 60 NERC also proposes 10 

‘‘benchmarks’’ for evaluating a proposed 

Reliability Standard that, according to 

NERC, ‘‘may be helpful’’ to the 

Commission in determining whether a 

Reliability Standard is ‘‘just, reasonable 

and not unduly discriminatory or 

preferential’’ if due process provided by 

the ANSI process alone does not 

suffice.61 In addition, NERC suggests 

that the Commission should consider 

the benchmarks when determining 

whether a proposed Reliability Standard 

‘‘is in the public interest.’’

74. In Order No. 672, the Commission 

rejected the notion that it would 


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62Order No. 672 at P 338. 

63ERO Certification Order, 116 FERC ¶ 61,062, at 

P 241. 

64Order No. 672 at P 262, 321–37. 

65See NERC Petition at 109; NERC Comments at 

14–19. 

66 July 6, 2006 technical conference, Tr. at 14–47. 

According to NERC, conditional approval means 

that the Commission would approve the Reliability 

Standards as mandatory and enforceable. In 

enforcing conditional standards, NERC and the 

Regional Entities would factor into the 

determination of violations and the imposition of 

penalties that certain requirements may be regional 

‘‘fill-in-the-blank’’ requirements or may be missing 

compliance information. 

67See ERO Certification Order at P 233, where the 

Commission also noted that, if a Reliability 

Standard is inadequate or has unintended 

consequences, it may order the ERO to submit a 

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

FPA, 16 U.S.C. 824o(d)(5), which provides that 

‘‘[t]he Commission * * * may order the Electric 

Reliability Organization to submit to the 

Commission a proposed reliability standard or 

modification to a reliability standard that addresses 

a specific matter if the Commission considers such 

a new or modified reliability standard appropriate 

to carry out this section.’’

68See 18 CFR 39.5(g) (‘‘[t]he Commission, when 

remanding a Reliability Standard * * * may order 

a deadline by which the [ERO] must submit a * * * 

modified Reliability Standard’’). 69Order No. 672 at P 329. 

presume that a proposed Reliability 

Standard developed through an ANSIcertified process automatically satisfies 

the statutory standard of review.62

While an open and transparent process 

certainly is extremely important to the 

overall success of implementing section 

215 of the FPA, an evaluation of any 

proposed Reliability Standard must 

focus primarily on matters of substance 

rather than procedure. We will, 

therefore, review each Reliability 

Standard in addition to the process 

through which it was approved by 

NERC to ensure that the Reliability 

Standard is just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest. 

75. Likewise, with regard to NERC’s 

benchmarks, we will not constrain 

ourselves by approving or remanding a 

proposed Reliability Standard based on 

whether it satisfies the benchmarks. In 

our order certifying NERC as the ERO, 

we determined that the benchmarks and 

other factors would be useful for the 

ERO in developing proposed Reliability 

Standards.63 The Commission did not 

suggest that it would rely on the 

benchmarks in its review of a proposed 

Reliability Standard. Rather, as 

discussed above, Order No. 672 

identified factors that the Commission 

will consider when determining 

whether a proposed Reliability Standard 

satisfies the statutory requirements.64

2. Commission Options When Acting on 

a Reliability Standard 

76. NERC recommends that the 

Commission ‘‘conditionally approve’’

certain proposed Reliability Standards 

that it believes satisfy the statutory 

requirement but require improvement.65

The concept of conditional approval of 

a Reliability Standard was discussed at 

length in the July 6, 2006 technical 

conference.66 Many commenters 

responding to the Staff Preliminary 

Assessment support some form of 

conditional approval, while others 

oppose the concept out of concern that 

conditional approval will further 

complicate the understanding of 

mandatory Reliability Standards and 

present a ‘‘moving target’’ because 

NERC has proposed a plan to modify 

numerous proposed Reliability 

Standards before the Commission would 

approve them in a final rule. 

77. The Commission believes that 

conditional approval may be a useful 

procedural tool that it may want to use 

when reviewing a Reliability Standard 

proposed at some future date. However, 

after careful consideration, the 

Commission is not proposing to 

conditionally approve any of the 107 

Reliability Standards currently before 

us. Rather, as reflected in our 

substantive analysis of each Reliability 

Standard, we will propose one of four 

actions: 

78. Approve: Approval is appropriate 

for a proposed Reliability Standard that 

the Commission determines to be ‘‘just, 

reasonable, not unduly discriminatory 

or preferential, and in the public 

interest,’’ and as to which the 

Commission has not identified any 

additional issues that the ERO needs to 

address at this time to improve the 

Reliability Standard. Mandatory 

compliance with the Reliability 

Standard would be required as of the 

effective date of the Final Rule. The 

Commission has approved NERC’s plan 

to review each Reliability Standard 

within five years from the effective date 

of the standard or its latest revision. 

79. Approve as mandatory and 

enforceable; and direct modification 

pursuant to section 215(d)(5): The 

Commission would take two separate 

and distinct actions under the statute. 

First, pursuant to section 215(d)(2) of 

the FPA, the Commission would 

approve a proposed Reliability 

Standard, which would be mandatory 

and enforceable upon the effective date 

of the Final Rule. Second, the 

Commission would direct NERC to 

submit a modification of the Reliability 

Standard to address specific issues or 

concerns identified by the Commission 

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

FPA.67

80. This option is appropriate for a 

large number of proposed Reliability 

Standards where the Commission has 

identified improvements which are 

necessary or appropriate, but where the 

proposed Reliability Standard 

nonetheless satisfies the statutory 

requirement that it be just, reasonable, 

not unduly discriminatory or 

preferential, and in the public interest. 

This approach also allows us to give due 

weight to the technical expertise of the 

ERO in approving a Reliability 

Standard, yet also provides a 

mechanism to have the Commission’s 

concerns addressed. Thus, where 

appropriate, we propose to approve 

these Reliability Standards as 

mandatory and enforceable, and direct 

modifications pursuant to section 

215(d)(5). For these Reliability 

Standards, we provide guidance with 

regard to how and why they need to be 

improved and may establish a deadline 

by which a modification must be 

resubmitted to the Commission. 

81. Request additional information: 

There are some Reliability Standards 

that do not contain sufficient 

information to enable us to propose a 

disposition. For those Reliability 

Standards, we will identify the 

information that we require, and 

propose not to approve or remand these 

Reliability Standards until all the 

relevant information is received. For 

example, many of the fill-in-the-blank 

Reliability Standards will not be 

approved or remanded until the 

Commission has received all the 

necessary information. We may set a 

deadline by which NERC must submit 

the necessary information. 

82. Remand: Remand is appropriate 

for a proposed Reliability Standard that 

does not satisfy the statutory criteria 

that it be ‘‘just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest.’’ The Commission 

may choose to set a deadline for NERC 

to submit a modified Reliability 

Standard.68 In the interim, the 

remanded standard would not be 

mandatory and enforceable. The 

Commission will not hesitate to remand 

a Reliability Standard that it finds does 

not provide for an adequate level of 

reliability.69

3. Prioritizing Modifications to 

Reliability Standards 

83. As discussed above, the 

Commission is proposing to approve 

certain Reliability Standards and, as a 

separate action, is proposing to direct 

the ERO to modify many of the same 

Reliability Standards pursuant to 

section 215(d)(5) of the FPA. The 


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70See Appendix D (High Priority List). 

71See, e.g., Alberta, APPA, ISO/RTO Council, 

PSEG, WIRAB and WECC. 

72ERO Certification Order, 116 FERC ¶ 61,062, at 

P 462. 

73See Order No. 672 at P 400. 

74ERO Certification Order, 116 FERC ¶ 61,062, at 

P 286. 

Commission recognizes that it is not 

reasonable to expect the modification of 

such a substantial number of Reliability 

Standards in a short period of time. 

Rather, the ERO will have to set 

priorities regarding the order and timing 

for developing modified Reliability 

Standards and resubmitting them to the 

Commission. 

84. Many commenters recognize the 

need for NERC to identify priorities in 

terms of which Reliability Standards are 

most critical to reliability and should be 

revised immediately, and which are of 

lesser priority. A number of 

commenters, including WIRAB, suggest 

detailed plans on how to set such 

priorities, focusing primarily on 

identifying those Reliability Standards 

that are most critical to maintaining 

reliability and those that are closest to 

being ready for implementation. 

Commenters suggest a staggered 

schedule, some suggesting several years 

for completion. 

85. We propose that NERC first focus 

its resources on modifying those 

Reliability Standards that have the 

largest impact on near term Bulk-Power 

System reliability. Many of the 

proposed modifications that reflect 

Blackout Report recommendations fit 

this description and should be a high 

priority. The Commission has identified 

a group of Reliability Standards that it 

believes should be given the highest 

priority by the ERO based on the above 

guidance.70 However, this is not meant 

to be an exclusive or inflexible list and 

ERO and commenter input is welcome. 

We propose that NERC address the 

modifications we propose for these high 

priority Reliability Standards within 1 

year of the effective date of the Final 

Rule. 

86. In addition, we propose that NERC 

address certain Reliability Standards 

that are not necessarily identified above 

as ‘‘high priority’’ may be modified in 

a relatively short time frame where the 

proposed modifications are relatively 

minor or ‘‘administrative’’ in nature. We 

believe that the ERO may complete such 

modifications relatively quickly with 

little diversion of ERO resources. Such 

modifications may include a proposal to 

modify a Reliability Standard to: (1) 

Identify the ERO as the compliance 

monitor rather than the regional 

reliability organization; (2) include 

Measures and Levels of Noncompliance; or (3) require other 

relatively minor clarifications or 

modifications. 

87. While the Commission has 

identified some modifications to 

Reliability Standards that it believes 

would be appropriate for the ERO to 

resubmit as high priority items, we 

believe that it is important that the ERO 

develop a detailed, comprehensive work 

plan to address all of the modifications 

that are directed pursuant to a final rule. 

The work plan should take a staggered 

approach and complete all the proposed 

modifications either within two or three 

years from the effective date of the final 

rule. 

88. The Commission believes that this 

proposal strikes a reasonable balance 

between the need to timely implement 

identified improvements to the existing 

Reliability Standards that will further 

Bulk-Power System reliability and the 

need for the ERO to develop 

modifications with industry input using 

its open, stakeholder process. The 

Commission may use its authority, 

pursuant to § 39.5(g) of the 

Commission’s regulations, to set a 

deadline for the ERO to submit a 

modified Reliability Standard if the 

Commission is not satisfied with the 

time frame proposed by the ERO work 

plan. 

89. The Commission solicits comment 

on its prioritization proposal. 

4. Trial Period 

90. A number of commenters favor a 

phase-in of Reliability Standards with a 

trial period, during which Reliability 

Standards would be mandatory, but no 

penalties would be assessed.71 Various 

commenters suggest that the trial period 

should last for a range of six months to 

five years. 

91. NERC, in its application for ERO 

certification, proposed a six month 

‘‘notice period’’ during which NERC 

would determine ‘‘financial’’ penalties 

and provide notice of the penalties to 

violating entities, but would not collect 

any penalties. NERC stated that it would 

submit a report on the effectiveness of 

the revised Sanction Guidelines to the 

Commission by May 31, 2007. In the 

ERO Certification Order, the 

Commission rejected requests to 

lengthen NERC’s proposed six-month 

‘‘notice period’’ because it 

‘‘appropriately balances the time needed 

for NERC to implement the Sanction 

Guidelines with the countervailing 

interest in activating the mandatory 

Compliance Enforcement program as 

rapidly as possible.’’ 72

92. The Commission, however, is 

increasingly concerned that a trial 

period that commences with the 

effective date of mandatory Reliability 

Standards may interfere with mandatory 

and enforceable Reliability Standards 

being in effect by next summer. 

Moreover, the proposed Reliability 

Standards have already been in effect 

for a substantial period of time on a 

voluntary basis. Thus, the Commission 

proposes to eliminate a formal trial 

period. Entities that have complied with 

NERC’s standards on a voluntary basis 

should be familiar with the proposed 

mandatory Reliability Standards and 

what is required for compliance. 

Therefore, an extensive trial period is 

unnecessary for such entities. 

93. The Commission recognizes that 

there are entities that have not 

historically participated in the 

voluntary system (including some 

relatively small entities) that may not be 

familiar with the proposed mandatory 

Reliability Standards and what is 

required for compliance. For such 

entities, we propose that the ERO and 

Regional Entities use their enforcement 

discretion in imposing penalties on 

such entities for the first six months the 

Reliability Standards are in effect. 

However, the Commission, the ERO, 

and the Regional Entities would still 

retain the authority to impose penalties 

on such entities if warranted by the 

circumstances. 

5. International Coordination of 

Remands 

94. Canadian commenters, such as the 

FPT Group, Alberta, CEA and Ontario 

IESO, request that the Commission 

affirm that it will seek to coordinate 

with authorities in Canada prior to any 

exercise of conditional approval, 

remand or rejection of a proposed 

Reliability Standard; and that each 

existing NERC standard will retain its 

present applicability until such time as 

the Commission approves it as a 

mandatory Reliability Standard. 

95. The Commission has recognized 

the importance of international 

coordination in both Order No. 672 73

and the ERO Certification Order.74 In 

the latter order, the Commission 

directed NERC to revise its proposed 

coordination process to: (1) Identify the 

relevant regulatory bodies and their 

respective standards approval and 

remand processes that will be 

implicated in any remand of a proposed 

standard; and (2) specify actual steps to 

coordinate all of these processing 

requirements, including those that may 

be necessary to expedite processing a 

proposed Reliability Standard that must 

be remanded. The Commission believes 


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75See Staff Preliminary Assessment at 17–26. 

76Blackout Report at Chapter 10. 

77NERC Comments at 40. 

78Although NERC does not formally define 

‘‘Measures,’’ NERC explains that they ‘‘are the 

evidence that must be presented to show 

compliance’’ with a standard and ‘‘are not intended 

to contain the quantitative metrics for determining 

satisfactory performance.’’ NERC Comments at 104. 

79 ‘‘Levels of Non-Compliance’’ are established 

criteria for determining the severity of noncompliance with a Reliability Standard. The levels 

of non-compliance range from Level 1 to Level 4, 

with Level 4 being the most severe. 

80See NERC Comments at 105 (‘‘Metrics of 

satisfactory performance are defined in the 

requirements. * * *’’). 

that NERC’s development of a 

coordination process, together with 

existing means of communication and 

coordination such as the U.S.—Canada 

Bilateral Electric Reliability Oversight 

Group, will provide the necessary 

mechanisms for international 

coordination. 

D. Common Issues Pertaining to 

Reliability Standards 

96. As explained in the Staff 

Preliminary Assessment,75 certain 

issues are common to a number of 

proposed Reliability Standards. 

Immediately below, we discuss these 

common issues, followed by a 

discussion and determination of each 

individual proposed Reliability 

Standard. 

1. Blackout Report Recommendations 

97. As explained in the Staff 

Preliminary Assessment, the Blackout 

Report identified a number of factors 

common to eight major blackouts 

experienced in North America since 

1965 and made 46 specific 

recommendations to improve reliability 

based on the lessons learned from the 

August 2003 blackout and previous 

blackouts. These included specific 

recommendations to modify certain 

existing Reliability Standards. While 

recognizing the progress NERC has 

made, the Staff Preliminary Assessment 

also expressed concern that the 

proposed Reliability Standards continue 

to reflect several of the deficiencies 

identified by the Blackout Report. 

98. In its comments, NERC 

emphasizes that implementation of the 

Blackout Report recommendations has 

been its top priority since August 2003 

and describes the progress it has made 

in addressing specific recommendations 

and the status of ongoing work. It states 

that some of the hardest work on issues 

such as relay loadability and reactive 

power require extensive investigation 

before standards can be drafted. Other 

commenters suggest that the Blackout 

Report recommendations provide useful 

direction for areas where the Reliability 

Standards require modification and for 

setting priorities when determining 

which Reliability Standards to modify 

first. A few commenters ‘‘downplayed’’

the significance of the Blackout Report, 

noting that there is no statutory basis to 

accept all the Task Force’s 

recommendations as absolute, infallible 

requirements and that not all 

recommendations translate into 

Reliability Standards. 

99. The Commission believes that the 

Blackout Report recommendations 

address key issues for assuring BulkPower System reliability. The Blackout 

Report recommendations were 

developed by and have received 

international support from both 

industry and regulators in the United 

States and Canada and we believe they 

represent a well-reasoned and sound 

basis for action. Further, the Blackout 

Report recommendations address issues 

that caused or contributed to not only 

the August 2003 blackout, but multiple 

blackouts over the past 20 years.76 Thus, 

in the discussion of a particular 

proposed Reliability Standard, we often 

will recognize the merit of a specific 

Blackout Report recommendation and 

reaffirm the reasoning behind such 

recommendation in proposing to 

approve with a directive to modify a 

specific Reliability Standard. Further, 

we believe that a modification to a 

proposed Reliability Standard that was 

recommended in the Blackout Report 

should receive the highest priority in 

terms of NERC’s workplan to address 

identified deficiencies. 

100. The Commission believes that 

prudent policy for Bulk-Power System 

reliability is to have Reliability 

Standards that are proactive. Such 

Reliability Standards would require 

actions be taken to prevent a blackout or 

outage and not simply address the 

undesirable outcomes. Therefore, it 

must first and foremost address the 

critical steps or actions that determine 

the achievement of the outcome. This 

proactive approach is necessary to 

ensure that the responsible entity is 

aware of and performs all of the 

necessary steps to achieve the ultimate 

reliability goal, rather than reacting to 

the implications of not achieving the 

outcome. 

101. Our concern is illustrated by an 

analogy provided by NERC in regard to 

commercial airline maintenance.77 A 

purely outcome-based standard on 

maintenance would require zero plane 

crashes due to failure of airplane 

components. But the public interest 

would not be well served if this were 

the only standard because the 

consequences of failing to meet the 

standard are immediate and 

unacceptable and provides no guidance 

on how to achieve the goal. The public 

interest dictates that there should be 

standards on maintenance procedures, 

frequency of testing and qualifications 

of personnel conducting the 

maintenance—not just a requirement 

that there be no accidents. This same 

concept applies to mandatory Reliability 

Standards pertaining to the Bulk-Power 

System. 

102. Accordingly, the Commission 

expects the ERO to include proactive 

Requirements in the Reliability 

Standards in addition to Requirements 

that identify a specific outcome. 

2. Measures and Levels of NonCompliance 

103. As noted above, the uniform 

format that NERC employs for each of 

its proposed Reliability Standards 

reflects five organizational elements: 

Introduction, Requirements, Measures, 

Compliance, and Regional Differences. 

The Staff Preliminary Assessment stated 

that 26 of the proposed Reliability 

Standards do not contain Measures 78 or 

Levels of Non-Compliance,79 or both. 

The Staff Preliminary Assessment 

emphasized that Reliability Standards 

would be less subject to variable 

implementation if they included the use 

of performance metrics, where 

applicable. The Staff Preliminary 

Assessment assumed that metrics used 

to determine non-compliance would be 

included in the Measures similar to 

BAL–001. NERC subsequently clarified 

that such metrics are not intended to be 

part of the Measure, but rather in the 

Requirements.80

104. NERC, in its Petition, identified 

21 Reliability Standards that lack 

Measures or Levels of Non-Compliance 

and indicated that it plans to file 

modified Reliability Standards that 

include the missing Measures and 

Levels of Non-Compliance in November 

2006. Further, NERC contends that a 

Reliability Standard lacking Measures or 

Levels of Non-Compliance is still 

enforceable because the Measures 

should be viewed as the process to 

determine non-compliance during 

audits and investigations. According to 

NERC, the ‘‘Requirements’’ within a 

Reliability Standard define what an 

entity must do to be compliant and 

establish an enforceable obligation, and 

the presence or absence of Measures or 

Levels of Non-Compliance should not 

be the sole determining factor as to 

whether a Reliability Standard meets 

the statutory test for approval. Several 


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81See, e.g., National Grid and BPA. 

82NERC Comments at 104. See also NERC 

Petition at 83. 

83Notably, the Commission elsewhere imposes 

records retention requirements to facilitate effective 

enforcement. For example, in Order No. 677, FERC 

Stats. & Regs. 31,218 (2006), the Commission 

amended 18 CFR parts 35 and 284 by extending 

certain sellers’ record retention requirement from 

three to five years so as to bring the record retention 

requirement in line with the five year limitations 

period applicable where the Commission might 

seek to impose civil penalties for violations of the 

anti-manipulation rule, 18 CFR part 1c. In the 

reliability context, the civil penalty statute of 

limitations period for both the Commission and 

ERO and Regional Entities will also be five years. 

See Order No. 672 at P 487. 

84Staff Preliminary Assessment at 18–19. 

85NERC Petition at 90–91; NERC Comments at 

101–02. 

86See, e.g., LPPC, MISO, NEMA, SDG&E and 

WECC. 87Staff Preliminary Assessment at 19. 

commenters take the opposite view, 

contending that Measures and Levels of 

Non-Compliance are necessary to ensure 

that a Reliability Standard is sufficiently 

clear to be fairly enforced.81

105. We agree that it is important to 

have Measures and Levels of NonCompliance specified for each 

Reliability Standard, and recognize that 

NERC has plans to provide many of 

these elements in a November 2006 

filing. However, the absence of these 

two elements, which describe 

approaches that will be used to assess 

non-compliance, including the severity 

of a violation for penalty settingpurposes, is not critical to our 

determination of whether to approve a 

proposed Reliability Standard. The most 

critical element of a Reliability Standard 

is the Requirements. As NERC explains, 

‘‘the Requirements within a standard 

define what an entity must do to be 

compliant * * * [and] binds an entity 

to certain obligations of performance 

under section 215 of the FPA.’’ 82 If 

properly drafted, a Reliability Standard 

may be enforced in the absence of 

specified Measures or Levels of NonCompliance. 

106. While Measures and Levels of 

Non-Compliance provide useful 

guidance to the industry, compliance 

will in all cases be measured by 

determining whether a party met or 

failed to meet the Requirement under 

the specific facts and circumstances of 

its use, ownership or operation of the 

Bulk-Power System. Therefore, we 

propose to approve a Reliability 

Standard that lacks Measures or Levels 

of Non-Compliance, or where these 

elements contain ambiguities, provided 

that the Requirement is sufficiently 

clear and enforceable. Where a 

Reliability Standard will be improved 

by providing missing Measures or 

Levels of Non-Compliance or by 

clarifying ambiguities with respect to 

Measures or Levels of Non-Compliance, 

we propose to approve the Reliability 

Standard and concurrently direct NERC 

to modify the Reliability Standard 

accordingly. 

107. The common format of NERC’s 

proposed Reliability Standards calls for 

a ‘‘data retention’’ metric, generally in 

the ‘‘Compliance’’ section of the 

Reliability Standard. Yet, some 

proposed Reliability Standards do not 

contain a data retention requirement or 

state positively that no record retention 

period applies. The Commission seeks 

comment on whether the retention time 

periods specified in various Standards 

proposed by NERC are sufficient to 

foster effective enforcement.83 The 

Commission also seeks comment on 

what, if any, additional records 

retention requirements should be 

established for the proposed Reliability 

Standards. 

3. Ambiguities and Potential Multiple 

Interpretations 

108. The Staff Preliminary 

Assessment indicated that ‘‘various 

elements of numerous standards appear 

to be subject to multiple interpretations, 

especially with regard to the lack of 

specificity in the standards’

requirements, measurability, and 

degrees of compliance.’’ 84 NERC agrees 

that there are many areas in which the 

Reliability Standards can be further 

improved and states that it is committed 

to review each Reliability Standard in 

the next few years, based on priorities 

coordinated with the Commission and 

applicable authorities in Canada.85

NERC adds that, while there are 

opportunities for improvement, the 

existing Reliability Standards contain 

the degree of clarity and specificity 

required to meet the statutory test for 

approval. 

109. Many commenters agree 

generally that ambiguities must be 

removed and mandatory Reliability 

Standards must be sufficiently clear 

with regard to who is responsible and 

what an entity must do to achieve 

compliance.86 Some commenters insist 

that a Reliability Standard should not go 

into effect until this is achieved. WECC 

and LPPC recommend that the 

Commission require NERC to institute a 

quality assurance program to ensure that 

Reliability Standards are clear, concise, 

and non-redundant. 

110. Our review of the Reliability 

Standards has confirmed staff’s concern 

regarding the degree of ambiguity 

contained in certain Measures and 

Levels of Non-compliance portions of 

the proposed Reliability Standards. We 

are pleased that the ERO intends to 

review each Reliability Standard to 

identify and address ambiguous 

Measures and Levels of NonCompliance language. While this is 

important, it is essential that the 

Requirements for each Reliability 

Standard, in particular, are sufficiently 

clear and not subject to multiple 

interpretations. Where the Requirements 

portion of a Reliability Standard is 

sufficiently clear (and no other issues 

have been identified), we propose to 

approve the Reliability Standard. 

111. In other cases, where some 

ambiguity may exist but there is also a 

common interpretation for certain terms 

based on the best practices within the 

industry, we propose to adopt that 

interpretation in the NOPR. For 

purposes of enforcement, the 

Commission proposes to implement any 

approved Reliability Standard 

consistent with our interpretation of any 

ambiguity as explained in the final rule. 

In some cases, we propose to direct 

NERC to supplement the language 

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

FPA. 

112. In summary, the Commission 

believes that a proposed Reliability 

Standard that has Requirements that are 

so ambiguous as to not be enforceable 

should be remanded. A Reliability 

Standard that has sufficiently clear 

Requirements, Measures, and 

Compliance language and is otherwise 

just and reasonable should be approved. 

A proposed Reliability Standard that 

has sufficiently clear and enforceable 

Requirements but Measures or Levels of 

Non-Compliance that are ambiguous (or 

none at all) should be approved in some 

cases with a directive that the ERO 

develop clear and objective Measures 

and Compliance language. 

4. Technical Adequacy 

113. The Staff Preliminary 

Assessment stated that the 

Requirements specified in certain 

Reliability Standards may not be 

sufficient to ensure an adequate level of 

reliability.87 Staff explained that, while 

Order No. 672 noted that the ‘‘best 

practice’’ may be an inappropriately 

high standard, it also warned that a 

‘‘lowest common denominator’’

approach is unacceptable if it is 

insufficient to ensure system reliability. 

114. NERC, EEI and others state that 

NERC’s proposed Reliability Standards 

are technically sound and that 

compliance with them will assure 

reliability. NERC contends that each 

proposed Reliability Standard meets the 

statutory test of providing an adequate 


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88See, e.g., NPCC, SDG&E and NYSRC. 

89See NERC Petition at 87–90. 

90EOP–007, IRO–001, MOD–003, MOD–011, 

MOD–013, MOD–014, MOD–015, MOD–016, PRC–

002, PRC–003, PRC–006, PRC–012, PRC–013, and 

PRC–014. 

91BAL–002, EOP–004, MOD–001, MOD–002, 

MOD–004, MOD–005, MOD–008, MOD–009, MOD–

024, and MOD–025. 

92EOP–009, FAC–001, FAC–002, FAC–004, 

MOD–010, MOD–012, MOD–017, MOD–019, PER–

002, PRC–004, PRC–007, PRC–008, PRC–009, PRC–

015, and PRC–016. 

93NERC Petition at 89. 

94This group includes 24 of the 25 standards 

originally included in categories two and three, 

plus two additional standards not originally 

designated as fill-in-the-blank standards: BAL–002–

0, EOP–009–0, FAC–001–0, FAC–002–0, FAC–004–

0, MOD–001–0, MOD–002–0, MOD–004–0, MOD–

005–0, MOD–008–0, MOD–009–0, MOD–010–0, 

MOD–012–0, MOD–017–0, MOD–019–9, MOD–

024–1, MOD–025–1, PER–002–0, PRC–004–1, PRC–

007–0, RPC–008–0, PRC–009–0, PRC–015–0, PRC–

016–0, TPL–002–0,* and TPL–004–0.* (* Newly 

identified as fill-in-the-blank standards.) 

95EOP–004–0, EOP–006–0,* and IRO–005–1.* 

(* Newly identified as fill-in-the-blank standards.) 

NERC proposes that these 3 standards, along with 

23 others that are missing measures or compliance 

elements be conditionally approved with the 

understanding that the missing measures and 

compliance information will be filed in November 

2006, after completion of stakeholder balloting in 

September and NERC board voting on November 1, 

2006. 

96NERC Comments at 107. 

97Order No. 672 at P 292. 

level of reliability for the Bulk-Power 

System. Others share staff’s concern that 

Reliability Standards not represent the 

lowest common denominator.88 One 

commenter suggested that there is a 

tendency for a standard drafting team to 

adopt a lowest common denominator 

approach to achieve a consensus on a 

standard. 

115. We are cautious about drawing 

any general conclusions about technical 

adequacy as we consider this a matter 

that can only be addressed on a 

standard-by-standard basis. While we 

are required under the statute to accord 

due weight to the technical expertise of 

the ERO, we are still required to 

independently assess the technical 

adequacy of any proposed Reliability 

Standard. Where we have specific 

concerns regarding whether a 

Requirement set forth in a proposed 

Reliability Standard may not be 

sufficient to ensure an adequate level of 

reliability or represents a ‘‘lowest 

common denominator’’ approach, we 

address those concerns in the context of 

that particular Reliability Standard. 

5. Fill-in-the-Blank Standards 

116. Certain Reliability Standards 

developed by NERC require the regional 

reliability organizations to develop 

criteria for use by users, owners, or 

operators within the region. NERC refers 

to these as ‘‘fill-in-the-blank 

standards.’’ 89 NERC originally proposed 

39 fill-in-the-blank standards, which it 

said fell into three categories. The first 

14 were Reliability Standards that 

require a regional reliability 

organization to set regional criteria or 

develop a regional procedure.90 The 

second group contained 10 Reliability 

Standards that require the regional 

reliability organization to develop such 

criteria or procedures, and also require 

entities within the region to follow 

those procedures or criteria.91 The third 

category consisted of 15 Reliability 

Standards that require users, owners, 

and operators to follow criteria or 

procedures developed by the regional 

reliability organization, but did not (in 

the same Reliability Standard) require 

the development of such criteria or 

procedures.92 NERC indicated that the 

first category did not pose a problem 

because they were enforceable as 

written. The issue with the remaining 

25 Reliability Standards was whether 

they could be enforced given that the 

regional criteria and procedures were 

not developed through an EROapproved process and were not 

submitted to the Commission for 

approval. NERC acknowledged that the 

25 fill-in-the blank Reliability Standards 

in categories two and three required 

further evaluation and proposed 

providing a work plan to the 

Commission by November 8, 2006 with 

a timetable for modifying, replacing, or 

withdrawing these standards.93

117. The Staff Preliminary 

Assessment recognized that the fill-inthe-blank standards raise two principal 

concerns: (i) Some are not enforceable 

against users, owners, and operators of 

the Bulk-Power System, but rather only 

provide broad direction to regional 

reliability organizations, and (ii) the 

specific implementing standards 

adopted by the regional reliability 

organizations have not undergone an 

approval process under section 215 and, 

thus cannot be enforced by the 

Commission or the ERO. 

118. In its June 26, 2006 comments to 

the Staff Preliminary Assessment, NERC 

amended its approach to the fill-in-theblank standards. It recommends 

unconditional approval of the ‘‘category 

one’’ Reliability Standards, which place 

a requirement on a regional reliability 

organization to set criteria or procedures 

for reliability in the region, claiming 

that they are really not fill-in-the-blank 

standards. NERC then proposes to 

divide the remaining fill-in-the-blank 

standards into two new groups, the first 

group consisting of 26 Reliability 

Standards.94 The remaining group 

consists of three fill-in-the-blank 

standards that also are missing measures 

or compliance elements.95 NERC 

recommends conditional approval of 

these 29 remaining fill-in-the-blank 

standards. 

119. Some commenters raised 

concerns that the fill-in-the-blank 

standards undermine uniformity, and 

may exacerbate differences or seams 

between the various ISO and RTO 

control areas. Several commenters 

support limited use of fill-in-the-blank 

standards, noting that they provide 

flexibility, which may facilitate 

development of a Reliability Standard in 

instances where a continent-wide 

approach may not work. 

120. NERC represents that it will 

submit an action plan and schedule in 

November 2006 for completing the fillin-the-blank standards. NERC expects 

that it will take approximately three 

years to complete the process, and will 

be prioritizing Reliability Standards that 

require the most immediate revision.96

NERC anticipates three potential 

approaches to the fill-in-the-blank 

standards: (1) If NERC determines that 

there is insufficient justification for a 

regional difference, it may replace a 

Reliability Standard with a uniform 

continent-wide Reliability Standard; (2) 

where a regional difference is justified, 

NERC proposes to direct the regions to 

develop their regional criteria as a 

Reliability Standard to be filed for 

approval with the ERO and thereafter 

with the Commission and applicable 

authorities in Canada; (3) if mandatory 

enforcement of a fill-in-the-blank 

standard is not necessary for reliability, 

NERC proposes to retire the Reliability 

Standard and allow a region to maintain 

voluntary criteria and procedures as 

needed. 

121. We share commenters’ concerns 

regarding the potential for the fill-inthe-blank standards to undermine 

uniformity. Order No. 672 stated that, 

while uniformity is the goal with 

respect to Reliability Standards, it may 

not be achievable overnight. Where 

NERC had directed the regions to 

develop a particular Reliability 

Standard, we noted that ‘‘[o]ver time, 

we would expect that the regional 

differences produced under this 

framework will decline and a set of best 

practices will develop.’’ 97 NERC’s 

review states it will take uniformity 

concerns into consideration, only 

permitting regional differences where 

justified. In Order No. 672, we specified 

two instances where regional 

differences may be permitted: regional 

differences that are more stringent than 

the continent-wide Reliability Standard, 

including those addressing matters not 


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98 Id. at P 291. Our position was reiterated in the 

ERO Certification Order where we directed NERC 

to delete additional criteria contained in its Rules 

of Procedure and Reliability Standard development 

procedures. ERO Certification Order, 116 FERC 

¶ 61,062, at P 274. 

99NERC Rule of Procedure section 312.4 states 

that regional Reliability Standards ‘‘may be 

developed through the NERC reliability standards 

development procedure, or alternatively, through a 

regional reliability standards development 

procedure that has been approved by NERC.’’ 100CenterPoint Comments at 15. 

addressed by a continent-wide 

Reliability Standard, and regional 

differences necessitated by a physical 

difference in the Bulk-Power System.98

NERC’s review must be consistent with 

these criteria. 

122. In addition, if after an 

appropriate review, NERC determines 

that regional differences are still 

warranted, we propose that any regional 

proposal to fill-in-the-blank must be 

developed in accordance with the 

NERC’s ANSI-approved process, or 

through an alternative process approved 

by the ERO,99 and must be submitted to 

the ERO and the Commission for 

approval. 

123. We propose to require 

supplemental information regarding any 

Reliability Standard that requires a 

regional reliability organization to fill in 

missing criteria or procedures. Where 

important information has not been 

provided to us to enable us to complete 

our review, we are not in a position to 

approve those Reliability Standards. 

Therefore, we propose to not approve or 

remand those Reliability Standards until 

all the necessary information has been 

provided. 

E. Discussion of Each Individual 

Reliability Standard 

124. We have reviewed each of the 

proposed Reliability Standards, and our 

analysis is by chapter according to the 

categories of Reliability Standards 

defined in NERC’s petition. Each 

chapter begins with an introduction to 

the category, followed by a discussion of 

each proposed Reliability Standard. The 

discussion includes summaries of 

NERC’s proposal, the Staff Preliminary 

Assessment, and comments received, as 

well as a Commission proposal. The 

Commission proposal for each standard 

will include a proposed disposition. For 

Reliability Standards that are proposed 

to be approved with direction that 

NERC modify the Reliability Standard, 

specific instructions are provided 

regarding areas that need to be 

modified, and how they should be 

modified. Where additional information 

is needed in order for the Commission 

to propose a disposition, the 

information required will be detailed. 

1. BAL: Resource and Demand 

Balancing 

a. Overview of Category 

125. The six Balancing (BAL) 

Reliability Standards address balancing 

resources and demand to maintain 

interconnection frequency within 

prescribed limits. 

i. General Comments 

126. LPPC comments generally that 

each Requirement contained in a 

Reliability Standard must be measurable 

to be mandatory. In this regard, LPPC 

identifies examples of Requirements in 

the BAL Standards that it claims are not 

measurable requirements but, rather, 

descriptive or explanatory statements. 

LPPC also identifies several 

Requirements in the BAL Standards that 

it claims are redundant to other 

Requirements in the BAL Standards. 

127. CenterPoint comments that 

significant regional variation ‘‘is 

necessary in matters such as amount 

and composition of spinning reserve 

and calculation of the Frequency Bias 

component of ACE due to the different 

operating characteristics of the 

regions.’’ 100 CenterPoint suggests that 

customers’ concerns are focused on 

ensuring that a Reliability Standard’s 

performance requirements are met as 

opposed to concerns about specifically 

how these requirements are met. 

CenterPoint indicates that regional 

variation in the method to comply with 

the Reliability Standard is acceptable so 

long as the Reliability Standard’s 

required level of performance is 

ultimately achieved. CenterPoint 

suggests that certain process-oriented 

Reliability Standards in this group 

should be eliminated because other BAL 

Reliability Standards already include 

metrics necessary to determine 

compliance. 

ii. Commission Response 

128. With respect to LPPC’s general 

comments, the Commission agrees that 

Reliability Standards must have clear 

and enforceable Requirements. LPPC 

correctly identifies a number of 

instances in the BAL Reliability 

Standards where a Requirement appears 

to entirely consist of, or contain, an 

explanatory statement rather than an 

actionable Requirement. While the 

Commission agrees with LPPC that 

explanatory statements should not be in 

the Requirements section of a Reliability 

Standard, the presence of an 

explanatory statement does not render 

the Reliability Standard unenforceable. 

The Commission has addressed the 

redundant Requirements identified by 

LPPC within the applicable Reliability 

Standards below. 

129. With respect to CenterPoint’s 

comment, the Commission believes 

there are certain processes, such as the 

methods for calculating frequency bias, 

which are accepted industry practices 

and should be included as uniform 

requirements in the Reliability 

Standards. The Commission proposes to 

formalize the process across the regions. 

This will protect reliability by providing 

a common basis for analysis and 

corrective actions. CenterPoint also 

comments that ‘‘some of the processoriented standards should be 

eliminated,’’ but because CenterPoint 

provided no further detail on this point, 

the Commission is unable to fully 

consider and respond to the comment. 

b. Real Power Balancing Control 

Performance (BAL–001–0) 

i. NERC Proposal 

130. The purpose of this Reliability 

Standard is to maintain Interconnection 

steady-state frequency within defined 

limits by balancing real power demand 

and supply in real-time. BAL–001–0 

establishes two requirements that are 

used to assess the proficiency of a 

balancing authority to maintain 

interconnection frequency by balancing 

real power (MW) demand, interchange, 

and supply. The proposed Reliability 

Standard would apply to balancing 

authorities. 

ii. Staff Preliminary Assessment 

131. Staff commented that 

BAL–001–0 provides a good example of 

performance metrics useful for assessing 

the performance of Balancing 

Authorities and compliance with the 

standard. 

iii. Comments 

132. ReliabilityFirst agrees with staff’s 

comments, and ISO/RTO Council 

recommends that the Commission 

accept this Reliability Standard. 

133. LPPC asserts that Requirements 

R1 and R2 are not actual Requirements 

but instead only determine whether the 

balancing authority has adequate 

regulating reserves, without specifying a 

performance metric. 

iv. Commission Proposal 

134. The Commission disagrees with 

LPPC’s comment that Requirements R1 

and R2 are not actual Requirements. To 

the contrary, Requirements R1 and R2 

state the bounds within which a 

balancing authority must control its area 


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101NERC defines ACE as ‘‘The instantaneous 

difference between a Balancing Authority’s net 

actual and scheduled interchange, taking into 

account the effects of frequency Bias and correction 

for meter error.’’

102Each regional difference approved by NERC is 

provided as a separate ‘‘waiver request’’ document 

that identifies the entity requesting a waiver, the 

Reliability Standard or Requirements that are 

waived, and explanation and a statement of NERC 

approval. See NERC Petition, Exhibit A. In addition, 

each regional difference is identified in the 

Reliability Standard to which the waiver applies. 

103At the time NERC granted this regional 

difference, the term ‘‘control area’’ was used instead 

of ‘‘balancing authority.’’ For purposes of this 

discussion, they are the same. 

104Order No. 672 at P 290. 

105 Id. at P 291. 

106 Id. 

107See ERCOT Protocols, section 5 (Dispatch) at 

21–23 (May 1, 2006), available at: http:// 

www.ercot.com/mktrules/protocols/current.html. 

108The minimum frequency response as 

calculated by ERCOT for reliable operation is 420 

MW/0.1 Hz, while the measured frequency 

response for the Eastern Interconnection is 

approximately 3,000 MW/0.1 Hz. ERCOT has a 

requirement for a minimum frequency bias that is 

almost twice that of the Eastern Interconnection 

taken on the same total load basis. 

109A ‘‘reserve sharing group’’ is a group of two 

or more balancing authorities that collectively 

maintain, allocate and supply operating reserves. 

See NERC glossary at 12. 

110Staff Preliminary Assessment at 30. 

control error (ACE).101 For example, 

Requirement R2 requires each balancing 

authority to operate such that its average 

ACE for at least 90 percent of the time 

is within a specific limit. These 

Requirements set forth an effective 

means for maintaining Interconnection 

steady-state frequency errors that are 

consistent with historic Interconnection 

frequency performance, which is the 

stated goal of BAL–001–0. These 

Requirements also have associated 

Measures and Levels of NonCompliance. 

135. BAL–001–0 provides for an 

important function necessary to 

maintain Bulk-Power System reliability. 

Further, the Commission agrees with 

NERC’s proposed applicability of this 

standard to balancing authorities. 

136. For the reasons discussed above, 

the Commission believes that Reliability 

Standard BAL–001–0 is just, reasonable, 

not unduly discriminatory or 

preferential, and in the public interest; 

and proposes to approve it as mandatory 

and enforceable. 

c. Regional Difference to BAL–001–0: 

ERCOT Control Performance Standard 2 

i. NERC Proposal 

137. NERC approved a regional 

difference for ERCOT from Requirement 

R2 in BAL–001–0, which requires that 

the average area control error or ‘‘ACE’’

for each of the six ten-minute periods 

during the hour must be within specific 

limits, and that a balancing authority 

achieve 90 percent compliance.102 This 

Requirement is referred to as Control 

Performance Standard 2 (CPS2). NERC 

explains that ERCOT requested a waiver 

of CPS2 because: (1) ERCOT, as single 

control area 103 asynchronously 

connected to the Eastern 

Interconnection, cannot create 

inadvertent flows or time errors in other 

control areas; and (2) CPS2 may not be 

feasible under ERCOT’s competitive 

balancing energy market. In support of 

this argument, ERCOT cites to a study 

which it performed showing that under 

the new market structure, the ten 

control areas in its region were able to 

meet CPS2 standards while the 

aggregate performance of the ten control 

areas was not in compliance. 

ii. Staff Preliminary Assessment 

138. This regional difference was not 

addressed in the Staff Preliminary 

Assessment. 

iii. Comments 

139. There were no comments 

regarding this regional difference. 

iv. Commission Proposal 

140. Order No. 672 explains that 

‘‘uniformity of Reliability Standards 

should be the goal and the practice, the 

rule rather than the exception.’’ 104

However, the Commission has stated 

that, as a general matter, regional 

differences are permissible if they are 

either more stringent than the continentwide Reliability Standard, or if they are 

necessitated by a physical difference in 

the Bulk-Power System.105 Regional 

differences must still be just, reasonable, 

not unduly discriminatory or 

preferential and in the public 

interest.106

141. ERCOT’s Protocols concerning 

frequency control identify that the 

existing ERCOT approach to 

Interconnection frequency control is 

necessary to assure reliability in that 

interconnection.107 However, the 

existing waiver was filed prior to the 

formation of these procedures. ERCOT 

is both a single balancing authority and 

the smallest of the three 

Interconnections, approximately one 

tenth of the size of the Eastern 

Interconnection. As such, frequency 

control is more critical to its system 

reliability.108

142. The Commission notes that the 

physical difference of ERCOT compared 

to the other two interconnections in 

terms of size is a sufficient reason for 

approving a regional difference. Also, 

ERCOT’s approach of determining the 

minimum frequency response needed 

for reliability and requiring appropriate 

generators to have specific governor 

droop appears to be a more stringent 

practice than Requirement R2 in BAL–

001–0. The calculation of the required 

frequency response will be discussed in 

BAL–002. However, neither reason is 

articulated in the proposed regional 

difference. 

143. The Commission proposes to 

approve the ERCOT regional difference. 

However, the Commission proposes to 

have the ERO submit a modification of 

the ERCOT regional difference to 

include the requirements concerning 

frequency response contained in the 

ERCOT Protocols, section 5. 

d. Disturbance Control Performance 

(BAL–002–0) 

i. NERC Proposal 

144. The reliability goal of this 

Reliability Standard is to utilize 

contingency reserves to balance 

resources and demand to return 

interconnection frequency to within 

defined limits following a reportable 

disturbance. BAL–002–0 establishes: 

(1) The generic requirements that each 

regional reliability organization should 

use to determine the amount and type 

of contingency reserves that will be 

needed to meet a metric called the 

Disturbance Control Standard (DCS); (2) 

how to calculate the DCS metric; (3) 

procedures to be used in calculating 

DCS for reserve sharing groups; (4) a 15 

minute default disturbance recovery 

period; (5) a 90 minute default 

contingency reserve restoration period; 

and (6) the requirement that balancing 

authorities have access to contingency 

reserves to respond to loss of generation, 

but not loss of load. The proposed 

Reliability Standard would apply to 

balancing authorities, reserve sharing 

groups,109 and regional reliability 

organizations. 

ii. Staff Preliminary Assessment 

145. Requirement R3.1 requires that a 

balancing authority or reserve sharing 

group carry ‘‘at least enough 

contingency reserves to cover the most 

severe single contingency.’’ Staff noted 

that the Requirement could be subject to 

multiple interpretations, one limited to 

only the loss of generation, whereas the 

other considers the loss of supply 

resulting from a transmission or 

generation contingency.110 Further staff 

noted that specific requirements related 

to the composition of reserves and the 

restoration time are left to Regions and 

sub-Regions to determine. For example, 

Requirement R2 directs each regional 

reliability organization (or sub-regional 


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111 ISO–RTO Council Comments, Attachment A 

at 3. 

112LOLE studies are probabilistic studies 

associated with determining the probability that 

there may not be sufficient generation to supply 

firm load. 

113Contingency reserves are those reserves used 

during real time operation to accommodate 

uncertainties in generation failures. In contrast, 

planning reserves have a long-term perspective. 

While BAL–002–0 has a requirement pertaining to 

contingency reserve policy, the Reliability 

Standards are silent on planning reserve. 114NERC Comments at 41. 

reliability organization or reserve 

sharing group) to specify its contingency 

reserve policies, including minimum 

reserve requirements and allocation and 

the permissible mix of reserves. Other 

provisions identified by staff as vague or 

missing include the definition as to 

which resources and demand side 

management are eligible to be counted 

as spinning reserves. Finally, staff stated 

that lower reporting thresholds for the 

size of the minimum disturbance, which 

may be required by certain regional 

reliability organizations, should be 

documented as a regional difference. 

iii. Comments 

146. NERC states that, with regard to 

contingency reserves, the BAL–002–0 

requirement that a balancing authority 

restore its resource-demand balance 

with the rest of the Interconnection 

within 15 minutes is absolute, objective 

and measurable. To meet this 

requirement, the balancing authority 

must have available sufficient reserves 

to recover from the largest single 

contingency and deploy those reserves 

within 15 minutes. It states that 

‘‘leaning on the system’’ for up to 15 

minutes is an appropriate use of the 

Interconnection. Thus, with regard to 

staff’s comments that the Reliability 

Standard does not specify minimum 

reserve requirements and that the 

appropriate mix of reserves is not 

defined, NERC questions whether it is 

appropriate to measure the desired 

outcome (as BAL–002–0 does), or how 

that outcome is achieved (as staff 

suggests). NERC suggests that the 

existing approach is more appropriate 

because the ‘‘how’’ portion is driven by 

system design, resource mix and 

economics. Further, it adds that regional 

variation is appropriate in determining 

the amount of contingency reserves 

because it is driven by the specific 

system configuration and operating 

conditions; and adding greater 

specificity to the contingency reserve 

requirements to achieve uniformity will 

not enhance reliability but will likely 

increase costs of compliance. NERC 

states that it will review the potential 

reliability benefits and costs associated 

with more specific and uniform 

contingency reserve requirements. 

147. Many commenters agree with the 

Staff Preliminary Assessment that BAL–

002–0 lacks specificity in certain areas. 

Most commenters also argue in favor of 

giving deference to regions or reserve 

sharing groups with regard to the 

requirements in Requirement R2 and 

certain other requirements of the 

standard. CPUC states that the 

corresponding WECC standards provide 

specificity in areas identified by staff 

and provide for a more stringent 

disturbance reporting threshold. It 

suggests that the Commission defer to 

and approve such regional standards 

already in place that correspond to 

NERC-proposed Reliability Standards, 

but add specificity and stringency 

without triggering a need for the 

regional reliability organization to 

provide extensive justification for a 

‘‘regional difference.’’ ISO/RTO Council 

states that ‘‘the requirements to recover 

the loss of generation and returning 

Area Control Error to a specified value 

within a specific time period as 

stipulated in the standard provide the 

needed reliability performance 

yardstick.’’ 111 It continues, stating that 

once these performance-based 

requirements are in place, the regional 

reliability organization standards can 

provide the supplementary process 

requirements. MidAmerican advocates 

that the appropriate reserve sharing 

group should specify requirements for 

contingency reserves, while CenterPoint 

states that a significant amount of 

regional variation is necessary. 

ReliabilityFirst believes that NERC 

should provide a clear definition of 

spinning reserves for Interconnections. 

148. MidAmerican suggests that there 

should be specific requirements such as 

the percentage of reserves to load, the 

permissible mix of spinning reserves 

verses non-spinning generation to meet 

operating reserves, the maximum 

allowable interruptible load, and other 

pool rules. These requirements should 

be based on composite reliability 

studies such as a Loss-of-Load 

Expectation (LOLE) 112 in the 

Interconnection. It also states that BAL–

002–0 should contain a planning reserve 

requirement 113 based on LOLE. 

MidAmerican suggests that BAL–002–0 

should allow for differing regional 

reserve requirements due to differing 

generation mixes in each region. 

149. ReliabilityFirst agrees with staff’s 

assessment. It comments that the loss of 

supply is another contingency and 

suggests that the Reliability Standard 

should further define the criteria for 

contingencies and state the requirement 

for all types of contingencies to be 

assessed during recovery from a 

disturbance. ReliabilityFirst also agrees 

that lower thresholds should be defined 

as regional differences but any 

difference should be demonstrated as 

technically defensible and warranted. 

ReliabilityFirst agrees with the Staff 

Preliminary Assessment that the 

procedures developed by the individual 

regions to determine contingency 

reserves need to be merged to develop 

consistency. 

150. LPPC points out several 

Requirements it considers problematic. 

It states that Requirement R4.1 is not a 

requirement but rather a definition of 

some of the criteria for disturbance 

recovery. It further states that the 

statement in Requirement R4.1, is only 

true if the balancing authority is not 

utilizing a reserve sharing group to 

respond to the event, and the definition 

should be expanded to include reserve 

sharing groups. LPPC suggests that there 

is some redundancy between 

Requirements R4 and R5 and that they 

could be combined. Specifically, LPPC 

suggests that the first sentence of each 

Requirement is essentially stating the 

same thing. It also states the reference 

to the NERC Operating Committee 

should be removed from Requirements 

R4.2 and R6.2. 

iv. Commission Proposal 

151. The Commission proposes to 

approve BAL–002–0 as mandatory and 

enforceable. In addition, we propose to 

direct that NERC develop modifications 

to the Reliability Standard as discussed 

below. 

152. The issues identified by the 

commenters and staff can be grouped 

into three categories: (1) The 

measurement of the performance of the 

contingency reserves through 

Disturbance Control Standard; (2) the 

determination of the amount and 

makeup of contingency reserves; and (3) 

what contingencies are appropriate to 

consider. 

(a) Disturbance Control Standard 

153. NERC contends that this 

standard is ‘‘absolute, objective, and 

measurable’’ in that it allows up to 15 

minutes for the recovery from a 

disturbance.114 The Commission agrees 

with allowing up to 15 minutes for 

recovery from a disturbance. To achieve 

NERC’s measurement approach, we 

propose that NERC modify Requirement 

R3.1, which currently requires that a 

balancing authority carry at least 

enough contingency reserve to cover 

‘‘the most severe single contingency,’’ to 

include enough contingency reserve to 

cover any event or single contingency, 


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115Although Frequency Response and Bias are 

discussed at length in Reliability Standard BAL–

003–0, the Commission notes here that it is 

important that contingency reserves should have 

adequate frequency response to ensure recovery 

immediately following an event. 

116See WECC Frequency Response Standard 

White Paper (2005), available at http:// 

www.wecc.biz/documents/library/RITF/ 

FRR_White_Paper_v12_1–27–06.pdf; ERCOT Energy 

Market Technical Paper 1C, Defining, Measuring 

and Valuing Frequency Response (January 2004). 

117See also Assessment of Demand Response and 

Advanced Metering: Staff Report (Aug. 2006) 

(Demand Response Report), available at http:// 

www.ferc.gov/legal/ staff-reports/demandresponse.pdf. 

118LPPC raises the same concern regarding 

references to the NERC Operating Committee in 

other Reliability Standards. We agree that the term 

should be removed and replaced with the term ERO 

in all such places. 

119This could be accomplished by modifying 

Requirement R2 or developing a new Reliability 

Standard. 

120The proposal to require that the ERO be 

identified as the compliance monitor (which may 

then choose to delegate compliance monitor 

responsibility to a Regional Entity) applies to each 

Reliability Standard that currently identifies the 

regional reliability organization as the compliance 

monitor. However, we will not repeat this proposal 

throughout the NOPR. 

121Frequency bias setting is a value expressed in 

MW/0.1 Hz, set into a balancing authority ACE 

algorithm that allows the balancing authority to 

including a transmission outage, which 

results in a significant deviation in 

frequency from the loss or mismatch of 

supply either from local generation or 

imports.115 We believe that this 

approach would address staff’s concern 

with Requirement R3.1 while giving due 

weight to the ERO’s position. Further, 

NERC should consider whether a 

frequency deviation of 20 milli Hertz 

lasting longer than the 15 minute 

recovery period should be used to 

define a significant deviation in 

frequency. The Commission is aware 

that this approach is consistent with the 

Balancing Authority ACE Limit (BAAL) 

presently being field tested. The major 

difference between the proposal and the 

BAAL is that the proposal is aimed at 

preserving the historic frequency 

performance of the system. 

154. The Commission agrees with 

ReliabilityFirst that lower reporting 

thresholds for the size of the minimum 

disturbance should be defined as a 

regional difference. However, the above 

approach eliminates that concern 

because any event or single contingency 

that causes a frequency deviation above 

the defined threshold would be 

included in the DCS calculation. 

(b) Determination of Amount and 

Makeup of Contingency Reserves 

155. The Commission notes that 

Requirement R2 of BAL–002–0 is a ‘‘fillin-the-blank’’ requirement, as it directs 

each regional reliability organization (or 

sub-regional reliability organization or 

reserve sharing group) to specify its 

contingency reserve policies, including 

minimum reserve requirements and 

allocation and the permissible mix of 

reserves. NERC and many other 

commenters state that the regional 

determination of contingency reserves is 

appropriate. 

156. While the Commission believes it 

is appropriate for balancing authorities 

to have different amounts of 

contingency reserves, these amounts 

should be based on one uniform 

continent-wide contingency reserves 

policy. The policy should be based on 

the reliability risk of not meeting load 

associated with a particular balancing 

authority’s generation mix and topology. 

The appropriate mix of operating 

reserves, spinning reserves and nonspinning reserves should be addressed 

on a consistent basis. As identified by 

the ERCOT and WECC whitepapers,116

due consideration should be given to 

the amount of frequency response from 

generation or load needed to assure 

reliability. We propose that this policy 

be neutral as to the source of the 

contingency reserves in terms of 

ownership or technology. Accordingly, 

the Commission proposes to require 

NERC to develop a continent-wide 

contingency reserve policy. 

157. As identified in the Staff 

Preliminary Assessment, the types of 

resources that can be used for 

contingency reserves should be 

consistent across the country and not 

have some regions allow the curtailment 

of irrigation pumps (one form of DSM) 

to be used as part of contingency 

reserves while other regions do not.117

Demand Side Management or Direct 

Control Load Management should be on 

the same basis as conventional 

generation or any other technology. 

Accordingly, the Commission proposes 

to direct NERC to modify BAL–002–0 to 

include a Requirement that explicitly 

allows demand side management as a 

resource for contingency reserves. 

158. With regard to MidAmerican’s 

suggestion that the BAL–002–0 

Reliability Standard should contain a 

planning reserve requirement based on 

LOLE, the Commission disagrees noting 

that BAL–002–0 deals with operating 

reserves and not planning reserves. 

(c) Contingencies 

159. Staff’s concern regarding 

transmission contingencies is resolved 

by the above approach in measuring 

response for frequency deviation. 

160. With regard to LPPC’s concerns, 

the Commission disagrees with its 

suggestion that the applicability of 

Requirement R4.1 should be extended to 

reserve sharing groups, noting that 

reserve sharing groups typically do not 

calculate a combined ACE. With regard 

to LPPC’s comment regarding the 

redundancy of R4 and R5 and the 

suggestion that these requirements be 

combined, we leave that to the 

discretion of the ERO. 

161. We agree with LPPC’s suggestion 

to modify Requirements R4.2 and 6.2 of 

BAL–002 to replace references to the 

NERC Operating Committee with the 

ERO.118

162. While the Commission has 

identified concerns with regard to BAL–

002–0, we believe that the proposal 

serves an important purpose in ensuring 

a balancing authority is able to utilize 

its contingency reserves to balance 

resources and demand and return 

interconnection frequency within 

defined limits following a reportable 

disturbance. Further, the proposed 

Requirements set forth in BAL–002–0 

are sufficiently clear and objective to 

provide guidance for compliance. 

163. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard 

BAL–002–0 as mandatory and 

enforceable. In addition, pursuant to 

section 215(d)(5) of the FPA and 

§ 39.5(f) of our regulations, the 

Commission proposes to direct that 

NERC submit, a modification to BAL–

002–0 that: (1) Includes a Requirement 

that explicitly allows demand side 

management as a resource for 

contingency reserves; (2) develop a 

continent-wide contingency reserve 

policy; 119 (3) includes a Requirement 

that measures response for any event or 

contingency that causes a frequency 

deviation; (4) substitutes ERO for 

regional reliability organization as the 

compliance monitor; 120 and (5) change 

references to the NERC Operating 

Committee in Requirements R4.2 and 

R6.2 to ERO. 

e. Frequency Response and Bias 

(BAL–003–0) 

i. NERC Proposal 

164. The purpose of BAL–003–0 is to 

ensure that a balancing authority’s 

frequency bias setting 121 is accurately 


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contribute its frequency response to the 

Interconnection. See NERC glossary at 5. 

122The actual frequency response is the increase 

in output from generators after loss of a generator 

and determines the frequency at which generation 

and load come in balance again. 

123Staff Preliminary Assessment at 28–30. 

124For example, certain generating units such as 

combined cycle units are not capable of increasing 

their output to restore the frequency back to 60 Hz 

and, in fact, their frequency responses tend to be 

opposite of what is required and thus aggravate a 

situation even further. 

125According to NERC’s Frequency Response 

White Paper (dated April 6, 2004), the frequency 

response in the Eastern Interconnection has 

declined at a rate of 70 MW/0.1 Hz annually. 

126Staff Preliminary Assessment at 28. 

calculated to match its actual frequency 

response.122 Among other things, BAL–

003–0 establishes: (1) A Requirement for 

balancing authorities to review their 

frequency bias calculation on an annual 

basis to reflect any changes in their 

frequency response and to update the 

frequency bias to reflect changes to any 

factors used in the calculation, and to 

report frequency bias setting and 

methodology used to the NERC 

Operating Committee; (2) general 

Requirements on how balancing 

authorities should calculate frequency 

bias, including which factors or 

parameters to include in the calculation; 

(3) a Requirement which establishes a 

default frequency bias setting of 1 

percent of yearly peak demand per 0.1 

Hz for balancing authorities that serve 

native load; and (4) for balancing 

authorities that do not serve native load, 

a Requirement which establishes a 

default frequency bias setting of 1 

percent of its estimated maximum 

generation level in the coming year per 

0.1 Hz. The proposed Reliability 

Standard would apply to balancing 

authorities. 

ii. Staff Preliminary Assessment 

165. Staff raised the concern that use 

of a frequency bias setting that is 

different from the natural frequency 

response of the balancing authority’s 

area could result in less control actions 

than are appropriate to preserve system 

reliability.123 In addition, staff noted 

that several metrics, such as ACE, CPS1, 

and CPS2, use frequency bias setting as 

an input and the use of an incorrect 

value of frequency bias setting would 

result in incorrect measurement of 

actual performance with respect to ACE, 

CPS1, and CPS2. 

166. Staff noted that BAL–003–0 does 

not specify the actual minimum 

frequency response needed for reliable 

operation and how the frequency 

response should vary with the types of 

generation used to ensure that all types 

of generators are contributing their share 

of frequency response to assure the 

reliability of the Bulk-Power System.124

Further, staff expressed concern that 

data from actual events show that the 

natural frequency response for Eastern 

and Western Interconnections have been 

declining every year for the past 

decade.125 NERC’s Frequency Response 

White Paper discusses these issues in 

detail. 

167. Staff noted that BAL–003–0 does 

not include Levels of Non-Compliance 

and has only one Measure. Staff pointed 

out limitations in the single Measure 

contained in BAL–003–0, which 

requires balancing authorities to 

conduct frequency response surveys 

only when NERC specifically requests 

that such surveys be performed. 

iii. Comments 

168. NERC states that it is important 

to distinguish between frequency bias 

and frequency response. With regard to 

the use of a frequency bias setting that 

is different from actual frequency 

response, NERC states that BAL–003–0 

allows a balancing authority to set its 

frequency bias setting to match its 

actual frequency response. For some 

balancing authorities that are unable to 

calculate their frequency response 

dynamically, BAL–003–0 establishes a 

minimum of 1 percent of the balancing 

authority’s peak demand to ensure 

sufficient frequency response from its 

generators. Southern states that the sum 

of frequency bias setting for all of the 

balancing authorities in the Eastern 

Interconnection is 6,700 MW/0.1 Hz, 

whereas the actual frequency response 

is 2,800 MW/0.1 Hz. In sum, it claims 

that the Eastern Interconnection is overbiased by a factor of 2.4 and the matter 

of frequency bias setting should not be 

taken lightly. 

169. ReliabilityFirst agrees with staff 

that use of an inappropriate frequency 

bias setting may have an adverse impact 

on reliability and adds that this should 

be addressed by a team of experts. 

ReliabilityFirst also states that the 

Reliability Standard should include 

Levels of Non-Compliance. It states that, 

although the referenced surveys are 

intended to monitor deviations in 

frequency response, the survey should 

be used more regularly. In addition, 

ReliabilityFirst and CenterPoint state 

that it is appropriate to allow balancing 

authorities to continue to define their 

own methodology for calculating 

frequency bias setting. 

170. Southern expresses concern 

regarding staff’s statement that ‘‘the 

frequency response of both the Eastern 

and Western Interconnections has 

decreased over the last 10 years’’ 126 and 

asserts that the Eastern Interconnection 

frequency bias setting is actually overbiased. In particular, Southern states 

that the NERC Operating Committee 

purposely chose to over-bias the 

frequency bias setting of the 

interconnections when it established the 

1 percent floor and that the Eastern 

Interconnection frequency bias setting is 

currently over-biased by a factor of 2.4. 

Southern believes that some 

clarification and industry feedback may 

be useful in considering issues and 

concerns raised by staff with regard to 

frequency bias and the way it is used to 

maintain reliability. 

iv. Commission Proposal 

171. The Commission proposes to 

approve BAL–003–0 as mandatory and 

enforceable. In addition, we propose to 

direct that NERC develop modifications 

to the Reliability Standard as discussed 

below. 

172. NERC claims that BAL–003–0 

allows a balancing authority to set its 

frequency bias setting to match its 

actual frequency response. Similarly, 

NERC’s Petition describes the reliability 

goal of BAL–003–0 is to: ‘‘maintain 

interconnection frequency by * * * 

ensuring that the balancing authority’s 

frequency bias setting is appropriately 

matched to its actual frequency 

response (governor plus load 

response).’’ However, Southern asserts 

that the Eastern Interconnection is overbiased. The Commission agrees that the 

frequency bias setting at peak, as 

compared to the actual frequency 

response of the system, is larger. The 

Commission is concerned that overbiasing is an approach to compensate 

for the low or no actual frequency 

response from some balancing 

authorities. In addition, Southern’s 

assertion that the system is over-biased 

is inconsistent with NERC’s stated 

reliability goal and highlights staff’s 

concern that data from actual events 

suggest an overall decline in the actual 

frequency response in the Eastern and 

Western Interconnection. 

173. In response to ReliabilityFirst 

and CenterPoint, the Commission notes 

that the Requirement R2 of BAL–003–0 

allows balancing authorities to choose a 

methodology for calculating frequency 

bias setting from at least two different 

ways. In addition, Requirement R2 

requires that each balancing authority 

shall establish its frequency bias setting 

that is as close as practical to, or greater 

than, its actual frequency response. 

174. In addition, the Commission 

notes that BAL–003–0 addresses 

frequency response only during normal 

conditions and does not establish the 

frequency bias setting that will be 

required during an emergency, black 


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127See WECC’s Frequency Response Standard 

White Paper (2005), at http://www.wecc.biz/ 

documents /library/RITF /FRR_White_Paper_ 

v12_1–27–06.pdf 

128The NERC glossary defines ‘‘time error 

correction’’ as ‘‘an offset to the Interconnection’s 

scheduled frequency to return the Interconnection 

Time Error to a predetermined value.’’ NERC 

glossary at 14. Time error is caused by the 

accumulation of frequency error over a given 

period. 

129NERC, Time Error Reports, at http:// 

www.nerc.com/~filez/∼timerror.html. Yearly data 

for total efficiency was 117 percent for 1996 and 65 

percent for 2005. If there is more participation than 

needed, the efficiency can be greater than 100 

percent. The goal is to be near 100 percent. 

130See http://www.wecc.biz/documents/library/ 

procedures/Time_Error_ Procedure_10–04–02.pdf. 

131See http://www.nerc.com/~filez/∼inadv.html 

(regarding inadvertent interchange data) and 

http://www.nerc.com/~filez/∼timerror.html 

(regarding time error correction). 

start or system restoration using 

‘‘islanding’’ schemes. Without proper 

frequency response, restoration of an 

isolated area using black start generation 

will be very difficult. Moreover, 

‘‘islanding’’ schemes used in some areas 

of the country may not be stable without 

proper frequency response. The 

Commission is aware that WECC is 

addressing the need for proper 

frequency response during all operating 

conditions, including emergencies, and 

that ERCOT has a procedure in place.127

175. Therefore, the Commission 

invites comments whether BAL–003–0 

appropriately addresses frequency bias 

setting during normal as well as 

emergency conditions and should a 

requirement be added for balancing 

authorities to calculate the frequency 

response necessary for reliability in 

each of the interconnections and 

identify a method of obtaining that 

frequency response from a combination 

of generation and load resources. 

176. Further, the surveys mentioned 

in Measure M1 are only conducted 

when NERC requests such surveys. The 

Commission proposes that yearly 

surveys should be performed to 

compare the calculated frequency bias 

values against actual frequency response 

to refine the balancing authorities’

frequency bias setting. While the 

Commission has identified concerns 

with regard to BAL–003–0, we believe 

that the Reliability Standard serves an 

important purpose in ensuring that 

balancing authorities accurately 

calculate their frequency bias setting to 

match their frequency response. While 

we have proposed a number of 

improvements to the Reliability 

Standard, we nonetheless, believe that 

the proposed Requirements set forth in 

BAL–003–0 are sufficiently clear and 

objective to provide guidance for 

compliance. 

177. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard BAL–003–

0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to BAL–003–0 that (1) includes Levels 

of Non-Compliance and (2) modifies 

Measure M1 to include yearly surveys. 

f. Time Error Correction (BAL–004–0) 

i. NERC Proposal 

178. The purpose of BAL–004–0 is to 

ensure that time error corrections are 

conducted in a manner that does not 

adversely affect the reliability of the 

Interconnection.128 The Reliability 

Standard requires that: (1) Only a 

reliability coordinator is eligible to serve 

as time monitor and that the NERC 

Operating Committee shall designate a 

single reliability coordinator in each 

Interconnection to serve as time monitor 

for that Interconnection; (2) the time 

monitor shall monitor time error and 

initiate and terminate all corrective 

action orders in accordance with the 

North American Energy Standards 

Board (NAESB) Time Error Correction 

Procedure; (3) each balancing authority 

shall participate in time error 

corrections; and (4) any reliability 

coordinator in an Interconnection may 

request the time monitor to terminate a 

time error correction for reliability 

reasons, and that balancing authorities 

may request termination of a time error 

correction through their respective 

reliability coordinator for reliability 

reasons. The proposed Reliability 

Standard would apply to reliability 

coordinators and balancing authorities. 

ii. Staff Preliminary Assessment 

179. Staff noted that this Reliability 

Standard does not contain any Measures 

or Levels of Non-Compliance. Staff 

highlighted the importance of 

developing Measures to assure that each 

balancing authority and reliability 

coordinator participates in achieving 

time error corrections since an analysis 

of time error correction data available 

on the ERO’s Web site indicates that 

participation may be lacking. 

iii. Comments 

180. ReliabilityFirst agrees with staff 

that BAL–004–0 lacks Measures and 

Levels of Non-Compliance. 

iv. Commission Proposal 

181. Although Requirement R3 

requires that all balancing authorities 

participate in time error corrections, 

data from the NERC time error Web page 

indicates that the efficiency of the time 

error correction has significantly 

decreased over the last 10 years.129 This 

decrease in efficiency is an indication 

that not all of the balancing authorities 

are fully participating in time error 

corrections. The Commission expects 

the ERO will ensure compliance with 

this Requirement. 

182. In addition, the Commission 

notes that WECC has implemented an 

automatic time error correction 

procedure 130 that, according to data on 

the NERC Web site, is more effective in 

minimizing both time error corrections 

and inadvertent interchange.131

Although the WECC time error 

correction procedure is not before us for 

consideration, since the WECC 

procedure appears more effective, the 

Commission seeks comment whether it 

should require that NERC adopt 

Requirements similar to those in the 

WECC automatic time error correction 

procedure. 

183. While the Commission has 

identified concerns with regard to BAL–

004–0, we believe that the Reliability 

Standard serves an important purpose 

in ensuring that time error corrections 

are conducted in a manner that does not 

adversely affect the reliability of the 

Interconnection. NERC should include 

Levels of Non-Compliance and 

additional Measures. Nonetheless, the 

proposed Requirements set forth in 

BAL–004–0 are sufficiently clear and 

objective to provide guidance for 

compliance. 

184. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard BAL–004–

0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to BAL–004–0 that includes Levels of 

Non-Compliance and additional 

Measures. Further, as discussed above, 

the Commission seeks comment 

whether it should require that NERC 

adopt Requirements similar to those in 


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132Staff Preliminary Assessment at 32. 

133NERC Resources Subcommittee (Frequency 

Task Force), Frequency Response Standard 

Whitepaper (2004), at http://www.nerc.com/pub/ 

sys/all_updl/oc/rs/ 

Frequency_Response_White_Paper.pdf. See also 

WECC Reserve Issues Task Force, Frequency 

Response Standard White Paper (2005), at http:// 

www.wecc.biz/documents/library/RITF/ 

FRR_White_Paper_v12_1–27–06.pdf. 

134See PJM RTO White Paper, Frequency 

Excursions, by Koza, Williams and Herbsleb. 

the WECC automatic time error 

correction standard. 

g. Automatic Generation Control (BAL–

005–0) 

i. NERC Proposal 

185. The reliability goal of this 

Reliability Standard is to maintain 

Interconnection frequency by requiring 

that all generation, transmission, and 

customer load be within the metered 

boundaries of a balancing authority 

area, and establishing the functional 

requirements for the balancing 

authority’s regulation service, including 

its calculation of ACE. BAL–005–0 

requires that: (1) All generation, 

transmission, and load operating within 

an Interconnection must be included 

within the metered boundaries of a 

balancing authority area; (2) each 

balancing authority shall maintain 

regulating reserve to meet the control 

performance standard; and (3) adequate 

metering, communication and control 

equipment are employed in the 

provision of regulation service. In 

addition, the Reliability Standard 

includes a series of requirements 

pertaining to the operation of automatic 

generation control and a series of 

requirements pertaining to the 

calculation of ACE. The proposed 

Reliability Standard would apply to 

balancing authorities, generator 

operators, transmission operators, and 

load serving entities. 

ii. Staff Preliminary Assessment 

186. Staff stated that this Reliability 

Standard does not require a generation 

operator or load-serving entity to 

provide automatic generation control 

capabilities to its balancing authority. 

Nor does it require the calculation of the 

amount of automatic generation control 

the generation operators or load-serving 

entities must have at all times. Without 

these requirements, it is not possible to 

determine whether there are adequate 

resources to maintain system frequency 

close to 60 Hz. Staff also noted that this 

Reliability Standard does not contain 

Measures or Levels of Non-Compliance. 

iii. Comments 

187. ReliabilityFirst agrees with Staff 

that Measures and Levels of NonCompliance need to be added to this 

Reliability Standard. 

188. CPUC expresses concern 

regarding a statement in the Staff 

Preliminary Assessment that BAL–005–

0 does not require generator operators or 

load-serving entities to provide 

automatic generation control 

capabilities to the balancing 

authority.132 It suggests that, in lieu of 

requiring generators to provide 

automatic generation control units, 

balancing authorities should have a 

specified percentage of their load 

subject to automatic generation control. 

CPUC also states that the characteristics 

of the load in the area and the amount 

of generation that is responsive to 

changes in voltage and frequency 

should also be considered. 

189. LPPC states that Requirement 

R17, which provides that each balancing 

authority must periodically calibrate its 

time error and frequency devices, 

should be moved to a ‘‘facility’’ (FAC) 

Reliability Standard and should also 

apply to the transmission operations 

and reliability coordinators. LPPC states 

that balancing authorities do not have 

time error devices and the reliability 

coordinator is responsible for 

monitoring time error. It also states that 

the requirement to calibrate time error 

devices should be deleted. 

iv. Commission Proposal 

190. The Commission proposes to 

approve Reliability Standard BAL–005–

0 as mandatory and enforceable. In 

addition, we propose to direct that 

NERC modify the Reliability Standard to 

address the Commission’s concerns 

discussed below. 

191. Currently, the title of the 

Reliability Standard implies that only 

generators can participate in regulation 

control portion of contingency reserves. 

The title should be changed from 

Automatic Generation Control to clearly 

indicate that it includes the systems 

necessary to implement Demand Side 

Management and Direct Control Load 

Management as part of contingency 

reserves and not just conventional 

generation. 

192. The stated goal of this Reliability 

Standard is to assure that all generation 

and load is under the control of a 

balancing authority. Ideally, the 

balancing authority would have control 

over adequate amounts and types of 

generation reserves and controllable 

load management resources under all 

operating conditions and at all times.133

The Commission notes that 

Requirement R2 of BAL–005–0 requires 

a balancing authority to obtain sufficient 

regulating reserves controlled by 

automatic generation control to meet the 

CPS requirements of BAL–001–0. 

However, the balancing authority may 

not itself have generation or control over 

loads that are the sources of regulating 

reserves. In contrast, a generation 

operator or load-serving entity typically 

has (or could have) the facilities to 

provide automatic generation control 

capabilities to the balancing authority. 

Recognizing that insufficient automatic 

generation control would constitute a 

violation of this Reliability Standard, 

the Commission is interested in 

understanding if any balancing 

authority is experiencing or is 

predicting any difficulty in obtaining 

sufficient automatic generation control. 

193. With regard to CPUC’s concern, 

the Commission does not propose a 

requirement that all generators provide 

automatic generation control 

capabilities. The Commission 

recognizes that, due to unit 

characteristics or operating restrictions, 

certain types of resources may not be 

capable of operation with automatic 

generation control, or automatic 

generation control may not be 

economically feasible. With regard to 

CPUC’s suggestion that the Reliability 

Standard require a balancing authority 

to have a certain percentage of its load 

subject to automatic generation control, 

the Commission notes that this may be 

one method of determining the amount 

of regulating reserve necessary to meet 

Requirement R2. 

194. The Commission notes that there 

are frequency excursions without loss of 

generation on a regular basis. Also, 

significant frequency excursions, 

without loss of generation are becoming 

more frequent.134 The Commission 

proposes that BAL–005–0 include a 

Requirement that addresses the amount 

of automatic generation control a 

balancing authority must have, prior to 

a contingency, to ensure that load 

variations and changes in schedules can 

be accommodated without frequency 

deviations beyond an appropriate 

threshold. 

195. Requirement R17 requires 

balancing authorities to calibrate time 

error and frequency devices annually 

according to the accuracy levels detailed 

in the Reliability Standard. The 

Commission disagrees with LPPC that 

the reference to the calibration of time 

error devices should be removed from 

Requirement R17 of this Reliability 

Standard. The Commission prefers that 

Requirements intended to achieve a 

specific reliability goal be in the same 

Reliability Standard or group of 

Reliability Standards. Since the BAL 


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135On August 28, 2006, NERC submitted BAL–

006–1 for approval, which replaces BAL–006–0. 

BAL–006–1 is the same as BAL–006–0 except that 

it includes a regional difference for SPP under an 

urgent action procedure. The comments submitted 

in response to the Staff Preliminary Assessment on 

BAL–006–0 apply equally to BAL–006–1. 136See Staff Preliminary Assessment at 32 n.63. 

group of Reliability Standards contains 

reliability goals concerning frequency, 

the Commission believes that 

Requirement R17 is appropriately 

placed in BAL–005–0. 

196. While we have identified 

concerns with regard to BAL–005–0, we 

believe that the proposal serves an 

important purpose in ensuring that the 

functional requirements of a balancing 

authority’s regulation service are met. 

The Commission believes it is important 

that NERC include Measures, including 

a Measure that would provide for 

verification of minimum automatic 

generation control or regulating 

reserves, and Levels of NonCompliance. Nonetheless, the proposed 

Requirements set forth in BAL–005–0 

are sufficiently clear and objective to 

provide guidance for compliance. 

197. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard BAL–005–

0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to BAL–005–0 that: (1) Includes 

Requirements that identify the 

minimum amount of automatic 

generation control or regulating reserves 

a balancing authority must have at any 

given time; (2) changes the title of the 

Reliability Standard to be neutral as to 

source of the reserves; (3) includes DSM 

and Direct Control Load Management as 

part of contingency reserves; and (4) 

includes Levels of Non-Compliance and 

Measures, including a Measure that 

provides for a verification process over 

the minimum required automatic 

generation control or regulating reserves 

a balancing authority maintains. 

h. Inadvertent Interchange (BAL–006–1) 

i. NERC Proposal 

198. BAL–006–1135 requires that: (1) 

Each balancing authority calculate and 

record inadvertent interchange on an 

hourly basis; (2) all AC tie lines with 

adjacent balancing authority areas be 

included in a balancing authority’s 

inadvertent account, and the balancing 

authority take into account interchange 

from jointly-owned generation; (3) all 

Interconnection points be equipped 

with common megawatt-hour meters 

with readings provided to adjacent 

balancing authorities; (4) adjacent 

balancing authorities compute and 

record inadvertent interchange on an 

hourly basis using common net 

scheduled interchange and net actual 

interchange values, and use the agreedto data to compile their monthly 

accumulated inadvertent interchange; 

and (5) balancing authorities make after 

the fact corrections to the agreed-to 

inadvertent amount as needed to reflect 

actual operating conditions. The 

proposed Reliability Standard would 

apply to balancing authorities. 

199. This Reliability Standard does 

not contain Measures but does contain 

a compliance monitoring process which 

requires a balancing authority to submit 

monthly inadvertent interchange reports 

to its regional reliability organization. 

The regional reliability organization is 

then required to submit a monthly 

inadvertent interchange summary for its 

region to NERC. This Reliability 

Standard contains one Level of NonCompliance which states that if a 

balancing authority does not timely 

submit its inadvertent interchange 

report to the regional reliability 

organization, it shall be considered noncompliant. 

ii. Staff Preliminary Assessment 

200. Staff found that this Reliability 

Standard does not contain any 

Requirement that would prevent a 

balancing authority from excessively 

depending on other balancing 

authorities over time. This makes it 

possible for balancing areas to lean on 

other balancing areas and not settle their 

inadvertent accounts on a timely basis. 

Data available from the NERC Web site 

indicates that the magnitudes of 

inadvertent interchange for some 

regional reliability organizations in the 

Eastern Interconnection are 

increasing.136

201. Staff also noted that this standard 

does not contain Measures and contains 

a single Level of Non-Compliance which 

is only associated with a Requirement 

for submission of a monthly report on 

inadvertent interchange. 

iii. Comments 

202. NERC contends that inadvertent 

imbalances do not affect the real-time 

operations of the Bulk-Power System. 

Rather, they represent accumulation of 

the real-time imbalances over hours, 

days and weeks. A separate NAESB 

standard, referred to as ‘‘Inadvertent 

Interchange Payback Standard—WEQ–

007’’ deals with how balancing 

authorities should eliminate their 

inadvertent interchanges. According to 

NERC, real-time imbalances between the 

generation and load are appropriately 

dealt with in BAL–001–0 and BAL–002–

0. 

203. TAPS argues that the treatment 

afforded to balancing authorities under 

NERC’s proposed Reliability Standards 

and NAESB rules is not comparable to 

the treatment afforded to non-controlarea utilities under the Commission’s 

OATT. In particular, TAPS states that, 

under the NERC standards, no penalties 

are assessed on a balancing authority for 

inadvertent interchange whereas under 

the OATT, penalties are assessed on 

non-control-area utilities for energy 

imbalances. TAPS is concerned that the 

OATT Reform NOPR does not 

adequately address the disparate 

treatment of imbalances. 

204. ReliabilityFirst agrees with staff 

that requirements should be added to 

prevent balancing authorities from 

depending excessively on other 

balancing authorities. 

205. LPPC states that Requirement R2 

of BAL–006–0, which provides that 

each balancing authority shall include 

all AC tie lines that connect to its 

adjacent balancing authority areas in its 

inadvertent interchange account, should 

apply to ‘‘physical’’ adjacent balancing 

authorities. It explains that the NERC 

glossary explains that an ‘‘adjacent 

balancing authority’’ is interconnected 

to another balancing authority either 

directly or via a multi-party agreement 

or transmission tariff. Thus, according 

to LPPC, the meaning of this 

Requirement changed when the word 

‘‘physical’’ was removed during the 

conversion to the Version 0 standards. 

LPPC also contends that Requirements 

R4.1, R4.1.1, R4.1.2, R4.2, R4.3, and R5 

are after-the-fact energy accounting 

practices and should be incorporated 

into the NAESB business practices. 

LPPC also suggests that Requirement R3 

of BAL–006 is redundant with 

Requirement R12.1 in BAL–005–0. 

iv. Commission Proposal 

206. The Commission proposes to 

approve Reliability Standard BAL–006–

1 as mandatory and enforceable. In 

addition, we propose to direct that 

NERC modify the Reliability Standard to 

address the Commission’s concerns 

discussed below. 

207. The Commission agrees with 

NERC that inadvertent imbalances do 

not affect the real-time operations of the 

Bulk-Power System. While large 

inadvertent imbalances pose no 

immediate threat to grid reliability, they 


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137BAL–006–1, filed on August 28, 2006, would 

extend the regional difference to SPP. 

represent dependence by some 

balancing authorities on their neighbors. 

The Commission notes that WECC has 

placed a limit on the inadvertent 

accumulation based on the bias of the 

balancing authority. We invite 

comments as to whether accumulation 

of large amount of inadvertent 

imbalances is a concern to the industry 

and if so, options to address the 

accumulation. 

208. With respect to TAPS concerns 

regarding disparate treatment of 

imbalances for non-control area utilities, 

the Commission is addressing this issue 

in the OATT Reform NOPR, and TAPS 

should pursue its concerns in that 

proceeding. Moreover, the issues raised 

by TAPS do not impact reliability of the 

Bulk-Power System, but instead are 

economic in nature. 

209. We disagree with LPPC’s 

comment that Requirement R2 should 

be applicable only to ‘‘physical’’

adjacent balancing authorities because it 

is reasonable to include those balancing 

authorities that are not physically 

adjacent but are connected by a multiparty agreement or transmission tariff. 

210. With regard to LPPC’s comment 

that several of the Requirements should 

be incorporated into NAESB business 

practices, the Commission notes that 

there is currently an industry process in 

place between NERC and NAESB to 

determine which standards or portions 

of standards should be developed as 

business practices. The Commission 

prefers to use that process to resolve 

issues with the particular Requirements 

highlighted by LPPC. With respect to 

LPPC’s comment that Requirement R3 of 

BAL–006–0 is redundant with 

Requirement R12.1 in BAL–005–0, the 

Commission observes that the two 

Requirements, although worded 

somewhat differently, are very similar. 

We propose to require NERC to review 

these Requirements and remove any 

unnecessary duplication. 

211. As mentioned above, the 

Reliability Standard includes a single 

Level of Non-Compliance that is 

triggered if a balancing authority fails to 

report its inadvertent interchange on 

time. There are no specific Measures 

concerning the accumulation of large 

inadvertent imbalances. Nor are there 

Measures and Levels of NonCompliance associated with each of the 

Requirements. While the Commission 

has identified concerns with regard to 

BAL–006–1, we believe that the 

proposal serves an important purpose in 

defining a process to ensure that 

balancing areas do not excessively 

depend on other balancing areas in the 

Interconnection for meeting their 

demand or interchange obligations. The 

Commission believes that it is important 

for NERC to provide Measures and 

additional Levels of Non-Compliance. 

Nonetheless, the proposed 

Requirements set forth in BAL–006–1 

are sufficiently clear and objective to 

provide guidance for compliance. 

212. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard BAL–006–

1 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to BAL–006–1 that adds Measures and 

additional Levels of Non-Compliance 

including Measures concerning the 

accumulation of large inadvertent 

imbalances. 

i. Regional Differences to BAL–006–1: 

Inadvertent Interchange Accounting and 

Financial Inadvertent Settlement 

i. NERC Petition 

213. BAL–006–1 provides for two 

regional differences. First, NERC 

explains that a regional difference is 

needed for an RTO with multiple 

balancing authorities. The control area 

participants of MISO requested that 

MISO be given an Inadvertent 

Interchange account so that financial 

settlement of all energy receipts and 

deliveries using LMP could be 

implemented to meet their Commission 

directed market obligations. 

Subsequently, Southwest Power Pool 

(SPP) requested, and NERC approved, 

that the same regional difference apply 

to SPP as well.137

214. Second, a regional difference 

would apply to the control area 

participants of MISO and SPP that 

would allow the RTO to financially 

settle inadvertent energy between 

control areas in the RTO. Each RTO 

would maintain accumulations of the 

net inadvertent interchange for all the 

control areas in the RTO after the 

financial settlement and as such would 

not affect the accumulation of netinterchange by non-participant control 

areas. 

ii. Comments 

215. These regional differences were 

not addressed in the Staff Preliminary 

Assessment and, consequently, no 

comments were received. 

iii. Commission Proposal 

216. The two proposed regional 

differences relate solely to facilitating 

financial settlements of accumulated 

inadvertent interchange and have 

minimal, if any, reliability implications. 

These regional differences allow 

coordination with the current RTO 

market tariffs and promote incentives 

that would deter balancing authorities 

from depending excessively on other 

balancing authorities. Accordingly, the 

Commission proposes to approve these 

regional differences. 

2. CIP: Critical Infrastructure Protection 

a. Overview 

217. The Critical Infrastructure 

Protection group of Reliability 

Standards, as filed, consists of two 

standards aimed at reporting 

occurrences of sabotage to the proper 

authorities and establishing security for 

critical cyber assets. The first standard 

is CIP–001–0 (Sabotage Reporting). The 

second standard is Urgent Action 1200 

(UA–1200), which addresses the cyber 

security of bulk electric system assets. 

UA–1200 was filed by NERC for 

informational purposes only and is 

therefore not the subject of Commission 

action in this proposed rule. 

b. NERC Proposal 

218. CIP–001–0 requires that each 

reliability coordinator, balancing 

authority, transmission operator, 

generation operator and load-serving 

entity: (1) Have procedures for 

recognizing and for making their 

operating personnel aware of sabotage 

events; (2) have procedures for 

communicating information concerning 

sabotage events to appropriate ‘‘parties’’

in the interconnection; (3) provide 

operating personnel with guidelines for 

reporting disturbances due to sabotage 

events; and (4) establish 

communications contacts with 

applicable government officials and 

develop appropriate reporting 

procedures. The reliability goal of the 

standard is to ensure that operating 

entities recognize sabotage events and 

inform appropriate authorities and each 

other to properly respond to the 

sabotage (via cyber or physical means) 

to minimize the impact on the BulkPower System. 

c. Staff Preliminary Assessment 

219. Staff noted that CIP–001–0 does 

not require an entity to actually contact 

a governmental or regulatory body in 

the event of sabotage (though staff 

acknowledged that Standard EOP–004–

0 does contain such a requirement). 

Staff also found that there is no 


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138Many commenters address concerns that staff 

raised with UA–1200. Those comments ran the 

gamut from support to disagreement with the Staff 

Preliminary Assessment. Since UA–1200 was 

submitted for informational purposes only, we will 

not address this Reliability Standard or related 

comments in the NOPR. 

139Order No. 672 at P 325 

140The American Heritage Dictionary defines 

‘‘sabotage’’ as ‘‘1. Destruction of property or 

obstruction of normal operations, as by civilians or 

enemy agents in time of war. 2. Treacherous action 

to defeat or hinder a cause or an endeavor; 

deliberate subversion.’’ The American Heritage 

Dictionary of the English Language, (Houghton 

Mifflin Co., 4th Ed. 2000). 

141Reference in CIP–001–0 to Standard EOP–

004–0, which requires entities to report actual or 

suspected physical or cyber attacks to the U.S. 

Department of Energy Operations Center would 

improve CIP–001–0. 

142ESISAC IAW SOP requires a preliminary 

report to be filed within 60 minutes, a follow-up 

report to be filed within four to six hours after the 

preliminary report and a final report to be filed 

within 60 days. 

definition of ‘‘sabotage’’ in the 

Reliability Standard, which could lead 

to inconsistent application. Finally, staff 

stated that CIP–001–0 does not contain 

Measures or Levels of Non-Compliance. 

d. Comments 

220. In response to the Staff 

Preliminary Assessment, NERC 

comments that a requirement for 

reporting to government agencies is a 

matter of jurisdiction of the respective 

government agencies and not one of 

reliability. NERC states that it will 

consider developing a definition of 

sabotage, though it believes there is no 

confusion within industry regarding the 

meaning of ‘‘sabotage’’ in CIP–001–0. 

221. ReliabilityFirst comments that 

language in CIP–001–0 is ambiguous but 

does not identify any specific examples. 

It states that CIP–001–0 is a ‘‘Version 0’’

standard, which means that it was not 

developed using NERC’s ANSIaccredited standards development 

process. ReliabilityFirst further 

comments that, during the development 

process for standards CIP–002 through 

CIP–009, the drafting team generally 

considered that standard CIP–001–0 

dealt only with physical sabotage 

reporting and, therefore, addressed 

cyber incident reporting requirements in 

CIP–008. 

222. With regard to the lack of 

metrics, CenterPoint observes that 

metrics would be difficult to develop.138

e. Commission Proposal 

223. The Commission proposes to 

approve CIP–001–0 as mandatory and 

enforceable. In addition, we propose 

directing that NERC develop 

modifications to the Reliability 

Standard, as discussed below. 

224. Order No. 672 explained that one 

of the factors that the Commission 

considers when reviewing a proposed 

Reliability Standard is whether the 

proposal is clear and unambiguous.139

The Requirements of CIP–001–0 refer to 

a ‘‘sabotage event’’ but do not define 

that term. Generally, we believe that 

‘‘sabotage’’ is a commonly understood 

term 140 and the Requirements of CIP–

001–0 are enforceable. While the 

common understanding of the term 

sabotage should suffice in most 

circumstances, we are concerned that 

situations may arise in which it is not 

clear whether action pursuant to CIP–

001–0 is required. For example, a breakin that gains access to a control room 

but does not cause damage, or a 

physical attack that results in minor 

damage, may be reported as sabotage by 

one entity but not another. Thus, the 

ERO should provide guidance clarifying 

the triggering event for an entity to take 

action pursuant to CIP–001–0. 

225. CIP–001–0 requires that an 

applicable entity have procedures for 

recognizing sabotage events and making 

its operating personnel aware of 

sabotage events. However, it does not 

establish baseline requirements 

regarding what issues should be 

addressed by the developed procedures. 

For example, a procedure could identify 

a chronological ‘‘checklist’’ of minimum 

actions that would apply if a sabotage 

event occurs, such as the timing and 

chain of communication, the 

preservation of evidence, repairing 

damage and contacting the appropriate 

law enforcement officials. 

226. As stated above, while an 

applicable entity must establish 

communication contacts, there is no 

Requirement in CIP–001–0 that an 

applicable entity actually contact the 

appropriate governmental or regulatory 

body in the event of sabotage consistent 

with the purpose of the standard, which 

states that ‘‘[d]isturbances or unusual 

occurrences, suspected or determined to 

be caused by sabotage, shall be reported 

to the appropriate systems, 

governmental agencies, and regulatory 

bodies.’’ 141 We believe that mandatory 

reporting of a sabotage event is 

important to achieve the reliability goal 

of this proposed Reliability Standard. 

Further, since sabotage is an intentional 

action directed at a specific entity, the 

timely reporting of such events is of the 

utmost importance as a tool to warn 

other entities of potential problems. 

227. With regard to NERC’s 

comments, NERC has not adequately 

explained its statement that reporting of 

sabotage is an issue of jurisdiction 

instead of reliability. It may be 

necessary for NERC to lay the 

groundwork with the appropriate 

government agencies, such as the 

Federal Bureau of Investigation or 

Department of Homeland Security, on 

an appropriate protocol for a report of 

sabotage. For example, NERC may want 

to consider the requirements for timely 

reporting developed by the Department 

of Homeland Security found in the 

Electric Sector Information Sharing & 

Analysis Center (ESISAC) Indications, 

Analysis and Warning Program (IAW) 

Standard Operating Procedure (SOP).142

Accordingly, the Commission proposes 

to direct NERC to modify the Reliability 

Standard to require an applicable entity 

to contact appropriate federal 

authorities, such as the Department of 

Homeland Security, in the event of 

sabotage within a specified period of 

time. 

228. The Commission is further 

concerned that CIP–001–0 does not 

include a requirement for the periodic 

review or updating of sabotage reporting 

plans or procedures, or for the periodic 

testing of the sabotage reporting 

procedures to verify that they achieve 

the desired result. The Commission 

believes that a periodic review is 

appropriate because appropriate 

methods of responding to a sabotage 

event may change or become more 

sophisticated. Also, contacts for 

reporting an incident should be 

periodically updated. 

229. As mentioned above, CIP–001–0 

does not contain Measures or Levels of 

Non-Compliance. Though CenterPoint 

believes that compliance elements 

would be difficult to develop, the 

Commission believes that Measures and 

Levels of Non-Compliance are important 

in this Reliability Standard to assure the 

consequences of failure to comply with 

the requirements are clear and 

unambiguous. 

230. While the Commission has 

identified concerns with regard to CIP–

001–0, we believe that the proposal 

serves an important purpose in ensuring 

that operating entities properly respond 

to sabotage events to minimize the 

adverse impact on the Bulk-Power 

System. The Commission believes that it 

is important for NERC to provide 

Measures and Levels of NonCompliance for this proposed Reliability 

Standard, and that a definition of 

‘‘sabotage’’ will provide desired clarity. 

Nonetheless, the proposed 

Requirements set forth in CIP–001–0 are 

sufficiently clear and objective to 

provide guidance for compliance. 

231. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 


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143Staff Preliminary Assessment at 45. 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard CIP–001–0 

as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to CIP–001–0 that: (1) Includes 

Measures and Levels of NonCompliance; (2) gives guidance for the 

term ‘‘sabotage’’; (3) requires an 

applicable entity to contact appropriate 

Federal authorities, such as the 

Department of Homeland Security, in 

the event of sabotage within a specified 

period of time; and (4) requires periodic 

review of sabotage response procedures. 

3. COM: Communications 

a. Introduction 

232. The Communications group 

contains two Reliability Standards. The 

first Reliability Standard requires that 

transmission operators, balancing 

authorities and other applicable entities 

have adequate internal and external 

telecommunications facilities for the 

exchange of interconnection and 

operating information necessary to 

maintain reliability. The second 

Reliability Standard requires that these 

communication facilities be staffed and 

available for addressing real-time 

emergencies and that operating 

personnel carry out effective 

communications. 

General Issues 

Performance Metrics 

233. CenterPoint comments that 

‘‘some or all’’ of the Communication 

group of Reliability Standards should be 

replaced by establishing performance 

metrics. It suggests that the Commission 

refer these Reliability Standards back to 

NERC with a directive to explore 

replacing process-oriented requirements 

with performance metrics. CenterPoint 

points to ERCOT as an example of a 

region that is developing performance 

metrics for telemetry and 

telecommunication infrastructure 

necessary to ensure situational 

awareness and address commercial 

considerations associated with a 

planned transition to a nodal market 

design. 

234. The Commission believes that 

including performance metrics within a 

Reliability Standard in specific 

instances would be an improvement. 

However, we do not see the 

development of performance metrics, 

lagging and/or forward-looking, as an 

adequate substitute for a mandatory and 

enforceable Reliability Standard. 

235. Accordingly, while the 

Commission encourages the use of 

performance metrics in conjunction 

with Measures and Requirements, we 

reject CenterPoint’s suggestion that the 

proposed Communications Reliability 

Standards be replaced with performance 

metrics. 

Local Control Centers 

236. The terms transmission operator 

and generator operator in NERC’s 

functional model include the activities 

that those operators would perform to 

achieve their specific reliability goals. 

As identified by MISO and Allegheny, 

confusion can arise when using these 

terms in the context of an ISO or RTO 

or in any organization that pools 

resources. In such organizations, 

decision making and implementation 

are performed by separate groups. The 

decision-making portion of the 

transmission operator and, to a lesser 

extent, the generation operator function 

typically is completed by the ISO or 

RTO. The actual implementation is 

performed by either local transmission 

control centers or independent 

generation control centers. For example, 

the transmission and generation owners 

usually operate and maintain the 

individual facilities, control systems, 

SCADA systems, etc. The data from 

these locations are sent to the ISO or 

RTO control center either directly or 

through the entity’s local control center. 

Upon receipt, the operators in the ISO 

or RTO control center make decisions 

that are transmitted to the local 

transmission and generation control 

centers. In some ISO or RTO 

arrangements, the request for action may 

be further divided and sent to 

individual generation facilities or 

transmission switching stations where it 

is actually implemented. 

237. The Commission proposes that 

all control centers and organizations 

that are necessary for the actual 

implementation of the decisions or are 

needed for operation and maintenance 

made by the ISO or RTO or the pooled 

resource organizations are part of the 

transmission or generation operator 

function in the functional model. All of 

the requirements for telecommunication 

would apply to all of these entities as 

appropriate to their respective functions 

within the transmission or generation 

operation functional model. Further, we 

note that this proposed definition of 

responsibility within a function would 

apply to other Reliability Standards that 

address such activities as training, 

operator certification, transmission 

operations, and cyber and physical 

security. 

b. Telecommunications (COM–001–0) 

i. NERC Proposal 

238. NERC states that COM–001–0 

ensures coordinated 

telecommunications among operating 

entities, which is fundamental to 

maintaining grid reliability. This 

proposed Reliability Standard 

establishes general telecommunications 

requirements for specific operating 

entities, including equipment testing 

and coordination. It also establishes 

English as the common language 

between and among operating 

personnel, and sets policy for using the 

NERCNet telecommunications system. 

COM–001–0 applies to transmission 

operators, balancing authorities, 

reliability coordinators and NERCNet 

user organizations. 

239. NERC indicates that it will 

modify this proposed Reliability 

Standard to address the lack of 

Measures and Levels of NonCompliance and resubmit the proposal 

for Commission approval in November 

2006. 

ii. Staff Preliminary Assessment 

240. The Staff Preliminary 

Assessment pointed out that the COM–

001–0 contains a general requirement to 

provide ‘‘adequate and reliable’’

telecommunications facilities for all 

applicable operating entities, but does 

not provide specific or minimum 

requirements on adequacy, redundancy 

and diverse routing of the 

telecommunications facilities necessary 

to ensure the exchange of operating 

information, both internally and among 

the operating entities.143

241. Staff also indicated that the 

Requirements set forth in the proposed 

Reliability Standard do not differentiate 

between operating entities with 

different needs. Staff explained that, for 

example, reliability coordinators need 

telecommunication facilities beyond 

those required by other operating 

entities. In addition, staff noted that 

generator operator is not designated as 

an applicable entity. 

iii. Comments 

242. NERC states with respect to 

Blackout Report Recommendation No. 

26, which called for a tightening of its 

communications protocols and 

upgrading its communication hardware, 

that it has installed a new conference 

bridge, approved a new set of hotline 

procedures for reliability coordinator 

hotline calls and is working on an 

upgrade of its Reliability Coordinator 

Information System that provides realVerDate Aug<31>2005 16:18 Nov 02, 2006 Jkt 211001 PO 00000 Frm 00027 Fmt 4701 Sfmt 4702 E:\FR\FM\03NOP2.SGM 03NOP2

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144NERC Comments at 118. 

145Loss of data from some entities may result in 

errors or non convergence of state estimators and 

security analysis, which may result in loss of a wide 

area view, situational awareness, and economic 

information such as LMP. 

time information to reliability 

coordinator control areas. NERC also 

states that it is not aware of any 

operating problems this Reliability 

Standard is causing. It explains that the 

methods chosen by operating entities to 

provide adequate and reliable 

communications facilities ‘‘will drive 

their needs for backup communications 

facilities and communications circuits 

with diverse routing.’’ 144

243. MRO generally agrees with staff’s 

assessment of COM–001–0 and suggests 

that the Reliability Standard be 

reviewed and modified in its entirety. It 

believes the Reliability Standard must 

balance the capability that the 

telecommunications industry can 

realistically provide against what is 

needed for reliability. MRO provides an 

example of a situation where an electric 

utility makes a good faith effort to 

comply with a dual communication 

path mandate by contracting with a 

third party vendor without knowing that 

this path contains a single point of 

failure for both communication paths. 

244. ReliabilityFirst comments on the 

need for expedited development of 

missing Measures and Levels of NonCompliance. 

iv. Commission Proposal 

245. The Commission proposes to 

approve Reliability Standard COM–001–

0 as mandatory and enforceable. In 

addition, we propose to direct that 

NERC develop modifications to the 

Reliability Standard, as discussed 

below. 

246. With regard to MRO’s concern 

about redundancy, we believe that the 

Reliability Standard is sufficiently clear 

that the functional entity is responsible 

for achieving redundancy and diverse 

routing requirements. 

247. The Staff Preliminary 

Assessment expressed concern that 

COM–001–0 does not provide specific 

or minimum requirements on adequacy, 

redundancy and diverse routing of the 

telecommunications facilities necessary 

to ensure the exchange of operating 

information. While MRO concurs with 

staff, NERC suggests that the methods 

chosen to comply with COM–001–0 will 

‘‘drive’’ the applicable entities’ need for 

redundant telecommunication facilities 

and diversely routed telecommunication 

circuits. The Commission believes that 

the Reliability Standard might be 

improved if NERC was to provide 

specific or minimum requirements for 

adequacy, redundancy and diverse 

routing. At the same time, we are 

concerned that the addition of specific 

or minimum requirements may result in 

a Reliability Standard that reduces the 

flexibility of applicable entities in 

achieving compliance or implementing 

new technologies and motivates 

applicable entities to simply achieve 

compliance with the minimum 

requirement. Accordingly, we seek 

comment on the specific requirements 

or performance criteria for 

telecommunications facilities.145

248. Further, assuming we direct 

NERC to develop such specific 

requirements, the Commission also 

seeks comment whether the modified 

Reliability Standard should provide 

requirements that also consider the 

relative role of applicable entities. 

While the Commission believes that 

applicable entities of all roles should 

have adequate telecommunications 

equipment, the needs will likely vary 

based on role. We would expect a 

modification to COM–001–0, if directed, 

to develop sufficient information so that 

transmission owners and other 

applicable entities of all sizes will have 

some specific guidance as to what is 

required to maintain an acceptable 

telecommunications facility. 

249. The Commission notes that this 

Reliability Standard is applicable to 

transmission operators, balancing 

authorities, reliability coordinators, and 

NERCNet user organizations. However, 

during normal and emergency 

operations, communications with 

additional entities are required. For 

example, during a blackstart when 

normal communications may be 

disrupted, it is essential that the 

transmission operator, balancing 

authority, and reliability coordinator 

have communications with the 

generator operators and distribution 

providers. The Commission proposes 

that NERC modify the applicability 

section of COM–001–0 to make 

generator operators and distribution 

providers as applicable entities and 

modify the requirements of this 

Reliability Standard as necessary to 

account for this change. 

250. Telecommunication facilities for 

emergency operations including 

restoration require special provisions 

which are lacking in COM–001–0. 

Inadequate telecommunication facilities 

during emergency operations would 

aggravate the duration and extent of the 

emergency and delay the subsequent 

restoration. Periodic testing of 

telecommunication facilities will insure 

that these facilities are functional when 

required. Accordingly, the Commission 

proposes to direct NERC to modify 

COM–001–0 to include requirements for 

communication facilities for use during 

emergency situations and periodic 

testing of these facilities. 

251. While the Commission has 

identified a number of concerns with 

regard to COM–001–0, this proposed 

Reliability Standard serves an important 

purpose by requiring transmission 

operators and others to have necessary 

telecommunication equipment. Further, 

NERC should provide Measures and 

Levels of Non-Compliance for this 

proposed Reliability Standard. 

Nonetheless, the Requirements set forth 

in COM–001–0 are sufficiently clear and 

objective to provide guidance for 

compliance. 

252. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard COM–001–

0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, we propose to direct that 

NERC submit a modification to COM–

001–0 that: (1) Includes Measures and 

Levels of Non-Compliance; (2) includes 

generator operators and distribution 

provider as applicable entities; and (3) 

includes requirements for 

communication facilities for use during 

emergency situations. 

c. Communications and Coordination 

(COM–002–1) 

i. NERC Proposal 

253. The stated purpose of COM–002–

1 is to ensure that transmission 

operators, generator operators and 

balancing authorities have adequate 

communications and that their 

communications capabilities are staffed 

and available to address real-time 

emergency conditions. This Reliability 

Standard requires balancing authority 

and transmission operators to notify 

others through pre-determined 

communication paths of any condition 

that could threaten the reliability of its 

area or when firm load shedding is 

anticipated. NERC has indicated that it 

will modify this Reliability Standard to 

address the lack of Measures and Levels 

of Non-Compliance and resubmit it for 

Commission approval in November 

2006. 

ii. Staff Preliminary Assessment 

254. Staff explained that COM–002–1 

does not require that ‘‘the appropriate 


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146Staff Preliminary Assessment at 44. 

147COM–002–1, Requirement R1.1. 

148Blackout Report at 107. 149Staff Preliminary Assessment at 43–44. 

operating actions in normal and 

emergency operating conditions that 

may have reliability impact beyond a 

local area or Reliability Coordinator’s 

area * * * be assessed and approved by 

the Reliability Coordinator, before being 

implemented by the operating 

entities.’’ 146 Staff noted that Blackout 

Report Recommendation No. 26 calls for 

effective communications, but COM–

002–1 does not provide for ‘‘tightened 

communication protocols.’’

iii. Comments 

255. NERC agrees with the need to 

develop additional Reliability Standards 

addressing consistent communications 

protocols among personnel responsible 

for the reliability of the Bulk-Power 

System. However, NERC does not 

believe that ‘‘tightened communication 

protocols’’ required by the Blackout 

Report should include the requirement 

that operating actions in normal and 

emergency conditions must be assessed 

and approved by the reliability 

coordinator before being implemented 

by the operating entities. Other 

Reliability Standards require 

coordination and communications 

among all operating entities, and 

transmission operators and balancing 

authorities have adequate authority to 

restore imbalances and mitigate 

transmission (SOL and IROL) violations. 

256. National Grid agrees with the 

Staff Preliminary Assessment that 

tighter communications protocols are 

needed with respect to assessment and 

approval of operating actions under 

normal and emergency conditions, but it 

believes any new requirements belong 

in COM–002–1, which deals with 

coordination rather than COM–001–0, 

which sets forth requirements for 

telecommunication facilities. National 

Grid states that this Reliability Standard 

for communication protocols should not 

be intermixed with Reliability 

Standards for communication facilities. 

257. ReliabilityFirst and MRO 

maintain that, without specific 

Measures and Levels of NonCompliance, NERC will not be able to 

implement consistent and effective 

enforcement of COM–002–1. MRO states 

that the Reliability Standard should 

clarify the role of the Regional Entities 

and clarify any distinctions between 

COM–001–0 and COM–002–1. 

iv. Commission Proposal 

258. COM–002–1 requires 

communications with the reliability 

coordinator through predetermined 

paths when a condition could threaten 

‘‘the reliability of [the reliability 

coordinator’s] area.’’ 147 As noted above, 

several commenters are of the opinion 

that this Reliability Standard does not 

recognize that operating actions can 

have reliability impacts beyond the 

local area for which a particular 

reliability coordinator is responsible. 

NERC disagrees on this issue and points 

out that other Reliability Standards 

require coordination and 

communications among operating 

entities. However, the Reliability 

Standards to which NERC refers require 

such coordination and communications 

only in limited, specified 

circumstances. Further, while NERC 

states that other Reliability Standards 

require coordination and 

communications among all operating 

entities, the Commission notes that 

transmission operators have unilateral 

authority to mitigate transmission (SOL 

and IROL) violations within their 

jurisdictions. Thus, those entities can 

take actions that place others at risk 

because they do not have a wide area 

view. Accordingly, we propose directing 

NERC to add a Requirement that the 

reliability coordinator assess and 

approve actions that have impacts 

beyond the area views of transmission 

operators and balancing authorities. 

259. In addition, we also believe that 

tightened protocols are necessary. The 

Blackout Report identifies ineffective 

communication as one of the common 

factors among major cascading 

outages.148 The Commission recognizes 

NERC for its efforts in following up on 

Blackout Report Recommendation No. 

26, especially with respect to specific 

communication protocols implemented 

to date. We encourage NERC to continue 

its effort in working with industry with 

the goal to incorporate their work into 

the Reliability Standards to achieve 

technical excellence as part of NERC’s 

stated goal. In addition, these efforts 

should include priorities that target 

improving the Reliability Standards in 

the near future. Specifically, NERC 

should modify COM–002–0 to ‘‘tighten’’

communications, especially for 

communications during alerts and 

emergencies. Staff explained in the Staff 

Preliminary Assessment that this can be 

understood to include two key 

components: (1) Effective 

communications that are delivered in 

clear language via pre-established 

communications paths among preidentified operating entities; and (2) 

communications protocols which 

clearly identify that any operating 

actions with reliability impact beyond a 

local area or beyond a reliability 

coordinator’s area must be 

communicated to the appropriate 

reliability coordinator for assessment 

and approval prior to implementation to 

ensure reliability of the interconnected 

systems.149 NERC should work from 

these components to develop 

modifications to COM–002–0 that will 

implement Blackout Report 

Recommendation No. 26. 

260. The Commission notes that this 

Reliability Standard is applicable to 

transmission operators, balancing 

authorities, reliability coordinators, and 

generator operators. However, during 

normal and emergency operations, 

communications with additional 

entities are required. For example, 

during emergency situations, it is 

essential that the transmission operator, 

balancing authority, and reliability 

coordinator have communications with 

distribution providers. The Commission 

proposes that NERC modify the 

applicability section of COM–002–1 to 

make distribution providers applicable 

entities and modify the requirements of 

this Reliability Standard as necessary to 

account for this change. 

261. While the Commission has 

identified concerns regarding COM–

002–1, this proposed Reliability 

Standard serves an important purpose 

by requiring users, owners and 

operators of the Bulk-Power System to 

implement the necessary 

communications and coordination 

among entities. NERC should provide 

Measures and Levels of NonCompliance. Nonetheless, the 

Requirements set forth in COM–002–1 

are sufficiently clear and objective to 

provide guidance for compliance. 

262. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, The Commission proposes to 

approve Reliability Standard COM–002–

1 as a mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, we propose to direct that 

NERC submit a modification to COM–

002–1 that: (1) Includes Measures and 

Levels of Non-Compliance; (2) includes 

a Requirement for the reliability 

coordinator to assess and approve 

actions that have impacts beyond the 

area views of transmission operators or 


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150This Requirement could be included in this 

communication Reliability Standard or in an 

operating Reliability Standard(s), at NERC’s option. 

balancing authorities; 150 (3) includes 

distribution providers as applicable 

entities; and (4) requires tightened 

communications protocols, especially 

for communications during alerts and 

emergencies. Alternatively, with respect 

to this final issue, we propose to direct 

NERC to develop a new Reliability 

Standard that responds to Blackout 

Report Recommendation No. 26 in the 

manner just described. 

4. EOP: Emergency Preparedness and 

Operations 

a. Overview 

263. The Emergency Preparedness 

and Operations (EOP) group of proposed 

Reliability Standards consists of nine 

Reliability Standards that address 

preparation for emergencies, necessary 

actions during emergencies, and system 

restoration and reporting following 

disturbances. 

b. Emergency Operations Planning 

(EOP–001–0) 

i. NERC Proposal 

264. NERC’s proposed Reliability 

Standard EOP–001–0 requires each 

transmission operator and balancing 

authority to develop, maintain, and 

implement a set of plans to mitigate 

operating emergencies. These plans 

must be coordinated with other 

transmission operators and balancing 

authorities, and the reliability 

coordinator. The Reliability Standard 

applies to balancing authorities and 

transmission operators and identifies 

the regional reliability organization as 

responsible for monitoring compliance. 

It also requires the regional reliability 

organization to review and evaluate 

emergency plans every three years to 

ensure that these plans consider the 

elements that the Reliability Standard 

specifies should be considered when 

developing an emergency plan, e.g., 

system energy use, load management 

and, environmental constraints. 

ii. Staff Preliminary Assessment 

265. Staff noted that while EOP–001–

0 requires a transmission operator and 

balancing authority to develop, 

maintain, and implement a set of plans 

to mitigate operating emergencies 

resulting from either insufficient 

generation or transmission, there is no 

similar requirement for a reliability 

coordinator, which is the highest level 

of authority responsible for the BulkPower System. Staff also found the 

requirement that transmission operators 

have emergency load reduction plans 

capable of being implemented within 30 

minutes after declaration of an operating 

emergency to be ambiguous. According 

to staff, the requirement could be read 

to imply that load-shedding capability 

with an implementation time of up to 30 

minutes is acceptable to address system 

emergencies. Staff deemed this 

conclusion to be inappropriate. It could 

expose the system to higher risk because 

load shedding is the option of last resort 

and must be capable of being 

implemented much sooner than 30 

minutes. Finally, staff noted that the 

Reliability Standard does not define 

transmission-related ‘‘normal,’’ ‘‘alert,’’

and ‘‘emergency’’ states, does not 

provide criteria for entering into these 

states, nor does it identify authority for 

declaring these states. 

iii. Comments 

266. NERC maintains that staff’s 

concerns regarding reliability 

coordinator involvement are addressed 

in other Reliability Standards. It states 

that proposed Reliability Standard IRO–

001–0 requires a reliability coordinator 

to have plans and coordination 

agreements to mitigate capacity and 

energy emergencies. Proposed 

Reliability Standard IRO–005–0 

provides more details on handling 

emergencies and mitigating SOL and 

IROL violations. Further, Attachment 1 

to proposed Reliability Standard EOP–

002–1 provides procedures that a loadserving entity can use to work with its 

reliability coordinator to obtain capacity 

and energy when it has exhausted all 

other options and can no longer provide 

its customers’ expected energy 

requirements. NERC also states that the 

NERC Operating Committee approves 

every reliability coordinator reliability 

plan and posts those plans on its Web 

site. Finally, NERC states that the 30- 

minute limit for mitigating IROL 

violations is one of many standards 

gleaned from decades of interconnected 

systems operation experience, and 

concludes that requiring SOL and IROL 

mitigation ‘‘as soon as possible’’ but 

within no longer than 30 minutes is 

reasonable because it allows the system 

operator to decide on what course of 

action to take. 

267. MRO agrees with staff that the 

reliability coordinator should be 

required to have an emergency plan. 

The requirement that load reduction 

plans be capable of implementation 

within 30 minutes should be clarified, 

and the Reliability Standard should 

include the definitions for ‘‘normal,’’

‘‘alert’’ and ‘‘emergency states.’’

However, MRO notes that these 

definitions were not finalized at the 

time the Staff Preliminary Assessment 

was issued. 

268. ReliabilityFirst agrees that the 

reliability coordinator is the highest 

authority on the bulk electric system 

with regard to real time, coordinated 

operations. The plans mentioned in the 

Reliability Standard are intended for 

operators within each reliability 

coordinator’s respective area. 

ReliabilityFirst states that the 30 minute 

load-shedding requirement establishes a 

maximum threshold. It is expected that 

action that can be taken prior to that 

deadline will be implemented as soon 

as possible. 

269. The ISO/RTO Council and 

Alberta agree that EOP–001–0 should 

apply to reliability coordinators. ISO/ 

RTO Council notes that NERC’s 

Reliability Coordinator Working Group 

is conducting a pilot program in the 

summer of 2006 to define terms to be 

used in ‘‘normal,’’ ‘‘alert’’ and 

‘‘emergency’’ conditions. The ISO/RTO 

Council recommends that NERC adopt 

these terms as part of the NERC glossary 

following completion of the pilot 

program. 

270. CPUC comments that it is 

reasonable to state that expeditious load 

shedding must be available, if that is the 

intent of Commission staff’s discussion 

of the load-shedding timing requirement 

in EOP–001–0. However, the CPUC 

takes the position that it is not 

reasonable to require that all load 

shedding capability be available within 

30 minutes. That would entail very 

significant, and possibly unnecessary, 

costs to the detriment of ratepayers. 

iv. Commission Proposal 

271. The Commission proposes to 

approve proposed Reliability Standard 

EOP–001–0 as mandatory and 

enforceable. In addition, the 

Commission proposes to direct that 

NERC develop modifications to the 

Reliability Standard, as discussed 

below. 

272. The proposed Reliability 

Standard applies to transmission 

operators and balancing authorities. The 

Commission believes that the 

applicability portion of the Reliability 

Standard is sufficiently clear as to who 

must comply with the filed version of 

the standard and can be enforced on 

these entities. However, commenters 

express concern that it does not assign 

a role to the reliability coordinator. 

NERC states that the reliability 

coordinator is the ‘‘entity that is the 

highest level of authority who is 

responsible for the reliable operation of 

the Bulk Electric System, has the Wide 

Area view of the Bulk Electric System, 

and has the operating tools, processes 


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151NERC glossary at 11. 

152Blackout Report at 158. 

and procedures, including the authority 

to prevent or mitigate emergency 

operating situations in both next-day 

analysis and real-time operations.’’ 151

Given the importance NERC attributes 

to the reliability coordinator in 

connection with matters covered by 

EOP–001–0, the Commission is 

persuaded that this Reliability Standard 

should also apply to the reliability 

coordinator and proposes that it be 

modified to include the reliability 

coordinator as an applicable entity. 

273. The proposed Reliability 

Standard allows load reduction within 

30 minutes of IROL violations. NERC 

maintains that requiring SOL and IROL 

mitigation ‘‘as soon as possible’’ but 

within no longer than 30 minutes is 

reasonable because it allows the system 

operator to decide on what course of 

action to take. The Commission 

understands that it is not the intent of 

this Reliability Standard to require that 

shedding of all available load occur 

within 30 minutes, but rather only the 

amount necessary to correct system 

emergencies. However, NERC’s 

conclusion that IROL or SOL mitigation 

within no longer than 30 minutes is 

reasonable does not address the 

Commission’s concern. That concern is 

rooted in the view that load shedding 

must be capable of being implemented 

as soon as possible and much sooner 

than 30 minutes. The reference to 30 

minutes in EOP–001–0 could suggest 

that anything up to that limit is 

acceptable. Consistent with NERC’s 

comments, the Commission proposes 

that this Reliability Standard should be 

modified to clarify that load shedding 

should be capable of being implemented 

as soon as possible and much less than 

30 minutes. 

274. Recommendation No. 20 of the 

Blackout Report called for establishing 

‘‘clear definitions for the normal, alert, 

and emergency operational system 

conditions,’’ and stated that the ‘‘roles, 

responsibilities and authorities of 

Reliability Coordinators and control 

areas under each condition’’ should be 

clarified.152 In the Commission’s view, 

the inability to identify clearly when the 

system is operating outside of the 

normal/secure system state, and the 

resulting inability to recognize the level 

of reliability deterioration experienced 

under all system conditions (other than 

the normal/secure system state), 

represents a deficiency that should be 

resolved. Some ISOs and RTOs clearly 

define multiple operating system states 

ranging from normal to restoration. 

System metering data and computer 

software that identify for system 

operators the current system state and 

clear procedures have been established 

to assist the operator in returning the 

system to the normal state as quickly as 

possible. Indeed, the overall operational 

objective is to proactively operate the 

Bulk-Power System to achieve a normal 

system state as contemplated by FPA 

section 215. 

275. The Commission believes that 

there is a need for clearly defined 

system states to be incorporated into 

real-time operation that can 

significantly improve operator 

recognition of emergency conditions, 

rapid and accurate response, and 

recovery to normal system conditions. 

In addition, a clearly defined set of 

system states implemented in real-time 

will help the operator proactively avert 

escalation of system disturbances and 

thus avert cascading outages and 

reliability standard violations. 

Moreover, statistics surrounding 

operating states based on the duration 

and frequency of excursions to nonnormal system states can provide 

understanding for the operator, 

management, the ERO and regulators on 

how reliably the system is being 

operated, how reliable it was operated 

over historic periods, trends in 

reliability performance and metrics that 

can provide part of the foundation for 

defining ‘‘an adequate level of 

reliability’’ that we required in our 

Order certifying the ERO. 

276. We therefore propose that the 

ERO modify this Reliability Standard to 

include clearly defined system states for 

capacity, energy, and transmission to be 

implemented in real-time operations. 

We note that some control areas define 

and effectively use more than the 

‘‘normal,’’ ‘‘alert’’ and ‘‘emergency’’

system states included in the Blackout 

Report recommendations. The ERO 

should determine the optimum number 

of system states to be employed 

continent-wide for consistency in the 

development of reliability performance 

metrics and should consider the 

addition of the restoration state. 

277. While the Commission has 

identified concerns with regard to EOP–

001–0 that call for improvements, we 

believe that the Reliability Standard in 

its present form serves an important 

purpose in promoting appropriate 

planning for operating emergencies. For 

instance, while we believe clarifying the 

terms ‘‘normal,’’ ‘‘alert,’’ and 

‘‘emergency’’ will provide for clearer 

metrics for measuring performance, the 

Commission believes that system 

operators generally understand when 

the system is in each of these states. The 

Requirements are sufficiently clear and 

objective to provide guidance for 

compliance. 

278. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission therefore 

proposes to approve Reliability 

Standard EOP–001–0 as mandatory and 

enforceable. In addition, pursuant to 

section 215(d)(5) of the FPA and 

§ 39.5(f) of our regulations, we propose 

to direct that NERC submit a 

modification to EOP–001–0 that: (1) 

Includes the reliability coordinator as an 

applicable entity with responsibilities as 

described above; (2) clarifies the 30- 

minute requirement in Requirement R2 

of the Reliability Standard to state that 

load shedding should be capable of 

being implemented as soon as possible 

and much less than 30 minutes; and (3) 

includes definitions of system states to 

be used by the operators, such as 

transmission-related ‘‘normal,’’ ‘‘alert,’’

and ‘‘emergency’’ states, provides 

criteria for entering into these states, 

and identifies the authority that will 

declare these states. 

c. Capacity and Energy Emergencies 

(EOP–002–1) 

i. NERC Proposal 

279. EOP–002–1 applies to balancing 

authorities and reliability coordinators 

and is intended to ensure that they are 

prepared for capacity and energy 

emergencies. NERC states that the 

proposed Reliability Standard requires 

that balancing authorities have the 

authority to bring all necessary 

generation on line, communicate the 

energy and capacity emergency with the 

reliability coordinator, and coordinate 

with other balancing authorities. NERC 

also states that the Reliability Standard 

limits a balancing authority’s use of any 

other balancing authority’s bias 

contribution to the Interconnection, 

referred to as ‘‘leaning on the ties.’’

EOP–002–1 includes an attachment that 

describes an emergency procedure to be 

initiated by a reliability coordinator that 

declares one of four energy emergency 

alert levels to provide assistance to the 

load serving entity. 

ii. Staff Preliminary Assessment 

280. The Staff Preliminary 

Assessment explained that while EOP–

002–1 addresses responsibility, 

authority and actions to be taken to 

alleviate a generation capacity and 

energy emergency, it does not address 

an emergency resulting from insufficient 


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153 Id. at 163. 

transmission capability, nor is this issue 

addressed elsewhere in other proposed 

Reliability Standards. Staff noted that 

transmission loading relief (TLR) 

procedures discussed in Reliability 

Standard IRO–006–3 are not appropriate 

for addressing actual transmission 

emergencies since, as stated in the 

Blackout Report, they are ‘‘not fast and 

predictable enough for use in situations 

in which an Operating Security Limit is 

close to or actually being violated.’’ 153

iii. Comments 

281. NERC states that, while EOP–

002–1 does not address emergencies 

resulting from insufficient transmission 

capability, a number of other proposed 

Reliability Standards related to 

transmission operation and reliability 

coordination address the need to 

operate within facility limits, SOL and 

IROL. NERC states that collectively the 

proposed Reliability Standards address 

emergencies resulting from insufficient 

transmission capability. 

282. MRO and ReliabilityFirst state 

that they agree with staff’s assessment of 

EOP–002–1. In addition, MRO states 

that TLRs are not appropriate for 

addressing actual transmission 

emergencies for the reasons stated in the 

Blackout Report. 

283. The ISO/RTO Council states that 

before approving EOP–002–1, the 

Commission should direct NERC to 

include in that Reliability Standard a 

requirement to assess whether sufficient 

transmission capability exists to allow 

the capacity and energy emergency plan 

mandated by the Reliability Standard to 

be ‘‘robust enough to ensure adequate 

resources.’’ The ISO/RTO Council also 

agrees with staff’s concerns that TLRs 

are not appropriate for addressing actual 

transmission emergencies for the 

reasons stated in the Blackout Report. It 

notes that ISOs and RTOs use 

redispatch to correct SOL and IROL 

instead of TLR procedures. Moreover, 

the ISO/RTO Council states that ISOs 

and RTOs that redispatch to protect 

system reliability do not get credit for 

such actions when another entity 

declares a TLR event. It also states that 

redispatch allows for a far more 

targeted, and thus effective, tool to 

resolve an imminent reliability threat 

than does a TLR, which can trigger 

additional TLRs on neighboring 

systems. As a result, the applicability of 

any Reliability Standard that relies on 

TLRs as the specific reliability tool to be 

used in an ISO or RTO region could be 

detrimental to system reliability. 

iv. Commission Proposal 

284. The Commission shares the 

concern expressed by MRO and the ISO/ 

RTO Council that the Emergency Plan 

required by EOP–002–1 addresses only 

generation capacity and energy 

emergencies and does not address 

emergencies resulting from inadequate 

transmission capability. NERC states 

that other Reliability Standards address 

mitigation of SOL and IROL violations 

due to loss of transmission facilities. 

While we agree with NERC that other 

Reliability Standards address mitigation 

of SOL and IROL violations, we remain 

concerned that neither EOP–002–1 nor 

any other Reliability Standard addresses 

the impact of inadequate transmission 

during generation emergencies. 

285. Requirement R6 of EOP–002–1 

identifies various remedies that a 

balancing authority should use to 

comply with Control Performance and 

Disturbance Control Standards 

including loading all available 

generating capacity and deploying all 

available operating reserve. The 

Commission proposes that the ERO 

modify Requirement R6 to include use 

of demand side management as one of 

the possible remedies. 

286. MRO and the ISO/RTO Council 

express concern that the TLR method is 

inappropriate for addressing actual 

transmission emergencies. The 

Commission’s proposal to address this 

concern is discussed fully in relation to 

Reliability Standards IRO–006–3 where 

the use of TLRs to mitigate potential or 

actual SOL and IROL violations is 

specified in these standards. The 

Commission shares the concerns of 

commenters about the use of TLR 

procedures for reasons stated in the 

Blackout Report, i.e., they are not fast 

and predictable enough for use in 

situations in which an operating 

security limit is close to being, or 

actually is being, violated. The 

Commission therefore proposes to 

instruct the ERO to include a clear 

warning that the TLR procedure is an 

inappropriate and ineffective tool to 

mitigate IROL violations or for use in 

emergency situations. 

287. While the Commission has 

identified concerns with regard to EOP–

002–1 that call for improvements, we 

believe that the proposed Reliability 

Standard serves an important purpose 

in promoting the goal of ensuring that 

balancing authorities and reliability 

coordinators are prepared for capacity 

and energy emergencies. In addition, the 

Requirements of the proposed 

Reliability Standard are sufficiently 

clear and objective to provide guidance 

for compliance. Accordingly, giving due 

weight to the technical expertise of the 

ERO and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard EOP–002–

1 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, we propose to direct that 

NERC submit a modification to EOP–

002–1 that: (1) Addresses emergencies 

resulting not only from insufficient 

generation but also from insufficient 

transmission capability, including 

situations where insufficient 

transmission impacts the 

implementation of the capacity and 

energy emergency plan; (2) identifies 

demand side management in 

Requirement R6 as one possible remedy 

that a balancing authority should use to 

bring it in compliance with Control 

Performance and Disturbance Control 

Standards; and (3) includes a clear 

warning that the TLR procedure is an 

inappropriate and ineffective tool to 

mitigate IROL violations or for use in 

emergency situations. 

d. Load Shedding Plans (EOP–003–0) 

i. NERC Proposal 

288. EOP–003–0 deals with loadshedding plans and requires that 

balancing authorities and transmission 

operators operating with insufficient 

transmission and generation capacity 

have the capability and authority to 

shed load rather than risk a failure of 

the Interconnection. The proposed 

Reliability Standard includes 

requirements to establish plans for 

automatic load shedding for 

underfrequency or undervoltage, 

manual load shedding to respond to 

real-time emergencies, and 

communication with other balancing 

authorities and transmission operators. 

NERC indicates that it plans to modify 

EOP–003–0 to include Measures and 

Levels of Non-Compliance. 

ii. Staff Preliminary Assessment 

289. Staff stated that EOP–003–0 does 

not specify the minimum load-shedding 

capability that should be provided and 

the maximum amount of delay before 

load shedding can be implemented. 

Staff noted that this Reliability Standard 

does not require that safeguards be 

provided to shield operators from 

retaliation when they declare an 

emergency or shed load in accordance 

with previously approved guidelines, as 


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154 Id. at 147. 155 Id. at 147. 

the Blackout Report recommends.154 In 

addition, the Staff Preliminary 

Assessment observed that the Reliability 

Standard does not require periodic 

drills of simulated load shedding. It 

stated that such drills are important to 

test the effectiveness of the processes, 

communications and protocols, and to 

familiarize operators from reliability 

coordinators, transmission operators 

and load serving entities with their 

respective roles and responsibilities in 

connection with the load shedding 

plans. 

iii. Comments 

290. NERC states that it considers 

operator liability to be a regulatory 

rather than a reliability issue, but that it 

has taken relevant action on two fronts. 

First, Version 0 of the proposed 

Reliability Standards provides direction 

to operators on when they should 

manually initiate load shedding, and 

expects operators to be empowered to 

take whatever action is necessary to 

ensure the reliability of the Bulk-Power 

System without fear of liability claims. 

Second, the regional reliability 

organizations are reviewing the 

applicability of automatic load-shedding 

plans in specific geographic areas, and 

are to present their recommendations to 

NERC. 

291. MRO states that the requirement 

that the balancing authority and 

transmission operator have the 

capability and authority to shed load 

rather than risk an uncontrolled failure 

is sufficient to meet the intent of this 

Reliability Standard and that the 

additional information suggested by 

staff is unnecessary. MRO maintains 

that the amount of load to be shed and 

the timeframe for shedding it is directly 

related to the system problem or 

condition at the time of the event. 

Adding an expected percentage and 

timeframe will not improve the 

Reliability Standard and would likely 

not meet every situation or system 

condition. MRO also concurs with staff 

that the Reliability Standard should 

require periodic drills of simulated load 

shedding and suggests that NERC better 

identify the type of training that should 

include load shed drills. 

292. MidAmerican shares staff’s 

concerns and suggests that the 

Reliability Standard should mandate 

regional studies to determine the 

appropriate minimum requirements for 

load shedding, recognizing the regional 

network is a portion of the 

interconnected network. It notes that 

certain portions of the Eastern 

Interconnection are not susceptible to 

instability, uncontrolled separation and 

cascading, while other portions of the 

Eastern Interconnection are very 

susceptible to these events. 

MidAmerican states that it may be more 

important to provide additional loadshedding capabilities in the portion of 

the Interconnection that is more 

susceptible to instability. 

293. Southern, ReliabilityFirst and 

MRO agree with staff that transmission 

operators who initiate load shedding 

pursuant to guidelines should be 

shielded from liability or retaliation. 

Southern states that it seems more 

appropriate to also address limitation of 

liability in each transmission owner’s 

OATT. Southern also submits that the 

role of the reliability coordinator as 

currently established under EOP–003–0 

is appropriate and is consistent with its 

role in maintaining reliability. Southern 

states that while the reliability 

coordinator should be aware of the 

restoration plan required by the 

Reliability Standard, approval of that 

plan would have no clear benefit. 

iv. Commission Proposal 

294. As discussed above, EOP–003–0 

does not specify the minimum loadshedding capability that should be 

provided and the maximum amount of 

delay before load shedding can be 

implemented. The Commission 

disagrees with MRO’s position that 

adding a minimum load shedding 

capability and timeframe will not 

improve the Reliability Standard 

because the Reliability Standard does 

not specify amount or timeframe to shed 

load. The actual amount of load to be 

shed, location and timeframe will be at 

the discretion of the system operator 

based on the nature of the system 

problem and his assessment of 

corrective actions required. However, if 

the capability to shed sufficient load in 

locations where it is required and in a 

timely manner is not available to the 

system operator then the risk of 

uncontrolled failure of system elements 

or cascading outages is increased due to 

no or delayed actions to shed load. The 

Commission agrees with MidAmerican 

that specifying a minimum capability 

and maximum allowable delay is 

necessary to ensure an adequate loadshedding plan to contain a disturbance 

and prevent system cascading. The 

Commission proposes that the 

Reliability Standard should be modified 

to address this matter. We recognize that 

this issue may be addressed on a 

regional basis if it meets the 

requirements for a regional difference as 

suggested by MidAmerican. 

295. Blackout Report 

Recommendation No. 8, which is 

addressed to ‘‘legislative bodies and 

regulators,’’ recommends that operators 

who initiate load shedding pursuant to 

approved guidelines should be shielded 

from ‘‘liability suits or other forms of 

retaliation, provided their action is 

pursuant to previously approved 

guidelines.’’ 155 Neither the Commission 

nor the ERO has authority under section 

215 of the FPA to shield operators from 

liability suits for actions that they take 

or fail to take. Further, the Commission 

believes that an added Requirement to 

shield operators from retaliation would 

be vague and beyond the scope of the 

Reliability Standard. As explained by 

NERC, the proposed Reliability 

Standards provide direction to operators 

on when they should manually initiate 

load shedding. The goal of EOP–003–0 

is to ensure that a transmission operator 

‘‘must have the capability and authority 

to shed load’’ and the Requirements 

provide the specifics on how this is to 

be achieved. We believe that this is 

sufficient to empower operators to take 

necessary action to ensure the reliability 

of the Bulk-Power System. The 

Commission notes that NERC has 

required each transmission operator 

post a letter from its CEO stating that 

there will be no retaliation against 

system operators that shed load in 

accordance with approved corporate 

policies and procedures. A review of 

such letters is included in NERC 

Readiness Reviews. The Commission 

believes that this is an acceptable 

approach. 

296. MRO concurs with staff that the 

Reliability Standard should require 

periodic drills of simulated load 

shedding. It suggests that NERC better 

identify the type of training that is 

required to include load shed drills. 

Load shedding drills will improve the 

operator response to emergencies, 

including timely implementation of 

load shedding. The Commission 

therefore proposes to direct the ERO to 

modify this Reliability Standard to 

require periodic drills of simulated load 

shedding. 

297. The Reliability Standard does not 

contain any Measures or Levels of NonCompliance. The Commission proposes 

that it be modified to address this 

deficiency. 

298. While the Commission has 

identified concerns with regard to EOP–

003–0, we believe that the proposal 

serves an important purpose in ensuring 

load-shedding plans are developed and 

that appropriate capability and 

authority for load shedding exists. As 

noted above, EPO–003–0 raises several 

issues that require NERC’s attention. 


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156On August 28, 2006, NERC submitted EOP–

005–1 for approval, which replaces EOP–005–0. 

EOP–005–1 is the same as EOP–005–0 except for 

the changes noted above. Thus, comments 

submitted in response to the Staff Preliminary 

Assessment on EOP–005–0 apply equally to EOP–

005–1. 

Nonetheless, the proposed 

Requirements set forth in EOP–003–0 

are sufficiently clear and objective to 

provide guidance for compliance. 

299. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard EOP–003–

0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to EOP–003–0 that (1) specifies the 

minimum load-shedding capability that 

should be provided and the maximum 

amount of delay before load shedding 

can be implemented; (2) requires 

periodic drills of simulated load 

shedding; and (3) contains Measures 

and Levels of Non-Compliance. 

e. Disturbance Reporting (EOP–004–0) 

i. NERC Proposal 

300. Proposed Reliability Standard 

EOP–004–0 establishes requirements for 

reporting system disturbances to the 

regional reliability organization and the 

ERO. It also establishes requirements for 

the analysis of these disturbances. NERC 

indicates that the Reliability Standard’s 

purpose is to minimize the likelihood of 

similar events in the future. NERC states 

that EOP–004–0 is linked to DOE 

disturbance reporting requirements and 

Energy Information Administration 

(EIA) Form 417. 

ii. Staff Preliminary Assessment 

301. Commission staff noted that 

EOP–004–0 does not address the 

Blackout Report’s recommendation that 

a standing framework be established for 

conducting future blackout and 

disturbance investigations. Staff noted 

that the U.S. Department of Energy 

(DOE) made a presentation to the NERC 

Board of Trustees on preparing for an 

investigation, priority actions following 

a blackout, and the investigation 

process. Staff also noted that NERC has 

prepared a procedure for responding to 

major events that affect the bulk electric 

system. Staff indicated it believes that 

the DOE presentation and the NERC 

procedure provide a reasonable basis for 

revising EOP–004–0. In addition, staff 

noted that the Reliability Standard does 

not contain any Measures or Levels of 

Non-Compliance. Staff acknowledged 

that NERC has indicated this deficiency 

will be addressed and that the 

Reliability Standard will be resubmitted 

for Commission approval in November 

2006. 

iii. Comments 

302. NERC states that procedures to 

conduct future blackout and disturbance 

investigations should not be included in 

the Reliability Standards. NERC states 

that it has developed these procedures 

and that they are provided as an 

appendix to its proposed ERO Rules of 

Procedure. 

303. MRO supports staff’s conclusion 

that this Reliability Standard does not 

address the Blackout Report’s 

recommendation that a standing 

framework be established for 

conducting future blackout and 

disturbance investigations. MRO 

maintains that NERC and the DOE 

procedures provide a formal process for 

investigating disturbances. 

iv. Commission Proposal 

304. The Commission agrees with the 

MRO that this Reliability Standard does 

not address the Blackout Report’s 

Recommendation No. 14 to establish a 

standing framework for conducting of 

future blackout and disturbance 

investigations and proposes that the 

Reliability Standard be modified to 

specify those requirements included in 

the ERO Rules of Procedure that apply 

to users, owners and operators of BulkPower System. NERC states that it has 

developed these procedures, and they 

are provided as an appendix to its 

proposed ERO Rules of Procedure. 

Although the Commission 

acknowledges that, under § 39.2 of our 

regulations, all users, owners and 

operators of the Bulk-Power System 

must comply with the ERO Rules, 

which includes its Rules of Procedure, 

we believe that requirements outlined in 

these procedures that apply to users, 

owners and operators of the Bulk-Power 

System must be included in this 

Reliability Standard, but not the rules of 

procedure themselves, so that they 

become mandatory and enforceable. The 

Commission believes that including 

these requirements in this Reliability 

Standard will promote system reliability 

by ensuring that users, owners and 

operators of the Bulk-Power System 

provide data to assist NERC 

investigations and ensuring that the 

Reliability Standard is clear and 

complete. Such requirements include 

the provision of system disturbance 

data, voice recordings and other 

information collected during the event 

to support the analysis of the event after 

the fact. Therefore, we propose to direct 

that NERC modify EOP–004–0 to 

include any requirements necessary for 

users, owners and operators of the BulkPower System to provide data that will 

assist NERC in the investigation of a 

blackout or disturbance. 

305. While the Commission has 

identified concerns with regard to EOP–

004–0, we believe that the proposal 

serves an important purpose in 

establishing requirements for reporting 

and analysis of system disturbances. 

While the Commission believes that 

additional Requirements are needed, the 

proposed Requirements set forth in 

EOP–004–0 are sufficiently clear and 

objective to provide guidance for 

compliance. 

306. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard EOP–004–

0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to EOP–004–0 that: (1) includes any 

requirements necessary for users, 

owners and operators of the Bulk-Power 

System to provide data that will assist 

NERC in the investigation of a blackout 

or disturbance; and (2) includes 

Measures and Levels of NonCompliance. 

f. System Restoration Plans (EOP–005–

1) 

i. NERC Proposal 

307. Proposed Reliability Standard 

EOP–005–1 156 deals with system 

restoration plans and requires that 

plans, procedures, and resources be 

available to restore the electric system to 

a normal condition in the event of a 

partial or total system shut down. The 

Reliability Standard requires 

transmission operators, balancing 

authorities, and reliability coordinators 

to have effective restoration plans, to 

test those plans, and to be able to restore 

the interconnection using them 

following a blackout. It also requires 

operating personnel to be trained in 

these plans. 

308. NERC’s August 28, 2006 

Supplemental Filing included a revised 

version of EOP–005, designated EOP–

005–1. The revised Reliability Standard 

includes two new Requirements, R9 and 


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157Requirement R1 provides that ‘‘[e]ach 

Transmission Operator shall have a restoration plan 

to reestablish its electric system in a stable and 

orderly manner in the event of a partial or total 

shutdown of its system, including necessary 

operating instructions and procedures to cover 

emergency conditions, and the loss of vital 

telecommunications channels. Each Transmission 

Operator shall include the applicable elements 

listed in Attachment 1–EOP–005–0 in developing a 

restoration plan.’’

R10, and two revised requirements, R4 

and R8. The new Requirement R9 

requires that the transmission operator 

document the cranking paths, including 

initial switching requirements, between 

each blackstart generating unit and the 

unit(s) to be started. The new 

Requirement R10 requires the 

transmission operator to demonstrate 

through simulation or testing, the 

blackstart units can perform their 

intended function and that simulation 

or testing be performed at least once 

every five years. The revised 

Requirement R4 requires the 

transmission operator to coordinate its 

restoration plans with the generator 

owners in addition to others. The 

revised Requirement R8 requires 

transmission operators to verify that the 

number, size, availability, and location 

of system blackstart generating units are 

sufficient to meet regional reliability 

organization restoration plan 

requirements for the transmission 

operator’s area. 

ii. Staff Preliminary Assessment 

309. Staff noted that, while EOP–005–

0 requires that operators be trained in 

the implementation of the restoration 

plan, it does not require this to be done 

periodically. In addition, the Reliability 

Standard contains Levels of NonCompliance but no Measures. Staff 

noted that NERC has not identified this 

Reliability Standard as one that would 

be modified and resubmitted for 

Commission approval in November 

2006. 

iii. Comments 

310. MRO comments that EOP–005–0 

should identify the timeframes for 

operator training and restoration plan 

review. National Grid comments that 

the Staff Preliminary Assessment does 

not offer any specific time interval over 

which periodic training of operators 

should occur and that the Commission 

and NERC should work together to 

establish a balanced training interval 

when establishing requirements for 

periodic training on restoration plan 

procedures. 

311. Alcoa states that two 

Requirements of EOP–005–0 either 

overlap with or are duplicative of 

Requirements contained in other 

proposed Reliability Standards, in 

particular COM–001–0. Alcoa states that 

any overlapping or duplicative 

requirements that can lead to multiple 

interpretations regarding compliance 

which could hinder system reliability. 

Alcoa suggests that the Reliability 

Standard can be improved by defining 

minimum requirements relating to the 

periodic monitoring of 

telecommunications facilities and by 

giving some attention to the technical 

requirements of ‘‘essential 

telecommunications facilities.’’

312. Alberta states that EOP–005–0 is 

an example of a Reliability Standard 

that should not be approved but should 

continue as a voluntary Reliability 

Standard unless it is determined that 

the Reliability Standard would have an 

adverse effect on system reliability. 

Alberta states that Requirement R1 of 

the Reliability Standard is missing 

elements—although it does not identify 

them—and lacks measurability, and it 

therefore should remain voluntary until 

it is revised.157

iv. Commission Proposal 

313. The Commission agrees with 

MRO and National Grid that the 

Reliability Standard should identify 

time frames for training, drills and 

review of restoration plan requirements 

to simulate contingencies and prepare 

operators for anticipated and unforeseen 

events. Periodic training, drills and plan 

review is necessary to ensure that the 

Reliability Standard effectively 

promotes Bulk-Power System reliability, 

and specific training and review time 

frames will enhance the effectiveness of 

the Reliability Standard. 

314. The Commission does not agree 

with Alcoa that the telecommunication 

testing requirements in COM–001–0 and 

EOP–005–0 can lead to multiple 

interpretations regarding compliance. 

315. The Commission believes that 

new Requirements R9 and R10 included 

in EOP–005–1 would contribute to 

maintaining or enhancing system 

reliability and therefore proposes to 

accept them. 

316. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard EOP–005–

0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to EOP–005–1 that (1) includes 

Measures; and (2) identifies time frames 

for training and review of restoration 

plan requirements to simulate 

contingencies and prepare operators for 

anticipated and unforeseen events. 

g. Reliability Coordination-System 

Restoration (EOP–006–0) 

i. NERC Proposal 

317. Proposed Reliability Standard 

EOP–006–0 deals with reliability 

coordination and system restoration. It 

establishes specific requirements for 

reliability coordinators during system 

restoration, and it states that reliability 

coordinators must have a coordinating 

role in system restoration to ensure that 

reliability is maintained during 

restoration and that priority is placed on 

restoring the Interconnection. 

ii. Staff Preliminary Assessment 

318. The Staff Preliminary 

Assessment noted that EOP–006–0 

requires only that reliability 

coordinators, which are the highest 

authority responsible for overall system 

restoration, are aware of the restoration 

plan of each transmission operator in its 

reliability coordination area, but it does 

not require that they be involved in the 

plan’s development or approval. Staff 

also noted that the Reliability Standard 

does not contain any Measures, metrics 

or processes to assess compliance with 

its requirements or any Levels of NonCompliance. Staff acknowledged that 

NERC has indicated that the Reliability 

Standard will be modified to address 

these deficiencies and resubmitted for 

Commission approval in November 

2006. 

iii. Comments 

319. NERC states that Requirement R3 

of EOP–006–0 requires the reliability 

coordinator to have an area restoration 

plan. NERC asserts that the reliability 

coordinator will have input into the 

transmission operators’ restoration 

plans to ensure those plans are 

coordinated. NERC acknowledges that 

there may be merit in requiring 

reliability coordinators to approve the 

restoration plans. 

320. MRO agrees with staff in that 

reliability coordinators should be 

required to be involved in the 

development and approval of 

restoration plans. MRO supports the 

inclusion of Measures and Levels of 

Non-Compliance. 

321. Southern submits that the role of 

the reliability coordinator as currently 

established is appropriate and is 

consistent with the role of the reliability 

coordinator in maintaining reliability. It 

states that while the reliability 

coordinator should be aware of the 


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158EEI Comments at 10. 

restoration plan required by the 

Reliability Standard, approval of that 

plan would have no clear benefit. 

iv. Commission Proposal 

322. The Commission agrees with 

MRO and NERC that the reliability 

coordinators should be involved in the 

development and approval of the 

restoration plans. The reliability 

coordinator’s position as the highest 

authority responsible for system 

reliability and system restoration 

justifies its involvement in the 

development and approval of these 

plans. The Commission thus disagrees 

with Southern that the reliability 

coordinator’s involvement would have 

no clear benefit. The Commission 

proposes that the Reliability Standard 

be modified to require that the 

reliability coordinator be involved in 

the development and approval of 

restoration plans. The Commission also 

proposes to direct NERC to include 

Measures and Levels of Noncompliance. 

323. While the Commission has 

identified concerns with regard to EOP–

006–0, we believe that the proposal 

serves an important purpose in 

promoting reliability coordination and 

system restoration. Further, the 

proposed Requirements set forth in 

EOP–006–0 are sufficiently clear and 

objective to provide guidance for 

compliance. Accordingly, giving due 

weight to the technical expertise of the 

ERO and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard EOP–006–

0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, we propose to direct that 

NERC submit a modification to EOP–

006–0 that: (1) requires that the 

reliability coordinator be involved in 

the development and approval of 

restoration plans; and (2) includes 

Measures and Levels of NonCompliance. 

h. Establish, Maintain, and Document a 

Regional Blackstart Capability Plan 

(EOP–007–0) 

i. NERC Proposal 

324. NERC states that proposed 

Reliability Standard EOP–007–0, which 

deals with establishing, maintaining and 

documenting regional blackstart 

capability plans, ensures that the 

quantity and location of system 

blackstart generators are sufficient and 

that they can perform their expected 

functions as specified in the overall 

coordinated regional system restoration 

plans. 

ii. Staff Preliminary Assessment 

325. Staff noted in the Staff 

Preliminary Assessment that Reliability 

Standard EOP–007–0 lists only the 

regional reliability organization as the 

applicable entity and stated that the 

appropriateness of designating the 

regional reliability organization as the 

applicable entity is a concern in the new 

mandatory Reliability Standard 

structure. 

iii. Comments 

326. ReliabilityFirst states that the 

blackstart procedures developed by the 

individual regions need to be merged to 

develop consistent procedures. 

327. EEI states that, for the most part, 

the Reliability Standard involves 

collection management and reporting 

requirements, although it notes that 

blackstart generation plans have 

reliability operation implications. MRO 

expresses concern that EOP–007–0 is an 

operating function rather than a 

Reliability Standard. MRO states that if 

EOP–007–0 remains a Reliability 

Standard, it should be revised to require 

that operating entities have a restoration 

and blackstart capability plan, and EEI 

states that it should be redrawn so that 

compliance obligations are assigned 

directly to those entities that provide 

the data and other information. In 

addition, MRO states that the regional 

reliability organization should be 

removed as an applicable entity. 

iv. Commission Proposal 

328. Consistent with our discussion in 

the Common Issues section above, the 

Commission will not propose to accept 

or remand EOP–007–0, as it applies 

only to regional reliability 

organizations. The Commission believes 

that, in the long-run, the Regional 

Entities should be responsible for 

establishing, maintaining and 

documenting regional blackstart 

capability plans. However, during the 

current period of transition, the regional 

reliability organizations should 

continue to perform this role as they 

have in the past. 

i. Plans for Loss of Control Center 

Functionality (EOP–008–0) 

i. NERC Proposal 

329. Proposed Reliability Standard 

EOP–008–0 deals with plans for loss of 

control center functionality. It requires 

that each reliability coordinator, 

transmission operator and balancing 

authority have a plan to continue 

reliable operations and to maintain 

situational awareness in the event its 

control center is no longer operable. 

ii. Staff Preliminary Assessment 

330. Staff noted that EOP–008–0 

requires the applicable entities to have 

a backup plan, but it does not 

specifically require that backup 

capabilities be provided. The Reliability 

Standard does not address requirements 

for independence from the primary 

control center, provide for prolonged 

operation or provide the minimum tools 

and facilities consistent with the roles, 

responsibilities and tasks of the 

different entities to which it applies. 

iii. Comments 

331. NERC agrees with Commission 

staff that the proposed Reliability 

Standard does not adequately address 

the requirements for backup of critical 

control center functionality, and it 

proposes that such a Reliability 

Standard should be developed. NERC 

states that the possible solutions for 

providing backup of critical Bulk-Power 

System operating functionality are not 

limited to a redundant control center. 

Neighboring systems can provide such 

functionality as contracted services, or 

they can be provided through backup 

equipment within a separate existing 

facility. 

332. EEI supports EOP–008–000 as 

technically sound. It states that the 

Reliability Standard requires 

implementation of the plan by defining 

as a Level 4 violation a failure to 

implement the plan. This clearly 

establishes that backup capabilities 

must exist as reflected in the plan. 

According to EEI, entities must have 

communications facilities that do not 

rely on the primary control center; and 

that procedures must be in place for 

monitoring and controlling critical 

facilities, and for maintaining voice 

communications capability with other 

areas.158

333. MRO, ReliabilityFirst and the 

ISO/RTO Council agree with staff’s 

evaluation of EOP–008–0. MRO states 

that this Reliability Standard requires a 

backup plan, but does not address the 

requirements for independence from the 

primary control center, does not provide 

for prolonged operation, does not 

provide the minimum tools and 

facilities consistent with the roles, 

responsibilities and tasks of the 

different entities. MRO suggests that 

NERC should modify this Reliability 

Standard accordingly. MRO notes that 

today many companies simply have a 

plan and do not have an actual backup 


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159Facilities examples include 

telecommunications, backup power supplies, 

computer systems, and security systems 

facility. It states that the new 

requirements would have to take effect 

at some time in the future and that this 

Reliability Standard needs to make clear 

that the backup site should be capable 

of withstanding anticipated disasters, 

such as the hurricanes in Florida. 

ReliabilityFirst states that EOP–008–0 

should include additional detail on 

dealing with prolonged primary control 

center inoperability. The ISO/RTO 

Council states that meeting the 

shortcomings staff identified in EOP–

008–0 will require identification of 

minimum required tools and facilities 

and definition of the appropriate 

entities responsibilities. 

iv. Commission Proposal 

334. Staff raised the concern that 

EOP–008–0 requires the applicable 

entities to have a backup plan, but it 

does not specifically require that backup 

capabilities be available. EEI comments 

that the Reliability Standard implicitly 

requires backup capabilities because a 

Level 4 violation occurs when an entity 

fails to implement such a plan. The 

Commission disagrees with EEI that 

such a Requirement can be discerned 

from Level 4 Non-Compliance. As we 

explained in our policy discussion in 

Measures and Levels of NonCompliance, NERC has stated that the 

‘‘Requirements’’ within a Reliability 

Standard define what an entity must do 

to be compliant and establish an 

enforceable obligation, and the presence 

or absence of Measures or Levels of 

Non-Compliance should not be the sole 

determining factor as to whether a 

Reliability Standard meets the statutory 

test for approval. 

335. Thus, the Commission believes 

that provision for backup capabilities 

should be an explicit Requirement. 

Such backup capability, at a minimum, 

must: (1) Be independent of the primary 

control center; (2) be capable of 

operating for a prolonged period of time; 

and (3) provide for a minimum set of 

tools and facilities to replicate the 

critical reliability functions of the 

primary control center.159 The 

Commission proposes that NERC 

modify the standard accordingly. In 

addition to the three capability 

requirements identified above, the 

Commission is interested in comments 

from industry concerning other specific 

capabilities. 

336. The Commission understands 

that backup control facilities can be 

costly but, when needed, are essential 

for reliability. To address the balance 

between cost and reliability benefits, 

there needs to be some flexibility on 

how the capability is achieved. For 

example, the mechanism to provide 

these capabilities may include building 

fully redundant physical back up 

control centers or, as NERC suggests, 

contracting back up control services or 

through backup equipment within a 

separate existing facility. However, the 

Commission proposes that the extent of 

the backup capability be consistent with 

the impact of the loss of the entity’s 

primary control center on the reliability 

of the Bulk-Power System. Further, the 

Commission proposes to direct NERC to 

modify the standard to include a 

Requirement that all reliability 

coordinators have full backup control 

centers since they are essential to BulkPower System reliability. In addition, 

the Commission is interested in 

comments on what other entities should 

have full backup centers for reliability 

such as balancing authorities and large 

transmission operators. 

337. While the Commission has 

identified concerns with regard to EOP–

008–0, we believe that the proposal 

serves an important purpose in ensuring 

that applicable entities have a backup 

plan in the case of loss of control center 

functionality. While the Commission 

believes that additional Requirements 

are needed, the proposed Requirements 

set forth in EOP–008–0 are sufficiently 

clear and objective to provide guidance 

for compliance. Accordingly, giving due 

weight to the technical expertise of the 

ERO and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard EOP–008–

0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, we propose to direct that 

NERC submit a modification to this 

Reliability Standard that includes a 

Requirement that provides for backup 

capabilities, as described above. 

j. Documentation of Blackstart 

Generating Unit Tests Results (EOP–

009–0) 

i. NERC Proposal 

338. Proposed Reliability Standard 

EOP–009–0 deals with documentation 

of blackstart generating unit test results. 

NERC states that this Reliability 

Standard ensures that the quantity and 

location of system blackstart generators 

are sufficient and that these generators 

can perform their expected functions as 

specified in overall coordinated regional 

system restoration plans. 

ii. Staff Preliminary Assessment 

339. Staff noted in the Staff 

Preliminary Assessment that this 

Reliability Standard requires that the 

start-up and operation of each 

generating blackstart unit be tested and 

that the results be submitted to the 

regional reliability organization. 

However, it does not require that 

blackstart units be periodically tested to 

ensure that they will be available when 

required to restore the system. 

iii. Comments 

340. NERC and other commenters 

point out that Reliability Standard EOP–

007–0 requires the routine testing, i.e., 

minimum testing of one-third of 

blackstart units each year, suggested by 

staff. 

iv. Commission Proposal 

341. The Commission is satisfied with 

the explanation of NERC and other 

commenters that Reliability Standard 

EOP–007–0 requires periodic testing of 

blackstart units. 

342. The Commission believes that 

the proposal serves an important 

purpose in ensuring adequate blackstart 

generation capability. Further the 

proposed Requirements set forth in 

EOP–009–0 are sufficiently clear and 

objective to provide guidance for 

compliance. Accordingly, the 

Commission believes that Reliability 

Standard EOP–009–0 is just, reasonable, 

not unduly discriminatory or 

preferential, and in the public interest; 

and proposes to approve it as mandatory 

and enforceable. 

5. FAC: Facilities Design, Connections, 

Maintenance, and Transfer Capabilities 

a. Overview 

343. The nine Facility (FAC) 

Reliability Standards address topics 

such as facility connection 

requirements, facility ratings, system 

operating limits, and transfer 

capabilities. The standards also 

establish requirements for maintaining 

equipment and rights-of-way, including 

vegetation management. 

344. How transmission local control 

centers are incorporated into the 

transmission operator definition will be 

the same as is described in the COM 

Chapter. 

b. Facility Connection Requirements 

(FAC–001–0) 

i. NERC Proposal 

345. Proposed Reliability Standard 

FAC–001–0 is intended to ensure that 


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160Standard TPL–001–0 (Requirement 1 states 

that ‘‘The Planning Authority and Transmission 

Planner shall each demonstrate through a valid 

assessment that its portion of the interconnected 

transmission system is planned such that, with all 

transmission facilities in service and with normal 

(pre-contingency) operating procedures in effect, 

the Network can be operated to supply projected 

customer demands * * *’’). 

161Standardization of Generator Interconnection 

Agreements and Procedures, Order No. 2003, 68 FR. 

49845 (Aug. 19, 2003), FERC Stats. & Regs. ¶ 31,146 

(2003), order on reh’g, Order No. 2003–A, 69 FR 

15932 at P 89 and 145 (Mar. 26, 2004), FERC Stats. 

& Regs. ¶ 31,160 (2004), order on reh’g, Order No. 

2003–B, 70 FR 265 (Jan. 4, 2005), FERC Stats. & 

Regs. ¶ 31,171 (2004), order on reh’g, Order No. 

2003–C, 70 FR 37661 (June 30, 2005), FERC Stats. 

& Regs. ¶ 31,190 (2005); see also Notice Clarifying 

Compliance Procedures, 106 FERC 1,009 (2004). 

transmission owners establish facility 

connection and performance 

requirements to avoid adverse impacts 

to the Bulk-Power System. 

ii. Staff Preliminary Assessment 

346. The Staff Preliminary 

Assessment did not identify any issues 

related to this Reliability Standard. 

iii. Comments 

347. No specific comments were 

received. 

iv. Commission Proposal 

348. This Reliability Standard is 

necessary to ensure standard procedures 

and performance assessments for new 

interconnection facilities. Further, the 

Requirements in FAC–001–0 are 

sufficiently clear and objective to 

provide guidance for compliance. Thus, 

the Commission proposes to approve 

Reliability Standard FAC–001–0 as just, 

reasonable, not unduly discriminatory 

or preferential, and in the public 

interest. 

c. Coordination of Plans for New 

Generation, Transmission, and End-User 

Facilities (FAC–002–0) 

i. NERC Proposal 

349. Proposed Reliability Standard 

FAC–002–0 requires that each 

generation owner, transmission owner, 

distribution provider, load-serving 

entity, transmission planner, and 

planning authority assess the impact of 

integrating generation, transmission, 

and end-user facilities into the 

interconnected transmission system. 

ii. Staff Preliminary Assessment 

350. Requirement R1 of FAC–002–0 

requires system performance 

assessments in accordance with 

Standard TPL–001–0,160 which relates 

only to normal system conditions. Staff 

pointed out that performance 

requirements for new generation 

interconnection in Order No. 2003 161

require assessment for both normal and 

post-contingency conditions and is 

therefore more rigorous than TPL–001–

0. 

iii. Comments 

351. NERC comments that, while the 

staff evaluation of FAC–002–0 is valid, 

the Reliability Standard should 

nonetheless be approved. NERC offers 

that it will continue to improve the 

Reliability Standard. Likewise, MRO 

and ISO/RTO Council agree with staff’s 

evaluation of FAC–002–0. MRO adds 

that an effort should be made to align or 

combine the requirements of Order No. 

2003 and the NERC Reliability 

Standards into a single set of standards. 

ISO/RTO Council expresses concern 

that the Reliability Standard does not 

identify parties responsible for 

particular tasks, stating that it should be 

reviewed to ensure that tasks are 

correctly assigned. 

352. NERC and others state that 

Requirement R1 of FAC–002–0 should 

require not only the use of TPL–001–0, 

but also TPL–002–0, and TPL–003–0. 

Similarly, ReliabilityFirst believes that 

FAC–002–0 contains an error in 

Requirement R1.4. It alleges that the 

requirement should have been 

translated to refer to standards TPL–

001–0 through TPL–004–0 instead of 

only referencing TPL–001–0. Similarly, 

ISO/RTO Council submits that 

Requirements R1.1 through R1.5 need to 

include a reference to standard TPL–

002–0. 

353. Alcoa points out that 

Requirements R1.1 and R1.2 lack 

metrics. Alcoa asserts that these 

Requirements are broadly-worded, 

open-ended and suggest that even a 

small addition of facilities would 

compel an entity to comply with all of 

the Reliability Standards, which might 

not otherwise apply. 

354. CenterPoint contends that 

coordination cannot be audited with an 

objective auditable measure and 

recommends that this standard be 

eliminated. CenterPoint notes tradeoffs 

involved in planning interconnections 

for generators can put transmission 

service providers at risk for either 

accusation by the ERO of failing to 

provide adequate facilities or accusation 

by state commissions of ‘‘gold-plating,’’

or not performing proper generation 

interconnection planning. CenterPoint 

adds that although staff has discussed 

planning for the most onerous 

conditions, real-life application of this 

is more complex because it needs to be 

based on the reasoned judgment of 

experts considering particular facts as 

opposed to rigid standards. 

355. MEAG asserts that including 

distribution providers in FAC–002–0 is 

unnecessarily redundant and potentially 

overbroad because the Reliability 

Standard should not apply to 

distribution providers that do not own 

generation or transmission facilities. It 

explains that, if a distribution provider 

owns facilities that are integral to the 

transmission system, then the 

distribution provider is also a 

transmission owner, according to the 

‘‘NERC glossary of Terms Used in 

Reliability Standards.’’ Likewise, if a 

distribution provider owns generating 

facilities, then the distribution provider 

is a generator owner. However, if each 

load-serving entity provides the 

transmission owner with its load 

characteristics and the distribution 

provider does not own integral 

generation or transmission facilities, 

then MEAG concludes that FAC–002–0 

should not apply to such distribution 

providers. 

iv. Commission Proposal 

356. The Commission agrees with 

NERC and others that the Reliability 

Standard should refer not only to TPL–

001, but also to TPL–002–0 and TPL–

003–0, which relate to loss of one or 

more Bulk-Power System elements. This 

would improve the technical soundness 

of the Reliability Standard by 

appropriately broadening the scope of 

system performance assessments to 

include post-contingency conditions. In 

addition, such a modification would 

achieve greater consistency with Order 

No. 2003. Thus, we propose to direct 

that NERC modify FAC–002–0 

accordingly. 

357. Requirements R1.1 and R1.2 

provide that an applicable entity 

seeking to integrate generation, 

transmission and end-user facilities 

must perform an assessment that 

includes: An evaluation of the reliability 

impact of the new facilities and their 

connections on the interconnected 

transmission systems (R1.1) and 

‘‘ensurance of compliance with NERC 

Reliability Standards’’ and other 

applicable criteria (R1.2). While we 

agree with Alcoa that Requirements 

R1.1 and R1.2 lack corresponding 

metrics, we disagree that these 

Requirements are overly-broad or openended. Nor do we read Requirement 

R1.2 as suggesting that even a small 

addition of facilities would compel an 

entity to comply with all of the 

Reliability Standards, which might not 

otherwise apply. Rather, we believe that 

the Requirements and existing Measures 

set forth in FAC–002–0 are sufficiently 

clear and objective to provide guidance 

for compliance. 

358. The Commission disagrees with 

CenterPoint’s comments that because 


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162Standard FAC–003–1 (Requirement R1.2.2). 

163 Institute of Electrical and Electronics 

Engineers, Inc. Standard 516–2003, IEEE Guide for 

Maintenance Methods on Energized Power Lines at 

1 (July 29, 2003) (IEEE 516–2003). 

164 Id. at 20. 

165ANSI Z133, American National Standards 

Institute Standard for Tree Care Operations—

Pruning, Trimming, Repairing, Maintaining and 

Removing Trees, and Cutting Brush—Safety 

Requirements. 

166Blackout Report at 154. 

coordination is not readily auditable, 

the Reliability Standard should be 

eliminated. The Reliability Standard 

specifies the assessments that must be 

carried out to demonstrate that facility 

connections meet reliability 

performance requirements. Furthermore 

the Reliability Standard specifies that 

the assessment studies must be jointly 

evaluated by the entities involved and 

that evidence of such coordination shall 

be provided. Coordination provides 

assurance of a fair, equitable and 

comprehensive Interconnection process, 

which is the basis for open access and 

is required to avoid adverse impacts on 

reliability. 

359. The Commission disagrees with 

MEAG’s comment that the inclusion of 

distribution providers is redundant and 

unnecessary. The NERC definition 

clearly identifies the role of the 

distribution provider as providing the 

‘‘wires’’ connecting the transmission 

system to the end use customer. FAC–

002–0 has a reliability goal of avoiding 

adverse impacts on Interconnections, 

including a number of types of end-user 

facilities. Because the distribution 

provider has responsibility at the 

interface between the transmission and 

distribution system, it is proper that 

FAC–002–0 include Requirements to 

address those responsibilities. 

360. The Commission agrees with the 

ISO/RTO Council that the Reliability 

Standard does not identify functional 

entities responsible for specific tasks. 

The Commission understands that the 

roles and responsibilities of the 

transmission planner and planning 

authority in carrying out the tasks are in 

accordance with the definitions in the 

NERC glossary. Since the Commission 

has previously approved the division of 

responsibilities in various tariffs, the 

exact delegation of individual tasks is 

better placed in the procedures manuals 

than in the Reliability Standard. 

361. While the Commission has 

identified concerns with regard to FAC–

002–0, we believe that the proposal 

serves an important purpose in ensuring 

that generator owners, transmission 

owners and end-users meet facility 

connection and performance 

requirements. We note that the 

Reliability Standards contains Measures 

and Levels of Non-Compliance. Further, 

the proposed Requirements set forth in 

this Reliability Standard are sufficiently 

clear and objective to provide guidance 

for compliance. 

362. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard FAC–002–

0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to FAC–002–0 that amends Requirement 

R1.4 to require evaluation of system 

performance under both normal and 

contingency conditions by referencing 

TPL–001 through TPL–003. 

d. Transmission Vegetation 

Management Program (FAC–003–1) 

i. NERC Proposal 

363. NERC stated that proposed 

Reliability Standard FAC–003–1 is 

designed to minimize transmission 

outages from vegetation located on or 

near transmission rights-of-way by 

maintaining safe clearances between 

transmission lines and vegetation, and 

establish a system for uniform reporting 

of vegetation-related transmission 

outages. FAC–003–1 applies to 

transmission lines operated at 200 kV or 

higher voltage (and lower-voltage 

transmission lines which have been 

deemed critical to reliability by a 

regional reliability organization). The 

Reliability Standard requires each 

transmission owner to have a 

documented vegetation management 

program in place, including records of 

its implementation. Each program must 

be designed for the geographical area 

and specific design configurations of the 

transmission owner’s system. 

364. This Reliability Standard 

requires a transmission owner to define 

a schedule for and the type (aerial or 

ground) of right-of-way vegetation 

inspections. In addition, it requires a 

transmission owner to determine and 

document the minimum allowable 

clearance between energized conductors 

and vegetation before the next trimming, 

and it specifically provides that 

‘‘Transmission-Owner-specific 

minimum clearance distances shall be 

no less than those set forth in the 

Institute of Electrical and Electronics 

Engineers (IEEE) Standard 516–2003 

(IEEE Guide for Maintenance Methods 

on Energized Power Lines).’’ 162

365. Compliance with this standard is 

measured against four Levels of NonCompliance. Levels 1 and 2 relate to 

documentation. Level 3 non-compliance 

occurs if a transmission owner reports 

one incident of vegetation-related 

outage in a calendar year due to 

vegetation grow-ins from inside or 

outside the right of way. If the 

transmission owner reports more than 

one vegetation-related outage, then 

Level 4 non-compliance has occurred. 

ii. Staff Preliminary Assessment 

366. Staff expressed concern that the 

Reliability Standard does not designate 

maximum allowable inspection 

intervals but, instead, allows each 

transmission owner to define its 

inspection schedule and maintain its 

own program. Thus, a transmission 

owner cannot be faulted for the length 

of its inspection interval, provided that 

it has defined the schedule in its formal 

program. 

367. Staff also expressed concern with 

the Reliability Standard’s development 

of a minimum clearance, i.e., the 

distance between a wire and the 

vegetation around it, based on IEEE 

standard 516–2003 that was developed 

with the primary purpose of enabling 

the performance of safe, energized line 

maintenance.163 IEEE 516–2003 

specifies a 2.45-foot clearance from a 

live conductor for the 120 kV voltage 

class.164 Staff noted that this clearance 

is lower than that specified by relevant 

U.S. safety codes such as the ANSI Z–

133 standard, which specifies 12-feet, 4- 

inches as the approach distance for the 

115 kV voltage class.165

368. Staff expressed concern that use 

of the IEEE clearance provision as a 

basis for minimum clearance may not be 

appropriate, and adopting it for use with 

regular maintenance practices in 

vegetation management may be a 

‘‘lowest common denominator’’

approach. In addition, use of IEEE 

Standard 516–2003 could create the 

unintended consequence that some 

transmission owners that currently 

maintain more stringent vegetation 

management programs based on 

standards such as the ANSI Z–133 may 

relax their practices to meet the lessstringent minimum requirement set 

forth in the NERC vegetation 

management standard FAC–003–1. Staff 

questioned whether the Reliability 

Standard sufficiently addresses 

Recommendation No. 16 of the Blackout 

Report to establish ‘‘enforceable 

standards for maintenance of electrical 

clearances in right-of-way areas.’’ 166


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167NERC Comments at 31. 168 ‘‘Clearance 1’’ is the clearance distance 

between vegetation and a transmission line to be 

achieved at the time of vegetation management 

work, and ‘‘clearance 2’’ is the minimum clearance 

distance between vegetation and a transmission line 

to be achieved at all times. FAC–003–1 defines 

‘‘clearance 2’’ in Requirement R1.2.2 as ‘‘The 

Transmission Owner shall determine and document 

specific radial clearances to be maintained between 

vegetation and conductors under all rated electrical 

operating conditions. These minimum clearance 

distances are necessary to prevent flashover 

between vegetation and conductors and will vary 

due to such factors as altitude and operating 

voltages. These Transmission Owner-specific 

minimum clearance distances shall be no less than 

those set forth in the [IEEE] Standard 516–2003 

* * * and as specified in its Section 4.2.2.3, 

Minimum Air Insulation Distances without Tolls in 

the Air Gap.’’

169E.g., EEI, Mid-American, National Grid, 

NRECA, PG&E, and Southern. 

170E.g., Allegheny, CenterPoint, EEI, MRO, 

National Grid, NRECA, NYSPUC, SCE, and 

Southern. 

171E.g., CenterPoint, National Grid, ISO/RTO 

Council and Southern. 

172EEI Comments at 8. 

iii. Comments 

369. NERC contends that FAC–003–1 

is an excellent standard that sets 

appropriate requirements for managing 

vegetation in transmission rights-ofway. NERC and other commenters 

address four key issues: (1) Adequacy of 

minimum clearances; (2) the need to 

specify maximum inspection intervals; 

(3) no vegetation-related outage can 

occur without also violating the 

proposed Reliability Standard; and (4) 

cost impact of expanding the minimum 

clearances. 

370. Adequacy of minimum 

clearances: NERC explains the adoption 

of minimum clearance distances based 

on the standard IEEE 516–2003 is 

appropriate because, even though the 

standard was originally developed for 

live line workers, ‘‘its engineering basis 

applies electric flashover physics that 

apply to flashover conditions between 

an energized conductor and a grounded 

object, such as a tree.’’ 167 NERC adds 

that the minimum clearances identified 

in the standard are the ‘‘second’’

clearance requirement.168 In the first 

instance, a transmission owner must 

develop wider clearances when 

accounting for vegetation growth, line 

dynamics and other conditions between 

the times of tree pruning. 

371. Similar to NERC’s view on the 

adequacy of minimum clearances, 

several commenters argue that the IEEE 

516–2003 standard is an appropriate 

standard for use in FAC–003–1.169

Southern indicates that full compliance 

with this standard would help to ensure 

line reliability consistent with the 

purposes of this standard and therefore 

believes the use of the IEEE standard is 

appropriate for use as a minimum 

acceptable clearance in this context. 

CenterPoint states that ‘‘clearance 2,’’

i.e., the minimum distance in FAC–003–

1, must be maintained under all rated 

electrical operating conditions and must 

consider additional clearance for the 

dynamic movement of the transmission 

conductors to avoid vegetation related 

outages. According to CenterPoint, the 

derived values from the IEEE table serve 

only as a theoretical minimum for static 

situations. 

372. Conversely, ReliabilityFirst 

submits that it agrees with staff’s 

evaluation of standard FAC–003–1 

regarding the appropriateness of using 

the IEEE standard. SCE believes that the 

adoption of IEEE 516–2003 in FAC–

003–1 to establish ‘‘specific radial 

clearances to be maintained between 

vegetation and conductors under all 

rated electrical operating conditions’’ is 

wholly inappropriate when determining 

minimum tree-to-line clearances. SCE 

states that no scientific evidence was 

ever presented or cited during the NERC 

standard development process that 

demonstrated vegetation represented a 

greater or equal flash-over hazard in 

comparison to the human body (i.e., a 

qualified electrical worker) when placed 

in proximity to transmission lines. SCE 

recommends that NERC establish a new 

minimum clearance for transmission 

lines operated at 200 kV and above and 

that studies be conducted so that these 

new minimum clearances be based on 

real-world knowledge and line clearing 

expertise, as opposed to simply 

appropriating standards that were 

designed for other situations. 

373. Inspection Cycle: With regard to 

a maximum allowable inspection cycle, 

NERC believes FAC–003–1 

appropriately provides discretion to 

transmission owners to develop 

vegetation inspection cycles appropriate 

for their respective systems. Several 

commenters argue that staff’s concern 

that FAC–003–1 does not designate 

maximum allowable inspection 

intervals fails to recognize varying types 

of vegetation, growth rates and climates 

throughout North America.170 Some 

commenters consider staff’s comment 

on maximum allowable inspection 

intervals as a ‘‘one size fits all’’

approach to vegetation management and 

advise that such an approach to 

inspection intervals could result in the 

lowest common denominator among all 

regions throughout the country or 

unfairly punish or financially burden 

certain regions. Allegheny proposes as 

an alternative that maximum inspection 

intervals could vary between Regional 

Entities and notes that there might need 

to be variations of the maximum 

interval within a Regional Entity that is 

geographically diverse. 

374. Performance measure: NERC 

states that no vegetation-related 

transmission line outage can occur 

without also being a violation of the 

standard. NERC expresses the view that, 

if such outages do occur, the 

transmission owner has violated the 

standard, and the solution is to engage 

in compliance enforcement actions 

rather than developing a wider margin 

of clearance. Several commenters 

concur with NERC on this point and 

assert that staff’s concerns with regard 

to maximum inspection intervals and 

minimum clearances would not be an 

issue if a vegetation management 

standard measured and used 

performance as a metric.171 Southern 

points out that FAC–003–1 utilizes 

outage reporting to measure the 

effectiveness of an entity’s vegetation 

management program and suggests that 

the performance metric will expose the 

standard’s shortcomings which can then 

be addressed through a revision of the 

standard. 

375. Cost of compliance: Finally, 

NERC and others express concern that 

expanding the minimum clearances 

could increase workload and costs yet 

not provide any added reliability 

benefit. Regarding the issue on 

increased costs to maintain greater 

minimum clearances versus reliability 

benefits, EEI points out that ‘‘flexibility 

written into the standard recognizes that 

fixed clearance distances will not 

provide stronger protection of the grid, 

and are certain to cause significant 

additional costs,’’ yet recognizes the 

need to prevent cost-based incentives 

which might drive the Reliability 

Standard toward a lowest common 

denominator.172

376. USDA Forest Service expresses 

concern with regard to the manner in 

which the requirements of EPAct 2005 

are being applied. In particular, utilities 

are submitting vegetation management 

standards to the Commission for use on 

National Forest System lands that were 

not first approved by the USDA Forest 

Service. It adds that it objects to any 

process that allows a utility to set its 

own new vegetation management 

standards independently and to any 

interpretation of EPAct 2005 that would 

diminish the USDA Forest Service’s 

authority to approve new vegetation 

management standards on Forest 

Service lands. 


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173FAC–003–1, Requirement R1.2. 

174FAC–003–1, Requirement R1.2.2 (emphasis 

added). 

175NERC Comments at 32. 

176 IEEE 516–2003 at 20. Further, IEEE 516–2003 

defines ‘‘standard atmospheric conditions’’ as 

temperatures above freezing, wind less than 24 

kilometer per hour, unsaturated air, normal 

barometer, uncontaminated air, and clean and dry 

insulators.’’

177Nothing in this Reliability Standard should be 

interpreted as preempting the authority and 

responsibility of the states to set and enforce 

minimum clearances, such as those delineated in 

the National Electric Safety Code, to protect the 

safety of the public. 

178The data provided in the survey was used to 

prepare a report to Congress, Federal Energy 

Regulatory Commission, Utility Vegetation 

Management and Bulk Electric Reliability Report, 

(September 7, 2004) (Vegetation Management 

Report). 

179 Id. at 11. The Vegetation Management Report 

indicates that 29 entities conduct ground 

inspections semi-annually or more frequently, 37 

entities inspect less frequently than annually, 12 

inspect on an ‘‘as needed’’ basis, and seven entities 

did not report on their inspection cycle. 

iv. Commission Proposal 

377. Giving due weight to the 

technical expertise of the ERO and with 

the expectation that the Reliability 

Standard will accomplish the purpose 

represented to the Commission by the 

ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard FAC–003–

1. In addition, pursuant to section 

215(d)(5) of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

modify the Reliability Standard, as 

discussed below. 

(a) Adequacy of Minimum Clearances 

378. NERC and others support the 

proposed minimum ‘‘clearance 2’’

distances based on IEEE 516–2003 as 

appropriate for use in vegetation 

management. The Commission believes 

that clearance distances need to exceed 

IEEE 516–2003’s requirements in many 

circumstances, but should never be less 

than these requirements. The 

Commission is concerned that the 

application of the IEEE requirement 

without consideration of specific 

circumstances may result in flashovers, 

and this possibility appears to be 

addressed in IEEE 516–2003 and the 

vegetation management standard. 

Specifically, FAC–003–1 provides that a 

transmission owner must ‘‘identify and 

document clearances between 

vegetation and [conductors] taking into 

consideration transmission line voltage, 

the effects of ambient temperature on 

conductor sag under maximum design 

loading, and the effects of wind 

velocities on conductor sway.’’ 173 In 

addition, the Reliability Standard 

provides: 

The Transmission Owner shall determine 

and document specific radial clearances to be 

maintained between vegetation and 

conductors under all rated electrical 

operating conditions. These minimum 

clearance distances are necessary to prevent 

flashover between vegetation and conductors 

and will vary due to such factors as altitude 

and operating voltages.’’ 174

379. Consistent with the notion that 

the minimum clearance may vary due to 

various factors, NERC states that the 

transmission owners must develop 

wider clearances when accounting for 

vegetation growth, line dynamics and 

other conditions between the times of 

tree pruning.175 In addition, IEEE 516–

2003 makes clear that the stated 

minimum clearances are based on 

‘‘standard’’ atmospheric conditions and 

‘‘if standard atmospheric conditions do 

not exist, extra care must be taken.’’ 176

380. NERC’s comments, IEEE 516–

2003, and the vegetation management 

standard itself all make clear that the 

minimum ‘‘clearance 2’’ distances based 

on IEEE 516–2003 are adequate in some, 

but not all, circumstances. The 

minimum clearances that a transmission 

owner must identify and document 

depend on a variety of conditions 

including, but not limited to, 

transmission line voltage, temperature, 

wind velocities, altitude. Accordingly, 

we interpret the FAC–003–1 to require 

trimming that is sufficient to prevent 

outages due to vegetation management 

practices under all applicable 

conditions.177

381. In response to the USDA Forest 

Service’s comments, we believe that any 

potential issues regarding minimum 

clearances on National Forest Service 

lands should be dealt with on a case-bycase basis. The Commission seeks 

comments whether another approach 

would be more appropriate. 

(b) Inspection Intervals 

382. NERC and other commenters 

believe FAC–003–1 appropriately 

provides discretion to transmission 

owners to develop vegetation inspection 

cycles appropriate for their respective 

systems. While the Commission 

recognizes that some variation in 

inspection cycles would be appropriate 

based on climate and other factors, we 

are concerned that the complete 

discretion left to the transmission 

owners in determining inspection cycles 

limits the effectiveness of the Reliability 

Standard. 

383. While the Commission will not 

dictate a specific minimum vegetation 

inspection cycle, based on data 

provided by transmission owners to the 

Commission in 2004 as part of the 

Commission’s vegetation management 

survey, it appears that a one-year 

vegetation inspection cycle is 

reasonable.178 According to the 

Vegetation Management Report, 76 of 

161 entities surveyed conduct ground 

inspections once a year.179 This 

indicates that a one-year vegetation 

inspection cycle is the ‘‘norm’’ for the 

industry, but not a lowest common 

denominator that sets a standard less 

stringent than the industry practice. 

While the Commission will not dictate 

a minimum vegetation inspection cycle, 

we do believe that it is important that 

the ERO develop a minimum 

requirement as a ‘‘backstop’’ to assure 

that transmission owners conduct 

inspections at a reasonable interval. 

Accordingly, we propose to direct that 

the ERO modify the Reliability Standard 

to establish a minimum vegetation 

inspection cycle. 

384. Further, as mentioned above, the 

Commission believes that some 

variation to a continent-wide, one year 

minimum cycle should be allowed due 

to physical differences such as climate 

and species of vegetation. Appropriate 

variations may be determined on a 

regional basis, with FAC–003–1 

providing a continent-wide ‘‘backstop.’’

Alternatively, the continent-wide 

standard could specify a one-year 

minimum inspection cycle, and provide 

that exemptions would be granted by 

the ERO for legitimate physical 

differences. The most appropriate 

approach could be determined in the 

ERO Reliability Standard development 

process. 

385. The applicability of FAC–003–1 

currently states that it applies to all 

transmission lines operated at 200 kV 

and above and to any lower voltage 

lines designated by the regional 

reliability organization as critical to 

reliability. The Commission is 

concerned that the bright-line 

applicability threshold of 200 kV will 

exclude a significant number of 

transmission lines that could impact 

Bulk-Power System reliability. Although 

the regional reliability organizations are 

given discretion to designate lower 

voltage lines under the proposed 

Reliability Standard, we are concerned 

that this approach will not result in the 

inclusion of all transmission lines that 

could impact Bulk Power System 

reliability. Accordingly, the 

Commission proposes to direct NERC to 

change the applicability of FAC–003–1 

so that it applies to Bulk-Power System 

transmission lines that have an impact 

of reliability as determined by the ERO. 

386. While we have expressed some 

concerns regarding FAC–003–1, we 


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180Blackout Report at 162. 

believe that it serves an important goal 

of improving the reliability of the BulkPower System by preventing outages 

from vegetation. Further, with our 

interpretation above regarding 

minimum clearances, the Commission 

believes that the proposed Requirements 

set forth in FAC–003–1 are sufficiently 

clear and objective to provide guidance 

for compliance. 

387. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard FAC–003–

1. Further, pursuant to section 215(d)(5) 

of the FPA and § 39.5(f) of our 

regulations, we propose to direct that 

NERC submit a modification to FAC–

003–1 that: (1) The ERO develop a 

minimum vegetation inspection cycle 

that allows variation for physical 

differences, as discussed above; and (2) 

removes the applicability to 

transmission lines operated at 200 kV 

and above so that the Reliability 

Standard applies to Bulk-Power System 

transmission lines that have an impact 

of reliability as determined by the ERO. 

e. Methodologies for Determining 

Electrical Facilities (FAC–004–0) and 

Electrical Facility Ratings for System 

Modeling (FAC–005–0) 

388. NERC’s August 28, 2006 

Supplemental Filing states that 

Reliability Standards FAC–004–0 and 

FAC–005–0 were filed for approval on 

April 4, 2006, but have been superseded 

by FAC–008–1 and FAC–009–1, 

respectively. NERC has withdrawn its 

request for approval of FAC–004–0 and 

FAC–005–0. Thus, the Commission will 

not address them in this notice of 

proposed rulemaking. 

f. Facility Ratings Methodology (FAC–

008–1) 

i. NERC Proposal 

389. The stated purpose of FAC–008–

1 is to ensure that facility ratings used 

in the reliable planning and operation of 

the bulk electric system are determined 

based on an established methodology. It 

requires that each transmission owner 

and generation owner develop a facility 

rating methodology for their facilities, 

which should consider manufacturing 

data; design criteria (such as IEEE, ANSI 

and other industry standards); ambient 

conditions; operating limitations; and 

other assumptions. This methodology is 

to be made available to reliability 

coordinators, transmission operators, 

transmission planners, and planning 

authorities who have responsibility in 

the same areas where the facilities are 

located for inspection and technical 

reviews. 

ii. Staff Preliminary Assessment 

390. Staff noted that this Reliability 

Standard does not establish or require a 

uniform or consistent set of 

methodologies, which has resulted in 

different ratings for the same equipment 

under the same conditions in the same 

region. Rather, it only requires an 

equipment owner to document the 

methodology it chooses to use. Thus, 

staff was concerned that FAC–008–1 

does not appear to address 

Recommendation No. 27 of the Blackout 

Report that NERC develop ‘‘clear, 

unambiguous requirements for the 

calculation of transmission line 

ratings.’’ 180

iii. Comments 

391. NERC comments that 

strengthening the consistency of the 

underlying assumptions and methods 

used to determine the ratings of 

facilities could improve the standard; 

however, NERC cautions that a single, 

uniform method for ratings calculations 

will not be practical or effective. This 

concern is echoed by ReliabilityFirst. 

NERC explains that the rating of 

facilities is very complex, beginning 

with the fact that each physical device 

has its own unique design criteria and 

limitations, which are incorporated into 

the device’s warranty. The facility 

owner risks voiding the warranty or 

damaging the physical device if it is 

operated outside of the manufacturer 

ratings. The second consideration is the 

configuration of the equipment within 

the power system. A facility owner 

examines the equipments’ limitations 

and uses engineering judgment to apply 

a variety of assumptions and practices 

in creating the design criteria for 

operational facilities. NERC agrees that 

it is at this step where practices could 

be more consistent. However, it adds 

that differences in assumptions and 

practices arise from site-specific 

characteristics such as climate 

conditions, local equipment safety 

codes, or life expectancy of the 

equipment, and that when the standards 

were developed, participants strongly 

agreed that uniform methods were not 

appropriate or feasible. 

392. NERC points out that there are 

trade-offs to uniform ratings methods. 

Currently, a facility owner assumes a 

business risk associated with the 

assumptions used in the rating of 

facilities because the facility owner has 

invested in the equipment and is 

responsible for maintaining the 

warranty, the equipment’s performance, 

and ultimately replacement costs. If 

ratings are uniform and outside a 

facility owner’s control, NERC questions 

who would be responsible for 

equipment failures. Uniform rating 

methods might also lead to a reduction 

in limits on facilities and, consequently, 

reduced capacity of the transmission 

network. Several commenters, including 

NERC, agree with staff that regardless of 

how ratings are developed, jointlyowned facilities must use the same 

ratings. 

393. Allegheny disagrees with staff’s 

evaluation of standard FAC–008. It 

comments that the industry does not 

consider the absence of a standard 

methodology for determining facility 

ratings a threat to the reliability of the 

transmission grid and that the 

establishment of a uniform standard 

will be a massive and costly 

undertaking. Allegheny explains that, 

historically, generator owners and 

transmission owners rely on 

manufacturer-provided equipment 

ratings, in conjunction with their 

respective business practices, to ensure 

consistent documentation and 

application of ratings to ensure 

reliability. Further, monitoring by 

regional organizations has also ensured 

that generator and transmission owners’

practices address reliability concerns. In 

light of this, Allegheny advocates that 

staff’s recommendations not be adopted 

without further demonstration that the 

benefits justify the cost. 

394. PG&E asserts that FAC–008–1 

appropriately balances the need for 

consistent facility ratings with the 

realities of the transmission system and 

that a single line rating methodology for 

all of North America is neither practical 

nor advisable. It explains that the 

Reliability Standard properly places the 

responsibility of determining facility 

ratings with the facility owners. PG&E 

believes the Reliability Standard’s 

disclosure requirement safeguards 

against manipulation of facility ratings. 

395. Mid-American and MRO agree 

that a consistent methodology should be 

established for equipment rating. MidAmerican believes that the standard 

should encourage a consistent 

methodology for calculating equipment 

ratings, ensure transmission customers 

of nondiscriminatory treatment without 

being overly burdensome to the facility 

owner, and must address all factors that 

affect equipment ratings. However, MidAmerican does not support an overlyprescriptive standard. It suggests that 

staff’s concerns should be directed at 


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181National Grid Comments at 19. 

182The Valley Group cites a CIGRE Technical 

Brochure entitled Guide for Selection of Weather 

Parameters for Overhead Bare Conductor Ratings 

published in August 2006 and a CIGRE/IEEE 

Tutorial, which was presented in June 2006. 

183MRO Comments at 8. 184See NERC Comments at 61. 

ensuring consistent methodologies for 

rating development, however, points out 

that a consistent methodology may still 

result in differing numerical ratings due 

to differing ambient temperatures, sag 

conditions, etc., that may exist in 

differing regions. While supporting 

staff’s recommendation for a consistent 

methodology, MRO disagrees with 

staff’s approach. Transmission owners 

should be able to set facility ratings as 

they see fit, provided the rating is 

communicated to others and the 

transmission owners operate with the 

same rating. 

396. National Grid comments that it 

supports some measure of 

standardization of equipment rating 

methodologies. It explains that, ‘‘if left 

entirely to the asset owners, the lack of 

uniform equipment rating 

methodologies leaves open the 

possibility in some circumstances that 

the determination of facility ratings can 

be used by an asset owner to gain a 

market edge over other market 

participants that do not own assets.’’ 181

National Grid encourages the 

standardization of facility ratings only at 

a conceptual level, though not 

necessarily the standardization of 

specific parameters, recognizing 

regional climatic and topological 

conditions. 

397. CenterPoint contends that 

Reliability Standards FAC–004–0, FAC–

005–0, FAC–008–1 and FAC–009–1 are 

not necessary and should be rejected. It 

explains that Blackout Report 

Recommendation No. 27 does not 

require a uniform set of methodologies 

for rating facilities, but instead only 

recommends that there be clear, 

unambiguous requirements to rate 

transmission lines. According to 

CenterPoint, most if not all utilities 

follow a standard IEEE method for 

rating transmission lines. 

398. The Valley Group proposes that 

the fastest and most efficient way to 

fulfill Blackout Report Recommendation 

No. 27 would be the adoption of the 

principles of the International Council 

on Large Electric Systems (CIGRE)/IEEE 

Guide and the necessary procedures for 

enforcement. The Valley Group cites 

survey data indicating that a large 

percentage of utilities have increased 

their facility ratings by changing certain 

ratings assumptions, most commonly by 

increasing the assumed wind speed. It 

views this as a dangerous trend because 

system loads have generally increased 

during the same period. It also sees the 

regional adoption of assumptions being 

based on utilities with the least 

conservative practices, leading to a 

‘‘lowest common denominator’’ result. 

To correct this problem, the Valley 

Group encourages adoption of IEEE/ 

CIGRE guidelines for selection of 

weather parameters.182

399. Alcoa agrees with staff’s 

evaluation of the facility Reliability 

Standards. It adds that, without a clear 

set of straightforward methodologies for 

facility ratings, the proposed 

documentation requirements are unduly 

burdensome. Alcoa suggests that the 

ERO propose methodologies that 

consider the relative importance to the 

reliability of the Bulk-Power System, as 

well as the ability of the owner of the 

facilities to pass on the costs incurred to 

enhance reliability to those receiving 

the benefit. 

iv. Commission Proposal 

400. The Commission proposes to 

approve FAC–008–1 as mandatory and 

enforceable. In addition, we propose 

directing that NERC develop 

modifications to the Reliability 

Standard, as discussed below. 

401. The Commission agrees with 

NERC and others that the assumptions 

used in the methodologies can not be 

standardized. The assumptions are 

essentially input variables into rating 

methodologies used to convert the input 

into the normal and emergency ratings 

of the facilities. Owners will use the 

actual topology and substation 

arrangement of the facilities in 

configuring equipment for facility 

ratings. There should be different input 

variables such as the ambient 

temperatures in Texas as compared to 

Maine. Thus, we are not proposing to 

require a ‘‘uniform method of ratings 

calculation,’’ which would standardize 

the input assumptions in the formula for 

calculating ratings. 

402. On the other hand, the 

Commission disagrees with MRO that 

transmission owners ‘‘should set the 

rating as they see fit, provided that 

everyone knows what the rating is and 

that rating is used for all purposes 

including the Transmission Owner’s use 

of the facilities.’’ 183 As explained by 

National Grid, allowing facility owners 

to set ratings ‘‘as they see fit’’ could 

result in the use of a facility rating 

determination to gain a competitive 

advantage over other market 

participants that do not own assets. This 

could harm the reliability of the 

transmission grid and can also impact 

competition as described by National 

Grid. Likewise, the Valley Group raises 

legitimate concerns about manipulation 

of the assumptions, in particular wind 

speed, demonstrating the need not only 

for uniformity, but for oversight as well. 

403. The Commission believes that, to 

address the concerns of National Grid, 

Valley Group and others, the Reliability 

Standard could be improved in two 

ways. First, we propose that the 

different assumptions that are the basis 

for the input variables should be 

documented and made available for 

review by other users, owners and 

operators of the Bulk-Power System. 

Currently, only a subset of functional 

entities responsible for the facilities in 

a specific area are able to view this 

information. The added transparency 

that we propose would allow customers, 

regulators and other affected users, 

owners and operators of the Bulk-Power 

System to understand how a facility 

owner sets its facility ratings. 

404. Second, asset owners use various 

methods for calculating ratings that are 

widely accepted throughout the 

industry, such as IEEE and CIGRE, to 

calculate transmission line conductor 

ratings. While not proposing to mandate 

a particular methodology, we do 

propose that the methodology chosen by 

a facility owner be consistent with 

industry standards developed through 

an open process such as IEEE or CIGRE. 

405. Further, consistent with NERC’s 

comments,184 the Commission proposes 

that the limiting component(s) be 

identified and that the increase in rating 

based on the next limiting component(s) 

be defined for all critical facilities, 

including facilities that limit TTC, limit 

delivery of generation to load, or bottle 

generation. This would provide 

additional transparency and sufficient 

information so that the most cost 

effective solutions to increase facility 

ratings can be identified. For example, 

if a specific transmission line is limited 

by the relay settings or protective relay 

system, ordinarily the line could be ‘‘up 

rated’’ for a relatively modest cost. As a 

second example, if a line is limited by 

the sag of one particular span, 

modifying the tension in that span, even 

if it requires reinforcing a few towers, 

may result in significant increases in 

capability at relatively low cost. Such 

information would be useful to users of 

the Bulk-Power System and to the 

Commission. 

406. CenterPoint has not provided a 

compelling reason for us to reject this 

Reliability Standard. Assuming 

CenterPoint is correct that most, if not 

all, utilities follow a standard method 

for rating transmission lines, that fact 


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does not obviate the need for mandatory 

and enforceable Reliability Standards 

that require clear, ambiguous 

requirements to rate transmission lines. 

Moreover, industry use of a standard 

line rating method may be a result of the 

Reliability Standard, which requires 

facility owners to consider industry 

rating practices such as IEEE. Moreover, 

the Reliability Standards include ratings 

for all facilities, not just transmission 

lines. 

407. FAC–008–1 makes considerable 

progress in addressing Blackout Report 

Recommendation No. 27, which as 

noted above recommends that NERC 

develop clear and unambiguous 

requirements for the calculation of 

transmission line ratings. While the 

Commission has identified ways to 

improve and strengthen this Reliability 

Standard, we believe that the proposal 

serves an important purpose in ensuring 

that facility ratings are determined 

based on an established methodology. 

Further, the Commission believes that 

the proposed Requirements set forth in 

FAC–008–1 are sufficiently clear and 

objective to provide guidance for 

compliance. 

408. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard FAC–008–

1 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to FAC–008–1 that requires 

transmission and generation facility 

owners to: (1) Document underlying 

assumptions and methods used to 

determine normal and emergency 

facility ratings; and (2) develop facility 

ratings consistent with industry 

standards developed through an open 

process such as IEEE or CIGRE; and (3) 

identify the limiting component(s) and 

define for all critical facilities the 

increase in rating based on the next 

limiting component(s). 

g. Establish and Communicate Facility 

Ratings (FAC–009–1) 

i. NERC Proposal 

409. The stated Purpose of FAC–009–

1 is to ensure that facility ratings are 

determined based on an established 

methodology. It requires each 

transmission owner and generation 

owner to establish facility ratings 

consistent with their associated facility 

ratings methodology and provide those 

ratings to their reliability coordinator, 

transmission operator, transmission 

planner, and planning authority. 

ii. Staff Preliminary Assessment 

410. The Staff Preliminary 

Assessment did not identify any issues 

related to this Reliability Standard. 

iii. Comments 

411. ReliabilityFirst agrees with staff’s 

evaluation that FAC–009–1 does not 

contain any substantive issues. 

iv. Commission Proposal 

412. FAC–009–1 serves an important 

reliability purpose of ensuring that 

facility ratings are determined based on 

an established methodology. Further, 

the proposed Requirements set forth in 

FAC–009–1 are sufficiently clear and 

objective to provide guidance for 

compliance. Accordingly, the 

Commission proposes to approve 

Reliability Standard FAC–009–1 

(Establish and Communicate Facility 

Ratings) as just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest. 

h. Transfer Capability Methodology 

(FAC–012–1) 

i. NERC Proposal 

413. Proposed Reliability Standard 

FAC–012–1 requires each reliability 

coordinator and planning authority to 

document their methodology used to 

develop inter-regional and intra-regional 

transfer capabilities. This methodology 

must describe how it addresses 

transmission topology, system demand, 

generation dispatch, and use of 

projected and existing commitment of 

transmission. 

ii. Staff Preliminary Assessment 

414. Staff noted that a move toward 

standardization of the inter-regional and 

intra-regional transfer capability may be 

desirable to ensure an adequate level of 

reliability and minimize undue negative 

impact on competition. 

iii. Comments 

415. Responding to staff’s suggested 

move toward standardization, MRO 

comments that the Reliability Standards 

should recognize the differences in 

geographical diversity, as well as 

relative population size, to maintain 

reliability. A single approach is 

desirable, but it should provide the 

flexibility to adjust for technical 

realities within a given part of the 

Eastern Interconnection. It explains that 

the assumptions underlying 

methodologies for determining interregional and intra-regional transfer 

capabilities may vary for different 

regions of the Eastern Interconnection 

due to geography, system design, 

weather, or state-specific requirements. 

Transparency in the approach and 

assumptions is essential. 

416. PG&E comments that the 

inherent differences in the development 

of the transmission infrastructure 

between the Eastern Interconnection 

and the Western Interconnection weigh 

against the imposition of a single 

methodology. Because transmission 

lines tend to be located in common 

corridors in the Western 

Interconnection, efficiency and 

reliability are maximized by transfer 

capabilities calculated with 

consideration of selected multiple 

contingencies to account for the 

multiplicity of potential credible events. 

417. CenterPoint proposes that FAC–

012–1 be consolidated with FAC–013–1. 

Further, it advocates that, because the 

ERCOT region operates as a single 

control area and thus does not have 

transfers between control areas, the 

NERC transfer capability methodology is 

not used, nor should it be. 

iv. Commission Proposal 

418. As the methodology to calculate 

transfer capability used by a reliability 

coordinator or planning authority has 

not been submitted to the Commission, 

it is not possible to determine at this 

time whether FAC–012–1 satisfies the 

statutory requirement that a proposed 

Reliability Standard be ‘‘just, 

reasonable, not unduly discriminatory 

or preferential, and in the public 

interest.’’ Accordingly, the Commission 

will not propose to accept or remand 

this Reliability Standard, until the 

regional procedures are submitted. In 

the interim, compliance with FAC–012–

1 should continue on its current basis, 

and the Commission considers 

compliance with the Reliability 

Standard to be a matter of good utility 

practice. 

419. Although we do not propose any 

action with regard to FAC–012–1 at this 

time, we address comments and our 

additional concerns regarding this 

Reliability Standard below. 

420. We agree with MRO and PG&E 

that different regions or 

Interconnections may have different 

geography, population size, or 

transmission structure that necessitate 

different approaches to transfer 

capability, and we have noted that the 

Requirement R1.3 addresses issues such 

as transmission system topology and 

current and projected use of 

transmission system for reliability 

margin but not for transfer capability 

calculation. FAC–012–1 only requires 


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185Path rating process in WECC and various 

regional transfer capability methodologies in the 

Eastern interconnection. 

186NERC glossary at 8 defines ‘‘Transaction’’ as 

‘‘[a]n agreement to transfer energy from a seller to 

a buyer that crosses one or more Balancing 

Authority Area boundaries.’’

187 INT–001–1, INT–003–1, INT–004–1, INT–005–

1, INT–006–1, INT–007–1, INT–008–1, INT–009–1, 

INT–010–1. 188Order No. 672 at P 324. 189NERC Petition at 40–41. 

that the regional reliability organization 

provide documentation on transfer 

capability methodology and provide this 

documentation to entities such as 

transmission planner, planning 

authority, reliability coordinator, and 

transmission operator. The Reliability 

Standard does not contain clear 

requirements on how transfer capability 

should be calculated, which has 

resulted in diverse interpretations of 

transfer capability and the development 

of various calculation methodologies.185

We believe that this Reliability Standard 

should, as a minimum, provide a 

framework for the transfer capability 

calculation methodology including data 

inputs, and modeling assumptions. We 

seek comments on the most efficient 

way to make the above information 

transparent for all participants. 

421. With regard to CenterPoint’s 

comment, while FAC–012, which 

pertains to the documentation of 

transfer capability methodologies, and 

FAC–013, which pertains to the 

establishment of transfer capabilities 

consistent with the methodology, are 

related, we leave it to NERC’s discretion 

whether they should be consolidated. 

As we have mentioned elsewhere, 

CenterPoint’s suggestion that the 

Reliability Standard not apply to the 

ERCOT region must be submitted by 

NERC as a regional difference. 

i. Establish and Communicate Transfer 

Capability (FAC–013–1) 

i. NERC Proposal 

422. Proposed Reliability Standard 

FAC–013–1 requires each reliability 

coordinator and planning authority to 

calculate transfer capabilities consistent 

with its transfer capability methodology 

and provide those capabilities to its 

transmission operators, transmission 

service providers, and planning 

authorities. 

ii. Staff Preliminary Assessment 

423. The Staff Preliminary 

Assessment did not identify any issues 

related to this Reliability Standard. 

iii. Comments 

424. ReliabilityFirst agrees with staff’s 

evaluation that FAC–013–1 does not 

contain any substantive issues. 

iv. Commission Proposal 

425. The Commission’s concern about 

this Reliability Standard is related to the 

applicability. The Reliability Standard 

currently states that it is applicable to a 

reliability coordinator (as required by its 

regional reliability organization), and a 

planning authority (as required by its 

regional reliability organization). The 

Commission believes that the Reliability 

Standard should be applicable to all 

Reliability Coordinators. A planning 

authority may also have a role in 

determining transfer capabilities, 

however, the regional reliability 

organization should not be the entity 

that makes this determination. 

426. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard FAC–013–

1 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to FAC–013–1 that: (1) Makes it 

applicable to all reliability coordinators; 

and (2) removes the regional reliability 

organization as the entity that 

determines whether a planning 

authority has a role in determining 

transfer capabilities. 

6. INT: Interchange Scheduling and 

Coordination 

a. Overview 

427. The Interchange Scheduling and 

Coordination (INT) group of Reliability 

Standards addresses the process of 

Interchange Transactions, which occur 

when electricity is purchased and 

transmitted from a seller to a buyer 

across the power grid.186 Specific 

information regarding each transaction 

must be identified in an electronic label, 

known as a ‘‘Tag,’’ which is used by an 

affected reliability coordinator, 

transmission service provider or 

balancing authority to assess the 

transaction for reliability impacts. In 

addition, communication, submission, 

assessment and approval of a Tag must 

be completed for reliability 

consideration before implementation of 

the transaction. 

428. In its April 4, 2006 Petition, 

NERC submitted four Version 0 

interchange Reliability Standards, INT–

001–0 through INT–004–0. In its August 

28, 2006 Supplemental Filing, NERC 

submitted nine Version 1 proposed 

Reliability Standards in the INT 

group.187 Reliability Standards INT–

001–1, INT–003–1 and INT–004–1 

replace the corresponding Version 0 

standards although, as discussed later 

on, the language of some Requirements 

have been modified and other 

Requirements have been transferred 

elsewhere. NERC states that Reliability 

Standard INT–002–0 is being retired, 

effective January 1, 2007 and asked that 

it be withdrawn for Commission review. 

Reliability Standards INT–005–1 

through INT–010–1 are new to the 

Version 1 Reliability Standards. 

i. General Comments 

429. CenterPoint comments that the 

INT group of proposed Reliability 

Standards should be rejected because 

Reliability Standards that attempt to 

create auditable requirements to 

measure ‘‘coordination’’ cannot 

realistically be implemented and are 

unnecessary appendages to Reliability 

Standards addressing the actual goal of 

ensuring reliable operation. CenterPoint 

also contends that, if the Commission 

approves the INT group of Reliability 

Standards, ERCOT should be explicitly 

exempted from them because 

interchange tagging is not used in 

ERCOT. 

430. ReliabilityFirst comments 

generally on the INT group of Reliability 

Standards. It states that the 

development of missing compliance 

elements by NERC’s drafting team must 

be expedited and that it may be 

necessary to supplement the team with 

additional experts if it is necessary to 

expand and/or detail requirements in 

these Reliability Standards. 

ii. Commission Proposal 

431. Order No. 672 explains that a 

Reliability Standard must be designed to 

achieve a specified reliability goal.188

The goal of the INT group of Reliability 

Standards is not simply to measure 

coordination as CenterPoint contends. 

Rather, these Reliability Standards are 

intended to ensure that uses of the BulkPower System are known to operating 

entities and reliability coordinators 

sufficiently in advance to permit them 

to evaluate reliability impacts and 

curtail transactions in the event system 

parameters approach their operating 

limits.189 In our view, the INT group of 

Reliability Standards is designed to 

achieve a specified goal that is 

important to maintaining Bulk-Power 

System reliability. Accordingly, the 

Commission disagrees with CenterPoint 


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190Order No. 672 at P 249. 

191Currently, the reliability analysis service used 

by NERC is the Interchange Distribution Calculator. 

192NERC’s Glossary of Terms adopted by NERC’s 

Board of Trustees on August 2, 2006 defines 

Interchange as ‘‘Energy transfers that cross 

Balancing Authority boundaries.’’

193See NERC Implementation Plan for Coordinate 

Interchange Standards INT–005 through INT–010 

(December 15, 2005) at 2–3. 

that the INT group of Reliability 

Standards should be rejected. 

432. With regard to CenterPoint’s 

suggestion that ERCOT be explicitly 

exempted from the INT group of 

Reliability Standards, we note that 

NERC has not proposed such an 

exemption as a regional difference. 

Order No. 672 makes clear that a 

proposed Reliability Standard, 

including a modification or regional 

difference to a Reliability Standard, 

must be submitted by the ERO to the 

Commission for our consideration.190

Accordingly, we will not consider such 

an exemption unless submitted by 

NERC for our review. 

433. With regard to ReliabilityFirst’s 

comment, we agree that the 

development of missing compliance 

elements is an important priority and 

note that NERC has stated that it plans 

to submit a filing in November 2006 that 

will include many such missing 

compliance elements. NERC staffing of 

the team assigned to develop missing 

compliance elements is a matter beyond 

the scope of this proceeding. 

b. Interchange Information (INT–001–1) 

i. NERC Proposal 

434. NERC states that the purpose of 

INT–001–1 is to ensure that interchange 

information is submitted to the 

reliability analysis service identified by 

NERC.191 Proposed Reliability Standard 

INT–001–1 applies to purchasing-selling 

entities and balancing authorities. It 

specifies two Requirements that focus 

primarily on establishing who has 

responsibility in various situations for 

submitting the Interchange information, 

previously known as transaction tag 

data, to the reliability analysis service 

identified by NERC.192 The 

Requirements apply to all dynamic 

schedules, delivery from a jointly 

owned generator and bilateral 

inadvertent interchange payback. 

ii. Staff Preliminary Assessment 

435. Staff noted that INT–001–0 has 

only one Measure and no Levels of NonCompliance. The Version 1 standard, 

INT–001–1, would delete the one 

Measure and, thus, would contain no 

Measures or Levels of Non-Compliance. 

iii. Comments 

436. ISO/RTO Council generally 

agrees with staff that INT–001–0 lacks 

sufficient compliance measures. 

Allegheny, in contrast, comments that 

tagging deadlines within the Reliability 

Standard provide an adequate measure 

of compliance. 

iv. Commission Proposal 

437. The Commission proposes to 

approve INT–001–1 as mandatory and 

enforceable. In addition, we propose to 

direct that NERC develop modifications 

to the Reliability Standard, as discussed 

below. 

438. Requirement R1.2 in INT–001–0 

(the Version 0 standard) requires data 

submission on all point-to-point 

transfers entirely within a balancing 

authority area, including ‘‘all 

grandfathered and ’non-Order 888’

Point-to-Point Transmission Service.’’

This Requirement to submit data for 

grandfathered and non-Order 888 pointto-point transmission service is not 

included in INT–001–1 or any other 

Version 1 Reliability Standard in the 

INT group. These transactions, if not 

reported, will create a gap in reliability 

assessment and transaction curtailment 

provisions and may result in adverse 

impact on reliable operation of the 

Interconnection. Therefore, the 

Commission proposes to direct that 

NERC retain this important 

Requirement. 

439. Requirements R1.1, R3, R4 and 

R5 of INT–001–0, which relate to the 

timing and content of e-tags, have been 

deleted in the Version 1 Reliability 

Standard. NERC indicates that these 

Requirements are actually business 

practices and that they will be included 

in the next version of NAESB Business 

Practices.193 Without prejudging any 

future proceeding regarding NAESB 

business practices, we find acceptable 

NERC’s explanation that the deleted 

Requirements are business practices, 

and we propose to approve INT–001–1 

with the deletion of Requirements R1.1, 

R3, R4 and R5. However, the 

Commission notes that NAESB has not 

at this time filed these e-tagging 

requirements as part of its business 

practices. If, at the time of the final rule, 

no such business practice has been 

submitted, the Commission may 

reinstate these Requirements as part of 

the final rule. In the future, to ensure 

that there is not a gap in Reliability 

Standards or business practices, the 

Commission expects filings from NERC 

and NAESB be coordinated to allow for 

the seamless transfer of Requirements 

from Reliability Standards to Business 

Practices. 

440. With regard to Allegheny’s 

comments, we believe that all 

Reliability Standards will benefit from 

Measures and Levels of NonCompliance. Further, as mentioned 

above, the tagging deadlines which 

Allegheny believes provides an 

adequate measure of compliance have 

been deleted and will be incorporated 

by NAESB as business practices. 

441. While the Commission has 

identified concerns with regard to INT–

001–1, it serves an important purpose in 

ensuring that responsible entities have 

the information they need to assess the 

reliability impact of an interchange 

transaction. While NERC should 

provide Measures and Levels of NonCompliance, the Requirements set forth 

in INT–001–1 are sufficiently clear and 

objective as to provide guidance for 

compliance. 

442. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard INT–001–

1 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, we propose directing that 

NERC submit a modification to INT–

001–1 that: (1) Includes Measures and 

Levels of Non-Compliance; and (2) 

includes a Requirement that interchange 

information must be submitted for all 

point-to-point transfers entirely within a 

balancing authority area, including all 

grandfathered and ‘‘non-Order No. 888’’

transfers. 

c. Regional Difference to INT–001–1 and 

INT–004–1: WECC Tagging Dynamic 

Schedules and Inadvertent Payback 

i. NERC Proposal 

443. NERC states that WECC has a 

regional variance that exempts tagging 

dynamic schedules and inadvertent 

payback. The waiver request included 

with the proposed Reliability Standards 

explains that tagging requirements 

simply do not apply to operations in the 

Western Interconnection. Also, a tagging 

requirement for dynamic schedules 

would create a burden for scheduling 

entities and not provide a substantial 

benefit. NERC explains that control 

areas and transmission providers have 

real-time scheduling information on 

dynamic schedules and that unilateral 


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194Waiver Request—Tagging Dynamic Schedules 

and Inadvertent Payback, Approved November 21, 

2002. NERC Petition, Exhibit A. 

195Order No. 672 at P 290. 

196 Information on this development can be found 

at: http://www.wecc.biz/index.php?module=pn

Forum&func=viewtopic&topic=394. 

197Waiver Request—Energy Flow Information, 

Approved July 16, 2003. (Attached to NERC’s 

proposed Reliability Standards). 

198Order No. 672 at P 290. 

199 Id. at 291. 

200 Id. 

201See Midwest Independent Transmission 

System Operator, Inc., 102 FERC ¶ 61,196 at P 38 

(2003). 

inadvertent payback is not allowed in 

the WECC.194

ii. Commission Proposal 

444. As discussed earlier, in Order 

No. 672, the Commission stressed that 

uniformity of Reliability Standards 

should be the goal and practice, ‘‘the 

rule rather than the exception.’’ 195 The 

absence of a tagging requirement for 

dynamic schedules in WECC is, 

therefore, a matter of concern to us. 

However, the Commission understands 

that WECC currently is developing a 

tagging requirement for dynamic 

schedules.196 The Commission seeks 

information from NERC on the status of 

the proposed tagging requirement, the 

time frame for its development, its 

consistency with INT–001–1 and INT–

004–1, and whether the need for the 

current waiver will be obviated when 

the tagging requirements become 

effective. The Commission will not 

approve or remand the waiver until 

NERC submits this information. The 

Commission will consider any regional 

differences contained in proposed 

WECC tagging requirement for dynamic 

schedules when it is submitted by NERC 

for Commission review. 

d. Regional Difference to INT–001–1 

and INT–003–1: MISO Energy Flow 

Information 

i. NERC Proposal 

445. NERC states that a regional 

difference is necessary to allow MISO to 

provide market flow information in lieu 

of tagging intra-market flows among its 

member balancing authorities. The 

waiver request included with the 

proposed Reliability Standards seeks 

specific provisions to accommodate a 

multi-control area energy market. 

According to the waiver request, the 

MISO energy flow information waiver is 

needed to realize the benefits of 

locational marginal pricing within 

MISO while increasing the level of 

granularity of information provided to 

the NERC TLR Process. The waiver 

request text states that it is understood 

that the level of granularity of 

information provided to reliability 

coordinators must not be reduced or 

reliability will be negatively 

impacted.197 The waiver text includes a 

condition specifying that the ‘‘Midwest 

ISO must provide equivalent 

information to Reliability Authorities as 

would be extracted from a transaction 

tag.’’

ii. Commission Proposal 

446. Order No. 672 explains that 

‘‘uniformity of Reliability Standards 

should be the goal and the practice, the 

rule rather than the 

exception.’’ 198However, the 

Commission has stated that, as a general 

matter, regional differences are 

permissible if they are either more 

stringent than the continent-wide 

Reliability Standard, or if they are 

necessitated by a physical difference in 

the Bulk-Power System.199 Regional 

differences must still be just, reasonable, 

not unduly discriminatory or 

preferential and in the public 

interest.200

447. Based on the information 

provided by NERC, the proposed 

regional difference for the INT 

Reliability Standards is necessary to 

accommodate MISO’s Commissionapproved, multi-control area energy 

market.201 Thus, we believe that the 

regional difference is appropriate as it is 

more stringent than the continent-wide 

Reliability Standard and otherwise 

satisfies the statutory standard for 

approval of a Reliability Standard. 

448. Accordingly, the Commission 

proposes to approve the regional 

difference. 

e. Interchange Transaction 

Implementation (INT–003–1) 

i. NERC Proposal 

449. NERC states that the purpose of 

the INT–003–1 is to ensure that 

balancing authorities confirm 

interchange schedules with adjacent 

balancing authorities prior to 

implementing the schedules in their 

area control error equations. The 

proposed Reliability Standard applies to 

balancing authorities. INT–003–1 

contains one Requirement that focuses 

on ensuring that a sending balancing 

authority confirms interchange 

schedules with the receiving balancing 

authority prior to implementing the 

schedules in its control area. The 

proposed Reliability Standard also 

requires that, for the instances where a 

high voltage direct current (HVDC) tie is 

on the scheduling path, both sending 

and receiving balancing authorities have 

to coordinate with the operator of the 

HVDC tie. 

450. NERC indicates that it will 

modify this proposed Reliability 

Standard to address the lack of 

Measures and Levels of NonCompliance and resubmit the proposal 

for Commission approval in November 

2006. 

ii. Staff Preliminary Assessment 

451. Staff noted in its Staff 

Preliminary Assessment that INT–003–0 

contains no Measures or Levels of NonCompliance. This comment applies 

equally to INT–003–1. 

iii. Commission Proposal 

452. The Commission notes that 

Requirement R1.1.3 addressing ramp 

starting time and duration in INT–003–

0 is removed from INT–003–1, and will 

be included as a NAESB business 

practice, whereas Requirement R1.3 

addressing interchange schedules 

crossing an interconnection boundary is 

now included in the new INT–009–1. In 

addition, Requirements R2, R3 and R4 

in INT–003–0 addressing 

implementation requirements and 

responsibilities on the balancing 

authorities are transferred to INT–009–

1. Requirement R5 stipulating that 

balancing authorities in implementing 

interchange schedule do not knowingly 

cause other system to violate operating 

criteria is now retired. Requirement R6 

on the maximum limit on the net 

interchange schedule is replaced with 

R1.2 in the new INT–006–1. 

453. As noted above, INT–003–1 lacks 

Measures and Levels of NonCompliance. While it is important to 

develop Measures and Levels of NonCompliance, the Commission believes 

that INT–003–1 serves an important 

purpose in requiring receiving and 

sending balancing authorities to confirm 

and agree on the interchange schedules. 

Further, we believe that the 

Requirements set forth in INT–003–1 are 

sufficiently clear and objective to 

provide appropriate guidance for 

compliance. 

454. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard INT–003–

1 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, we propose directing NERC 

to submit a modified Reliability 


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202NERC has proposed three regional differences 

for INT–003–1 that would apply to MISO. One 

regional difference was addressed above as it also 

related to Reliability Standard INT–001–1. The 

remaining two are discussed here. 

203Waiver Request—Scheduling Agent, 

Approved November 21, 2002. NERC Petition, 

Exhibit A. 

204 Midwest Independent Transmission System 

Operator, Inc., et al., 108 FERC ¶ 61,163 at P 100 

(2004). 

205Waiver Request—Enhanced Scheduling Agent, 

Approved November 16, 2003. ERC Petition, 

Exhibit A. 

206Order No. 672 at P 291. 

207See Midwest Independent Transmission 

System Operator, Inc., 102 FERC ¶ 61,196 at P 38 

(2003). 

Standard that includes Measures and 

Levels of Non-Compliance. 

f. Regional Differences to INT–003–1: 

MISO/SPP Scheduling Agent and MISO 

Enhanced Scheduling Agent 

i. NERC Proposal 

455. The MISO/SPP Scheduling Agent 

Waiver dated November 21, 2002 

creates variances from this proposed 

Reliability Standard for MISO/SPP that 

permits a market participant to utilize a 

scheduling agent to prepare a 

transaction Tag on its behalf.202 The 

scheduling agent is a single point of 

contact for all external, nonparticipating control areas or other 

scheduling agents with respect to 

scheduling interchange into, out of, or 

through the RTO to which the variance 

applies. The variance document 

explains that the variance is needed to 

implement a proposed RTO scheduling 

process to meet the RTO obligations 

under Order No. 2000, simplify 

transaction information requirements 

for market participants, reduce the 

number of parties with which control 

area operators must communicate, and 

provide a common means to tag 

transactions within and between RTOs. 

It also specifies that the specific 

scheduling processes implemented 

between participating control areas are 

internalized and transparent to the 

market, but that it has no reliability 

implications and will not violate any 

reliability criteria.203 The Commission 

has issued orders authorizing use of 

these practices by MISO.204

456. The MISO Enhanced Scheduling 

Agent Waiver dated July 16, 2003 

creates a variance from INT–003–1 for 

MISO that permits an enhanced single 

point of contact scheduling agent. 

Again, the variance document explains 

that the variance is needed to 

implement a proposed RTO scheduling 

process to meet the RTO obligations 

under Order No. 2000, simplify 

transaction information requirements 

for market participants, reduce the 

number of parties with which control 

area operators must communicate, and 

provide a common means to tag 

transactions within and between 

RTOs.205

ii. Commission Proposal 

457. The Commission ruled in Order 

No. 672 that, as a general matter, the 

following types of regional differences 

in Reliability Standards would be 

acceptable: (1) a regional difference that 

is more stringent than the continentwide Reliability Standard, including a 

regional difference that addresses 

matters that the continent-wide 

Reliability Standard does not; and (2) a 

regional Reliability Standard that is 

necessitated by a physical difference in 

the Bulk-Power System.206

458. Based on the information 

provided by NERC, the proposed 

regional differences for the INT 

Reliability Standard will provide 

administrative efficiency, and equal or 

greater amounts of information to the 

appropriate entities as required in 

MISO’s Commission-approved multicontrol area energy market.207 Thus, we 

believe that the proposed regional 

differences meet the legal standard for 

approval as well as the first criteria 

discussed above for a regional 

difference. 

459. Accordingly, for the reasons set 

forth above, the Commission proposes 

to approve these two additional regional 

differences. 

g. Dynamic Interchange Transaction 

Modifications (INT–004–1) 

i. NERC Proposal 

460. NERC states that the purpose of 

INT–004–1 is to ensure that dynamic 

transfers are adequately tagged to be 

able to determine their reliability 

impact. It requires the sink balancing 

authority, i.e., the balancing authority 

responsible for the area where the load 

or end-user is located, to communicate 

any change in the transaction. It also 

requires the updating of a Tag for 

dynamic schedules, i.e., transactions 

that vary from within an hour. INT–

004–1 does not identify Levels of NonCompliance. 

ii. Staff Preliminary Assessment 

461. No concerns were raised in the 

Staff Preliminary Assessment. 

iii. Comments 

462. INT–004–1 was included in 

NERC’s August 28, 2006 Supplemental 

Filing, and no comments were 

submitted regarding it. 

iv. Commission Proposal 

463. The Commission notes that 

Requirement R1 in INT–004–1 

providing procedures to modify 

interchange schedules to address 

reliability events are replaced with 

Requirements R1, R2 and R3 in the new 

INT–010–1. Requirement R2 which 

applies to generator operators or load 

serving entities for requesting to modify 

an interchange transaction due to loss of 

generation or load is replaced with 

Requirements in INT–005–1 through 

INT–010–1. 

464. The Commission believes that 

Levels of Non-Compliance should be 

included. 

465. INT–004–1 contains a regional 

variance from WECC that exempts 

tagging dynamic schedules and 

inadvertent payback. This is discussed 

above in more detail. The Commission 

proposes to leave pending the WECC 

regional difference until NERC files a 

new regional difference. 

466. While the Commission has 

identified concerns with regard to INT–

004–1, this proposed Reliability 

Standard serves an important purpose 

by setting thresholds on changes in 

dynamic schedules for which modified 

interchange data must be submitted for 

reliability assessment. Further, the 

Requirements set forth in INT–004–1 are 

sufficiently clear and objective to 

provide guidance for compliance. 

467. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard INT–004–

1 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, we propose directing NERC 

to submit a modification to INT–004–1 

that includes Levels of NonCompliance. 

h. Interchange Authority Distributes 

Arranged Interchange (INT–005–1) 

i. NERC Proposal 

468. INT–005–1, submitted with 

NERC’s August 28, 2006 Supplemental 

Filing, ensures the implementation of 

interchange between source and sink 

balancing authorities and the 

interchange information is distributed 

by an interchange authority to the 

relevant entities for reliability 


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Federal Register / Vol. 71, No. 213 / Friday, November 3, 2006 / Proposed Rules 64817 

208NERC’s glossary defines ‘‘interchange 

authority’’ as ‘‘[t]he responsible entity that 

authorizes implementation of valid and balanced 

Interchange Schedules between Balancing 

Authority Areas, and ensures communication of 

Interchange information for reliability assessment 

purposes.’’

assessments. INT–005–1 is applicable to 

the ‘‘interchange authority.’’ 208

ii. Commission Proposal 

469. The Commission is satisfied that 

the Requirements of the Reliability 

Standard are appropriate to ensure that 

interchange information is distributed 

and available for reliability assessment 

prior to its implementation. However, 

we are concerned regarding the 

applicability of INT–005–1 to the 

interchange authority. It is not clear 

from NERC’s definition whether an 

interchange authority is a user, owner or 

operator of the Bulk-Power System, or 

what types of entities would be eligible 

to perform such a function. Therefore, 

the Commission requests that NERC 

provide additional information 

regarding the role of the interchange 

authority so that the Commission can 

determine whether it is a user, owner or 

operator of the Bulk-Power System that 

is required to comply with mandatory 

Reliability Standards. 

470. Reliability Standard INT–005–1 

does not include Levels of NonCompliance. 

471. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard INT–005–

1 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, we propose to direct that 

NERC submit a modification to INT–

005–1 that includes Levels of NonCompliance. Further, the Commission 

requests that NERC provide additional 

information regarding the role of the 

interchange authority so that the 

Commission can determine whether it is 

a user, owner or operator of the BulkPower System that is required to comply 

with mandatory Reliability Standards. 

i. Response to Interchange Authority 

(INT–006–1) 

i. NERC Proposal 

472. INT–006–1, submitted with 

NERC’s August 28, 2006 Supplemental 

Filing to replace INT–002–0, ensures 

that each arranged interchange is 

checked for reliability before it is 

implemented. It is applicable to 

balancing authorities and transmission 

service providers and requires these 

entities to evaluate the energy profile 

and the ramp rate of the generation to 

support the transactions in response to 

the request from the interchange 

authority to change the status of an 

interchange from an arranged 

interchange to a confirmed interchange. 

ii. Staff Preliminary Assessment 

473. INT–006–1 is a new Reliability 

Standard that mostly contains 

Requirements from retired INT–002–0. 

Staff noted in its Staff Preliminary 

Assessment that INT–002–0 does not 

explicitly apply to reliability 

coordinators and transmission operators 

for reliability assessments of 

transactions before they are 

implemented. Staff indicated that it is 

important that the Reliability Standard 

apply to these entities explicitly because 

power flows for interchange 

transactions cross multiple balancing 

authority areas and affect multiple 

transmission paths in an 

Interconnection. 

iii. Comments 

474. As discussed below, INT–006–1 

raises a number of issues that are 

similarly raised by the Reliability 

Standard it replaces, INT–002–0. 

Therefore, relevant comments regarding 

INT–002–0 are discussed here. 

475. NERC maintains that staff’s 

concerns regarding the applicability of 

INT–002–0 to reliability coordinators 

and transmission operators are 

addressed by proposed Reliability 

Standard INT–004–0, which addresses 

reliability events such as potential or 

actual SOL or IROL violations. 

476. Similarly, Southern submits that 

the Reliability Standard currently 

applies to reliability coordinators and 

transmission operators in their role in 

the reliability assessment of individual 

interchange transactions. Southern 

explains that an individual Tag is first 

assessed by the balancing authority 

based on information on system limits 

provided by the reliability coordinator 

and/or the transmission operator. The 

composite set of Tags and associated 

schedules are then forwarded to the 

reliability analysis services that 

reliability coordinators and 

transmission operators use for their 

wide-area review. Southern contends 

that it would not be appropriate for 

reliability coordinators and 

transmission owners to approve or deny 

individual schedules during tagging, 

and states that they should be involved 

in reviewing tags in a composite 

manner. 

iv. Commission Proposal 

477. The Commission proposes to 

approve INT–006–1 as mandatory and 

enforceable. In addition, we propose to 

direct that NERC develop modifications 

to the Reliability Standard, as discussed 

below. 

478. We agree with NERC and 

Southern that it would be duplicative 

for a reliability coordinator or 

transmission owner to approve or deny 

an individual schedule during tagging. 

However, consistent with Southern’s 

comment, we believe that reliability 

coordinators and transmission operators 

should review composite energy 

interchange transaction information 

(composite Tags) for wide-area 

reliability impact. When the review 

indicated a potential detrimental 

reliability impact, the reliability 

coordinator or transmission operator 

should communicate to the sink 

balancing authority the necessary 

transaction modifications prior to 

implementation. Accordingly, we 

propose to require the ERO to modify 

the proposed Reliability Standard to 

ensure that reliability coordinators and 

transmission operators validate 

composite Tags (now called composite 

arranged interchanges) for reliability. 

479. The Commission notes that INT–

006–1 has included Measures and 

Levels of Non-Compliance with 

Requirements on balancing authorities 

and transmission service providers to 

check each arranged interchange for 

reliability. We believe that INT–006–1 

serves an important purpose in 

assessing each interchange transaction 

from a reliability perspective. 

480. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard INT–006–

1 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, we propose to direct that 

NERC submit a modification to INT–

006–1 that: (1) Makes it applicable to 

reliability coordinators and 

transmission operators; and (2) requires 

reliability coordinators and 

transmission operators to review 

composite transactions from the widearea reliability viewpoint and, where 

their review indicates a potential 

detrimental reliability impact, 

communicate to the sink balancing 

authorities necessary transaction 

modifications prior to implementation. 


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64818 Federal Register / Vol. 71, No. 213 / Friday, November 3, 2006 / Proposed Rules 

209NERC defines IROL as ‘‘[t]he value (such as 

MW, MVar, Amperes, Frequency or Volts) derived 

from, or a subset of the System Operating Limits, 

which if exceeded, could expose a widespread area 

of the Bulk Electric System to instability, 

uncontrolled separation(s) or cascading outages.’’

NERC glossary at 8. 

210Reliability Standard IRO–005–0, Requirement 

R3, states in part ‘‘[i]f a potential or actual IROL 

violation cannot be avoided through proactive 

intervention, the Reliability Coordinator shall 

initiate control actions or emergency procedures to 

relieve the violation without delay, and no longer 

than 30 minutes.’’

j. Interchange Confirmation (INT–007–1) 

i. NERC Proposal 

481. INT–007–1, submitted with 

NERC’s August 28, 2006 Supplemental 

Filing, ensures that each arranged 

interchange is checked for reliability 

before it is implemented. INT–007–1 

requires the interchange authority to 

verify that the submitted arranged 

interchanges are valid and complete 

with relevant information and approvals 

from the balancing authorities and 

transmission service providers before 

changing their status to confirmed 

interchanges. 

ii. Commission Proposal 

482. We are concerned regarding the 

applicability of INT–007–1 to the 

interchange authority. As discussed 

previously, it is not clear from NERC’s 

definition whether an interchange 

authority is a user, owner or operator of 

the Bulk-Power System, or what types of 

entities would be eligible to perform 

such a function, and in our discussion 

of INT–005–1 we request that NERC 

provide additional information 

regarding the role of the interchange 

authority. 

483. However, the Commission is 

satisfied that the Requirements of the 

Reliability Standard are appropriate to 

ensure that interchange information is 

verified prior to its implementation. 

Accordingly, the Commission therefore 

proposes to approve INT–007–1 as 

mandatory and enforceable. We believe 

that the proposed Reliability Standard is 

just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest. 

k. Interchange Authority Distributes 

Status (INT–008–1) 

i. NERC Proposal 

484. INT–008–1, submitted with 

NERC’s August 28, 2006 Supplemental 

Filing, ensures that the implementation 

of interchanges between source and sink 

balancing authorities is coordinated by 

an interchange authority. The Reliability 

Standard applies to the interchange 

authority. INT–008–1 requires the 

interchange authority to distribute 

information to all balancing authorities, 

transmission service providers and 

purchasing-selling entities involved in 

the arranged interchange when the 

status of the transaction has changed 

from arranged interchange to confirmed 

interchange. 

ii. Commission Proposal 

485. Again, we are concerned 

regarding the applicability of INT–008–

1 to the interchange authority. As 

explained above, the Commission 

requests additional information because 

it is not clear from NERC’s definition 

whether an interchange authority is a 

user, owner or operator of the BulkPower System, or what types of entities 

would be eligible to perform such a 

function. 

486. However, the Commission is 

satisfied that the Requirements of the 

Reliability Standard are appropriate to 

ensure that interchange information is 

coordinated between the source and 

sink balancing authorities prior to its 

implementation. Accordingly, the 

Commission therefore proposes to 

approve INT–008–1 as mandatory and 

enforceable. We believe that the 

proposed Reliability Standard is just, 

reasonable, not unduly discriminatory 

or preferential, and in the public 

interest. 

l. Implementation of Interchange (INT–

009–1) 

i. NERC Proposal 

487. INT–009–1, submitted with 

NERC’s August 28, 2006 Supplemental 

Filing, ensures that the implementation 

of an interchange between source and 

sink balancing authorities is 

coordinated by an interchange 

authority. 

ii. Commission Proposal 

488. The Commission is satisfied that 

the proposed Reliability Standard 

performs a necessary reliability function 

by coordination of interchanges and 

incorporating them into the ACE 

calculation of the respective balancing 

authorities. Further, INT–009–1 

includes clear and appropriate 

Requirements, Measurements and 

Levels of Non-Compliance to ensure 

proper implementation of interchange 

transactions that have received 

reliability assessments. The Commission 

therefore proposes to approve INT–009–

1 as mandatory and enforceable. We 

believe that the proposed Reliability 

Standard is just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest. 

m. Interchange Coordination 

Exemptions (INT–010–1) 

i. NERC Proposal 

489. INT–010–1, submitted with 

NERC’s August 28, 2006 Supplemental 

Filing, allows certain types of 

interchange schedules to be initiated or 

modified by reliability entities under 

abnormal operating conditions, and to 

be exempt from compliance with other 

Reliability Standards in the INT group. 

The Reliability Standard is applicable to 

the balancing authority and reliability 

coordinator. 

490. The proposed Reliability 

Standard, INT–010–1 has three 

Requirements, which allows 

modifications to interchange schedules 

under abnormal system conditions: (1) 

The balancing authority that 

experiences a loss of resources covered 

by an energy sharing agreement shall 

ensure that a request for an arranged 

interchange is submitted within 

required time; (2) for a modification to 

an existing interchange schedule that is 

directed by a reliability coordinator for 

a current or imminent reliability-related 

reasons, the reliability coordinator 

directs a balancing authority to submit 

the modified arranged interchange 

reflecting that modification within a 

specified time; and (3) for a new 

interchange schedule that is directed by 

a reliability coordinator for current or 

imminent reliability-related reasons, the 

reliability coordinator directs a 

balancing authority to submit an 

arranged interchange reflecting that 

interchange schedule within required 

time. 

ii. Staff Preliminary Assessment 

491. INT–010–1 includes three 

Requirements that replace Requirement 

R1 from INT–004–0. Staff raised 

concerns in the Staff Preliminary 

Assessment on INT–004–0 with respect 

to the use of transaction modifications 

to address reliability events such as 

actual IROL violations. 

492. Specifically, staff noted that 

INT–004–0 (now INT–010–1) allows 

modification of an interchange 

transaction to address an actual SOL or 

IROL violation.209 Staff stated that, in 

light of the procedures involved, 

including submission, assessment and 

approval, the total time necessary to 

implement an interchange transaction 

modification is expected to exceed 

significantly the 30 minute time-frame 

established in other Reliability 

Standards, i.e., the requirement that the 

system be returned from a SOL/IROL 

violation to a secure operating state as 

soon as possible, but no more than 30 

minutes after the violation.210 INT–004–

0 (now INT–010–1) does not contain a 

clear reference to this potential 


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Federal Register / Vol. 71, No. 213 / Friday, November 3, 2006 / Proposed Rules 64819 

211Blackout Report at 163. 

212According to the NERC glossary, at 13, a 

reliability coordinator is ‘‘the entity with the 

highest level of authority who is responsible for the 

reliable operation of the Bulk Electric System, has 

the Wide Area view of the Bulk Electric System, 

and has the operating tools, processes and 

procedures, including the authority to prevent or 

mitigate emergency operating situations in both 

next-day analysis and real-time operations * * *’’

limitation, and staff observed that it 

could lead to the inappropriate use of 

transaction modification by reliability 

entities to deal with actual SOL/IROL 

violations. Staff expressed concern that 

such actions could lead to the loss of 

valuable time that would be needed to 

readjust the system effectively using 

other operational corrective actions. 

iii. Comments 

493. There were no comments 

submitted regarding the use of 

transaction modification to address 

actual IROL violations in INT–010–1. 

iv. Commission Proposal 

494. The Commission believes that it 

is generally ineffective to use 

transaction modifications to mitigate an 

actual IROL violation or other system 

condition that calls for expeditious 

return to a secure system state. 

Transaction modifications are even less 

effective than the use of transmission 

load relief (TLR) procedures to mitigate 

an actual IROL violation. We note that 

the Blackout Report specified that NERC 

should ‘‘clarify that the [TLR] process 

should not be used in situations 

involving an actual violation of an 

Operating Security Limit.’’ The Blackout 

Report stated that ‘‘the TLR procedure is 

often too slow for use in situations in 

which an affected system is already in 

violation of an Operating Security 

Limit.’’ 211 We believe these same 

concerns articulated in the Blackout 

Report apply all the more so to a 

transaction modification to address an 

actual IROL violation. 

495. Reliability Standard INT–010–1 

includes provisions that allow 

modification to an existing interchange 

schedule or submission of a new 

interchange schedule that is directed by 

a reliability coordinator to address 

current or imminent reliability-related 

reasons. We interpret that these current 

or imminent reliability-related reasons 

do not include actual IROL violations as 

they require immediate control actions 

so that the system can be returned to a 

secure operating state as soon as 

possible and no longer than 30 

minutes—a period that is much shorter 

than the time that is expected to require 

for new or modified transactions to be 

implemented. 

496. Accordingly, with the above 

interpretation, the Commission 

therefore proposes to approve INT–010–

1 as mandatory and enforceable. We 

believe that the proposed Reliability 

Standard is just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest. 

7. IRO: Interconnection Reliability 

Operations and Coordination 

a. Overview 

497. The Interconnection Reliability 

Operations and Coordination (IRO) 

group of Reliability Standards detail the 

responsibilities and authorities of a 

reliability coordinator.212 The proposed 

IRO Reliability Standards establish 

requirements for data, tools and wide 

area view, all of which are intended to 

facilitate a reliability coordinator’s 

ability to perform its responsibilities 

and ensure the reliable operation of the 

interconnected grid. 

b. General Comments 

498. CenterPoint believes that the IRO 

series of Reliability Standards are 

largely unnecessary as they are processoriented. It proposes the consolidation 

of the IRO series of Reliability Standards 

to replace the process based 

Requirements with performance 

metrics. If, after some time, these do not 

achieve their reliability goal, they 

should be rejected. 

499. The Commission believes that 

performance metrics will generally 

complement and improve the proposed 

Reliability Standards. However, we do 

not believe that a Reliability Standard 

based solely on performance metrics can 

replace the proposed IRO Reliability 

Standards. This is because performance 

metrics, in general, are lagging 

indicators, and therefore, could only 

serve as reactive tools in improving the 

Reliability Standards. Additionally, we 

do not agree with CenterPoint’s 

statement that the IRO series of 

Reliability Standards are largely 

unnecessary and can be replaced with 

performance standards. On the contrary, 

we believe that the proposed IRO series 

of Reliability Standards establish 

requirements for data, tools, and wide 

area view and other real-time operating 

activities that must be performed by a 

reliability coordinator to ensure the 

reliable operation of the interconnected 

grid. 

c. Reliability Coordination—

Responsibilities and Authorities (IRO–

001–0) 

i. NERC Proposal 

500. IRO–001–0 requires that a 

reliability coordinator have reliability 

plans, coordination agreements and the 

authority to act and direct reliability 

entities to maintain reliable system 

operations under normal, contingency 

and emergency conditions. This 

Reliability Standard would apply to 

reliability coordinators and regional 

reliability organizations. 

ii. Staff Preliminary Assessment 

501. The Staff Preliminary 

Assessment noted that IRO–001–0 does 

not explicitly assign responsibilities to 

reliability coordinators in its Purpose or 

Requirements. Responsibilities can only 

be inferred from the definition of 

reliability coordinator in the NERC 

glossary. 

iii. Comments 

502. NERC comments that virtually 

every Requirement in IRO–001–0 

applies to reliability coordinators, so it 

does not understand the Staff 

Preliminary Assessment’s concern 

regarding the assignment of a reliability 

coordinator’s responsibilities. It also 

states that the compliance registry will 

include reliability coordinators. 

503. MRO and ReliabilityFirst agree 

with the Staff Preliminary Assessment. 

MRO believes that a clarification of the 

‘‘Purpose’’ section of IRO–001–0 is 

warranted to better identify a reliability 

coordinator’s responsibilities. 

504. The ISO/RTO Council does not 

share the Staff Preliminary Assessment’s 

concern because each reliability 

coordinator’s ‘‘reliability plan’’ is 

approved by the NERC Operating 

Committee. It states that this process is 

intended to ensure that a reliability 

coordinator’s peers validate that there is 

an appropriate entity authorized to carry 

out a reliability coordinator’s plans. 

iv. Commission Proposal 

505. The stated Purpose of IRO–001–

0 is ‘‘[r]eliability [c]oordinators must 

have the authority, plans and 

agreements in place to immediately 

direct reliability entities within their 

Reliability Coordinator Areas to redispatch generation, reconfigure 

transmission, or reduce load to mitigate 

critical conditions to return the system 

to a reliable state.’’ As noted by NERC, 

IRO–001–0 includes eight Requirements 

that set forth reliability coordinator 

responsibilities. However, these 

Requirements do not comprehensively 

match the responsibilities described in 

the Purpose statement of this Reliability 

Standard. Nonetheless, the Commission 

observes that the IRO group of 

Reliability Standards, taken as a whole, 

together with the NERC glossary 

definition of reliability coordinator, 

provides an adequate understanding of 


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64820 Federal Register / Vol. 71, No. 213 / Friday, November 3, 2006 / Proposed Rules 

213MISO Comments at 13, n.13, quoting IRO–

002–0, Requirement R7, which states, ‘‘[e]ach 

Reliability Coordinator shall have adequate analysis 

tools such as state estimation, pre- and postcontingency analysis capabilities (thermal, stability, 

and voltage), and wide-area overview displays.’’ 214NERC Comments at 126. 

the role and responsibilities of a 

reliability coordinator. Thus, while 

IRO–001–0 could be improved by 

comprehensively defining the overall 

responsibility of a reliability 

coordinator, as suggested in the title of 

the Reliability Standard (Reliability 

Coordination—Responsibilities and 

Authorities), we will not propose to 

direct NERC to do so. 

506. Requirement R1 of IRO–001–0 

provides that each regional reliability 

organization, ‘‘subregion’’ or 

‘‘interregional coordinating group’’ shall 

establish one or more reliability 

coordinators to continuously assess 

transmission reliability and coordinate 

emergency operations. Sections 502 and 

503 of NERC’s Rules of Procedure 

indicate that the ERO and Regional 

Entities are responsible for registering, 

certifying and verifying entities 

pursuant to NERC’s compliance registry, 

including reliability coordinators. The 

Commission proposes that NERC 

modify Requirement R1 to reflect the 

process set forth in the NERC Rules of 

Procedures, including the substitution 

of Regional Entity for regional reliability 

organization. 

507. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard IRO–001–

0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to Requirement R1 of IRO–001–0 that: 

(1) Reflects the process set forth in the 

NERC Rules of Procedures; and (2) 

eliminates the regional reliability 

organization as an applicable entity. 

d. Reliability Coordination—Facilities 

(IRO–002–0) 

i. NERC Proposal 

508. The proposed Reliability 

Standard, IRO–002–0, establishes the 

requirements for data, information, 

monitoring and analytical tools and 

communication facilities to enable a 

reliability coordinator to meet the 

reliability needs of the Interconnection, 

act in addressing real-time emergency 

conditions and control analysis tools. 

NERC indicates that it plans to modify 

IRO–002–0 to address the lack of 

Measures and Levels of NonCompliance and resubmit it for 

Commission approval in November 

2006. 

ii. Staff Preliminary Assessment 

509. The Staff Preliminary 

Assessment did not identify any 

substantive issues other than noting the 

absence of Measures and Levels of NonCompliance. 

iii. Comments 

510. MISO contends that the proposed 

Reliability Standard does not clearly 

require all reliability coordinators to 

demonstrate a functioning state 

estimation, real-time contingency 

analysis or a defined ‘‘wide area view’’

that includes visibility into neighboring 

regions. According to MISO, the 

requirement that a reliability 

coordinator have ‘‘adequate analysis 

tools’’ is a ‘‘loophole that belies the term 

‘standard.’ ’’213 ReliabilityFirst asserts 

that NERC should expedite the 

development of missing compliance 

elements within IRO–002–0. 

iv. Commission Proposal 

511. Requirement R7 currently does 

not specifically require the reliability 

coordinators to have specific tools 

because it includes the phrase ‘‘such 

as.’’ Requirement R7 should be modified 

to explicitly require a minimum set of 

tools that should be made available to 

the reliability coordinator. We share 

ReliabilityFirst’s concern that IRO–002–

0 lacks Measures and Levels of NonCompliance and direct NERC to add 

these compliance elements in its 

modification of the proposed Reliability 

Standard. While the Commission has 

identified concerns with regard to IRO–

002–0, we believe that the proposal 

serves an important purpose in ensuring 

that reliability coordinators have the 

information, tools and capabilities to 

perform their functions. NERC should 

provide Measures and Levels of NonCompliance for this proposed Reliability 

Standard. Nonetheless, the proposed 

Requirements set forth in this Reliability 

Standard are sufficiently clear and 

objective to provide guidance for 

compliance. 

512. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard IRO–002–

0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit, a modification 

to IRO–002–0 that: (1) Includes 

Measures and Levels of NonCompliance and (2) modifies 

Requirement R7 to explicitly require a 

minimum set of tools for the reliability 

coordinator. 

e. Reliability Coordination—Wide Area 

View (IRO–003–1) 

i. NERC Proposal 

513. The stated purpose of the 

proposed Reliability Standard is that a 

reliability coordinator must have a wide 

area view of its own and adjacent areas 

to maintain situational awareness. Wide 

area view also facilitates a reliability 

coordinator’s ability to calculate SOL 

and IROL as well as determine potential 

violations in its own area. NERC 

indicates that it plans to modify IRO–

003–1 to address the absence of 

Measures and Levels of NonCompliance and will resubmit it for 

Commission approval in November 

2006. 

ii. Staff Preliminary Assessment 

514. The Staff Preliminary 

Assessment indicated that IRO–003–1 

does not specify the criteria for defining 

critical facilities in adjacent systems 

whose status and loading could affect 

the reliability of neighboring systems. 

iii. Comments 

515. NERC responds that IRO–003–1 

provides that ‘‘critical facilities’’ are 

those that, if they fail, would result in 

an SOL or IROL violation. According to 

NERC, this means that critical facilities 

can only be determined by contingency 

analysis and change through time, and 

therefore, ‘‘may or may not exist.’’

Because an SOL or IRO violation is an 

operating state that can only be 

determined by running a series of ‘‘what 

if’’ analyses, IRO–003–1 defines a 

‘‘critical facility’’ as the facility that, if 

it fails, places the transmission system 

in a state ‘‘such that the failure of some 

other element will result in facility 

overloads, instability, or uncontrolled 

cascading outages.’’ 214 NERC states that 

the Commission should approve the 

Reliability Standard and adds that it 

will consider revising it to clarify the 

definition of ‘‘critical facility.’’

516. MRO agrees with the Staff 

Preliminary Assessment that this 

Reliability Standard should be revised 

to specify the criteria for defining 

‘‘critical facilities’’ in adjacent systems. 

MISO contends that the proposed 

Reliability Standard does not clearly 


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Federal Register / Vol. 71, No. 213 / Friday, November 3, 2006 / Proposed Rules 64821 

215Blackout Report at 159. 

216 Id. 

217 IRO–003–1, Requirement R1. 218Staff Preliminary Assessment at 71. 

219Requirement R1 requires that ‘‘Each Reliability 

Coordinator shall conduct next-day reliability 

analyses for its reliability coordinator area to ensure 

that the Bulk Electric System can be operated 

reliably in anticipated normal and contingency 

event conditions. The reliability coordinator shall 

conduct contingency analysis studies to identify 

potential interface and other SOL and IROL 

violations, including overloaded transmission lines 

and transformers, voltage and stability limits, etc.’’

220 IRO–005–1, Requirement R3 states, in relevant 

part, ‘‘* * * the [r]eliability [c]oordinator shall 

initiate control actions or emergency procedures to 

relieve the violations without delay, and no longer 

than 30 minutes.’’

define the term ‘‘wide area view’’ that 

includes visibility into neighboring 

regions. 

iv. Commission Proposal 

517. The Blackout Report emphasized 

that a principal cause of the August 

2003 blackout was a lack of situational 

awareness, which was in turn the result 

of inadequate reliability tools and 

backup capabilities.215 It pointed out 

that the need for improved visualization 

capabilities over a wide geographic area 

has been a recurrent theme in blackout 

investigations. The Blackout Report also 

explained that the Task Force 

investigation of the August 2003 

blackout revealed that ‘‘there has been 

no consistent means across the Eastern 

Interconnection to provide an 

understanding of the status of the power 

grid outside of a control area,’’ and 

improved visibility of grid status would 

aid an operator in making adjustments 

in operations to mitigate potential 

problems.216 The Commission believes 

that this issue is applicable to the entire 

country and not just the Eastern 

Interconnection. IRO–003–1 addresses 

these important concerns of the 

Blackout Report by requiring that a 

reliability coordinator monitor its own 

and adjacent areas to have a wide area 

view that is ‘‘necessary to ensure that, 

at any time, regardless of prior planned 

or unplanned events, the Reliability 

Coordinator is able to determine any 

potential System Operating Limit and 

Interconnection Reliability Operating 

Limit violations within its Reliability 

Coordination Area.’’ 217

518. The Commission notes that 

Requirement R2 of the Reliability 

Standard requires that each reliability 

coordinator know the current status of 

all ‘‘critical facilities’’ whose ‘‘failure, 

degradation or disconnection’’ could 

result in an SOL or IROL violation. 

However, IRO–003–1 does not specify 

the criteria for defining critical facilities. 

NERC explains that specifying such 

criteria is very difficult because critical 

facilities can only be determined by 

contingency analysis and change 

through time. While NERC 

acknowledges the absence of such 

criteria, it requests that the Reliability 

Standard be approved. In addition, 

NERC indicates that it will consider a 

modification to clarify the definition of 

‘‘critical facility.’’

519. IRO–003–1 serves an important 

reliability goal of requiring reliability 

coordinators to have a wide area view 

and maintain situational awareness. The 

Commission proposes to direct NERC to 

provide Measures and Compliance 

elements for the proposed Reliability 

Standard, and include criteria to define 

‘‘critical facilities’’ in a reliability 

coordinator’s area and its adjacent 

systems. Nonetheless, the Requirements 

set forth in IRO–003–1 are sufficiently 

clear and objective to provide guidance 

for compliance and a basis for 

enforcement. 

520. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard IRO–003–

1 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to IRO–003–1 that includes: (1) 

Measures and Levels of NonCompliance; and (2) criteria to define 

the term ‘‘critical facilities’’ in a 

reliability coordinator’s area and its 

adjacent systems. 

f. Reliability Coordination—Operations 

Planning (IRO–004–1) 

i. NERC Proposal 

521. The stated purpose of IRO–004–

1 is to require that each reliability 

coordinator conduct next-day 

operations reliability analyses to ensure 

that the system can be operated reliably 

in anticipated normal and contingency 

system conditions. Operations plans 

must be developed to return the system 

to a secure operating state after 

contingencies and shared with other 

operating entities. 

ii. Staff Preliminary Assessment 

522. The Staff Preliminary 

Assessment noted that, while IRO–004–

1 requires Reliability Coordinators to 

conduct next-day reliability analyses to 

ensure reliable operations in anticipated 

normal and contingency event 

conditions, it ‘‘does not require that the 

system be assessed in the next-day 

planning analysis to identify the control 

actions needed to bring the system back 

to a stable state, with an effective 

implementation time of within 30 

minutes, so that the system will be able 

to withstand the next contingency 

without cascading.’’ 218

iii. Comments 

523. NERC asserts that Requirement 

R1 of IRO–004–1 does require next-day 

operations planning studies and does 

not require modification.219 Similarly, 

ISO–RTO Council comments that the 

proposed Reliability Standard contains 

the appropriate requirements for 

ensuring reliable operations because 

there are other tools available to meet 

the needs identified with a next-day 

analysis. These alternative tools are 

adequate for conducting next-day 

analysis. 

524. MRO suggests that the next-day 

reliability analyses do not need to 

include the control actions that would 

be implemented to bring the system 

back to a stable state. MRO argues that, 

in most cases, the actual dispatch and 

condition of the system during real-time 

is not representative of the dispatch 

used in the model for performing the 

next-day analyses and, thus, mitigation 

action needed during real-time will 

differ. 

525. ReliabilityFirst agrees in general 

with the Staff Preliminary Assessment’s 

comments, but cautions that the 

proposal to identify and study all 

possibilities for alleviating SOL and 

IROL may be impractical and 

unachievable. 

iv. Commission Proposal 

526. The Commission agrees with 

NERC that the proposed Reliability 

Standard requires next day operations 

planning. While the Staff Preliminary 

Assessment mentions the next-day 

planning analysis and the need to study 

events that would result in cascading for 

the first contingency, this was not the 

intended focus of staff’s observations. 

Rather, the thrust of staff’s concern was 

that the control actions necessary to 

return the system to a stable state after 

the first contingency must do so 

effectively within the specified 

implementation time of less than 30 

minutes.220 To assure that an operator 

has either sufficient generation 

resources, transmission modifications, 

or load shedding capability to avoid a 

cascading outage after the first 

contingency, the control actions should 

be identified in the next-day analyses to 

better prepare system operators to deal 


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221See NERC Comments at 43–48. 

with system contingencies or 

emergencies in real-time operations. 

527. The Commission believes that 

identification of potential control 

actions will aid system operators in 

performance of their duties. While MRO 

is correct that control actions identified 

in a next-day analysis may not always 

be useful in a real-time scenario, 

nonetheless, the control actions 

identified in the next-day analysis may 

quite often be relevant and having the 

system operators aware of options 

earlier on would be helpful. 

528. The Commission agrees with 

NERC regarding the applicability of this 

Reliability Standard. While most 

Requirements pertain to reliability 

coordinators, they also require each 

balancing authority, transmission 

operator, transmission owner, generator 

operator, and load-serving entity to 

provide information to its reliability 

coordinator for system studies. It also 

requires that each transmission 

operator, balancing authority and 

transmission service provider to comply 

with the directive of its reliability 

coordinator based on next-day 

assessments. 

529. While the Commission has 

identified one concern with regard to 

IRO–004–1, the proposed Reliability 

Standard serves an important purpose 

by requiring that each reliability 

coordinator conduct next-day 

operations reliability analyses to ensure 

that the system can be operated reliably 

in anticipated normal and contingency 

system conditions. Further, the 

Requirements set forth in IRO–004–1 are 

sufficiently clear and objective to 

provide guidance for compliance and a 

basis for enforcement. 

530. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard IRO–004–

1 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to IRO–004–1 that requires the next-day 

analysis to identify effective control 

actions that can be implemented within 

30 minutes during contingency 

conditions. 

g. Reliability Coordination—Current 

Day Operations (IRO–005–1) 

531. IRO–005–1 ensures energy 

balance and transmission reliability for 

the current day by identifying tasks that 

reliability coordinators must perform 

throughout the day. The stated 

purposed of the proposed Reliability 

Standard is that a reliability coordinator 

must be continuously aware of 

conditions within its area and include 

this information in its reliability 

assessments. Additionally, a reliability 

coordinator must monitor the 

parameters of the system that may have 

a significant impact upon its area and 

neighboring reliability coordinator 

areas. NERC indicates that it plans to 

modify IRO–005–0 to address the lack of 

Measures and Levels of NonCompliance and resubmit it for 

Commission approval in November 

2006. 

i. Staff Preliminary Assessment 

532. Requirement R3 of IRO–005–1 

provides that: ‘‘[i]f a potential or actual 

IROL violation cannot be avoided 

through proactive intervention, the 

Reliability Coordinator shall initiate 

control actions or emergency procedures 

to relieve the violation without delay, 

and no longer than 30 minutes. The 

Reliability Coordinator shall ensure all 

resources, including load shedding, are 

available to address a potential or actual 

IROL violation.’’ The Staff Preliminary 

Assessment pointed out that this 

Requirement may be interpreted in 

either of two ways: (1) a less 

conservative interpretation in which an 

IROL is allowed to be exceeded during 

normal operations, i.e., prior to a 

contingency, provided that corrective 

actions are taken within 30 minutes; 

and (2) a more conservative 

interpretation that an IROL should only 

be exceeded after a contingency and the 

system must subsequently be returned 

to a secure condition as soon as 

possible, but no longer than 30 minutes. 

Therefore, IRO–005–1 creates the 

situation in which the system may be 

one contingency away from potential 

cascading failure if operated under the 

less conservative interpretation or two 

contingencies away from potential 

cascading failure if the more 

conservative interpretation is adopted. 

ii. Comments 

533. NERC acknowledges that the 

SOLs and IROLs are among the most 

important operating measures contained 

in the proposed Reliability Standards 

and that it continues to refine the 

definitions of both these terms. NERC 

explains that SOL and IROL violations 

do not necessarily result from an event 

or ‘‘contingency.’’ It asserts that the 

transmission system may ‘‘drift’’ into an 

SOL or IROL violation without any 

triggering event and with every element 

of the transmission system operation 

within its own safe limit.221 NERC states 

that the point of these limits is not 

whether a particular transmission 

facility is operating within its normal 

limits, but to determine what happens if 

the transmission element fails regardless 

of how much power is flowing through 

it. 

534. NERC states that it will consider 

clarifying those Reliability Standards 

that indicate a contingency is not 

required and, as a corollary, that a 

Reliability Standard should not allow a 

system operator to ‘‘drift’’ in and out of 

an SOL or IROL violation. Further, 

NERC will continue to refine its 

definition of SOL and IROL violations. 

The Operating Committee has 

commissioned an Operating Limits 

Definition Task Force to work on this 

matter, and the Task Force will bring its 

final suggestions to the Operating 

Committee by the end of 2006. NERC 

indicates that it will review proposed 

Reliability Standards IRO–003–0 and 

IRO–005–1 and address SOL and IROL 

violation mitigation. 

535. According to NERC, the 30- 

minute limit for mitigating IROL 

violations is one of many reliability 

standards gleaned from decades of 

interconnected systems operation 

experience, and represents a tradeoff 

between: (1) sufficient time to allow the 

transmission operator or reliability 

coordinator to mitigate the violation 

without having to shed load or 

disconnect transmission system 

components; and (2) the risk that some 

event will occur before the mitigating 

action is taken. NERC explains that 

action is required ‘‘as soon as possible’’

or ‘‘without delay,’’ however, exceeding 

an SOL or IROL for no more than 30 

minutes is not a violation. It contends 

that this approach is reasonable because 

it allows the system operator to decide 

on what course of action to take. 

Operating options that are less severe 

than shedding load are often available, 

but it explains that these actions may 

require more time for implementation. 

NERC asserts that its committees and 

subcommittees have debated the phrase, 

‘‘as soon as possible’’ for years and have 

not found a better way to articulate a 

requirement that allows the system 

operator the leeway to decide the best 

course of action. 

536. MRO and NYSRC agree with the 

Staff Preliminary Assessment that IRO–

005–1 allows varying interpretations 

with respect to IROL limits under 

normal and contingency conditions and 

should be revised to clarify how IROL 

events are addressed. ReliabilityFirst 

believes that a methodology to address 


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Federal Register / Vol. 71, No. 213 / Friday, November 3, 2006 / Proposed Rules 64823 

222Reliable operation: Operating the elements of 

the Bulk-Power System within equipment and 

electric system thermal, voltage and stability limits 

so that instability, uncontrolled separation, or 

cascading failures of such system will not occur as 

a result of sudden disturbance, including a 

Cybersecurity Incident, or unanticipated failure of 

system elements. 

223TPL–002–0 System Performance Following 

Loss of a Single Bulk Electric System Element, 

Table 1: For Category B events resulting in loss of 

a single element, the system remains stable and 

both thermal and voltage limits are within 

applicable ratings with no loss of demand or 

curtailment of firm transfers and no cascading 

outages. 

SOLs and IROLs must be developed. It 

argues that this will aid in clarifying 

that exceeding limits is not acceptable 

operating practice. According to 

ReliabilityFirst, proposed Reliability 

Standards are being developed that will 

provide more definition and detail in 

this area. It urges the acceleration of this 

development. 

537. MidAmerican believes that staff’s 

‘‘more conservative’’ interpretation may 

be overly conservative and should not 

be adopted. It contends that, in an 

interconnected transmission network, it 

is difficult to operate prior to a 

contingency so that potential IROL 

violations are avoided at all times. It 

believes that to adopt the more 

conservative interpretation could 

require an operator to scale back the 

operation of its system pre-contingency 

by an inordinate amount to provide a 

safety margin so as not to risk a 

potential IROL violation even for only 

very short periods of time. 

MidAmerican maintains that such an 

operation would result in slightly more 

reliable operation at an unjustifiably 

high price. 

iii. Commission Proposal 

538. The Commission proposes to 

approve IRO–005–1 as mandatory and 

enforceable. In addition, we propose to 

direct that NERC develop modifications 

to the Reliability Standard and perform 

a survey of present operating practices 

and actual operating experience 

concerning drifting in and out of IROL 

violations. 

539. The Commission believes that 

one of the fundamental principles in 

operating the Bulk-Power System 

reliably is that the system must be 

capable of supplying firm demand and 

supporting firm transactions while 

retaining the capability to withstand a 

critical contingency without resulting in 

instability, uncontrolled separation or 

cascading failures. This is affirmed by 

the term, Reliable Operation, as set forth 

in section 215(a)(4) of the FPA 222 and 

the technical requirement as stated in 

Table 1 of Reliability Standard TPL–

002–0.223 Therefore, in order to achieve 

the reliability goal stated in the 

definition of Reliable Operation, the 

Bulk-Power System must be operated to 

respect all applicable IROLs during 

normal conditions, i.e. prior to a 

contingency, so that the system is 

capable of withstanding a critical 

contingency without resulting in 

instability, uncontrolled separation or 

cascading outages. 

540. IRO–005–1 allows a system 

operation to respect IROLs in two 

possible ways: (1) allowing IROL to be 

exceeded during normal operations, i.e., 

prior to a contingency, provided that 

corrective actions are taken within 30 

minutes or (2) exceeding IROL only after 

a contingency and subsequently 

returning the system to a secure 

condition as soon as possible, but no 

longer than 30 minutes. Thus, the 

system can be one contingency away 

from potential cascading failure if 

operated under the first interpretation 

and two contingencies away from 

cascading failure under the second 

interpretation. 

541. The Commission notes that the 

proposed Reliability Standards (e.g. 

TOP–007–0) do not consider operation 

exceeding IROL for less than 30 minutes 

as a compliance violation. This, in 

addition to the less conservative 

interpretation that IROL violation is 

permissible during normal operations, 

opens up a significant reliability gap 

that allows operations with IROL 

violations for less than 30 minutes at a 

time. Under the mandatory reliability 

construct, there would be no 

enforcement provision to sanction 

against such actions even they resulted 

in cascading outages. 

542. The Commission believes a 

proactive standard, that clearly defines 

that reliable operations means operating 

the system within IROLs and requires 

such operating practice be reinforced by 

periodic reporting of the frequency, 

duration and causes of IROL violations, 

is needed to prevent or mitigate the risk 

of blackouts. This is because, by 

definition, when the system is operating 

in violation of IROLs and if a critical 

contingency occurs, cascading outages 

will result. 

543. Operating the system during 

normal system conditions with IROL 

violations is also known in the industry 

as ‘‘drifting in and out’’ of an IROL 

violation. This is the first and less 

conservative interpretation of the 

proposed Reliability Standard as stated 

above and one contingency away from 

cascading failure. We particularly note 

that the NERC Operating Committee 

recommended that the proposed 

Reliability Standards should not allow a 

system operator to ‘‘drift’’ in and out of 

an SOL or IROL violation. 

544. The Commission agrees with 

ReliabilityFirst’s comments that 

exceeding any limit is not acceptable 

operating practice. The system should 

strive to operate in a secure state that 

respects all IROLs under normal 

conditions at all times, except for 

infrequent and unanticipated changing 

conditions that are beyond the control 

of reliability coordinators and operating 

entities under their jurisdiction. 

Furthermore, these unanticipated 

factors should be limited and should not 

include load pick-up and drop-off as 

changes in load demand or coordinated 

generation dispatches and transactions, 

all of which would have obtained prior 

assessments and approvals. 

545. In contrast to MidAmerican’s 

comments, the Commission does not 

believe that respecting IROL under 

normal system conditions requires an 

inordinate amount of operating margin 

which may result in an unjustifiably 

high price. However, we propose to 

direct NERC to perform a survey of 

present operating practices and actual 

operating experience concerning 

drifting in and out of IROL violations. 

As part of the survey, we will require all 

reliability coordinators to report any 

violations of IROLs, their causes, the 

date and time of the violation, and the 

duration in which actual operations 

exceeded IROL to the ERO on a monthly 

basis for one year beginning two months 

after the effective date of the final rule. 

546. The Commission also finds that 

well-designed Levels of NonCompliance should duly recognize the 

magnitude, frequency and duration of 

IROL violations under normal system 

conditions and differentiate those 

caused by system contingencies. The 

former, if not severe, frequent, of 

extended duration or willfully 

deployed, should not incur heavy 

penalties. Nevertheless, these 

occurrences and causes should be 

recorded and reported. We understand 

that most reliability coordinators and 

transmission operators already keep 

records of power flows on transmission 

interfaces, transmission paths or 

flowgates versus their respective IROLs 

as a part of their operating and 

management tools. We believe that the 

practice of separately recording and 

reporting IROL violations and durations 

occurring under normal and 

contingency system conditions serves 

several purposes, including: (1) 

Reinforcing the sound principles of 

reliable system operations; (2) serving as 

a performance metric to gauge the 

effectiveness of Reliability Standards, 

coordinated Interconnection operations, 


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64824 Federal Register / Vol. 71, No. 213 / Friday, November 3, 2006 / Proposed Rules 

224The equivalent Interconnection-wide 

transmission loading relief procedures for use in 

WECC and ERCOT are known as ‘‘WSCC 

Unscheduled Flow Mitigation Plan’’ and Section 7 

of the ‘‘ERCOT Protocols,’’ respectively. 

225The NERC glossary defines Interchange 

Distribution Calculator as ‘‘The mechanism used by 

reliability coordinators in the Eastern 

Interconnection to calculate the distribution of 

Interchange Transactions over specific Flowgates. It 

includes a database of all Interchange Transactions 

and a matrix of the Distribution Factors for the 

Eastern Interconnection.’’ NERC glossary at 6. 

226We note that on September 29, 2006, NERC 

submitted Version 2 of the same Reliability 

Standard (ERO–006–2) in Docket No. ER06–1545–

000, seeking approval of its TLR procedure 

pursuant to section 205 of the FPA. 

227Blackout Report, Recommendation No. 31 at 

163. 

228Staff Preliminary Assessment at 69. 

229NERC Comments at 49. 

230 Id. at 50. 

231 In its comments on EOP–002–0 regarding 

Capacity and Energy Emergencies, ISO/RTO 

Council elaborates that it ‘‘agrees with FERC Staff’s 

concerns that TLRs are not appropriate for 

addressing actual transmission emergencies, 

because TLRs are not a method that can be used 

quickly or predictably enough in situations where 

an operating security limit is close to, or actually 

being violated.’’

232 IRO–006–1, Requirement R1 states, ‘‘[a] 

[r]eliability [c]oordinator shall take appropriate 

actions in accordance with established policies, 

procedures, authority, and expectations to relieve 

transmission loading.’’

and the health of the Bulk-Power 

System; and (3) proactively improving 

system reliability over time. 

547. It is important to keep in mind 

that, while the Commission has 

concerns regarding Requirement R3, the 

proposed Reliability Standard contains 

17 Requirements relating to current day 

operations. With this perspective, while 

the Commission has identified a number 

of concerns with regard to IRO–005–1, 

we believe that the proposed Reliability 

Standard adequately addresses the 

important reliability goal of requiring a 

reliability coordinator to be 

continuously aware of conditions 

within its reliability coordinator area 

and include this information in its 

reliability assessments. Further, NERC 

should provide Measures and Levels of 

Non-Compliance elements for this 

proposed Reliability Standard. 

Nonetheless, the proposed 

Requirements set forth in this Reliability 

Standard are sufficiently clear and 

objective to provide guidance for 

compliance. 

548. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard IRO–005–

1 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to IRO–005–1 that includes Measures 

and Levels of Non-Compliance. We 

propose that the Measures and Levels of 

Non-Compliance specific to IROL 

violations should be commensurate 

with the magnitude, duration, frequency 

and causes of the violation. Further, as 

discussed above, we propose that the 

ERO conduct a survey on IROL practices 

and experiences. The Commission may 

propose further modifications to IRO–

005–1 based on the survey results. 

h. Reliability Coordination—

Transmission Loading Relief (IRO–006–

3) 

i. NERC Proposal 

549. IRO–006–3 ensures that a 

reliability coordinator has a coordinated 

method to alleviate loadings on the 

transmission system if it becomes 

congested to avoid limit violations. 

IRO–006–3 establishes a detailed 

Transmission Loading Relief (TLR) 

process for use in the Eastern 

Interconnection to alleviate loadings on 

the system by curtailing or changing 

transactions based on their priorities 

and according to different levels of TLR 

procedures.224 The proposed Reliability 

Standard includes a regional difference 

for reporting market flow information to 

the Interchange Distribution Calculator 

rather than tagged transaction 

information for the MISO and PJM 

areas.225 It also references the 

equivalent Interconnection-wide 

congestion management methods used 

in the WECC and ERCOT regions. 

550. On August 28, NERC submitted 

IRO–006–3 for approval, which replaces 

IRO–006–1. The new proposal would 

extend the PJM/MISO regional 

difference to SPP and contains some 

additional changes to the Attachment to 

the Reliability Standard. The comments 

submitted in response to the 

Preliminary Staff Assessment on IRO–

006–1 apply equally to IRO–006–3.226

ii. Staff Preliminary Assessment 

551. The Staff Preliminary 

Assessment noted that IRO–006–1 does 

not address concerns expressed in the 

Blackout Report that call for 

‘‘clarify[ing] that the transmission 

loading relief (TLR) process should not 

be used in situations involving an actual 

violation of an Operating Security Limit 

[SOL].’’ 227 It also noted that 

Requirement R2, which provides that a 

reliability coordinator experiencing a 

potential or actual SOL or IROL 

violation shall select from either a local 

or Interconnection-wide transmission 

loading relief procedure, could lead a 

reliability system operator to 

‘‘inappropriately use transmission 

loading relief procedures to mitigate 

actual IROL violations’’ and, ‘‘in doing 

so, valuable time that could be utilized 

to re-adjust the system by other, more 

effective, operating measures would be 

lost.’’ 228

iii. Comments 

552. NERC explains that the TLR 

procedure is a method of addressing the 

impacts of bilateral transactions causing 

parallel flows. The procedure curtails 

bilateral transactions, which causes 

generation to be re-dispatched, which in 

turn changes the flow patterns on the 

transmission system. The curtailments 

are based on a power flow model of the 

Eastern Interconnection, and have the 

effect of reducing the loading on those 

lines over which the transactions are 

actually flowing. 

553. NERC agrees that the TLR 

procedure alone is usually not effective 

as a control measure to mitigate an IROL 

violation and explains that the TLR 

procedure was not intended to be 

effective in this manner.229 It states that, 

while TLR procedures can be effective 

as a preventive tool to adjust and 

manage bilateral transactions so that 

limit violations do not occur, other 

options such as local or market area redispatch and transmission 

reconfiguration are more precise for a 

system operator to stay within SOLs and 

IROLs. 

554. NERC believes that transmission 

operators and reliability coordinators 

understand that the TLR procedure is 

not the only method for mitigating an 

SOL or IROL violation and that the 

proposed Reliability Standard—as one 

tool among many—is adequate and 

necessary to protect Bulk-Power System 

reliability. NERC states that ‘‘it does not 

believe the recommendation of the 

Blackout Report that ‘‘the [TLR] process 

should not be used in situations 

involving an actual violation of an 

Operating Security Limit [SOL]’’ needs 

further discussion to determine possible 

changes to standard.’’ 230

555. ISO/RTO Council states that, 

although TLR should not be considered 

an emergency procedure,231

Requirement R1 of IRO–006–3 does not 

require use of TLR procedures and 

permits the implementation of existing 

policies and procedures to correct 

transmission loading.232 It further states 

that Requirement R1 appropriately 

identifies a reliability coordinator as 

being responsible for actions related to 

transmission loading. As a result, 


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233NERC Comments at 49. 

234See Blackout Report at 63. 

235 Id. at 163. 

236WSCC is an old reference to WECC. 

because Requirement R1 clearly does 

not specify the use of TLR, and instead 

explicitly calls for the use of appropriate 

tools available to the reliability 

coordinator, the ISO/RTO Council 

believes that IRO–006–3 allows entities 

sufficient flexibility to ensure reliability. 

556. However, ISO/RTO Council 

explains the limitations of TLR in EOP–

002–0 that most ISOs and RTOs use redispatch to correct SOL and IROL 

violations instead of TLR procedures 

because re-dispatch is superior to TLR 

procedures for the purposes of ensuring 

system reliability. It further states that 

as a result, the applicability to an ISO 

or RTO region of any Reliability 

Standard that provides for the use of 

TLR procedures is not clear, and if 

applied, could actually be detrimental 

to reliability. 

557. ReliabilityFirst agrees in general 

with the Staff Preliminary Assessment. 

NYSRC comments that the concerns 

articulated by staff are not significant 

enough to prevent approval of the 

proposed Reliability Standard. MRO 

believes that IRO–006–3 should be 

modified to clarify the use of TLR as 

proposed by the Staff Preliminary 

Assessment due to the identified 

interpretation issue. 

558. CenterPoint contends that the 

ERCOT region should be explicitly 

exempted from these [IRO] Reliability 

Standards since ERCOT does not use 

TLR procedures. Instead, it manages 

congestion using procedures relevant to 

ERCOT market rules. 

iv. Commission Proposal 

559. The Commission proposes to 

approve IRO–006–3 as mandatory and 

enforceable. In addition, we propose to 

direct that NERC develop modifications 

to the Reliability Standard as discussed 

below. 

560. The Commission notes that 

NERC agrees that the TLR procedure is 

usually not effective by itself as a 

control measure to mitigate an IROL 

violation, the procedure is not intended 

to be effective in this manner and that 

it be combined with other effective 

methods such as reconfiguration, redispatch or load shedding until relief 

requested by the TLR process is 

achieved.233 The Commission is 

concerned, however, that the 

Requirements in IRO–006–3 do not 

sufficiently convey the availability of 

alternatives, nor highlight the 

inefficiency of TLR procedure which 

requires a lead time for implementation 

much longer than the allowable 30 

minutes to return the system from IROL 

violation to a secure state. This could 

potentially mislead a transmission 

operator or reliability coordinator that is 

attempting to mitigate an IROL violation 

to first deploy the TLR procedure only 

to find out later that other more effective 

operating measures should have been 

used. In addition, we duly note ISO/ 

RTO Council’s comment that the 

applicability to an ISO or RTO region of 

any Reliability Standard that provides 

for the use of TLR procedures is not 

clear, and if applied, could actually be 

detrimental to reliability. Since the 

system is subject to cascading outages 

when it is in IROL violation, we have 

particular concern regarding the use of 

TLR to mitigate IROL violations and less 

so on its use on SOLs since the latter 

would not result in cascading outages. 

561. While NERC suggests that 

transmission operators and reliability 

coordinators understand that the TLR 

procedure is not the sole method for 

mitigating an SOL or IROL violation, the 

Commission notes that the Blackout 

Report suggests otherwise with regard to 

the causes of the August 2003 cascading 

blackout since the operator was first 

attempting to use TLR to mitigate an 

IROL violation only to find out it was 

ineffective.234 This led the Blackout 

Task Force to recommend that NERC 

‘‘clarify that the [TLR] process should 

not be used in situations involving an 

actual violation of an Operating Security 

Limit.’’ 235

562. We propose that the Reliability 

Standard should also clearly provide the 

flexibility for ISOs and RTOs to rely on 

re-dispatch, as suggested by ISO/RTO 

Council. Accordingly, we propose to 

direct that NERC modify IRO–006–3 to 

(1) include a clear warning that TLR 

procedure is an inappropriate and 

ineffective tool to mitigate IROL 

violation and (2) to identify effective 

alternatives to use of the TLR procedure 

in situations involving an IROL 

violation. 

563. With regard to CenterPoint 

suggestion that the ERCOT region be 

explicitly exempted from compliance 

with IRO–006–3, we note that our 

regulations require that any such 

proposal must be developed through an 

open, stakeholder process and 

submitted to the Commission by the 

ERO. 

564. The Commission notes that 

Requirement R2.2 identifies the ‘‘WSCC 

Unscheduled Flow Mitigation Plan’’ 236

as an equivalent load relief procedure 

for use in the Western Interconnection. 

The referenced document contains 

governance, compensation, charges for 

use of the procedure and limitations on 

applicable facilities which are unusual 

in a Reliability Standard. The 

Commission believes that these issues 

are part of the transition to mandatory 

Reliability Standards and are mainly 

administrative in nature. The 

Commission believes that the WECC 

approach is superior to the national 

standard because it uses phase angle 

regulators, series capacitors and back-toback DC lines to mitigate contingencies 

without curtailing transactions. The 

Commission proposes to approve its 

use. 

565. The Commission notes that 

Requirement R2.3 identifies section 7 of 

the ERCOT Protocols as an equivalent 

load relief procedure for use in the 

Texas Interconnection. The Protocol 

contains significant details about the 

ERCOT market that are unusual in a 

Reliability Standard. The Commission 

believes that these issues are part of the 

transition to mandatory Reliability 

Standards and are mainly 

administrative in nature. The 

Commission believes that the ERCOT 

zonal LMP approach is superior to the 

national standard in that it uses 

generation re-dispatch and pricing to 

mitigate congestion without curtailing 

transactions. The Commission proposes 

to approve its use. 

566. While the Commission has 

identified concerns with regard to IRO–

006–3, we believe that the proposal 

serves an important purpose in ensuring 

reliability coordinators have a 

coordinated method for alleviating 

loadings on the transmission system 

when it becomes too congested to avoid 

potential SOL and IROL violations. It 

also includes a regional difference for 

reporting market flow information to the 

Interchange Distribution Calculator. The 

Commission believes that it is important 

for NERC to clarify that the TLR process 

is not the only, and perhaps not even 

the preferred, method to mitigate an 

SOL and especially IROL violation. The 

proposed Requirements set forth in 

IRO–006–3 are sufficiently clear and 

objective to provide guidance for 

compliance. 

567. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard IRO–006–

3 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 


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64826 Federal Register / Vol. 71, No. 213 / Friday, November 3, 2006 / Proposed Rules 

to IRO–006–3 that: (1) Includes a clear 

warning that TLR procedure is an 

inappropriate and ineffective tool to 

mitigate IROL violations; (2) identifies 

in a Requirement the available 

alternatives to use of the TLR procedure 

to mitigate an IROL violation; and (3) 

includes Measures and Levels of NonCompliance that address each 

Requirement. 

i. Regional Difference to IRO–006–3: 

PJM/MISO/SPP Enhanced Congestion 

Management (Curtailment/Reload/ 

Reallocation) 

i. NERC Proposal 

568. IRO–006–003 provides for a 

regional difference for MISO, PJM and 

SPP. NERC explains that this regional 

difference is needed to allow RTO 

market practices, simplify transaction 

information requirements for market 

participants, and provide reliability 

coordinators with appropriate 

information for security analysis and 

curtailments, reloads, reallocations and 

redispatch requirements. 

ii. Staff Preliminary Assessment 

569. This regional difference was not 

addressed in the Staff Preliminary 

Assessment. 

iii. Comments 

570. MISO and PJM, in a joint filing, 

contend that there is unduly 

discriminatory treatment of the market 

flows of MISO and PJM versus the 

generation-to-load impacts of nonmarket entities in the application of the 

TLR standard. They argue that NERC 

should modify IRO–006–3 and the 

MISO/PJM regional difference to 

require: (1) Netting of generation-to-load 

impacts; (2) reporting to the Interchange 

Distribution Calculator all net 

generation-to-load impacts for both 

market and non-market transmission 

providers; and (3) modifying the 

curtailment threshold to a standard 

percentage for all impacts thus reported 

to the Interchange Distribution 

Calculator to a level that is technically 

feasible to implement and on a nondiscriminatory basis. MISO and PJM 

also note that they, as well as SPP, have 

been working through various groups to 

achieve a consensus on these changes. 

According to MISO and PJM, these 

efforts were fruitful, but they were 

unable to complete the changes prior to 

NERC’s April 6, 2006 submission of its 

Version 0 reliability standards for 

Commission approval. The Commission 

believes that SPP could experience the 

same problems identified by MISO and 

PJM. 

iv. Commission Proposal 

571. The Commission believes that 

the comments and information 

presented by MISO and PJM are 

persuasive. However, before acting on 

this regional difference, the Commission 

invites comments to assure that we have 

a full and complete record on which to 

base our decision. 

572. The Commission notes that 

MISO and PJM indicate that their 

competition concerns are being 

addressed in discussions with NERC 

and other relevant entities. The 

Commission prefers that PJM, MISO and 

others continue to pursue a negotiated 

resolution rather than having the 

Commission impose a solution on 

market participants. Accordingly, the 

Commission will not propose to 

approve or remand this regional 

difference. 

j. Procedures, Processes, or Plans to 

Support Coordination Between 

Reliability Coordinators (IRO–014–1) 

i. NERC Proposal 

573. The stated purpose of IRO–014–

1 is to ensure that each reliability 

coordinator’s operations are coordinated 

such that they will not have an adverse 

reliability impact on other reliability 

coordinator areas and to preserve the 

reliability benefits of interconnected 

operation. Specifically, IRO–014–1 

ensures energy balance and 

transmission by requiring a reliability 

coordinator to have operating 

procedures, processes or plans for the 

(1) exchange of operating information 

and (2) coordination of operating plans. 

ii. Staff Preliminary Assessment 

574. No substantive issues were 

identified for IRO–014–1. 

iii. Comments 

575. No comments were submitted 

regarding IRO–014–1. 

iv. Commission Proposal 

576. The Commission believes that 

IRO–014–1 contains sufficient details in 

the specification of the required 

procedures, processes or plans for a 

reliability coordinator to support 

coordination among it neighbors, and 

agreements that all reliability 

coordinators, as the only applicable 

entity, must take the indicated actions 

to ensure coordinated and reliable 

operations. 

577. For the reasons discussed above, 

the Commission proposes to approve 

Reliability Standard IRO–014–1 as just, 

reasonable, not unduly discriminatory 

or preferential, and in the public 

interest. 

k. Notifications and Information 

Exchange Between Reliability 

Coordinators (IRO–015–1) 

i. NERC Proposal 

578. Proposed Reliability Standard 

IRO–015–1 establishes Requirements for 

a reliability coordinator to share and 

exchange reliability-related information 

among its neighbors and participate in 

agreed-upon conference calls and other 

communication forums with adjacent 

reliability coordinators. This exchange 

of reliability-related information among 

reliability coordinators facilitates 

situation awareness. 

ii. Staff Preliminary Assessment 

579. No substantive issues were 

identified for IRO–015–1. 

iii. Comments 

580. No comments were submitted 

regarding IRO–015–1. 

iv. Commission Proposal 

581. The Commission believes that 

IRO–015–1 contains sufficient 

Requirements to ensure that reliability 

coordinators inform and exchange 

information with other reliability 

coordinators, as the only applicable 

entity, to ensure coordinated operations. 

582. For the reasons discussed above, 

the Commission proposes to approve 

Reliability Standard IRO–015–1 as just, 

reasonable, not unduly discriminatory 

or preferential, and in the public 

interest. 

l. Coordination of Real-Time Activities 

Between Reliability Coordinators (IRO–

016–1) 

i. NERC Proposal 

583. IRO–016–1 establishes 

Requirements for coordinated real-time 

operations, including: (1) Notification of 

problems to neighboring reliability 

coordinators and (2) discussions and 

decisions for agreed-upon solutions for 

implementation. It also requires a 

reliability coordinator to maintain 

records of its actions. Where a 

disagreement arises, IRO–016–1 requires 

that reliability coordinators work with 

one another until a system problem is 

resolved or implement the more 

conservative solution. 

ii. Staff Preliminary Assessment 

584. No substantive issues were 

identified for IRO–016–1. 

iii. Comments 

585. No comments were submitted 

regarding IRO–016–1. 

iv. Commission Proposal 

586. The Commission believes that 

IRO–016–1 contains sufficient 


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237MOD–001–0 through MOD–009–0. 

238MOD–010–0 through MOD–015–0. 

239MOD–016–0 through MOD–021–0. 

240MOD–024–1 through MOD–025–1. 

241OATT Reform NOPR, 71 FR 32636 at 32658. 

242 Id., 71 FR at 32654 and 32667. 

243AFC is a methodology that first calculates 

available capacity on a flowgate-AFC, and transfers 

that value into ATC by dividing AFC with the 

associated flowgate distribution factor. After ATC is 

determined, TTC is calculated from ATC for posting 

on OASIS. This method is different from NERC’s 

original ATC calculation, where TTC is calculated 

in a first step and then used to determine ATC by 

reducing TTC with capacity needed for existing 

commitments and reserve margins. 

244The NERC Report made recommendations for 

greater consistency and greater clarity in the 

calculation of ATC/AFC. The task force also 

recommended greater communication and 

coordination of ATC/AFC information to ensure 

that neighboring entities exchange relevant 

information. See NERC, Long-Term AFC/ATC Task 

Force Final Report (2005) (NERC Report) at 2, 

available at: ftp://www.nerc.com/pub/sys/all_updl/ 

mc/ltatf/LTATF_Final_Report_Revised.pdf. 

245The first SAR proceeding proposes changes to 

the existing standards on ATC to, among other 

things, further establish consistency in the 

calculation of ATC and to increase the clarity of 

each transmission provider’s ATC calculation 

methodology. The second SAR proceeding proposes 

certain changes to NERC’s existing CBM and TRM 

standards and calls for greater regional consistency 

and transparency in how CBM and TRM are treated 

in transmission providers’ ATC calculations. 

requirements for a reliability 

coordinator to inform, discuss and 

identify a solution with other reliability 

coordinators to prevent or resolve a 

problem that requires joint actions from 

all affected reliability coordinators as 

the only applicable entity. It also clearly 

articulates binding and conservative 

corrective actions to be taken in the 

event that an agreement cannot be 

reached among them. 

587. For the reasons discussed above, 

the Commission proposes to approve 

Reliability Standard IRO–016–1 as just, 

reasonable, not unduly discriminatory 

or preferential, and in the public 

interest. 

8. MOD: Modeling, Data, and Analysis 

a. Overview 

588. The Modeling, Data, and 

Analysis group of Reliability Standards 

are intended to standardize 

methodologies and system data needed 

for traditional transmission system 

operation and expansion planning, 

reliability assessment, and the 

calculation of available transmission 

capacity (ATC) in an open access 

environment. The 23 standards may be 

grouped into four distinct categories. 

The first category covers methodology 

and associated documentation, review, 

and validation of Total Transfer 

Capability (TTC), ATC, Capacity Benefit 

Margin (CBM), and Transmission 

Reliability Margin (TRM) 

calculations.237 The second category 

covers steady-state and dynamics data 

and models.238 The third category 

covers actual and forecast demand 

data.239 The fourth category covers the 

verification of generator real and 

reactive power capability.240

OATT Reform NOPR and the MOD 

Standards 

589. The Commission has been 

considering ATC, TTC, CBM and TRM 

calculation issues in Docket Nos. 

RM05–17–000 and RM05–25–000, and 

is addressing them in the OATT Reform 

NOPR.241 Among other things, the 

OATT Reform NOPR discusses the need 

for consistency and transparency of 

ATC, TTC, CBM, and TRM. It proposes 

that public utilities, working through 

NERC/NAESB, would use the guidelines 

in the OATT Reform NOPR to revise the 

relevant standards and business 

practices, and asks for comments on 

certain proposals. It also recognizes that 

there are still many unspecified 

elements in the calculation processes 

and development of modeling 

assumptions, and deficiencies in data 

exchange that may have a negative 

impact on both transmission system 

reliability and competition.242

590. The industry also acknowledged 

this problem and has taken steps to 

address the lack of consistency and 

transparency in the way ATC is 

calculated. NERC formed a Long-Term 

Available Flowgate Capacity 243 (AFC)/ 

ATC Task Force to review NERC’s 

standards on ATC, which issued a final 

report in 2005.244 Based on the 

recommendations in the NERC Report, 

NERC has begun two Standards 

Authorization Request (SAR) 

proceedings to revise the standards on 

ATC.245 NAESB has also begun a 

proceeding to develop business practice 

standards to enhance the processing of 

transmission service requests, which 

affects the ATC calculation. 

Staff Preliminary Assessment 

591. Staff expressed concerned that 

fourteen of the twenty-three Reliability 

Standards in this group apply to 

regional reliability organization, which 

is not a user, owner, or operator of the 

Bulk-Power System. 

General Comments 

592. NERC comments that it has a 

team in place to address the regional 

reliability organization applicability 

issue and will submit an action plan 

and schedule in November 2006 for 

completing the fill-in-the-blank 

standards. NERC expects that it will 

take approximately three years to 

complete the process, and will prioritize 

standards that require the most 

immediate revision. 

593. CenterPoint advocates 

eliminating many of the MOD 

Reliability Standards or consolidating 

them into planning or operating 

standards. CenterPoint reasons that, to 

the extent the process-oriented 

Reliability Standards are necessary, the 

‘‘fill-in-the-blank’’ standards are 

necessary; however, it is impractical to 

require that each region use identical 

practices in building and validating its 

models. CenterPoint adds that, should 

the Reliability Standards be approved 

by the Commission, ERCOT should be 

exempt from those that address transfer 

capability because ERCOT does not 

have any inter-control area transfers and 

does not use the NERC methodologies. 

Commission Proposal 

594. As we discussed in the Common 

Issues section above describing fill-inthe-blank Reliability Standards, we 

propose to seek additional information 

before acting on the Reliability 

Standards that require the regional 

reliability organization to provide 

criteria on procedures. 

595. While we agree with CenterPoint 

that some of the MOD Reliability 

Standards could be grouped into 

planning or operating standards, we will 

not propose any such modification, but 

rather, leave it to the discretion of the 

ERO. Regarding CenterPoint’s 

suggestion that ERCOT should be 

exempt from Reliability Standards that 

address available transfer capability, the 

Commission will consider any regional 

difference at the time it is submitted by 

NERC for Commission review. 

Therefore, if ERCOT wishes to request a 

regional difference it must do so 

through the ERO process. 

b. Documentation of Total Transfer 

Capability and Available Transfer 

Capability Calculation Methodologies 

(MOD–001–0) 

i. NERC Proposal 

596. NERC states that the purpose of 

MOD–001–0 is to promote the 

consistent and uniform application of 

transfer capability calculations among 

transmission system users. The 

Reliability Standard requires the 

regional reliability organizations to 

develop their respective methods for 

determining TTC and ATC and to make 

those methodologies available to others 

for review. The Reliability Standard 

contains two Requirements directing 

each regional reliability organization to: 

(1) Develop and document a regional 

TTC and ATC methodology in 

conjunction with its members; and (2) 


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64828 Federal Register / Vol. 71, No. 213 / Friday, November 3, 2006 / Proposed Rules 

246OATT Reform NOPR at ¶ 155–70. 

247For example, there are two primary ATC 

calculation methodologies: the contract path 

approach and the flowgate approach. However, the 

ATC values that result from application of either 

method should largely be the same if consistent 

data inputs and modeling assumptions are used. 

See OATT Reform NOPR, 71 FR 32653. 

248Available Flowgate Capability is a method 

widely used in the Eastern Interconnection but 

there is no NERC definition for that term. 

249ETC includes transmission capacity set aside 

for both native load and transmission reservations. 

post the most recent version of its TTC 

and ATC methodology at a Web site 

accessible by NERC, the regional 

reliability organizations, and 

transmission users. 

597. The first Requirement specifies 

nine items that the regional reliability 

organization must include in its 

methodology for determining its TTC 

and ATC values. Most of these items 

call for descriptions on how TTC and 

ATC values are determined and what 

assumptions are used. Two items 

require the regional reliability 

organization to take into account the 

reservations and schedules for 

transactions occurring inside and 

outside the transmission provider’s 

system. One item specifies a time and 

frequency for calculating and posting 

TTC and ATC values. 

ii. Staff Preliminary Assessment 

598. Staff identified MOD–001–0 as a 

‘‘fill-in-the-blank’’ standard that applies 

to the regional reliability organization. 

Staff expressed concern that industry 

historically used inconsistent 

calculation methodologies and stated 

that this inconsistency could have an 

undue negative impact on competition. 

iii. Comments 

599. Although NERC acknowledges 

that proposed Reliability Standard 

MOD–001–0 needs improvement, it 

urges that the Commission approve it. 

NERC explains that the final version of 

the ATC/TTC/AFC Revision SAR 

proposes a method for calculating ATC 

and requires that specific reliability 

practices be incorporated into the ATC 

calculation and coordination 

methodologies. Further, NERC advises 

that a requirement will be added to 

enhance documentation of the 

calculation. 

600. MRO acknowledges that, because 

TTC and ATC values must satisfy 

certain principles, which balance both 

technical and commercial issues from 

each of the regions, there may be 

differences in the calculation of these 

values from the different regions. 

However, MRO adds that the parties in 

the Eastern Interconnection must agree 

to the values, calculations, and 

methodologies which flow across the 

borders of various regions and system 

operators. MRO states that these should 

be transparent and agreements should 

be based on rational, technical 

requirements. 

601. ReliabilityFirst submits that it 

generally agrees with staff’s evaluation 

that, to ensure consistency, procedures 

developed by the individual regions 

need to be combined. Similarly, TAPS 

advises that there are significant flaws 

and undue competitive impacts in the 

way the Reliability Standard is currently 

proposed. TAPS urges the Commission 

to make the calculations related to this 

Reliability Standard transparent, 

consistent, and regionally-based. 

iv. Commission Proposal 

602. MOD–001–0 is a ‘‘fill-in-theblank’’ standard that requires each 

regional reliability organization to 

develop its respective methods for 

determining TTC and ATC and to make 

those methodologies available to others 

for review. Because the regional 

procedures have not been submitted to 

the Commission, it is not possible to 

determine at this time whether MOD–

001–0 satisfies the statutory requirement 

that a proposed Reliability Standard be 

‘‘just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest.’’ Accordingly, the 

Commission will not propose to accept 

or remand this Reliability Standard 

until the ERO submits additional 

information. In the interim, compliance 

with MOD–001–0 should continue on 

its current basis, and the Commission 

considers compliance with the 

Reliability Standard to be a matter of 

good utility practice. Although we do 

not propose any action with regard to 

MOD–001–0 at this time, we address 

our concerns regarding this Reliability 

Standard below. The concerns we 

discuss below are consistent with the 

OATT Reform NOPR.246

603. The Reliability Standard only 

requires that the regional reliability 

organization document its ATC and TTC 

methodology and post that 

documentation. The Reliability 

Standard does not contain clear 

Requirements on how ATC and TTC 

should be calculated, which has 

resulted in diverse interpretations of 

ATC, TTC, and the development of 

various calculation methodologies, 

modeling assumptions, and data 

exchange protocols by various 

entities.247 This creates potential 

reliability issues and an opportunity to 

unduly discriminate against 

competitors. 

604. Further, the different approaches 

in calculation of ATC/AFC,248 TTC, and 

lack of clear requirements for 

calculation of existing transmission 

commitments (ETC) 249 could also create 

an undue negative impact on 

competition. For example, NERC has 

not proposed either a definition or 

Reliability Standard on how ETC should 

be determined. This could allow 

transmission providers to set aside more 

capacity for native load than is needed, 

and ultimately block capacity that 

would otherwise be available to 

unaffiliated transmission customers. 

This also gives broad discretion to a 

transmission provider to determine how 

to model power transfers and associated 

loop flows that impact the neighboring 

systems reliability. We believe that this 

Reliability Standard should, at a 

minimum, provide a framework for the 

ATC, TTC, and ETC calculation. 

605. MOD–001–0 requires that the 

regional reliability organization develop 

and post its methodology on TTC and 

ATC, but only requires a narrative 

description of a few elements of the TTC 

and ATC calculation. We believe that 

this Reliability Standard should include 

a requirement that applicable entities 

make available a comprehensive list of 

assumptions and contingencies 

underlying ATC and TTC calculations. 

We believe that such documentation 

should include mathematical 

algorithms, process flow diagrams, data 

inputs, identification of flowgates, and 

modeling assumptions used to perform 

the TTC and ATC calculations, 

consistent with those proposed in the 

OATT Reform NOPR. 

606. We are further concerned that the 

Reliability Standard does not clearly 

define the data to be shared among 

transmission service providers. We 

believe that MOD–001–0 could be 

improved by identifying a detailed list 

of information to be shared. This is 

consistent with the OATT Reform 

NOPR, which proposes that, at a 

minimum, the following data should be 

exchanged among transmission 

providers for the purposes of ATC 

modeling: (1) Load levels; (2) 

transmission planned and contingency 

outages; (3) generation planned and 

contingency outages; (4) base generation 

dispatch; (5) existing transmission 

reservations, including counterflows; (6) 

ATC calculation frequency; and (7) 

source/sink modeling identification. 

607. In addition, the Commission 

notes that MOD–001–0 inappropriately 

combines the requirements for TTC and 

ATC methodology into one Reliability 

Standard. TTC and ATC serve two 

different purposes and are calculated 

through different calculation processes. 

We believe that MOD–001–0 should 


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250Total Transfer Capability is defined in the 

NERC glossary as ‘‘[t]he amount of electric power 

that can be moved or transferred reliably from one 

area to another area of the interconnected 

transmission systems by way of all transmission 

lines (or paths) between those areas under specified 

system conditions.’’ NERC glossary at 14. 

251Transfer Capability is defined in NERC 

glossary as ‘‘[t]he measure of the ability of 

interconnected electric systems to move or transfer 

power in a reliable manner from one area to another 

over all transmission lines (or paths) between those 

areas under specified system conditions. The units 

of transfer capability are in terms of electric power, 

generally expressed in megawatts (MW). The 

transfer capability from ‘Area A’ to ‘Area B’ is not 

generally equal to the transfer capability from ‘Area 

B’ to ‘Area A.’ ’’ NERC glossary at 15. 

252OATT Reform NOPR at P 166. 

253We note that our observation here also applies 

to MOD–002, MOD–003, MOD–004, MOD–005, 

MOD–008, MOD–009, MOD–011, MOD–013, MOD–

014, MOD–015, MOD–016, MOD–024, and MOD–

025. 

address only the ATC and AFC 

requirements while the TTC 

requirements should be addressed in a 

separate Reliability Standard such as 

FAC–012–1, as discussed below. 

608. The NERC glossary does not 

substantially differentiate between the 

definition of TTC (as used in MOD–

001–0) 250 and transfer capability (as 

used in FAC–012–1).251 Thus, there are 

two Reliability Standards to measure 

essentially the same thing: One 

Reliability Standard calculates TTC 

using one set of data and modeling 

assumptions presumably for use in 

evaluating transmission service 

requests, and another Reliability 

Standard calculates transfer capability 

for in-house use in planning and 

operations studies. This will not only 

cause confusion, but also opportunities 

for discrimination against transmission 

customers. We believe that the TTC 

calculation methodology should be 

addressed under FAC–012–1, which 

standardizes transfer capability 

methodology. 

609. We reiterate our concern 

expressed in the OATT Reform NOPR 

that modeling assumptions are a crucial 

element in the calculation of ATC.252

We believe that NERC should develop a 

set of consistent assumptions as a part 

of MOD–001–0 for use in ATC and AFC 

determinations. Consistent with the 

OATT Reform NOPR, we believe that 

the assumptions in the calculation of 

ATC and AFC should be used 

consistently among transmission 

providers to the maximum extent 

practicable. In general, the Commission 

believes that the assumptions used in 

the determination of ATC and AFC 

should be consistent with those used for 

planning the expansion or operation of 

the Bulk-Power System. Consequently, 

the models for short- and long-term ATC 

and AFC calculation should be 

developed using consistent assumptions 

regarding the load level, generation 

dispatch, transmission and generation 

facilities maintenance schedules, 

contingency outages and topology as 

those used for expansion planning and 

operations. Consistent with the OATT 

Reform NOPR, we believe that the longterm ATC and AFC models should rely 

to the maximum extent possible on the 

same assumptions regarding new 

transmission and generation facility 

additions and retirements as those used 

in the planning for expansion. 

Specifically, MOD–001–0 should 

contain a Requirement that long-term 

ATC (one year and longer) be based on 

the calculation that uses the same power 

flow models, assumptions regarding 

load, generation dispatch, special 

protection systems, post contingency 

switching, and transmission and 

generation facility additions and 

retirements as those used in the 

expansion planning for the same time 

frame. 

610. Finally, the applicability section 

identifies that the Reliability Standard 

applies to regional reliability 

organizations. Consistent with our 

discussion above, we believe that NERC 

should identify the applicable entities 

in terms of users, owners, and operators 

of the Bulk-Power System.253

c. Review of Transmission Service 

Provider Total Transfer Capability and 

Available Transfer Capability 

Calculations and Results (MOD–002–0) 

i. NERC Proposal 

611. MOD–002–0 concerns the review 

of transmission service providers’

compliance with the regional 

methodologies for calculating TTC and 

ATC. It requires that the regional 

reliability organization: (1) Develop and 

implement a procedure to periodically 

review and ensure that the TTC and 

ATC calculations and resulting values 

developed by transmission service 

providers comply with the regional TTC 

and ATC methodology and applicable 

regional criteria; (2) document the 

results of its periodic review of TTC and 

ATC; and (3) provide the results of its 

most current reviews to NERC on 

request within 30 calendar days. 

ii. Staff Preliminary Assessment 

612. Staff identified no substantive 

issues other than the fact that MOD–

002–0 is a ‘‘fill-in-the-blank’’ standard 

and that the standard applies to the 

regional reliability organization. 

iii. Comments 

613. The Commission received no 

specific comments regarding MOD–002–

0. 

iv. Commission Proposal 

614. MOD–002–0 is a ‘‘fill-in-theblank’’ Reliability Standard that requires 

each regional reliability organization to 

develop and implement a procedure to 

periodically review and ensure that a 

transmission service provider’s TTC and 

ATC calculations comply with regional 

TTC and ATC methodologies and 

criteria. Because the regional procedures 

have not been submitted to the 

Commission, it is not possible to 

determine at this time whether MOD–

002–0 satisfies the statutory requirement 

that a proposed Reliability Standard be 

‘‘just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest.’’ Accordingly, the 

Commission will not propose to 

approve or remand this Reliability 

Standard until the regional procedures 

are submitted. In the interim, 

compliance with MOD–002–0 should 

continue on a voluntary basis, and the 

Commission considers compliance with 

the Reliability Standard to be a matter 

of good utility practice. 

d. Regional Procedure for Input on Total 

Transfer Capability and Available 

Transfer Capability Methodologies and 

Values (MOD–003–0) 

i. NERC Proposal 

615. MOD–003–0 defines how a 

transmission user can submit its 

concerns regarding ATC/TTC 

calculation methodologies and values. It 

requires each regional reliability 

organization to: (1) Develop and 

document a procedure on how a 

transmission user can input their 

concerns or questions regarding TTC 

and ATC calculations including the TTC 

and ATC values, and how these 

concerns will be addressed; and (2) 

make its procedure for receiving and 

addressing these concerns available to 

other regional reliability organizations, 

NERC and transmission users on its 

Web site. 

ii. Staff Preliminary Assessment 

616. The Staff Preliminary 

Assessment noted that MOD–003–0 is a 

‘‘fill-in-the-blank’’ standard. It also 

raised concern that MOD–003–0 does 

not provide a consistent procedure for 

transmission users to input concerns or 

questions regarding the methodology for 

calculation of TTC and ATC and 

resulting TTC and ATC values, nor does 

it provide a consistent procedure for 


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64830 Federal Register / Vol. 71, No. 213 / Friday, November 3, 2006 / Proposed Rules 

254The NERC glossary defines ‘‘capacity benefit 

margin’’ or ‘‘CBM’’ as the amount of firm 

transmission transfer capability preserved by a 

transmission provider for load serving entities 

whose loads are located on the transmission service 

provider’s system, to enable access by the load 

serving entity to generation from interconnected 

systems to meet generation reliability requirements. 

NERC glossary at 2. 

255The Commission has explained that the pro 

forma OATT requires both transmission customers 

and transmission providers using the transmission 

system to serve network load (including bundled 

retail native load) to designate their resources and 

loads so that the transmission customers and 

transmission providers would have no incentive to 

designate network resources above their needs and, 

in so doing, tie up valuable transmission capacity. 

Aquila Power Corp. v. Entergy Services, Inc., 90 

FERC ¶ 61,260, reh’g denied, 92 FERC ¶ 61,064 

(2000), reh’g denied, 101 FERC¶ 61,328 (2002), aff’d 

sub nom. Entergy Services, Inc. v. FERC, 375 F.3d 

1204 (D.C. Cir. 2004). 

how these questions or concerns will be 

addressed. 

iii. Comments 

617. The Commission received no 

comments regarding MOD–003–0. 

iv. Commission Proposal 

618. MOD–003–0 is a ‘‘fill-in-theblank’’ standard that requires each 

regional reliability organization to 

develop and document a procedure to 

on how a transmission user can input its 

concerns regarding the TTC and ATC 

methodologies of a transmission service 

provider. Because the regional 

procedures have not been submitted to 

the Commission, it is not possible to 

determine at this time whether MOD–

003–0 satisfies the statutory requirement 

that a proposed Reliability Standard be 

‘‘just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest.’’ Accordingly, the 

Commission will not propose to accept 

or remand this Reliability Standard 

until the regional procedures are 

submitted. In the interim, compliance 

with MOD–003–0 should continue on a 

voluntary basis, and the Commission 

considers compliance with the 

Reliability Standard to be a matter of 

good utility practice. 

e. Documentation of Regional Reliability 

Organization Capacity Benefit Margin 

Methodologies (MOD–004–0) 

i. NERC Proposal 

619. NERC states that the purpose of 

MOD–004–0 is to promote the 

consistent and uniform application of 

transmission transfer capability margin. 

MOD–004–0 addresses the development 

of a regional methodology for CBM.254

The Reliability Standard requires each 

regional reliability organization to: (1) 

Develop and document a regional CBM 

methodology in conjunction with its 

members; and (2) post the most recent 

version of its CBM methodology on a 

Web site accessible by NERC, regional 

reliability organizations, and 

transmission users. 

620. The first Requirement specifies 

ten items that the regional reliability 

organization must include and explain 

in its CBM calculation method. In 

addition, the Reliability Standard 

requires that other regional reliability 

organization-specific items be explained 

along with their use in determining 

CBM values. These requirements specify 

that calculation of CBM be consistent 

with the generation planning criteria, 

and that generation outages simulated in 

a transmission provider’s CBM 

calculation be restricted to those 

generators located within the 

transmission provider’s system. It is also 

required that CBM should be preserved 

only for the load within the control area. 

The allocation process of the CBM 

should be identified. In addition, it 

requires that the sum of the CBM values 

allocated to all interfaces at one control 

area shall not exceed the portion of the 

generation reliability requirement that is 

to be provided from outside resources. 

The remaining items require a 

description of the rationale regarding 

the assumptions used for CBM 

calculation. Finally, it requires a 

description of the formal process and 

rational for the regional reliability 

organization to grant any variances to 

individual transmission providers from 

the regional reliability organization’s 

CBM methodology. 

ii. Staff Preliminary Assessment 

621. The Staff Preliminary 

Assessment noted that MOD–004–0 is a 

‘‘fill-in-the-blank’’ standard. Further, 

while MOD–004–0 requires each 

regional reliability organization to 

develop and document a regional CBM 

methodology, it does not specify how 

CBM is determined and allocated across 

transmission paths. Staff expressed 

concern that the Reliability Standard 

does not address the effect of associated 

transmission service requirements and 

curtailment provisions on transmission 

customers nor does it specify the criteria 

used in determining whether or not to 

include generation resources, reserves, 

and loads in its methodology as 

described in four of the Requirements 

(R1.5, R1.6, R1.9, and R1.10). 

iii. Comments 

622. NERC points out that the CBM/ 

TRM Revisions Standard Authorization 

Request (SAR) proposes requiring crisp 

and clear calculation documentation 

and making various components of the 

methodology mandatory to ensure 

consistency. 

623. TAPS agrees with staff’s 

evaluation of MOD–004–0. TAPS states 

that the proposed Reliability Standard 

has significant flaws and will harm 

competition if accepted in its current 

form. For example, TAPS refers to the 

significant potential for abuse because 

transmission providers have flexibility 

in the calculation of CBM. Further, 

TAPS questions how CBM can be 

viewed as a Reliability Standard if it is 

optional to the transmission provider. 

TAPS urges the Commission to make 

the calculations related to this standard 

transparent, consistent, and regionallybased. 

iv. Commission Proposal 

624. MOD–004–0 is a ‘‘fill-in-theblank’’ Reliability Standard that requires 

each regional reliability organization to 

develop and document a regional CBM 

methodology. Because the regional CBM 

methodologies have not been submitted 

to the Commission, it is not possible for 

determine at this time whether MOD–

004–0 satisfies the statutory requirement 

that a proposed Reliability Standard be 

‘‘just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest.’’ Accordingly, the 

Commission will not propose to accept 

or remand this Reliability Standard 

until the regional procedures are 

submitted. In the interim, compliance 

with MOD–004–0 should continue on a 

voluntary basis, and the Commission 

considers compliance with the 

Reliability Standard to be a matter of 

good utility practice. 

625. Although we do not propose any 

action with regard to MOD–004–0 at 

this time, we address our concerns 

regarding the Reliability Standard 

below. 

626. We share TAPS’ concern that 

MOD–004–0 may contain significant 

flaws and may unduly impact 

competition. The Commission 

expressed similar concerns with the 

CBM calculation in the OATT Reform 

NOPR. The lack of consistent criteria 

and clarity with regard to the entity on 

whose behalf CBM has been set aside 

has the potential to result in the 

transmission provider setting aside 

capacity that it might not otherwise 

need to, thus increasing costs for native 

load customers and blocking third party 

uses of the transmission system.255

627. We also share TAPS’ concern 

that the calculations related to this 

Reliability Standard must be transparent 

and consistent. We are concerned with 

the latitude that transmission providers 

have when preserving a portion of 

transfer capability for CBM. There are 


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no consistent industry-wide standards 

for determining how much transfer 

capability should be set aside as CBM 

and how that amount should be 

allocated to interfaces. Therefore, we 

believe that MOD–004–0 could be 

improved by providing more specific 

Requirements on how CBM should be 

determined and allocated to interfaces. 

628. In response to TAPS’s question 

about how CBM can be viewed as a 

Reliability Standard if it is optional to 

the Transmission Provider, our 

understanding is that transmission 

providers that opt not to use CBM could 

instead set aside transmission margin 

(needed to meet the generation 

Reliability Standard) either through ETC 

or TRM. Obviously, CBM is not the only 

way to preserve transmission margin. 

However, if the Reliability Standard is 

not clear regarding the method to 

calculate transmission margin, it may 

cause double-counting of transmission 

margins and reduction of ATC. 

Therefore, we believe that MOD–004–0 

could be improved by including a 

provision ensuring that CBM, TRM, and 

ETC cannot be used for the same 

purpose, such as the loss of the identical 

generation unit. Without a clear 

requirement against double-counting of 

margins causing ATC decrease, there is 

a possibility that such double-counting 

may be used to prevent the nonaffiliated third party’s access to the 

transmission system. 

f. Procedure for Verifying Capacity 

Benefit Margin Values (MOD–005–0) 

i. NERC Proposal 

629. The Reliability Standard 

specifies the requirements regarding the 

periodic review of a transmission 

service provider’s adherence to the 

regional reliability organization’s CBM 

methodology. This Reliability Standard 

has three Requirements. The first 

Requirement calls for each regional 

reliability organization to develop and 

implement a procedure to review at 

least annually the CBM calculations and 

the resulting values determined by 

member transmission service providers. 

The second Requirement mandates that 

the regional reliability organization 

document its CBM review procedure 

and make it available to NERC on 

request within 30 calendar days. The 

third Requirement specifies that the 

regional reliability organization must 

make the results of the most current 

CBM review available to NERC on 

request, within 30 calendar days. There 

are several sub-requirements specifying 

the regional reliability organization’s 

CBM review process, including an 

assurance that the transmission 

provider’s CBM components are 

calculated consistently with its 

planning criteria, and a Requirement 

that CBM values are at least annually 

updated and made available to the 

regional reliability organization, NERC, 

and transmission users. 

ii. Staff Preliminary Assessment 

630. Staff Preliminary Assessment 

noted that although MOD–005–0 

requires each regional reliability 

organization to review the CBM 

calculations and the resulting values, it 

does not require a consistent and 

uniform calculation of CBM. 

iii. Comments 

631. The Commission received no 

comments regarding MOD–005–0. 

iv. Commission Proposal 

632. MOD–005–0 is a ‘‘fill-in-theblank’’ standard that requires the 

regional reliability organization to 

develop and implement a procedure to 

review the CBM calculations and the 

resulting values and to make the 

documentation of the results of the CBM 

review available to NERC and others. 

Because the regional procedures have 

not been submitted to the Commission, 

it is not possible to determine at this 

time whether MOD–005–0 satisfies the 

statutory requirement that a proposed 

Reliability Standard be ‘‘just, 

reasonable, not unduly discriminatory 

or preferential, and in the public 

interest.’’ Accordingly, the Commission 

will not propose to accept or remand 

this Reliability Standard until the ERO 

submits additional information. In the 

interim, compliance with MOD–005–0 

should continue on a voluntary basis, 

and the Commission considers 

compliance with the Reliability 

Standard to be a matter of good utility 

practice. 

g. Procedure for the Use of Capacity 

Benefit Margin Values (MOD–006–0) 

i. NERC Proposal 

633. NERC states that the purpose of 

MOD–006–0 is to promote the 

consistent and uniform use of 

transmission transfer capability margins 

calculations among transmission system 

users. MOD–006–0 requires a 

transmission service provider to 

document and post its procedures on 

the use of CBM. Specifically, the 

Reliability Standard requires that each 

transmission service provider document 

its procedure explaining scheduling of 

energy against CBM. It also requires the 

transmission service provider to make 

that procedure available on a Web site 

accessible by the regional reliability 

organization, NERC, and transmission 

users. 

ii. Staff Preliminary Assessment 

634. Staff stated that it was concerned 

that proposed Reliability Standard 

MOD–006–0 does not require a 

consistent and uniform calculation of 

CBM. 

iii. Comments 

635. The Commission received no 

comments regarding MOD–006–0. 

iv. Commission Proposal 

636. The Commission proposes to 

approve MOD–006–0 as mandatory and 

enforceable. In addition, we propose to 

direct NERC to modify the Reliability 

Standard, as discussed below. 

637. As discussed above regarding 

MOD–004–0, we are concerned that 

there is an opportunity to double-count 

transmission margins CBM and TRM, 

which will result in lower ATC values. 

Without a clear requirement against 

double-counting margins, this may be 

used to prevent non-affiliated third 

party access to the transmission system. 

Therefore, we propose to direct the ERO 

to modify this Reliability Standard to 

include a provision that will ensure that 

CBM and TRM cannot be used for the 

same purpose. 

638. Requirement R1.2 of MOD–006–

0 calls for CBM to be used by a loadserving entity that experiences a 

generation deficiency only when its 

transmission provider simultaneously 

experiences ‘‘transmission constraints 

relative to imports of energy on its 

transmission system.’’ It is our 

understanding that a load-serving entity 

can experience a generation deficiency 

without the simultaneous transmission 

constraint on its transmission service 

provider’s system. Therefore, we 

propose that the ERO modify 

Requirement R1.2 so that concurrent 

occurrence of transmission constraints 

is not a required condition for CBM 

usage. 

639. Moreover, the Reliability 

Standard does not specify how the 

generation deficiency is identified. We 

propose to direct that the ERO define 

‘‘generation deficiency’’ based on a 

specific energy emergency alert level 

(specified in the EOP Reliability 

Standards) that triggers CBM usage. 

640. The Commission believes that 

CBM should be used only when the 

load-serving entity’s local generation 

capacity is insufficient to meet 

balancing Reliability Standards. 

Moreover, a load-serving entity that has 

sufficient generation resources within 

its balancing authority to meet the 

balancing Reliability Standards should 


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not need to preserve capacity for CBM 

at all. In addition, we believe that CBM 

should have a zero value in the 

calculation of non-firm ATC. Based on 

this guidance, we propose that NERC 

should clarify the Requirements to 

address when and how CBM can be 

used to reduce transmission provider 

discretion with regard to CBM usage. 

641. Requirement R1.2 of MOD–006–

0 provides that CBM shall only be used 

if the load-serving entity calling for its 

use is experiencing a generation 

deficiency. The applicability section, 

however, applies to only transmission 

service providers and not load-serving 

entities. The Commission believes that 

the applicability section should be 

expanded to include the entities that 

actually use CBM, such as load serving 

entities. 

642. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard MOD–

006–0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, we propose directing that 

NERC submit a modification to MOD–

006–0 that: (1) Includes a provision that 

will ensure that CBM and TRM are not 

used for the same purpose; (2) modifies 

Requirement R1.2 so that concurrent 

occurrence of generation deficiency and 

transmission constraints is not a 

required condition for CBM usage; (3) 

modifies Requirement R1.2 to define 

‘‘generation deficiency’’ based on a 

specific energy emergency alert level; 

and (4) expands the applicability 

section to include the entities that 

actually use CBM, such as load serving 

entities. 

h. Documentation of the Use of Capacity 

Benefit Margin (MOD–007–0) 

i. NERC Proposal 

643. NERC states that the purpose of 

MOD–007–0 is to promote the 

consistent use of transmission transfer 

capability margin calculations among 

transmission system users. MOD–007–0 

requires transmission service providers 

that use CBM to report and post its use. 

This Reliability Standard has two 

Requirements. The first Requirement 

calls for each transmission provider that 

uses CBM, at the request of a loadserving entity, to report that use to the 

regional reliability organization, NERC 

and the transmission users. The 

transmission service provider is not 

required to report the occasions when 

CBM is sold on a non-firm basis. The 

second Requirement is that, for any use 

of CBM concurrent with an energy 

emergency situation, the transmission 

service provider must disclose and post 

circumstances, duration, and the 

amount of CBM used on a Web site 

accessible by the regional reliability 

organization, NERC, and transmission 

users. 

ii. Staff Preliminary Assessment 

644. Staff noted that MOD–007–0 

does not specify how CBM should be 

preserved, which is important to allow 

both transmission providers and 

transmission customers to meet their 

respective generation reliability criteria. 

iii. Comments 

645. The Commission received no 

comments regarding MOD–007–0. 

iv. Commission Proposal 

646. The Commission proposes to 

approve MOD–007–0 as mandatory and 

enforceable. In addition, we propose to 

direct that NERC develop modifications 

to the Reliability Standard, as discussed 

below. 

647. Requirement R1 of MOD–007–0 

provides that the use of CBM by the 

load-serving entity shall be 

documented. However, the applicability 

section of MOD–007–0 applies to only 

transmission service providers and not 

load-serving entities. The Commission 

believes that the applicability section 

should be expanded to include the 

entities that actually use CBM, such as 

load-serving entities. 

648. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard MOD–

007–0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, we propose directing that 

NERC to submit a modification to 

MOD–007–0 that expands the 

applicability section to include the 

entities that actually use CBM, such as 

load-serving entities. 

i. Documentation and Content of Each 

Regional Transmission Reliability 

Margin Methodology (MOD–008–0) 

i. NERC Proposal 

649. NERC notes that the purpose of 

MOD–008–0 is to promote the 

consistent application of transmission 

transfer capability margin calculations 

among transmission service providers 

and transmission owners. MOD–008–0 

requires the development and posting of 

a regional methodology for TRM, a 

transmission capacity that is preserved 

to provide reasonable assurance that the 

interconnected transmission network 

will remain secure under various system 

conditions. The Reliability Standard 

specifies two Requirements for the 

regional reliability organization to: (1) 

Develop and document a regional TRM 

methodology in conjunction with its 

members, and (2) post the most recent 

version of its TRM methodology on a 

Web site accessible by NERC, the 

regional reliability organizations, and 

transmission users. 

650. The first Requirement specifies 

five items that the regional reliability 

organization must include and explain 

in its TRM calculation method. In 

addition, the Reliability Standard allows 

other items specific to a regional 

reliability organization to be explained 

along with their use in determining 

TRM values, if such items exist. Some 

of these items require the regional 

reliability organization to specify TRM 

update frequency, describe how TRM 

values are accounted for in ATC 

calculations, and detail which 

uncertainties are accounted for in TRM. 

The regional reliability organization 

must also describe how transmission 

capacity preserved for TRM can be sold 

for non-firm services. 

ii. Staff Preliminary Assessment 

651. Staff noted that although MOD–

008–0 requires each regional reliability 

organization to develop and document a 

Regional TRM methodology, it does not 

specify how TRM is determined and 

allocated across transmission paths. 

Staff also stated that the Requirement 

R1.5 does not specify the criteria for 

granting variances from the regional 

TRM methodology. 

iii. Comments 

652. NERC points out that a 

Reliability Standard is under 

development that will make various 

components of the methodology 

mandatory to ensure consistency. 

653. MRO advocates that MOD–008–

0 should specify the criteria for granting 

variances. 

iv. Commission Proposal 

654. MOD–008–0 is a ‘‘fill-in-theblank’’ Reliability Standard that requires 

each regional reliability organization to 

develop a methodology for determining 

TRM and to make the methodology 

available to others for review. Because 

the regional methodologies have not 

been submitted to the Commission, it is 


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not possible to determine at this time 

whether MOD–008–0 satisfies the 

statutory requirement that a proposed 

Reliability Standard be ‘‘just, 

reasonable, not unduly discriminatory 

or preferential, and in the public 

interest.’’ Accordingly, the Commission 

will not propose to accept or remand 

this Reliability Standard until the ERO 

submits additional information. In the 

interim, compliance with MOD–008–0 

should continue on its current basis, 

and the Commission considers 

compliance with the Reliability 

Standard to be a matter of good utility 

practice. 

655. Although we do not propose any 

action with regard to MOD–008–0 at 

this time, we address our concerns 

regarding this Reliability Standard 

below. 

656. We are concerned about the lack 

of clear requirements on how TRM 

should be calculated and allocated 

across the paths. In addition, the lack of 

consistent criteria and clarity with 

regard to the entity on whose behalf 

TRM has been set aside may result in 

the transmission provider setting aside 

excess capacity, thus increasing costs 

for native load customers, and blocking 

third party uses of the transmission 

system. We seek comments on how 

TRM is currently calculated and 

allocated across the paths, and what 

would be a recommended approach for 

the future. 

j. Procedure for Verifying Transmission 

Reliability Margin Values (MOD–009–0) 

i. NERC Proposal 

657. MOD–009–0 specifies the 

Requirements for establishing a 

procedure for periodic review of a 

transmission provider’s adherence to 

the relevant regional reliability 

organization’s TRM methodology. This 

Reliability Standard has three 

Requirements. The first Requirement 

calls for each regional reliability 

organization to develop and implement 

a procedure to review TRM calculations 

and the resulting values determined by 

member transmission providers to 

ensure compliance with the regional 

TRM methodology. The second 

Requirement is that the regional 

reliability organization documents its 

TRM review procedure and makes that 

available to NERC on request within 30 

calendar days. The third Requirement 

specifies that the reliability regional 

organization must make the 

documentation of the results of the most 

current TRM review available to NERC 

on request, within 30 calendar days. 

ii. Staff Preliminary Assessment 

658. Staff noted that MOD–009–0 

does not provide a consistent procedure 

for review of TRM calculations and the 

resulting values. 

iii. Comments 

659. The Commission received no 

specific comments regarding MOD–009–

0. 

iv. Commission Proposal 

660. MOD–009–0 is a ‘‘fill-in-theblank’’ Reliability Standard that requires 

each regional reliability organization to 

develop its procedure for review of TRM 

calculations and the resulting values. 

Because the regional procedures have 

not been submitted to the Commission, 

it is not possible to determine at this 

time whether MOD–009–0 satisfies the 

statutory requirement that a proposed 

Reliability Standard be ‘‘just, 

reasonable, not unduly discriminatory 

or preferential, and in the public 

interest.’’ Accordingly, the Commission 

will not propose to accept or remand 

this Reliability Standard until the ERO 

submits additional information. In the 

interim, compliance with MOD–009–0 

should continue on its current basis, 

and the Commission considers 

compliance with the Reliability 

Standard to be a matter of good utility 

practice. 

k. Steady-State Data for Modeling and 

Simulation of Interconnected 

Transmission System (MOD–010–0) 

i. NERC Proposal 

661. The purpose of this Reliability 

Standard is to establish consistent data 

requirements, reporting procedures, and 

system models to be used in the 

reliability analysis. MOD–010–0 

requires the transmission owner, 

transmission planner, generator owner, 

and resource planner to provide steadystate data, such as equipment 

characteristics, system data, and 

existing and future interchange 

schedules, to the regional reliability 

organization, NERC, and entities 

specified in Requirement R1 of MOD–

011–0. Data is to be provided within the 

determined time schedule or upon 

request if no time schedule exists. 

ii. Staff Preliminary Assessment 

662. Staff noted that MOD–010–0 

does not include the planning authority 

as an applicable entity. The inclusion of 

the planning authority is necessary in 

the applicability section of the 

Reliability Standard because the 

planning authority is the entity 

responsible for the coordination and 

integration of transmission facilities and 

resource plans, as well as one of the 

entities responsible for the integrity and 

consistency of the data. 

iii. Comments 

663. MRO and ReliabilityFirst state 

that they generally agree with staff’s 

evaluation of MOD–010–0. However, in 

response to the staff comment regarding 

inappropriate exclusion of the planning 

authority from the Reliability Standard’s 

applicability, ReliabilityFirst points out 

that the information required by the 

Reliability Standard originates with the 

transmission planner and resource 

planner who, ultimately, provide such 

information to the planning authority. 

Similarly, PG&E states that a planning 

authority does not develop, and cannot 

provide such information and is rightly 

not included in the applicability section 

of the standard. PG&E explains that 

MOD–010–0 requires transmission 

owners, transmission planners, 

generator owners, and resource planners 

to provide appropriate equipment 

characteristics, system data, and 

existing and future interchange 

schedules in compliance with 

Interconnection regional steady-state or 

dynamic modeling and simulation data 

requirements and reporting procedures. 

iv. Commission Proposal 

664. The Commission proposes to 

approve MOD–010–0 as mandatory and 

enforceable. In addition, we propose to 

direct that NERC develop modifications 

to the Reliability Standard, as discussed 

below. 

665. We propose that MOD–010–0 

should add a new requirement to have 

the transmission owners also provide 

the list of the contingencies they use in 

performing system operation and 

planning studies. We believe that access 

to such information will enable 

neighboring systems to accurately study 

their effects on their own systems. 

666. In addition, we propose that the 

Reliability Standard should be modified 

to apply to the planning authority. The 

planning authority is the entity 

responsible for coordination and 

integration of transmission facilities and 

resource plans, as well as one of the 

entities responsible for the integrity and 

consistency of the data. We disagree 

with commenters that the planning 

authority should be omitted from the 

applicability section because it merely 

gets the data from the others. We believe 

that the planning authority plays a 

significant role in integration of the 

data. 

667. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 


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64834 Federal Register / Vol. 71, No. 213 / Friday, November 3, 2006 / Proposed Rules 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard MOD–

010–0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, we propose to direct that 

NERC to submit a modification to 

MOD–010–0 that: (1) Adds a new 

requirement for transmission owners to 

provide the list of contingencies they 

use in performing system operation and 

planning studies; and (2) expands the 

applicability section to include the 

planning authority. 

l. Maintenance and Distribution of 

Steady-State Data Requirements and 

Reporting Procedures (MOD–011–0) 

i. NERC Proposal 

668. The purpose of MOD–011–0 is to 

establish consistent data requirements, 

reporting procedures, and system 

models to be used in the reliability 

analysis. MOD–011–0 requires the 

regional reliability organization within 

an Interconnection to develop 

comprehensive steady-state data 

requirements and reporting procedures 

needed to model and analyze the 

steady-state conditions for each of the 

three NERC Interconnections. The 

regional reliability organizations within 

an Interconnection are required to: 

(1) Document their Interconnection’s 

data requirements and reporting 

procedures; 

(2) Review the data requirements and 

reporting procedures at least every five 

years; and 

(3) Make the data requirements and 

reporting procedures available on 

request to the regional reliability 

organizations, NERC, and all users of 

the interconnected transmission system. 

ii. Staff Preliminary Assessment 

669. Staff noted that MOD–011–0, 

identified as a ‘‘fill-in-the-blank’’

standard, does not include the planning 

authority in the Requirements section. 

The planning authority is the entity 

responsible for coordination and 

integration of transmission facilities and 

resource plans, as well as one of the 

entities responsible for the integrity and 

consistency of the data. 

iii. Comments 

670. PG&E comments that MOD–011–

0 does not need to be modified because 

the appropriate planning authority will 

be a part of the regional reliability 

organization. 

iv. Commission Proposal 

671. As mentioned above, MOD–011–

0 is a ‘‘fill-in-the-blank’’ standard that 

requires the regional reliability 

organizations within an Interconnection 

to develop comprehensive steady-state 

data requirements and reporting 

procedures needed to model and 

analyze the steady-state conditions for 

each of the three NERC 

Interconnections. Because the regional 

methodologies have not been submitted 

to the Commission, it is not possible to 

determine at this time whether MOD–

011–0 satisfies the statutory requirement 

that a proposed Reliability Standard be 

‘‘just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest.’’ Accordingly, the 

Commission will not propose to accept 

or remand this Reliability Standard 

until the ERO submits additional 

information. In the interim, compliance 

with MOD–011–0 should continue on 

its current basis, and the Commission 

considers compliance with the 

Reliability Standard to be a matter of 

good utility practice. 

672. As we noted in the discussion of 

MOD–010–0, we believe that the 

planning authority plays a significant 

role in integration of data and should 

also be included in the applicability 

section of MOD–011–0. 

m. Dynamics Data for Modeling and 

Simulation of the Interconnected 

Transmission System (MOD–012–0) 

i. NERC Proposal 

673. The purpose of MOD–012–0 is to 

establish consistent data requirements, 

reporting procedures, and system 

models to be used in the reliability 

analysis. MOD–012–0 requires 

transmission owners, transmission 

planners, generator owners, and 

resource planners to provide dynamic 

system modeling and simulation data, 

such as equipment characteristics and 

system data, to the regional reliability 

organization, NERC, and entities 

specified in MOD–013–0, Requirement 

R1, within a pre-determined time 

schedule or upon request if no time 

schedule exists. 

ii. Staff Preliminary Assessment 

674. Staff stated that proposed 

Reliability Standard MOD–012–0 does 

not apply to the planning authority. 

However, the planning authority is the 

entity responsible for the coordination 

and integration of transmission facilities 

and resource plans, as well as one of the 

entities responsible for the integrity and 

consistency of the data. 

iii. Comments 

675. MRO agrees with staff that the 

planning authority should be included 

in MOD–012–0. In contrast, PG&E 

comments that MOD–012–0 does not 

need to be modified, as found by staff’s 

evaluation. Since the appropriate 

planning authority is already a part of 

the regional reliability organization, 

specific inclusion of the planning 

authority within the Reliability 

Standard is unnecessary. PG&E explains 

that, because MOD–012–0 requires the 

regional reliability organization within 

an Interconnection to develop data 

requirements and reporting procedures 

needed to model and analyze the 

conditions for each Interconnection, it 

already provides for appropriate 

participation by the planning authority. 

iv. Commission Proposal 

676. We propose that MOD–012–0 

add a new requirement for transmission 

owners to provide the list of faults or 

disturbances they use in performing 

dynamic stability analysis. We believe 

that access to such information will 

enable neighboring systems to 

accurately study their effects on their 

own systems. As we noted in the 

discussions of MOD–010–0 and MOD–

11–0, we believe that the planning 

authority plays a significant role in 

integration of data and should also be 

included in the applicability section of 

MOD–012–0. 

677. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard MOD–

012–0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, we propose directing that 

NERC submit a modification to MOD–

012–0 that: (1) adds a new requirement 

for transmission owners to provide the 

list of faults or disturbances they use in 

performing dynamic stability analysis; 

and (2) expands the applicability 

section to include the planning 

authority. 

n. Maintenance and Distribution of 

Dynamics Data Requirements and 

Reporting Procedures (MOD–013–1) 

i. NERC Proposal 

678. The purpose of MOD–013–1 is to 

establish consistent data requirements, 

reporting procedures, and system 

models to be used in reliability analysis. 

MOD–013–1 requires the regional 


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256Although the Staff Preliminary Assessment 

addresses concerns regarding the MOD–013–0, 

many of the same concerns apply to MOD–013–1 

as well. 257Blackout Report at 160. 

reliability organizations within an 

Interconnection to develop 

comprehensive dynamics data 

requirements and reporting procedures 

needed to model and analyze the 

dynamic behavior and response of each 

of the three NERC Interconnections. 

More specifically, the regional 

reliability organization, in coordination 

with its transmission owners, 

transmission planners, generator 

owners, and resource planners within 

an Interconnection, is required to: (1) 

Participate in development of 

documentation for their Interconnection 

data requirements and reporting 

procedures; (2) participate in the review 

of those data requirements and reporting 

procedures (at least every five years); 

and (3) make the data requirements and 

reporting procedures available on 

request to the regional reliability 

organizations, NERC, and all users of 

the interconnected transmission system 

on request. 

679. The proposed Reliability 

Standard specifies the types of dynamic 

data that should be included. For 

example, it specifies that dynamics data 

pertaining to generating units, 

synchronous condensers, other devices 

that dynamically respond during 

disturbances, and dynamics data 

representing load characteristics should 

be provided. In addition, the Reliability 

Standard requires that dynamics data be 

consistent with the steady state data 

supplied according to MOD–010–0, 

Requirement R1. 

680. NERC’s August 28, 2006 

Supplemental Filing includes a revised 

version of MOD–013, designated MOD–

013–1. MOD–013–1 has an additional 

Requirement to provide design data for 

the new or refurbished excitation 

systems. 

ii. Staff Preliminary Assessment 

681. Staff stated that proposed 

Reliability Standard does not include 

the planning authority in the 

applicability section. The inclusion of 

the planning authority is necessary in 

the applicability section of the 

Reliability Standard because the 

planning authority is the entity 

responsible for coordinating and 

integrating transmission facilities and 

resource plans, as well as one of the 

entities responsible for the integrity and 

consistency of the data.256

iii. Comments 

682. NERC acknowledges that 

planning authorities also have 

responsibilities under the Reliability 

Standard and the applicability section 

should be revised to reflect that. PG&E, 

on the other hand, asserts that the 

proposed Reliability Standard does not 

need to be modified, because the 

appropriate planning authority is a part 

of the regional reliability organization, 

specific inclusion of the planning 

authority within the Reliability 

Standard is unnecessary. 

683. PG&E adds that Requirement 

R1.1.1, which allows for the use of 

estimated or typical manufacturer’s data 

on pre-1990 units to model dynamic 

behavior when unit-specific data is 

unavailable, is arbitrary in imposing the 

1990 cut-off. PG&E asserts that difficulty 

in obtaining unit specific data is not 

limited to the age of the unit but also 

unit configuration. As a result, PG&E 

recommends that the 1990 cut-off be 

removed from the proposed Reliability 

Standard and that the Reliability 

Standard be revised to allow the use of 

estimated or typical manufacturer data 

where unit specific data is impractical 

to obtain. 

iv. Commission Proposal 

684. MOD–013–1 is a ‘‘fill-in-theblank’’ Reliability Standard that requires 

the regional reliability organizations 

within an Interconnection to develop 

comprehensive dynamics data 

requirements and reporting procedures 

needed to model and analyze the 

dynamic behavior or response for each 

of the three NERC Interconnections. 

Because the regional methodologies 

have not been submitted to the 

Commission, it is not possible to 

determine at this time whether the 

proposed Reliability Standard satisfies 

the statutory requirement that it be 

‘‘just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest.’’ Accordingly, the 

Commission will not propose to accept 

or remand this Reliability Standard 

until the ERO submits additional 

information. In the interim, compliance 

with the proposed Reliability Standard 

should continue, and the Commission 

considers compliance with the 

Reliability Standard to be a matter of 

good utility practice. Although we do 

not propose any action with regard to 

MOD–013–1 at this time, we address 

our concerns regarding this Reliability 

Standard below. 

685. We share PG&E’s concern 

regarding the 1990 cut off date that the 

difficulty in obtaining unit-specific data 

is not limited to the age, but may also 

be due to other factors such as unit 

configuration. The Commission seeks 

comment whether it is reasonable to 

permit entities to estimate dynamics 

data if they are unable to obtain unit 

specific data for any reason. 

686. We agree with NERC that the 

Reliability Standard should apply to the 

planning authority. 

o. Development of Steady-State System 

Models (MOD–014–0) 

i. NERC Proposal 

687. The purpose of MOD–014–0 is to 

establish consistent data requirements, 

reporting procedures, and steady-state 

system models to be used in reliability 

analysis. The Reliability Standard 

requires the regional reliability 

organizations within each 

Interconnection to coordinate and 

jointly develop and maintain a library of 

solved Interconnection-specific steadystate models. These models are to 

include near- and long-term planning 

horizons representing system conditions 

for various demand levels. The yearly 

models represent various seasonal 

conditions, usually for on- and off-peak 

load. The models are to be updated 

annually. The regional reliability 

organizations are required to submit the 

most recent models to NERC in 

accordance with a set schedule. 

ii. Staff Preliminary Assessment 

688. Staff pointed out that while the 

Reliability Standard requires the 

development of steady-state models, it 

does not require periodic verification or 

appropriate modification of models 

against field data in accordance with 

Recommendation No. 24 of the Blackout 

Report.257

iii. Comments 

689. NERC comments that the NERC 

Multiregional Modeling Working Group 

(MMWG) is following recommendations 

from the Blackout Report that involve 

verifying powerflow models and 

databases, which include benchmarking 

to actual load levels and the periodic 

testing of MW, MVAR, and dynamic 

controls of generators. 

690. MRO, National Grid and ISO/ 

RTO Council agree with staff’s 

evaluation of MOD–014–0. 

ReliabilityFirst submits that it generally 

agrees with staff’s evaluation of MOD–

014–0 that, to ensure consistency, 

procedures developed by the individual 

regions need to be merged. In contrast, 

CenterPoint maintains that it is 

impractical to require each region to use 

identical practices in building and 

validating its models. 

iv. Commission Proposal 

691. MOD–014–0 is a ‘‘fill-in-theblank’’ Reliability Standard that requires 


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258Blackout Report at 160. 

259FERC Form 715 is available at http:// 

www.ferc.gov/docs-filing/eforms.asp#715. FERC 

Form 715 specific instructions on Part 2, power 

flow base cases: 

‘‘The input data to the solved power flow base 

cases must be forward-looking. For example, the 

power flow base cases submitted and made 

available might include: 1. One, two, five and tenyear forecasts under summer and winter peak 

conditions and 2. A one-year forecast under light 

load/heavy transfers condition. This example is 

similar to a schedule of base cases proposed by 

NERC’s Multiregional Modeling Working Group for 

development at the time this form was created.’’ 260Blackout Report at 160. 

261See ERCOT report ‘‘August 19, 2004 Forney 

Plant Trip Event Simulation’’ prepared by the 

ERCOT Reliability and Operations Subcommittee 

by ERCOT Dynamics Working Group. 

262On August 28, 2006, NERC submitted MOD–

016–1 for approval, which replaces MOD–016–0. 

MOD–016–1 contains an additional Requirement 

that each load-serving entity must count its 

customer demand values only once. MOD–016–1 

has also an improved set of Measures and Levels 

of Non-compliance. 

the regional reliability organizations 

within an Interconnection to develop, 

coordinate and maintain a library of 

solved Interconnection-specific steadystate models. Because the regional 

procedures have not been submitted to 

the Commission, it is not possible to 

determine at this time whether MOD–

014–0 satisfies the statutory requirement 

that a proposed Reliability Standard be 

‘‘just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest.’’ Accordingly, the 

Commission will not propose to accept 

or remand this Reliability Standard 

until the ERO submits additional 

information. In the interim, compliance 

with MOD–014–0 should continue, and 

the Commission considers compliance 

with the Reliability Standard to be a 

matter of good utility practice. 

692. Although we do not propose any 

action with regard to MOD–014–0 at 

this time, we address our concerns 

regarding this Reliability Standard 

below. 

693. The Reliability Standard does not 

require periodic verification or 

appropriate modification of models 

against field data in accordance with 

Recommendation No. 24 of the Blackout 

Report.258 We understand that the NERC 

MMWG that is incorporating 

recommendations from the Blackout 

Report is developing models only for 

the Eastern Interconnection. We believe 

that a Requirement to verify that steady 

state models are accurate should be a 

part of this Reliability Standard so that 

it applies to all three Interconnections. 

694. In addition, we are concerned 

about creating a duplicate effort if both 

the transmission owner and the regional 

reliability organization separately 

develop the steady-state base cases 

required for the FERC Form 715 filing 

and for MOD–014–0. We believe that 

this Reliability Standard should contain 

a Requirement specifying the time 

period and the planning years to be 

identical to those found in FERC Form 

715.259 We also seek comments on any 

incompatibility between our 

requirements under FERC Form 715 and 

MOD–014–0. 

p. Development of Dynamics System 

Models (MOD–015–0) 

i. NERC Proposal 

695. The purpose of MOD–015–0 is to 

establish consistent data requirements, 

reporting procedures, and system 

models to be used in the reliability 

analysis. The Reliability Standard 

requires the regional reliability 

organizations within each 

Interconnection to coordinate and 

jointly develop and maintain a library of 

initialized (with no faults and 

disturbances) Interconnection-specific 

dynamic system models. These models 

represent near-term years and the years 

chosen from the longer-term planning 

horizon. The models are to be updated 

annually. The regional reliability 

organizations are required to submit the 

most recent models to NERC in 

accordance with a set schedule. 

ii. Staff Preliminary Assessment 

696. Staff noted that, while the 

Reliability Standard requires the 

development of dynamic models, it does 

not require periodic verification or 

appropriate modification of models 

against field data in accordance with 

Recommendation No. 24 of the Blackout 

Report.260

iii. Comments 

697. NERC comments that testing 

should be done to periodically verify 

that system dynamics models are 

accurate. 

698. ISO/RTO Council and MRO agree 

with staff’s evaluation of Reliability 

Standard MOD–015–0. MRO suggests 

that, should a Regional Entity be 

required to perform this responsibility, 

it should be required in the Regional 

Entity’s delegation agreement. 

iv. Commission Proposal 

699. MOD–015–0 is a ‘‘fill-in-theblank’’ Reliability Standard that requires 

the regional reliability organizations 

within an Interconnection to develop, 

coordinate and maintain a library of 

initialized Interconnection-specific 

dynamics system models. Because the 

applicable regional procedures have not 

been submitted to the Commission, it is 

not possible to determine at this time 

whether MOD–015–0 satisfies the 

statutory requirement that a proposed 

Reliability Standard be ‘‘just, 

reasonable, not unduly discriminatory 

or preferential, and in the public 

interest.’’ Accordingly, the Commission 

will not propose to accept or remand 

this Reliability Standard until the ERO 

submits additional information. In the 

interim, compliance with MOD–015–0 

should continue on a voluntary basis, 

and the Commission considers 

compliance with the Reliability 

Standard to be a matter of good utility 

practice. 

700. Although we do not propose any 

action with regard to MOD–015–0 at 

this time, we address our concerns 

regarding this Reliability Standard 

below. 

701. We agree with NERC and believe 

that a Requirement to verify accuracy of 

system dynamics models should be a 

part of this Reliability Standard.261

q. Documentation of Data Reporting 

Requirements for Actual and Forecast 

Demands, Net Energy for Load, 

Controllable Demand—Side 

Management (MOD–016–1) 

i. NERC Proposal 

702. The purpose of MOD–016–1 is to 

ensure that past and forecasted demand 

data are available for validation of past 

events and future system assessments. 

MOD–016–1 requires the planning 

authority and the regional reliability 

organization to have documentation 

identifying the scope and details of the 

actual and forecast demand and load 

data, and controllable Demand-Side 

Management (DSM) data to be reported 

for system modeling and reliability 

analysis. These requirements are to 

ensure that consistent data is supplied 

for various TPL and MOD Reliability 

Standards that address system models 

and simulations.262

ii. Staff Preliminary Assessment 

703. Staff noted that the proposed 

Reliability Standard does not include 

the transmission planner in the 

applicability section. The transmission 

planner is one of the entities involved 

in assuring the integrity and consistency 

of the load, energy, and DSM data. 

iii. Comments 

704. The Commission received no 

specific comments regarding this 

Reliability Standard. 

iv. Commission Proposal 

705. We propose that the Reliability 

Standard be modified to include 


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263 DSM may include control of electric supply to 

individual appliances or equipment on customer 

premises, interruptible/curtailable load, demand 

bidding/buy-back programs, emergency demand 

response programs, capacity market programs, 

ancillary service market programs, and distributed 

generation (including solar PV, Combined Heat and 

Power facilities, and micro turbines). See Demand 

Response Report, Executive Summary at viii. 

264The Commission expects that the data 

provided in response to MOD–017–0 will be 

consistent with data reported in MOD–019–0, 

MOD–020–0 and MOD–021–0. 

transmission planner in the 

applicability section because the 

transmission planner is one of the 

entities involved in assuring the 

integrity and consistency of the load, 

energy, and DSM data.263

706. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard MOD–

016–1 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, we propose directing that 

NERC submit a modification to MOD–

016–1 that expands the applicability 

section to include the transmission 

planner. 

r. Aggregated Actual and Forecast 

Demands and Net Energy for Load 

(MOD–017–0) 

i. NERC Proposal 

707. The purpose of MOD–017–0 is to 

ensure that past and forecasted demand 

data are available for validation of past 

events and future system assessment. 

The Reliability Standard requires the 

load-serving entities, planning 

authorities and resource planners to 

annually provide aggregated 

information on: (1) Integrated hourly 

demands; (2) actual monthly and annual 

peak demand (MW) and net load energy 

(GWh) for the prior year; (3) monthly 

peak demand forecast and net load 

energy for the next two years; and (4) 

annual peak demand forecast (summer 

and winter) and annual net load energy 

for at least five and up to ten years into 

the future. 

ii. Staff Preliminary Assessment 

708. Staff stated that MOD–017–0 

does not require a consistent 

methodology in validating and 

forecasting demand. Specifically, there 

are no Requirements to report the 

accuracy, error, and bias of load 

forecasts. 

iii. Comments 

709. ReliabilityFirst submits that it 

generally agrees with staff’s evaluation 

of MOD–017–0. It also points out that 

some of the data related to the 

Reliability Standard are already 

addressed in U.S. Energy Information 

Administration (EIA) reporting 

requirements. 

iv. Commission Proposal 

710. The Commission proposes to 

approve MOD–017–0 as mandatory and 

enforceable. In addition, we propose to 

direct that NERC develop modifications 

to the Reliability Standard, as discussed 

below. 

711. The Commission notes that load 

forecasts for most of the nation are 

driven by hot and humid weather. Most 

forecasts are ‘‘normalized’’ to a standard 

temperature and humidity condition to 

avoid the variations caused by real 

weather conditions. It is important to 

know these conditions when viewing 

the actual peak loads and in predicting 

what peak loads will be in the future. 

The Commission proposes to add a 

Requirement to provide temperature 

and humidity information that is 

associated with peak load data. 

712. MOD–017–0 does not require a 

consistent methodology in validating 

and forecasting demand, specifically in 

reporting the accuracy, error, and bias of 

load forecasts by load serving entity, 

planning authority, and resource 

planner. This can lead to 

inconsistencies in modeling the load 

data for transmission planning and ATC 

analysis. We believe that 

underestimated load data (modeled in 

steady-state cases for future years) may 

not adequately indicate a need for 

operating procedures, or system 

reinforcements, and can potentially 

jeopardize system reliability. 

713. We propose that the Reliability 

Standard have additional requirements 

for reporting the accuracy, error, and 

bias of load forecasts compared to actual 

loads with due regard to temperature 

and humidity variations.264

714. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard MOD–

017–0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, we propose to direct that 

NERC submit a modification to MOD–

017–0 that includes new Requirements 

for: (1) reporting of temperature and 

humidity along with the peak load; and 

(2) reporting of the accuracy, error, and 

bias of load forecasts compared to actual 

loads with due regard to temperature 

and humidity variations. 

s. Treatment of Nonmember Demand 

Data and How Uncertainties Are 

Addressed in the Forecasts of Demand 

and Energy for Load (MOD–018–0) 

i. NERC Proposal 

715. The purpose of MOD–018–0 is to 

ensure that past and forecasted demand 

data are available for validation of past 

events and future system assessment. 

The Reliability Standard requires that 

the load-serving entities, planning 

authorities, transmission planners, and 

resource planners each submit a load 

data report which: (1) Indicates whether 

the demand data includes the regional 

reliability organization non-members’

demand, and (2) addresses how 

assumptions, methods, and 

uncertainties are treated. The Reliability 

Standard also requires that each of the 

load-serving entities, planning 

authorities, transmission planners, and 

resource planners report the above 

information to NERC, the regional 

reliability organization, and the loadserving entities, planning authorities, 

transmission planners, and resource 

planners on request. 

ii. Staff Preliminary Assessment 

716. Staff raised no specific concerns 

regarding MOD–018–0. 

iii. Comments 

717. The Commission received no 

specific comments regarding 

MOD–018–0. 

iv. Commission Proposal 

718. The Commission proposes to 

approve MOD–018–0 as mandatory and 

enforceable. The Requirements set forth 

in MOD–018–0 are sufficiently clear and 

objective as to provide guidance for 

compliance. 

t. Reporting of Interruptible Demands 

and Direct Control Load Management 

(MOD–019–0) 

i. NERC Proposal 

719. The purpose of MOD–019–0 is to 

ensure that past and forecasted demand 

data are available for validation of past 

events and future system assessment. 

The Reliability Standard requires that 

the load-serving entities, planning 

authorities, transmission planners, and 

resource planners annually provide 

their forecasts of interruptible demands 

and direct control load management to 

NERC, the regional reliability 


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64838 Federal Register / Vol. 71, No. 213 / Friday, November 3, 2006 / Proposed Rules 

265Whereas MOD–019–0 and MOD–020–0 use 

two separate terms interruptible load and Direct 

Control Load Management, NOPR uses 

‘‘controllable load’’ to refer to both of them. 

organization, and other entities as 

specified in MOD–016–1, Requirement 

R1. The data should contain the 

forecasts for at least five years, and up 

to ten years. 

ii. Staff Preliminary Assessment 

720. Staff stated that proposed 

Reliability Standard MOD–019–0 does 

not require a consistent methodology to 

validate and forecast interruptible 

demand. Specifically, there are no 

Requirements to report the accuracy, 

error and bias of load forecasts. 

iii. Comments 

721. The Commission received no 

specific comments regarding 

MOD–019–0. 

iv. Commission Proposal 

722. MOD–019–0 does not require 

reporting of the accuracy, error and bias 

of controllable load 265 forecast. 

Therefore, we propose that NERC 

develop a Requirement for a consistent 

approach to controllable load forecast 

and verification as well as reporting of 

the associated accuracy, error and bias 

of controllable load forecast. 

723. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard MOD–

019–0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, we propose to direct that 

NERC submit a modification to MOD–

019–0 that includes new Requirements 

for reporting of the accuracy, error and 

bias of controllable load forecast. 

u. Providing Interruptible Demands and 

Direct Control Load Management Data 

to System Operators and Reliability 

Coordinators (MOD–020–0) 

i. NERC Proposal 

724. The purpose of MOD–020–0 is to 

ensure that past and forecasted demand 

data are available for validation of past 

events and future system assessment. 

The Reliability Standard requires that 

each load-serving entity, planning 

authority, transmission planner, and 

resource planner identifies its amount 

of: (1) Interruptible demand and (2) 

direct control load management (DCLM) 

to the transmission operators, balancing 

authorities, and reliability coordinators 

on request. 

ii. Staff Preliminary Assessment 

725. Staff found that proposed 

Reliability Standard MOD–020–0 does 

not require a consistent methodology in 

validating and forecasting interruptible 

demand. Specifically, there are no 

Requirements to report the accuracy, 

error and bias of load forecasts. 

iii. Comments 

726. The Commission received no 

specific comments regarding 

MOD–020–0. 

iv. Commission Proposal 

727. The Commission proposes to 

approve MOD–020–0 as mandatory and 

enforceable. In addition, we propose to 

direct that NERC develop modifications 

to the Reliability Standard, as discussed 

below. 

728. For the same reasons as 

discussed in MOD–017, the Commission 

proposes to direct NERC to add 

requirements concerning the reporting 

of the accuracy, error, and bias of 

controllable load forecasts. 

729. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard MOD–

019–0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, we propose directing that 

NERC submit a modification to MOD–

020–0 that includes a new requirement 

concerning the reporting of the 

accuracy, error, and bias of controllable 

load forecasts. 

v. Documentation of the Accounting 

Methodology for the Effects of 

Controllable Demand-Side Management 

in Demand and Energy Forecasts (MOD–

021–0) 

i. NERC Proposal 

730. The purpose of MOD–021–0 is to 

ensure that past and forecasted demand 

data are available for validation of past 

events and future system assessment. 

The Reliability Standard requires the 

load-serving entities, transmission 

planners, and resource planners to 

clearly document how each addresses 

the demand and energy effects of DSM 

programs . The Reliability Standard also 

requires the load-serving entities, 

transmission planners, and resource 

planners to each include information 

detailing how Demand-Side 

Management measures are addressed in 

the forecasts of its peak demand and 

annual net energy for load in the data 

reporting procedures of MOD–016–0, 

Requirement R1. Lastly, MOD–021–0 

requires load-serving entities, 

transmission planners, and resource 

planners to each document the 

treatment of its DSM programs, which is 

to be made available to NERC on 

request. 

ii. Staff Preliminary Assessment 

731. Staff stated that proposed 

Reliability Standard MOD–021–0 does 

not require a consistent methodology in 

validating and forecasting demand. 

Specifically, there are no Requirements 

to report the accuracy, error and bias of 

load forecasts. 

iii. Comments 

732. The Commission received no 

specific comments regarding 

MOD–021–0. 

iv. Commission Proposal 

733. The Commission proposes to 

approve MOD–021–0 as mandatory and 

enforceable. In addition, we propose to 

direct that NERC develop modifications 

to the Reliability Standard, as discussed 

below. 

734. MOD–021–0 does not require a 

consistent methodology in validating 

and forecasting demand, specifically in 

reporting information detailing how 

DSM measures are addressed in the 

forecasts. We propose that NERC modify 

MOD–021–0 to contain Requirements 

standardizing principles on reporting 

and validation of DSM program 

information. While the title of this 

Reliability Standard includes 

‘‘controllable demand side 

management,’’ the Requirements only 

relate to demand side management in 

general. We have a similar concern with 

the purpose statement of this Reliability 

Standard. Thus, we propose that the 

ERO modify the title and purpose 

statement consistent with the 

Requirements. 

735. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard MOD–

019–0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, we propose directing that 

NERC submit a modification to MOD–

021–0 that: (1) Includes a Requirement 

standardizing principles on reporting 


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and validation of DSM program 

information; and (2) modifies the title 

and purpose statement to remove the 

word ‘‘controllable,’’ consistent with the 

Requirements. 

w. Verification of Generator Gross and 

Net Real Power Capability (MOD–024–

1) 

i. NERC Proposal 

736. NERC states that the purpose of 

MOD–024–1 is to ensure that accurate 

information on generation gross and net 

real power capability is used for 

reliability assessment. The Reliability 

Standard requires the regional reliability 

organization to establish and maintain 

procedures to address verification of 

generator gross and net real power 

capability. The Reliability Standard also 

requires the regional reliability 

organization to provide its generator 

gross and net real power capability 

verification and reporting procedures, 

and any changes to those procedures, to 

the generation owners, generation 

operators, transmission operators, 

planning authorities, and transmission 

planners affected by those procedures. 

Finally, MOD–024–1 requires the 

generator owners to follow their 

regional reliability organization’s 

procedure for verifying and reporting 

gross and net real power generating 

capability. 

ii. Staff Preliminary Assessment 

737. Staff noted that while the 

Reliability Standard requires the 

regional reliability organization to 

establish and maintain procedures to 

address verification of generator gross 

and net real power capability, the 

Reliability Standard does not define test 

conditions, e.g., ambient temperature, 

river water temperature, or 

methodologies for calculating de-rating 

factors for conditions such as higher 

ambient temperatures than the test 

temperature. 

iii. Comments 

738. NERC points out that 

Requirement R1.3 of MOD–024–1 

includes data verification of any 

applicable conditions under which the 

data should be verified. MRO and 

ReliabilityFirst note that MOD–024–1 is 

currently undergoing field-testing. 

iv. Commission Proposal 

739. MOD–024–1 is a ‘‘fill-in-theblank’’ Reliability Standard that requires 

the regional reliability organizations to 

establish and maintain procedures to 

address verification of generator gross 

and net real power capability. Because 

the applicable regional procedures have 

not been submitted to the Commission, 

it is not possible to determine at this 

time whether MOD–024–1 satisfies the 

statutory requirement that a proposed 

Reliability Standard be ‘‘just, 

reasonable, not unduly discriminatory 

or preferential, and in the public 

interest.’’ Accordingly, the Commission 

will not propose to accept or remand 

this Reliability Standard until the ERO 

submits additional information. In the 

interim, compliance with MOD–24–1 

should continue on its current basis, 

and the Commission considers 

compliance with the Reliability 

Standard to be a matter of good utility 

practice. 

740. Although we do not propose any 

action with regard to MOD–024–1 at 

this time, we address our concerns 

regarding this Reliability Standard 

below. 

741. We believe that the Reliability 

Standard is not sufficiently clear 

because it does not define the test 

conditions and methodologies for 

calculating de-rating factors. Such 

specificity would provide consistency 

in reporting of generator gross and net 

real power capability. In addition, we 

note that the Requirement R2 states that 

the ‘‘Regional Reliability Organization 

shall provide generator gross and net 

real power capability verification within 

30 calendar days of approval.’’ It is not 

clear what approval is required and it is 

also not clear when the 30 days period 

starts. Taking into account that the 

Reliability Standard is currently 

undergoing field-testing, we believe that 

more information will be available at 

the time the NOPR comments are due. 

x. Verification of Generator Gross and 

Net Reactive Power Capability (MOD–

025–1) 

i. NERC Proposal 

742. NERC states that the purpose of 

MOD–025–1 is to ensure that accurate 

information on generation gross and net 

reactive power capability is used for 

reliability assessment. The Reliability 

Standard requires the regional reliability 

organization to establish and maintain 

procedures to address verification of 

generator gross and net reactive power 

capability. The Reliability Standard also 

requires the regional reliability 

organization to provide its generator 

gross and net reactive power capability 

verification and reporting procedures, 

and any changes to those procedures, to 

the generator owners, generator 

operators, transmission operators, 

planning authorities, and transmission 

planners affected by the procedure 

within 30 calendar days of approval. 

Lastly, MOD–025–1 requires the 

generator owner to follow its regional 

reliability organization’s procedures for 

verifying and reporting its gross and net 

reactive power generating capability. 

ii. Staff Preliminary Assessment 

743. Staff identified MOD–025–1 as a 

‘‘fill-in-the-blank’’ standard that applies 

to the regional reliability organization. 

iii. Comments 

744. CenterPoint suggests that MOD–

025–1 does not adequately address the 

verification of generator reactive 

capability. It explains that the 

Reliability Standard requires a generator 

to provide certain reactive power 

capability at the unit’s full MW loading. 

However, it points out that most units 

rarely operate at full MW loading, 

making it unclear what reactive 

capability is required over a unit’s real 

power (MW) operating range. 

CenterPoint suggests that MOD–025–1 

would be clearer if it requires a 

minimum reactive (MVAR) capability 

throughout a unit’s real power operating 

range. 

745. MRO and ReliabilityFirst note 

that MOD–025–1 is currently 

undergoing field-testing. 

iv. Commission Proposal 

746. The MOD–025–1 is a ‘‘fill-in-theblank’’ Reliability Standard that requires 

the regional reliability organizations to 

establish and maintain procedures to 

address verification of generator gross 

and net reactive power capability. 

Because the applicable regional 

procedures have not been submitted to 

the Commission, it is not possible to 

determine at this time whether MOD–

025–1 satisfies the statutory requirement 

that a proposed Reliability Standard be 

‘‘just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest.’’ Accordingly, the 

Commission will not propose to accept 

or remand this Reliability Standard 

until the ERO submits additional 

information. In the interim, compliance 

with MOD–25–1 should continue on its 

current basis, and the Commission 

considers compliance with the 

Reliability Standard to be a matter of 

good utility practice. 

747. Although we do not propose any 

action with regard to MOD–025–1 at 

this time, we address our concerns 

regarding this Reliability Standard 

below. 

748. We agree with CenterPoint that 

MOD–025–1 could be clearer. This 

could be accomplished by requiring a 

minimum reactive power (MVAR) 

capability throughout a unit’s real 

power operating range. In addition, we 

note that the Requirement R2 states that 

the ‘‘Regional Reliability Organization 


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64840 Federal Register / Vol. 71, No. 213 / Friday, November 3, 2006 / Proposed Rules 

266Reliability Standard EOP–003–0 addresses the 

need to provide safeguards to shield operators from 

retaliation when they declare an emergency or shed 

load in accordance with previously approved 

guidelines. 

267See, e.g., NYSRC, WECC/OTS, ReliabilityFirst 

and NERC. 

268PER–001–0, Measure M1. 

269Blackout Report at 107. 

270 Id. at 110. 

shall provide generator gross and net 

real power capability verification within 

30 calendar days of approval.’’ It is not 

clear what approval is required and it is 

also not clear when the 30 days period 

starts. Taking into account that the 

Reliability Standard is currently 

undergoing field-testing, we believe that 

more information will be available at 

the time the NOPR comments are due. 

9. PER: Personnel Performance, Training 

and Qualifications 

a. Overview 

749. The four proposed Personnel 

Performance, Training and 

Qualifications (PER) Reliability 

Standards are applicable to transmission 

operators, reliability coordinators and 

balancing authorities with the intention 

of ensuring the safe and reliable 

operation of the interconnected grid 

through the retention of suitably trained 

and qualified personnel in positions 

that can impact the reliable operation of 

the Bulk-Power System. The proposed 

PER Reliability Standards address: (1) 

Operating personnel responsibility and 

authority; (2) operating personnel 

training; (3) operating personnel 

credentials; and (4) reliability 

coordination staffing. 

b. Operating Personnel Responsibility 

and Authority (PER–001–0) 

i. NERC Proposal 

750. PER–001–0 ensures the energy 

balance and transmission reliability of 

the Interconnected grid by requiring that 

transmission operator and balancing 

authority personnel have the 

responsibility and authority to direct 

actions in real-time. In practical terms, 

NERC asserts that the proposed 

Reliability Standard requires operating 

personnel who are responsible for 

operating the Bulk-Power System to 

have the authority to take action when 

they believe it is necessary.266

Additionally, PER–001–0 requires clear 

documentation that operating personnel 

have the responsibility and authority to 

implement real-time action to ensure 

the stable and reliable operation of the 

Bulk-Power System. 

ii. Staff Preliminary Assessment 

751. No substantive issues were 

identified concerning PER–001–0. 

iii. Comments 

752. Several commenters recommend 

that the Commission accept the 

proposed Reliability Standard.267

iv. Commission Proposal 

753. PER–001–0 requires that each 

transmission operator and balancing 

authority provide operating personnel 

with the responsibility and authority to 

implement real-time actions to ensure 

the stable and reliable operation of the 

Bulk Electric System. Documentation 

designating the job description and 

responsibilities and authorities of each 

operating position of a transmission 

operator and balancing authority must 

be articulated in ‘‘clear and 

unambiguous language.’’ 268 Further, the 

required documentation should be 

readily available in the control room to 

all operating personnel. 

754. We believe that the proposed 

Reliability Standard clarifies the level of 

responsibility and authority that the 

transmission operator and the balancing 

authority have to act in real-time, which 

will add to the overall reliability of the 

Bulk-Power System. We note that the 

Blackout Report identified the 

inadequate training of operating 

personnel as a factor that was common 

to some major outages that it 

reviewed.269 Further, it suggests that 

prior blackouts could have been 

prevented if the operators had believed 

that they had the responsibility and 

authority to act.270

755. The Commission agrees with 

NERC that this Reliability Standard 

should be applicable to all transmission 

operators and balancing authorities. 

How local transmission and generation 

control centers are incorporated into the 

definition of transmission operator and 

generator operator is described in the 

COM Chapter of this NOPR. 

756. Accordingly, the Commission 

proposes to approve PER–001–0 as 

mandatory and enforceable. We propose 

to find that the Reliability Standard is 

just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest. 

c. Operating Personnel Training (PER–

002–0) 

i. NERC Proposal 

757. PER–002–0 requires that 

transmission operator and balancing 

authority personnel are adequately 

trained. Requirement R2 directs each 

transmission operator and balancing 

authority to have a training program for 

all operating personnel who occupy 

positions that either have primary 

responsibility, directly or indirectly, for 

the real-time operation of the BulkPower System or who are directly 

responsible for complying with the 

NERC Reliability Standards. According 

to NERC’s petition, the purpose of a 

training program is to ensure that 

operating personnel are capable of 

competently performing their tasks. 

Requirement R3 lists the criteria that 

must be met by the training program to 

attain that goal and Requirement R4 

calls for operating personnel to receive 

at least five days of training in 

emergency operations each year using 

realistic simulations of system 

emergencies. 

ii. Staff Preliminary Assessment 

758. While PER–002–0 sets out broad 

objectives that a training program must 

satisfy, the Staff Preliminary 

Assessment stated that it does not 

specify the minimum expectations of a 

training program consistent with the 

roles, responsibilities and authorities of 

operating and support personnel. As 

such, staff explained that the nature, 

objective and criteria of operator 

training programs and minimum hours 

of training (other than a requirement of 

five days per year for realistic 

simulation training) are open to 

interpretation. Staff expressed concern 

that the lack of specificity in this 

Reliability Standard will allow training 

programs to vary widely in their 

implementation. 

759. Further, staff stated that the 

proposed Reliability Standard does not 

tailor training programs according to the 

needs of reliability coordinators, 

balancing authorities, transmission 

operators, generator operators and 

operation planning and support 

personnel with differing authorities, 

responsibilities, roles and tasks. 

Additionally, staff observed that this 

Reliability Standard should also apply 

to reliability coordinators, generator 

operators, operations planning and 

operations support staff because they 

also play an important role in 

maintaining Bulk-Power System 

reliability. 

760. Finally, the Staff Preliminary 

Assessment noted that there is a widely 

accepted Systematic Approach to 

Training (SAT) methodology that has 

been successfully used in the electric 

industry as well as other industries. 

According to the Staff Preliminary 

Assessment, PER–002–0 should be 

revised to incorporate some of the 

elements of the SAT methodology. 


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271NERC, WECC/OTS and ISO/RTO Council. 

272Blackout Report at 107. 

273 Id. at 157. 

274 Id. 

iii. Comments 

761. NERC agrees with the Staff 

Preliminary Assessment with respect to 

training issues, with a few minor 

clarifications. NERC states that there 

must be minimum specific criteria for 

training critical reliability personnel 

and training must be custom designed 

and delivered to be effective. NERC also 

agrees with staff on the need to expand 

training requirements to other persons 

in addition to real-time operators. 

However, NERC believes it more 

important, at this point, to focus its 

proposed training Reliability Standards 

on those positions directly responsible 

for real-time operations. NERC states 

that currently work is ongoing to 

develop new, substantially more robust 

Reliability Standards for training that 

address staff’s points. 

762. EEI supports strengthening the 

full range of training programs and 

initiatives but believes that a one-sizefits-all approach is inappropriate. Also, 

EEI states that developing strong 

programs, such as those used in the 

nuclear industry, may result in setting 

requirements that go far beyond those 

needed for many operations personnel. 

EEI notes that a drafting team has begun 

development of a new Reliability 

Standard for training, with a possible 

filing date with the Commission near 

the end of 2006. 

763. ISO/RTO Council notes that 

many of the Requirements have illdefined terms, no measures of 

compliance and lack specificity. ISO/ 

RTO Council argues that rather than 

defining the objective of the training 

program, PER–002–0 leaves an 

individual entity to develop a training 

program on its own. Concurring with 

the Staff Preliminary Assessment, 

NYSRC, NERC and ReliabilityFirst state 

that PER–002–0 should specify the 

minimum requirements of a training 

program. Moreover, ISO/RTO Council 

recommends that the PER Reliability 

Standards should specifically identify 

the positions that are directly 

responsible for complying with the 

proposed Reliability Standard. 

764. NERC and WECC/OTS support 

the use of the SAT concept, which 

would customize training to the job 

requirements of each position. Although 

WECC/OTS endorses the five-day 

training requirement, it asserts that 

specifying a minimum number of 

training hours devoted to a certain task 

or establishing a mandatory curriculum 

within the Reliability Standard is 

inconsistent with the SAT concept. It 

argues that the training needs of one 

transmission operator may be quite 

different from another due to size, 

impact on the Interconnection, and 

experience and skill of its operating 

personnel. ISO/RTO Council generally 

supports a performance-based approach 

to training and metrics. 

765. Although several commenters 

support the Staff Preliminary 

Assessment,271 National Grid maintains 

that some of staff’s comments on the 

PER Reliability Standards are overly 

prescriptive and appear to be mandating 

various training tools, such as 

simulation training and SAT, without 

assessing the cost effectiveness of such 

measures. It contends that the PER 

Reliability Standards should focus on 

performance measures without being 

overly prescriptive. 

766. Along with NERC, WECC/OTS 

supports expanding the applicability of 

training programs. WECC/OTS further 

recommends that training requirements 

should apply to all personnel with the 

ability to affect real-time operations of 

the Bulk-Power System. However, it 

believes that the training programs 

should focus on positions directly 

responsible for real-time operations at 

this point. In contrast, National Grid 

expresses concern regarding the Staff 

Preliminary Assessment’s suggestion to 

expand training to other functions with 

responsibilities for Bulk-Power System 

reliability. Specifically, it argues that 

there is an implication that all 

employees listed within the categories 

identified by staff would be required to 

receive training even if some have no 

responsibility for grid reliability. It 

suggests that the staff’s comments in 

this area should be taken by NERC as a 

cue to explore expanding training to 

necessary areas without requiring all 

employees within a function or category 

to receive training. 

767. WECC/OTS notes that a full scale 

simulator can be an effective tool in 

operator training, but cautions against a 

requirement that all operating entities 

employ a full-scale simulator, stating 

that emergency training can be 

effectively provided through other 

means, i.e., drills or computer models. 

With regard to the EPAct 2005 provision 

for training guidelines for non-nuclear 

electric energy industry personnel, it 

maintains that the provision should not 

apply to the ERO with the exception of 

the operation function. Nonetheless, 

WECC/OTS argues that training in other 

areas cited in EPAct 2005 should be 

covered in a specific course tailored to 

the function’s effect on the real-time 

reliability of the Bulk-Power System. It 

argues that requirements for initial 

certification, assessment and 

recertification identified in EPAct 2005 

should be separated from the 

requirements of system operators. 

768. NYSRC recommends that the 

Commission conditionally approve 

PER–002–0, while WECC/OTS supports 

approval of the proposed Reliability 

Standard with the understanding that 

NERC is currently developing a new 

Reliability Standard to replace PER–

002–0 with an emphasis on the SAT 

process. 

iv. Commission Proposal 

769. The Commission proposes to 

approve PER–002–0 as mandatory and 

enforceable. In addition, we propose to 

direct that NERC develop modifications 

to the Reliability Standard, as discussed 

below. 

770. Inadequate operator training has 

been identified as a common factor 

among past major system outages.272 In 

the context of the task force 

investigation of the August 2003 

blackout, the Blackout Report stated that 

some reliability coordinators and 

balancing authority operators did not 

receive adequate training in recognizing 

and responding to system 

emergencies.273 The ‘‘deficiency in 

training contributed to the lack of 

situational awareness and failure to 

declare an emergency while operator 

intervention was still possible (before 

events began to occur at a speed beyond 

human control.)’’ 274

771. PER–002–0 requires that each 

transmission operator and balancing 

authority shall be staffed with 

adequately trained personnel and 

directs the transmission operator and 

balancing authority to have training 

programs for all their operating 

personnel who occupy positions that 

either have primary responsibility, 

directly or indirectly, for the real-time 

operation of the Bulk-Power System or 

who are directly responsible for 

complying with the Reliability 

Standards. Transmission operators and 

balancing authorities are not the only 

entities that have operating personnel in 

positions that directly impact the 

reliable operation of the Bulk-Power 

System or must comply with the 

Reliability Standards. Reliability 

coordinators, generator operators, 

operations planning and operations 

support staff also potentially impact the 

reliable operation of the Bulk-Power 

System, yet these entities are not 

required to participate in mandatory 

training programs. The Commission 

agrees with NERC, WECC/OTS and 

National Grid and supports the 


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275 Id. at 107. 

expanding training programs to other 

personnel with the ability to affect realtime operations of the Bulk-Power 

System. The Commission proposes that 

such expansion be based on the role of 

the entity rather than its size. Further, 

we note that NERC has stated that it has 

asked its Reliability Standards drafting 

team to prepare a request for a new 

project to expand the scope of the 

training requirements to other positions 

essential to reliability of the Bulk-Power 

System. 

772. After considering the comments 

of NERC and National Grid that the 

training programs should focus on 

positions directly responsible for realtime operations at this point in time, 

and in recognition of the need to give 

first priority to real-time operations, the 

Commission proposes a modification of 

PER–002–0 to include real-time 

operations personnel from reliability 

coordinators, generator operators, 

operations planning and operations 

support staff in training programs with 

a time phased effective date. The 

phasing of the effective date would 

acknowledge the priority of training 

each group. This prioritization is also 

supported by WECC/OTS which 

cautions that limited training resources 

may be diverted from system operators 

to other personnel that can effect 

reliable operation at the expense of 

those responsible for real-time 

operations. 

773. In order to maintain an adequate 

level of reliability, the Commission 

proposes to require NERC to modify 

PER–002–0 in the future or to develop 

a new training Reliability Standard for 

all personnel who may directly impact 

the reliable operation of the Bulk-Power 

System or for all personnel who have 

responsibility for compliance with the 

Reliability Standards. These personnel 

include operations planning and 

operations support staff. We disagree 

with the comments of EEI and believe 

that this does not imply a one-size-fitsall approach. Rather, this course of 

action ensures the creation of training 

programs that are structured and 

tailored to the different functions and 

needs of the personnel involved. 

774. A review of operator 

demographics reveals that a large 

percentage of electrical operators will 

retire over the next five years. As these 

older and more experienced operators 

retire, the need for structured, 

comprehensive and effective training 

programs tailored to the needs of the 

functions and individuals become even 

more crucial, and will need to be 

developed and implemented for 

incoming operators who will not have 

benefited from years of on-the-job 

training, mentoring and knowledge 

transfer from experienced operators. 

Requirement R3 sets out broad 

objectives that a training program must 

satisfy, yet it does not specify the 

minimum expectations of an effective 

training program. In its comments, 

NERC agrees with the Staff Preliminary 

Assessment that PER–002–0 must have 

minimum expectations and specific 

criteria for training critical reliability 

personnel. The Commission concurs 

with NERC’s comments, calling for 

measurable requirements regarding 

objectives, content, minimum hours of 

training and types of training in the 

proposed Reliability Standard. The 

Commission proposes that NERC 

modify the Reliability Standard to 

include minimum training requirements 

related to objectives, program content, 

minimum hours of training and types of 

training with specific performance 

metrics to gauge the effectiveness of the 

training program. 

775. Although EEI cautions against 

using the nuclear industry training 

program as a model, we do not believe 

that the use of an SAT method would 

set requirements that go beyond those 

needed for many operating personnel. 

We agree with WECC/OTS that training 

based on SAT is a proven approach to 

identify the tasks and associated skills 

and knowledge necessary to accomplish 

those tasks, determine the competency 

level of each operator to carry out those 

tasks, determine the competency gaps, 

then design, implement and evaluate a 

training plan to address each operator’s 

competency gaps. 

776. CenterPoint and National Grid 

caution against being overly prescriptive 

and propose that the Commission focus 

on desired outcomes. ISO/RTO Council 

stated that there is no definition for 

‘‘adequately trained operating 

personnel’’ and suggested the adoption 

of performance metrics to ensure that 

training results in competent operating 

personnel. These are distinct from 

measures used to ensure compliance 

with the requirements. The Commission 

strongly supports the adoption of 

performance metrics to ensure that 

training results in competent operating 

personnel. However, such performance 

metrics are not a substitute for an SAT 

developed training program. The 

Commission proposes to require that 

NERC modify PER–002–0 to include 

performance metrics associated with the 

effectiveness of the training program. 

777. Effective training programs must 

be structured and address competency 

gaps of operating personnel. WECC/OTS 

states that SAT-based training plans 

tailor to the needs of not only various 

job functions, but also to individual 

operator competency gaps within those 

functions. WECC/OTS and NERC 

support this approach in identifying the 

tasks and associated skills and 

knowledge necessary to accomplish the 

specific tasks of each operator. In 

addition, they support implementing 

and evaluating a unique training plan to 

address each operator’s competency 

gap. NERC stated that the 

implementation of minimum training 

requirements, as well as an SAT 

methodology, is essential to ensuring 

system operator competencies. NERC 

claims that a new Reliability Standard is 

under development which will address 

the above concerns. The Commission 

proposes that NERC explore the SAT 

methodology in its efforts to establish 

training plans tailored to the needs of 

various job functions and individuals. 

778. Requirement R4 of the Reliability 

Standard requires training in emergency 

operations using realistic simulations of 

system emergencies. Several entities 

currently use full scale operator training 

simulators for this purpose with 

scenarios derived from actual system 

disturbances supplemented with drills 

to deal with communications during 

emergencies. WECC/OTS notes that the 

use of such a simulator can be an 

effective tool in operator training 

programs, but cautions against making 

this a requirement for all operating 

entities. The Commission notes that 

there are various options available for 

providing operator training simulator 

capability, including contracting for this 

service from others who have developed 

the capability. The Commission solicits 

comments on the benefits and 

appropriateness of required ‘‘hands-on’’

training using simulators in dealing 

with system emergencies as identified 

in the training related recommendations 

made in studies of major outages.275

779. The Commission proposes that 

this Reliability Standard be Applicable 

to transmission operators, balancing 

authorities, reliability coordinators, 

generator operators, and operations 

planning and operations support staffs 

that have a direct impact on the reliable 

operation of the Bulk-Power System. 

How local transmission and generation 

control centers are incorporated into the 

definition of transmission operator and 

generator operator is described in the 

COM Chapter. The extent of the training 

shall take into account the need to 

assure real time operators do not suffer 

because of the training needs of non-real 

time staff. 

780. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 


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276Staff Preliminary Assessment at 89–90. 

277North American Electric Reliability Council’s 

Application for Certification as the Electric 

Reliability Organization, Rules of Procedure of the 

Electric Reliability Organization, System Operator 

Certification Program Manual, Appendix 6 available 

at ftp://www.nerc.com/pub/sys/all_updl/ero/ 

application/ERO-Application-Complete.pdf. 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard PER–002–

0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to PER–002–0 that: (1) Identifies the 

expectations of the training for each job 

function; (2) develops training programs 

tailored to each job function with 

consideration of the individual training 

needs of the personnel; (3) expands the 

Applicability to include reliability 

coordinators, generator operators, and 

operations planning and operations 

support staff with a direct impact on the 

reliable operation of the Bulk-Power 

System; (4) uses the SAT methodology 

in its development of new training 

programs; and (5) includes performance 

metrics associated with the effectiveness 

of the training program. 

d. Operating Personnel Credentials 

(PER–003–0) 

i. NERC Proposal 

781. PER–003–0 requires transmission 

operators, balancing authorities and 

reliability coordinators to staff all 

operating positions that have a primary 

responsibility for real-time operations or 

are directly responsible for complying 

with the Reliability Standards with 

NERC-certified staff. NERC grants 

certification to operating personnel 

through a separate program documented 

in the NERC System Operator 

Certification Manual and administered 

by an independent Personnel 

Certification Governance Committee. 

ii. Staff Preliminary Assessment 

782. In its Staff Preliminary 

Assessment, staff stated that this 

Reliability Standard does not specify the 

minimum competencies that operating 

personnel must demonstrate to meet the 

certification requirements.276 Although 

NERC’s System Operator Certification 

Program Manual outlines the 

requirements for certification, the 

manual is not a part of the proposed 

Reliability Standard. Therefore, staff 

contended that the Manual is not 

enforceable.277

783. Moreover, staff noted that 

generator operators, who have 

responsibility for the real-time operation 

of the Bulk-Power System and are 

directly responsible for complying with 

NERC Reliability Standards, do not 

require NERC-certification under this 

Reliability Standard. 

iii. Comments 

784. NERC does not agree with the 

Staff Preliminary Assessment’s view 

that the NERC System Operator 

Certification Program Manual should be 

included in the Reliability Standard to 

be enforceable. It states that this is a 

procedural document and the 

Certification Program is managed by an 

independent Personnel Certification 

Governance Committee as required by 

the standards of the National 

Organization for Competency Assurance 

and employment law. 

785. WECC/OTS and NYSRC join 

with comments of the Staff Preliminary 

Assessment in observing that the 

Applicability and Requirements 

sections of PER–003–0 potentially 

weaken the enforcement of this 

Reliability Standard. While WECC/OTS 

encourages Commission approval of 

PER–003–0 with the understanding that 

NERC or another interested party will 

submit a Standard Authorization 

Request to more specifically define 

which functions should be performed 

by certified personnel, NYSRC 

recommends conditional approval of 

PER–003–0. Although the ISO/RTO 

Council does not address staff’s 

comment that the NERC Manual is not 

enforceable, it agrees that the proposed 

Reliability Standard should contain 

minimum Certification Requirements. It 

also implies that the NERC System 

Operator Certification Program Manual 

contains the needed level of 

requirements and measurability. In 

contrast, WECC/OTS opposes including 

the specific competencies operating 

personnel must demonstrate to meet the 

certification requirements. It states that 

these details are retained with the 

certification program governance body. 

786. ReliabilityFirst disagrees with 

the Staff Preliminary Assessment’s 

comments regarding PER–003–0. It 

asserts that personnel are obligated to 

follow the appropriate NERC process to 

become certified. It argues that PER–

003–0 should make reference to this as 

a stand-alone manual that could be 

adjusted and maintained without 

affecting the current Reliability 

Standard. 

iv. Commission Proposal 

787. The Commission proposes to 

approve PER–003–0 as mandatory and 

enforceable. In addition, we propose to 

direct that NERC develop modifications 

to the Reliability Standard, as discussed 

below. 

788. PER–003–0 requires applicable 

entities to staff real-time operation 

positions with NERC-certified 

personnel. The Commission interprets 

this to include real-time operating 

positions in a transmission operations 

control center that performs switching 

operations via SCADA for the BulkPower System. 

789. Some commenters agree with 

staff that PER–003–0 should contain 

minimum certification requirements, 

while others do not. The Commission 

acknowledges the commenter’s 

concerns and the convenience of 

maintaining a procedural document that 

is separate from the Reliability Standard 

so that it can be modified without 

requiring a revision to the entire 

Reliability Standard. Nevertheless, the 

Commission believes that the minimum 

competencies that must be 

demonstrated to become a certified 

operator and the minimum 

requirements to remain certified should 

be included in PER–003–0. To address 

commenter’s concerns, we propose that 

the ERO modify PER–003–0 to identify 

the minimum competencies operating 

personnel must demonstrate to be 

certified, but not include the entire 

Certification Program Manual. 

790. Additionally, we note that 

generator operators who have 

responsibility for real-time operation of 

the Bulk-Power System and who are 

directly responsible for complying with 

the Reliability Standards are not 

designated in the Applicability section 

of PER–003–0, and therefore, do not 

require NERC-certification. We agree 

with the concerns articulated in the 

Staff Preliminary Assessment and we 

believe that this omission has the 

potential to impact the reliable 

operation of the Bulk-Power System. 

Therefore, the Commission proposes the 

modification of PER–003–0 to include 

generator operators as applicable 

entities. 

791. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard PER–003–

0 as mandatory and enforceable. In 

addition, we propose to direct NERC to 

modify the Reliability Standard to 

address the Commission’s concerns. In 

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

of the FPA and § 39.5(f) of our 


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278A comprehensive understanding of a 

reliability coordinator’s ‘‘area’’ includes: Familiarity 

with transmission operators, generator operators 

and balancing authorities, as well as their operating 

practices and procedures, equipment capabilities 

and restrictions, system operating limits and 

interconnection reliability operating limits. 279See NERC glossary at 11. 

280Blackout Report at 107. 

281Topics addressed under the PRC Reliability 

Standards include: system protection coordination, 

regulations, the Commission proposes to 

direct NERC to submit a modification to 

PER–003–0 that: (1) Expands the 

Applicability to include generator 

operators; (2) specifies the minimum 

competencies that must be 

demonstrated to become and remain a 

certified operator; and (3) identifies the 

minimum competencies operating 

personnel must demonstrate to be 

certified (but not include the 

Certification Program Manual). 

e. Reliability Coordination—Staffing 

(PER–004–0) 

i. NERC Proposal 

792. PER–004–0 ensures that 

reliability coordinator personnel are 

adequately trained, NERC-certified, and 

staffed 24 hours a day, seven days a 

week with properly trained and certified 

individuals. Further, reliability 

coordinator operating personnel must 

have a comprehensive understanding of 

the area of the Bulk-Power System over 

which they are responsible, including 

familiarity with transmission operators, 

generator operators and balancing 

authorities, as well as their operating 

practices and procedures, equipment 

capabilities and restrictions, system 

operating limits and interconnection 

reliability operating limits.278 In 

addition the reliability coordinator must 

complete a minimum of five days per 

year of emergency operations training in 

addition to the training required to 

maintain qualified operating personnel. 

793. NERC indicates that it will 

modify this proposed Reliability 

Standard to address the lack of 

Measures and Levels of NonCompliance and resubmit the proposal 

for Commission approval in November 

2006. 

ii. Staff Preliminary Assessment 

794. The Staff Preliminary 

Assessment noted that there was no 

formal training program requirement for 

reliability coordinators similar to the 

program required for transmission 

operators and balancing authority 

personnel under PER–002–0. 

iii. Comments 

795. ReliabilityFirst notes that PER–

004–0 does require reliability 

coordinators to be NERC-certified and to 

complete required training. WECC/OTS 

states that the NERC System Personnel 

Training Reliability Standard, which is 

under development, includes reliability 

coordinators in the applicability section. 

796. ReliabilityFirst, NYSRC and ISO/ 

RTO all note the Reliability Standard’s 

lack of Measures and Levels of NonCompliance. 

iv. Commission Proposal 

797. The Commission proposes to 

approve PER–004–0 as mandatory and 

enforceable. In addition, we propose 

directing that NERC develop 

modifications to the Reliability 

Standard, as discussed below. 

798. A reliability coordinator is the 

entity with the highest level of authority 

that is responsible for the reliable 

operation of the Bulk-Power System, has 

a ‘‘wide area view,’’ and has the 

operating tools, processes and 

procedures, including authority to 

prevent or mitigate emergency operating 

situations in both next-day analysis and 

real-time operations.279 Most of the 

Requirements for PER–004–0 address 

training issues pertaining to reliability 

coordinators, yet there is no 

requirement for a formal training 

program for reliability coordinators that 

is similar to the program required for 

transmission operators under PER–002–

0. We believe that the addition of formal 

training requirements for reliability 

coordinators will help to ensure 

adequate training and competency for 

an entity that plays a critical role in 

ensuring the reliability of the 

interconnected grid. To ensure that the 

training requirements for reliability 

coordinators are comprehensive, we 

propose that the ERO either modify 

PER–006–0 to include the same quality 

and clarity as the training requirements 

for other operating personnel as set forth 

in PER–002–0 or, alternatively, given 

the high priority work that the ERO 

must accomplish it may want to 

consider including the reliability 

coordinator as an applicable entity in 

PER–002–0. Similarly, we propose that 

the ERO either modify PER–006–0 to 

address personnel credentials for 

reliability coordinators in a similar 

manner as for other operating personnel 

in PER–003–0 or, alternatively, it may 

address this concern by including 

reliability coordinators as an applicable 

entity in PER–006–0. 

799. We agree with commenters that 

Measures and Levels of NonCompliance should be added to the 

proposed Reliability Standard, 

including Measures to address staffing 

requirements and the minimum five 

days of emergency training. 

800. While the Commission has 

identified a number of concerns with 

regard to PER–003–0, this proposed 

Reliability Standard serves an important 

purpose of ensuring that reliability 

coordinator personnel are adequately 

trained. Further, NERC should provide 

Measures and Levels of NonCompliance for this proposed Reliability 

Standard. Nonetheless, the 

Requirements set forth in PER–003–0 

are sufficiently clear and objective to 

provide guidance for compliance. 

801. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard PER–004–

0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to PER–004–0 that: (1) Includes formal 

training requirements for reliability 

coordinators similar to those addressed 

under the personnel training Reliability 

Standard PER–002–0; (2) includes 

requirements pertaining to personnel 

credentials for reliability coordinators 

similar to those in PER–003–0; and (3) 

includes Levels of Non-Compliance and 

Measures that address staffing 

requirements and the requirement for 

five days of emergency training. 

10. PRC: Protection and Control 

a. Overview 

802. Protection and Control (PRC) 

systems on Bulk-Power System 

elements are an integral part of reliable 

grid operation. Protection systems are 

designed to detect and isolate a faulted 

element from the system, thereby 

limiting the severity and spread of 

system disturbances and preventing 

possible damage to protected elements. 

SOLs and IROLs are only valid when 

they recognize the function, settings and 

limitations of the protection system. 

One of the common factors among the 

major outages from 1965 to 2003 was 

the lack of coordination of system 

protection.280

803. The PRC Reliability Standards 

apply to transmission operators, 

transmission owners, generator 

operators, generator owners, 

distribution providers and regional 

reliability organizations and cover a 

wide range of topics related to the 

protection and control of power 

systems.281 NERC has recognized that 


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disturbance monitoring, under-frequency load 

shedding (UFLS), special protection systems, 

under-voltage load shedding (UVLS) and their 

assessments, database, event and mis-operation 

analysis, maintenance and testing requirements and 

performance evaluation. 

282See NERC Planning Standards Phase III-IV, 

available at http://www.nerc.com/∼filez/standards/ 

Phase-III–IV.html. 

283The regional reliability organization is 

assigned compliance monitoring responsibility 

under the following Reliability Standards in the 

PRC group: PRC–004–1; PRC–005–1; PRC–007–0; 

PRC–008–0; PRC–009–0; PRC–010–0; PRC–011–0; 

PRC–015–0; PRC–016–0; PRC–017–0; PRC–018–1; 

PRC–021–1; and PRC–22–1. 

284The regional reliability organization is listed 

as the applicability entity under the following 

Reliability Standards in the PRC group: PRC–002–

0; PRC–003–1; PRC–006–0; PRC–012–0; PRC–013–

0; PRC–014–0; and PRC–020–1. 

the Reliability Standards do not form a 

complete set of PRC Reliability 

Standards to meet the goal of 

reliability.282

804. Generally, the proposed 

Reliability Standards in the PRC group 

raise issues related to Measures, Levels 

of Non-compliance, and Requirements. 

The regional reliability organization is 

the compliance monitor for twelve of 

the PRC Reliability Standards 283 and 

the applicable entity for seven of 

them.284

b. System Protection Coordination 

(PRC–001–0) 

i. NERC Proposal 

805. Proposed Reliability Standard 

PRC–001–0 ensures that protection 

systems are coordinated among 

operating entities by requiring 

transmission operators and generator 

operators to notify appropriate entities 

of relay or equipment failures that could 

impact system reliability. In addition, 

these entities must coordinate with 

appropriate entities when new 

protection systems are installed or when 

existing protection systems are 

modified. 

ii. Staff Preliminary Assessment 

806. The Staff Preliminary 

Assessment pointed out that 

Requirement R2 of PRC–001–0 instructs 

transmission operators or generator 

operators to take corrective action as 

soon as possible where a protective 

relay or equipment failure reduces 

system reliability. However, PRC–001–0 

does not designate a maximum time 

period for corrective control actions. 

This is inconsistent with the 

requirement that system operators readjust the system within 30 minutes for 

contingencies under the proposed IRO 

and TOP Reliability Standards. Staff 

also noted that the lack of Measures and 

Levels of Non-Compliance in this 

Reliability Standard may hinder 

consistent and effective enforcement. 

iii. Comments 

807. NERC agrees with staff that PRC–

001–0 requires modification and 

requests that the Commission 

conditionally approve it. NERC reasons 

that even if a generator operator fails to 

tend to a protective relay failure, other 

proposed Reliability Standards still 

require the transmission operator and 

reliability coordinator to ensure reliable 

operation of the grid by mitigating SOL 

and IROL violations as soon as possible. 

In addition, NERC indicates that it will 

modify this Reliability Standard to 

include missing Measures and Levels of 

Non-Compliance and resubmit it for 

Commission approval in November 

2006. 

808. CPUC argues that ‘‘action 

adequate to bring the system into 

balance’’ may be ambiguous, i.e., a more 

effective action taken in 35 minutes may 

be preferable to a less effective action 

taken in 28 minutes in an attempt to 

follow the 30-minute time limit 

specified under the IRO and TOP 

Reliability Standards. It also stated that 

the Staff Preliminary Assessment’s 

concern apparently relates to the August 

2003 Blackout, where operators failed to 

take effective action in the very short 

time frame required to prevent 

cascading outages throughout the 

region. CPUC questions the extent to 

which a rigid 30-minute maximum time 

limit would have prevented much of the 

system dysfunction that occurred in 

August 2003. 

809. National Grid suggests that 

requiring a maximum time period for 

corrective actions where a protective 

relay or equipment failure reduces 

reliability inappropriately mixes 

protection design engineering issues 

with operational issues. National Grid 

asserts that the proposed Reliability 

Standard addresses design engineering 

and specifying a maximum time period 

for corrective actions to respond to 

protective equipment failures would be 

inappropriate. Further, CenterPoint 

states that the amount of time required 

to diagnose and correct different types 

of failures varies. It explains that 

investigating and correcting relay 

failures is a fundamentally different 

exercise from that of real-time operators 

taking corrective actions in response to 

operating contingencies that may occur. 

810. ReliabilityFirst agrees that a 

failed protection system element must 

be replaced as soon as possible, but 

agrees with staff that PRC–001–0 should 

clearly state that system performance 

requirements must continue to be met 

when the affected protection system 

element has failed or is out of service. 

Repair or replacement of the failed 

protection element or an alternate 

corrective solution, such as operator 

control action, must be implemented to 

satisfy performance requirements. 

ReliabilityFirst concludes that a specific 

time for repairing the failed protection 

system element is not necessary if 

performance requirements must be 

maintained. 

iv. Commission Proposal 

811. The Commission proposes to 

approve PRC–001–0 as mandatory and 

enforceable. In addition, we propose to 

direct that NERC develop modifications 

to the Reliability Standard as discussed 

below. 

812. We recognize that protection and 

control systems are integral part of 

reliable grid operation and agree that 

protection systems affect the validity of 

IROLs. We further note that if a nonredundant protection system for a 

critical element fails and no corrective 

control action is taken, the system could 

be subject to the risk of cascading failure 

if a critical contingency subsequently 

occurred. 

813. The Commission emphasizes the 

importance of immediately informing 

transmission operators and generator 

operators of any protection failure that 

may affect SOLs and IROLs so that they 

can take corrective control action to 

maintain reliable system operations. We 

further note that PRC–001–0 or other 

relevant PRC Reliability Standards do 

not contain such a Requirement. 

814. PRC–001–0 should designate a 

maximum time limit for corrective 

control action where the failure of a 

protection system element has reduced 

system reliability and undermined 

performance requirements. The 

Commission commends NERC’s 

initiative in attempting to address and 

clarify this issue in PRC–001–0. 

However, we do not agree with NERC 

that even if a generator operator fails to 

tend to a protective relay failure, other 

proposed Reliability Standards still 

require the transmission operator and 

reliability coordinator to ensure the 

reliable operation of the grid by 

mitigating SOL and IROL violations as 

soon as possible, i.e., respecting 

performance requirements. We believe 

that the Reliability Standards on 

mitigating IROL violations are not 

specific enough and system operators or 

field protection and control personnel 

would not be alerted about failures of 

relays and protection systems on critical 

elements. Therefore, in addition to 

clarifying the ambiguity in future 

revision, we propose to require NERC to 

include a requirement that the 


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285We note that PRC–002–0 has been revised and 

separated into two Reliability Standards, PRC–002–

1 (Define Regional Disturbance Monitoring and 

Reporting Requirements) and PRC–018–1 

(Disturbance Monitoring Equipment Installation 

and Data Reporting). 286CPUC, FRCC, National Grid, NPCC, NYSRC, 

ReliabilityFirst, Southern and TANC. Their 

appropriate transmission operators or 

generator operators should be notified 

immediately upon detection of failures 

on relays or protection systems on BulkPower System elements so that they can 

maintain system reliability requirements 

by taking corrective actions in the same 

manner used to mitigate IROL 

violations. 

815. The Commission does not agree 

with National Grid’s comment that 

staff’s concern inappropriately mixes 

protection design engineering issues 

with operational issues. Design 

engineering refers to protection system 

schemes with protective elements, such 

as relays. Furthermore, the applicable 

entities for design engineering would 

include field protection and control 

personnel who are responsible for 

carrying out the inspection, replacement 

and repair of damaged protection 

system elements. PRC–001–0 requires 

transmission operators or generator 

operators to carry out corrective actions 

because this Reliability Standard 

addresses system performance 

requirements. We believe that the Staff 

Preliminary Assessment correctly 

advocated the establishment of a 

maximum time period for corrective 

control actions when a protective relay 

or equipment failure reduces reliability, 

i.e., performance requirements that are 

consistent with mitigating IROL 

violations. 

816. The Commission believes that 

CenterPoint also misinterpreted the 

Staff Preliminary Assessment’s concern. 

The Staff Preliminary Assessment 

advises the addition of a requirement 

that transmission operators carry out 

corrective control actions to return the 

system to a secure state, i.e., respecting 

system performance requirements, by 

recognizing the reduction in IROL due 

to a failed relay or protection system 

elements in no longer than 30 minutes. 

It is generally understood that the 

corrective actions stated in this 

Reliability Standard do not include 

actions requiring the field protection 

and control personnel to respond and 

repair faulty relays or failed protection 

system elements as this type of repair 

would normally take hours, if not days. 

817. The Commission does not share 

CPUC’s view that the Staff Preliminary 

Assessment is advocating a rigid 30- 

minute requirement to re-adjust the 

system or fix or replace failed protection 

system elements. Since failures of relays 

or protection system elements would 

expose the Bulk-Power System to 

cascading outages through a possible 

failure to respect performance 

requirements, we believe that 

transmission operators and generator 

operators must take corrective control 

actions in the same manner used to 

mitigate IROL violations as stipulated in 

relevant IRO and TOP Reliability 

Standards, as soon as possible but no 

more than 30 minutes. 

818. The Commission agrees with 

ReliabilityFirst that protection system 

elements must be replaced as soon as 

possible, and PRC–001–0 should clearly 

state that system performance 

requirements must continue to be met 

when the affected protection system 

element is out of service. 

819. Although the Commission has 

identified concerns regarding PRC–001–

0’s lack of a maximum interval for 

corrective control action when a 

protection system element has failed 

and reduced reliability, i.e., system 

performance requirements, we believe 

that the proposed Reliability Standard 

provides a good base and is integral to 

ensuring that system protection is 

coordinated among operating entities. 

The Commission also believes that it is 

important for NERC to provide 

Measures and Levels of NonCompliance for the proposed Reliability 

Standard. However, the Requirements 

set forth in PRC–001–0 are sufficiently 

clear and objective to provide guidance 

for compliance. 

820. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard PRC–001–

0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to PRC–001–0 that: (1) Includes 

Measures and Levels of NonCompliance; (2) includes a requirement 

that relevant transmission operators and 

generator operators must be informed 

immediately upon the detection of 

failures in relays or protection system 

elements on the Bulk-Power System that 

would threaten reliable operation, so 

that these entities can carry out the 

appropriate corrective control actions 

consistent with those used in mitigating 

IROL violations; and (3) clarifies that, 

after being informed of failures in relays 

or protection system elements on the 

Bulk-Power System, transmission 

operators or generator operators shall 

carry out corrective control actions, i.e., 

returning the system to a stable state 

that respects system requirements as 

soon as possible and no longer than 30 

minutes. 

c. Define Regional Disturbance 

Monitoring and Requirements (PRC–

002–1) 

i. NERC Proposal 

821. Proposed Reliability Standard 

PRC–002–1 ensures that each regional 

reliability organization establishes 

requirements to install Disturbance 

Monitoring Equipment (DME) and 

report disturbance data to facilitate 

analyses of events and verify system 

models. 

822. NERC’s August 28, 2006 

Supplemental Filing, as corrected on 

September 12, 2006, includes a revised 

version of PRC–002–0, designated as 

PRC–002–1. This revised Reliability 

Standard still applies to regional 

reliability organizations. Both of the 

original Requirements have been 

substantially revised.285 Requirement 

R1 from version 0 was substantially 

revised to require the regional reliability 

organization to establish certain 

installation requirements for sequence 

of event recording. Requirement R2 

from version 0 was modified to replace 

the regional reliability organization with 

transmission owners and generator 

owners and designated as Requirement 

R5 in version 1. The revised PRC–002–

1 includes four new Requirements: 

Requirement R2 (installation 

requirement for fault recording), 

Requirement R3 (installation 

requirement for dynamic disturbance 

recording), Requirement R4 (disturbance 

data reporting requirements), and 

Requirement R6 (regional reliability 

organization requirement to periodically 

review, update, and approve regional 

requirements for disturbance monitoring 

and reporting). In PRC–002–1, two new 

Measures for Requirements R4 and R6 

have been added and compliance was 

modified to include new Requirements. 

ii. Staff Preliminary Assessment 

823. The Staff Preliminary 

Assessment noted that PRC–002–0 is a 

fill-in-the-blank standard and identifies 

the regional reliability organization as 

the sole applicable entity, and PRC–

002–1 does as well. 

iii. Comments 

824. A number of commenters 

discussed how the Commission should 

address PRC–002–1 and other 

Reliability Standards in the PRC group 

that are ‘‘fill-in-the-blank’’ standards.286


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comments also apply to PRC–003–1, PRC–006–0, 

PRC–012–0, PRC–013–0; PRC–014–0 and PRC–020–

1. 

287An example of this is PRC–013–0, which 

requires the establishment of a regional database for 

special protection systems. 

CPUC and National Grid share the Staff 

Preliminary Assessment’s concern that 

certain ‘‘fill-in-the-blank’’ Reliability 

Standards are not written in a manner 

allowing enforcement against users, 

owners and operators of the Bulk-Power 

System. They point out that some of 

these Reliability Standards must be 

‘‘substantively regional’’ due to their 

unique characteristics and the physical 

realities of various regional transmission 

grids, citing examples such as underfrequency load shedding (UFLS) and 

under-voltage load shedding (UVLS) 

schemes, which are necessarily 

regionally unique. Further, they state 

that some are ‘‘procedurally regional’’

because they must be implemented by a 

regional body.287 National Grid urges 

the Commission and NERC that any 

revision of these Reliability Standards 

must adequately address these 

substantive and procedural concerns. 

825. Southern indicates that the 

industry and NERC are currently 

considering revisions to the ‘‘fill-in-theblank’’ standards. It states that revision 

would require a significant amount of 

time and coordination within the 

industry. Mandatory Reliability 

Standards must enhance and not detract 

from reliability. 

826. TANC advises the Commission to 

approve these ‘‘fill-in-the-blank’’

Reliability Standards on an interim 

basis until the applicable Regional 

Entities and NERC have conducted the 

appropriate approval procedure and are 

able to re-submit these Reliability 

Standards in final form to the 

Commission for its approval. 

iv. Commission Proposal 

827. Because regional procedures 

have not been submitted to the 

Commission, it is not possible to 

determine at this time whether PRC–

002–1 satisfies the statutory requirement 

that a proposed Reliability Standard be 

‘‘just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest.’’ Accordingly, the 

Commission will not propose to accept 

or remand this Reliability Standard 

until the ERO submits additional 

information. In the interim, compliance 

with PRC–002–1 should continue on its 

present basis, and the Commission 

considers compliance with the 

Reliability Standard to be a matter of 

good utility practice. 

d. Regional Procedure for Analysis of 

Misoperations of Transmission and 

Generation Protection Systems (PRC–

003–1) 

i. NERC Proposal 

828. PRC–003–1 ensures that all 

transmission and generation protection 

system misoperations are analyzed, and 

corrective action plans are developed. 

Misoperations occur when a protection 

system operates when it should not or 

does not operate when it should have. 

This Reliability Standard requires the 

regional reliability organization to 

develop a procedure to monitor and 

review misoperations of protection 

systems as well as the development and 

documentation of corrective actions. As 

discussed in PRC–002–0, this is one of 

the proposed Reliability Standards 

referred to as a ‘‘fill-in-the-blank’’

Reliability Standard. 

ii. Staff Preliminary Assessment 

829. Similar to its discussion of PRC–

002–0, staff noted that this Reliability 

Standard designates a regional 

reliability organization as the sole 

applicable entity. Staff was concerned 

about the feasibility of a regional 

reliability organization serving as the 

applicable entity and the enforceability 

of the proposed Reliability Standard in 

the mandatory Reliability Standards 

structure. 

iii. Comments 

830. A number of commenters 

discussed how the Commission should 

address PRC–003 and other Reliability 

Standards in the PRC group that are 

‘‘fill-in-the-blank’’ standards. In 

addition, ISO/RTO Council states that 

PRC–003–1 needs to better define the 

contents of the procedures in the 

Requirements and that the proposed 

Reliability Standard is unclear about 

how it may be effectively measured. 

iv. Commission Proposal 

831. The Commission does not share 

ISO/RTO Council’s view that a better 

definition of the contents of the regional 

reliability organization’s procedure is 

required. We refer to the list of elements 

that are included in Requirements R1.1 

to R1.5 to address transmission system 

protection misoperations. In addition, 

we note that PRC–003–1 contains two 

Measures requiring these procedures to 

be available and submitted on a timely 

basis upon request. 

832. Because the regional procedures 

have not been submitted to the 

Commission, it is not possible to 

determine at this time whether PRC–

003–1 satisfies the statutory requirement 

that a proposed Reliability Standard be 

‘‘just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest.’’ Accordingly, the 

Commission will not propose to accept 

or remand this Reliability Standard 

until the ERO submits additional 

information. In the interim, compliance 

with PRC–003–1 should continue on its 

present basis, and the Commission 

considers compliance with the 

Reliability Standard to be a matter of 

good utility practice. 

e. Analysis and Reporting of 

Transmission Protection System 

Misoperations (PRC–004–1) 

i. NERC Proposal 

833. Proposed Reliability Standard 

PRC–004–1 ensures that all 

transmission and generation protection 

system misoperations affecting the 

reliability of the Bulk-Power System are 

analyzed and mitigated by requiring 

transmission owners, generator owners 

and distribution providers that own a 

transmission protection system to 

analyze and document protection 

system misoperations. These entities 

must also develop corrective action 

plans in accordance with the regional 

reliability organization’s procedures. 

ii. Staff Preliminary Assessment 

834. No substantive issues were 

identified regarding PRC–004–1. 

iii. Comments 

835. MEAG states that, if a 

distribution provider owns a 

transmission protection system, the 

distribution provider is also a 

transmission owner according to 

NERC’s glossary definition. MEAG 

comments that it is unnecessary, 

overbroad and contrary to FPA section 

215 to include distribution providers in 

any of the proposed PRC Reliability 

Standards when the term ‘‘transmission 

owner’’ is sufficient to cover the scope 

of entities that own transmission 

protection systems. 

836. ISO/RTO Council comments that 

PRC–004–1 should clarify the definition 

of what the procedures must contain 

and how PRC–004–1 can be effectively 

measured. 

iv. Commission Proposal 

837. We disagree with the ISO/RTO 

Council that the Requirements and 

Measures of the proposed Reliability 

Standard are unclear. Requirement R1 

requires the owners of transmission 

protection systems to analyze all 

protection system misoperations, take 

corrective actions and provide the 

associated analysis documents with 

corrective action plans to NERC. Further 

PRC–004–1 contains Measures that 


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288Staff identified several other PRC Reliability 

Standards such as PRC–005–1, PRC–008–0, PRC–

011–0 and PRC–017–0 that contain similar 

concerns. 

289Blackout Report, Recommendation No. 21 at 

159. 

these owners have evidence that they 

analyzed protection system 

misoperations and took corrective 

actions, with all associated 

documentation provided. 

838. The applicability section of PRC–

004–1 provides that, inter alia, a 

‘‘Distribution Provider that owns a 

transmission Protection System’’ must 

comply with this Reliability Standard. 

This applicability provision makes clear 

that the Reliability Standard applies 

only to a subset of distribution 

providers. We believe that this approach 

is appropriate. With regard to MEAG’s 

concern, the Commission disagrees with 

MEAG that a distribution provider by 

virtue of owning transmission 

protection equipment becomes a 

transmission owner, which would then 

be subject to all of the Reliability 

Standards applicable to a transmission 

owner. 

839. Reliability Standard PRC–004–1 

serves an important purpose in ensuring 

that transmission and generation 

protection system misoperations 

affecting the reliability of the BulkPower System are analyzed and 

mitigated. For the reasons discussed 

above, the Commission believes that 

Reliability Standard PRC–004–1 is just, 

reasonable, not unduly discriminatory 

or preferential, and in the public 

interest; and proposes to approve it as 

mandatory and enforceable. 

f. Transmission Protection System 

Maintenance and Testing (PRC–005–1) 

i. NERC Proposal 

840. Proposed Reliability Standard 

PRC–005–1 ensures that all 

transmission and generation protection 

systems affecting the reliability of the 

Bulk-Power System are maintained and 

tested by requiring the transmission 

owners, distribution providers, and 

generator owners to develop, document, 

and implement a protection system 

maintenance program that may be 

reviewed by the regional reliability 

organization. 

ii. Staff Preliminary Assessment 

841. The Staff Preliminary 

Assessment stated that protection 

systems must be maintained and tested 

at regular intervals to ensure that they 

will operate as intended when called 

upon and that maintenance intervals 

vary depending on the type and nature 

of the protection system, as well as the 

reliability impact of a potential failure 

of that system. Staff identified several 

Reliability Standards in the PRC group 

addressing the maintenance and testing 

of different protection systems that are 

technically deficient because they do 

not specify the criteria to determine the 

appropriate maintenance intervals, and 

they do not specify maximum allowable 

maintenance intervals for the 

protections systems.288

842. Staff cited PRC–006–0 as good 

example of a Reliability Standard that 

requires periodic assessments of the 

effectiveness of regional UFLS programs 

at least once every five years regardless 

of the circumstance. 

iii. Comments 

843. NERC states that it welcomes 

discussion and debate on the proper 

study and maintenance intervals for 

regular and special protection systems. 

It will consider these comments in the 

re-authorization of these Reliability 

Standards or the development of future 

Reliability Standards. Within its 

existing scope, the NERC System 

Protection and Controls Task Force will 

examine all PRC Reliability Standards 

for consistency and technical 

completeness. It will then propose any 

appropriate modifications through the 

standards process. 

844. ISO/RTO Council echoes the 

concerns of the Staff Preliminary 

Assessment that the proposed 

Reliability Standard must define the 

missing maintenance intervals. 

845. ReliabilityFirst contends that the 

purpose of PRC–005–1 does not call for 

specific justification for allowable 

maintenance intervals, it calls for 

intervals only. However, it urges NERC 

to develop maximum allowable 

intervals based on reliability-centered 

study results developed by the regions 

and companies therein. 

iv. Commission Proposal 

846. The Commission proposes to 

approve PRC–005–1 as mandatory and 

enforceable. In addition, we propose to 

direct that NERC develop modifications 

to the Reliability Standard as discussed 

below. 

847. Proposed Reliability Standard 

PRC–005–1 does not specify the criteria 

to determine the appropriate 

maintenance intervals, nor does it 

specify maximum allowable 

maintenance intervals for the 

protections systems. The Commission 

therefore proposes that NERC include a 

requirement that maintenance and 

testing of these protection systems must 

be carried out within a maximum 

allowable interval that is appropriate to 

the type of the protection system and its 

impact on the reliability of the BulkPower System. 

848. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard PRC–005–

1 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to PRC–005–1 that includes a 

requirement that maintenance and 

testing of a protection system must be 

carried out within a maximum 

allowable interval that is appropriate to 

the type of the protection system and its 

impact on the reliability of the BulkPower System. 

g. Development and Documentation of 

Regional UFLS Programs (PRC–006–0) 

i. NERC Proposal 

849. Proposed Reliability Standard 

PRC–006–0 ensures the development of 

a regional UFLS program that will be 

used as a last resort to preserve the 

Bulk-Power System during a major 

system failure that could cause system 

frequency to collapse. PRC–006–0 is a 

‘‘fill-in-the-blank’’ standard that 

requires the regional reliability 

organization to develop, coordinate, 

document and assess UFLS program 

design and effectiveness at least every 

five years. 

ii. Staff Preliminary Assessment 

850. The Staff Preliminary 

Assessment identified two concerns for 

PRC–006–0: (1) A regional reliability 

organization is identified as the sole 

applicable entity; and (2) it lacks the 

proper specificity for an integrated and 

coordinated approach for the protection 

systems for generators, transmission 

lines and UFLS and UVLS programs as 

recommended by the Blackout 

Report.289

Staff also pointed out that the 

proposed Reliability Standard requires a 

periodic assessment of the effectiveness 

of the regional UFLS programs and 

design details at least once every five 

years, which is a good example of a 

maximum allowable interval without 

specific justification. 

iii. Comments 

851. NERC claims that it is addressing 

Staff’s concern that PRC–006–0 lacks an 

integrated and coordinated approach to 

protection for generators, transmission 


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lines and UFLS and UVLS programs 

within its work on the ‘‘fill-in-theblank’’ proposed Reliability Standards. 

However, NERC points out that 

Requirement R3 of EOP–003–0 obligates 

transmission operators and balancing 

authorities to coordinate load shedding 

plans among other interconnected 

transmission operators and balancing 

authorities. 

852. Alcoa contends that proposed 

Reliability Standards PRC–006–0 and 

EOP–003–0 essentially assign similar 

responsibilities to different entities, 

thereby creating the potential for 

ambiguity. It states that while EOP–003–

0 applies to transmission operators and 

balancing authorities and PRC–006–0 

applies to regional reliability 

organizations, requirements in both 

proposed Reliability Standards mandate 

the design of a load shedding scheme, 

including frequency set points as a 

design component, under abnormal 

system conditions. 

853. CenterPoint believes that the 

proposed Reliability Standard 

adequately addresses the integration 

and coordination issues, but does not 

address coordination between the 

generator low voltage ride-through 

requirement, UVLS and dynamic 

voltage recovery requirements. Further, 

it states that such coordination is not 

addressed by the proposed Reliability 

Standard because the underlying 

requirements are missing. 

854. ReliabilityFirst suggests that 

NERC should develop an 

Interconnection-based program and use 

the programs developed by the regions 

within the Interconnection as a starting 

point. It believes that the primary 

objective of the proposed Reliability 

Standards is to meet system 

performance requirements and suggests 

that more definitive measurable 

requirements should be developed to 

create an integrated and coordinated 

approach to Bulk-Power System 

protection. 

iv. Commission Proposal 

855. Because the regional procedures 

have not been submitted to the 

Commission, it is not possible to 

determine at this time whether PRC–

006–0 satisfies the statutory requirement 

that a proposed Reliability Standard be 

‘‘just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest.’’ Accordingly, the 

Commission will not propose to accept 

or remand this Reliability Standard 

until the ERO submits additional 

information. In the interim, compliance 

with PRC–006–0 should continue on its 

current basis, and the Commission 

considers compliance with the 

Reliability Standard to be a matter of 

good utility practice. Although we do 

not propose to approve or remand with 

regard to MOD–002–0 at this time, we 

address comments and our additional 

concerns regarding this Reliability 

Standard below. 

856. The Commission commends 

NERC’s initiative in adopting an 

integrated and coordinated approach to 

protection for generators, transmission 

lines and UFLS and UVLS programs 

within its work on the ‘‘fill in the 

blank’’ proposed Reliability Standards. 

Responding to NERC’s comments on 

Requirement R3 of EOP–003–0, the 

Commission cautions that it only 

addresses a relatively small portion of 

the coordination of load shedding plans 

among other interconnected entities, but 

still lacks the main and overall 

integration and coordination 

requirements for all protection systems 

in the Bulk-Power System. 

857. The Commission disagrees with 

Alcoa that Reliability Standards PRC–

006–0 and EOP–003–0 essentially assign 

similar responsibilities to different 

entities, thereby creating the potential 

for ambiguity. There are distinctive 

features of UFLS programs which are 

designed to trip load automatically 

within seconds upon detection of 

abnormal system conditions due to the 

imbalance of generation and load 

resulting in rapidly declining 

interconnected system frequencies. 

Therefore, the design and coordination 

of UFLS programs must be region-wide 

or Interconnection-wide to ensure their 

effectiveness as covered by PRC–006–0. 

The load shedding plans that are 

covered in EOP–003–0 are also required 

as an operating measure of last resort to 

address system emergencies in which 

declining system frequency may not be 

a prevailing indicator. Instead, system 

voltages may fast approach voltage 

instability, system elements may be 

severely overloaded or an IROL of a 

critical interface may be severely 

exceeded. All of these are indicators of 

an imminent threat of cascading outages 

while system operators have exhausted 

all available corrective actions to return 

the system to a secure state. In addition, 

load shedding plans usually consist of 

several components including UFLS or 

UVLS with different levels of response 

time to facilitate load shedding. Some 

load shedding capability is achieved via 

remote SCADA control from the 

transmission operators’ control room 

and some via manual disconnection by 

load serving entities under direct order 

from a transmission operator or 

reliability coordinator during system 

emergencies. In some cases, 

transmission operators may use system 

reconfiguration to disconnect large 

blocks of load as a part of their load 

shedding plans. The Commission views 

PRC–006–0 and EOP–003–0 as two 

separate and necessary Reliability 

Standards and the small overlap 

between the two is necessary to ensure 

that effective load shedding capabilities 

are available to address a wide range of 

emergency operating conditions. 

858. The Commission disagrees with 

CenterPoint that adequate integration 

and coordination is already included in 

PRC–006–0 because this is contrary to 

NERC’s initiative in adopting an 

integrated and coordinated approach to 

protection for generators, transmission 

lines and UFLS and UVLS programs. 

However, we support CenterPoint’s 

recommendation that the generator 

under-voltage ride-through capability is 

an important element that should be 

included in the integrated and 

coordinated approach among relay 

protection for generators and 

transmission lines and the use of UFLS 

and UVLS programs. 

859. In response to ReliabilityFirst’s 

suggestion to include additional 

definitive measures to meet system 

performance, the Commission believes 

that the technical requirements should 

first include the integrated and 

coordinated approach in Bulk-Power 

System protection, including the 

frequency response of the 

interconnection to load and generation 

loss. Compliance Measures should be 

definitive to ensure these technical 

requirements are met. 

h. Assuring Consistency With Regional 

UFLS Program Requirements (PRC–007–

0) 

i. NERC Proposal 

860. Proposed Reliability Standard 

PRC–007–0 requires transmission 

owners, transmission operators, loadserving entities, and distribution 

providers to provide, and annually 

update, their under-frequency data to 

facilitate the regional reliability 

organization’s maintenance of, and 

updates to, the UFLS program database. 

Transmission owners and distribution 

providers must provide documentation 

of their UFLS program to the regional 

reliability organization. 

ii. Staff Preliminary Assessment 

861. No substantive issues were 

identified regarding PRC–007–0. 

iii. Comments 

862. CPUC states that PRC–007–0 is 

an example of a Reliability Standard 

that should be mandatory on a national 

level, but for which it is appropriate for 

the details of implementation to be 


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delegated to a regional reliability 

organization. ISO/RTO Council states 

that PRC–007–0 fails to define an 

acceptable UFLS program. 

iv. Commission Proposal 

863. With regard to ISO/RTO 

Council’s comment, the specification of 

an acceptable UFLS program is the 

subject of PRC–006–0. In contrast, PRC–

007–0 provides that, if an entity has a 

UFLS program, the program must be 

consistent with its regional reliability 

organization’s requirements. 

864. The Commission believes that 

there are no substantive issues with this 

proposed Reliability Standard. We note 

that, once approved, the proposed 

Reliability Standard will be applied and 

enforced on a national scale as 

suggested by CPUC. 

865. Accordingly, the Commission 

proposes to approve PRC–007–0 as 

mandatory and enforceable. We believe 

that the proposed Reliability Standard is 

just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest. 

i. Under Frequency Load Shedding 

Equipment Maintenance Programs 

(PRC–008–0) 

i. NERC Proposal 

866. Proposed Reliability Standard 

PRC–008–0 requires transmission 

owners and distribution providers to 

implement UFLS equipment 

maintenance and testing programs and 

provide program results to the regional 

reliability organization. 

ii. Staff Preliminary Assessment 

867. According to the Staff 

Preliminary Assessment, PRC–008–0 

does not specify the criteria to 

determine appropriate maintenance 

intervals or the maximum allowable 

interval to ensure effectiveness, as 

discussed in detail in the Staff 

Preliminary Assessment section of this 

rulemaking under PRC–005–1. No other 

substantive issues were identified for 

this proposed Reliability Standard. 

iii. Comments 

868. Commenter’s statements 

regarding maximum allowable intervals 

for the performance of maintenance and 

testing programs have been presented in 

detail under the comments for PRC–

005–1. 

iv. Commission Proposal 

869. The Commission notes that the 

commenters generally share staff’s 

concern that the proposed Reliability 

Standard does not specify the criteria to 

determine the appropriate maintenance 

intervals, nor does it specify maximum 

allowable maintenance intervals for the 

protection systems. The Commission 

agrees and proposes to require NERC to 

modify the proposed Reliability 

Standard to include a requirement that 

maintenance and testing of UFLS 

programs must be carried out within a 

maximum allowable interval that is 

appropriate to the type of relay used and 

the impact on the reliability of the BulkPower System. 

870. Accordingly, the Commission 

proposes to approve Reliability 

Standard PRC–008–0 as mandatory and 

enforceable. In addition, the 

Commission proposes to direct that 

NERC submit a modification to PRC–

008–0 that includes a requirement that 

maintenance and testing of UFLS 

programs must be carried out within a 

maximum allowable interval 

appropriate to the relay type and the 

potential impact on the Bulk-Power 

System. 

j. UFLS Performance Following an 

Under Frequency Event (PRC–009–0) 

i. NERC Proposal 

871. Proposed Reliability Standard 

PRC–009–0 ensures that the 

performance of an UFLS system is 

analyzed and documented following an 

under frequency event by requiring the 

transmission owner, transmission 

operator, load-serving entity and 

distribution provider to document their 

operation in accordance with the 

regional reliability organization’s 

program and to provide that 

documentation to the regional reliability 

organization and NERC upon their 

request. 

ii. Staff Preliminary Assessment 

872. Staff noted that, although the 

proposed Reliability Standard contains 

the reporting requirement for operation 

events for UFLS, there is no similar 

reporting requirement for operation 

events for UVLS in the proposed 

Reliability Standards that are associated 

with UVLS programs. 

iii. Comments 

873. ReliabilityFirst supports the 

development of a companion UVLS 

Reliability Standard with reporting 

requirements that are similar to this 

UFLS Reliability Standard. Likewise, 

NERC acknowledges the concerns of the 

Staff Preliminary Assessment, noting 

the lack of a reporting requirement for 

operation events of UVLS and plans to 

address this omission in its work on the 

‘‘fill-in-the-blank’’ proposed Reliability 

Standards that are associated with 

UVLS. 

874. ISO/RTO Council states that, due 

to the fact that PRC–009–0 

inappropriately relies on the undefined 

UFLS programs of regional reliability 

organizations, NERC must review and 

approve the regional reliability 

organizations’ programs before the 

proposed Reliability Standard can go 

into effect. 

875. TAPS states that PRC–009–0 

requires distribution providers with a 

transmission protection program to 

analyze an under-frequency event and 

document the post-mortem. It cautions 

that it may be difficult and unduly 

burdensome for a small entity to 

perform given limited access to event 

data and the need to perform a stability 

analysis. 

876. CenterPoint suggests adopting a 

performance metric approach rather 

than a ‘‘fill-in-the-blank’’ approach to 

this Reliability Standard. It contends 

that compliance should be 

straightforward since transmission and 

distribution service providers are 

supposed to trip a certain amount of 

load under specified under-frequency 

conditions. Therefore, either the utility 

tripped the required amount of load or 

it did not, perhaps with some 

bandwidth. 

iv. Commission Proposal 

877. The Commission discusses ISO/ 

RTO Council’s comments on the general 

issue that regional Reliability Standards 

must be approved by the ERO and the 

Commission before they become 

effective above in the section on 

Common Issues. 

878. The Commission does not find 

any material difference between 

CenterPoint’s suggestion to use a 

performance metric approach and the 

Requirements in this proposed 

Reliability Standard. We believe 

performance metrics, especially leading 

metrics, are excellent complementary 

components in Reliability Standards 

which enable further enhancement and 

effectiveness of these Reliability 

Standards. 

879. With respect to TAPS’ concern 

regarding the size of distribution 

providers and load serving entities, the 

Commission discusses this issue in the 

Common Issues section of this NOPR. 

880. The Commission believes that 

the proposal serves an important 

purpose in ensuring that the 

performance of an UFLS system is 

analyzed and documented following an 

under frequency event. Further the 

proposed Requirements are sufficiently 

clear and objective to provide guidance 

for compliance. Accordingly, the 

Commission proposes to approve PRC–

009–0 as mandatory and enforceable. 

We believe that the proposed Reliability 

Standard is just, reasonable, not unduly 


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290At least every five years or as required by 

changes in system conditions. 

291Blackout Report at 159. 

292Available at http://www.nerc.com/∼filez/ 

reports.html. 

293PRC–010–0, PRC–020–1 and PRC–021–1. 

discriminatory or preferential, and in 

the public interest. 

k. Assessment of the Design and 

Effectiveness of UVLS Program (PRC–

010–0) 

i. NERC Proposal 

881. Proposed Reliability Standard 

PRC–010–0 requires transmission 

owners, transmission operators, loadserving entities, and distribution 

providers to periodically conduct and 

document an assessment of the 

effectiveness of the UVLS program.290

This assessment shall be conducted 

with the associated transmission 

planner and planning authority. 

ii. Staff Preliminary Assessment 

882. The Staff Preliminary 

Assessment raised the concern that this 

proposed Reliability Standard on UVLS, 

similar to PRC–006–0 on UFLS, is not 

specific enough to address Blackout 

Report Recommendation No. 21 

concerning an integrated and 

coordinated approach for the protection 

systems for generators, transmission 

lines and UFLS and UVLS programs.291

iii. Comments 

883. NERC states that it has made 

progress in responding to Blackout 

Recommendation No. 21 on the 

Evaluation of Applicability of UVLS 

programs. The NERC Planning 

Committee reviewed each regional 

reliability organization’s assessment of 

the feasibility and benefits of installing 

UVLS capability. In addition, the NERC 

Planning Committee has completed a 

report entitled, ‘‘Review of Regional 

Evaluations of Under-voltage Load 

Shedding Capability in Response to 

NERC Blackout Recommendation 

8b,’’ 292 with follow-up 

recommendations to be completed by 

the NERC Planning Committee and the 

regions, along with an implementation 

plan. NERC further states that the work 

is ongoing under the supervision of the 

NERC Planning Committee and will 

result in requests for new standards as 

the work is completed and suitable 

methods and criteria are developed. 

884. CenterPoint questions the need 

for this Reliability Standard and the 

other three Reliability Standards that 

address other UVLS requirements,293

while acknowledging that there is a 

significant need for UVLS for some 

systems. CenterPoint contends that it is 

unreasonable and unnecessary to 

require examination and documentation 

of any and all UVLS trips. Further, it 

states that producing unnecessary 

Reliability Standards for utilities that 

install UVLS schemes could have the 

adverse effect of discouraging utilities 

that might benefit from UVLS by 

installing the schemes or, alternatively, 

punishing the utilities that do so. 

885. MEAG seeks a clarification in the 

specific instance where the transmission 

owner owns and maintains a 

transmission protection system, e.g., a 

UFLS or UVLS system, and where some 

of the associated relays are designed to 

trip a distribution breaker owned by a 

customer. 

886. ReliabilityFirst suggests an 

integrated and coordinated approach to 

Bulk-Power System protection, as 

discussed above in the context of PRC–

006–0. 

iv. Commission Proposal 

887. The Commission commends the 

initiative and efforts that have been 

taken by NERC and industry in 

addressing UVLS requirements as 

recommended by the Blackout Report 

and expects to review these 

improvements in the proposed 

Reliability Standards associated with 

UVLS in their future revisions. 

888. The Commission believes that 

Reliability Standards of UVLS are 

required in the same manner as 

Reliability Standards for line and 

generation protection, UFLS or special 

protection systems since all of them are 

required to ensure reliable system 

operation. Therefore, we disagree with 

CenterPoint’s view that UVLS 

Reliability Standards are not necessary. 

889. In response to a question raised 

by MEAG regarding the ownership of an 

UFLS or UVLS installed by a 

transmission owner on a breaker owned 

by a customer, the transmission owner 

remains the owner. The transmission 

owner or transmission operator can trip 

the breaker automatically or have a 

delegated agreement with the customer 

to trip the breaker in case of an UFLS 

or UVLS event. The Commission 

believes that the Reliability Standard 

should be interpreted to achieve its 

reliability goal. This can be 

accomplished by each entity performing 

their required maintenance and 

operational activities or by one entity 

doing the required activities. However, 

the UFLS or UVLS system must be 

maintained from the sensors that detect 

the event to the actual opening of the 

circuit breaker. 

890. In response to ReliabilityFirst’s 

suggestion to include additional 

definitive measures to meet system 

performance, the Commission believes 

that the technical requirements should 

include an integrated and coordinated 

approach in Bulk-Power System 

protection, including the frequency 

response of the interconnection to load 

and generation loss. Compliance 

Measures should be definitive to ensure 

these technical requirements are met. 

891. The Commission believes that 

Reliability Standard PRC–010–0 serves 

an important purpose in requiring the 

periodical assessment of the 

effectiveness of a UVLS program. 

Further, the proposed Requirements are 

sufficiently clear and objective to 

provide guidance for compliance. 

892. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard PRC–010–

0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to PRC–010–0 that requires that an 

integrated and coordinated approach be 

included in all protection systems on 

the Bulk-Power System, including 

generators and lines, generator’s low 

voltage ride-through capabilities, and 

UFLS and UVLS programs. 

l. Under Voltage Load Shedding System 

Maintenance and Testing (PRC–011–0) 

i. NERC Proposal 

893. Proposed Reliability Standard 

PRC–011–0 requires transmission 

owners and distribution providers to 

implement their UVLS equipment 

maintenance and testing program and 

provide program results to regional 

reliability organization. 

ii. Staff Preliminary Assessment 

894. Staff expressed concern that 

PRC–011–0 does not specify the criteria 

to determine the appropriate 

maintenance intervals or maximum 

allowable intervals for protection 

systems to ensure effectiveness has been 

articulated in detail in the same section 

in PRC–005–1. 

iii. Comments 

895. NERC indicates that it will 

consider maximum intervals; and ISO/ 

RTO Council and other commenters 


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294While commenters raise these concerns 

primarily in the context of PRC–005–1, their 

comments apply to PRC–011–0 as well. 

295A special protection system is a unique system 

designed to automatically take corrective actions to 

protect the system under abnormal or 

predetermined conditions, excluding the 

coordinated tripping of circuit breakers to isolate 

faulted components, which is typically the purpose 

of other protection devices. 

296 296 CPUC, FRCC, National Grid, NPCC, 

NYSRC, ReliabilityFirst, Southern and TANC. Their 

comments also apply to PRC–003–1, PRC–006–0, 

PRC–012–0, PRC–013–0; PRC–014–0 and PRC–020–

1. 

agree with the Staff Preliminary 

Assessment.294

iv. Commission Proposal 

896. PRC–011–0 does not specify the 

criteria to determine the appropriate 

maintenance intervals, nor does it 

specify maximum allowable 

maintenance intervals for the 

protections systems. The Commission 

proposes that NERC include a 

Requirement that maintenance and 

testing of these UFLS programs must be 

carried out within a maximum 

allowable interval that is appropriate to 

the type of the relay used and the 

impact of these UFLS on the reliability 

of the Bulk-Power System. 

897. The Commission believes that 

Reliability Standard PRC–011–0 serves 

an important purpose in requiring 

transmission owners and distribution 

providers to implement their UVLS 

equipment maintenance and testing 

programs. Further, the proposed 

Requirements are sufficiently clear and 

objective to provide guidance for 

compliance. 

898. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard PRC–011–

0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to PRC–011–0 that includes a 

requirement that maintenance and 

testing of UVLS programs must be 

carried out within a maximum 

allowable interval appropriate to the 

applicable relay and the impact on the 

reliability of the Bulk-Power System. 

m. Special Protection System Review 

Procedure (PRC–012–0) 

i. NERC Proposal 

899. Proposed Reliability Standard 

PRC–012–0 requires regional reliability 

organizations to ensure that all special 

protection systems 295 are properly 

designed, meet performance 

requirements and are coordinated with 

other protection systems. Maintenance 

and testing programs must be developed 

and special protection system 

misoperations must be analyzed and 

corrected. 

ii. Staff Preliminary Assessment 

900. Similar to its discussion of PRC–

002–1, staff noted that Reliability 

Standard designates a regional 

reliability organization as the sole 

applicable entity. 

iii. Comments 

901. A number of commenters 

discussed how the Commission should 

address PRC–012–0 and other fill-inthe-blank standards in the PRC group 

that require compliance by regional 

reliability organizations.296

iv. Commission Proposal 

902. Because the regional procedures 

have not been submitted to the 

Commission, it is not possible to 

determine at this time whether PRC–

012–0 satisfies the statutory requirement 

that a proposed Reliability Standard be 

‘‘just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest.’’ Accordingly, the 

Commission will not propose to accept 

or remand this Reliability Standard 

until the ERO submits additional 

information. In the interim, compliance 

with PRC–012–0 should continue on its 

current basis, and the Commission 

considers compliance with the 

Reliability Standard to be a matter of 

good utility practice. 

n. Special Protection System Database 

(PRC–013–0) 

i. NERC Proposal 

903. Proposed Reliability Standard 

PRC–013–0 ensures that all special 

protection systems are properly 

designed, meet performance 

requirements and are coordinated with 

other protection systems by requiring 

the regional reliability organization to 

maintain a database of pertinent 

information on special protection 

systems. 

ii. Staff Preliminary Assessment 

904. Similar to its discussion of PRC–

002–1, staff noted that this Reliability 

Standard designates a regional 

reliability organization as the sole 

applicable entity. 

iii. Comments 

905. A number of commenters 

discussed how the Commission should 

address PRC–012–0 and other fill-inthe-blank standards in the PRC group 

that require compliance by regional 

reliability organizations. 

906. ISO/RTO Council states that this 

Reliability Standard identifies only 

categories rather than the detailed data 

useful for ensuring that a meaningful 

special protection system database is 

maintained. 

907. National Grid identifies this 

Reliability Standard as one of those it 

refers to as ‘‘procedurally regional.’’

That is, the requirement is set on a 

national level but is implemented 

regionally. In the case of PRC–013–0, all 

relevant entities would be required to 

provide information to databases 

established and maintained by some 

regional body. National Grid explains 

that this is one example of a legitimate 

‘‘fill-in-the-blank’’ Reliability Standard. 

iv. Commission Proposal 

908. The Commission believes that 

the current Requirements and Measures 

in the proposed Reliability Standard are 

adequate, and therefore, disagrees with 

ISO/RTO Council’s comments in this 

regard. Requirement R1 includes three 

categories of data with each category 

providing a more detailed description of 

required data. Measure M1 requires that 

each owner with a special protection 

system must have the corresponding 

database as specified in the proposed 

Reliability Standard. 

909. We agree with National Grid that 

the database should be maintained on a 

regional basis. However, Regional 

Entities have not undergone an approval 

process under section 215. Therefore, 

we cannot yet enforce this requirement. 

910. Because the regional procedures 

have not been submitted to the 

Commission, it is not possible to 

determine at this time whether PRC–

013–0 satisfies the statutory requirement 

that a proposed Reliability Standard be 

‘‘just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest.’’ Accordingly, the 

Commission will not propose to accept 

or remand this Reliability Standard 

until the ERO submits additional 

information. In the interim, compliance 

with PRC–013–0 should continue on its 

current basis, and the Commission 

considers compliance with the 

Reliability Standard to be a matter of 

good utility practice. 


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o. Special Protection System 

Assessment (PRC–014–0) 

i. NERC Proposal 

911. Proposed Reliability Standard 

PRC–014–0 ensures that special 

protection systems are properly 

designed, meet performance 

requirements, and are coordinated with 

other protection systems by requiring 

the regional reliability organization to 

assess and document the operation, 

coordination, compliance with NERC 

Reliability Standards, as well as the 

effectiveness of special protection 

systems, at least once every five years. 

ii. Staff Preliminary Assessment 

912. Similar to its discussion of PRC–

002–1, staff noted that this Reliability 

Standard designates a regional 

reliability organization as the sole 

applicable entity. 

913. The Staff Preliminary 

Assessment noted that the maximum 

allowable interval of at least once every 

five years as a Requirement for assessing 

the effectiveness of the special 

protection systems is a good example of 

a maximum allowable interval without 

specific justification. 

iii. Comments 

914. A number of commenters 

discussed how the Commission should 

address PRC–012–0 and other fill-inthe-blank standards in the PRC group 

that require compliance by regional 

reliability organizations. 

iv. Commission Proposal 

915. Because the regional procedures 

have not been submitted to the 

Commission, it is not possible to 

determine at this time whether PRC–

014–0 satisfies the statutory requirement 

that a proposed Reliability Standard be 

‘‘just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest.’’ Accordingly, the 

Commission will not propose to accept 

or remand this Reliability Standard 

until the ERO submits the regional 

procedures or a single continent-wide 

procedure. In the interim, compliance 

with PRC–014–0 should continue on its 

current basis, and the Commission 

considers compliance with the 

Reliability Standard to be a matter of 

good utility practice. 

p. Special Protection System Data and 

Documentation (PRC–015–0) 

i. NERC Proposal 

916. Proposed Reliability Standard 

PRC–015–0 requires transmission 

owners, generator owners, and 

distribution providers to maintain a 

listing, retain evidence of review, and 

provide documentation for existing, 

new, or functionally modified special 

protection systems. 

ii. Staff Preliminary Assessment 

917. No substantive issues were 

identified for the proposed Reliability 

Standard. 

iii. Comments 

918. The ISO/RTO Council believes 

that the time period used for assessing 

compliance is not clear in this 

Reliability Standard. 

iv. Commission Proposal 

919. The Commission believes that 

there are no substantive issues 

identified for this proposed Reliability 

Standard. 

920. We disagree with ISO/RTO 

Council’s view that the compliance time 

period is not clear. Requirement 3 of 

this Reliability Standard requires 

documentation to be provided within 30 

days for compliance requirements. 

921. Accordingly, the Commission 

proposes to approve PRC–015–0 as 

mandatory and enforceable. We believe 

that the proposed Reliability Standard is 

just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest. 

q. Special Protection System 

Misoperations (PRC–016–0) 

i. NERC Proposal 

922. Proposed Reliability Standard 

PRC–016–0 requires transmission 

owners, generator owners and 

distribution providers to provide the 

regional reliability organization with 

documentation, analyses and corrective 

action plans for misoperation of special 

protection systems. 

ii. Staff Preliminary Assessment 

923. No substantive issues were 

identified for the proposed Reliability 

Standard. 

iii. Comments 

924. ISO/RTO Council is concerned 

that this Reliability Standard fails to 

identify the analysis sufficient for 

reviewing special protection system 

operations and the type of corrective 

action that must be taken to avoid 

misoperations. It also believes that 

reports on special protection system 

misoperations should be routinely 

provided to the regional reliability 

organization and NERC. 

iv. Commission Proposal 

925. We disagree with ISO/RTO 

Council that PRC–016–0 does not 

identify the analysis sufficient for 

reviewing special protection systems 

and the type of corrective actions 

required to avoid misoperations. 

However, we agree that reports on 

special protection system misoperations 

should be routinely provided to the 

regional reliability organization and 

NERC and propose to require NERC to 

provide that routine reporting be limited 

to misoperations of special protection 

systems that have Interconnection-wide 

reliable impact and routine submission 

of the corrective action plans upon 

implementation instead of the current 

requirement of 90 days upon request. 

926. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard PRC–016–

0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to PRC–016–0 that includes a 

requirement that maintenance and 

testing of these special protection 

system programs must be carried out 

within a maximum allowable interval 

that is appropriate for the type of 

relaying used and the impact of these 

special system protection programs on 

the reliability of the Bulk-Power System. 

r. Special Protection System 

Maintenance and Testing (PRC–017–0) 

i. NERC Proposal 

927. Proposed Reliability Standard 

PRC–017–0 requires transmission 

owners, generator owners, and 

distribution providers to provide the 

regional reliability organization with 

documentation on special protection 

system maintenance, testing and 

implementation plans. 

ii. Staff Preliminary Assessment 

928. Staff expressed concern that this 

Reliability Standard does not specify the 

criteria to determine the appropriate 

maintenance intervals or maximum 

allowable intervals for protection 

systems to ensure effectiveness. 

iii. Comments 

929. The comments provided by ISO/ 

RTO Council and NERC regarding 

maximum allowable intervals in 

carrying out maintenance and testing 

programs in the PRC Reliability 

Standards have been presented in detail 

in PRC–005–1. 


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iv. Commission Proposal 

930. PRC–017–0 does not specify the 

criteria to determine the appropriate 

maintenance intervals, nor does it 

specify maximum allowable 

maintenance intervals for the 

protections systems. The Commission 

proposes to require NERC to include a 

requirement that maintenance and 

testing of these special protection 

system programs must be carried out 

within a maximum allowable interval 

that is appropriate to the type of 

relaying used and the impact of these 

special protection system programs on 

the reliability of the Bulk-Power System. 

931. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard PRC–017–

0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to PRC–017–0 that: (1) Includes a 

requirement that maintenance and 

testing of these special protection 

system programs must be carried out 

within a maximum allowable interval 

that is appropriate to the type of 

relaying used; and (2) identifies the 

impact of these special protection 

system programs on the reliability of the 

Bulk-Power System. 

s. Disturbance Monitoring Equipment 

Installation and Data Reporting (PRC–

018–1) 

i. NERC Proposal 

932. Proposed Reliability Standard 

PRC–018–1 ensures that disturbance 

monitoring equipment is installed and 

disturbance data is reported in 

accordance with comprehensive 

requirements for installing disturbance 

monitoring equipment. 

ii. Staff Preliminary Assessment 

933. This is a new Reliability 

Standard and it was not assessed in the 

Staff Preliminary Assessment. 

iii. Comments 

934. Because this Reliability Standard 

was not discussed in the Staff 

Preliminary Assessment, no comments 

have been filed. 

iv. Commission Proposal 

935. The Commission notes that the 

proposed Reliability Standard addressed 

Blackout Report Recommendation No. 

28 by requiring the transmission owner 

and generator owner to install 

disturbance monitoring equipment and 

report disturbance data. The 

Commission commends the initiative 

and efforts taken by NERC and industry 

in addressing this recommendation. 

936. Accordingly, the Commission 

proposes to approve PRC–018–1 as 

mandatory and enforceable. We believe 

that the proposed Reliability Standard is 

just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest. 

t. Under-Voltage Load Shedding 

Program Database (PRC–020–1) 

i. NERC Proposal 

937. Proposed Reliability Standard 

PRC–020–1 ensures that a regional 

database for UVLS programs is available 

for Bulk-Power System studies by 

requiring regional reliability 

organizations with any entities that have 

UVLS programs to maintain and 

annually update a database. 

ii. Staff Preliminary Assessment 

938. Staff noted that this version 1 

Reliability Standard was recently 

approved by the NERC Board of 

Trustees, effective May 1, 2006, and 

does not address the applicability 

concerns articulated in the Staff 

Preliminary Assessment. 

939. In addition, similar to its 

discussion of PRC–002–1, staff noted 

that this Reliability Standard designates 

a regional reliability organization as the 

sole applicable entity. Staff was 

concerned about the feasibility of a 

regional reliability organization serving 

as the applicable entity and the 

enforceability of the proposed 

Reliability Standard in the mandatory 

Reliability Standards structure. 

iii. Comments 

940. A number of commenters 

discussed how the Commission should 

address PRC–020–0 and other fill-inthe-blank standards in the PRC group 

that require compliance by regional 

reliability organizations. 

iv. Commission Proposal 

941. Because the regional procedures 

have not been submitted to the 

Commission, it is not possible to 

determine at this time whether PRC–

020–1 satisfies the statutory requirement 

that a proposed Reliability Standard be 

‘‘just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest.’’ Accordingly, the 

Commission will not propose to accept 

or remand this Reliability Standard 

until the ERO submits additional 

information. In the interim, compliance 

with PRC–020–1 should continue on its 

current basis, and the Commission 

considers compliance with the 

Reliability Standard to be a matter of 

good utility practice. 

u. Under-Voltage Load Shedding 

Program Data (PRC–021–1) 

i. NERC Proposal 

942. Proposed Reliability Standard 

PRC–021–1 ensures that data is 

supplied to support the regional UVLS 

database by requiring the transmission 

owner and distribution provider to 

supply data related to its system and 

other related protection schemes to its 

regional reliability organization’s data 

base. 

ii. Staff Preliminary Assessment 

943. No substantive issues were 

identified for the proposed Reliability 

Standard PRC–021–1. 

iii. Comments 

944. CenterPoint seems to promote 

eliminating this Reliability Standard as 

stated previously in PRC–010–0. 

iv. Commission Proposal 

945. The Commission believes that 

Reliability Standards for UVLS are 

required in the same manner as 

Reliability Standards for line and 

generation protection, UFLS or special 

protection systems since all of them are 

required to ensure reliable system 

operations. Therefore, we disagree with 

CenterPoint’s view that UVLS 

Reliability Standards are not needed. 

946. The Commission proposes to 

approve, as mandatory and enforceable, 

Reliability Standard PRC–021–1 as just, 

reasonable, not unduly discriminatory 

or preferential, and in the public 

interest. 

v. Under-Voltage Load Shedding 

Program Performance (PRC–022–1) 

i. NERC Proposal 

947. Proposed Reliability Standard 

PRC–022–1 requires transmission 

operators, load-serving entities, and 

distribution providers to provide 

analysis, documentation on UVLS 

operations and misoperations to the 

regional reliability organization. 

ii. Staff Preliminary Assessment 

948. No substantive issues were 

identified regarding Reliability Standard 

PRC–022–1. 

iii. Comments 

949. No comments were filed. 

iv. Commission Proposal 

950. The Commission believes that 

there are no substantive issues for this 


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297We note that NERC’s reliability functional 

model (Function Definitions and Responsible 

Entities, version 2, approved by the Board of 

Trustees Feb. 10, 2004) defines Reliability 

Authority Area, Balancing Authority Area, 

Transmission Planning Area, and Planning 

Authority Area, but does not define Transmission 

Operator Area. 

proposed Reliability Standard. 

Therefore, the Commission proposes to 

approve, as mandatory and enforceable, 

Reliability Standard PRC–022–1 as just, 

reasonable, not unduly discriminatory 

or preferential, and in the public 

interest. 

11. TOP: Transmission Operations 

a. Overview 

951. The eight proposed Transmission 

Operations (TOP) Reliability Standards 

apply to transmission operators, 

generator operators and balancing 

authorities. The goal of these Reliability 

Standards is to ensure that the 

transmission system is operated within 

operating limits. Specifically, these 

Reliability Standards cover the 

responsibilities and decision-making 

authority for reliable operations, 

requirements for operations planning, 

planned outage coordination, real-time 

operations, provision of operating data, 

monitoring of system conditions, 

reporting of operating limit violations 

and actions to mitigate such violations. 

The Interconnection Reliability 

Operations and Coordination (IRO) 

group of Reliability Standards 

complement these proposed TOP 

Reliability Standards. 

b. Reliability Responsibilities and 

Authorities (TOP–001–0) 

i. NERC Proposal 

952. TOP–001–0 requires that: (a) The 

transmission operating personnel must 

have the authority to direct actions in 

real-time; (b) the transmission operator, 

balancing authority, and generator 

operator must follow the directives of 

their reliability coordinator; and (c) the 

balancing authority and generator 

operator must follow the directives of 

the transmission operator. In addition, 

the proposed Reliability Standard 

requires the transmission operator, 

balancing authority, generator operator, 

distribution provider and load-serving 

entity to take emergency actions when 

directed to do so in order to keep the 

transmission system intact. The 

reliability goal of TOP–001–1 is to: (1) 

Ensure that system operators have the 

authority to take actions and direct 

others to take action to maintain BulkPower System facilities within limits; 

(2) protect transmission, generation, 

distribution, and customer equipment; 

and (3) prevent cascading failures of the 

interconnected grid. Further, NERC 

indicates that it plans to modify TOP–

001–0 to address the lack of Measures 

and Levels of Non-Compliance. 

ii. Staff Preliminary Assessment 

953. The Staff Preliminary 

Assessment did not identify any 

substantive issues regarding TOP–001–

0, other than noting that it does not 

contain Measures or Levels of NonCompliance. 

iii. Comments 

954. MEAG states that, under 

Requirement R2 a transmission operator 

must take immediate actions to shed 

load to alleviate an emergency, and 

Requirement R4 obligates distribution 

providers and load-serving entities to do 

the same. MEAG contends that 

Requirement R4 should be eliminated 

because, to the extent that a 

transmission owner relies on a 

distribution provider or load serving 

entity to respond to a system 

emergency, including load shedding, 

this should be done through a formal 

agreement with specific protocols that 

all parties have agreed to follow. MEAG 

states that, as long as Requirement R4 is 

included in the Reliability Standard, an 

entity may make faulty assumptions 

about the emergency response of 

another entity. 

955. MRO states that Requirements 

7.1, 7.2, and 7.3, which relate to 

coordination when a generation or 

transmission facility is removed from 

service, appear to be instructions rather 

than requirements. It asks the 

Commission to revise or remove these 

Requirements. 

iv. Commission Proposal 

956. The Commission proposes to 

approve TOP–001–0 as mandatory and 

enforceable. In addition, we propose to 

direct that NERC develop modifications 

to the Reliability Standard, as discussed 

below. 

957. Requirement R1 of TOP–001–0 

states that a transmission operator must 

have the responsibility and clear 

decision-making authority ‘‘to take 

whatever actions are needed to ensure 

the reliability of its area.’’ Neither the 

Reliability Standard nor the NERC 

glossary explains what is meant by a 

transmission operator’s ‘‘area.’’ We 

interpret the term to mean the area in 

which the transmission facilities under 

the transmission operator’s control are 

located.297

958. We are not persuaded by MEAG’s 

suggestion to eliminate Requirement R4 

and utilize a formal agreement to 

determine the response of a distribution 

provider or load serving entity to a 

system emergency. As set forth in 

Requirement R1, each transmission 

operator must have the responsibility 

and corresponding decision-making 

authority to take ‘‘whatever actions are 

needed’’ to ensure reliability in an 

emergency. This includes the 

curtailment of transmission service and 

load shedding. Eliminating the general 

obligation set forth in Requirement R4 

that a distribution provider or load 

serving entity must ‘‘comply with all 

reliability directives of the transmission 

operator * * * unless such action 

would violate safety, equipment, 

regulatory or statutory requirements,’’

and replacing it with formal agreements 

would result not only in regional 

differences but differences in the ability 

of a transmission operator to respond to 

an emergency on a system-by-system 

and contract-by-contract basis. Rather 

than enhancing reliability, we believe 

that such latitude could result in the 

deterioration of Bulk-Power System 

reliability. 

959. MRO claims that Requirements 

R7.1, R7.2, and R7.3 appear to be 

instructions rather than requirements. 

Requirement R7 provides that each 

transmission operator and generator 

operator shall not remove facilities from 

service if removing those facilities 

would burden a neighboring system 

unless certain events occur that are 

delineated in Requirements R7.1, R7.2 

and R7.3. While MRO does not explain 

what it considers to be the difference 

between an instruction and a 

requirement, we interpret that, read 

together as a whole Requirement R7 

articulates binding obligations on a 

transmission operator and is properly 

characterized as a requirement. 

960. As mentioned above, TOP–001–

0 does not contain Measures or Levels 

of Non-Compliance. However, we 

believe that the Requirements set forth 

in TOP–001–0 are sufficiently clear and 

objective to provide guidance for 

compliance. Moreover, TOP–001–0 

serves the vital purpose of ensuring that 

transmission operators and others have 

clear decision-making authority to take 

appropriate actions or direct the actions 

of others to return the transmission 

system to normal conditions during an 

emergency. 

961. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 


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298On August 28, 2006, NERC submitted TOP–

002–1 for approval, which replaces TOP–002–0. 

TOP–002–1 simply deletes the Requirement R14.2, 

which required automatic voltage regulators. 

According to NERC, the deleted requirement is now 

included in the recently revised VAR–001–1 and is 

therefore unnecessary in TOP–002–1. 

299Although the Staff Preliminary Assessment 

addresses concerns regarding the TOP–002–0, many 

of these same concerns apply to TOP–002–1 as 

well. 

300See proposed Reliability Standard IRO–005–1. 

301System operators should operate the BulkPower System such that firm load will continue to 

be supplied after a contingency. The operations 

planning function should provide the system 

operators with information (control actions) 

concerning what actions may be needed to avoid 

cascading after the worst contingency has occurred. 

302Failure of an electrical component includes 

relay and control system failures, which may 

remove more than one element. 

approve Reliability Standard TOP–001–

0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to TOP–001–0 that includes Measures 

and Levels of Non-Compliance. 

c. Normal Operations Planning (TOP–

002–1) 

i. NERC Proposal 

962. TOP–002–1 requires 

transmission operators and balancing 

authorities to look ahead to the next 

hour, day and season, and have 

operating plans ready to meet any 

unscheduled changes in system 

configuration and generation dispatch. 

The proposed Reliability Standard 

covers a broad array of matters, 

including: (1) Procedures to mitigate 

System Operating Limit (SOL) and 

Interconnection Reliability Operating 

Limit (IROL) violations; (2) verification 

of real and reactive reserve capabilities; 

(3) communications; (4) modeling; (5) 

information exchange; and (6) data 

confidentiality restrictions. The goal of 

TOP–002–1 is to ensure that resources 

and operational plans are in place to 

enable system operators to maintain the 

Bulk-Power System in a reliable state. 

Further, NERC indicates that it plans to 

modify the Reliability Standard to 

address the lack of Measures and Levels 

of Non-Compliance. 

963. Two Requirements of particular 

note are R7 and R14. Requirement R7 of 

TOP–002–1 provides that each 

balancing authority shall plan to meet 

capacity and energy reserve 

requirements, including being able to 

deliver power in the case of any single 

contingency. Requirement R14 directs 

each generator operator to notify its 

balancing authority and transmission 

operator of changes in: (1) real and 

reactive power output capabilities.298

ii. Staff Preliminary Assessment 

964. The Staff Preliminary 

Assessment noted that Requirement R7 

specifies that capacity and energy 

reserves must be deliverable to local 

areas in case of a single contingency.299

Other Reliability Standards require that 

the system operate in a manner that 

allows it to be returned to a stable state 

within 30 minutes after a contingency 

occurs with the capacity to withstand 

another contingency without 

cascading.300 In contrast, the Reliability 

Standard does not require the next-day 

planning analysis to identify control 

actions that are needed to bring the 

system back to a stable state within 30 

minutes after a contingency occurs with 

the capacity to withstand another 

contingency without cascading.301 The 

Staff Preliminary Assessment noted that 

this may present a potential 

vulnerability as operators may not be 

aware of available control actions or 

may not have control actions, other than 

firm load shedding, available to adjust 

the system after a first contingency 

occurs. 

965. The Staff Preliminary 

Assessment also pointed out a potential 

gap in the analysis of and planning for 

contingencies. This Reliability Standard 

refers to a ‘‘single contingency’’ and is 

defined as the loss of a transformer, 

transmission circuit, single DC pole or 

generator, but does not include the 

assessment of outages of multiple 

elements that would be removed from 

service as a result of a single component 

failure.302 Thus, the loss of a single 

relay, breaker, control system 

component or transmission tower may 

affect multiple system elements. 

However, these circumstances are not 

required to be considered in the analysis 

of, and planning for, contingencies. 

966. Finally, the Staff Preliminary 

Assessment stated that, although 

Requirement R14 of the Reliability 

Standard recognizes the need to 

communicate changes in generator ‘‘real 

and reactive capability as well as the 

status of automatic voltage regulators,’’

it does not include a similar 

requirement to communicate changes in 

the status of power system stabilizers. 

iii. Comments 

967. NERC states that, contrary to the 

Staff Preliminary Assessment, 

Requirement R11 of the Reliability 

Standard does require next-day studies. 

NERC further states that next-day 

analysis should not have to identify 

control actions. Rather, it is intended to 

provide a look into the next day so that 

the transmission operator can then 

develop operating strategies. 

Appropriate real-time control actions 

may diverge from those identified by a 

transmission operator’s previous-day 

studies, and therefore, according to 

NERC, the Reliability Standard does not 

identify control actions to be followed 

by the operators. Similarly, NERC states 

that it is impractical to identify and 

study all possibilities in next-day 

analysis. 

968. Regarding staff’s concern 

regarding the lack of analysis of 

multiple system elements, NERC 

responds that Requirement R6 instructs 

each balancing authority and 

transmission operator to meet NERC, 

regional reliability organization, 

subregional and local reliability 

requirements. Thus, the Reliability 

Standard recognizes that some 

situations require operating in a manner 

that provides protection against the 

failure of multiple system elements. 

However, NERC adds that it will review 

Requirement R7 to ensure that reserves 

can be deployed to meet the 

requirements of the disturbance control 

Reliability Standard, BAL–002–0. 

969. MidAmerican and MRO point 

out that the availability for the sale of 

short-term firm transmission service is 

based on calculations taking into 

account single element events. Any 

effort to define single contingencies in 

terms of multiple elements will result in 

a significant decrease in available 

transmission capability; resulting in a 

negative impact on competition in the 

wholesale market. MRO also maintains 

that technology does not allow for 

comprehensive assessment of outages of 

multiple elements due to a single 

component failure. 

970. Regarding the Staff Preliminary 

Assessment’s statement that the status 

of power system stabilizers should be 

communicated in TOP–002–0, NERC 

notes that this is covered by a separate 

Reliability Standard, VAR–001–0, under 

Requirements R4 and R9. 

971. Requirements R3 and R4 provide 

that each load serving entity and 

generator operator shall coordinate its 

operations with its balancing authority 

and transmission service provider, 

‘‘where confidentiality agreements 

allow.’’ Alcoa objects to this phrase, 

contending that a load serving entity or 

generator operator may evade these 

coordination requirements by simply 

not executing a confidentiality 

agreement. 

iv. Commission Proposal 

972. The Commission proposes to 

approve TOP–002–1 as mandatory and 

enforceable. In addition, we propose to 

direct that NERC develop modifications 


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303NERC glossary at 3. 

304See R7 of TOP–002–0. 

to the Reliability Standard, as discussed 

below. 

973. While Requirement R11 requires 

next day studies, as mentioned above, 

TOP–002–1 does not require the nextday planning analysis to identify control 

actions that are needed to bring the 

system back to a stable state within 30 

minutes after a contingency occurs with 

the capacity to withstand another 

contingency without cascading. 

Operators should have at their disposal 

and be aware of control actions to adjust 

the Bulk-Power System within 30 

minutes to avoid cascading after the 

worst contingency has occurred. Such 

control actions include reconfiguring 

the transmission system, recalling 

facilities from planned outages, and 

ensuring availability of generation and 

reactive power resources. These control 

actions should be determined as part of 

day ahead operations planning. While 

NERC suggests that it would be 

impractical to study every possibility to 

identify control actions, we believe that 

in fact only a limited number of critical 

facilities associated with IROLs would 

require analysis to identify control 

actions aimed at avoiding cascading 

outages. Accordingly, we propose 

directing that NERC modify TOP–002–

1 to include identification of control 

actions that can be implemented within 

30 minutes as a part of the next-day 

analysis and communication of these 

control actions to system operators. 

974. NERC’s glossary defines 

‘‘contingency’’ as ‘‘the unexpected 

failure or outage of a system component, 

such as a generator, transmission line, 

circuit breaker, switch or other electric 

element.’’ 303 Requirement R7 of TOP–

002–1 requires that each balancing 

authority plan to meet capacity and 

energy reserve requirements, including 

deliverability/capability for any single 

contingency.304 Although the NERC 

glossary defines ‘‘contingency,’’ we are 

concerned that the phrase ‘‘single 

contingency’’ is open to interpretation 

and that deliverability is not defined. 

The Commission proposes to interpret 

contingency as discussed in the 

transmission planning chapter and to 

interpret deliverability as the ability to 

deliver the output from generation 

resources to firm load without any 

reliability criteria violations for 

plausible generation dispatches. 

975. The Staff Preliminary 

Assessment suggested that TOP–002–0 

should include a requirement to 

communicate a change in the status of 

power system stabilizers. In response, 

NERC comments that this is addressed 

in VAR–001–0, which requires that each 

generator operator provide information 

to its transmission operator on the status 

of generation reactive power resources 

including the status of power system 

stabilizers. We agree with NERC and do 

not propose any changes in this regard. 

976. We share Alcoa’s concern 

regarding the possible interference with 

the coordination demanded in 

Requirements R3 and R4 if that 

coordination is dependent upon the 

execution of a confidentiality 

agreement. Generally, the effectiveness 

of a Reliability Standard should not be 

predicated upon the existence of a 

confidentiality agreement or any other 

private agreement. If some Reliability 

Standards require a confidentiality 

agreement, the Commission believes 

that the matter should be addressed 

separately and globally so that it applies 

to all Reliability Standards rather than 

designating that a specific requirement 

is subject to existence of a 

confidentiality agreement. Accordingly, 

we propose to direct that NERC modify 

Requirements R3 and R4 by deleting 

references to confidentiality agreements. 

Rather, NERC should address the issue 

separately to ensure that necessary 

protections are in place related to 

confidential information. 

977. While we have identified 

concerns with regard to TOP–002–1, we 

believe that the proposed Reliability 

Standard serves an important purpose 

in ensuring that resources and 

operational plans are in place to enable 

system operators to maintain the BulkPower System in a reliable state. As 

mentioned above, TOP–002–1 does not 

contain Measures or Levels of NonCompliance. The Commission believes 

that it is important for NERC to provide 

Measures and Levels of NonCompliance. Nonetheless, the 

Requirements set forth in TOP–002–1 

are sufficiently clear and objective to 

provide guidance for compliance. 

978. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard TOP–002–

1 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to TOP–002–1 that: (1) Includes 

Measures and Levels of Noncompliance; (2) deletes references to 

confidentiality agreements in 

Requirements R3 and R4, but addresses 

the issue separately to ensure that 

necessary protections are in place 

related to confidential information; and 

(3) requires the next-day analysis for all 

IROLs to identify and communicate 

control actions to system operators that 

can be implemented within 30 minutes 

following a contingency to return the 

system to a reliable operating state and 

prevent cascading outages. 

979. Regarding outages of multiple 

elements caused by the failure of single 

element, NERC comments that it will 

review the Requirement R7 to ensure 

that reserves can be deployed to meet its 

disturbance control Reliability 

Standard, BAL–002–0. However, 

MidAmerican and MRO assert that any 

effort to define single contingencies in 

terms of multiple elements will result in 

a significant decrease in available 

transmission capability (ATC) and will, 

therefore, have a negative impact on 

competition in the wholesale market. As 

discussed in the TPL Chapter, the 

simulations used for either planning or 

calculating available transmission 

capability must be consistent with the 

number of elements that will be 

removed from service in the physical 

system. 

d. Planned Outage Coordination (TOP–

003–0) 

i. NERC Proposal 

980. TOP–003–0 requires 

transmission operators, generator 

operators and balancing authorities to 

coordinate transmission and generator 

maintenance schedules. Where a 

conflict in maintenance schedule arises, 

the reliability coordinator is authorized 

to resolve the conflict. 

ii. Staff Preliminary Assessment 

981. TOP–003–0 requires that each 

transmission provider must provide 

outage information on transmission 

lines and transformers greater than 100 

kV and each generator operator must 

provide outage information for 

generators greater than 50 MW. The 

Staff Preliminary Assessment observed 

that these Requirements assume that 

only systems greater than 100 kV or 

generators above 50 MW will affect the 

reliability of interconnected operations. 

Staff stated that, although this 

assumption may be true in most 

instances, a justification should be 

provided for the threshold of 100 kV for 

transmission and 50 MW for generation 

outages. Staff further stated that the loss 

of transmission lines or transformers 

less than 100 kV and generators less 

than 50 MW may affect system stability 

in load pockets or remote sections of the 

grid depending upon system conditions. 


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982. The Staff Preliminary 

Assessment noted that, while a related 

Reliability Standard, TOP–002–0, 

requires the coordination of planned 

outages on a current-day, next-day and 

seasonal basis for normal operations 

planning, TOP–003–0 only requires 

next-day reporting for planned outages 

and does not include longer range 

planning. The Staff Preliminary 

Assessment expressed the concern that 

this gap may affect reliability because 

proper assessment of the system and 

coordination between generation and 

transmission outages may not occur. 

Moreover, the lack of information may 

also have an impact on TTC/ATC 

calculations. Staff also noted that the 

Levels of Non-Compliance are based on 

designating a process for providing 

information, but they do not contain 

requirements for the actual provision of 

that information 

iii. Comments 

983. NERC comments that the 100 kV 

and 50 MW thresholds may need to be 

reviewed over time. However, NERC 

believes that the Commission should 

approve TOP–003–0 as proposed 

because transmission operators, 

balancing authorities and reliability 

coordinators should decide which 

facilities to include in their operations 

planning assessments. 

984. Allegheny agrees that the 100 kV 

and 50 MW thresholds may not be 

appropriate in all situations. However, 

Allegheny points out that transmission 

operators and reliability coordinators 

typically coordinate all planned outages 

that may have a significant impact on 

interconnected operations. Rather than 

lowering the thresholds to include all 

facilities, Allegheny suggests that 

transmission operators and reliability 

coordinators identify significant 

facilities through system studies. 

MidAmerican and MRO recommend 

that the thresholds should not be 

lowered because this will slow down 

the coordination of outages for higher 

voltage facilities and larger generators. 

985. ISO/RTO Council believes that 

any size or voltage threshold must be 

justified based on its potential impact to 

reliability. In addressing lower voltage 

levels, ReliabilityFirst comments that 

system operators typically evaluate and 

monitor lower voltages levels to ensure 

they do not impact the reliability of the 

Bulk Electric System. However, 

ReliabilityFirst believes that the 

assessment and monitoring of these 

lower voltage levels should be included 

in the Reliability Standard for 

uniformity and consistency. 

iv. Commission Proposal 

986. The Commission notes that 

outage information is important to both 

reliable operation and to the calculation 

of available transfer capability. This 

information is also needed to assure 

coordination of outages long before next 

day or current day operations. The 

Commission proposed that applicable 

scheduled outages be communicated to 

impacted transmission operators and 

reliability coordinators with sufficient 

lead time to coordinate outages. The 

Commission requests industry input on 

what constitutes sufficient lead time for 

planned outages. 

987. NERC, Allegheny, ISO/RTO 

Council, and ReliabilityFirst agree with 

the Staff Preliminary Assessment that 

the thresholds for providing outage 

information should be reviewed. While 

we agree with commenters that lowering 

the threshold might slow down the 

coordination process, we are also 

concerned that the thresholds of 100 kV 

and 50 MW may not include all 

facilities that have a significant impact 

on the operation of Bulk-Power System. 

For example, emergency operations 

would require, at a minimum, that there 

are adequate blackstart resources 

available if needed. Thus, while in the 

longer-term a review of the existing 

thresholds is appropriate, at this time, 

we propose directing NERC to modify 

TOP–003–0, Requirement R1 to provide 

that a generator operator or transmission 

operator must provide planned outage 

information for any facility above 100 

kV and 50 MW and any other facility 

below these thresholds that, in the 

opinion of the transmission operator, 

balancing authority, or reliability 

coordinator, would have a direct impact 

on the operation of Bulk-Power System. 

988. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard TOP–003–

0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to TOP–003–0 that: (1) Includes a 

requirement to communicate scheduled 

outages well in advance to ensure 

reliability and accuracy of ATC 

calculation; and (2) makes any facility 

below the thresholds that, in the 

opinion of the transmission operator, 

balancing authority, or reliability 

coordinator, will have a direct impact 

on the operation of Bulk-Power System 

subject to Requirement R1 for planned 

outage coordination. 

e. Transmission Operations (TOP–004–

0) 

i. NERC Proposal 

989. TOP–004–0 requires 

transmission operators to operate the 

transmission system within SOL and 

IROL. The ‘‘N–1’’ operating criterion for 

the transmission system is also 

established in this Reliability Standard. 

It provides that operating configurations 

for which limits have not yet been 

determined should be treated as 

emergencies. The reliability goal of 

TOP–004–0 is to maintain Bulk-Power 

System facilities within limits, thereby 

protecting transmission, generation, 

distribution and customer equipment 

and preventing cascading failures of the 

interconnected grid. Further, NERC 

indicates that it plans to modify TOP–

004–0 to address the lack of Measures 

and Levels of Non-Compliance. 

ii. Staff Preliminary Assessment 

990. The Staff Preliminary 

Assessment noted that a regional review 

of the potential impact of multiple 

outages in day-ahead operations 

planning is included in Requirement R3 

for TOP–004–0. However, staff observed 

that the conditions under which 

multiple outages can occur remain 

undefined. 

991. The proposed Reliability 

Standard requires the operation of the 

system within IROL and SOL. When the 

system enters an unknown state (i.e., 

any state for which operating limits 

have not been determined), 

Requirement R4 instructs the operator to 

‘‘restore operations to respect proven 

reliable power system limits within 30 

minutes.’’ Staff cautioned that the 

phrase ‘‘within 30 minutes’’ could be 

interpreted as a grace period. However, 

such an interpretation may not be 

consistent with the intent that, while 30 

minutes has been adopted by the 

industry as a reasonable time period, it 

is expected that corrective actions will 

be taken as soon as possible and without 

delay. 

iii. Comments 

992. NERC responds to the Staff 

Preliminary Assessment, stating that the 

specification of 30 minutes is not meant 

to suggest that system operators should 

take as long as 30 minutes. Rather, it is 

meant to provide system operators with 

the flexibility to respond to emergencies 

in the manner they determine is best, 

even if it is not the fastest alternative. 

In addition, NERC asserts that: (1) 30 

minutes is based on decades of system 


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305The issue of drifting in and out of IROL limits 

is discussed in the IRO chapter and provides 

specifics of proposed survey in greater detail. See 

discussion for IRO–005–1. 

306NERC states that, effective November 1, 2006, 

proposed Reliability Standard TOP–005–1 will 

replace existing Reliability Standard, TOP–005–0. 

307 Interregional Security Network is a data 

exchange system that facilitates the exchange of 

real-time and other operational data among 

reliability coordinators, balancing authorities, and 

transmission operators to help ensure reliable 

electric power system operations. 

operations experience; (2) system 

operators do not treat ‘‘within 30 

minutes’’ as a grace period and it has 

not come across situations when system 

operators waited for 29 minutes before 

taking an appropriate action; and (3) 

although a system is not allowed to drift 

in and out of a secure state, sometimes 

it enters an unknown state that was not 

studied and it is appropriate to allow 

the system operators a reasonable 

amount of time to bring the system back 

to the normal state. 

993. MidAmerican comments that, if 

IROL cannot be exceeded even for one 

minute, operators will need to maintain 

a margin at significant cost and there 

will be a resulting negative impact on 

competition. 

iv. Commission Proposal 

994. The Commission proposes to 

approve TOP–004–0 as mandatory and 

enforceable. In addition, we propose to 

direct that NERC develop modifications 

to the Reliability Standard as discussed 

below. 

995. Requirement R4 of TOP–004–0 

provides that, if a transmission operator 

enters an unknown state, i.e., any state 

for which valid operating limits have 

not been determined, operations should 

be restored to respect proven reliable 

power system limits within 30 minutes. 

We agree with NERC that 30 minutes is 

a reasonable period within which 

operators should return the system to a 

reliable operating state. However, as 

stated in the Staff Preliminary 

Assessment it may be interpreted as a 

grace period to the detriment of 

reliability and therefore the Commission 

proposes that Requirement R4 be 

modified to state that the system should 

be restored to respect proven reliable 

power system limits as soon as possible 

and no longer than 30 minutes. 

996. With respect to NERC’s comment 

that the system is not allowed to drift in 

and out of a reliable state, the 

Commission is concerned that neither 

TOP–004–0 nor the IRO Reliability 

Standards address this issue and that 

some entities may be engaging in this 

practice to the detriment of reliability. 

The Commission proposes to require 

that NERC survey and report the 

operating practices and actual 

experiences surrounding drifting into 

and out of IROL limits.305

997. The Staff Preliminary 

Assessment noted that while 

Requirement R3 states that, when 

practical, the system must be operated 

to respect multiple outages as specified 

by the regional reliability organization 

policy it does not define conditions 

under which such multiple outages 

must be considered. We interpret such 

conditions to include high risk 

conditions such as hurricanes, ice 

storms or periods of high solar magnetic 

disturbances during which the 

probability of a multiple outage 

approaches that of single element 

outage. The Commission proposes that 

Requirement R3 be modified to define 

conditions under which the system 

must be operated to respect multiple 

outages. 

998. The Commission notes that TOP–

004–0 does not contain Measures or 

Levels of Non-Compliance. TOP–004–0 

serves an important reliability goal of 

ensuring that the Bulk-Power System 

facilities are operated within safe limits, 

thereby protecting transmission, 

generation, distribution and customer 

equipment and preventing cascading 

failures. The Commission believes that 

it is important for NERC to provide 

Measures and Levels of NonCompliance elements for this proposed 

Reliability Standard. Nonetheless, the 

proposed Requirements set forth in 

TOP–004–0 are sufficiently clear and 

objective to provide guidance for 

compliance. 

999. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard TOP–004–

0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to TOP–004–0 that (1) includes 

Measures and Levels of NonCompliance; (2) clarifies that the 30 

minute response time is not a grace 

period; and (3) defines in Requirement 

R3, high risk conditions under which 

the system must be operated to respect 

multiple outages. In addition, we 

propose to direct that the ERO perform 

a survey of the prevailing operating 

practices and actual operating 

experiences surrounding drifting in and 

out of IROL limits. As part of the survey, 

we would require all reliability 

coordinators to report any violations of 

IROLs, their causes, the date and time 

of the violation, and the duration in 

which actual operations exceeded IROL 

to the ERO on a monthly basis for one 

year beginning two months after the 

effective date of the final rule. 

f. Operational Reliability Information 

(TOP–005–1) 

i. NERC Proposal 

1000. TOP–005–1 ensures that 

reliability information is shared among 

reliability coordinators, transmission 

operators and balancing authorities.306

It requires the transmission operator and 

the balancing authority to provide 

operating data to each other and to the 

reliability coordinator and provides a 

list of typical operating data that must 

be provided. TOP–005–1 also provides 

that, as a condition of receiving data 

from the NERC’s Interregional Security 

Network,307 each data recipient must 

execute a confidentiality agreement. 

ii. Staff Preliminary Assessment 

1001. Staff noted that Attachment 1 of 

TOP–005–1 entitled, ‘‘Electric System 

Reliability Data,’’ which specifies the 

types of operating data that reliability 

coordinators, balancing authorities and 

transmission operators are expected to 

share, does not include the operational 

status of special protection systems and 

power system stabilizers. The Staff 

Preliminary Assessment raised the 

concern that the absence of this 

information could lead to an erroneous 

assessment of system capability. 

iii. Comments 

1002. NERC agrees with Commission 

Staff that Attachment 1 of TOP–005–1 

should be modified to include special 

protection systems and power system 

stabilizers. 

1003. ReliabilityFirst states that 

information pertaining to the special 

protection systems is included in 

Attachment 1, section 2.6, which refers 

to ‘‘new or degraded special protection 

systems.’’

1004. ISO/RTO Council argues that 

the Commission should direct NERC to 

eliminate the requirement that each data 

recipient sign a confidentiality 

agreement. It claims that the 

requirement to sign a confidentiality 

agreement is an administrative matter, 

not a reliability issue. 

iv. Commission Proposal 

1005. ReliabilityFirst points out that 

the operational information pertaining 

to the ‘‘new or degraded special 

protection systems’’ is included in 

Attachment 1. However, a special 


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308See Blackout Report at 159. 309 Id. at 108. 

protection system may be turned on or 

off and not be degraded. Awareness of 

the operational state is different from 

knowing that degradation has occurred. 

In addition, Attachment 1 does not 

contain information about power system 

stabilizers. While Attachment 1 contains 

a large amount of data pertaining to 

Bulk-Power System reliability, inclusion 

of information about the operation 

status of special protection systems will 

provide a more comprehensive list. We 

agree with NERC and propose that 

Attachment 1 be modified to include the 

status of special protection systems and 

power system stabilizers. 

1006. We agree with ISO/RTO 

Council that the reference to execution 

of confidentiality agreement should be 

deleted from the Reliability Standard 

and NERC should address the issue 

separately and globally as we indicate 

above in our discussion of TOP–002–1. 

1007. TOP–005–1 furthers an 

important reliability goal of ensuring 

that reliability entities have the 

operating data needed to monitor 

system conditions within their area. 

Further, the Requirements set forth in 

TOP–005–1 are sufficiently clear and 

objective to provide guidance for 

compliance. Accordingly, giving due 

weight to the technical expertise of the 

ERO and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard TOP–005–

1 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to TOP–005–1 that: (1) Includes 

information about the operational status 

of special protection systems and power 

system stabilizers in Attachment 1; and 

(2) deletes references to confidentiality 

agreements, but addresses the issue 

separately to ensure that necessary 

protections are in place related to 

confidential information. 

g. Monitoring System Conditions (TOP–

006–0) 

i. NERC Proposal 

1008. TOP–006–0 requires that 

operating personnel continuously 

monitor essential Bulk-Power System 

parameters such as line flows, circuit 

breaker status, generator resources, 

relays, weather forecasts and frequency 

to ensure that the facilities do not 

exceed their operating limits. NERC 

indicates that it plans to modify TOP–

006–0 to address the lack of Measures 

and Levels of Non-Compliance. 

ii. Staff Preliminary Assessment 

1009. The Staff Preliminary 

Assessment noted that, while TOP–006–

0 identifies data requirements it does 

not identify any minimum acceptable 

tools and capabilities to turn the data 

into information to aid in situational 

awareness. Staff explained that 

reliability coordinators, transmission 

operators and balancing authorities 

must be aware of the status of their 

respective systems, and such situational 

awareness cannot be obtained by 

viewing massive amounts of raw data. 

iii. Comments 

1010. NERC agrees with the Staff 

Preliminary Assessment that situational 

awareness is ‘‘key’’ to operating an 

interconnected electric system reliably 

and that data collection is only one 

component of a successful situational 

awareness strategy. NERC, however, 

states that whether a Reliability 

Standard should specify how data 

should be analyzed and presented to the 

system operator or reliability 

coordinator requires further discussion, 

including discussions with vendors who 

supply situational awareness and 

visualization tools. 

1011. ReliabilityFirst comments that 

due to the variety of equipment used to 

manage the Bulk-Electric System, it is 

impractical to specify the type of 

software and processes acceptable for 

monitoring. 

1012. MRO states that Requirement 

R3, which requires an applicable entity 

to provide ‘‘appropriate technical 

information’’ concerning protective 

relays, should be revised to clarify the 

phrase, ‘‘appropriate technical 

information.’’

iv. Commission Proposal 

1013. The Commission proposes to 

approve TOP–006–0 as mandatory and 

enforceable. In addition, we propose to 

direct that NERC develop modifications 

to the Reliability Standard, as discussed 

below. 

1014. The Blackout Report states that 

‘‘a principal cause of the blackout was 

a lack of situational awareness, which 

was in turn a result of inadequate tools 

and back-up capabilities.’’ 308 In 

addition, in reviewing common factors 

between the August 2003 blackout and 

other major outages the Blackout Report 

states ‘‘power system data may be 

available but not be presented to 

operators or coordinators as information 

they can use in making appropriate 

decisions.’’ 309 While TOP–006–0 

requires that a significant amount of 

data be provided to operating personnel, 

we agree with NERC that this is only 

one component of a successful 

situational awareness strategy. The data 

must be converted into information that 

operators can use to assess the state of 

the system and its vulnerability, should 

a contingency occur, and take 

appropriate actions to maintain a 

reliable system. We note that the 

Requirement R7 of Reliability Standard 

IRO–002–0 requires that reliability 

coordinators have adequate tools such 

as state estimation, pre and post 

contingency analysis capabilities and 

wide area overview displays. We believe 

that similar tools should be made 

available to transmission providers and 

balancing authorities and propose that 

the ERO add a new Requirement in this 

Reliability Standard to provide adequate 

tools to transmission operators and 

balancing authorities, which will 

provide them situational awareness. 

1015. Although we agree with NERC 

that further discussions may be needed 

with vendors who supply situational 

awareness and visualization tools, 

modification of TOP–006–0 should not 

have to wait for those discussions to 

occur. A variety of off-the-shelf tools are 

currently available from vendors and in 

use across the industry. At a 

Commission sponsored technical 

conference on July 14, 2004, staff 

presented its views on minimum 

requirements and best practices for 

reliability tools for the purpose of 

initiating discussions on what these 

minimum reliability capabilities ought 

to be. We believe that identification of 

the types of tools and what they should 

minimally accomplish would improve 

the proposed Reliability Standard. 

Entities that must comply with TOP–

006–0 could choose among the available 

software tools that accomplish the 

desired goal or meet the Requirement 

set forth in the Reliability Standard. 

Accordingly, we propose to direct NERC 

to modify TOP–006–0 to include a 

requirement for a minimum set of tools 

for transmission operators and 

balancing authorities that will aid in 

situational awareness. 

1016. We agree with MRO that the 

phrase ‘‘appropriate technical 

information’’ is open to interpretation 

and propose to direct that NERC modify 

TOP–006–0, Requirement R3, to identify 

the specific type of technical 

information concerning protective 

relays that should be provided. 

1017. TOP–006–0 serves an important 

reliability goal of requiring monitoring 


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310Reliability Standard TOP–007–0, Requirement 

R2. 

of essential Bulk-Power System 

parameters such as the status of power 

system elements, real and reactive 

power flows, voltages and frequency to 

ensure that the system and its 

equipment are operated in a reliable and 

safe manner. The Commission believes 

that it is important for NERC to provide 

Measures and Levels of Non-compliance 

for this proposed Reliability Standard. 

Nonetheless, the proposed 

Requirements set forth in TOP–006–0 

are sufficiently clear and objective to 

provide guidance for compliance. 

1018. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO, and that it will improve the 

reliability of the nation’s Bulk-Power 

System the Commission proposes to 

approve Reliability Standard TOP–006–

0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to TOP–006–0 that: (1) Includes 

Measures and Levels of Non-compliance 

elements; (2) includes a new 

requirement related to the provision of 

a minimum set of analysis tools that 

will aid in situational awareness; and 

(3) clarifies the meaning of ‘‘appropriate 

technical information’’ concerning 

protective relays. 

h. Reporting SOL and IROL Violations 

(TOP–007–0) 

i. NERC Proposal 

1019. TOP–007–0 requires that 

violations of SOL and IROL are 

promptly reported to the reliability 

coordinator so that it can direct 

corrective action and inform other 

affected systems. It also requires a 

transmission operator to mitigate an 

IROL violation as soon as possible but 

no longer than 30 minutes. A 

transmission operator must take ‘‘all 

appropriate actions up to and including 

shedding firm load’’ to return its system 

to a stable state within IROL. Finally, it 

requires that the reliability coordinator 

take action to mitigate an SOL or IROL 

violation if the transmission operator’s 

actions are not effective. 

ii. Staff Preliminary Assessment 

1020. As indicated above, TOP–007–

0 requires that, ‘‘[f]ollowing a 

[c]ontingency or other event that results 

in an IROL violation, the transmission 

operator shall return its transmission 

system to within IROL as soon as 

possible, but not longer than 30 

minutes.’’310 The Staff Preliminary 

Assessment explained that the phrase 

‘‘or other event’’ in this Requirement is 

open to interpretation. One 

interpretation is that it allows IROLs to 

be exceeded under normal precontingency conditions, provided the 

system can be returned to a secure state 

within 30 minutes. Another, more 

conservative, interpretation is that the 

Requirement does not allow IROLs to be 

exceeded under normal pre-contingency 

conditions, and that after a contingency 

occurs the system must be returned to 

a secure condition as soon as possible 

and no later than 30 minutes. The Staff 

Preliminary Assessment cautioned that, 

if the system is operated in a less 

conservative manner during the period 

where IROL is exceeded, even a single 

system contingency could cause 

instability, uncontrolled separation, and 

even a cascading blackout. 

iii. Comments 

1021. NERC states that SOL and IROL 

need better definition, also noting that 

SOL and IROL are operating states that 

system operators must move away from 

as quickly as possible. It will consider 

revising the standard to clarify that a 

contingency is not required to violate 

the SOL and IROL limits. NERC notes 

that it has commissioned an Operating 

Limit Definition Task Force to work on 

this matter and the Task Force is 

expected to submit its recommendation 

by the end of 2006. 

1022. Also seeking more definition 

and detail on SOL and IROL, 

ReliabilityFirst urges the acceleration of 

standards now being developed to 

clarify SOL and IROL. However, it adds 

that it would be impractical to identify 

and study all possibilities for alleviating 

SOL and IROL. 

1023. ISO/RTO Council agrees with 

the Staff Preliminary Assessment that 

this Reliability Standard is open to 

interpretation. However, ISO/RTO 

Council states that it is appropriate to 

give system operators discretion in 

making real-time system operating 

decisions. It comments that a more 

prescriptive standard would unduly 

restrict system operators and the nature 

of real-time operations requires giving 

these entities some leeway. Thus, the 

ISO/RTO Council recommends that the 

Commission approve TOP–007–0 in its 

present form. 

1024. MRO recommends that an IROL 

violation exceeding 30 minutes be 

reported to NERC within 48 hours rather 

than the 72 hours allowed under the 

compliance section of this Reliability 

Standard. 

iv. Commission Proposal 

1025. As noted in our discussion in 

IRO–005 and TOP–004, the Commission 

is concerned about systems drifting in 

and out of SOL and IROL violations. 

One source of justification for that 

practice is the term ‘‘other event.’’ We 

agree with NERC that SOL and IROL 

need better definitions and TOP–007–0 

could be improved by making the 

requirements clearer. Our proposal for a 

survey in IRO–005 and TOP–004 to 

collect data will give us more 

information about the extent of the 

problem with regard to drifting in and 

out of SOL and IROL violations. 

1026. Regarding MRO’s 

recommendation that IROL violations 

exceeding 30 minutes be reported to 

NERC within 48 hours, we will leave 

this determination to NERC because we 

consider this to be a matter of 

administrative convenience. 

1027. TOP–007–0 serves an important 

reliability goal of ensuring that when 

critical limits are violated, the violations 

are reported and appropriate actions 

taken to avoid any cascading outages. 

The Commission believes that it is 

important that NERC address the 

ambiguity regarding IROL violations, 

discussed above. Nonetheless, the 

proposed Requirements set forth in 

TOP–007–0 are sufficiently clear and 

objective to provide guidance for 

compliance. 

1028. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission believes that 

Reliability Standard TOP–007–0 is just, 

reasonable, not unduly discriminatory 

or preferential, and in the public 

interest; and proposes to approve it as 

mandatory and enforceable. 

1029. The Commission solicits 

comment on potentially overlapping 

matters addressed in Reliability 

Standards TOP–007–0 and TOP–008–0. 

The title and the purpose of TOP–007–

0 state that it ensures that SOL and 

IROL violations are being reported, but 

we believe that only Requirement R1 

relates to reporting. The remaining 

requirements in TOP–007–0, R2, R3 and 

R4, go beyond reporting of violations 

and provide that the transmission 

operator will take actions on its own or 

as directed by the reliability 

coordinator. We observe that proposed 

Reliability Standard TOP–008–0 

addresses the same subject. In fact, 


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311See TPL–001–0, TPL–002–0, TPL–003–0, and 

TPL–004–0. 

312See TPL–005–0 and TPL–006–0. 

313See discussion of Bulk Power System v. bulk 

electric system in section III.D.5 above. 314Staff Preliminary Assessment at 108. 

Requirement R1 of TOP–008–0 is 

similar to Requirement R3 of TOP–007–

0. It appears that both Reliability 

Standards deal with the same subject, 

but more emphasis is placed on 

reporting in TOP–007–0. If two separate 

Reliability Standards address similar 

topics, the purpose statement should 

succinctly capture the intent of each 

Reliability Standard. 

i. Response to Transmission Limit 

Violations (TOP–008–0) 

i. NERC Proposal 

1030. TOP–008–0 requires a 

transmission owner to take immediate 

steps to mitigate SOL and IROL 

violations. NERC indicates that it plans 

to modify TOP–008–0 to address the 

lack of Measures and Levels of NonCompliance. 

ii. Staff Preliminary Assessment 

1031. The Staff Preliminary 

Assessment did not identify any 

substantive issues in TOP–008–0, other 

than noting that it does not contain 

Measures or Levels of Non-Compliance. 

iii. Comments 

1032. No comments were submitted 

regarding TOP–008–0. 

iv. Commission Proposal 

1033. We observe that proposed 

Reliability Standard TOP–007–0 

addresses the same subject. 

1034. Requirements R1 through R4 

provide that the transmission operator 

shall take certain actions to mitigate the 

effects of SOL and IROL violations. No 

role is specified for the reliability 

coordinator. A reliability coordinator 

plays a key role in the reliability of the 

Bulk-Power Systems and should be 

involved in the decision-making process 

of bringing the system back within 

operating limits as soon as possible. A 

parallel Reliability Standard covering 

this subject, TOP–007–0, identifies a 

role for the reliability coordinator. The 

Commission proposes to require NERC 

to modify TOP–008–0 to apply to 

reliability coordinators. 

1035. TOP–008–0 serves an important 

reliability goal of ensuring that when 

critical limits are violated, appropriate 

actions are taken to avoid any cascading 

outages. The Commission believes that 

it is important for NERC to provide 

Measures and Levels of non-compliance 

elements for this proposed Reliability 

Standard. Nonetheless, the proposed 

Requirements set forth in TOP–008–0 

are sufficiently clear and objective to 

provide guidance for compliance. 

1036. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard TOP–008–

0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to TOP–008–0 that: (1) includes 

Measures and Levels of Non-compliance 

elements; and (2) includes reliability 

coordinators in the Applicability 

section. 

12. TPL: Transmission Planning 

a. Overview 

1037. The Transmission Planning 

(TPL) group of Reliability Standards 

consists of six Reliability Standards that 

are applicable to transmission planners, 

planning authorities and regional 

reliability organizations. These 

Reliability Standards are intended to 

ensure that the transmission system is 

planned and designed to meet an 

appropriate and specific set of reliability 

criteria. Transmission planning is a 

process that involves a number of stages 

including developing a model of the 

Bulk-Power System, using this model to 

assess the performance of the system for 

a range of operating conditions and 

contingencies, determining those 

operating conditions and contingencies 

that have an undesirable reliability 

impact, identifying the nature and the 

need for transmission upgrades, 

developing and evaluating a range of 

transmission reinforcement and upgrade 

options and selecting the preferred 

option, taking into account the time 

needed to place the facilities in service. 

The proposed TPL Reliability Standards 

address: (1) the types of simulations and 

assessments that must be performed to 

ensure that reliable systems are 

developed to meet present and future 

system needs 311 and (2) the information 

required to assess regional compliance 

with planning criteria and for selfassessment of regional reliability.312 The 

differing definitions of the Bulk-Power 

System and bulk electric system 

discussed above is central to the 

concerns raised by this group of 

Reliability Standards.313 That issue has 

important implications for the range of 

contingencies that must be evaluated 

and facilities to be simulated in the 

transmission planning process. 

1038. The TPL group of Reliability 

Standards contains a table designated 

Table 1 (Transmission System 

Standards—Normal and Emergency 

Conditions), which is a key part of this 

group of Reliability Standards. It lays 

out the system performance 

requirements for a range of 

contingencies grouped according to the 

number of elements forced out of 

service as a result of the contingency. 

For example: Category A applies to the 

normal system with no contingencies; 

Category B applies to contingencies 

resulting in the loss of a single element 

defined as a generator, transmission 

circuit, transformer, single DC pole with 

or without a fault; Category C applies to 

a contingency resulting in loss of two or 

more elements, such as any two circuits 

on a multiple circuit tower line or both 

poles of a bi-polar DC line; while 

Category D applies to extreme 

contingencies resulting in loss of 

multiple elements, such as a substation 

or all lines on a right-of-way. The 

system performance expectations for 

Category C contingencies are lower than 

those for Category B contingencies, in 

that they allow unspecified amounts of 

planned or controlled loss of demand. 

b. General Issues 

1039. Both the Staff Preliminary 

Assessment and commenters raise a 

number of issues that apply generally to 

Reliability Standards TPL–001–0 

through TPL–004–0. We address these 

issues here and, in addition, apply our 

general discussion when addressing 

each individual Reliability Standard. 

i. Staff Preliminary Assessment 

1040. Staff stated that, in general, the 

TPL Reliability Standards raise issues 

regarding requirements that are 

ambiguous, and ‘‘limited sets of 

contingencies,’’ i.e, they do not address 

outages of multiple-elements resulting 

from some probable single events and 

critical system conditions.314

1041. NERC responds that, while the 

proposed Reliability Standards need 

review and incremental improvement, 

staff’s criticisms of the TPL group of 

Reliability Standards are overstated. 

Likewise, EEI believes that the TPL 

group of proposed Reliability Standards 

is technically sound and sufficiently 

detailed. NERC contends that the 

purpose of Reliability Standards is not 

to make the Bulk-Power System failureproof, but to ensure it is able to meet 

specific performance requirements 

under normal conditions and following 


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315Examples include practices cited in NERC’s 

‘‘Examples of Excellence’’ found in its Readiness 

Audits, filings for jurisdictional utilities in Part 4 

of FERC Form No. 715, Transmission Planning 

Reliability Criteria. Regional Reliability 

Organizations also specify requirements that exceed 

NERC Reliability Standards, such as WECC’s 

Minimum Operating Requirement Criteria and the 

NPCC Document A–02—Basic Criteria for Design 

and Operation of Interconnected Power Systems. 

316Staff Preliminary Assessment at 109. 

317E.g., Reliability Standard TPL–001–0, 

Requirement R1.3. 

318See Staff Preliminary Assessment at 109. See 

also CenterPoint, MidAmerican and MRO 

comments. 

319While contingencies have been defined in 

Table I, the Commission does not believe systems 

conditions lend themselves to a table or a simple 

list. 

single contingencies and certain 

credible multiple-contingencies. The 

TPL standards require assessment of 

multiple-contingency and extreme 

contingency events but do not require 

that the system be able to withstand 

such events without loss of firm load 

and, according to NERC, requiring this 

would be impractical and extremely 

costly. 

1042. The Commission agrees with 

NERC that the Reliability Standards are 

not intended to make the Bulk-Power 

System failure-proof. Nor do we propose 

to modify the TPL Reliability Standards 

to require that the system be able to 

withstand all multiple-contingency and 

extreme contingency events without 

loss of load. Nonetheless, we believe 

that the planning-related Reliability 

Standards could be improved to better 

take into account probable 

contingencies when planning studies 

are conducted. Much of our proposal is 

consistent with the possible means of 

improvement recognized by NERC in its 

comments responding to the Staff 

Preliminary Assessment. Further, we 

note that a number of regions currently 

utilize superior planning practices that 

may be characterized as ‘‘best practices’’

and are more stringent than the 

proposed TPL Reliability Standards.315

Accordingly, we propose that the ERO 

submit to the Commission such regional 

differences in transmission planning 

criteria that are more stringent than 

those specified in the TPL group of 

Reliability Standards. 

ii. Stressing the System During 

Simulations 

1043. Staff stated that, when carrying 

out power systems simulations it is 

important to ensure that the system 

under study is sufficiently stressed so 

that any underlying weaknesses or 

deficiencies can be identified and to test 

the performance of the system under 

study for a wide variety of probable 

scenarios. It suggested that such 

simulations ‘‘would determine the most 

onerous sets of system conditions 

***’’ 316 Staff stated that system 

conditions are as important as 

contingencies in evaluating the 

performance of present and future 

systems, but that the Reliability 

Standards do not require that sensitivity 

studies be carried out or specify the 

rationale for determining critical system 

conditions and study years. 

1044. A number of commenters 

reacted strongly to staff’s suggestion 

regarding the use of simulations to 

determine ‘‘the most onerous sets of 

system conditions.’’ CenterPoint states 

that planning for the most onerous set 

of conditions would have an 

unreasonable impact on transmission 

rates and the need for new transmission 

lines. 

1045. MRO and MidAmerican support 

clarifying ambiguities but prefer that 

Reliability Standards not become overly 

prescriptive in a way that would restrict 

engineering judgment. For example, 

MRO comments that sensitivity studies 

should be performed as part of the 

planning process, but it recommends 

that the planning entity develop the 

system conditions, planning years, and 

other aspects of the sensitivity 

scenarios. ReliabilityFirst adds that 

defining a checklist for planning would 

encourage planners to rely on the 

checklist to the exclusion of good 

engineering judgment. 

1046. The TPL Reliability Standards 

require Transmission Planners and 

Planning Authorities to conduct system 

performance assessments. Such 

assessments must address specific 

topics, including ‘‘critical system 

conditions and study years as deemed 

appropriate by the entity performing the 

study.’’ 317 As noted by staff and 

commenters,318 system conditions are as 

important as contingencies in evaluating 

the performance of present and future 

systems. The Commission is concerned 

that this Requirement allows complete 

discretion to the entity performing the 

study and does not provide any 

parameters or criteria for such an entity 

to determine critical system conditions 

and study years in a rational and 

consistent manner. 

1047. With regard to CenterPoint’s 

comment, we agree that it is not realistic 

to expect the ERO to develop a 

Reliability Standard that anticipates 

every conceivable critical operating 

condition applicable to unknown future 

configurations for regions with various 

configurations and operating 

characteristics. The practical solution 

that has been implemented by many in 

the industry is to perform sensitivity 

studies that define and provide 

documentation of the impact on the 

system. For that reason, we believe that 

it would be appropriate for planning 

entities to conduct sensitivity studies to 

‘‘bracket’’ the range of probable 

outcomes. Thus, without having to 

anticipate ‘‘every conceivable critical 

operating condition,’’ planning entities 

will have a means to identify an 

appropriate range of critical operating 

conditions. While Requirement R1.3 

identifies firm transfers, selected 

demand levels, existing and planned 

facilities, reactive power resources, and 

control devices, a sensitivity study to 

determine critical system conditions 

should consider such additional matters 

as the range of load power factors, 

generation retirements, generation 

dispatch and transaction patterns, 

controllable loads and DSM at specific 

locations, and transmission outages, 

including outages of reactive power 

devices. The Commission is not 

precluding other approaches to define 

and document critical system 

conditions that have been proven to be 

effective.319 We propose that the ERO 

modify the relevant TPL Reliability 

Standards accordingly. Further we 

propose that the results of these studies 

be documented to support the selection 

of critical system conditions used in 

assessing system performance. 

iii. Element-Based vs. Event-Based 

Contingencies 

1048. As explained in the TPL 

overview above, Table 1 of the TPL 

Standards lays out the system 

performance requirements for a range of 

contingencies grouped according to the 

number of elements forced out of 

service as a result of the contingency. 

The Staff Preliminary Assessment 

explained that the single unanticipated 

failure of some elements in the BulkPower System can result in the loss of 

multiple elements. Because of the 

resulting impact on reliability, some 

regions base their groupings according 

to the event irrespective of the number 

of elements forced out of service (as 

opposed to categorizing contingencies 

according to elements forced out of 

service). For such a region, a single 

event that results in the loss of multiple 

elements, e.g., a lightning strike, that 

simultaneously forces out of service 

both circuits of a double circuit tower 

line, is considered a single contingency 

similar to the loss of a single element 

such as a generator. What is acceptable 

in one region may not be acceptable in 

another region because of historical 

adoption of reliability criteria rather 

than physical differences in systems. 


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320See, e.g., CenterPoint, EEIm Mid American, 

New York Commission and ReliabilityFirst. 321Section 215(a) of the FPA defines ‘‘Reliable 

Operation’’ as ‘‘means’’ operating the elements of 

the Bulk-Power System within equipment and 

electric system thermal, voltage, and stability limits 

so that instability, uncontrolled separation, or 

cascading failures of such system will not occur as 

a result of sudden disturbance, including a 

Cybersecurity Incident, or unanticipated fialure of 

system elements’’ (emphasis added). 

322The NERC glossay defines a ‘‘contingency’’ as 

‘‘[t]he unexpected failure or outage of a system 

component, such as a generator, transmission line, 

circuit breaker, switch or other electrical element.’’

NERC glossary at 3. 323The performance requirements are set forth in 

Category A of Table I of the standard. 

1049. Most commenters that address 

this topic oppose an event-based 

contingency planning approach on the 

grounds that it is difficult to perform, 

too conservative, too costly to the 

public, too rigid, or not based on the 

probabilities of outages occurring in the 

real system.320 National Grid, on the 

other hand, supports event-based 

contingency planning on the contention 

that it provides a more robust analysis. 

The Commission believes that planning 

standards must influence system design 

and not the other way around. To 

achieve this objective, planning 

standards should promote system 

designs that result in the minimum set 

of elements being removed from service 

for ‘‘unanticipated failures of system 

elements.’’ 321 The Commission notes 

that entities with planning 

responsibility for approximately half of 

the load in the nation analyze 

contingencies based on the actual 

number of elements that would be 

removed from service in the actual 

power system for an unanticipated 

failure of system elements, rather than 

simulating only the outages identified in 

Table 1. Simply put, the Commission 

believes that the simulations should 

faithfully duplicate what will happen in 

the actual power system and not a 

generic listing of outages. 

1050. In addition, the Bulk-Power 

System must be operated and planned 

to be operated within a number of 

conditions after a contingency or cyber 

event. The Contingency can be a sudden 

disturbance or unanticipated failure of 

any system element. If a specific portion 

of the system has been designed such 

that the response to a failure results in 

multiple lines, transformers, generators, 

circuit breakers, etc., being removed 

from service, then the Commission 

proposes that this is what should be 

simulated. 

1051. Planning for Cybersecurity 

incidents have not been part of the 

traditional planning study process. One 

approach is to identify specific 

vulnerabilities based on the designs at 

specific locations and then study the 

impact of those vulnerabilities. The 

Commission is interested in comments 

from industry on this subject such as 

whether planning for cybersecurity 

events should be addressed in the 

planning standards or in the CIP 

standards. 

c. System Performance Under Normal 

(No Contingency) Conditions (TPL–001–

0) 

i. NERC Proposal 

1052. Proposed Reliability Standard 

TPL–001–0 deals with planning relevant 

to system performance under normal 

conditions, i.e., a situation where no 

system contingency or no unexpected 

failure or outage of a system component 

has occurred.322 NERC states in its 

application that the proposed Reliability 

Standard ensures that the Bulk-Power 

System is planned to meet the system 

performance requirements under these 

normal conditions by requiring the 

transmission planner and the planning 

authority to evaluate their transmission 

system annually and document the 

ability of that system to meet the 

performance requirements established 

in the Reliability Standard under 

conditions where no system 

contingencies are present.323 Meeting 

these requirements means two things. 

First, when all system facilities are in 

service and normal operating 

procedures are in effect, the system can 

be operated to supply projected 

customer demands and projected firm 

(non-recallable reserved) transmission 

services at all demand levels over the 

range of forecast system demands. 

Secondly, the system remains stable and 

within the applicable ratings for thermal 

and voltage limits, no loss of demand or 

curtailed firm transfers occurs, and no 

cascading outages occur. TPL–001–0 

applies both to near-term and longerterm planning horizons. 

1053. The Requirements of TPL–001–

0 specify that the planning authority 

and transmission planner must 

demonstrate through a valid assessment 

that the Reliability Standard’s system 

performance requirements can be met. 

The assessment must be supported by a 

current or past study and/or system 

simulation testing that addresses 

various categories of conditions to be 

simulated as set forth in the Reliability 

Standard to verify system performance 

under normal conditions. When system 

simulations indicate that the system 

cannot meet the performance 

requirements stipulated in the 

Reliability Standard, a documented plan 

to achieve system performance 

requirements must be prepared. The 

specific study elements selected from 

each of the categories for assessments 

are subject to approval by the associated 

regional reliability organization. 

ii. Staff Preliminary Assessment 

1054. The Staff Preliminary 

Assessment explained that TPL–001–0 

does not require the consideration of 

planned outages, which are a common 

occurrence, in assessing system 

performance. Staff also stated that the 

Reliability Standard does not require 

sensitivity studies to define critical 

conditions and that footnote (a) to Table 

1—which states in part that ‘‘Applicable 

Ratings may include Emergency Ratings 

applicable for short durations as 

required to permit operating steps 

necessary to maintain system control’’

and therefore only pertains to 

contingency conditions—should be 

clarified that it is only applicable to 

Categories B, C, and D, i.e., situations 

involving system contingencies or 

failures of system components. 

1055. Staff noted that the purpose 

statement for this Reliability Standard is 

identical to those for TPL–002, TPL–003 

and TPL–004 although the goal and 

requirements are different. The 

transmission planning Reliability 

Standards TPL–001–0 through TPL–

004–0 define various categories of 

conditions to be simulated. Staff noted 

that Requirement R1.3 in each of these 

Reliability Standards allows fewer than 

the specific study elements identified in 

Table 1 to be selected from each of the 

categories for assessments with the 

approval by the associated regional 

reliability organization, even though 

selection of fewer elements may impact 

neighboring systems. 

iii. Comments 

1056. MRO comments that the 

Requirements of TPL–001–0 need 

clarification because it is not clear as to 

what is required. In addition, it asserts 

that staff appears to indicate that Order 

No. 2003 and TPL–001–0 have separate 

requirements which must be followed. 

To avoid the creation of dual Reliability 

Standards, MRO maintains that the 

Commission should explain how the 

Requirements of this Reliability 

Standard relate to the requirements of 

Order No. 2003 and clarify that entities 

will only be required to comply with a 

single set of reliability requirements. 

1057. ReliabilityFirst disagrees that 

footnote (a) to Table 1 is ambiguous. It 

states that emergency ratings are not 

applicable when all facilities are in 

service. 

1058. ISO/RTO Council comments 

that Requirement 1 of TPL–001–0 

should define more clearly which entity 


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324The Commission expects that the results of the 

sensitivity studies taken together would form the 

basis for evaluating adherence to criteria, i.e., 

adhering to system performance expectations 

following contingencies specified in Table 1. 

Failure of one sensitivity study of a very low 

probability simulation would not, by itself, warrant 

the need for mitigation plans. However, if the 

simulations, taken as a whole, show miltiple areas 

of weaknesses or criteria violations, then mitigation 

plans would be required. 

325NERC Transmission Issues Subcommittee, 

Evaluation of Criteria, Methods, and Practices Used 

for System Design, Planning and Analysis in 

Response to NERC Blackout Recommendation 13c 

(Nov. 28, 2005) (NERC TIS Report) at 15. 

is classified as a ‘‘planning authority.’’

It also recommends that because the 

planning authority only has authority to 

plan for system expansion, the word 

‘‘consider’’ used in Requirement R2 in 

connection with lead times necessary 

for implementation should be changed 

to ‘‘estimate.’’

iv. Commission Proposal 

1059. The Commission proposes to 

approve TPL–001–0 as a mandatory and 

enforceable Reliability Standard. In 

addition, we propose to direct that 

NERC develop modifications to the 

Reliability Standard, as discussed 

below. 

1060. Transmission Planning requires 

information on forecasted loads and 

probable generation plans to supply 

those loads. While information on 

forecasted loads, energy, interruptible 

loads and direct control load 

management over the next ten years are 

required to be made available by the 

MOD Reliability Standards, there is no 

requirement to inform transmission 

planners and planning authorities of 

new or retiring generation resources. We 

seek comments on whether transmission 

planners and planning authorities are 

currently able to obtain and validate 

resource information on new generation 

and retirements for assessments over the 

ten year planning horizon. If 

transmission planners and planning 

authorities currently experience 

difficulty obtaining this information, 

how should this potential information 

gap be addressed? 

1061. In assessing system 

performance, TPL–001–0 requires 

entities to cover ‘‘critical system 

conditions and study years,’’ as deemed 

appropriate by the entity performing the 

study. As discussed above regarding 

Stressing the System During 

Simulations, the Reliability Standard 

does not specify the rationale for 

determining critical system conditions 

and study years. Consistent with our 

discussion of this issue above, the 

Commission proposes that the ERO 

modify TPL–001–0 to require that 

critical system conditions be 

determined by conducting sensitivity 

studies covering such factors as load 

power factors, different likely 

generation expansion scenarios 

including generation retirements, 

alternative generation dispatch and 

transaction patterns, controllable loads 

and DSM at specific locations, and 

transmission outages, including outages 

of reactive power devices. The 

Commission would expect that the 

results of these studies would be used 

to document the selection of critical 

system conditions and study years used 

in assessing system performance.324

1062. The Commission notes that load 

models used in system studies have a 

significant impact on system 

performance, particularly as they relate 

to the dynamic performance of the 

system. The Commission proposes that 

the Reliability Standard be modified to 

require documentation of load models 

used in system studies and supporting 

rationale for their use. 

1063. Requirement R1.3 of TPL–001–

0 provides that the Planning Authority 

and Transmission Planner must provide 

studies and system simulations to 

support its planning assessment, and 

that the ‘‘specific elements selected [for 

the study] shall be acceptable to the 

associated Regional Reliability 

Organization(s).’’ As we have discussed 

elsewhere, the Commission believes that 

the regional reliability organization 

should not have such a role in the 

context of mandatory Reliability 

Standards. Rather, the ERO or the 

appropriate Regional Entity(s) should 

provide this oversight. Also, given that 

neighboring systems may be adversely 

impacted, the Commission proposes 

that the neighboring systems be 

involved in the determination and 

review of system conditions and 

contingencies to be assessed. 

1064. As mentioned above, staff noted 

that TPL–001–0 does not require the 

consideration of planned outages. While 

Reliability First agrees with staff, 

CenterPoint disagrees because operators 

schedule planned outages at times when 

the reliability risk is minimized. 

Planned outages are an every day 

occurrence that, if excluded, would not 

provide an accurate assessment of 

system conditions. Accordingly, the 

Commission proposes to direct that 

NERC modify TPL–001–0 to require 

consideration of planned outages of 

critical equipment. We note that TPL–

002–0 through TPL–004–0 require 

consideration of planned outages. 

1065. NERC and other commenters 

agree with staff that footnote (a) to Table 

1 requires clarification. The NERC 

Transmission Issues Subcommittee 

(TIS) 325 recommended that footnote (a) 

be modified to state explicitly that 

emergency ratings apply to Category B 

and C (contingency conditions) and not 

to Category A (system intact). The 

Commission proposes that footnote (a) 

be modified in the revised Reliability 

Standard as recommended by TIS and 

that the normal facility rating be in 

accordance with Reliability Standard 

FAC–008–1 and normal voltages be in 

accordance with Reliability Standard 

VAR–001–1. 

1066. While the Commission has 

identified a number of concerns with 

regard to TPL–001–0, this proposed 

Reliability Standard serves an important 

purpose by ensuring the Bulk-Power 

System is planned to meet the system 

performance requirements under normal 

conditions. Further, the Requirements 

set forth in TPL–001–0 are sufficiently 

clear and objective to provide guidance 

for compliance. 

1067. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard TPL–001–

0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to TPL–001–0 that: (1) Requires that 

critical system conditions be 

determined by conducting sensitivity 

studies; (2) requires that system 

conditions and contingencies assessed 

be reviewed by neighboring systems; (3) 

modifies Requirement R1.3 to substitute 

the reference to regional reliability 

organization with Regional Entity; (4) 

requires consideration of planned 

outages of critical equipment; and (5) 

modifies footnote (a) as discussed 

above. 

d. System Performance Following Loss 

of a Single Element (TPL–002–0) 

i. NERC Proposal 

1068. Proposed Reliability Standard 

TPL–002–0 concerns planning system 

relevant to performance under 

contingency conditions involving the 

failure of a single element with or 

without a fault, i.e., the occurrence of an 

event such as a short circuit, a broken 

wire or an intermittent connection. 

NERC states that the Reliability 

Standard ensures that the future BulkPower System is planned to meet the 

system performance requirements of a 


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326The performance requirements are set forth in 

Category B of Table I of the Reliability Standard. 

327Footnote (b) reads states ‘‘Planned or 

controlled interruption of electric supply to radial 

customers or some local Network customers, 

connected to or supplied by the Faulted element or 

by the affected area, may occur in certain areas 

without impacting the overall reliability of the 

interconnected transmission systems. To prepare 

for the next contingency, system adjustments are 

permitted, including curtailments of contracted 

Firm (non-recallable reserved) electric power 

transfers.’’

system, with the loss of one element, by 

requiring that the transmission planner 

and planning authority annually 

evaluate and document the ability of the 

transmission system to meet the 

performance requirements where an 

event results in the loss of a single 

element.326 Meeting these requirements 

means two things. First, the system can 

be operated following the event to 

supply projected firm customer 

demands and projected firm (nonrecallable reserved) transmission 

services at all demand levels over the 

range of forecast system demands. 

Second, the system remains stable and 

within the applicable ratings for thermal 

and voltage limits, no loss of demand or 

curtailed firm transfers occurs, and no 

cascading outages occur. The Reliability 

Standard applies both to near-term and 

longer-term planning horizons. 

1069. TPL–002–0 specifies that the 

planning authority and transmission 

planner must demonstrate through a 

valid assessment that the standard’s 

system performance requirements can 

be met. The assessment must be 

supported by a current or past study 

and/or system simulation testing that 

addresses various categories of 

conditions to be simulated, as set forth 

in the Reliability Standard, to verify 

system performance under contingency 

conditions involving the failure of a 

single element with or without a fault. 

The Reliability Standard requires that 

planned outages of transmission 

equipment be considered for those 

demand levels for which planned 

outages are performed. When system 

simulations indicate that the system 

cannot meet the performance 

requirements stipulated in the standard, 

a documented plan to achieve system 

performance requirements must be 

prepared. The specific study elements 

selected from each of the categories for 

assessments are subject to approval by 

the associated regional reliability 

organization. 

ii. Staff Preliminary Assessment 

1070. Staff stated that its general 

concerns regarding stressing the system 

during simulations and event-based 

contingencies apply to TPL–002–0. In 

other words, TPL–002–0 does not 

require sensitivity studies to define 

critical conditions and does not address 

the unanticipated failure of some single 

elements in the Bulk-Power System that 

result in subsequent loss of multiple 

elements. Staff also stated that footnotes 

associated with Table 1, which are 

meant to aid the interpretation of the 

performance requirements, are 

ambiguous and need to be clarified so 

that they are applied appropriately and 

consistently by all the entities to whom 

they apply. In particular staff noted that 

for TPL–002–0 footnote (b) to the 

Reliability Standard is sufficiently 

ambiguous to allow differing 

interpretations.327

1071. Staff further noted that while 

the Reliability Standard defines various 

categories of conditions to be simulated, 

the specific study elements selected 

from each of the categories for 

assessments are subject to approval by 

the associated regional reliability 

organization, even though they may 

impact neighboring utilities and 

reliability coordinators. 

iii. Comments 

1072. NERC states that the reliability 

Standards do not consider load 

shedding acceptable for single 

contingency events. As such, footnote 

(b) provides a limited exception to the 

general rule against serving load from a 

radial transmission line. 

1073. In addition to its comments 

regarding stressing the system discussed 

above, NERC comments that it intends 

to pursue the following improvements: 

(1) Expand the list of Category B 

contingencies, and differentiate between 

an element (i.e., circuit) and a system of 

elements (i.e., multi-circuit line or DC 

bi-pole); (2) review Category B and C 

contingencies based not only on 

probability, but also on reliability risk 

and consider including risk 

quantification methodology in the 

Reliability Standards; and (3) clarify 

footnote (b) of Table 1 to address staff’s 

concern. 

1074. CenterPoint disagrees with staff 

that planners should specifically plan 

for planned outages plus unplanned 

outages. According to CenterPoint, it 

suffices that operators currently 

schedule planned outages at times when 

reliability risk is minimized. Further, it 

contends that planning for one planned 

outage in addition to outages prescribed 

in the TPL Reliability Standards would 

make an N–1 requirement effectively an 

N–2 requirement. Based on that 

premise, it argues that no utility has 

software to exhaustively test every 

conceivable combination of outages or 

that it would be worthwhile to do so. 

1075. ReliabilityFirst and TAPS also 

agree that footnote (b) needs 

clarification. However, ReliabilityFirst 

comments that the wording simply 

reflects how the system is actually built 

rather than indicating a lower level of 

performance. 

1076. The ISO/RTO Council 

comments that the process for 

determining load levels for purposes of 

Requirement 1 of TPL–002–0 needs to 

be standardized, and local area 

networks and system adjustments 

should be specifically defined. 

1077. MRO finds an inconsistency in 

Table 1. Under the ‘‘Loss of Demand or 

Curtailed Firm Transfers’’ column for 

category B the entries are all ‘‘No.’’

However, footnote (b) indicates that 

curtailments of contracted firm transfers 

are permitted. MRO states that the ‘‘no’’

response in this column may need to be 

revised to ‘‘Planned/Controlled’’ as it is 

used for other categories of 

disturbances. 

iv. Commission Proposal 

1078. The Commission proposes to 

approve TPL–002–0 as a mandatory and 

enforceable Reliability Standard. In 

addition, we propose to direct that 

NERC develop modifications to the 

Reliability Standard, as discussed 

below. 

1079. The Commission notes that, like 

TPL–001–0, TPL–002–0 requires an 

entity assessing system performance to 

cover ‘‘critical system conditions and 

study years’’ as deemed appropriate by 

the entity performing the study, but 

does not specify the rationale for 

determining critical system conditions 

and study years. The Commission 

therefore proposes to direct NERC to 

modify TPL–002–0 to require that 

critical system conditions be 

determined in the same manner as we 

propose with regard to TPL–001–0. The 

Commission also proposes that the 

results of these studies be documented 

to support the selection of critical 

system conditions and study years used 

in assessing system performance. We 

also note that load models used in 

system studies have a significant impact 

on system performance, particularly as 

they relate to the dynamic performance 

of the system. The Commission 

proposes that the documentation of 

system studies include a description of 

the load models used including 

supporting rationale for their use. The 

Commission expects the ERO to provide 

consistency and quality control in these 

interpretations and that over time one or 

more performance metrics would be 


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328 Interconnection for Wind Energy, Order No. 

661, 70 FR 34993 (June 16, 2005), FERC Stats. & 

Regs. ¶ 31,186 (2005), order on reh’g, Order No. 

661–A, 70 FR 75,005 (Dec. 19, 2005), FERC Stats. 

& Regs. ¶ 31,198 (2005). 

329NERC TIS Report at 15. 

330Load associated with the failure could be 

radial load supplied by the transmission element 

that is assumed to be removed from service, load 

supplied from separate transmission elements that 

are both removed from service due to a single 

failure, or load that is tapped onto a single 

transmission element. 

developed to assess the rigor of these 

evaluations. 

1080. The Commission commends 

NERC’s initiative on improving the TPL 

standards and proposes that NERC 

modify the Reliability Standard to 

expand category B to achieve 

consistency in continent-wide 

Reliability Standards. 

1081. With regard to CenterPoint’s 

concerns, we disagree that planned 

outages would be considered the same 

as an unexpected contingency that 

would effectively turn an N–1 scenario 

into an N–2 scenario. Further, the 

studies/assessments should recognize 

that planned outages are not scheduled 

for peak periods and when required the 

system is adjusted to accommodate the 

planned outage. However, we do not 

believe that fact justifies ignoring 

planned outages altogether, as suggested 

by CenterPoint. While TPL–002–0 

requires consideration of planned 

outages at those demand levels for 

which planned outages are performed, it 

does not address situations in which 

critical equipment, such as a 

transformer or phase angle regulator, 

may be unavailable for a prolonged 

period. Including such a requirement 

would ensure the coordination of 

contingency plans, including the 

entity’s spare equipment strategy, to 

return facilities to service in a timely 

manner as required for reliability. 

Therefore, the Commission proposes 

that the ERO modify the Reliability 

Standard by developing a new 

requirement that would include the 

reliability impact of an entity’s existing 

spare equipment strategy, address the 

unavailability of long lead time critical 

facilities. Critical facilities are those 

facilities that impact IROLs and 

deliverability of generation to firm load. 

1082. Order No. 661 requires all wind 

generators to remain online during 

voltage disturbances for specified time 

periods and associated voltage levels. 

Category B and some Category C events 

capture these disturbances for planning 

study purposes.328 We understand that 

the TPL Reliability Standards implicitly 

require all generators to ride through 

these same types of voltage disturbances 

and remain in service after the fault is 

cleared. The Commission proposes to 

direct NERC to modify TPL–002–0 to 

explicitly state this requirement. 

1083. Several commenters agree with 

staff that a number of footnotes of Table 

1 could be enhanced. We agree with TIS 

with respect to footnote (a), which is 

applicable to TPL–002–0. This states, in 

part, ‘‘[a]pplicable ratings may include 

Emergency Ratings applicable for short 

durations as required to permit 

operating steps necessary to maintain 

system control.’’ 329 TIS states that on 

the basis of its review of criteria, 

methods and practices used for system 

design, planning and analysis across the 

NERC reliability regions, the footnote is 

intended to provide flexibility to the 

responsible planning entity to decide 

the appropriate planning response. That 

response could be to plan for a facility 

addition or enhancement, or to develop 

and document an operating guide or 

procedure that can be reliably 

implemented to achieve the required 

system performance for the event in 

question. In the latter case, the operating 

action must be completed in sufficient 

time to return the system to a secure 

operating state with no additional loss 

of firm load. The Commission proposes 

to require that the phrase ‘‘permit 

operating steps necessary to maintain 

system control’’ be clarified to state that 

the operating steps required to relieve 

emergency loadings and return the 

system to a normal state do not include 

firm load shedding. The Commission 

also proposes that these required 

operating steps be identified and be 

capable of returning the system to the 

normal secure state within the 30 

minute allowable period. 

1084. Footnote (b) to Table 1 raises 

three issues that need to be addressed. 

Two relate to the use of planned or 

controlled load interruptions under 

certain circumstances, and the third 

relates to the use of system adjustments 

including curtailment of firm transfers 

to prepare for the next contingency. 

NERC and TAPS agree with the Staff 

Preliminary Assessment that footnote 

(b) of Table 1 could be enhanced with 

regard to its intended interpretation for 

contingencies associated with 

transmission lines used to serve or 

supply load. NERC states that it does 

not consider shedding load acceptable 

for single contingency events. The 

Commission agrees and thus proposes to 

require NERC to modify footnote (b) to 

state that load shedding for a single 

contingency is not permitted except in 

very special circumstances where such 

interruption is limited to the firm load 

associated with the failure 

(consequential load loss).330 For 

purposes of clarity, the Commission 

proposes to require that the phrase ‘‘to 

prepare for the next contingency, system 

adjustments are permitted, including 

curtailments of contracted Firm (nonrecallable reserved) electric power 

transfers’’ be deleted from footnote (b). 

This statement is more appropriate for 

Category C events and is already 

captured by footnote (c) to Table 1, 

which is applicable to Category C 

events. 

1085. While all commenters agree 

with staff on the need to clarify footnote 

(b), the Commission has proposed above 

that footnote (b) be clarified to allow no 

firm load or firm transactions to be 

interrupted except consequential load 

loss. NERC identifies another concern 

with its example, specifically, the 

acceptable magnitude and duration of 

consequential load loss. The 

Commission believes that the Reliability 

Standard should provide some limits on 

the magnitude and duration of 

consequential load loss. While the 

Commission does not propose to require 

any specific maximum consequential 

load loss level or maximum load loss 

duration at this time, we do propose to 

require that those values be documented 

by all users of the Bulk-Power System. 

1086. MRO points to the same 

ambiguity in Table 1 that staff identified 

in the Staff Preliminary Assessment. 

The Commission interprets Table 1 to 

specify no permitted loss of demand or 

curtailment of firm transfers for 

Category B contingencies. If the 

Reliability Standard intended to use 

Planned/Controlled demand loss, it 

would have stated such, as they do in 

other portions of the same table. It is 

footnote (b) that introduces the 

ambiguity, and the Commission 

proposes that the footnote be viewed as 

identifying rare exceptions, such as 

radial customers. 

1087. The Commission proposes to 

require that the purpose statement of 

TPL–002–0 be modified to reflect the 

specific goal of the Reliability Standard. 

1088. While the Commission has 

identified a number of concerns with 

regard to TPL–002–0, this proposed 

Reliability Standard serves an important 

purpose by ensuring that the future 

Bulk-Power System is planned to meet 

the system performance requirements of 

a system, with the loss of one element. 

Further, the Requirements set forth in 

TPL–002–0 are sufficiently clear and 

objective to provide guidance for 

compliance. 

1089. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 


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331See NERC TIS Report. 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard TPL–002–

0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to TPL–002–0 that: (1) Requires that 

critical system conditions be 

determined in the same manner as we 

propose to require for TPL–001–0; (2) 

requires the inclusion of the reliability 

impact of the entities’ existing spare 

equipment strategy; (3) explicitly 

requires all generators to ride through 

the same set of Category B and C 

contingencies as required for wind 

generators in Order No. 661; (4) requires 

documentation of load models used in 

system studies and supporting rationale 

for their use; (5) clarifies the phrase 

‘‘permit operating steps necessary to 

maintain system control;’’ and (6) 

clarifies footnote (b), as discussed 

above. 

e. System Performance Following Loss 

of Two or More Elements (TPL–003–0) 

i. NERC Proposal 

1090. NERC states that proposed 

Reliability Standard TPL–003–0 ensures 

that the future Bulk-Power System is 

planned to meet the system performance 

requirements of a system with the loss 

of multiple elements. It does this by 

requiring that the transmission planner 

and the planning authority annually 

evaluate and document the ability of its 

transmission system to meet the 

performance requirements of Category C 

contingencies specified in Table 1 (i.e., 

events resulting in the loss of two or 

more elements) for both the near-term 

and the longer-term planning horizons. 

TPL–003–0 requires the preparation of a 

documented plan to achieve the 

necessary performance requirements if 

the system is unable to meet the 

Category C performance criteria. 

1091. TPL–003–0 applies to each 

planning authority and transmission 

planner. They must demonstrate 

annually through valid assessments that 

their portion of the interconnected 

transmission system is planned to meet 

the performance requirements of 

Category C with all transmission 

facilities in service over a planning 

horizon that takes into account lead 

times for corrective plans. The 

Reliability Standard also requires the 

applicable entities to consider planned 

outages of transmission equipment for 

those demand levels for which they 

perform such outages. The Reliability 

Standard defines various categories of 

conditions to be simulated. The specific 

study elements selected from each of the 

categories for assessments, including the 

subset of Category C contingencies to be 

evaluated, require approval by the 

associated regional reliability 

organization. 

ii. Staff Preliminary Assessment 

1092. Commission staff stated in its 

Staff Preliminary Assessment that TPL–

003–0 does not require sensitivity 

studies to define critical conditions and 

study years, does not base its 

contingencies on probable events, and 

as a result has contingencies included 

that would be more appropriate in 

Category B contingencies treated under 

TPL–002–0. Staff also stated that 

footnotes associated with TPL–003–0 in 

Table 1, which are meant to aid the 

interpretation of the performance 

requirements, are ambiguous and 

require clarification to permit 

appropriate and consist application. 

1093. Staff noted that the purpose 

statement for TPL–003–0 is identical to 

those for TPL–001, TPL–003 and TPL–

004, although the Reliability Standard 

has a different goal and different 

requirements. Staff further noted that 

while the Reliability Standard defines 

various categories of conditions to be 

simulated, the specific study elements 

selected from each of the categories for 

assessments are subject to approval by 

the associated regional reliability 

organization, even though they may 

impact neighboring utilities and 

reliability coordinators. 

iii. Comments 

1094. ISO/RTO Council comments 

that Requirement 2 of TPL–003–0 does 

not clearly define ‘‘simulation’’ and 

does not define ‘‘inability to respond.’’

In addition, several commenters note 

that the footnotes in Table 1 of the TPL 

group of Reliability Standards could be 

enhanced, including footnote (c) of 

Table 1. 

iv. Commission Proposal 

1095. The Commission proposes to 

approve proposed Reliability Standard 

TPL–003–0 as a mandatory and 

enforceable Reliability Standard. In 

addition, we propose to direct that 

NERC develop modifications to the 

Reliability Standard, as discussed 

below. 

1096. The Commission notes that, like 

TPL–001–0 and TPL–002–0, in 

assessing system performance, TPL–

003–0 requires entities to cover ‘‘critical 

system conditions and study years’’ as 

deemed appropriate by the entity 

performing the study, but does not 

specify the rationale for determining 

critical system conditions and study 

years. The Commission therefore 

proposes that NERC modify TPL–003–0 

to require that critical system conditions 

be determined in the same manner 

discussed above with regard to TPL–

001–0. The Commission also proposes 

that the results of these studies be 

documented to support the selection of 

critical system conditions and study 

years used in assessing system 

performance. Also the Commission 

notes that load models used in system 

studies have a significant impact on 

system performance, particularly as they 

relate to the dynamic performance of the 

system. The Commission proposes that 

the documentation of system studies 

include a description of the load models 

used including supporting rationale for 

their use. 

1097. Several commenters agree with 

Commission staff that a number of 

footnotes in Table 1 to the Reliability 

Standard could be enhanced. The 

reference to ‘‘controlled interruption’’ of 

load in regard to footnote (c), which is 

applicable to TPL–003–0, suggests the 

possibility of automatic load shedding 

through the use of Special Protection 

Systems or safety nets such as Under 

Voltage Load Shedding Schemes. 

Alternatively, a defined manual load 

interruption could be used to deal with 

short-time emergency thermal 

overloads. The Commission proposes to 

require that the ERO modify footnote (c) 

to provide specificity regarding the use 

of the term ‘‘controlled interruption’’ of 

load. Further, the Commission proposes 

that, in modifying TPL–003–0, the ERO 

require documentation and 

identification of the firm load that is 

subject to the controlled interruption. 

To avoid any undue negative impact on 

competition, third-party impact studies 

would be permitted to implement the 

same or less controlled load 

interruption as used by the transmission 

owner. 

1098. The performance requirements 

for Category C events stipulate ‘‘no 

cascading outages.’’ The NERC 

Transmission Issues Subcommittee 

identified a concern regarding the 

determination of whether cascading 

outages result in the evaluation of 

Category C events.331 This concern 

relates to the use of thermal overload or 

low voltage proxies to judge the 

likelihood of subsequent line or 

generator trips. The Commission 

proposes to require NERC to modify the 

Reliability Standard to require the 

applicable entities to define and 

document the proxies necessary to 

simulate cascading outages and to 


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332Two entities are Consolidated Edison 

Company of New York and Public Service Electric 

and Gas. 

require that the ERO approve the 

proxies. 

1099. Category C3 of TPL–003–0 

involves a situation in which two single 

contingencies occur, with manual 

system adjustments permitted after the 

first contingency to prepare for the next 

one. Proposed Reliability Standard IRO–

005–0 requires that the manual system 

adjustments be implemented as soon as 

possible and no later than 30 minutes 

after the first contingency has occurred. 

Should the second contingency occur 

before the manual system adjustments 

can be completed, the local area and 

potentially the system would be 

exposed to risk of cascading outages. 

Recognizing this risk and its potential 

consequences, some entities plan and 

operate their systems so that they are 

able to withstand the simultaneous 

occurrence of the two contingencies for 

major load pockets.332 The Commission 

solicits comments on the value and 

appropriateness of including such a 

requirement in TPL–003–0. 

1100. The Commission also notes that 

TPL–003–0 would be enhanced if its 

purpose statement were tailored to 

reflect the specific goal of the Reliability 

Standard and that each requirement 

should correspond with one or more 

Measures and each Measure should 

correspond to a Level of NonCompliance. 

1101. While the Commission has 

identified a number of concerns with 

regard to TPL–003–0, this proposed 

Reliability Standard serves an important 

purpose by ensuring that the future 

Bulk-Power System is planned to meet 

the system performance requirements of 

a system with the loss of multiple 

elements. Further, the Requirements set 

forth in TPL–003–0 are sufficiently clear 

and objective to provide guidance for 

compliance. 

1102. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard TPL–003–

0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to TPL–003–0 that: (1) Requires that 

critical system conditions be 

determined by conducting sensitivity 

studies (as elaborated in our discussion 

of TPL–001–0); (2) clarifies footnote (c) 

as discussed above; (3) requires the 

applicable entities to define and 

document the proxies necessary to 

simulate cascading outages; and (4) 

tailors the purpose statement to reflect 

the specific goal of the Reliability, as 

discussed above. 

f. System Performance Following 

Extreme Events (TPL–004–0) 

i. NERC Proposal 

1103. NERC states the proposed 

Reliability Standard TPL–004–0 ensures 

that the future Bulk-Power System is 

evaluated to assess the risks and 

consequences of an extreme event 

involving the loss of multiple elements. 

It does this by requiring that the 

transmission planner and the planning 

authority to evaluate and document 

annually the risks and consequences of 

Category D contingencies (i.e., extreme 

events resulting in loss of two or more 

elements or cascading) for the near-term 

(five-year) planning horizon. 

1104. TPL–004–0 applies to each 

planning authority and transmission 

planner. Each must demonstrate 

annually through valid assessments that 

its portion of the interconnected 

transmission system is evaluated for the 

risks and consequences of a number of 

each of the extreme contingencies of 

Category D with all transmission 

facilities in service over a planning 

horizon that takes into account lead 

times for corrective plans. TPL–004–0 

also requires that planned outages of 

transmission equipment be considered 

for those demand levels for which 

planned outages are performed. It 

defines various categories of conditions 

to be simulated. The associated regional 

reliability organization must approve 

the specific study elements selected 

from each of the categories for 

assessment, including the subset of 

Category D contingencies to be 

evaluated. 

ii. Staff Preliminary Assessment 

1105. ‘‘Extreme events’’ are low 

probability but high impact events. Staff 

noted that while the Reliability 

Standards require assessments of 

extreme events, documentation of the 

results and submission to the regional 

reliability organization, they do not 

require that consideration be given 

either to reducing the probability of the 

loss of multiple elements or mitigating 

the impact. 

1106. Staff also stated that this 

proposed Reliability Standard does not 

require that assessment results be 

shared with impacted entities or 

communicated to operations planning 

staff and control room operators. Staff 

noted that TPL–004–0 does not address 

scenarios that are equal to or more 

severe than actual weather events, such 

as hurricanes that affect the Southern 

United States and ice storms in the 

north. 

iii. Comments 

1107. ISO/RTO Council believes that 

Requirement R1 of TPL–004–0 needs to 

be revised to provide better definition of 

terms and obligations and requires 

review to determine whether it is too 

prescriptive in specifying responses to 

extreme contingencies. ISO/RTO 

Council also believes that before 

Requirement R2 can be enforced, 

regional seasonal assessments should be 

provided to the regional reliability 

organizations. 

1108. MRO does not believe that it is 

practical to develop deterministic 

criteria for extreme events. MRO and the 

New York Commission state that 

Reliability Standards should not require 

improvements that are not justified by 

very low probability events. However, a 

Reliability Standard should require 

assessment and consideration of actions 

necessary to resolve such events. 

MidAmerican recommends that 

transmission planning Reliability 

Standards permit probabilistic 

approaches to responding to extreme 

events and events in Category D of Table 

1. While the probability of extreme 

events often does not warrant system 

improvements, it does make sense to 

require consideration of mitigating 

actions or improvements whose cost is 

justified by the expected benefits. 

1109. ReliabilityFirst recommends 

that consideration should be given to 

establishing some record of studies and 

identifying system weaknesses. 

CenterPoint states it does not believe 

that companies should be required to 

share planning assessments because it 

relates more to open access tariff 

concerns than reliability. In addition, 

sharing assessments would promote the 

unnecessary disclosure of critical energy 

infrastructure information. 

iv. Commission Proposal 

1110. The Commission proposes to 

approve proposed Reliability Standard 

TPL–004–0 as a mandatory and 

enforceable Reliability Standard. In 

addition, we propose to direct that 

NERC develop modifications to the 

Reliability Standard, as discussed 

below. 

1111. The Commission notes that, like 

Reliability Standards TPL–001–0 

through TPL–003–0, TPL–004–0 

requires entities assessing system 

performance to cover ‘‘critical system 


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conditions and study years’’ the entity 

performing the study deems 

appropriate, but it does not specify the 

rationale for determining critical system 

conditions and study years. The 

Commission therefore proposes that 

NERC modify TPL–004–0 to require that 

critical system conditions be 

determined in the same manner as 

discussed above with regard to TPL–

001–0. The Commission also proposes 

that the results of these studies be 

documented to support the selection of 

critical system conditions and study 

years used in assessing system 

performance. Also the Commission 

notes that load models used in system 

studies have a significant impact on 

system performance, particularly as they 

relate to the dynamic performance of the 

system. The Commission proposes that 

the documentation of system studies 

include a description of the load models 

used including supporting rationale for 

their use. 

1112. MidAmerican and MRO agree 

with Commission staff that 

consideration must be given to 

mitigating actions associated with 

impacts of extreme events. 

MidAmerican proposes using an 

approach to take into account 

probability, impact and value to 

customers of reliability. MRO cautions 

against requiring improvements that 

cannot be justified. NERC also states 

that Reliability Standards should not 

require compliance with a high-impact, 

low probability contingency imposed on 

a low probability base case. The 

Commission agrees that the Reliability 

Standard should not require 

improvements for low probability 

events that cannot be justified. 

However, the Commission proposes that 

NERC modify TPL–004–0 to require the 

identification of options for reducing 

the probability or impacts of extreme 

events that cause cascading outages. The 

Commission also proposes that these 

options be documented together with a 

supporting rationale for cases where 

such options were not pursued. 

1113. In determining the range of 

extreme events to be assessed, staff 

noted that a number of recent high risk 

events, such as the hurricanes affecting 

the southern United States and the ice 

storm in the north, resulted in a greater 

impact on the Bulk-Power System in 

terms of the number of elements forced 

out of service than events listed in TPL–

004–0. The Commission proposes that 

the contingency list of Category D be 

expanded to include similar events. 

1114. Staff noted that the Reliability 

Standard does not explicitly require that 

the results of assessments be shared 

with impacted entities or communicated 

to operations planning staff and control 

room operators. While CenterPoint 

disfavors such information sharing, we 

believe that sharing assessment results 

would serve an important reliability 

purpose as it would provide system 

operators and impacted entities with an 

opportunity to mitigate the identified 

impact. However, we agree with 

CenterPoint that any such requirement 

should make clear that that critical 

energy infrastructure information 

should not be unnecessarily disclosed. 

1115. The Commission also notes that 

TPL–004–0 would be enhanced if its 

purpose statement would be tailored to 

reflect the specific goal of the standard. 

In addition, the Commission proposes 

that each requirement should 

correspond to one or more measures and 

each measure should correspond to a 

level of non-compliance. 

1116. While the Commission has 

identified a number of concerns with 

regard to TPL–004–0, this proposed 

Reliability Standard serves an important 

purpose by ensuring that the future 

Bulk-Power System is evaluated to 

assess the risks and consequences of an 

extreme event involving the loss of 

multiple elements. Further, the 

Requirements set forth in TPL–004–0 

are sufficiently clear and objective to 

provide guidance for compliance. 

1117. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard TPL–004–

0 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to TPL–004–0 that: (1) Requires that 

critical system conditions be 

determined in the same manner as 

proposed for TPL–001–0; (2) requires 

the identification of options for 

reducing the probability or impacts of 

extreme events that cause cascading; (3) 

requires that, in determining the range 

of extreme events to be assessed, the 

contingency list of Category D be 

expanded to include recent events; and 

(4) tailors the purpose statement to 

reflect the specific goal of the Reliability 

Standard. 

g. Regional and Interregional SelfAssessment Reliability Reports (TPL–

005–0) 

i. NERC Proposal 

1118. NERC states that proposed 

Reliability Standard TPL–005–0 ensures 

that each regional reliability 

organization conducts reliability 

assessments of its existing and planned 

regional bulk electric system annually 

by requiring the regional reliability 

organization to assess and document the 

performance of its power system for the 

current year, the next five years, and to 

analyze trends for the longer-term 

planning horizons. 

ii. Staff Preliminary Assessment 

1119. Staff noted that the Reliability 

Standard identifies the regional 

reliability organization as the applicable 

entity. 

iii. Comments 

1120. NYSRC recommends that this 

proposed Reliability Standard be 

withdrawn, as it anticipates that 

regional reliability organizations will 

develop regional transmission planning 

standards due to regional differences 

specific to their region. CenterPoint also 

suggests that the proposed Reliability 

Standard be eliminated. 

1121. ISO/RTO Council states that the 

term and extent of assessment, as well 

as the study years, are not appropriately 

defined; the process for determining 

load levels needs to be standardized; 

and local area networks and system 

adjustments need to be specifically 

defined. 

iv. Commission Proposal 

1122. Consistent with our discussion 

in the Common Issues section above, the 

Commission will not propose any action 

on TPL–005–0, as it applies only to 

regional reliability organizations. 

Accordingly, the Reliability Standard 

will remain pending at the Commission. 

The Commission believes that, in the 

long-run, the Regional Entities should 

be responsible for conducting reliability 

assessments of the existing and planned 

regional system. However, during the 

current period of transition, the regional 

reliability organizations should 

continue to perform this role as they 

have in the past. 

1123. In addition, the Commission 

agrees with the ISO/RTO Council 

regarding the shortcomings in the 

Reliability Standard it has identified 

and proposes that NERC address these 

issues in the revision to the Reliability 

Standard. 


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333See VAR–001–1, Requirements R2 and R8. 

334Staff Preliminary Assessment at 118 (although 

the Staff Preliminary Assessment addresses 

concerns regarding the version 0 VAR Reliability 

Standard, many of these same concerns apply to the 

version 1 VAR Reliability Standards as well). 

335Blackout Report at 160. 

h. Assessment Data From Regional 

Reliability Organizations (TPL–006–0) 

i. NERC Proposal 

1124. NERC states that proposed 

Reliability Standard TPL–006–0 ensures 

that the data necessary to conduct 

reliability assessments is available by 

requiring the regional reliability 

organization to provide NERC with 

Bulk-Power System data, reports, 

demand and energy forecasts, and other 

information necessary to assess 

reliability and compliance with NERC 

Reliability Standards and relevant 

regional planning criteria. 

ii. Staff Preliminary Assessment 

1125. Staff noted that the Reliability 

Standard identifies the regional 

reliability organization as the applicable 

entity. 

iii. Comments 

1126. NYSRC recommends that this 

Reliability Standard be withdrawn 

because it anticipates that regional 

reliability organizations will develop 

regional transmission planning 

standards based on regional differences 

specific to their regions. CenterPoint 

also suggests eliminating this Reliability 

Standard. 

1127. ISO/RTO Council suggests that, 

for the ERO to be successful at assessing 

overall reliability, it must identify what 

data and reports it needs to review in 

order to ensure that adequate planning 

is being conducted. 

iv. Commission Proposal 

1128. Consistent with our discussion 

in the Common Issues section above, the 

Commission will not propose any action 

on TPL–006–0, as it applies only to 

regional reliability organizations. 

Accordingly, the Reliability Standard 

will remain pending at the Commission. 

The Commission believes that, in the 

long-run, the Regional Entities should 

be responsible for providing NERC with 

Bulk-Power System data, reports, 

demand and energy forecasts, and other 

information necessary to assess 

reliability and compliance with NERC 

Reliability Standards and relevant 

regional planning criteria. However, 

during the current period of transition, 

the regional reliability organizations 

should continue to perform this role as 

they have in the past. 

13. VAR: Voltage and Reactive Control 

a. Overview 

1129. The Version 0 Voltage and 

Reactive Control (VAR) Reliability 

Standard VAR–001–0 is intended to 

maintain Bulk-Power System facilities 

within voltage and reactive power 

limits, thereby protecting transmission, 

generation, distribution, and customer 

equipment and the reliable operation of 

the Interconnection. The Voltage and 

Reactive Control group of Reliability 

Standards is intended to replace the 

existing VAR–001–0 and consists of two 

proposed Reliability Standards, VAR–

001–1 and VAR–002–1, with new 

Requirements. These two new proposed 

Reliability Standards have been 

submitted by NERC as part of the 

August 28, 2006 Supplemental Filing 

for Commission review. Because there is 

significant overlap between VAR–001–0 

and version 1 Reliability Standards, the 

Commission will address them 

collectively below, giving due 

consideration to the new Requirements 

in addressing the proposed disposition 

of VAR–001–1 and VAR–002–1. 

b. Voltage and Reactive Control (VAR–

001–1 and VAR–002–1) 

i. NERC Proposal 

1130. NERC explains that VAR–001–

1 requires the transmission operator to 

monitor and control voltage levels, 

reactive flows, and reactive resources, in 

order to keep these parameters within 

their reliability limits. Further, it 

requires a generator operator to provide 

critical operating data to its 

transmission operator, and to maintain 

generator field excitation at proper 

levels. The proposed Reliability 

Standard would apply to transmission 

operators, generator operators and 

purchasing-selling entities. 

1131. In its August 28, 2006 

Supplemental Filing, NERC indicates 

that VAR–001–1 includes three new 

Requirements, designated R3, R4 and 

R11, which apply to transmission 

operators. Requirement R9 from VAR–

001–0, which applies to generator 

operators, is now replaced with five 

Requirements in VAR–002–1. Both 

Reliability Standards include Measures 

and Levels of Non-Compliance. 

ii. Staff Preliminary Assessment 

1132. The VAR Reliability Standard 

requires each transmission owner to 

‘‘acquire sufficient reactive resources 

within its areas to protect the voltage 

levels under normal and Contingency 

conditions’’ and ‘‘maintain system and 

Interconnection voltages within 

established limits.’’ 333 The Staff 

Preliminary Assessment stated that 

these Requirements may not be 

sufficient to assure reliable operation 

when operating power systems under 

conditions that make them vulnerable to 

voltage collapse.334 Staff noted that 

voltage instability has been a common 

causal factor in major power outages 

worldwide and voltage magnitudes 

alone are poor indicators of voltage 

stability. 

1133. The Staff Preliminary 

Assessment explained that the proposed 

Reliability Standard does not require 

applicable entities to perform operations 

planning studies that would identify the 

minimum permissible pre-contingency 

voltage levels and reactive power 

reserves to ensure stable postcontingency voltages. In addition, the 

standard does not require similar 

voltage stability assessments to be 

carried out periodically during real-time 

operations so that system operators can 

continuously respond to changing 

system conditions. 

1134. Because voltage and reactive 

control is an integral part of 

Interconnection Reliability Operating 

Limits and voltage collapse can result in 

widespread cascading outages, staff 

expressed concern that reliable 

operation of the Bulk-Power System 

requires that reliability coordinators be 

authorized to direct and coordinate 

voltage and reactive control among 

operating entities in an Interconnection, 

and accordingly this standard should 

also apply to reliability coordinators. 

Similarly, staff noted that Requirement 

R5, which requires each purchasingselling entity to arrange for reactive 

resources to satisfy its reactive 

requirements identified by its 

transmission service provider, does not 

currently apply to load-serving entities, 

even though a load-serving entity is 

responsible for significantly more load 

than a purchasing-selling entity. 

Therefore, the Reliability Standard 

should also apply to load-serving 

entities. 

1135. Finally, staff noted that the 

proposed reliability standard does not 

address Recommendation No. 23 of the 

Blackout Report, ‘‘[s]trengthen reactive 

power and voltage control practices in 

all NERC regions.’’ 335 However, staff 

noted that NERC did respond to the 

recommendation by establishing the 

Transmission Issues Subcommittee 

(TIS) which completed an evaluation of 

reactive power planning and voltage 

control practices. 

iii. Comments 

1136. NERC states that the proposed 

reactive power and voltage control 


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336 VAR–001–1, Requirement R2. 

337 VAR–001–1, Requirement R8. 

338See Staff Preliminary Assessment at 118, 

citing Blackout Report at 36 (‘‘voltage magnitude 

alone is a poor indicator of voltage stability’’). 

339WECC’s Reliability Criteria at 32 states ‘‘For 

transfer paths, post-transient voltage stability is 

required with the path modeled at a minimum of 

105% of the path rating (or Operational Transfer 

Capability) for system normal conditions (Category 

A) and for single contingencies (Category B). For 

multiple contingencies (Category C), post-transient 

voltage stability is required with the path modeled 

at a minimum of 102.5% of the path rating (or 

Operational Transfer Capability). 

340See http://www.NERC.com/pub/sys/all_updl/ 

pc/tis/TIS_Reactive_Recom7a_BOTapprvd_050305. 

341 VAR–001–1 Requirement R3 requires 

transmission owners to specify criteria that exempt 

generators from complying with Requirement R4. 

Requirement R4 requires transmission owners to 

specify a voltage or reactive power schedule to be 

maintained by generators. Requirement R11 

requires transmission operators to provide 

documentation to generator owners on necessary 

step-up transformer tap changes. 342NERC glossary at 9. 

Reliability Standard is adequate and 

necessary to protect the reliability of the 

Bulk-Power System. It points out that, 

in addition to the proposed Reliability 

Standard, a number of other Version 0 

standards in the IRO, TOP, and TPL 

series address reactive power and 

voltage control requirements and 

suggests that the proposed Reliability 

Standards should be viewed in their 

entirety in assessing their adequacy. 

1137. Nonetheless, NERC states that 

staff is correct that additional 

consideration regarding the 

development of the Reliability Standard 

related to reactive power and voltage 

control, reactive reserves, and the 

related subject of under-voltage load 

shedding is required. It explains that, in 

response to the Blackout Report 

recommendations related to reactive 

power and voltage control, the NERC 

Planning Committee prepared a report 

titled ‘‘Evaluation of Reactive Power 

Planning and Voltage Control 

Practices,’’ which was accepted by the 

NERC board of Trustees in May 2005. 

NERC states that it is committed to 

developing, as a high priority, new 

Reliability Standards that will 

incorporate the recommendations of the 

Planning Committee’s report. NERC 

does not agree with the Staff 

Preliminary Assessment concerning the 

lack of applicability of the standard to 

load-serving entities. NERC contends 

that a load-serving entity that purchases 

outside resources to serve its load and 

uses transmission service to import that 

energy acts as a purchasing-selling 

entity and must arrange reactive support 

services pursuant to VAR–001–0. 

1138. ReliabilityFirst, on the other 

hand, agrees with staff’s concern that 

the proposed Reliability Standard 

should apply to load-serving entities 

and reliability coordinators. As a 

general matter and in the specific 

context of the proposed Reliability 

Standard, ReliabilityFirst states the 

work by NERC’s drafting team to 

develop missing compliance elements 

must be expedited. In addressing staff’s 

primary issues with this standard, 

ReliabilityFirst states that acceptable 

variations in voltage used by operating 

personnel should be minimized by the 

development of more defined terms. 

iv. Commission Proposal 

1139. The Commission proposes to 

approve VAR–001–1 as mandatory and 

enforceable. In addition, we propose to 

direct that NERC develop modifications 

to the Reliability Standard, as discussed 

below. 

1140. As explained in the Staff 

Preliminary Assessment, the proposed 

Reliability Standard requires a 

transmission owner to ‘‘acquire 

sufficient reactive resources within its 

area to protect the voltage levels under 

normal and Contingency conditions’’ 336

and ‘‘maintain system and 

Interconnection voltages within 

established limits.’’ 337 In the 

Commission’s view, technical 

requirements containing terms such as 

‘‘established limits’’ or ‘‘sufficient 

reactive resources’’ are not definitive 

enough to address voltage instability 

and to ensure reliable operations.338 As 

an example of the Commission’s 

concept of a more effective requirement, 

NERC should consider WECC’s 

Reliability Criteria, which contain 

specific and definitive technical 

requirements on voltage and margin 

application.339 The Commission’s view 

is also consistent with the NERC 

Transmission Issue Subcommittee’s 

findings in its ‘‘Evaluation of Reactive 

Power Planning and Voltage Control 

Practices.’’ 340 The Commission notes 

that VAR–001–1, while adding three 

new Requirements that apply to 

transmission operators regarding voltage 

and reactive control, still lacks the 

specific and technical Requirements on 

voltage and margin application to 

prevent voltage instability.341 Therefore, 

the Commission proposes directing 

NERC to modify VAR–001–1 to include 

more detailed and definitive 

requirements on ‘‘established limits’’

and ‘‘sufficient reactive resources’’ to 

prevent voltage instability and to ensure 

reliable operations. These requirements 

for ensuring voltage stability shall be 

included in operations planning studies 

and real-time assessment in addition to 

real time operation. 

1141. While real-time operations are 

covered by other standards, the 

requirement to perform periodic voltage 

stability analysis in real-time operations 

is not directly addressed. Because of its 

importance to Bulk-Power System 

reliability, as discussed in section ii 

above, the Commission proposes that it 

be directly addressed in VAR–001–1. 

1142. Section 215(b) of the FPA 

provides that users, owners and 

operators of the Bulk-Power System 

must comply with a Commissionapproved Reliability Standard. As 

discussed above, NERC’s proposed 

Reliability Standards identify the 

entities to which a particular Reliability 

Standard would apply according to the 

NERC Functional Model. According to 

NERC’s proposal, VAR–001–1 would 

apply to transmission operators and 

purchasing-selling entities. In 

Requirement R5, purchasing-selling 

entities are required to arrange for 

reactive resources to satisfy their 

reactive requirements as identified by 

their transmission service provider. 

Because purchasing-selling entities are 

either self-providing or purchasing the 

reactive resources, they are clearly users 

of the Bulk-Power System. 

1143. The Commission believes that 

NERC’s proposed applicability 

provision in VAR–001–1, in terms of the 

Functional Model, should be expanded 

to include ‘‘reliability coordinators’’ and 

‘‘load-serving entities.’’ According to 

NERC’s petition, ‘‘load-serving entities’’

are energy providers for end use 

customers, and NERC’s functional 

model defines the load serving function 

as responsible for ‘‘secur[ing] energy 

and transmission service (and related 

Interconnected Operations Services) to 

serve the end-use customer.’’ 342

Reliability coordinators and loadserving entities are operators and users 

of the bulk-power system respectively, 

and should be included in the 

applicability of this standard as 

discussed in more detail below. 

1144. In a complex power grid such 

as the one which exists in North 

America, reliable operations can only be 

ensured by coordinated efforts from all 

operating entities in long term planning, 

operational planning and real time 

operations. To that end, the Staff 

Preliminary Assessment recommended 

(and ReliabilityFirst concurred) that the 

applicability of this proposed Reliability 

Standard extend to both reliability 

coordinators and load-serving entities. 

Since reliability coordinators are the 

highest level of authority overseeing the 

reliability of the Bulk-Power System, it 

is important to include them as an 

applicable entity to maintain adequate 

voltage and reactive resources. As for 

load-serving entities, NERC states that 


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343See Principles of Efficient and Reliable 

Reactive Power Supply and Consumption: FERC 

Staff Report (2005). 344Staff Preliminary Assessment at 25–26. 

VAR–001–0 (and NERC’s statement 

applies equally to VAR–001–1) is 

indirectly applicable to a load-serving 

entity in its role as a purchasing-selling 

entity to the extent that it purchases 

outside resources to serve its load and 

uses transmission service to import that 

energy. Although the Commission 

agrees with this statement to the extent 

that a load-serving entity is purchasing 

point-to-point transmission service to 

serve its load, it is not clear that a loadserving entity would become a 

purchasing-selling entity when utilizing 

network service to meet its load 

obligations. The Commission is 

interested in comments concerning 

NERC’s assertion that all load serving 

entities are also purchasing-selling 

entities. 

1145. We propose directing NERC to 

add reliability coordinators and loadserving entities to the existing list of 

applicable entities for VAR–001–1 for 

added clarity. VAR–001–1 recognizes 

that energy purchases of purchasingselling entities can increase reactive 

power consumption on the Bulk-Power 

System and that they must supply what 

they consume. Load-serving entities also 

consume reactive power. We note that 

in many cases load response and loadside investment can reduce the need for 

reactive power capability in the 

system.343 Therefore, we propose to 

include controllable load among the 

reactive resources to satisfy reactive 

requirements. 

1146. We are also interested in 

comments on the acceptable ranges of 

net power factor range at the interface 

that the load serving entities receive 

service from the Bulk-Power System 

during normal and extreme load 

conditions. 

1147. While the Commission has 

identified a number of concerns with 

regard to VAR–001–1, we believe that 

the proposal serves an important 

purpose in requiring users, owners and 

operators of the Bulk-Power System to 

maintain facilities within voltage limits. 

The Commission believes it is important 

for NERC to include Requirements 

which contain added specificity; and 

additional Requirements to perform 

voltage stability assessments during 

real-time operations. Nonetheless, the 

proposed requirements set forth in 

VAR–001–1 are sufficiently clear and 

objective to provide guidance for 

compliance. 

1148. Accordingly, giving due weight 

to the technical expertise of the ERO 

and with the expectation that the 

Reliability Standard will accomplish the 

purpose represented to the Commission 

by the ERO and that it will improve the 

reliability of the nation’s Bulk-Power 

System, the Commission proposes to 

approve Reliability Standard VAR–001–

1 as mandatory and enforceable. In 

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

of the FPA and § 39.5(f) of our 

regulations, the Commission proposes to 

direct that NERC submit a modification 

to VAR–001–1 that: (1) Includes 

detailed and definitive requirements on 

‘‘established limits’’ and ‘‘sufficient 

reactive resources’’ as discussed above, 

and identifies acceptable margins above 

the voltage instability points; (2) 

includes Requirements to perform 

voltage stability assessments 

periodically during real-time operations; 

and (3) expands the applicability to 

include reliability coordinators and 

load-serving entities. 

1149. The Commission commends 

NERC and industry for their efforts in 

expanding on Requirement R9, which 

applied to generator operators in VAR–

001–0, and making it into several 

detailed Requirements in VAR–002–1, 

which apply to generator operators and 

generator owners, complete with 

Measures and Levels of NonCompliance to ensure appropriate 

generation operation to maintain 

network voltage schedules. 

1150. Accordingly, the Commission 

believes that Reliability Standard VAR–

002–1 is just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest; and proposes to 

approve it as mandatory and 

enforceable. 

14. Glossary of Terms Used in 

Reliability Standards 

a. NERC Proposal 

1151. In its petition, NERC submitted, 

and requested approval of the Glossary 

of Terms Used in Reliability Standards. 

NERC states that the glossary, which 

defines terms used in Reliability 

Standards, initially became effective on 

April 1, 2005. The glossary is updated 

whenever a new or revised Reliability 

Standards is approved that includes a 

new term or definition. The glossary 

may also be approved by a separate 

action using NERC’s Reliability 

Standards development process. NERC 

updated the glossary in its August 28, 

2006 Supplemental Filing. 

b. Staff Preliminary Assessment 

1152. While staff did not globally 

address the NERC glossary, it did 

express concern regarding the definition 

of bulk electric system in the glossary. 

Staff stated that differences between the 

Bulk-Power System in section 215 of the 

FPA and the NERC definition of bulk 

electric system could create a 

discrepancy that results in reliability 

‘‘gaps.’’ 344 Further, in its discussion of 

planning (TPL) Reliability Standards, 

staff expressed concern regarding the 

statutory definition of Reliable 

Operation as it would impact the 

contingencies to be considered in 

setting system performance expectations 

set forth in the TPL standard. 

c. Comments 

1153. Commenters note that some 

glossary terms are not consistent with 

the definition for those same terms in 

the ERO’s Rules of Procedure. They 

point to the definition of regional 

reliability organization and load serving 

entity as examples. Comments on the 

term Bulk-Power System and Reliable 

Operation are included with the TPL 

chapter. 

d. Commission Proposal 

1154. The Commission believes that 

the NERC glossary is an important 

supplement to understanding the 

mandatory and enforceable Reliability 

Standards. While we are generally 

satisfied with the NERC glossary, we 

believe that it is appropriate that NERC 

modify the glossary to include terms 

defined in section 215(a) of the FPA. 

Further, in the general Applicability 

discussion we explained our specific 

concerns regarding potential differences 

between the statutory term Bulk-Power 

System and the NERC term bulk electric 

system and how to bring consistency 

between the two terms. Further, in our 

discussion of general issues concerning 

the communication (COM) Reliability 

Standards, we identified specific 

concerns regarding the definitions of 

transmission operator and generator 

operator. We propose to direct that 

NERC modify the glossary to reflect 

these concerns. 

1155. With regard to commenters 

concerns regarding the consistency of 

definitions between the glossary and the 

ERO Rules of Procedure, we believe that 

the ERO documents should be 

consistent in their definition of a 

specific term. However, we will leave it 

to the ERO’s discretion whether the 

glossary or the Rules of Procedure 

should be modified to assure 

consistency in the definition of any 

particular term. 

1156. Accordingly, the Commission 

proposes to approve the Glossary of 

Terms Used in Reliability Standards. In 

addition, we propose to direct that 

NERC submit, a modification to the 


sroberts on PROD1PC70 with PROPOSALS
64874 Federal Register / Vol. 71, No. 213 / Friday, November 3, 2006 / Proposed Rules 

345 5 CFR 1320.11. 346 44 U.S.C. 3507(d). 

glossary that: (1) Includes the statutory 

definitions of Bulk-Power System, 

Reliable Operation, Reliability Standard, 

as set forth in section 215 (a); (2) 

modifies the definitions of 

‘‘transmission operator’’ and ‘‘generator 

operator’’ to include aspects unique to 

ISO/RTO and pooled resource 

organizations; (3) modifies the 

definition of ‘‘bulk electric system’’

consistent with our discussion in the 

Common Issues section above; and (4) 

modifies the definition of terms 

concerning reserves (such as operating 

reserves) to include demand side 

management, including controllable 

load. 

IV. Information Collection Statement 

1157. The Office of Management and 

Budget (OMB) regulations require that 

OMB approve certain reporting and 

recordkeeping (collections of 

information) imposed by an agency.345

The information contained here is also 

subject to review under Section 3507(d) 

of the Paperwork Reduction Act of 

1995.346 As stated above, these 107 

proposed Reliability Standards—of 

which the Commission proposes to 

approve 83 in a final rule—make up the 

current NERC standards that the electric 

industry currently is expected to 

comply with on a voluntary basis. 

Therefore, in proposing to adopt the 

Reliability Standards, the Commission 

would adopt reporting requirements 

that have been implemented on a 

voluntary basis for many years in most 

instances. Because the reporting 

requirements are usual and customary 

practices in the industry, and 

respondents incur the time and 

financial resources in the course of their 

regular activity, the transition from 

voluntary to mandatory Reliability 

Standards effected by this Proposed 

Rule will not increase the reporting 

burden nor impose any additional 

information collection requirements. 

1158. However, we also recognize that 

there may be some smaller entities such 

as municipal utilities, cooperatives and 

small generators that may not have been 

members of NERC and may not have 

been participants in NERC’s voluntary 

standards program. For such entities, 

compliance with the proposed 

mandatory Reliability Standards will 

include compliance with reporting 

requirements for the first time. 

1159. It is difficult to determine 

exactly how many entities fall into this 

category. First, as discussed above with 

regard to applicability issues, not every 

proposed Reliability Standard would 

apply to every user, owner or operator 

of the Bulk-Power System, and each 

proposed Reliability Standard contains 

its own set of reporting requirements. 

For example, only 24 proposed 

Reliability Standards would apply to 

generators, which contain 142 reporting 

requirements. 

1160. Further, as discussed in greater 

detail below with regard to small 

business flexibility, NERC has indicated 

that it will propose specific limits on 

the applicability of Reliability Standards 

to small entities that do not have a 

material impact on the Bulk-Power 

System. While we do not pre-judge this 

proposal, we note that Commission 

acceptance of such a proposal could 

also have a significant impact on the 

reporting burden of small entities that 

have not previously complied with the 

NERC standards on a voluntary basis. 

1161. In addition, some small entities 

may join together in Joint Action 

Agencies or other such organizations 

that will be responsible for certain 

aspects of their members’ compliance 

with mandatory Reliability Standards. 

Such umbrella organizations may lessen 

the reporting burden of individual 

users, owners and operators. 

Accordingly, the reporting burden 

estimate below, while based on the 

Commission’s best information, is 

subject to numerous variables. Although 

there is considerable uncertainty 

regarding the number of entities or the 

burden on those entities for which 

compliance with reliability standards 

will be a new exercise and not a 

customary practice, the Commission 

provides below what it believes to be a 

reasonable estimate based on available 

information. 

PUBLIC REPORTING BURDEN

Data collection Number of 

respondents 

Number of 

responses 

Number of 

hours per 

response 

Total annual 

hours 

FERC–725A ..................................................................................................... 2,000 1 100 200,000 

Information Collection Costs: The 

Commission seeks comments on the 

costs on complying with these 

requirements. It has projected the 

average annualized cost to be the 

following: 

200,000 hours @ $200 an hour = $ 

40,000,000. 

1162. Title: Bulk Power System 

Mandatory Reliability Standards. 

1163. Action: Proposed Collection. 

1164. OMB Control No. To be 

Determined. 

1165. Respondents: Businesses or 

other for profit; not for profit 

institutions. 

1166. Frequency of Responses: On 

Occasion. 

1167. Necessity of the Information: 

This proposed rule implements section 

215(d)(2) of the FPA, which provides 

that the Commission may approve a 

proposed Reliability Standard if it 

determines that the proposal is just, 

reasonable, not unduly discriminatory 

or preferential, and in the public 

interest. 

1168. Internal Review: The 

Commission has reviewed the proposed 

reliability standards and made a 

determination that these requirements 

are necessary to implement section 215 

of the Energy Policy Act of 2005. These 

requirements conform to the 

Commission’s plan for efficient 

information collection, communication 

and management within the energy 

industry. The Commission has to assure 

itself, by means of internal review, that 

there is specific, objective support for 

the burden estimates associated with the 

information requirements. 

1169. Interested person may obtain 

information on the reporting 

requirements by contacting the 

following: Federal Energy Regulatory 

Commission, 888 First Street, NE., 

Washington, DC 20426 [Attention: 

Michael Miller, Office of the Executive 

Director, Phone: (202) 502–8415, fax: 

(202) 273–0873, e-mail: 

michael.miller@ferc.gov. 

1170. For submitting comments 

concerning the collection(s) of 

information and the associated burden 

estimate(s), please send your comments 

to the contact listed above and to the 

Office of Information and Regulatory 

Affairs, Office of Information and 

Regulatory Affairs, Washington, DC 


sroberts on PROD1PC70 with PROPOSALS
Federal Register / Vol. 71, No. 213 / Friday, November 3, 2006 / Proposed Rules 64875 

347Regulations Implementing the National 

Environmental Policy Act, Order No. 486, 52 FR 

47,897 (Dec. 17, 1987), FERC Stats. & Regs., 

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

348 18 CFR 380.4(a)(5). 

349 5 U.S.C. 601–12. 

350See NERC Petition at 9–10. 

351 Id. at 81–82. 

352 Id. at 10. 

353Order No. 672 at P 330. 

354See, discussion of Applicability to Small 

Entities, section III.B.3. above. 

20503 [Attention: Desk Officer for the 

Federal Energy Regulatory Commission, 

phone (202) 395–4650, fax: (202) 395–

7285, e-mail: 

oira_submission@omb.eop.gov. 

V. Environmental Analysis 

1171. 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.347 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.348

VI. Regulatory Flexibility Act 

Certification 

1172. The Regulatory Flexibility Act 

of 1980 (RFA) 349 requires that a 

rulemaking contain either a description 

and analysis of the effect that the 

proposed rule will have on small 

entities or a certification that the rule 

will not have a significant economic 

impact on a substantial number of small 

entities. The RFA mandates 

consideration of regulatory alternatives 

that accomplish the stated objectives of 

a proposed rule and that minimize any 

significant economic impact on a 

substantial number of small entities and 

sends the certification to the Chief 

Counsel for Advocacy of the Small 

Business Administration (SBA). The 

SBA’s Office of Size Standards develops 

the numerical definition of a small 

business. (See 13 CFR 121.201.) For 

electric utilities, a firm is small if, 

including its affiliates, it is primarily 

engaged in the transmission, generation 

and/or distribution of electric energy for 

sale and its total electric output for the 

preceding 12 months did not exceed 

four million megawatt hours. 

1173. Section 215(b) of the FPA 

requires all users, owners and operators 

of the Bulk-Power System to comply 

with Commission-approved Reliability 

Standards. As discussed above, each 

proposed Reliability Standard submitted 

for approval by NERC applies to some 

subset of users, owners and operators. 

Each proposed Reliability Standard 

includes an ‘‘applicability’’ statement 

that identifies the functional classes of 

entities responsible for compliance. 

Such functional classes include 

reliability coordinators, balancing 

authorities, transmission operators, 

transmission owners, generator 

operators, generator owners, interchange 

authorities, transmission service 

providers, market operators, planning 

authorities, transmission planners, 

resource planners, load-serving entities, 

purchasing-selling entities, and 

distribution providers.350

1174. As explained by NERC, a 

generator operator, for example, could 

include any entity that operates a 

generator interconnected to the grid, be 

it a large unit in excess of 1,000 MW or 

a small generator of one MW or less. 

NERC states that to ensure that 

Reliability Standards are applied cost 

effectively and that the applicability of 

Reliability Standards is focused on 

entities having a material impact on 

Bulk-Power System reliability; it will 

begin providing greater specificity in the 

applicability section of a Reliability 

Standard.351 For example, a Reliability 

Standard may identify limitations on 

applicability based on electric facility 

characteristics, such as generators with 

a minimum nameplate rating or a 

transmission facility energized at a 

specified kV level or greater.352 NERC 

plans to establish a set of guidelines to 

address this matter. 

1175. The Commission believes that 

the proposed Reliability Standards may 

cause some small entities to experience 

significant economic impact. While the 

Commission is mindful of the possible 

impact on small entities, the 

Commission is also concerned that 

Bulk-Power System reliability not be 

compromised based on an 

unwillingness of entities, large or small, 

to incur reasonable expenditures 

necessary to preserve such reliability. 

As we explained in Order No. 672: 

A proposed Reliability Standard may take 

into account the size of the entity that must 

comply with the Reliability Standard and the 

cost to those entities of implementing the 

proposed Reliability Standard. However, the 

ERO should not propose a ‘‘lowest common 

denominator’’ Reliability Standard that 

would achieve less than excellence in 

operating system reliability solely to protect 

against reasonable expenses for supporting 

this vital national infrastructure. For 

example, a small owner or operator of the 

Bulk Power-System must bear the cost of 

complying with each Reliability Standard 

that applies to it.353

1176. While we cannot rule on the 

merits until a specific proposal has been 

submitted, we believe that reasonable 

limits on applicability based on size 

may be an acceptable alternative to 

lessen the economic impact on the 

proposed rule on small entities.354 We 

emphasize, however, that any such 

limits must not weaken Bulk-Power 

System reliability. 

VII. Comment Procedures 

1177. The Commission invites 

interested persons to submit comments 

on the matters and issues proposed in 

this notice to be adopted, including any 

related matters or alternative proposals 

that commenters may wish to discuss. 

Comments are due January 2, 2007. 

Comments must refer to Docket No. 

RM06–16–000, and must include the 

commenter’s name, the organization 

represented, if applicable, and the 

commenter’s address. Comments may be 

filed either in electronic or paper 

format. 

1178. Comments may be filed 

electronically via the eFiling link on the 

Commission’s Web site at http:// 

www.ferc.gov. The Commission accepts 

most standard word processing formats 

and commenters may attach additional 

files with supporting information in 

certain other file formats. Commenters 

filing electronically do not need to make 

a paper filing. Commenters that are not 

able to file comments electronically 

must send an original and fourteen (14) 

copies of their comments to: Federal 

Energy Regulatory Commission, Office 

of the Secretary, 888 First Street, NE., 

Washington, DC 20426. 

VIII. Document Availability 

1179. In addition to publishing the 

full text of this document in the Federal 

Register, the Commission provides all 

interested persons an opportunity to 

view and/or print the contents of this 

document via the Internet through 

FERC’s Home Page (http://www.ferc.gov) 

and in FERC’s Public Reference Room 

during normal business hours (8:30 a.m. 

to 5 p.m. Eastern time) at 888 First 

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

20426. 

1180. From the Commission’s Home 

Page on the Internet, this information is 

available in the Commission’s document 

management system, 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. 

1181. User assistance is available for 

eLibrary and the FERC’s Web site during 

normal business hours. For assistance, 

please contact FERC Online Support at 


sroberts on PROD1PC70 with PROPOSALS
64876 Federal Register / Vol. 71, No. 213 / Friday, November 3, 2006 / Proposed Rules 

1–866–208–3676 (toll free) or 202–502–

6652 (e-mail at 

FERCOnlineSupport@FERC.gov), or the 

Public Reference Room at 202–502–

8371, TTY 202–502–8659 (e-mail at 

public.referenceroom@ferc.gov). 

List of Subjects in 18 CFR Part 40 

Electric power, Reporting and 

recordkeeping requirements. 

By direction of the Commission. 

Magalie R. Salas, 

Secretary. 

In consideration of the foregoing, the 

Commission proposes to amend Chapter 

I, Title 18, Code of Federal Regulations, 

by adding part 40 to read as follows: 

PART 40—MANDATORY RELIABILITY 

STANDARDS FOR THE BULK-POWER 

SYSTEM 

Sec. 

40.1 Applicability. 

40.2 Mandatory Reliability Standards. 

40.3 Availability of Reliability Standards. 

Authority: 16 U.S.C. 824o. 

§ 40.1 Applicability. 

(a) This part applies to all users, 

owners and operators of the Bulk-Power 

System within the United States (other 

than Alaska or Hawaii), including, but 

not limited to, entities described in 

section 201(f) of the Federal Power Act. 

(b) Each Reliability Standard made 

effective by § 40.2 must identify the 

subset of users, owners and operators of 

the Bulk-Power System to which a 

particular Reliability Standard applies. 

§ 40.2 Mandatory Reliability Standards. 

(a) Each applicable user, owner or 

operator of the Bulk-Power System must 

comply with Commission-approved 

Reliability Standards developed by the 

North American Electric Reliability 

Corporation which can be obtained from 

the Commission’s Public Reference 

Room at 888 First Street, NE., Room 2A, 

Washington, DC 20426. 

(b) A proposed modification to a 

Reliability Standard proposed to 

become effective pursuant to § 39.5 of 

this Chapter will not be effective until 

approved by the Commission. 

§ 40.3 Availability of Reliability Standards. 

The Electric Reliability Organization 

must make each effective Reliability 

Standard available on its Internet Web 

site. 

Note: The following appendices will not be 

published in the Code of Federal 

Regulations. 

APPENDIX A.—PROPOSED DISPOSITION OF STANDARDS, GLOSSARY AND REGIONAL DIFFERENCES

Reliability standard Title Proposed disposition 

BAL–001–0 ................ Real Power Balancing Control Performance ..................................... Approve. 

BAL–002–0 ................ Disturbance Control Performance ...................................................... Approve; direct modification. 

BAL–003–0 ................ Frequency Response and Bias .......................................................... Approve; direct modification. 

BAL–004–0 ................ Time Error Correction ........................................................................ Approve; direct modification. 

BAL–005–0 ................ Automatic Generation Control ............................................................ Approve; direct modification. 

BAL–006–1 ................ Inadvertent Interchange ..................................................................... Approve; direct modification. 

CIP–001–0 ................. Sabotage Reporting ........................................................................... Approve; direct modification. 

COM–001–0 .............. Telecommunications .......................................................................... Approve; direct modification. 

COM–002–1 .............. Communications and Coordination .................................................... Approve; direct modification.

EOP–001–0 ............... Emergency Operations Planning ....................................................... Approve; direct modification. 

EOP–002–1 ............... Capacity and Energy Emergencies ................................................... Approve; direct modification.

EOP–003–0 ............... Load Shedding Plans ......................................................................... Approve; direct modification. 

EOP–004–0 ............... Disturbance Reporting ....................................................................... Approve; direct modification. 

EOP–005–1 ............... System Restoration Plans .................................................................. Approve; direct modification. 

EOP–006–0 ............... Reliability Coordination—System Restoration ................................... Approve; direct modification. 

EOP–007–0 ............... Establish, Maintain, and Document a Regional Blackstart Capability 

Plan.

Pending. 

EOP–008–0 ............... Plans for Loss of Control Center Functionality .................................. Approve; direct modification. 

EOP–009–0 ............... Documentation of Blackstart Generating Unit Test Results .............. Approve. 

FAC–001–0 ............... Facility Connection Requirements ..................................................... Approve. 

FAC–002–0 ............... Coordination of Plans for New Facilities ............................................ Approve; direct modification. 

FAC–003–1 ............... Transmission Vegetation Management Program .............................. Approve; direct modification. 

FAC–004–0 ............... Methodologies for Determining Electrical Facility Ratings ................ Withdrawn. 

FAC–005–0 ............... Electrical Facility Ratings for System Modeling ................................. Withdrawn. 

FAC–008–1 ............... Facility Ratings Methodology ............................................................. Approve; direct modification. 

FAC–009–1 ............... Establish and Communicate Facility Ratings .................................... Approve. 

FAC–012–1 ............... Transfer Capabilities Methodology .................................................... Pending. 

FAC–013–1 ............... Establish and Communicate Transfer Capabilities ............................ Approve; direct modification. 

INT–001–1 ................. Interchange Transaction Tagging ...................................................... Approve; direct modification. 

INT–002–0 ................. Interchange Transaction Tag Communication and Assessment ....... Withdrawn. 

INT–003–1 ................. Interchange Transaction Implementation ........................................... Approve; direct modification. 

INT–004–1 ................. Interchange Transaction Modifications .............................................. Approve; direct modification. 

INT–005–1 ................. Interchange Authority Distributes Arranged Interchange ................... Approve; direct modification. 

INT–006–1 ................. Response to Interchange Authority ................................................... Approve; direct modification. 

INT–007–1 ................. Interchange Confirmation ................................................................... Approve. 

INT–008–1 ................. Interchange Authority Distributes Status ........................................... Approve. 

INT–009–1 ................. Implementation of Interchange .......................................................... Approve. 

INT–010–1 ................. Interchange Coordination Exceptions ................................................ Approve. 

IRO–001–0 ................ Reliability Coordination—Responsibilities and Authorities ................ Approve; direct modification. 

IRO–002–0 ................ Reliability Coordination—Facilities ..................................................... Approve; direct modification. 

IRO–003–1 ................ Reliability Coordination—Wide Area View ......................................... Approve; direct modification. 

IRO–004–1 ................ Reliability Coordination—Operations Planning .................................. Approve; direct modification. 

IRO–005–1 ................ Reliability Coordination—Current Day Operations ............................ Approve; direct modification. 

IRO–006–3 ................ Reliability Coordination—Transmission Loading Relief ..................... Approve; direct modification. 

IRO–014–1 ................ Procedures, Processes, or Plans to Support Coordination Between 

Reliability Coordinators.

Approve. 


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APPENDIX A.—PROPOSED DISPOSITION OF STANDARDS, GLOSSARY AND REGIONAL DIFFERENCES—Continued 

Reliability standard Title Proposed disposition 

IRO–015–1 ................ Notifications and Information Exchange Between Reliability Coordinators.Approve. 

IRO–016–1 ................ Coordination of Real-time Activities Between Reliability Coordinators.Approve. 

MOD–001–0 .............. Documentation of TTC and ATC Calculation Methodologies ............ Pending. 

MOD–002–0 .............. Review of TTC and ATC Calculations and Results .......................... Pending. 

MOD–003–0 .............. Procedure for Input on TTC and ATC Methodologies and Values ... Pending. 

MOD–004–0 .............. Documentation of Regional CBM Methodologies .............................. Pending. 

MOD–005–0 .............. Procedure for Verifying CBM Values ................................................. Pending. 

MOD–006–0 .............. Procedures for Use of CBM Values .................................................. Approve; direct modification. 

MOD–007–0 .............. Documentation of the Use of CBM .................................................... Approve; direct modification.

MOD–008–0 .............. Documentation and Content of Each Regional TRM Methodology .. Pending. 

MOD–009–0 .............. Procedure for Verifying TRM Values ................................................. Pending. 

MOD–010–0 .............. Steady-State Data for Transmission System Modeling and Simulation.Approve; direct modification. 

MOD–011–0 .............. Regional Steady-State Data Requirements and Reporting Procedures.Pending. 

MOD–012–0 .............. Dynamics Data for Transmission System Modeling and Simulation Approve; direct modification. 

MOD–013–1 .............. RRO Dynamics Data Requirements and Reporting Procedures ...... Pending. 

MOD–014–0 .............. Development of Interconnection-Specific Steady State System 

Models.

Pending. 

MOD–015–0 .............. Development of Interconnection-Specific Dynamics System Models Pending. 

MOD–016–1 .............. Actual and Forecast Demands, Net Energy for Load, Controllable 

DSM.

Approve; direct modification. 

MOD–017–0 .............. Aggregated Actual and Forecast Demands and Net Energy for 

Load.

Approve; direct modification. 

MOD–018–0 .............. Reports of Actual and Forecast Demand Data ................................. Approve. 

MOD–019–0 .............. Forecasts of Interruptible Demands and DCLM Data ....................... Approve; direct modification. 

MOD–020–0 .............. Providing Interruptible Demands and DCLM Data ............................ Approve; direct modification. 

MOD–021–0 .............. Accounting Methodology for Effects of Controllable DSM in Forecasts.Approve; direct modification. 

MOD–024–1 .............. Verification of Generator Gross and Net Real Power Capability ...... Pending. 

MOD–025–1 .............. Verification of Generator Gross and Net Reactive Power Capability Pending. 

PER–001–0 ............... Operating Personnel Responsibility and Authority ............................ Approve. 

PER–002–1 ............... Operating Personnel Training ............................................................ Approve; direct modification. 

PER–003–0 ............... Operating Personnel Credentials ....................................................... Approve; direct modification. 

PER–004–0 ............... Reliability Coordination—Staffing ....................................................... Approve; direct modification. 

PRC–001–0 ............... System Protection Coordination ........................................................ Approve; direct modification. 

PRC–002–0 ............... Define and Document Disturbance Monitoring Equipment Requirements.Pending. 

PRC–003–1 ............... Regional Requirements for Analysis of Misoperations of Transmission and Generation Protection Systems.Pending. 

PRC–004–1 ............... Analysis and Mitigation of Transmission and Generation Protection 

System Misoperations.

Approve. 

PRC–005–1 ............... Transmission and Generation Protection System Maintenance and 

Testing.

Approve; direct modification. 

PRC–006–0 ............... Development and Documentation of Regional UFLS Programs ....... Pending. 

PRC–007–0 ............... Assuring Consistency with Regional UFLS Program ........................ Approve. 

PRC–008–0 ............... Underfrequency Load Shedding Equipment Maintenance Programs Approve; direct modification. 

PRC–009–0 ............... UFLS Performance Following an Underfrequency Event .................. Approve. 

PRC–010–0 ............... Assessment of the Design and Effectiveness of UVLS Program ..... Approve; direct modification. 

PRC–011–0 ............... UVLS System Maintenance and Testing ........................................... Approve; direct modification. 

PRC–012–0 ............... Special Protection System Review Procedure .................................. Pending. 

PRC–013–0 ............... Special Protection System Database ................................................ Pending. 

PRC–014–0 ............... Special Protection System Assessment ............................................ Pending. 

PRC–015–0 ............... Special Protection System Data and Documentation ........................ Approve. 

PRC–016–0 ............... Special Protection System Misoperations ......................................... Approve; direct modification. 

PRC–017–0 ............... Special Protection System Maintenance and Testing ....................... Approve; direct modification. 

PRC–018–1 ............... Disturbance Monitoring Equipment Installation and Data Reporting Approve. 

PRC–020–1 ............... Under-Voltage Load Shedding Program Database ........................... Pending. 

PRC–021–1 ............... Under-Voltage Load Shedding Program Data ................................... Approve. 

PRC–022–1 ............... Under-Voltage Load Shedding Program Performance ...................... Approve. 

TOP–001–0 ............... Reliability Responsibilities and Authorities ........................................ Approve; direct modification. 

TOP–002–1 ............... Normal Operations Planning .............................................................. Approve; direct modification. 

TOP–003–0 ............... Planned Outage Coordination ............................................................ Approve; direct modification. 

TOP–004–0 ............... Transmission Operations ................................................................... Approve; direct modification. 

TOP–005–1 ............... Operational Reliability Information ..................................................... Approve; direct modification. 

TOP–006–0 ............... Monitoring System Conditions ........................................................... Approve; direct modification. 

TOP–007–0 ............... Reporting SOL and IROL Violations .................................................. Approve. 

TOP–008–0 ............... Response to Transmission Limit Violations ....................................... Approve; direct modification. 

TPL–001–0 ................ System Performance Under Normal Conditions ................................ Approve; direct modification. 

TPL–002–0 ................ System Performance Following Loss of a Single BES Element ....... Approve; direct modification. 


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APPENDIX A.—PROPOSED DISPOSITION OF STANDARDS, GLOSSARY AND REGIONAL DIFFERENCES—Continued 

Reliability standard Title Proposed disposition 

TPL–003–0 ................ System Performance Following Loss of Two or More BES Elements.Approve; direct modification. 

TPL–004–0 ................ System Performance Following Extreme BES Events ...................... Approve; direct modification. 

TPL–005–0 ................ Regional and Interregional Self-Assessment Reliability Reports ...... Pending. 

TPL–006–0 ................ Assessment Data from Regional Reliability Organizations ............... Pending. 

VAR–001–1 ............... Voltage and Reactive Control ............................................................ Approve; direct modification. 

VAR–002–1 ............... Generator Operations for Maintaining Network Voltage Schedules .. Approve 

Glossary .................... Glossary of Terms Used in Reliability Standards .............................. Approve; direct modification. 

Regional Difference ... BAL–001: ERCOT: CPS2 .................................................................. Approve. 

Regional Difference ... INT–001/4: WECC Tagging Dynamic Schedules and Inadvertent 

Payback.

Pending. 

Regional Difference ... BAL–006: MISO RTO inadvertent Interchange Accounting .............. Approve. 

Regional Difference ... BAL–006: MISO/SPP Financial Inadvertent Settlement .................... Approve. 

Regional Difference ... INT–003: MISO/SPP Scheduling Agent ............................................ Approve. 

Regional Difference ... INT–003: MISO Enhanced Scheduling Agent ................................... Approve. 

Regional Difference ... INT–001/3: MISO Energy Flow Information ....................................... Approve. 

Regional Difference ... IRO–006: PJM/MISO/SPP Enhanced Congestion Management ...... Pending. 

APPENDIX B.—COMMENTERS ON STAFF PRELIMINARY ASSESSMENT

Abbreviation Commenter 

Alberta ................................................................................ Alberta Department of Energy; Alberta Utilities and Energy Board; Alberta Electric 

System Operator. 

Alcoa .................................................................................. Alcoa, Inc. and Alcoa Power Generating Company. 

Allegheny ............................................................................ Allegheny Power and Allegheny Energy Supply Company, LLC. 

Ameren Services Co .......................................................... Ameren. 

American Transmission ...................................................... American Transmission Company, LLC. 

Professor Bose ................................................................... Professor Anjan Bose. 

APPA .................................................................................. American Public Power Association. 

BG&E ................................................................................. Baltimore Gas & Electric Company. 

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

CPUC ................................................................................. Public Utilities Commission of the State of California. 

CEA .................................................................................... Canadian Electricity Association. 

Centerpoint ......................................................................... CenterPoint Energy Houston Electric, LLC. 

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

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

E.ON U.S ........................................................................... E.ON U.S. LLC. 

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

FPL Energy ........................................................................ FPL Energy. 

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

Georgia System ................................................................. Georgia System Operations Corporation. 

Hydro One .......................................................................... Hydro One Networks Inc. 

ISO/RTO Council ............................................................... The ISO/RTO Council. 

KeySpan ............................................................................. KeySpan—Ravenswood, LLC. 

LPPC .................................................................................. Large Public Power Council. 

MEAG ................................................................................. MEAG Power. 

MidAmerican ...................................................................... MidAmerican Energy Company. 

MISO .................................................................................. Midwest Independent Transmission System Operator, Inc. 

MRO ................................................................................... Midwest Reliability Organization. 

Multiple Intervenors ............................................................ Multiple Intervenors, an unincorporated association of approximately 55 large industrial, commercial and institutional end-use energy consumers with facilities in New 

York. 

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

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

NEMA ................................................................................. National Electrical Manufacturers Association. 

NERC ................................................................................. North American Electric Reliability Council. 

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

NPCC ................................................................................. Northeast Power Coordinating Council. 

NRECA ............................................................................... National Rural Electric Cooperative Association. 

NYSRC ............................................................................... New York State Reliability Council LLC. 

Ohio Consumers’ Council .................................................. Ohio Consumers’ Council. 

Old Dominion ..................................................................... Old Dominion Electric Cooperative. 

Ontario IESO ...................................................................... Ontario Independent Electricity System Operator. 

PG&E ................................................................................. Pacific Gas & Electric Company. 

PSEG Companies .............................................................. Public Service Electric & Gas Company, PSEG Energy Resources & Trade LLC, 

PSEG Power LLC. 

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

SDG&E ............................................................................... San Diego Gas & Electric Company. 

SoCal Edison ..................................................................... Southern California Edison Company. 

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


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APPENDIX B.—COMMENTERS ON STAFF PRELIMINARY ASSESSMENT—Continued 

Abbreviation Commenter 

Southwest TDU .................................................................. Southwest Transmission Dependent Utility Group. 

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

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

TVA .................................................................................... Tennessee Valley Authority. 

USDA Forest Service ......................................................... U.S. Department of Agriculture Forest Service. 

Valley Group ...................................................................... The Valley Group, Inc. 

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

WECC OIWG ..................................................................... Operating Issues Work Group, a work group of WECC’s Compliance Monitoring and 

Operating Practices Subcommittee. 

WECC/OTS ........................................................................ Operations and Training Subcommittee, a subcommittee of WECC’s Operating Committee. 

Wisconsin Electric .............................................................. Wisconsin Electric Power Company. 

APPENDIX C.—ABBREVIATIONS IN THIS DOCUMENT

ACE .................................................................................... Area Control Error. 

AGC .................................................................................... Automatic Generation Control. 

ANSI ................................................................................... American National Standards Institute. 

ATC .................................................................................... Available Transfer Capability. 

BCP .................................................................................... Blackstart Capability Plan. 

CBM ................................................................................... Capacity Benefit Margin. 

CPS .................................................................................... Control Performance Standard. 

DC ...................................................................................... Direct Current. 

DCS .................................................................................... Disturbance Control Standard. 

ERO .................................................................................... Electric Reliability Organization. 

GWh ................................................................................... Gigawatt Hour. 

IEEE ................................................................................... Institute of Electrical and Electronics Engineers. 

IROL ................................................................................... Interconnection Reliability Operating Limits. 

MW ..................................................................................... Mega Watt. 

ROW ................................................................................... Right of Way. 

SOL .................................................................................... System Operating Limit. 

SPS .................................................................................... Special Protection System. 

TIS ...................................................................................... Transmission Issues Subcommittee. 

TLR ..................................................................................... Transmission Loading Relief. 

TRM .................................................................................... Transmission Reliability Margin. 

TTC .................................................................................... Total Transfer Capability. 

UFLS .................................................................................. Under Frequency Load Shedding. 

UVLS .................................................................................. Under Voltage Load Shedding. 

APPENDIX D.—HIGH PRIORITY LIST

Reliability standard Title 

COM–001–0 ....................................................................... Telecommunications. 

COM–002–1 ....................................................................... Communications and Coordination. 

EOP–002–0 ........................................................................ Capacity and Energy Emergency. 

EOP–003–0 ........................................................................ Load Shedding Plans. 

EOP–008–0 ........................................................................ Plans for Loss of Control Center Functionality. 

FAC–003–1 ........................................................................ Vegetation Management Program. 

FAC–008–1 ........................................................................ Facility Ratings Methodology. 

IRO–003–1 ......................................................................... Reliability Coordination—Wide Area View. 

IRO–006–3 ......................................................................... Reliability Coordination—Transmission Loading Relief. 

PER–002–0 ........................................................................ Operating Personnel Training. 

PER–003–0 ........................................................................ Operating Personnel Credentials. 

PER–004–0 ........................................................................ Reliability Coordination—Staffing. 

PRC–006–0 ........................................................................ Development and Documentation of Regional UFLS Programs. 

PRC–020–1 ........................................................................ Under-Voltage Load Shedding Program Database. 

TOP–006–0 ........................................................................ Monitoring System Conditions. 

VAR–001–1 ........................................................................ Voltage and Reactive Control. 

[FR Doc. 06–8927 Filed 11–2–06; 8:45 am] 

BILLING CODE 6717–01–P 


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