117 FERC ¶61,084 

UNITED STATES OF AMERICA 

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. 

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 whollyowned 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 
Docket No. RM06-16-000 ii 

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 website for public inspection. 

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

REGISTER]. 

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 N.E., Washington, DC, 

20426. Refer to the Comment Procedures section of the preamble for additional 

information on how to file paper comments. 
Docket No. RM06-16-000 iii 

FOR FURTHER INFORMATION CONTACT: 

Jonathan First (Legal Information) 

Office of the General Counsel 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, D.C. 20426 

(202) 502-8529 

Paul Silverman (Legal Information) 

Office of the General Counsel 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, D.C. 20426 

(202) 502-8683 

Robert Snow (Technical Information) 

Office of Energy Markets and Reliability 

Division of Reliability 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, D.C. 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, N.E. 

Washington, D.C. 20426 

(202) 502-8923 

SUPPLEMENTARY INFORMATION

:
UNITED STATES OF AMERICA 117 FERC ¶61,084 

FEDERAL ENERGY REGULATORY COMMISSION 

Mandatory Reliability Standards for the 

Bulk-Power System 

Docket No. RM06-16-000 

NOTICE OF PROPOSED RULEMAKING 

(October 20, 2006) 

 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.

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

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

4. Technical Adequacy..........................................................................................113.
Docket No. RM06-16-000 - 2 - 

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 .............................................264.

5. FAC: Facilities Design, Connections, Maintenance, and Transfer Capabilities344.

6. INT: Interchange Scheduling and Coordination .............................................428.

7. IRO: Interconnection Reliability Operations and Coordination .....................498.

8. MOD: Modeling, Data, and Analysis...............................................................589.

9. PER: Personnel Performance, Training and Qualifications .............................753.

10. PRC: Protection and Control .........................................................................806.

11. TOP: Transmission Operations .....................................................................955.

12. TPL: Transmission Planning .......................................................................1041.

13. VAR: Voltage and Reactive Control............................................................1133.

14. Glossary of Terms Used in Reliability Standards .........................................1153.

IV. Information Collection Statement..........................................................................1159.

V. Environmental Analysis ..........................................................................................1173.

VI. Regulatory Flexibility Act Certification ................................................................1174.

VII. Comment Procedures............................................................................................1179.

VIII. Document Availability ........................................................................................1181.

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 

(October 20, 2006) 

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-
Docket No. RM06-16-000 - 3 - 

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 
Docket No. RM06-16-000 - 4 - 

will be maintained in the Commission’s Public Reference Room and on the ERO’s 

Internet website 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 

 1

 The 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). 

2

 Rules 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). 
Docket No. RM06-16-000 - 5 - 

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 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. 

 3

 The 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. 

4

 ERO Certification Order, 116 FERC ¶ 61,062. 
Docket No. RM06-16-000 - 6 - 

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 BulkPower 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. 

 5

 See NERC Petition at 69. 

6

 16 U.S.C. 824o (d)(2). 
Docket No. RM06-16-000 - 7 - 

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 Bulk-Power 

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 

 7

 NERC Petition at 25. 
Docket No. RM06-16-000 - 8 - 

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 

 8

 See id. at 87-90. 

9

 The 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 continentwide standard should not result in a lowest common denominator. Order No. 672 at P 

291. 
Docket No. RM06-16-000 - 9 - 

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 Bulk-Power 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 

 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). 
Docket No. RM06-16-000 - 10 - 

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 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. 

 11 The 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). 

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. 
Docket No. RM06-16-000 - 11 - 

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 non-compliance 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, 

 13 The 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. 

14 See id. at 140-42. 

15 Order 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. 

16 Section 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 

(continued) 
Docket No. RM06-16-000 - 12 - 

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 

 

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). 

17 The Commission can independently enforce Reliability Standards. 16 U.S.C. 

824o (e)(3). 

18 Order No. 672 at P 262, 321-337. 
Docket No. RM06-16-000 - 13 - 

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 

 19 Order No. 672 at P 329. 
Docket No. RM06-16-000 - 14 - 

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 Interconnection-wide 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 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 

 20 Order No. 672 at P 332. 

21 Id. at P 337. 

22 18 CFR 39.5(c)(1), (3). 
Docket No. RM06-16-000 - 15 - 

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, industry-sponsored 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 18 CFR 39.5(a). 

24 18 CFR 39.5(e). 
Docket No. RM06-16-000 - 16 - 

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 

 25 Although the ERO Certification Order directs NERC to modify the pro forma

delegation agreement, the pro forma agreement will not be re-filed 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. 

26 The 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 website, 

http://www.nerc.com/~filez/nerc_filings_ferc.html. 
Docket No. RM06-16-000 - 17 - 

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. 

 27 See NERC Petition at 28. 
Docket No. RM06-16-000 - 18 - 

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

 

 28 NERC 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. 
Docket No. RM06-16-000 - 19 - 

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 non-compliance. 

E. Regional Differences: Identification of any regional differences that have 

been approved by the applicable NERC Committee (including Regions that 

are exempt). 
Docket No. RM06-16-000 - 20 - 

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 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-the-blank’ 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 Non-compliance 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. 
Docket No. RM06-16-000 - 21 - 

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. 
Docket No. RM06-16-000 - 22 - 

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. 
Docket No. RM06-16-000 - 23 - 

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 Bulk-Power 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, N.E., Room 2A, Washington, D.C., 20426. 
Docket No. RM06-16-000 - 24 - 

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 website. 

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 Commission-approved Reliability 

Standards that are available in the Commission’s Public Reference Room and on the 

Internet at the ERO’s website. 
Docket No. RM06-16-000 - 25 - 

41. This approach would preserve the statutory options of approving a proposed 

Reliability Standard or modification to a Reliability Standard “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-by-case basis.”30

43. We do not propose a generic definition of the term “User of the Bulk-Power 

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 

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

30 Order No. 672 at P 99. 

31 Many of the proposed Reliability Standards apply to reliability coordinators and 

balancing authorities and other clearly appropriate entities. We believe that such 

(continued) 
Docket No. RM06-16-000 - 26 - 

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 Bulk-Power System” that must comply with a specific 

Reliability Standard. 

 

Reliability Standards do not raise applicability issues. Thus, in our standard-by-standard 

analysis, the Commission’s silence as to applicability issues means that it agrees with the 

ERO’s proposed applicability of a Reliability Standard. 

32 See 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 

website at: http://www.nerc.com/~filez/functionalmodel.html. 
Docket No. RM06-16-000 - 27 - 

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 

 33 The 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. 

34 Staff Preliminary Assessment at 24. 

35 NERC 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). 
Docket No. RM06-16-000 - 28 - 

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 Commission-approved 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 

 36 ERO Certification Order, 116 FERC ¶ 61,062, at P 689. 
Docket No. RM06-16-000 - 29 - 

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 

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 

 37 For example, commenters’ concerns regarding applicability to ISOs and RTOs 

are discussed in detail in the chapter on proposed communications Reliability Standards. 

38 See NERC Rule of Procedure section 501.1.3. 

39 NERC Petition at 9. 
Docket No. RM06-16-000 - 30 - 

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. 

 40 Id. at 82. 

41 See, e.g., Alcoa, APPA, BPA and TAPS. 
Docket No. RM06-16-000 - 31 - 

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? 

 42 For example, a dedicated phone line that would remain operative during a power 

failure may suffice for a small cooperative with minimal Bulk-Power System facilities, 

while a large investor-owned utility may need a sophisticated communication system 

with redundancy and diverse routing requirements. 
Docket No. RM06-16-000 - 32 - 

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 standardby-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-inthe-blank” Reliability Standards. Many of the proposed Reliability Standards that have 

compliance measures refer to the regional reliability organization as a compliance 

monitor. 

 43 NERC 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. 
Docket No. RM06-16-000 - 33 - 

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 Bulk-Power 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 

 44 Pursuant to NERC’s ERO application, a member “accepts the responsibility to 

promote, support, and comply with the Bylaws, Rules of Procedure, and Reliability 

Standards....” 
Docket No. RM06-16-000 - 34 - 

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 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 

 45 BAL-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, MOD014, MOD-015, MOD-016, MOD-024, MOD-025, PRC-002, PRC-003, PRC-006, PRC012, PRC-013, PRC-014, PRC-020, TPL-005, and TPL-006. 
Docket No. RM06-16-000 - 35 - 

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 information47 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. 

 46 BAL-002, EOP-004, FAC-003, IRO-001, and MOD-016. Three of these (EOP004, FAC-003 and MOD-016) are “data-gathering” or “process-type” Reliability 

Standards. 

47 EOP-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).
Docket No. RM06-16-000 - 36 - 

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 fill-in-the-blank standards. 

5. Bulk-Power System v. Bulk Electric System

60. As noted above, Commission-approved Reliability Standards are to provide for the 

Reliable Operation of the Bulk-Power System. Generally speaking, the Nation’s BulkPower 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 

 49 MOD-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. 
Docket No. RM06-16-000 - 37 - 

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 Commission-approved 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 

 51 16 U.S.C. 824o (a)(1). 
Docket No. RM06-16-000 - 38 - 

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 Bulk-Power 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 

 52 See NERC Petition, Exhibit A, NERC glossary at 2. 

53 Staff 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. 
Docket No. RM06-16-000 - 39 - 

facilities necessary for Bulk-Power 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 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 Operation55 in section 215 of the FPA to further the objective of maintaining the 

 54 Staff review of selected Form No. 1 reports filed with the Commission indicates 

that 25 percent or more of many public utilities’ total transmission 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. 

55 As 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. 
Docket No. RM06-16-000 - 40 - 

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 

 56 We 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. 
Docket No. RM06-16-000 - 41 - 

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. 
Docket No. RM06-16-000 - 42 - 

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 

 57 Order No. 672 at P 262, 321-37. 

58 Id. at P 345. 
Docket No. RM06-16-000 - 43 - 

balance any conflict between a proposed Reliability Standard and competition on a caseby-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 presume that a 

proposed Reliability Standard developed through an ANSI-certified process 

automatically satisfies the statutory standard of review.62 While an open and transparent 

 59 Id. at P 378. 

60 NERC 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. 

62 Order No. 672 at P 338. 
Docket No. RM06-16-000 - 44 - 

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 

 63 ERO Certification Order, 116 FERC ¶ 61,062, at P 241. 

64 Order No. 672 at P 262, 321-37. 
Docket No. RM06-16-000 - 45 - 

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 of 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 

 65 See 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. 
Docket No. RM06-16-000 - 46 - 

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 

 67 See 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 USC 

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.” 
Docket No. RM06-16-000 - 47 - 

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 

 68 See 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”). 
Docket No. RM06-16-000 - 48 - 

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 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. 

 69 Order No. 672 at P 329. 
Docket No. RM06-16-000 - 49 - 

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 

 70 See Appendix D (High Priority List). 
Docket No. RM06-16-000 - 50 - 

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 

 71 See, e.g., Alberta, APPA, ISO/RTO Council, PSEG, WIRAB and WECC. 
Docket No. RM06-16-000 - 51 - 

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 

 72 ERO Certification Order, 116 FERC ¶ 61,062, at P 462. 
Docket No. RM06-16-000 - 52 - 

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. 67273 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 

 73 See Order No. 672 at P 400. 

74 ERO Certification Order, 116 FERC ¶ 61,062, at P 286. 
Docket No. RM06-16-000 - 53 - 

be necessary to expedite processing a proposed Reliability Standard that must be 

remanded. The Commission believes 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. 

 75 See Staff Preliminary Assessment at 17-26. 
Docket No. RM06-16-000 - 54 - 

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 Bulk-Power 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 

 76 Blackout Report at Chapter 10. 
Docket No. RM06-16-000 - 55 - 

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 

 77 NERC Comments at 40. 
Docket No. RM06-16-000 - 56 - 

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 Non-Compliance

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 Measures78 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 

 78 Although 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 non-compliance with a Reliability Standard. The levels of non-compliance 

range from Level 1 to Level 4, with Level 4 being the most severe. 
Docket No. RM06-16-000 - 57 - 

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 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 Non-Compliance 

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, 

 80 See NERC Comments at 105 (“Metrics of satisfactory performance are defined 

in the requirements . . . .”). 

81 See, e.g., National Grid and BPA. 
Docket No. RM06-16-000 - 58 - 

including the severity of a violation for penalty setting-purposes, 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 Non-Compliance. 

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, 

 82 NERC Comments at 104. See also NERC Petition at 83. 
Docket No. RM06-16-000 - 59 - 

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 

 83 Notably, 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. 

84 Staff Preliminary Assessment at 18-19. 

85 NERC Petition at 90-91; NERC Comments at 101-02. 
Docket No. RM06-16-000 - 60 - 

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 Non-Compliance 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 

 86 See, e.g., LPPC, MISO, NEMA, SDG&E and WECC. 
Docket No. RM06-16-000 - 61 - 

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. 

 87 Staff Preliminary Assessment at 19. 
Docket No. RM06-16-000 - 62 - 

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 

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. 

 88 See, e.g., NPCC, SDG&E and NYSRC. 
Docket No. RM06-16-000 - 63 - 

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 ERO-approved 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 

 89 See NERC Petition at 87-90. 

90 EOP-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. 

91 BAL-002, EOP-004, MOD-001, MOD-002, MOD-004, MOD-005, MOD-008, 

MOD-009, MOD-024, and MOD-025. 

92 EOP-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. 
Docket No. RM06-16-000 - 64 - 

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-in-the-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-the-blank 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-

 93 NERC Petition at 89. 

94 This 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, MOD012-0, 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 TPL004-0*. (* Newly identified as fill-in-the-blank standards.) 
Docket No. RM06-16-000 - 65 - 

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 fill-in-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 

 95 EOP-004-0, EOP-006-0,* and IRO-005-1.* (* Newly identified as fill-in-theblank 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. 

96 NERC Comments at 107. 
Docket No. RM06-16-000 - 66 - 

Commission and applicable authorities in Canada; (3) if mandatory enforcement of a fillin-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-in-the-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 addressed by a continentwide 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. 

 97 Order No. 672 at P 292. 

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. 
Docket No. RM06-16-000 - 67 - 

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 

 99 NERC 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.” 
Docket No. RM06-16-000 - 68 - 

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 

 100 CenterPoint Comments at 15. 
Docket No. RM06-16-000 - 69 - 

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 
Docket No. RM06-16-000 - 70 - 

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 process-oriented 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. 
Docket No. RM06-16-000 - 71 - 

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 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 Non-Compliance. 

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. 

 101 NERC 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.” 
Docket No. RM06-16-000 - 72 - 

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 BAL001-0, 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 area103 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 

 102 Each 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. 

103 At 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. 
Docket No. RM06-16-000 - 73 - 

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 continent-wide 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 

 104 Order No. 672 at P 290. 

105 Id. at P 291. 

106 Id.

107 See ERCOT Protocols, section 5 (Dispatch) at 21-23 (May 1, 2006), available 

at: http://www.ercot.com/mktrules/protocols/current.html. 
Docket No. RM06-16-000 - 74 - 

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. 

 108 The 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. 
Docket No. RM06-16-000 - 75 - 

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 

 109 A “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. 
Docket No. RM06-16-000 - 76 - 

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 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 

 110 Staff Preliminary Assessment at 30. 
Docket No. RM06-16-000 - 77 - 

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 
Docket No. RM06-16-000 - 78 - 

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 nonspinning 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 requirement113 based on LOLE. 

 111 ISO-RTO Council Comments, Attachment A at 3. 

112 LOLE studies are probabilistic studies associated with determining the 

probability that there may not be sufficient generation to supply firm load. 

113 Contingency 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. 
Docket No. RM06-16-000 - 79 - 

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. 
Docket No. RM06-16-000 - 80 - 

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, 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 

 114 NERC Comments at 41. 

115 Although Frequency Response and Bias are discussed at length in Reliability 

Standard BAL-003-0, the Commission notes here that it is important that contingency 

(continued) 
Docket No. RM06-16-000 - 81 - 

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 “fill-in-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 should have adequate frequency response to ensure recovery immediately 

following an event. 
Docket No. RM06-16-000 - 82 - 

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 non-spinning 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 

 116 See 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).. 
Docket No. RM06-16-000 - 83 - 

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. 

 117 See also Assessment of Demand Response and Advanced Metering: Staff 

Report (Aug. 2006) (Demand Response Report), available at http://www.ferc.gov/legal/

staff-reports/demand-response.pdf.
Docket No. RM06-16-000 - 84 - 

161. We agree with LPPC’s suggestion to modify Requirements R4.2 and 6.2 of BAL002 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 BulkPower 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 continentwide contingency reserve policy;119 (3) includes a Requirement that measures response 

 118 LPPC 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. 

119 This could be accomplished by modifying Requirement R2 or developing a 

new Reliability Standard. 
Docket No. RM06-16-000 - 85 - 

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 

setting121 is accurately 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 

 120 The 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. 

121 Frequency bias setting is a value expressed in MW/0.1 Hz, set into a balancing 

authority ACE algorithm that allows the balancing authority to contribute its frequency 

response to the Interconnection. See NERC glossary at 5. 

122 The 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. 
Docket No. RM06-16-000 - 86 - 

percent of yearly peak demand per 0.1Hz 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 0.1Hz. 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 

 123 Staff Preliminary Assessment at 28-30. 

124 For 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. 
Docket No. RM06-16-000 - 87 - 

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 BAL003-0, 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 

 125 According 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. 
Docket No. RM06-16-000 - 88 - 

MW/0.1 Hz. In sum, it claims that the Eastern Interconnection is over-biased 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 

over-biased. 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. 

 126 Staff Preliminary Assessment at 28. 
Docket No. RM06-16-000 - 89 - 

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 over-biased. 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 over-biasing 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, 
Docket No. RM06-16-000 - 90 - 

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 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 

 127 See WECC’s Frequency Response Standard White Paper (2005), at

http://www.wecc.biz/documents/library/RITF/FRR_White_Paper_v12_1-27-06.pdf
Docket No. RM06-16-000 - 91 - 

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 BulkPower 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. 
Docket No. RM06-16-000 - 92 - 

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. 

 128 The 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. 
Docket No. RM06-16-000 - 93 - 

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 

website 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. 

 129 NERC, 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. 
Docket No. RM06-16-000 - 94 - 

182. In addition, the Commission notes that WECC has implemented an automatic time 

error correction procedure130 that, according to data on the NERC website, 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 BulkPower System, the Commission proposes to approve Reliability Standard BAL-004-0 as 

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

Procedure_10-04-02.pdf. 

131 See http://www.nerc.com/~filez/inadv.html (regarding inadvertent interchange 

data) and http://www.nerc.com/~filez/timerror.html (regarding time error correction). 
Docket No. RM06-16-000 - 95 - 

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 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. 
Docket No. RM06-16-000 - 96 - 

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 Non-Compliance 

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. 

 132 Staff Preliminary Assessment at 32. 
Docket No. RM06-16-000 - 97 - 

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 

 133 NERC Resources Subcommittee (Frequency Task Force), Frequency Response 

Standard Whitepaper (2004), at http://www.nerc.com/pub/sys/all_updl/oc/rs/Frequency 

(continued) 
Docket No. RM06-16-000 - 98 - 

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 

 

_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. 
Docket No. RM06-16-000 - 99 - 

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 

group of Reliability Standards contains reliability goals concerning frequency, the 

Commission believes that Requirement R17 is appropriately placed in BAL-005-0. 

 134 See PJM RTO White Paper, Frequency Excursions, by Koza, Williams and 

Herbsleb. 
Docket No. RM06-16-000 - 100 - 

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 Non-Compliance. 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 BulkPower 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. 
Docket No. RM06-16-000 - 101 - 

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 agreed-to 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 

 135 On 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 BAL006-1. 
Docket No. RM06-16-000 - 102 - 

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 non-compliant. 

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 website 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 

 136 See Staff Preliminary Assessment at 32 n.63. 
Docket No. RM06-16-000 - 103 - 

“Inadvertent Interchange Payback Standard- WEQ-007” deals with how balancing 

authorities should eliminate their inadvertent interchanges. According to NERC, realtime imbalances between the generation and load are appropriately dealt with in BAL001-0 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-control-area 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, 
Docket No. RM06-16-000 - 104 - 

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 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 
Docket No. RM06-16-000 - 105 - 

balancing authorities that are not physically adjacent but are connected by a multi-party 

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 NonCompliance 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 Non-Compliance 

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 
Docket No. RM06-16-000 - 106 - 

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 BulkPower 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 NonCompliance 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. 
Docket No. RM06-16-000 - 107 - 

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 net-interchange 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. 

 137 BAL-006-1, filed on August 28, 2006, would extend the regional difference to 

SPP. 
Docket No. RM06-16-000 - 108 - 

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 CIP001-0 (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 Bulk-Power System. 
Docket No. RM06-16-000 - 109 - 

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 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 ANSI-accredited 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. 
Docket No. RM06-16-000 - 110 - 

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 

term140 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 break-in that gains access to a control room but 

 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. 

139 Order No. 672 at P 325. 

140 The 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). 
Docket No. RM06-16-000 - 111 - 

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 

 141 Reference 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. 
Docket No. RM06-16-000 - 112 - 

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 

 142 ESISAC 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. 
Docket No. RM06-16-000 - 113 - 

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 NonCompliance. 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 Non-Compliance 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 by the ERO and that it will improve the reliability of the nation’s BulkPower System, the Commission proposes to approve Reliability Standard CIP-001-0 as 
Docket No. RM06-16-000 - 114 - 

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 Non-Compliance; 

(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 
Docket No. RM06-16-000 - 115 - 

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 
Docket No. RM06-16-000 - 116 - 

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 
Docket No. RM06-16-000 - 117 - 

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 Non-Compliance 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 

 143 Staff Preliminary Assessment at 45. 
Docket No. RM06-16-000 - 118 - 

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 real-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 

 144 NERC Comments at 118. 
Docket No. RM06-16-000 - 119 - 

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 Non-Compliance. 

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 
Docket No. RM06-16-000 - 120 - 

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 

 145 Loss 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. 
Docket No. RM06-16-000 - 121 - 

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 COM001-0, 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-
Docket No. RM06-16-000 - 122 - 

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 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 
Docket No. RM06-16-000 - 123 - 

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 COM001-0, which sets forth requirements for telecommunication facilities. National Grid 

 146 Staff Preliminary Assessment at 44. 
Docket No. RM06-16-000 - 124 - 

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 

Non-Compliance, 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 COM002-1. 

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 

 147 COM-002-1, Requirement R1.1. 
Docket No. RM06-16-000 - 125 - 

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 pre-identified operating entities; and 

(2) communications protocols which clearly identify that any operating actions with 

 148 Blackout Report at 107. 
Docket No. RM06-16-000 - 126 - 

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 Non-

 149 Staff Preliminary Assessment at 43-44. 
Docket No. RM06-16-000 - 127 - 

Compliance. 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 BulkPower 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 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. 

 150 This Requirement could be included in this communication Reliability 

Standard or in an operating Reliability Standard(s), at NERC’s option. 
Docket No. RM06-16-000 - 128 - 

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 
Docket No. RM06-16-000 - 129 - 

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 Bulk-Power 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 loadshedding 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 load-serving entity can use to work with 
Docket No. RM06-16-000 - 130 - 

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. 
Docket No. RM06-16-000 - 131 - 

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 
Docket No. RM06-16-000 - 132 - 

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 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-

 151 NERC glossary at 11. 
Docket No. RM06-16-000 - 133 - 

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. 

 152 Blackout Report at 158. 
Docket No. RM06-16-000 - 134 - 

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 
Docket No. RM06-16-000 - 135 - 

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 BulkPower System, the Commission therefore proposes to approve Reliability Standard EOP001-0 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 transmissionrelated “normal,” “alert,” and “emergency” states, provides criteria for entering into these 

states, and identifies the authority that will declare these states. 
Docket No. RM06-16-000 - 136 - 

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 

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 
Docket No. RM06-16-000 - 137 - 

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 EOP002-1. 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 

 153 Id. at 163. 
Docket No. RM06-16-000 - 138 - 

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. 
Docket No. RM06-16-000 - 139 - 

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, 
Docket No. RM06-16-000 - 140 - 

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 load-shedding 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. 
Docket No. RM06-16-000 - 141 - 

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 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 

 154 Id. at 147. 
Docket No. RM06-16-000 - 142 - 

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 load-shedding capabilities in the portion of the 

Interconnection that is more susceptible to instability. 
Docket No. RM06-16-000 - 143 - 

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 load-shedding 

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 
Docket No. RM06-16-000 - 144 - 

is necessary to ensure an adequate load-shedding 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 

 155 Id. at 147. 
Docket No. RM06-16-000 - 145 - 

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. 

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-
Docket No. RM06-16-000 - 146 - 

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 
Docket No. RM06-16-000 - 147 - 

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 NonCompliance. 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 
Docket No. RM06-16-000 - 148 - 

ERO Rules of Procedure that apply to users, owners and operators of Bulk-Power 

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 Bulk-Power 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 
Docket No. RM06-16-000 - 149 - 

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 BulkPower 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 

Non-Compliance. 

f. System Restoration Plans (EOP-005-1)

i. NERC Proposal

307. Proposed Reliability Standard EOP-005-1156 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 

 156 On 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. 
Docket No. RM06-16-000 - 150 - 

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 EOP005, designated EOP-005-1. The revised Reliability Standard includes two new 

Requirements, R9 and 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 Non-Compliance but no Measures. 
Docket No. RM06-16-000 - 151 - 

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 
Docket No. RM06-16-000 - 152 - 

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 EOP005-1 would contribute to maintaining or enhancing system reliability and therefore 

proposes to accept them. 

 157 Requirement 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.” 
Docket No. RM06-16-000 - 153 - 

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 BulkPower 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 
Docket No. RM06-16-000 - 154 - 

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 Non-Compliance. 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 

restoration plan required by the Reliability Standard, approval of that plan would have no 

clear benefit. 
Docket No. RM06-16-000 - 155 - 

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 Non-compliance. 

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 BulkPower 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 EOP006-0 that: (1) requires that the reliability coordinator be involved in the development 
Docket No. RM06-16-000 - 156 - 

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 EOP007-0 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 
Docket No. RM06-16-000 - 157 - 

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. 
Docket No. RM06-16-000 - 158 - 

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 
Docket No. RM06-16-000 - 159 - 

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 

provides 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 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. 

 158 EEI Comments at 10. 
Docket No. RM06-16-000 - 160 - 

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 

Non-Compliance, 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 

 159 Facilities examples include telecommunications, backup power supplies, 

computer systems, and security systems. 
Docket No. RM06-16-000 - 161 - 

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 Bulk-Power 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 
Docket No. RM06-16-000 - 162 - 

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 (EOP009-0)

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 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. 
Docket No. RM06-16-000 - 163 - 

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. 
Docket No. RM06-16-000 - 164 - 

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 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. 
Docket No. RM06-16-000 - 165 - 

c. Coordination of Plans for New Generation, Transmission, and EndUser 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. 2003161 require assessment for both normal and post-contingency conditions 

and is therefore more rigorous than TPL-001-0.

 160 Standard 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 ...”). 

161 Standardization 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 61,009 (2004). 
Docket No. RM06-16-000 - 166 - 

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 TPL004-0 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 
Docket No. RM06-16-000 - 167 - 

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 
Docket No. RM06-16-000 - 168 - 

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 open-ended. 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 

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 
Docket No. RM06-16-000 - 169 - 

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 
Docket No. RM06-16-000 - 170 - 

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 BulkPower 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 TPL001 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-ofway 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 
Docket No. RM06-16-000 - 171 - 

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 

 162 Standard FAC-003-1 (Requirement R1.2.2). 
Docket No. RM06-16-000 - 172 - 

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 Z133 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 

 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. 

165 ANSI Z133, American National Standards Institute Standard For Tree Care 

Operations – Pruning, Trimming, Repairing, Maintaining and Removing Trees, and 

Cutting Brush – Safety Requirements. 
Docket No. RM06-16-000 - 173 - 

stringent vegetation management programs based on standards such as the ANSI Z-133 

may relax their practices to meet the less-stringent 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

iii. Comments

369. NERC contends that FAC-003-1 is an excellent standard that sets appropriate 

requirements for managing vegetation in transmission rights-of-way. 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 

 166 Blackout Report at 154.

167 NERC Comments at 31. 
Docket No. RM06-16-000 - 174 - 

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 FAC003-1, 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. 

 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.” 

169 E.g., EEI, Mid-American, National Grid, NRECA, PG&E, and Southern. 
Docket No. RM06-16-000 - 175 - 

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 realworld 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 

 170 E.g., Allegheny, CenterPoint, EEI, MRO, National Grid, NRECA, NYSPUC, 

SCE, and Southern. 
Docket No. RM06-16-000 - 176 - 

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. 

 171 E.g., CenterPoint, National Grid, ISO/RTO Council and Southern. 
Docket No. RM06-16-000 - 177 - 

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 2005that would diminish the USDA 

Forest Service’s authority to approve new vegetation management standards on Forest 

Service lands. 

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 

 172 EEI Comments at 8. 
Docket No. RM06-16-000 - 178 - 

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 

 173 FAC-003-1, Requirement R1.2. 
Docket No. RM06-16-000 - 179 - 

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 

 174 FAC-003-1, Requirement R1.2.2 (emphasis added). 

175 NERC 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.” 
Docket No. RM06-16-000 - 180 - 

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-by-case 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 

 177 Nothing 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. 
Docket No. RM06-16-000 - 181 - 

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 

 178 The 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. 
Docket No. RM06-16-000 - 182 - 

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 believe that it 

serves an important goal of improving the reliability of the Bulk-Power 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-
Docket No. RM06-16-000 - 183 - 

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); 
Docket No. RM06-16-000 - 184 - 

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 

 180 Blackout Report at 162.
Docket No. RM06-16-000 - 185 - 

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, jointly-owned 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 
Docket No. RM06-16-000 - 186 - 

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. Mid-American 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, Mid-American does not support an overly-prescriptive standard. It suggests 
Docket No. RM06-16-000 - 187 - 

that staff’s concerns should be directed at 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, FAC008-1 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 

 181 National Grid Comments at 19. 
Docket No. RM06-16-000 - 188 - 

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 

 182 The 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. 
Docket No. RM06-16-000 - 189 - 

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 

 183 MRO Comments at 8. 
Docket No. RM06-16-000 - 190 - 

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. 
Docket No. RM06-16-000 - 191 - 

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 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 

 184 See NERC Comments at 61. 
Docket No. RM06-16-000 - 192 - 

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 BulkPower 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 
Docket No. RM06-16-000 - 193 - 

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 
Docket No. RM06-16-000 - 194 - 

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 intraregional 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 inter-regional and intra-regional transfer capabilities may vary for 

different regions of the Eastern Interconnection due to geography, system design, 
Docket No. RM06-16-000 - 195 - 

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 
Docket No. RM06-16-000 - 196 - 

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 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. 

 185 Path rating process in WECC and various regional transfer capability 

methodologies in the Eastern interconnection. 
Docket No. RM06-16-000 - 197 - 

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 
Docket No. RM06-16-000 - 198 - 

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 BulkPower 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 
Docket No. RM06-16-000 - 199 - 

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. 

 186 NERC 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, INT008-1, INT-009-1, INT-010-1. 
Docket No. RM06-16-000 - 200 - 

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 Bulk-Power System are known to 

operating entities and reliability coordinators sufficiently in advance to permit them to 

 188 Order No. 672 at P 324. 
Docket No. RM06-16-000 - 201 - 

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 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. 

 189 NERC Petition at 40-41. 

190 Order No. 672 at P 249. 
Docket No. RM06-16-000 - 202 - 

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. 

 191 Currently, the reliability analysis service used by NERC is the Interchange 

Distribution Calculator. 

192 NERC’s Glossary of Terms adopted by NERC Board of Trustee on August 2, 

2006 defines Interchange as “Energy transfers that cross Balancing Authority 

boundaries.” 
Docket No. RM06-16-000 - 203 - 

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 point-to-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 
Docket No. RM06-16-000 - 204 - 

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 Non-Compliance. 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 

 193 See NERC Implementation Plan for Coordinate Interchange Standards INT-005 

through INT-010 (December 15, 2005) at 2-3. 
Docket No. RM06-16-000 - 205 - 

provide Measures and Levels of Non-Compliance, the Requirements set forth in INT001-1 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 BulkPower 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 INT001-1 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 “nonOrder 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 
Docket No. RM06-16-000 - 206 - 

scheduling information on dynamic schedules and that unilateral 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. 

 194 Waiver Request – Tagging Dynamic Schedules and Inadvertent Payback, 

Approved November 21, 2002. NERC Petition, Exhibit A. 

195 Order No. 672 at P 290. 

196 Information on this development can be found at: 

http://www.wecc.biz/index.php?module=pnForum&func=viewtopic&topic=394. 
Docket No. RM06-16-000 - 207 - 

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.” 

 197 Waiver Request – Energy Flow Information, Approved July 16, 2003. 

(Attached to NERC’s proposed Reliability Standards) 
Docket No. RM06-16-000 - 208 - 

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.”198 However, 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. 

 198 Order No. 672 at P 290. 

199 Id. at 291. 

200 Id.

201 See Midwest Independent Transmission System Operator, Inc., 102 FERC 

¶ 61,196 at P 38 (2003). 
Docket No. RM06-16-000 - 209 - 

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 Non-Compliance 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 Non-Compliance. This comment applies equally to INT-003-1. 
Docket No. RM06-16-000 - 210 - 

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 Non-Compliance. 

While it is important to develop Measures and Levels of Non-Compliance, 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 BulkPower System, the Commission proposes to approve Reliability Standard INT-003-1 as 
Docket No. RM06-16-000 - 211 - 

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 

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, non-participating 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 

 202 NERC 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. 
Docket No. RM06-16-000 - 212 - 

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 continent-wide Reliability Standard, including a 

regional difference that addresses matters that the continent-wide Reliability Standard 

 203 Waiver 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). 

205 Waiver Request – Enhanced Scheduling Agent, Approved November 16, 2003. 

ERC Petition, Exhibit A. 
Docket No. RM06-16-000 - 213 - 

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 multi-control 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 Non-Compliance. 

 206 Order No. 672 at P 291. 

207 See Midwest Independent Transmission System Operator, Inc., 102 FERC 

¶ 61,196 at P 38 (2003). 
Docket No. RM06-16-000 - 214 - 

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 
Docket No. RM06-16-000 - 215 - 

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 BulkPower 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 INT004-1 that includes Levels of Non-Compliance. 

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 assessments. INT-005-1 is applicable to the “interchange authority.”208 

 208 NERC’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.” 
Docket No. RM06-16-000 - 216 - 

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 BulkPower 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 Non-Compliance. 

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 BulkPower 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 Non-Compliance. Further, the Commission requests 

that NERC provide additional information regarding the role of the interchange authority 
Docket No. RM06-16-000 - 217 - 

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. 
Docket No. RM06-16-000 - 218 - 

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. 
Docket No. RM06-16-000 - 219 - 

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 NonCompliance 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. 
Docket No. RM06-16-000 - 220 - 

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 BulkPower 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 INT006-1 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 wide-area reliability viewpoint and, where their review indicates a 

potential detrimental reliability impact, communicate to the sink balancing authorities 

necessary transaction modifications prior to implementation. 

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. INT007-1 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. 
Docket No. RM06-16-000 - 221 - 

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 purchasingselling entities involved in the arranged interchange when the status of the transaction has 

changed from arranged interchange to confirmed interchange. 
Docket No. RM06-16-000 - 222 - 

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 Bulk-Power 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 
Docket No. RM06-16-000 - 223 - 

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 
Docket No. RM06-16-000 - 224 - 

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 INT004-0. 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 

 209 NERC 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. 

210 Reliability 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." 
Docket No. RM06-16-000 - 225 - 

potential 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 

 211 Blackout Report at 163. 
Docket No. RM06-16-000 - 226 - 

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, 

 212 According 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 

(continued) 
Docket No. RM06-16-000 - 227 - 

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 process-oriented. 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 

 

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...” 
Docket No. RM06-16-000 - 228 - 

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 (IRO001-0)

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. 
Docket No. RM06-16-000 - 229 - 

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 re-dispatch 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 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 
Docket No. RM06-16-000 - 230 - 

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 BulkPower 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. 
Docket No. RM06-16-000 - 231 - 

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 Non-Compliance. 

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 

 213 MISO 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 post-contingency analysis capabilities (thermal, stability, and 

voltage), and wide-area overview displays.” 
Docket No. RM06-16-000 - 232 - 

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 Non-Compliance 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 

Non-Compliance 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 BulkPower 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 
Docket No. RM06-16-000 - 233 - 

modification to IRO-002-0 that: (1) includes Measures and Levels of Non-Compliance 

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 Non-Compliance 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 
Docket No. RM06-16-000 - 234 - 

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 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 

 214 NERC Comments at 126. 

215 Blackout Report at 159. 
Docket No. RM06-16-000 - 235 - 

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.” 

 216 Id. 

217 IRO-003-1, Requirement R1. 
Docket No. RM06-16-000 - 236 - 

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 BulkPower 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 Non-Compliance; 

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 
Docket No. RM06-16-000 - 237 - 

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 

 218 Staff Preliminary Assessment at 71. 

219 Requirement R1 requires that “Each Reliability Coordinator shall conduct nextday 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.” 
Docket No. RM06-16-000 - 238 - 

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 nextday 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 

 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.” 
Docket No. RM06-16-000 - 239 - 

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 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. 
Docket No. RM06-16-000 - 240 - 

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 BulkPower 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 IRO005-0 to address the lack of Measures and Levels of Non-Compliance and resubmit it for 

Commission approval in November 2006. 
Docket No. RM06-16-000 - 241 - 

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 
Docket No. RM06-16-000 - 242 - 

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 

 221 See NERC Comments at 43-48. 
Docket No. RM06-16-000 - 243 - 

“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 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-
Docket No. RM06-16-000 - 244 - 

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 

FPA222 and the technical requirement as stated in Table 1 of Reliability Standard TPL002-0.223 Therefore, in order to achieve the reliability goal stated in the definition of 

 222 Reliable 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. 

223 TPL-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 

(continued) 
Docket No. RM06-16-000 - 245 - 

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. 

 

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. 
Docket No. RM06-16-000 - 246 - 

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. 
Docket No. RM06-16-000 - 247 - 

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 Non-Compliance 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 
Docket No. RM06-16-000 - 248 - 

Interconnection operations, 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 BulkPower 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 
Docket No. RM06-16-000 - 249 - 

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 

 224 The 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. 

225 The 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. 
Docket No. RM06-16-000 - 250 - 

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 IRO006-1. 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 

 226 We 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. 

227 Blackout Report, Recommendation No. 31 at 163. 
Docket No. RM06-16-000 - 251 - 

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 re-dispatch 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 

 228 Staff Preliminary Assessment at 69. 

229 NERC Comments at 49. 
Docket No. RM06-16-000 - 252 - 

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, 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. 

 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.” 
Docket No. RM06-16-000 - 253 - 

556. However, ISO/RTO Council explains the limitations of TLR in EOP-002-0 that 

most ISOs and RTOs use re-dispatch 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 
Docket No. RM06-16-000 - 254 - 

methods such as reconfiguration, re-dispatch or load shedding until relief requested by 

the TLR process is achieved.233 The Commission is concerned, however, that 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 

 233 NERC Comments at 49. 
Docket No. RM06-16-000 - 255 - 

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 

 234 See Blackout Report at 63. 

235 Id. at 163. 

236 WSCC is an old reference to WECC. 
Docket No. RM06-16-000 - 256 - 

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-to-back 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 
Docket No. RM06-16-000 - 257 - 

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 BulkPower 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 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 Non-Compliance 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. 
Docket No. RM06-16-000 - 258 - 

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 

non-market 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 non-discriminatory 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 
Docket No. RM06-16-000 - 259 - 

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. 
Docket No. RM06-16-000 - 260 - 

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. 
Docket No. RM06-16-000 - 261 - 

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. 
Docket No. RM06-16-000 - 262 - 

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 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 
Docket No. RM06-16-000 - 263 - 

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 accuracy 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 

 237 MOD-001-0 through MOD-009-0. 

238 MOD-010-0 through MOD-015-0. 

239 MOD-016-0 through MOD-021-0. 

240 MOD-024-1 through MOD-025-1. 

241 OATT Reform NOPR, 71 FR 32636 at 32658. 
Docket No. RM06-16-000 - 264 - 

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 Capacity243 (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 

 242 Id., 71 FR at 32654 and 32667. 

243 AFC is a methodology that first calculates available capacity on a flowgateAFC, 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. 

244 The 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. 

245 The 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. 
Docket No. RM06-16-000 - 265 - 

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 intercontrol area transfers and does not use the NERC methodologies. 
Docket No. RM06-16-000 - 266 - 

 Commission Proposal 

594. As we discussed in the Common Issues section above describing fill-in-the-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 
Docket No. RM06-16-000 - 267 - 

TTC and ATC methodology in conjunction with its members; and (2) 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 
Docket No. RM06-16-000 - 268 - 

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-the-blank” 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 
Docket No. RM06-16-000 - 269 - 

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. 

1. 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. 

 246 OATT Reform NOPR at ¶ 155-70. 

247 For 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 Fed. Reg. at 32,653. 
Docket No. RM06-16-000 - 270 - 

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, 

 248 Available Flowgate Capability is a method widely used in the Eastern 

Interconnection but there is no NERC definition for that term. 

249 ETC includes transmission capacity set aside for both native load and 

transmission reservations. 
Docket No. RM06-16-000 - 271 - 

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 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. 
Docket No. RM06-16-000 - 272 - 

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 

 250 Total 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. 

251 Transfer 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. 

252 OATT Reform NOPR at P 166. 
Docket No. RM06-16-000 - 273 - 

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 long-term 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 
Docket No. RM06-16-000 - 274 - 

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 (MOD002-0)

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 “fillin-the-blank” standard and that the standard applies to the regional reliability 

organization. 

 253 We note that our observation here also applies to MOD-002, MOD-003, MOD004, MOD-005, MOD-008, MOD-009, MOD-011, MOD-013, MOD-014, MOD-015, 

MOD-016, MOD024, and MOD-025. 
Docket No. RM06-16-000 - 275 - 

iii. Comments 

613. The Commission received no specific comments regarding MOD-002-0. 

iv. Commission Proposal 

614. MOD-002-0 is a “fill-in-the-blank” 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. 

 
Docket No. RM06-16-000 - 276 - 

d. Regional Procedure for Input on Total Transfer Capability and 

Available Transfer Capability Methodologies and Values (MOD003-0)

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 website. 

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 how these questions or concerns will be addressed. 
Docket No. RM06-16-000 - 277 - 

iii. Comments 

617. The Commission received no comments regarding MOD-003-0. 

iv. Commission Proposal 

618. MOD-003-0 is a “fill-in-the-blank” 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 
Docket No. RM06-16-000 - 278 - 

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 

 254 The 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. 
Docket No. RM06-16-000 - 279 - 

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, 
Docket No. RM06-16-000 - 280 - 

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 regionally-based. 

iv. Commission Proposal 

624. MOD-004-0 is a “fill-in-the-blank” 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 
Docket No. RM06-16-000 - 281 - 

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 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, 

 255 The 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). 
Docket No. RM06-16-000 - 282 - 

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 non-affiliated third party’s access to the transmission system. 

f. Procedure for Verifying Capacity Benefit Margin Values (MOD005-0)

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 
Docket No. RM06-16-000 - 283 - 

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-the-blank” 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. 
Docket No. RM06-16-000 - 284 - 

g. Procedure for the Use of Capacity Benefit Margin Values (MOD006-0)

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 website 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. 
Docket No. RM06-16-000 - 285 - 

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 load-serving 

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 
Docket No. RM06-16-000 - 286 - 

balancing authority to meet the balancing Reliability Standards should 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 BulkPower 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 
Docket No. RM06-16-000 - 287 - 

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 load-serving 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 website 

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. 
Docket No. RM06-16-000 - 288 - 

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 BulkPower 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. 
Docket No. RM06-16-000 - 289 - 

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. 
Docket No. RM06-16-000 - 290 - 

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-the-blank” 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 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, 
Docket No. RM06-16-000 - 291 - 

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 
Docket No. RM06-16-000 - 292 - 

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-the-blank” 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. 
Docket No. RM06-16-000 - 293 - 

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 steady-state 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, 
Docket No. RM06-16-000 - 294 - 

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. 

iii. 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 
Docket No. RM06-16-000 - 295 - 

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 purpose represented to the 

Commission by the ERO and that it will improve the reliability of the nation’s BulkPower 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: 
Docket No. RM06-16-000 - 296 - 

(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 
Docket No. RM06-16-000 - 297 - 

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. 
Docket No. RM06-16-000 - 298 - 

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 MOD012-0. 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 
Docket No. RM06-16-000 - 299 - 

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 BulkPower 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 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 
Docket No. RM06-16-000 - 300 - 

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 to 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 
Docket No. RM06-16-000 - 301 - 

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 unitspecific 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. 

 256 Although the Staff Preliminary Assessment addresses concerns regarding the 

MOD-013-0, many of the same concerns apply to MOD-013-1 as well. 
Docket No. RM06-16-000 - 302 - 

iv. Commission Proposal

684. MOD-013-1 is a “fill-in-the-blank” 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. 

2. 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. 
Docket No. RM06-16-000 - 303 - 

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 steady-state 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 

 257 Blackout Report at 160. 
Docket No. RM06-16-000 - 304 - 

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 MOD014-0. ReliabilityFirst submits that it generally agrees with staff’s evaluation of MOD014-0 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-the-blank” Reliability Standard that requires the regional 

reliability organizations within an Interconnection to develop, coordinate and maintain a 

library of solved Interconnection-specific steady-state 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. 
Docket No. RM06-16-000 - 305 - 

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. 

 258 Blackout Report at 160. 

259 FERC 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 ten-year 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.” 
Docket No. RM06-16-000 - 306 - 

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. 

 260 Blackout Report at 160. 
Docket No. RM06-16-000 - 307 - 

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-the-blank” 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. 
Docket No. RM06-16-000 - 308 - 

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 

 261 See ERCOT report “August 19, 2004 Forney Plant Trip Event Simulation” 

prepared by the ERCOT Reliability and Operations Subcommittee by ERCOT Dynamics 

Working Group. 

262 On August 28, 2006, NERC submitted MOD-016-1 for approval, which 

replaces MOD-016-0. MOD-016-1 contains an additional Requirement that each loadserving entity must count its customer demand values only once. MOD-016-1 has also 

an improved set of Measures and Levels of Non-compliance. 
Docket No. RM06-16-000 - 309 - 

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 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 BulkPower 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 

 263 DSM may include control of electric supply to individual appliances or 

equipment on customer premises, interruptible/curtailable load, demand bidding/buyback 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. 
Docket No. RM06-16-000 - 310 - 

§ 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 MOD017-0. It also points out that some of the data related to the Reliability Standard are 
Docket No. RM06-16-000 - 311 - 

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. 
Docket No. RM06-16-000 - 312 - 

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 BulkPower 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 to 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. 

 264 The 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. 
Docket No. RM06-16-000 - 313 - 

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 load-serving 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. 
Docket No. RM06-16-000 - 314 - 

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 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. 
Docket No. RM06-16-000 - 315 - 

iv. Commission Proposal

722. MOD-019-0 does not require reporting of the accuracy, error and bias of 

controllable load265 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 BulkPower 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. 

 265 Whereas 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. 
Docket No. RM06-16-000 - 316 - 

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. 
Docket No. RM06-16-000 - 317 - 

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 BulkPower 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 
Docket No. RM06-16-000 - 318 - 

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. 
Docket No. RM06-16-000 - 319 - 

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 BulkPower 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 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 
Docket No. RM06-16-000 - 320 - 

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. 

iii. Commission Proposal

739. MOD-024-1 is a “fill-in-the-blank” 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 
Docket No. RM06-16-000 - 321 - 

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. 
Docket No. RM06-16-000 - 322 - 

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. 
Docket No. RM06-16-000 - 323 - 

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 fieldtesting. 

iv. Commission Proposal

746. The MOD-025-1 is a “fill-in-the-blank” 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. 
Docket No. RM06-16-000 - 324 - 

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 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. 
Docket No. RM06-16-000 - 325 - 

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

 266 Reliability 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. 

267 See, e.g., NYSRC, WECC/OTS, ReliabilityFirst and NERC. 
Docket No. RM06-16-000 - 326 - 

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 

 268 PER-001-0, Measure M1. 

269 Blackout Report at 107. 

270 Id. at 110. 
Docket No. RM06-16-000 - 327 - 

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 Bulk-Power 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 
Docket No. RM06-16-000 - 328 - 

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. 

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 
Docket No. RM06-16-000 - 329 - 

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-size-fits-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 ill-defined 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. 
Docket No. RM06-16-000 - 330 - 

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 

 271 NERC, WECC/OTS and ISO/RTO Council. 
Docket No. RM06-16-000 - 331 - 

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 affect 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 
Docket No. RM06-16-000 - 332 - 

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 

 272 Blackout Report at 107. 

273 Id. at 157. 

274 Id.
Docket No. RM06-16-000 - 333 - 

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 BulkPower 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 expanding training programs to other personnel with the ability to affect 

real-time 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 real-time 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 
Docket No. RM06-16-000 - 334 - 

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 BulkPower 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-fits-all 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 
Docket No. RM06-16-000 - 335 - 

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 
Docket No. RM06-16-000 - 336 - 

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 
Docket No. RM06-16-000 - 337 - 

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 Reliability Standard will accomplish the purpose represented to the 

Commission by the ERO and that it will improve the reliability of the nation’s BulkPower 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 

 275 Id. at 107. 
Docket No. RM06-16-000 - 338 - 

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 realtime 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 
Docket No. RM06-16-000 - 339 - 

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 

 276 Staff Preliminary Assessment at 89-90. 

277 North 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. 
Docket No. RM06-16-000 - 340 - 

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. 
Docket No. RM06-16-000 - 341 - 

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 Bulk-Power 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 realtime 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 
Docket No. RM06-16-000 - 342 - 

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 BulkPower 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 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 
Docket No. RM06-16-000 - 343 - 

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 Non-Compliance 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. 

 278 A 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. 
Docket No. RM06-16-000 - 344 - 

796. ReliabilityFirst, NYSRC and ISO/RTO all note the Reliability Standard’s lack of 

Measures and Levels of Non-Compliance 

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 

 279 See NERC glossary at 11. 
Docket No. RM06-16-000 - 345 - 

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 Non-Compliance 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 PER003-0, 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 Non-Compliance 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 BulkPower 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 
Docket No. RM06-16-000 - 346 - 

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 

 280 Blackout Report at 107. 
Docket No. RM06-16-000 - 347 - 

control of power systems.281 NERC has recognized that 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 Standards283

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 

 281 Topics addressed under the PRC Reliability Standards include: system 

protection coordination, 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. 

282 See NERC Planning Standards Phase III-IV, available at 

http://www.nerc.com/~filez/standards/Phase-III-IV.html. 

283 The 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. 

284 The regional reliability organization is listed as the applicability entity under 

the following Reliability Standards in the PRC group: PRC-002-0; PRC-003-1; PRC006-0; PRC-012-0; PRC-013-0; PRC-014-0; and PRC-020-1. 
Docket No. RM06-16-000 - 348 - 

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 re-adjust 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. 
Docket No. RM06-16-000 - 349 - 

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 
Docket No. RM06-16-000 - 350 - 

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 non-redundant 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 
Docket No. RM06-16-000 - 351 - 

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 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 
Docket No. RM06-16-000 - 352 - 

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 
Docket No. RM06-16-000 - 353 - 

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 BulkPower 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 Non-Compliance; 
Docket No. RM06-16-000 - 354 - 

(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 
Docket No. RM06-16-000 - 355 - 

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 PRC002-1 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. 

 285 We 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). 
Docket No. RM06-16-000 - 356 - 

iii. Comments

824. A number of commenters discussed how to the Commission should address PRC002-1 and other Reliability Standards in the PRC group that are “fill-in-the-blank” 

standards.286. 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 under-frequency 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-the-blank” 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. 

 286 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. 

287 An example of this is PRC-013-0, which requires the establishment of a 

regional database for special protection systems. 
Docket No. RM06-16-000 - 357 - 

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 
Docket No. RM06-16-000 - 358 - 

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 
Docket No. RM06-16-000 - 359 - 

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. 
Docket No. RM06-16-000 - 360 - 

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 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. 
Docket No. RM06-16-000 - 361 - 

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 Bulk-Power 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 (PRC005-1)

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 
Docket No. RM06-16-000 - 362 - 

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. 

 288 Staff 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. 
Docket No. RM06-16-000 - 363 - 

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 do 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 Bulk-Power 

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 BulkPower System, the Commission proposes to approve Reliability Standard PRC-005-1 as 
Docket No. RM06-16-000 - 364 - 

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 

Bulk-Power 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 one 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 
Docket No. RM06-16-000 - 365 - 

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 lines and 

UFLS and UVLS programs within its work on the “fill-in-the-blank” 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 

 289 Blackout Report, Recommendation No. 21 at 159. 
Docket No. RM06-16-000 - 366 - 

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 
Docket No. RM06-16-000 - 367 - 

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 
Docket No. RM06-16-000 - 368 - 

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 
Docket No. RM06-16-000 - 369 - 

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, load-serving 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. 
Docket No. RM06-16-000 - 370 - 

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 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 believes that the proposed Reliability Standard is just, reasonable, not 

unduly discriminatory or preferential, and in the public interest. 
Docket No. RM06-16-000 - 371 - 

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 
Docket No. RM06-16-000 - 372 - 

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 Bulk-Power 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 (PRC009-0)

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 
Docket No. RM06-16-000 - 373 - 

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 “fillin-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, 
Docket No. RM06-16-000 - 374 - 

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 discriminatory or preferential, and in 

the public interest. 
Docket No. RM06-16-000 - 375 - 

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, load-serving 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 

 290 At least every five years or as required by changes in system 

conditions.

291 Blackout Report at 159. 
Docket No. RM06-16-000 - 376 - 

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 

 292 Available at http://www.nerc.com/~filez/reports.html. 

293 PRC-010-0, PRC-020-1 and PRC-021-1. 
Docket No. RM06-16-000 - 377 - 

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 
Docket No. RM06-16-000 - 378 - 

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 serve an important 

purpose in requiring the periodically 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 BulkPower 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 
Docket No. RM06-16-000 - 379 - 

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 PRC005-1. 

iii. Comments

895. NERC indicates that it will consider maximum intervals; and ISO/RTO Council 

and other commenters agree with the Staff Preliminary Assessment.294 

 294 While commenters raise these concerns primarily in the context of PRC-005-1, 

their comments apply to PRC-011-0 as well. 
Docket No. RM06-16-000 - 380 - 

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 BulkPower 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. 
Docket No. RM06-16-000 - 381 - 

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 systems295 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 PRC012-0 and other fill-in-the-blank standards in the PRC group that require compliance by 

regional reliability organizations.296. 

 295 A 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 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. 
Docket No. RM06-16-000 - 382 - 

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. 
Docket No. RM06-16-000 - 383 - 

iii. Comments

905. A number of commenters discussed how the Commission should address PRC012-0 and other fill-in-the-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. 
Docket No. RM06-16-000 - 384 - 

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. 

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. 
Docket No. RM06-16-000 - 385 - 

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 PRC012-0 and other fill-in-the-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 
Docket No. RM06-16-000 - 386 - 

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 
Docket No. RM06-16-000 - 387 - 

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 
Docket No. RM06-16-000 - 388 - 

Commission by the ERO and that it will improve the reliability of the nation’s BulkPower 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. 
Docket No. RM06-16-000 - 389 - 

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. 

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 BulkPower 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 
Docket No. RM06-16-000 - 390 - 

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. 
Docket No. RM06-16-000 - 391 - 

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. 
Docket No. RM06-16-000 - 392 - 

iii. Comments

940. A number of commenters discussed how the Commission should address PRC020-0 and other fill-in-the-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. 
Docket No. RM06-16-000 - 393 - 

ii. Staff Preliminary Assessment

943. No substantive issues were identified for the proposed Reliability Standard PRC021-1. 

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, loadserving entities, and distribution providers to provide analysis, documentation on UVLS 

operations and misoperations to the regional reliability organization. 
Docket No. RM06-16-000 - 394 - 

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 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. 
Docket No. RM06-16-000 - 395 - 

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 Bulk-Power 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 

Non-Compliance. 
Docket No. RM06-16-000 - 396 - 

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 
Docket No. RM06-16-000 - 397 - 

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. 

 297 We 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. 
Docket No. RM06-16-000 - 398 - 

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 NonCompliance. However, we believe that the Requirements set forth in TOP-001-0 are 

sufficiently clear and objective to provide guidance for compliance. Moreover, TOP001-0 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 BulkPower System, the Commission proposes to 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. 
Docket No. RM06-16-000 - 399 - 

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 TOP002-1 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

 298 On 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 

(continued) 
Docket No. RM06-16-000 - 400 - 

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. 

 

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. 

299 Although the Staff Preliminary Assessment addresses concerns regarding the 

TOP-002-0, many of these same concerns apply to TOP-002-1 as well. 

300 See proposed Reliability Standard IRO-005-1. 

301 System operators should operate the Bulk-Power 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. 
Docket No. RM06-16-000 - 401 - 

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 nextday 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 

 302 Failure of an electrical component includes relay and control system failures, 

which may remove more than one element. 
Docket No. RM06-16-000 - 402 - 

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 nextday 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. 
Docket No. RM06-16-000 - 403 - 

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 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 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. 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 
Docket No. RM06-16-000 - 404 - 

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 TOP002-1 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. 

 303 NERC glossary at 3. 

304 See R7 of TOP-002-0. 
Docket No. RM06-16-000 - 405 - 

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 Bulk-Power 
Docket No. RM06-16-000 - 406 - 

System in a reliable state. As mentioned above, TOP-002-1 does not contain Measures or 

Levels of Non-Compliance. The Commission believes that it is important for NERC to 

provide Measures and Levels of Non-Compliance. 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 BulkPower 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 Non-compliance; 

(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, 
Docket No. RM06-16-000 - 407 - 

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 
Docket No. RM06-16-000 - 408 - 

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. 

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 
Docket No. RM06-16-000 - 409 - 

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. 
Docket No. RM06-16-000 - 410 - 

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 BulkPower 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 
Docket No. RM06-16-000 - 411 - 

(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 NonCompliance. 

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. 
Docket No. RM06-16-000 - 412 - 

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 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. 
Docket No. RM06-16-000 - 413 - 

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 
Docket No. RM06-16-000 - 414 - 

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 Non-compliance 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. 

 305 The 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. 
Docket No. RM06-16-000 - 415 - 

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 BulkPower 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 Non-Compliance; 

(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. 
Docket No. RM06-16-000 - 416 - 

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. 

 306 NERC 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. 
Docket No. RM06-16-000 - 417 - 

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 

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. 
Docket No. RM06-16-000 - 418 - 

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 BulkPower System parameters such as line flows, circuit breaker status, generator resources, 
Docket No. RM06-16-000 - 419 - 

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. 
Docket No. RM06-16-000 - 420 - 

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 

 308 See Blackout Report at 159. 

309 Id. at 108. 
Docket No. RM06-16-000 - 421 - 

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 TOP006-0 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 
Docket No. RM06-16-000 - 422 - 

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 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 BulkPower 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. 
Docket No. RM06-16-000 - 423 - 

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 pre-contingency 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-

 310 Reliability Standard TOP-007-0, Requirement R2. 
Docket No. RM06-16-000 - 424 - 

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 
Docket No. RM06-16-000 - 425 - 

leeway. Thus, the ISO/RTO Council recommends that the Commission approve TOP007-0 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 
Docket No. RM06-16-000 - 426 - 

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 BulkPower 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, 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. 
Docket No. RM06-16-000 - 427 - 

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 Non-Compliance. 

ii. Staff Preliminary Assessment

1031. The Staff Preliminary Assessment did not identify any substantive issues in TOP008-0, 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. 
Docket No. RM06-16-000 - 428 - 

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 BulkPower 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 
Docket No. RM06-16-000 - 429 - 

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 needs311 and (2) the information required to 

assess regional compliance with planning criteria and for self-assessment 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 

 311 See TPL-001-0, TPL-002-0, TPL-003-0, and TPL-004-0. 

312 See TPL-005-0 and TPL-006-0. 

313 See discussion of Bulk Power System v. bulk electric system in section III.D.5 

above. 
Docket No. RM06-16-000 - 430 - 

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 
Docket No. RM06-16-000 - 431 - 

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 failure-proof, but to ensure it 

is able to meet specific performance requirements under normal conditions and following 

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 multiplecontingency 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 

 314 Staff Preliminary Assessment at 108. 
Docket No. RM06-16-000 - 432 - 

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. 

 315 Examples 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. 

316 Staff Preliminary Assessment at 109. 
Docket No. RM06-16-000 - 433 - 

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 

 317 E.g., Reliability Standard TPL-001-0, Requirement R1.3. 

318 See Staff Preliminary Assessment at 109. See also CenterPoint, MidAmerican 

and MRO comments. 
Docket No. RM06-16-000 - 434 - 

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 

 319 While contingencies have been defined in Table I, the Commission does not 

believe systems conditions lend themselves to a table or a simple list. 
Docket No. RM06-16-000 - 435 - 

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 Bulk-Power 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. 

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 
Docket No. RM06-16-000 - 436 - 

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 

 320 See, e.g., CenterPoint, EEI, MidAmerican, New York Commission and 

ReliabilityFirst. 

321 Section 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 failure of system elements” (emphasis added). 
Docket No. RM06-16-000 - 437 - 

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. 

b. System Performance Under Normal (No Contingency) Conditions 

(TPL-001-0)

iii. 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 

 322 The NERC glossary 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. 
Docket No. RM06-16-000 - 438 - 

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 longer-term 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. 

 323 The performance requirements are set forth in Category A of Table I of the 

standard. 
Docket No. RM06-16-000 - 439 - 

iv. 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. 

v. 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 
Docket No. RM06-16-000 - 440 - 

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 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.” 

vi. 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 
Docket No. RM06-16-000 - 441 - 

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 

 324 The 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 

(continued) 
Docket No. RM06-16-000 - 442 - 

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 

 

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 multiple 

areas of weaknesses or criteria violations, then mitigation plans would be required. 
Docket No. RM06-16-000 - 443 - 

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 TPL001-0, 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. 

 325 NERC 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. 
Docket No. RM06-16-000 - 444 - 

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 BulkPower 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. 

c. 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 Bulk-Power System is planned to meet the system performance requirements of a 

system, with the loss of one element, by requiring that the transmission planner and 
Docket No. RM06-16-000 - 445 - 

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 (non-recallable 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 nearterm 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 

 326 The performance requirements are set forth in Category B of Table I of the 

Reliability Standard. 
Docket No. RM06-16-000 - 446 - 

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, TPL002-0 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 TPL002-0 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 

 327 Footnote (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.” 
Docket No. RM06-16-000 - 447 - 

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. 
Docket No. RM06-16-000 - 448 - 

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 
Docket No. RM06-16-000 - 449 - 

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 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 TPL002-0 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 
Docket No. RM06-16-000 - 450 - 

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 TPL002-0. This states, in part, “[a]pplicable ratings may include Emergency Ratings 

applicable for short durations as required to permit operating steps necessary to maintain 

 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). 
Docket No. RM06-16-000 - 451 - 

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 

 329 NERC TIS Report at 15.
Docket No. RM06-16-000 - 452 - 

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 

 330 Load 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. 
Docket No. RM06-16-000 - 453 - 

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 TPL002-0, 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 TPL002-0 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 by the ERO and that it will improve the reliability of the nation’s BulkPower 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 
Docket No. RM06-16-000 - 454 - 

§ 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. 

d. 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. 
Docket No. RM06-16-000 - 455 - 

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 TPL001, TPL-003 and TPL-004, although the Reliability Standard has a different goal and 
Docket No. RM06-16-000 - 456 - 

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 
Docket No. RM06-16-000 - 457 - 

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 
Docket No. RM06-16-000 - 458 - 

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 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. 

 331 See NERC TIS Report. 

332 Two entities are Consolidated Edison Company of New York and Public 

Service Electric and Gas. 
Docket No. RM06-16-000 - 459 - 

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 Non-Compliance. 

1101. While the Commission has identified a number of concerns with regard to TPL003-0, 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 BulkPower 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. 
Docket No. RM06-16-000 - 460 - 

e. 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. 
Docket No. RM06-16-000 - 461 - 

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 
Docket No. RM06-16-000 - 462 - 

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 TPL003-0, TPL-004-0 requires entities assessing system performance to cover “critical 

system 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 
Docket No. RM06-16-000 - 463 - 

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 
Docket No. RM06-16-000 - 464 - 

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 TPL004-0, 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 
Docket No. RM06-16-000 - 465 - 

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 BulkPower 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. 

f. Regional and Interregional Self-Assessment 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 
Docket No. RM06-16-000 - 466 - 

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 
Docket No. RM06-16-000 - 467 - 

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. 

g. Assessment Data from Regional Reliability Organizations (TPL006-0)

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. 
Docket No. RM06-16-000 - 468 - 

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 VAR001-0 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 
Docket No. RM06-16-000 - 469 - 

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 VAR001-1 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. 
Docket No. RM06-16-000 - 470 - 

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 post-contingency voltages. In addition, the standard does 

not require similar voltage stability assessments to be carried out periodically during realtime operations so that system operators can continuously respond to changing system 

conditions. 

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

334 Staff 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). 
Docket No. RM06-16-000 - 471 - 

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 purchasing-selling 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 entities. 

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. 

 335 Blackout Report at 160. 
Docket No. RM06-16-000 - 472 - 

iii. Comments 

1136. NERC states that the proposed reactive power and voltage control 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 loadserving 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 VAR001-0. 
Docket No. RM06-16-000 - 473 - 

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 

 336 VAR-001-1, Requirement R2. 

337 VAR-001-1, Requirement R8. 
Docket No. RM06-16-000 - 474 - 

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 

 338 See Staff Preliminary Assessment at 118, citing Blackout Report at 36 

(“voltage magnitude alone is a poor indicator of voltage stability”). 

339 WECC’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). 

340 See NERC.com/pub/sys/all_updl/pc/tis/TIS_Reactive_Recom7a_BOT 

apprvd_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. 
Docket No. RM06-16-000 - 475 - 

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 BulkPower System must comply with a Commission-approved 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 selfproviding 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 VAR001-1, 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 
Docket No. RM06-16-000 - 476 - 

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 load-serving 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 loadserving entities, NERC states that 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 purchasingselling 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 load-serving entity would become a 

 342 NERC glossary at 9. 
Docket No. RM06-16-000 - 477 - 

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 load-serving 

entities to the existing list of applicable entities for VAR-001-1 for added clarity. VAR001-1 recognizes that energy purchases of purchasing-selling 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 load-side 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 VAR001-1, 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 

 343 See Principles of Efficient and Reliable Reactive Power Supply and 

Consumption: FERC Staff Report (2005). 
Docket No. RM06-16-000 - 478 - 

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 BulkPower 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 Non-Compliance to ensure 

appropriate generation operation to maintain network voltage schedules. 
Docket No. RM06-16-000 - 479 - 

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 

 344 Staff Preliminary Assessment at 25-26. 
Docket No. RM06-16-000 - 480 - 

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 
Docket No. RM06-16-000 - 481 - 

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 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 - 

 345 5 CFR 1320.11. 

346 44 U.S.C. § 3507(d) . 
Docket No. RM06-16-000 - 482 - 

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. 
Docket No. RM06-16-000 - 483 - 

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 BulkPower 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. 
Docket No. RM06-16-000 - 484 - 

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. 
Docket No. RM06-16-000 - 485 - 

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, N.E. 

Washington, D.C. 20426 [Attention: Michael Miller, Office of the Executive Director, 

Phone: (202)502-8415, fax: (202) 273-0873, e-mail: michael.miller@ferc.gov. 

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, D.C. 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 
Docket No. RM06-16-000 - 486 - 

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. 

 347 Regulations 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. 
Docket No. RM06-16-000 - 487 - 

1173. Section 215(b) of the FPA requires all users, owners and operators of the BulkPower 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 

 350 See NERC Petition at 9-10. 

351 Id. at 81-82. 
Docket No. RM06-16-000 - 488 - 

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] 

 352 Id. at 10. 

353 Order No. 672 at P 330. 
Docket No. RM06-16-000 - 489 - 

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 [insert date 60 days 

from publication in the FEDERAL REGISTER]. 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: 

 354 See, discussion of Applicability to Small Entities, section III.B.3. above. 
Docket No. RM06-16-000 - 490 - 

1179. Federal Energy Regulatory Commission, Office of the Secretary, 888 First Street 

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

VIII. Document Availability

1180. In addition to publishing the full text of this document in the Federal Register, the 

Commission provides all interested persons an opportunity to view and/or print the 

contents of this document via the Internet through FERC's Home Page 

(http://www.ferc.gov) and in FERC's Public Reference Room during normal business 

hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, N.E., Room 2A, 

Washington, D.C., 20426. 

1181. 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. 

1182. User assistance is available for eLibrary and the FERC's website during normal 

business hours. For assistance, please contact FERC Online Support at 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). 
Docket No. RM06-16-000 - 491 - 

List of Subjects in 18 C.F.R. 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 BULKPOWER 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, N.E., Room 2A, Washington, D.C., 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 website. 
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
Docket No. RM06-16-000 - 494 - 

Reliability 

Standard Title Proposed Disposition 

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 

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
Docket No. RM06-16-000 - 495 - 

Reliability 

Standard Title Proposed Disposition 

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
Docket No. RM06-16-000 - 496 - 

Reliability 

Standard Title Proposed Disposition 

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

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. 

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