UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

18 CFR Part 40 

(Docket No. RM06-16-000; Order No. 693) 

Mandatory Reliability Standards for the Bulk-Power System 

(Issued March 16, 2007) 

AGENCY: Federal Energy Regulatory Commission, DOE. 

ACTION: Final Rule. 

SUMMARY: Pursuant to section 215 of the Federal Power Act (FPA), the Commission 

approves 83 of 107 proposed Reliability Standards, six of the eight proposed regional 

differences, and the Glossary of Terms Used in Reliability Standards developed by 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, 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. Therefore, pursuant to section 215(d)(5), we require the ERO to submit 

significant improvements to 56 of the 83 Reliability Standards that are being approved as 

mandatory and enforceable. The remaining 24 Reliability Standards will remain pending 

at the Commission until further information is provided. 

The Final Rule adds a new part to the Commission’s regulations, which states that this 

part applies to all users, owners and operators of the Bulk-Power System within the 

United States (other than Alaska or Hawaii) and requires that each Reliability Standard 

identify the subset of users, owners and operators to which that particular Reliability 

Standard applies. The new regulations also require that each Reliability Standard that is 

approved by the Commission will be maintained on the ERO’s Internet website for public 

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

EFFECTIVE DATE: This rule will become effective [insert date 60 days from the date 

the rule is published in the Federal Register]

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 Markets 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 

FEDERAL ENERGY REGULATORY COMMISSION 

Before Commissioners: Joseph T. Kelliher, Chairman; 

 Suedeen G. Kelly, Marc Spitzer, 

 Philip D. Moeller, and Jon Wellinghoff. 

Mandatory Reliability Standards for the Bulk-Power 

System 

Docket No. RM06-16-000 

ORDER NO. 693 

FINAL RULE 

(Issued March 16, 2007) 

TABLE OF CONTENTS

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

A. Background .............................................................................................................. 3.

1. EPAct 2005 and Order No. 672............................................................................ 3.

2. NERC Petition for Approval of Reliability Standards ....................................... 12.

3. Staff Preliminary Assessment and Commission NOPR..................................... 15.

4. Notice of Proposed Rulemaking......................................................................... 17.

II. Discussion................................................................................................................... 21.

A. Overview ................................................................................................................ 21.

1. The Commission’s Underlying Approach to Review and Disposition of the 

Proposed Standards.................................................................................................. 21.

2. Mandates of Section 215 of the FPA.................................................................. 23.

3. Balancing the Need for Practicality with the Mandates of Section 215 and Order 

No. 672 .................................................................................................................... 29.

B. Discussion of the Commission’s New Regulations .............................................. 34.

1. Applicability ....................................................................................................... 34.

2. Mandatory Reliability Standards........................................................................ 40.

3. Availability of Reliability Standards .................................................................. 44.

C. Applicability Issues ................................................................................................ 50.

1. Bulk-Power System v. Bulk Electric System ..................................................... 50.

2. Applicability to Small Entities ........................................................................... 80.

3. Definition of User of the Bulk-Power System ................................................ 110.

4. Use of the NERC Functional Model................................................................. 117.

5. Regional Reliability Organizations .................................................................. 146.
Docket No. RM06-16-000 - 2 - 

D. Mandatory Reliability Standards.......................................................................... 161.

1. Legal Standard for Approval of Reliability Standards..................................... 161.

2. Commission Options When Acting on a Reliability Standard......................... 169.

3. Prioritizing Modifications to Reliability Standards.......................................... 193.

4. Trial Period ....................................................................................................... 208.

5. International Coordination ............................................................................... 226.

E. Common Issues Pertaining to Reliability Standards ............................................ 234.

1. Blackout Report Recommendation on Liability Limitations ........................... 234.

2. Measures and Levels of Non-Compliance........................................................ 238.

3. Ambiguities and Potential Multiple Interpretations ......................................... 264.

4. Technical Adequacy ......................................................................................... 282.

5. Fill-in-the-Blank Standards .............................................................................. 287.

F. Discussion of Each Individual Reliability Standard ............................................ 304.

1. BAL: Resource and Demand Balancing.......................................................... 305.

2. CIP: Critical Infrastructure Protection............................................................. 445.

3. COM: Communications ................................................................................... 472.

4. EOP: Emergency Preparedness and Operations.............................................. 541.

5. FAC: Facilities Design, Connections, Maintenance, and Transfer Capabilities677.

6. INT: Interchange Scheduling and Coordination.............................................. 795.

7. IRO: Interconnection Reliability Operations and Coordination...................... 888.

8. MOD: Modeling, Data, and Analysis............................................................ 1006.

9. PER: Personnel Performance, Training and Qualifications .......................... 1324.

10. PRC: Protection and Control ...................................................................... 1418.

11. TOP: Transmission Operations .................................................................. 1567.

12. TPL: Transmission Planning ...................................................................... 1684.

13. VAR: Voltage and Reactive Control........................................................... 1847.

14. Glossary of Terms Used in Reliability Standards ........................................ 1887.

III. Information Collection Statement ......................................................................... 1900.

IV. Environmental Analysis ........................................................................................ 1909.

V. Regulatory Flexibility Act ..................................................................................... 1910.

VI. Document Availability .......................................................................................... 1947.

VII. Effective Date and Congressional Notification ................................................... 1950.

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

Appendix B: Commenters on the Notice of Proposed Rulemaking 

Appendix C: Abbreviations in this Document 
Docket No. RM06-16-000 - 3 - 

I. Introduction

1. Pursuant to section 215 of the Federal Power Act (FPA), the Commission 

approves 83 of 107 proposed Reliability Standards, six of the eight proposed regional 

differences, and the Glossary of Terms Used in Reliability Standards (glossary) 

developed by 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, 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.1

 Therefore, pursuant to section 215(d)(5), we require the ERO to 

submit significant improvements to 56 of the 83 Reliability Standards that are being 

approved as mandatory and enforceable. The remaining 24 Reliability Standards will 

remain pending at the Commission until further information is provided. 

2. The Final Rule adds a new part to the Commission’s regulations, which states that 

this part applies to all users, owners and operators of the Bulk-Power System within the 

United States (other than Alaska or Hawaii) and requires that each Reliability Standard 

identify the subset of users, owners and operators to which that particular Reliability 

Standard applies. The new regulations also require that each Reliability Standard that is 

approved by the Commission will be maintained on the ERO’s Internet website for public 

inspection. 

A. Background

1. EPAct 2005 and Order No. 672

3. On August 8, 2005, the Electricity Modernization Act of 2005, which is Title XII, 

Subtitle A, of the Energy Policy Act of 2005 (EPAct 2005), was enacted into law.2

 

 1

 U.S.-Canada Power System Outage Task Force, Final Report on the August 14 

Blackout in the United States and Canada: Causes and Recommendations (April 2004) 

(Blackout Report). The Blackout Report is available on the Internet at 

http://www.ferc.gov/cust-protect/moi/blackout.asp

2

 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. 
Docket No. RM06-16-000 - 4 - 

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 or the Commission can 

independently enforce Reliability Standards.3

4. On February 3, 2006, the Commission issued Order No. 672, implementing 

section 215 of the FPA.4

 Pursuant to Order No. 672, the Commission certified one 

organization, NERC, as the ERO.5

 The ERO is required to develop Reliability Standards, 

which are subject to Commission review and approval.6

 The Reliability Standards will 

apply to users, owners and operators of the Bulk-Power System, as set forth in each 

Reliability Standard. 

5. 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 

 3

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

4

 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). 

5

 North American Electric Reliability Corp., 116 FERC ¶ 61,062 (ERO 

Certification Order), order on reh’g & compliance, 117 FERC ¶ 61,126 (ERO Rehearing 

Order) (2006), order on compliance, 118 FERC ¶ 61,030 (2007) (January 2007 

Compliance Order). 

6

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

consider when assessing whether a particular Reliability Standard is just and reasonable.7

 

According to this guidance, a 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 Reliability 

Standard should be clear and unambiguous regarding what is required and who is 

required to comply. The possible consequences for violating a Reliability Standard 

should be clear and understandable to those who must comply. There should be clear 

criteria for whether an entity is in compliance with a Reliability Standard. While a 

Reliability Standard does not necessarily need to reflect the optimal method for achieving 

its reliability goal, a Reliability Standard should achieve its reliability goal effectively 

and efficiently. A 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.8

6. A Reliability Standard may take into account the size of the entity that must 

comply and the costs of implementation. A 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 physical differences in grid characteristics 

and regional Reliability Standards that result in more stringent practices. It can also 

account for regional variations in the organizational and corporate structures of 

transmission owners and operators, variations in generation fuel type and ownership 

patterns, and regional variations in market design if these affect the proposed Reliability 

Standard. Finally, a Reliability Standard should have no undue negative effect on 

competition.9

 

7. Order No. 672 directs the ERO to explain how the factors the Commission 

identified are satisfied and how the ERO balances any conflicting factors when seeking 

approval of a proposed Reliability Standard.10

 7

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

8

 Id. at P 329. 

9

 Id. at P 332. 

10 Id. at P 337. 
Docket No. RM06-16-000 - 6 - 

8. Pursuant to section 215(d)(2) of the FPA and § 39.5(c) of the Commission’s 

regulations, the Commission will 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 will not defer to the ERO or to such a 

Regional Entity with respect to the effect of a proposed Reliability Standard or proposed 

modification to a Reliability Standard on competition.11

9. 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 

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.12

10. Where a Reliability Standard requires significant improvement, but is otherwise 

enforceable, the Commission approves the Reliability Standard. In addition, as a distinct 

action under the statute, the Commission directs the ERO to modify such a Reliability 

Standard, pursuant to section 215(d)(5) of the FPA, to address the identified issues or 

concerns. This approach will allow the proposed Reliability Standard to be enforceable 

while the ERO develops any required modifications. 

11. 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.13 

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. 

2. NERC Petition for Approval of Reliability Standards

12. 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 

 11 18 CFR 39.5(c)(1), (3). 

12 18 CFR 39.5(a). 

13 18 CFR 39.5(e). 
Docket No. RM06-16-000 - 7 - 

are the subject of this Final Rule.14 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 stated that it simultaneously 

filed the proposed Reliability Standards with governmental authorities in Canada. The 

Commission addresses these proposed Reliability Standards in this rulemaking 

proceeding.15 

13. On November 15, 2006, NERC filed 20 revised proposed Reliability Standards 

and three new proposed Reliability Standards for Commission approval. The 20 revised 

Reliability Standards primarily provided additional Measures and Levels of NonCompliance, but did not add or revise any existing Requirements to these Reliability 

Standards. NERC requested that the 20 revised proposed Reliability Standards be 

included as part of the Final Rule issued by the Commission in this docket. The proposed 

new Reliability Standards, FAC-010-1, FAC-011-1, and FAC-014-1, will be addressed in 

a separate rulemaking proceeding in Docket No. RM07-3-000. 

14. On December 1, 2006, NERC submitted in Docket No. RM06-16-000 an 

informational filing entitled “NERC’s Reliability Standards Development Plan: 2007 — 

2009” (Work Plan). NERC stated it was submitting the Work Plan to inform the 

Commission of NERC’s program to improve the Reliability Standards that currently are 

the subject of the Commission’s rulemaking proceeding. 

3. Staff Preliminary Assessment and Commission NOPR

15. 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 identifies 

staff’s observations and concerns regarding NERC’s then-current voluntary Reliability 

 14 The filed proposed Reliability Standards are not attached to the Final Rule 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. 

15 Eight proposed Reliability Standards submitted in the August 29, 2006 filing 

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. 
Docket No. RM06-16-000 - 8 - 

Standards. The Staff Preliminary Assessment describes issues common to a number of 

proposed Reliability Standards. It reviews and identifies issues regarding each individual 

Reliability Standard but did not make specific recommendations regarding the 

appropriate Commission action on a particular proposal. 

16. Comments on the Staff Preliminary Assessment were due by June 26, 2006. 

Approximately 50 entities 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, the 

comments and other related issues. 

4. Notice of Proposed Rulemaking

17. The Commission issued the NOPR on October 20, 2006, and required that 

comments be filed within 60 days after publication in the Federal Register, or January 2, 

2007.16 The Commission granted the request of several commenters to extend the 

comment date to January 3, 2007. Several late-filed comments were filed. The 

Commission will accept these late-filed comments. A list of commenters appears in 

Appendix A. 

18. On November 27, 2006, the Commission issued a notice on the 20 revised 

Reliability Standards filed by NERC on November 15, 2006. In the notice, the 

Commission explained that, because of their close relationship with Reliability Standards 

dealt with in the October 20, 2006 NOPR, the Commission would address these 20 

revised Reliability Standards in this proceeding.17 The notice provided an opportunity to 

comment on the revised Reliability Standards, with a comment due date of January 3, 

2007. 

19. The Commission issued a notice on NERC’s Work Plan on December 8, 2006. 

While the Commission sought public comment on NERC’s filing because it was 

informative on the prioritization of modifying Reliability Standards raised in the NOPR, 

 16 Mandatory Reliability Standards for the Bulk Power System, Notice of 

Proposed Rulemaking, 71 FR 64,770 (Nov. 3, 2006), FERC Stats. & Regs., Vol IV, 

Proposed Regulations, ¶ 32,608 (2006). 

17 The modified 20 Reliability Standards are: CIP-001-1; COM-001-1; COM-002-

2; EOP-002-2; EOP-003-1; EOP-004-1; EOP-006-1; INT-001-2; INT-003-2; IRO-001-1; 

IRO-002-1; IRO-003-2; IRO-005-2; PER-004-1; PRC-001-1; TOP-001-1; TOP-002-2; 

TOP-004-1; TOP-006-1; and TOP-008-1. 
Docket No. RM06-16-000 - 9 - 

the notice emphasized that the Work Plan was filed for informational purposes and 

NERC stated that it is not requesting Commission action on the Work Plan. 

20. On February 6, 2007, NERC submitted a request for leave to file supplemental 

information, and included a revised version of the NERC Statement of Compliance 

Registry Criteria (Revision 3). NERC noted that it had submitted with its NOPR 

comments an earlier version of the same document.18 

II. Discussion

A. Overview

1. The Commission’s Underlying Approach to Review and 

Disposition of the Proposed Standards

21. In this Final Rule, the Commission takes the important step of approving the first 

set of mandatory and enforceable Reliability Standards within the United States in 

accordance with the provisions of new section 215 of the FPA. The Commission’s action 

herein marks the official departure from reliance on the electric utility industry’s 

voluntary compliance with Reliability Standards adopted by NERC and the regional 

reliability councils and the transition to the mandatory, enforceable Reliability Standards 

under the Commission’s ultimate oversight through the ERO and, eventually, the 

Regional Entities, as directed by Congress. As we discuss more fully below, in deciding 

whether to approve, approve and direct modifications, or remand each of the proposed 

Reliability Standards in this Final Rule, our overall approach has been one of carefully 

balancing the need for practicality during the time of transition with the imperatives of 

section 215 of the FPA and Order No. 672, and other considerations. 

22. In addition, our action today is informed by the August 14, 2003 blackout which 

affected significant portions of the Midwest and Northeast United States and Ontario, 

Canada and impacted an estimated 50 million people and 61,800 megawatts of electric 

load. As noted in the NOPR, a joint United States-Canada task force found that the 

blackout was caused by several entities violating NERC’s then-effective policies and 

Reliability Standards.19 Those violations directly contributed to the loss of a significant 

amount of electric load. The joint task force identified both the need for legislation to 

make Reliability Standards mandatory and enforceable with penalties for noncompliance, 

 18 See NERC comments, Attachment B. 

19 NOPR at P 14. 
Docket No. RM06-16-000 - 10 - 

as well as particular Reliability Standards that needed corrections to make them more 

effective in preventing blackouts. Indeed, the August 2003 blackout and the 

recommendations of the joint task force helped foster enactment of EPAct 2005 and new 

section 215 of the FPA. 

2. Mandates of Section 215 of the FPA

23. The imperatives of section 215 of the FPA address not only the protection of the 

reliability of the Bulk-Power System but also the reliability roles of the Commission, the 

ERO, the Regional Entities, and the owners, users and operators of the Bulk-Power 

System.20 First, section 215 specifies that the ERO is to develop and enforce a 

comprehensive set of Reliability Standards subject to Commission review. Section 215 

explains that a Reliability Standard is a requirement approved by the Commission that is 

intended to provide for the Reliable Operation of the Bulk-Power System. Such 

requirement may pertain to the operation of existing Bulk-Power System facilities, 

including cybersecurity protection, or it may pertain to the design of planned additions or 

modifications to such facilities to the extent necessary to provide for reliable operation of 

the Bulk-Power System.21

24. Second, the reliability mandate of section 215 of the FPA addresses not only the 

comprehensive maintenance of the reliable operation of each of the elements of the BulkPower System, it also contemplates the prevention of incidents, acts and events that 

would interfere with the reliable operation of the Bulk-Power System. Further, section 

215 seeks to prevent an instability, an uncontrolled separation or a cascading failure, 

whether resulting from either a sudden disturbance, including a cybersecurity incident, or 

an unanticipated failure of the system elements. In order to avoid these outcomes, the 

 20 Generally speaking, the nation’s Bulk-Power System has been described as 

consisting of “generating units, transmission lines and substations, and system controls.” 

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. The transmission 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, transmission 

lines and other parts of the transmission system, including control facilities, serve to 

transmit electricity in bulk from generation sources to concentrated areas of retail 

customers, while the distribution system moves the electricity to where these retail 

customers consume it at a home or business. 

21 16 U.S.C. 824o(a)(3). 
Docket No. RM06-16-000 - 11 - 

various elements and components of the Bulk-Power System are to be operated within 

equipment and electric system thermal, voltage and stability limits.22 

25. Third, section 215 of the FPA explains that the Bulk-Power System broadly 

encompasses both the facilities and control systems necessary for operating an 

interconnected electric energy transmission network (or any portion thereof) as well as 

the electric energy from generation facilities needed to maintain transmission system 

reliability.23 Further, section 215 explains that the interconnected transmission network 

within an Interconnection is a geographic area in which the operation of Bulk-Power 

System components is synchronized such that the failure of one such component, or more 

than one such component, may adversely affect the ability of the operators of other 

components within the system to maintain reliable operation of the facilities within their 

control.24 A Cybersecurity Incident is explained to be a malicious act that disrupts or 

attempts to disrupt the operation of programmable electronic devices and communication 

networks including hardware, software or data that are essential to the reliable operation 

of the Bulk-Power System.25 

26. Next, as to the reliability roles of the Commission and others, section 215 of the 

FPA explains that the ERO must file each of its Reliability Standards and any 

modification thereto with the Commission.26 The Commission will consider a number of 

factors before taking any action with respect thereto. We may approve the Reliability 

Standard or its modification only if we determine that it is just, reasonable, and not 

unduly discriminatory or preferential and in the public interest to do so. Also, in doing 

so, we are instructed to give due weight to the technical expertise of the ERO concerning 

 22 “The term ‘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 a sudden disturbance, including a cybersecurity incident, or unanticipated 

failure of system elements.” 16 U.S.C. 824o(a)(4). 

23 16 U.S.C. 824o(a)(1). 

24 16 U.S.C. 824o(a)(5). 

25 16 U.S.C. 824o(a)(8). 

26 “The Electric Reliability Organization shall file each Reliability Standard or 

modification to a Reliability Standard that it proposes to be made effective under this 

section with the Commission.” 16 U.S.C. 824o(d)(1). 
Docket No. RM06-16-000 - 12 - 

the content of a proposed standard or a modification thereto. We must also give due 

weight to an Interconnection-wide Regional Entity with respect to a proposed Reliability 

Standard to be applicable within that Interconnection, except for matters concerning the 

effect on competition.27

27. Similarly, in considering whether to forward a proposed Reliability Standard to the 

Commission for approval, the ERO must rebuttably presume that a proposal from a 

Regional Entity organized on an Interconnection-wide basis for a Reliability Standard or 

modification to a Reliability Standard to be applicable on an Interconnection-wide basis 

is just, reasonable, and not unduly discriminatory or preferential, and in the public 

interest.28 The Commission may also give deference to the advice of a Regional 

Advisory Body organized on an Interconnection-wide basis in regard to whether a 

proposed Reliability Standard is just, reasonable and not unduly discriminatory or 

preferential and in the public interest, as it may apply within the region.29

28. Finally, the Commission is further instructed to remand to the ERO for further 

consideration any standard or modification that it does not approve in whole or part.30 

We may also direct the ERO to submit a proposed Reliability Standard or modification 

that addresses a specific problem if we consider this course of action to be appropriate.31 

Further, if we find that a conflict exists between a Reliability Standard and any function, 

rule, order, tariff, rate schedule, or agreement accepted, approved, or ordered by the 

 27 “The Commission may approve, by rule or order, a proposed Reliability 

Standard or modification to a Reliability Standard if it determines that the standard is 

just, reasonable, not unduly discriminatory or preferential, and in the public interest. The 

Commission shall give due weight to the technical expertise of the Electric Reliability 

Organization with respect to the content of a proposed standard or modification to a 

Reliability Standard and to the technical expertise of a regional entity organized on an 

Interconnection-wide basis with respect to a Reliability Standard to be applicable within 

that Interconnection, but shall not defer with respect to the effect of a standard on 

competition. A proposed standard or modification shall take effect upon approval by the 

Commission.” 16 U.S.C. 824o(d)(2). 

28 16 U.S.C. 824o(d)(3). 

29 16 U.S.C. 824o(j). 

30 16 U.S.C. 824o(d)(4). 

31 16 U.S.C. 824o(d)(5). 
Docket No. RM06-16-000 - 13 - 

Commission applicable to a transmission organization,32 and if we determine that the 

Reliability Standard needs to be changed as a result of such a conflict, we must order the 

ERO to develop and file with the Commission a modified Reliability Standard for this 

purpose.33

3. Balancing the Need for Practicality with the Mandates of Section 

215 and Order No. 672

29. In enacting section 215, Congress chose to expand the Commission's jurisdiction 

beyond our historical role as primarily an economic regulator of the public utility 

industry under Part II of the FPA. Many entities not previously touched by our economic 

regulatory oversight are within our reliability purview and these entities will have to 

familiarize themselves not only with the new reliability obligations under section 215 of 

the FPA and the Reliability Standards that we are approving in this Final Rule, but also 

any proposed Reliability Standards or improvements that may implicate them that are 

under development by the ERO and the Regional Entities.34 We have taken these and 

other considerations into account and have tried to reach an appropriate balance among 

them. 

30. First, we have decided, as proposed in our NOPR, to approve most of the 

Reliability Standards that the ERO submitted in this proceeding, even though concerns 

with respect to many of the Reliability Standards have been voiced. As most of these 

 32 Under section 215, a transmission organization is a RTO, ISO, independent 

transmission provider or other Transmission Organization finally approved by the 

Commission for the operation of transmission facilities. 16 U.S.C. 824o(a)(6). 

33 16 U.S.C. 824o(d)(6). 

34 Section 215(b) of the FPA provides that, for purposes of approving Reliability 

Standards and enforcing compliance with such standards, the Commission shall have 

jurisdiction over those entitles that had previously been excluded under section 201(f) of 

the FPA. Section 201(f) excludes the United States, a state or any political subdivision of 

a state, an electric cooperative that receives financing under the Rural Electrification Act 

of 1936, 7 U.S.C. 901 et seq., or that sells less than 4,000,000 megawatt hours of 

electricity per year, or any agency, authority, or instrumentality of any one or more of the 

foregoing, or any corporation which is wholly owned, directly or indirectly, by any one 

or more of the foregoing, or any officer, agent, or employee of any of the foregoing 

acting as such in the course of his official duty, unless such provision makes specific 

reference thereto. 16 U.S.C. 824(f). 
Docket No. RM06-16-000 - 14 - 

Reliability Standards are already being adhered to on a voluntary basis, we are concerned 

that to remand them and leave no standard in place in the interim would not help to 

ensure reliability when such standards could be improved over time. In these cases, 

however, the concerns highlighted below merit the serious attention of the ERO and we 

are directing the ERO to consider what needs to be done and how to do so, often by way 

of descriptive directives.35

31. We emphasize that we are not, at this time, mandating a particular outcome by 

way of these directives, but we do expect the ERO to respond with an equivalent 

alternative and adequate support that fully explains how the alternative produces a result 

that is as effective as or more effective that the Commission’s example or directive. 

32. We have sought to provide enough specificity to focus the efforts of the ERO and 

others adequately. We are also sensitive to the concern of the Canadian Federal 

Provincial Territorial Working Group (FPT) about the status of an existing standard that 

is already being followed on a voluntary basis. The FPT suggests, for example, that 

instead of remanding an existing Reliability Standard, the Commission should 

conditionally approve the standard pending its modification.36 We believe the action we 

take today is similar in many respects to this approach. 

33. We have also adopted a number of other measures to mitigate many of the 

difficulties associated with the electric utility industry’s preparation for and transition to 

 35 In Order No. 672, we decided, in response to some commenters’ suggestions 

that a Reliability Standard should address the “what” and not the “how” of reliability and 

that the actual implementation should be left to entities such as control area operators and 

system planners, that in some limited situations, there may be good reason to do so but, 

for the most part, in other situations the “how” may be inextricably linked to the 

Reliability Standard and may need to be specified by the ERO to ensure the enforcement 

of the standard. Since leaving out implementation features could sacrifice necessary 

uniformity, create uncertainty for the entity that has to follow the standard, make 

enforcement difficult, or increase the complexity of the Commission’s oversight and 

review process, we left it to the ERO to reach the appropriate balance between reliability 

principles and implementation features. Order No. 672 at P 260. We also decided that 

the Commission’s authority to order the ERO to address a particular reliability topic is 

not in conflict with other provisions of Order No. 672 that assigned the responsibility for 

developing a proposed Reliability Standard to the ERO. Order No. 672 at P 416. 

36 FPT letter to Chairman Kelliher (submitted on July 10, 2006) (placed in the 

record of this proceeding). 
Docket No. RM06-16-000 - 15 - 

mandatory Reliability Standards. For instance, we are directing the ERO and Regional 

Entities to focus their enforcement resources during an initial period on the most serious 

Reliability Standard violations. Moreover, because commenters have raised valid 

concerns as discussed below, our Final Rule relies on the existing NERC definition of 

bulk electric system and its compliance registration process to provide as much certainty 

as possible regarding the applicability and responsibility of specific entities under the 

approved standards. This approach should also assuage the concerns of many smaller 

entities. 

B. Discussion of the Commission’s New Regulations 

1. Applicability

34. In the NOPR, the Commission proposed to add § 40.1(a) to the regulations. The 

Commission proposed that § 40.1(a) would provide 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 section 215(b) of the FPA and § 39.2 of the 

Commission’s regulations. 

35. The Commission further proposed to add § 40.1(b), which would require each 

Reliability Standard made effective under this Part to identify the subset of users, owners 

and operators to whom that particular Reliability Standard applies. 

a. Comments 

36. NERC agrees with the Commission’s proposal to add the text of § 40.1(b) to its 

regulations to require that each Reliability Standard identify the subset of users, owners 

and operators to which that particular Reliability Standard applies and believes this 

requirement is currently established in NERC’s Rules of Procedure. 

37. TANC supports proposed § 40.1. It states that requiring each Reliability Standard 

to identify the subset of users, owners and operators to whom it applies, thereby limiting 

the scope of the broad phrase "users, owners and operators," is a critical step to removing 

ambiguities from the Reliability Standards. According to TANC, the proposed text of 

§ 40.1 would eliminate ambiguities with regard to the entity responsible for complying 

with each Reliability Standard. In this way, Regional Entities and other interested parties 

will be allowed to weigh in during the Reliability Standards development process on the 

breadth of each standard and may urge NERC to accept any necessary regional variations 

that are necessary to maintain adequate reliability within the region. 
Docket No. RM06-16-000 - 16 - 

38. APPA believes that the Commission’s proposal to add § 40.1 and 40.2 to its 

regulations is generally appropriate and acceptable, but the regulatory language should be 

amended to make clear the exact universe of users, owners and operators of the BulkPower System to which the mandatory Reliability Standards apply. It recommends that 

the regulations provide that determinations as to applicability of standards to particular 

entities shall be resolved by reference to the NERC compliance registry. 

b. Commission Determination

39. The Commission adopts the NOPR’s proposal to add § 40.1 to the Commission’s 

regulations. The Commission disagrees with APPA’s suggestion to define here the exact 

universe of users, owners and operators of the Bulk-Power System to which the 

mandatory Reliability Standards apply. Rather, consistent with NERC’s existing 

approach, we believe that it is appropriate that each Reliability Standard clearly identify 

the subset of users, owners and operators to which it applies and the Commission 

determines applicability on that basis. As we discuss later, we approve NERC’s current 

compliance registry to provide certainty and stability in identifying which entities must 

comply with particular Reliability Standards. 

2. Mandatory Reliability Standards

40. The Commission proposed to add § 40.2(a) to the Commission’s regulations. The 

proposed regulation text would require that each applicable user, owner and operator of 

the Bulk-Power System comply with Commission-approved Reliability Standards 

developed by the ERO, and would provide 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. 

41. The Commission further proposed to add § 40.2(b) to its regulations, providing 

that a modification to a Reliability Standard proposed to become effective pursuant to 

§ 39.5 shall not be effective until approved by the Commission. 

a. Comments

42. NERC concurs with the Commission’s proposal to require NERC to provide to the 

Commission a copy of all approved Reliability Standards for posting in its Public 

Reference Room. NERC agrees with the Commission that neither the text nor the title of 

an approved Reliability Standard should be codified in the Commission’s regulations. 
Docket No. RM06-16-000 - 17 - 

b. Commission Determination

43. For the reasons discussed in the NOPR, the Commission generally adopts the 

NOPR’s proposal to add § 40.2 to the Commission’s regulations.37 However, after 

consideration, the Commission has determined that it is not necessary to have the 

approved Reliability Standards on file in the Commission’s public reference room and on 

the NERC website. Therefore, we will require that all Commission-approved Reliability 

Standards be available on the ERO’s website, with an effective date, and revise § 40.2(b) 

to remove the following language: “which can be obtained from the Commission’s 

Public Reference Room at 888 First Street, N.E., Room 2A, Washington, D.C., 20426.” 

Further, to be consistent with Part 39 of our regulations, we remove the reference to 

NERC and replace it with “Electric Reliability Organization.” 

3. Availability of Reliability Standards

44. The Commission proposed to add § 40.3 to the regulation text, which requires 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 stated that it 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 noted that NERC currently maintains the existing, voluntary Reliability Standards on 

the NERC website. 

45. While the NOPR discusses each Reliability Standard and identifies the 

Commission’s proposed disposition for each Reliability Standard, we did not propose to 

codify either the text or the title of an approved Reliability Standard in the Commission’s 

regulations. Rather, we proposed that each user, owner or operator of the Bulk-Power 

System must comply with applicable Commission-approved Reliability Standards that 

are available in the Commission’s Public Reference Room and on the Internet at the 

ERO’s website. We stated that this approach is consistent with the statutory options of 

approving a proposed Reliability Standard or modification to a Reliability Standard “by 

rule or order.”38

 37 NOPR at P 37. 

38 See 16 U.S.C. 824o(d)(2). 
Docket No. RM06-16-000 - 18 - 

a. Comments

46. NERC states that it can successfully implement the Commission’s proposal to 

require NERC to maintain in electronic format that is accessible from the Internet the 

complete set of Reliability Standards that have been developed by the ERO and approved 

by the Commission. NERC currently maintains a public website displaying the existing, 

voluntary Reliability Standards for access by users, owners and operators of the BulkPower System. Once the proposed Reliability Standards are approved by the 

Commission, NERC will modify its website to distinguish which Reliability Standards 

have been approved by the Commission for enforcement in the United States. 

47. EEI states that the approval of Reliability Standards should be through a 

rulemaking rather than an order, except in very rare circumstances, because of the open 

nature of the rulemaking process. Where the Commission decides to proceed by order, 

EEI states that the Commission should give notice and an opportunity to comment on any 

proposed Reliability Standards. 

b. Commission Determination

48. For the reasons discussed in the NOPR, the Commission adopts the NOPR’s 

proposal to add § 40.3 to the Commission’s regulations; however the Commission has 

further clarified the proposed regulatory text.39 We clarify that the ERO must post on its 

website the currently effective Reliability Standards as approved and enforceable by the 

Commission. Further, we require the effective date of the Reliability Standards must be 

included in the posting. 

49. In response to EEI, the Commission anticipates that it will address most, if not all, 

new Reliability Standards proposed by NERC through a rulemaking process. However, 

we retain the flexibility to address matters by order where appropriate, consistent with the 

statute and our regulations.40 In Order No. 672, the Commission stated that it would 

provide notice and opportunity for public comment except in extraordinary circumstances 

and, on rehearing, clarified that any decision by the Commission not to provide notice 

 39 NOPR at P 39-41. 

40 See 16 U.S.C. 824o(d)(2) (“the Commission may approve, by rule or order, a 

proposed Reliability Standard or modification . . .”); 18 CFR 39.5(c). 
Docket No. RM06-16-000 - 19 - 

and comment when reviewing a proposed Reliability Standard will be made in 

accordance with the criteria established in section 553 of the Administrative Procedure 

Act.41

C. Applicability Issues

1. Bulk-Power System v. Bulk Electric System

50. The NOPR observed that, for purposes of section 215, “Bulk-Power System” 

means: 

(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. The NERC glossary, in contrast, states that Reliability Standards apply to the 

“bulk electric system,” which is defined by its regions in terms of a voltage threshold and 

configuration, as follows: 

As defined by the Regional Reliability Organization, the electrical 

generation resources, transmission lines, interconnections with neighboring 

systems, and associated equipment, generally operated at voltages of 100 

kV or higher. Radial transmission facilities serving only load with one 

transmission source are generally not included in this definition.[42] 

52. In the NOPR, the Commission proposed 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.43 However, the Commission interpreted 

the term “bulk electric system” to apply to: (1) all of the > 100 kV transmission systems 

and any underlying transmission system (< 100 kV) that could limit or supplement the 

 41 See Order No. 672 at P 308; Order No 672-A at P 26. 

42 NERC Glossary at 2. All citations to the Glossary in this Final Rule refer to the 

November 1, 2006 version filed on November 15, 2006.

43 NOPR at P 66-70. The Commission explained in the NOPR that regional 

definitions had not been submitted and it would not determine the appropriateness of any 

regional definition in the current rulemaking proceeding. Id. at n. 56. 
Docket No. RM06-16-000 - 20 - 

operation of the higher voltage transmission systems and (2) transmission to all 

significant local distribution systems (but not the distribution system itself), transmission 

to load centers and transmission connecting generation that supplies electric energy to the 

system. The Commission proposed that, if a question arose concerning which underlying 

transmission system limits or supplements the operation of the higher voltage 

transmission system, the ERO would determine the matter on a case-by-case basis. 

53. The Commission solicited comment on its 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. 

54. Further, the NOPR explained that 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. Thus, the NOPR proposed that, in the long run, 

NERC 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 of Reliability Standards, and that 

NERC’s revision is consistent with the statutory term Bulk-Power System. 

a. Comments

55. Most commenters, including NERC, NARUC, APPA, National Grid, EEI and 

Ontario IESO, believe that the Commission should only impose Reliability Standards on 

those entities that fall under NERC’s definition of bulk electric system as it existed under 

the voluntary regime. They state that, by extending the definition of bulk electric system, 

the Commission goes beyond what is necessary to protect Bulk-Power System reliability, 

creates uncertainty and will divert resources from monitoring compliance of those entities 

that could have a material impact on Bulk-Power System reliability. 

56. Entergy, however, agrees with the Commission that NERC’s definition of bulk 

electric system is not adequate and agrees with the Commission’s proposed 

interpretation. ISO-NE does not oppose the NOPR’s approach on how to interpret the 

term “Bulk-Power System,” but it states that this broader scope justifies a delay in the 

date civil penalties take effect, to January 1, 2008, to provide the industry sufficient time 

to review the Commission’s Final Rule and to adjust to the expanded reach of the 

Reliability Standards. 

57. NERC, APPA and NRECA maintain that there was no intentional distinction 

made by Congress between “Bulk-Power System” (as defined in section 215) and the 

“bulk electric system” (as defined by the NERC glossary). NERC asserts that recent 

discussions with stakeholders confirm NERC’s belief that there was no distinction 
Docket No. RM06-16-000 - 21 - 

intended. Moreover, NERC is not aware of any documentation that suggests a distinction 

was intended. NRECA argues that legislative intent and prior usage do not support the 

Commission’s approach to defining the Bulk-Power System. NRECA concedes that no 

conference committee report accompanied EPAct 2005, but it notes that the 

Congressional Research Service specifies in its manual on statutory interpretation that 

“[W]here Congress borrows terms of art in which are accumulated the legal tradition and 

meaning of centuries of practice, it presumably knows and adopts the cluster of ideas that 

were attached to each borrowed word in the body of learning from which it was taken.”44 

58. TAPS states that the Commission cannot lawfully “interpret” the bulk electric 

system definition contrary to its terms. According to TAPS, the Commission cannot 

include facilities below 100 kV “that could limit or supplement the operation of the 

higher voltage transmission systems,” in the bulk electric system, even if they are 

“necessary for operating” the bulk system, because these facilities are not included in 

NERC’s definition of bulk electric system. 

59. NERC states that the Commission’s proposal that NERC’s “bulk electric system” 

should apply to all of the equal to or greater than 100 kV transmission systems and any 

underlying transmission system (less than 100 kV) that could limit or supplement the 

operation of the higher voltage transmission systems is a significant expansion over what 

the industry has historically regarded as the bulk electric system, both in terms of the 

facilities covered and the entities involved. While NERC agrees with the Commission 

that Congress intended to give the Commission broad jurisdiction over the reliability of 

the Bulk-Power System, it does not believe this is the right time for the Commission to 

define the full extent of its jurisdiction or that the approach proposed in the NOPR is the 

right way to do so. In addition, NERC does not believe it is legally necessary for the 

Commission to extend its jurisdiction to the limits in a single step. 

60. NERC states that the Commission should make clear in this Final Rule that its 

jurisdiction is at least as broad as the historic NERC definition of “bulk electric system” 

and that the Commission will use that definition for the near term. NERC asserts that the 

Commission should also make clear that it is not deciding in this docket the full scope of 

its jurisdiction and is reserving its right to consider a broader definition. Instead, NERC 

states that the Commission should focus on approving an initial set of Reliability 

Standards for the core set of users, owners and operators that have the most significant 

impact on the reliability of the Bulk-Power System. NERC maintains that this core set 

has been defined through its use of the terms “bulk electric system” and “responsible 

entities” provided in the NERC Glossary, the “Applicability” section of each Reliability 

 44 NRECA, citing Morissette v. United States, 342 U.S. 246, 263 (1952). 
Docket No. RM06-16-000 - 22 - 

Standard and substantive requirements of the standards themselves, and NERC’s 

registration of specific entities that are responsible for compliance with the Reliability 

Standards. 

61. NRECA argues that the definition of “Bulk-Power System” contained in section 

215(a)(1) reflects Congressional intent to codify the established materiality component 

because Congress limited the definition of Bulk-Power System to facilities and control 

systems necessary for operating an interconnected electric energy transmission network 

and electric energy from generation facilities needed to maintain transmission system 

reliability. NRECA argues that these limiting terms mean that not all transmission 

facilities are included. In NRECA’s view, the definition of the Bulk-Power System 

within the meaning of section 215 cannot extend to radial facilities to “significant local 

distribution systems,” “load centers,” or local transmission facilities unless otherwise 

“necessary for” (i.e., material to) the reliable operation of the interconnected grid. 

Further, NRECA states that the definition of “Reliable Operation” in section 215(a) 

focuses on the reliable operation of the Bulk-Power System and not the protection of 

local load per se. 

62. Certain commenters assert that expanding the scope of the Commission’s 

jurisdiction and the scope of the Reliability Standards in this proceeding would be an 

unanticipated expansion of the reach of the existing Reliability Standards implemented 

with insufficient due process and may cause jurisdictional concerns.45 They state that the 

Reliability Standards under consideration were developed and approved through NERC’s 

Reliability Standards development process with the intention that they would apply based 

on the industry’s historical conception of the bulk electric system and that the outcome 

might have been different using the Commission’s proposed definition. NERC therefore 

argues that it would be inappropriate to assume that the requirements of the existing 

Reliability Standards would be relevant to an expanded set of entities or an expanded 

scope of facilities under a broader definition of the Bulk-Power System. NERC also 

asserts that there is no reasonable justification for subjecting “thousands of small entities” 

to the costs of compliance with the Reliability Standards when there is no reasonable 

justification to do so in terms of incremental benefit to the reliability of the Bulk-Power 

System. 

63. NRECA, APPA and others argue that the Commission’s interpretation would 

undermine, rather than promote, reliability. According to these commenters, the 

Commission’s interpretation would require new definitions, such as one for “load 

center,” and otherwise creates confusion. For example, Small Entities Forum states that 

 45 See, e.g., NERC, TAPS and NRECA. 
Docket No. RM06-16-000 - 23 - 

it is concerned with the inclusion of “transmission connecting generation that supplies 

electric energy to the system” because that could include any transmission connected to 

any generation of any size. 

64. APPA objects to the Commission’s statement that “[t]he 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.” 

APPA states that it does not believe there is an industry “understanding” that the bulk 

electric system or the Bulk-Power System necessarily encompass all transmission 

facilities that connect major generation stations to distribution systems or that there is a 

bright line between transmission and distribution facilities. APPA interprets these terms 

as describing the backbone facilities that integrate regional transmission networks. 

65. NERC’s approach to moving forward with the enforcement of mandatory 

Reliability Standards is to register the specific entities that NERC will hold accountable 

for compliance with the Reliability Standards. The registration will identify all entities 

that are material to the reliability of the Bulk-Power System. NERC maintains its most 

important role is to mitigate noncompliant behavior regardless of an entity’s registration. 

Further, NERC asserts that all that it and the Commission give up by using the 

registration approach is, at most, “one penalty, one time” for an entity. That is, if there is 

an entity that is not registered and NERC later discovers that the entity can have a 

material impact on the reliability of the Bulk-Power System, NERC has the ability to add 

the entity, and possibly other entities of a similar class, to the registration list and to direct 

corrective action by that entity on a going forward basis.46 Thereafter, of course, the 

entity would be subject to sanctions. APPA, TANC, AMP-Ohio and NPCC support this 

approach. While SoCal Edison believes that there can be no single definition of BulkPower System, it states that NERC’s registry is a good starting point to developing 

general criteria for what facilities should be subject to the Reliability Standards. 

66. AMP-Ohio supports NERC’s proposal to include any additional entities or 

facilities that it believes could have a detrimental effect on the reliability of the bulk 

electric system on a case-by-case basis over time. Further, Ontario IESO suggests that if 

the Commission believes that NERC’s definition of bulk electric system excludes 

facilities that should be subject to Reliability Standards for reasons other than preventing 

cascading outages, the Commission could submit a detailed request through the ERO 

Reliability Standards development process. 

 46 See Rules of Procedure, § 500. 
Docket No. RM06-16-000 - 24 - 

67. NERC and EEI believe that, in the long run, NERC should be directed to develop, 

through its Reliability Standards development process, a single process to identify the 

specific elements of the Bulk-Power System that must comply with Reliability Standards 

under section 215. According to NERC, the Commission, the states, and all other 

stakeholders would benefit tremendously from a deliberate dialogue on these matters. 

NERC asks that the Commission not directly define the outer limits of its jurisdiction 

under section 215, but requests that the Commission direct NERC to undertake certain 

activities to reconcile the definitions of bulk electric system and Bulk-Power System and 

report the results back to the Commission. 

68. Similarly, TAPS, APPA, Duke and MidAmerican state that, if there is a problem 

with NERC’s current definition of the bulk electric system, the Commission should 

require NERC to revisit it using the ANSI process to give “due weight” to NERC’s 

technical expertise. AMP-Ohio, TANC, Georgia Operators and Entergy state that 

Regional Entities should play a primary role in defining the facilities that are subject to a 

Reliability Standard because the Regional Entities will have more detailed system 

knowledge in their regions than NERC or the Commission. 

69. The Connecticut Attorney General, the Connecticut DPUC and the New England 

Conference of Public Utilities Commissioners maintain that NERC's definition of the 

“bulk electric system” exceeds the Commission’s jurisdiction by including generation 

that is not needed to maintain transmission system reliability and therefore intrudes into 

state jurisdiction over generation resource adequacy matters and is unlawful. According 

to Connecticut DPUC, section 215(a)(1) of the FPA excludes from federal regulation 

(1) facilities that are used in local distribution, (2) facilities and control systems that are 

not necessary for operating an interconnected electric energy transmission network or 

part of a network and (3) electric energy from generating facilities not needed to maintain 

transmission system reliability. Connecticut DPUC maintains that, in contrast, NERC’s 

definition replaces the FPA definition with criteria based on voltage thresholds for 

transmission facilities and electric energy from generating facilities. According to 

Connecticut DPUC, NERC’s definition does not comply with section 215(a)(1) because it 

includes facilities and equipment that are neither “necessary” for operation of the 

transmission network nor “needed” to maintain transmission system reliability. The 

Connecticut Attorney General and Connecticut DPUC, therefore, urge the Commission to 

reject this definition. 

70. Further, in Connecticut DPUC’s view, because the Commission cannot adopt 

NERC’s definition of bulk electric system, it cannot expand the boundaries of its 

jurisdiction farther than the bulk electric system. It maintains that Congress did not give 

the Commission jurisdiction to mandate and enforce all Reliability Standards, especially 

those related to the long-term adequacy of generation resources; therefore, the 

Commission may not delegate to an ERO authority that it does not have. APPA also 
Docket No. RM06-16-000 - 25 - 

states that the Commission expanded the definition of the bulk electric system so that it 

may affect facilities subject to state reliability jurisdiction, such as low-voltage 

transmission systems that affect only the local areas served by those facilities, which do 

not cause cascading outages, without explaining why it is necessary to federalize 

reliability responsibility for outages on these facilities. 

71. NARUC and New York Commission maintain that the Commission’s proposed 

interpretation of what facilities constitute the Bulk-Power System is inconsistent with 

section 215 of the FPA. They state that the ability of a facility to “limit or supplement” 

the transmission system does not automatically mean that a facility is necessary for 

operating an interconnected transmission system, as required by the FPA, or for 

maintaining system reliability. According to NARUC, Congress only authorized the 

Commission to approve Reliability Standards necessary for operating an interconnected 

electric energy transmission network. Although the NOPR interpretation includes these 

underlying facilities, it also covers others that are not required to operate an 

interconnected transmission network. 

72. Moreover, NARUC and New York Commission state that the NOPR proposal to 

define Bulk-Power System as all facilities operating at or above 100 kV exceeds the 

Commission’s jurisdiction. According to NARUC and New York Commission, there is 

generally a layer of “area” transmission facilities below the “Bulk-Power System” and 

above distribution facilities that move energy within a service territory and toward load 

centers. However, NARUC and New York Commission claim that only a small subset of 

these underlying facilities assists in maintaining the reliability of the Bulk-Power System. 

73. Several commenters, including New York Commission, NYSRC, Massachusetts 

DTE, NPCC, TANC and Ontario IESO, support a functional, impact-based approach to 

applying Reliability Standards. According to NPCC, neither NERC nor section 215 of 

the FPA provide a rigorous approach to determining which elements play a role in 

maintaining reliability of the bulk electric system. These commenters generally state that 

an impact-based approach would define those elements necessary for Reliable Operation 

and ensure that compliance and enforcement efforts concentrate on those facilities that 

materially affect the Reliable Operation of the interconnected Bulk-Power System, while 

at the same time balancing the costs imposed by mandatory Reliability Standards with the 

reliability improvement realized on the interconnected Bulk-Power System. 

74. Ontario IESO maintains that reliability impact is a process of assessing facilities to 

determine if, due to recognized contingencies and other test criteria, they represent a 

significant adverse impact beyond a local area. This assessment will be the basis of a 

consistent test methodology the ERO must develop to define the facilities included within 

the overall Bulk-Power System to which a Reliability Standard would apply. Ontario 

IESO states that the Commission should direct the ERO to take the lead in developing the 
Docket No. RM06-16-000 - 26 - 

impact assessment procedure to provide a consistent and uniform methodology that can 

be applied by any Regional Entity. Ontario IESO does not support the Commission’s 

proposal to limit case-by-case determinations to underlying transmission systems 

operating at less than 100 kV. 

b. Commission Determination

75. The Commission agrees with commenters that, at least initially, expanding the 

scope of facilities subject to the Reliability Standards could create uncertainty and might 

divert resources as the ERO and Regional Entities implement the newly created 

enforcement and compliance regime. Further, we agree with commenters that 

unilaterally modifying the definition of the term bulk electric system is not an effective 

means to achieve our goal. For these reasons, the Commission is not adopting the 

proposed interpretation contained in the NOPR. Rather, for at least an initial period, the 

Commission will rely on the NERC definition of bulk electric system47 and NERC’s 

registration process to provide as much certainty as possible regarding the applicability to 

and the responsibility of specific entities to comply with the Reliability Standards in the 

start-up phase of a mandatory Reliability Standard regime.48

76. However, we disagree with NERC, APPA and NRECA that there is no intentional 

distinction between Bulk-Power System and bulk electric system. NRECA states that 

“[W]here Congress borrows terms of art in which are accumulated the legal tradition and 

meaning of centuries of practice, it presumably knows and adopts the cluster of ideas that 

were attached to each borrowed word in the body of learning from which it was taken.”49 

In this instance, however, Congress did not borrow the term of art – bulk electric system 

– but instead chose to create a new term, Bulk-Power System, with a definition that is 

distinct from the term of art used by industry. In particular, the statutory term does not 

establish a voltage threshold limit of applicability or configuration as does the NERC 

definition of bulk electric system. Instead, section 215 of the FPA broadly defines the 

Bulk-Power System as “facilities and control systems necessary for operating an 

 47 “As defined by the Regional Reliability Organization, the electrical generation 

resources, transmission lines, interconnections with neighboring systems, and associated 

equipment, generally operated at voltages of 100 kV or higher. Radial transmission 

facilities serving only load with one transmission source are generally not included in this 

definition.” 

48 See Section II.C.2., Applicability to Small Entities, infra. 

49 Citing Morissette v. United States, 342 U.S. 246, 263 (1952). 
Docket No. RM06-16-000 - 27 - 

interconnected electric energy transmission network (or any portion thereof) [and] 

electric energy from generating facilities needed to maintain transmission system 

reliability.” Therefore, the Commission confirms its statements in the NOPR that the 

Bulk-Power System reaches farther than those facilities that are included in NERC’s 

definition of the bulk electric system.50

77. Although we are accepting the NERC definition of bulk electric system and 

NERC’s registration process for now, the Commission remains concerned about the need 

to address the potential for gaps in coverage of facilities. For example, some current 

regional definitions of bulk electric system exclude facilities below 230 kV and 

transmission lines that serve major load centers such as Washington, DC and New York 

City.51 The Commission intends to address this matter in a future proceeding. As a first 

step in enabling the Commission to understand the reach of the Reliability Standards, we 

direct the ERO, within 90 days of this Final Rule, to provide the Commission with an 

informational filing that includes a complete set of regional definitions of bulk electric 

system and any regional documents that identify critical facilities to which the Reliability 

Standards apply (i.e., facilities below a 100 kV threshold that have been identified by the 

regions as critical to system reliability). 

78. The Commission believes that the above approach satisfies concerns raised by 

NARUC and New York Commission that the proposal to interpret Bulk-Power System

exceeds the Commission’s jurisdiction. When the Commission addresses this matter in a 

future proceeding, it will consider NARUC’s and New York Commission’s comments 

regarding the “layer of ‘area’ transmission.” 

79. We disagree with commenters claiming that the ERO’s definition of bulk electric 

system is broader than the statutory definition of Bulk-Power System. Connecticut 

Attorney General, Connecticut DPUC and others argue that the ERO’s definition of bulk 

electric system exceeds the Commission’s jurisdiction by including generation that is not 

needed to maintain transmission system reliability and, therefore, intrudes into state 

jurisdiction over generation resource adequacy. First, none of the Reliability Standards 

submitted by the ERO set requirements for resource adequacy. Moreover, commenters 

have not adequately supported their claim that the “threshold” in the NERC definition of 

bulk electric system that includes facilities “generally operated at 100 kV or higher” is 

 50 NOPR at P 66. For these same reasons, the Commission rejects the position of 

those commenters that suggest the statutory definition of Bulk-Power System is more 

limited than the NERC definition of bulk electric system. 

51 See id. at P 64-65 & n.53-54. 
Docket No. RM06-16-000 - 28 - 

broader than the statutory phrase “electric energy from generation facilities needed to 

maintain transmission system reliability.” As stated explicitly in the NERC definition, 

this is a “general” threshold and allows leeway to address specific circumstances. On its 

face, the NERC definition is not overbroad; as applied, it must be interpreted and applied 

consistent with the statutory language in section 215. Finally, as stated above, we believe 

that the ERO definition of bulk electric system is narrower than the statutory definition of 

Bulk-Power System. 

2. Applicability to Small Entities

80. The NOPR discussed NERC’s plan to, in the future, identify in a particular 

Reliability Standard limitations on applicability based on electric facility characteristics.52 

The Commission agreed 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, the Commission stated that a “blanket waiver” approach that would 

exempt entities below a threshold level from compliance with all Reliability Standards 

would not be appropriate because there may be instances where a small entity’s 

compliance is critical to reliability. The Commission also proposed to direct NERC to 

develop procedures that permit a joint action agency or similar organization to accept 

compliance responsibility on behalf of their members. 

81. In addition, the Commission solicited 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 and, if so, what, if any, 

process the ERO or Regional Entity should provide when making such a determination. 

a. Identifying Applicable Small Entities 

i. Comments

82. While certain commenters, including EEI, FirstEnergy, SERC, Xcel and Entergy, 

agree with the Commission that a blanket waiver to exempt small entities from 

compliance is not appropriate because there may be instances where a small entity’s 

compliance is critical to reliability, APPA, ELCON, Process Electricity Committee, 

MEAG and South Carolina E&G advocate a blanket waiver. 

 52 Id. P 49-53. 
Docket No. RM06-16-000 - 29 - 

83. APPA notes that none of the entities that contributed to the August 14, 2003 

blackout were “small entities” within the meaning of the Regulatory Flexibility Act. 

APPA and MEAG believe that the Commission’s refusal to provide for a blanket waiver 

to small entities is counterproductive to maintaining reliability, as it will distract 

compliance staff at NERC and the Regional Entities from identifying and monitoring 

those with a material impact on reliability, and gives insufficient deference to NERC as 

the ERO. APPA recommends that the methods and procedures used to identify critical 

facilities that impact the bulk electric system, regardless of size, should be the subject of 

a specific set of NERC Reliability Standards. Objective, transparent study criteria and 

assumptions and due process for affected entities are essential to implement such 

standards properly. Regional Entities should take advantage of industry expertise in 

developing and applying the methodology for determining critical facilities. 

84. According to MEAG, because the Commission has already determined that it is 

not bound by the NERC compliance registry,53 the NOPR’s approach leaves small 

systems, which do not appear on the compliance registry, confused about whether the 

Reliability Standards apply to them. MEAG asks the Commission to either: (1) grant a 

temporary, size-based exemption to those small entities that NERC omits from its 

preliminary compliance registry; or (2) direct NERC to develop and file with the 

Commission an appropriate size-based exemption for small entities. 

85. Several commenters suggest thresholds for applying Reliability Standards. 

MEAG states that an appropriate threshold level for an exemption, on either an interim or 

more permanent basis, should at least provide that a LSE or distribution provider should 

generally be omitted from the compliance registry if it meets the following criteria: (1) its 

peak load is less than 25 MW and it is not directly connected to the Bulk-Power System; 

(2) it is not designated as the responsible entity for facilities that are part of a required 

underfrequency load shedding (UFLS) program designed, installed, and operated for the 

protection of the Bulk-Power System; or (3) it is not designated as the responsible entity 

for facilities that are part of a required undervoltage load shedding (UVLS) program 

designed, installed, and operated for the protection of the Bulk-Power System. STI 

Capital states that there should be a rebuttable presumption that any generation facility 

below 50 MW does not pose a threat to reliability. Moreover, more data intensive 

standards are beyond the ability of small generators. 

86. SERC states that exemptions should be granted through the Reliability Standards 

development process. The ERO and the Regional Entities can provide guidance in that 

process, and stakeholders have an opportunity to comment on that guidance. 

 53 See ERO Rehearing Order at P 108. 
Docket No. RM06-16-000 - 30 - 

87. A number of commenters, including APPA, NRECA, TANC and TAPS, ask the 

Commission to adopt NERC’s registry guidelines and make clear that issues of 

applicability will be determined with reference to the NERC compliance registry.54 

TAPS asks the Commission to either approve NERC’s registry criteria, or send them 

back to NERC for further consideration, with mandatory application of Reliability 

Standards deferred until NERC submits waiver criteria the Commission finds acceptable. 

According to TAPS, these criteria do not constitute a blanket waiver because they allow 

NERC and its Regional Entities to go below the general threshold requirements where 

they determine it is necessary. 

88. California Cogeneration states that, while focusing on entities that have a material 

impact on the Bulk-Power System is a possible approach to applying the Reliability 

Standards, the proposed rule does not define how “material impact” may be 

demonstrated. According to California Cogeneration, material impact will vary among 

Interconnections and it may vary among individual transmission systems. Therefore, 

California Cogeneration states that the task of defining “material impact” should be 

remanded by the Commission to NERC for resolution through an inclusive stakeholder 

process. Until that process is completed, California Cogeneration maintains that the 

Reliability Standards should not be finally adopted as mandatory and enforceable. 

89. Various Georgia cities, which are all member systems of MEAG, state that the 

Commission should place reasonable limits on the applicability of the proposed 

Reliability Standards.55 Each maintains that the Final Rule should include a rebuttable 

presumption that their distribution system facilities have no material effect on BulkPower System reliability unless established otherwise. They suggest that such a 

rebuttable presumption approach would fairly establish the “reasonable limits on 

applicability” of the Reliability Standards based on their respective sizes. Similarly, 

Small Entities Forum supports a rebuttable presumption that any LSE or distribution 

provider with less than 25 MW of load would be excluded unless a Regional Entity 

decides that a reason exists to include it. 

90. California Cogeneration states that qualifying facilities (QFs) are exempted from 

section 215 of the FPA. It claims that, after passage of EPAct 2005, the Commission 

 54 NERC has developed a Statement of Compliance Registry Criteria that provides 

guidance on how NERC will identify organizations that may be candidates for 

registration. See NERC comments, Attachment B; NERC’s February 6, 2007 

supplemental filing. 

55 See NOPR at P 1175-76. 
Docket No. RM06-16-000 - 31 - 

modified its regulations to provide that QFs are exempt from all sections of the FPA 

except sections 205, 206, 220, 221 and 222.56 Further, California Cogeneration states 

that the Commission should set limits on whether a Reliability Standard applicable to a 

generator owner or operator also applies to operators of cogeneration facilities. 

According to California Cogeneration, the Commission has clearly determined that the 

impact by a cogenerator on the reliability of the system is limited to its net load on the 

system.57 Therefore, California Cogeneration maintains that the Reliability Standards 

should reflect this limitation. 

91. Finally, Small Entities Forum and Entergy state that, despite the existence of a 

threshold in a particular Reliability Standard, the ERO or a Regional Entity should be 

permitted to include an otherwise exempt facility, on a facility-by-facility basis, if it 

determines that the facility is needed for Bulk-Power System reliability. South Carolina 

E&G states that exceptions to an exemption threshold should sufficiently improve 

reliability so as to justify the administrative costs and other burdens. However, SMA and 

MidAmerican oppose allowing the ERO or its designee to include otherwise exempt 

facilities by making exceptions. 

ii. Commission Determination

92. The Commission believes that, at the outset of this new program, it is important to 

have as much certainty and stability as possible regarding which users, owners and 

operators of the Bulk-Power System must comply with mandatory and enforceable 

Reliability Standards. NERC, as the ERO, has developed an approach to accomplish this 

through its compliance registry process. The Commission has previously found NERC’s 

compliance registry process to be 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.”58

93. NERC has provided with its NOPR comments, and in a subsequent supplemental 

filing, a Statement of Compliance Registry Criteria that describes how NERC will 

identify organizations that may be candidates for registration and assign them to the 

compliance registry. For example, NERC plans to register only those distribution 

 56 18 CFR 292.601(c).

57 California Cogenration at 6-7, citing California Independent System Operator 

Corp., 96 FERC ¶ 63,015, at P 7, 24-25 (2001). 

58 ERO Certification Order at P 689. 
Docket No. RM06-16-000 - 32 - 

providers or LSEs that have a peak load of 25 MW or greater and are directly connected 

to the bulk electric system or are designated as a responsibility entity as part of a required 

underfrequency load shedding program or a required undervoltage load shedding 

program. For generators, NERC plans to register individual units of 20 MVA or greater 

that are directly connected to the bulk electric system, generating plants with an 

aggregate rating of 75 MVA or greater, any blackstart unit material to a restoration plan, 

or any generator “regardless of size, that is material to the reliability of the Bulk-Power 

System.” 

94. The compliance registry identifies specific categories of users, owners and 

operators that correlate to the types of entities responsible for performing specific 

functions described in the NERC Functional Model.59 These same functional types are 

also used by the ERO to identify the entities responsible for compliance with a particular 

Reliability Standard in the Applicability section of a given standard. Thus, each 

registered entity will be registered under one or more appropriate functional categories, 

and that registration by function will determine with which Reliability Standards – and 

Requirements of those Reliability Standards – the entity must comply. In other words, a 

user, owner or operator of the Bulk-Power System would be required to comply with 

each Reliability Standard that is applicable to any one of the functional types for which it 

is registered. 

95. We believe that NERC has set reasonable criteria for registration and, thus, we 

approve the ERO’s compliance registry process as an appropriate approach to allow the 

ERO, Regional Entities and, ultimately, the entities responsible for compliance with 

mandatory Reliability Standards to know which entities are responsible for initial 

implementation of and compliance with the new Reliability Standards. Further, based on 

supplemental comments of APPA, TAPS and NRECA, it appears that there is support 

among many of the smaller entities for the NERC compliance registry process.60 Thus, at 

this juncture, the Commission will rely on the NERC registration process to identify the 

set of entities that are responsible for compliance with particular Reliability Standards. 

 59 The Statement of Compliance Registry Criteria, as well as the Functional 

Model, identify, inter alia, the following functions: balancing authority, distribution 

provider, generator operator, generator owner, load serving entity, planning authority, 

purchasing-selling entity, transmission owner, transmission operator and transmission 

service provider. An entity may be registered under one or more of these functions. 

60 See Supplemental Comments of TAPS (February 13, 2007), APPA 

(February 14, 2007), and NRECA (February 15, 2007). 
Docket No. RM06-16-000 - 33 - 

96. In sum, the ERO will identify those entities that must comply with Reliability 

Standards in three steps: (1) the ERO will identify and register those entities that fall 

under its definition of bulk electric system; (2) each registered entity will register in one 

or more appropriate functional categories and (3) each registered entity will comply with 

those Reliability Standards applicable to the functional categories in which it is 

registered. 

97. In response to MEAG’s concern that the Commission previously determined that 

it was not bound by the NERC compliance registry process and that there thus was 

uncertainty, the Commission is modifying the approach proposed in the NOPR and, as 

noted above, will use the NERC compliance registry to determine those users, owners 

and operators of the Bulk-Power System that must comply with the Reliability Standards. 

Each individual Reliability Standard will then identify the set of users, owners and 

operators of the Bulk-Power System that must comply with that standard. While the 

Commission may take prospective action against an entity that was not previously 

identified as a user, owner or operator through the NERC registration process once it has 

been added to the registry, the Commission will not assess penalties against an entity that 

has not previously been put on notice, through the NERC registration process, that it must 

comply with particular Reliability Standards. Under this process, if there is an entity that 

is not registered and NERC later discovers that the entity should have been subject to the 

Reliability Standards, NERC has the ability to add the entity, and possibly other entities 

of a similar class, to the registration list and to direct corrective action by that entity on a 

going-forward basis.61 The Commission believes that this should prevent an entity from 

being subject to a penalty for violating a Reliability Standard without prior notice that it 

must comply with that Reliability Standard. 

98. As stated in the NOPR, NERC has indicated that in the future it may add to a 

Reliability Standard limitations on applicability based on electric facility characteristics 

such as generator nameplate ratings.62 While the NOPR explored this approach as a 

means of addressing concerns over applicability to smaller entities, the Commission 

believes that, until the ERO submits a Reliability Standard with such a limitation to the 

Commission, the NERC compliance registry process is the preferred method of 

determining the applicability of Reliability Standards on an entity-by-entity basis. 

99. A number of municipalities and generation owners ask that the Commission 

review their particular circumstances and provide an individual waiver from compliance 

 61 See NERC Rules of Procedure, § 500. 

62 NOPR at P 49. 
Docket No. RM06-16-000 - 34 - 

with the mandatory Reliability Standards. In light of our above discussion, the 

Commission declines to determine whether any individual municipality, generation 

owner or other entity is subject to a specific Reliability Standard. Rather, NERC and the 

Regional Entities should determine such applicability in the first instance through the 

registration process. 

100. We agree with California Cogeneration that the Commission’s regulations 

currently exempt most QFs from specific provisions of the FPA including section 215.63 

The Commission is concerned, however, whether it is appropriate to grant QFs a 

complete exemption from compliance with Reliability Standards that apply to other 

generator owners and operators. It is not clear to the Commission that for reliability 

purposes there is a meaningful distinction between QF and non-QF generators. While 

such an issue is beyond the scope of the current rulemaking, we note that, concurrent 

with the issuance of this Final Rule, the Commission is issuing a notice of proposed 

rulemaking that proposes to amend the Commission’s regulation that exempts most QFs 

from section 215 of the FPA. 

101. Finally, the Commission agrees that, despite the existence of a voltage or demand 

threshold for a particular Reliability Standard, the ERO or Regional Entity should be 

permitted to include an otherwise exempt facility on a facility-by-facility basis if it 

determines that the facility is needed for Bulk-Power System reliability.64 However, we 

note that an entity that disagrees with NERC’s determination to place it in the compliance 

registry may submit a challenge in writing to NERC and, if still not satisfied, may lodge 

an appeal with the Commission.65 Therefore, a small entity may appeal to the 

Commission if it believes it should not be required to comply with the Reliability 

Standards. 

b. Ability to Accept Compliance on Behalf of Members

i. Comments

102. APPA, NERC, ELCON, APPA, TAPS and Small Entities Forum support the 

Commission’s proposal to allow a joint action agency, generation and transmission 

 63 18 CFR 292.601(c). 

64 Demand resources deemed critical by the ERO to Bulk- Power System 

reliability should be included in the registry

65 See ERO Certification Order at P 679. 
Docket No. RM06-16-000 - 35 - 

(G&T) cooperative, or other entities to accept responsibility for compliance with 

Reliability Standards on behalf of their members and also may divide the responsibilities 

for compliance with its members. APPA states that this should also be extended to 

RTOs, vertically integrated utilities, and other wholesale power suppliers that perform 

substantial reliability functions on behalf of their full requirements wholesale customers, 

including public power distribution systems and other entities that currently fulfill 

reliability functions for customers. APPA, TAPS and Small Entities Forum state that the 

procedure should allow for this responsibility to be assigned on a standard-by-standard 

basis. 

103. In response to the Commission’s proposal to direct NERC to develop procedures 

that permit a joint action agency or similar organization to accept compliance 

responsibility on behalf of its members, NERC proposes the following procedure, and has 

updated its entity registration criteria to reflect these changes.66 NERC states that each 

“central” organization should be able to register as being responsible for compliance for 

itself and collectively on behalf of its members. Each member within a central 

organization may separately register to be accountable for a particular reliability function 

defined by the standards. Under NERC’s proposal, if the central organization and a 

member organization cannot agree that one organization or the other is responsible, or if 

the parties agree that the responsibilities for a particular reliability function should be 

split, then NERC would register both entities concurrently. NERC and the Regional 

Entities will then have the authority to find either organization or both accountable for a 

violation of a Reliability Standard, based on the facts of the case and circumstances 

surrounding the violation. 

104. AMP-Ohio states that the Commission should clarify that a joint action agency 

should not be required to assume compliance responsibility for its members for all 

reliability-related functions. It asks that the Commission allow flexibility in how joint 

action agencies and their members allocate responsibility. TAPS states that joint action 

agencies should be allowed to achieve compliance with a standard at the joint action 

agency level rather than to simply stand in the shoes of their individual members. TAPS 

states that this is necessary to ensure comparable treatment for small entities in relation to 

large utilities. Where a joint action agency accepts compliance responsibility and a 

standard is susceptible to joint action agency-level assessment of compliance, the 

Commission should ask NERC to adopt such assessment to avoid an adverse impact on 

competition. 

 66 See NERC comments at 53-55; NERC supplemental filing, Statement of 

Compliance Registry Criteria (Revision 3) at 9. 
Docket No. RM06-16-000 - 36 - 

105. MEAG finds the Commission’s proposal with regard to joint action agencies 

problematic. MEAG asserts that the proxy approach is not a universal approach to small 

municipal systems. For example, this option would be fundamentally inconsistent with 

MEAG’s role as a G&T cooperative serving its member systems because MEAG has no 

authority to plan, physically operate, modify, maintain or test the local distribution 

system facilities of the member systems. Second, MEAG states that if it were to assume 

the role of the proxy compliance agent for the member systems and incur a fine for the 

failure of a few to comply with the requirements of the Reliability Standards, then the 

imposition of fines would lead to a rate increase to all systems, an improper and 

unjustifiable cost shifts among the member systems. Third, if MEAG were to err in its 

role as a proxy compliance agent for the member systems, MEAG could be sued and 

there is nothing that presently limits its liability or provides indemnification to MEAG in 

that circumstance. Moreover, MEAG states that the compliance-by-proxy option will not 

mitigate the economic impact on many small distribution-only entities because many are 

not members of joint action agencies. 

106. Several commenters, including EEI, PJM and FirstEnergy do not oppose the 

Commission’s proposal to allow organizations to accept compliance responsibility on 

behalf of members so long as compliance responsibility is clear and responsible entities 

are held accountable. FirstEnergy and PJM state that some Reliability Standards appear 

to have duplicate accountability in different organizational entities, which could create 

confusion and complicate operational authority and thus undermine the transmission 

operator chain of command required to respond quickly and decisively to system 

operational events. Further, FirstEnergy states that some Reliability Standards obligate 

an entity to perform reliability functions when that entity may not be able to perform its 

reliability function due to other legal constraints. FirstEnergy states that one effective 

approach to resolving this problem would be to establish a “priority” of control between 

entities. FirstEnergy adds that entities that are subject to legal control by ISOs and RTOs 

should be afforded a “safe harbor” under the Reliability Standards if, during an 

emergency, they perform as directed by the ISO or RTO, whether under the ISO/RTO’s 

OATT or under the ISO/RTO’s authority as reliability coordinator. 

ii. Commission Determination

107. The Commission directs the ERO to file procedures which permit (but do not 

require) an organization, such as a joint action agency, G&T cooperative or similar 

organization to accept compliance responsibility on behalf of its members. The 

Commission believes that NERC’s proposed procedures described above are reasonable, 
Docket No. RM06-16-000 - 37 - 

and directs the ERO to submit a filing within 60 days.67 In allowing a joint action 

agency, G&T cooperative or similar organization to accept compliance responsibility on 

behalf of its members, our intent is not to change existing contracts, agreements or other 

understandings as to who is responsible for a particular function under a Reliability 

Standard. Further, we clarify that there should not be overlaps in responsibility nor 

should there be any gaps. 

108. In response to concerns raised by AMP-Ohio and MEAG, the Commission 

clarifies that an organization is not required to assume compliance responsibility for its 

members for any reliability-related functions and all Reliability Standards. Moreover, 

under NERC’s proposal, a member within a central organization may separately register 

to be accountable for a particular reliability function so the responsibility for reliability 

functions can be split. The Commission believes that this will provide flexibility and will 

not require an entity to assume responsibility where it is not possible to do so. We also 

believe that NERC’s proposal adequately addresses TAPS’ concern that a joint action 

agency should be allowed to achieve compliance at the joint action agency level. 

Specifically, the Statement of Compliance Registry Criteria provides that a central 

organization can register for all functions that it performs itself and, in addition, may 

register on behalf of one or more of its members for functions for which the member 

would otherwise be required to register.68 

109. NERC, in developing its procedures relating to joint action agencies and similar 

organizations, should consider the concerns of EEI, PJM and FirstEnergy regarding the 

need for ensuring clear lines of responsibility. While we agree with FirstEnergy in the 

abstract that an entity implementing the legal directives of an ISO or RTO should not be 

penalized for following an ISO or RTO directive during an emergency, we will not 

mandate a safe harbor provision for such circumstances. Rather, these and other matters 

should be considered by the ERO or a Regional Entity when deciding the appropriate 

enforcement action in response to an event where a violation of a Reliability Standard 

may have occurred. 

 67 Section 39.10(b) of the Commission’s regulations, 18 CFR 39.10(b), provides 

that the Commission, upon its own motion or upon complaint, may propose a change to 

an ERO or Regional Entity Rule. 

68 See NERC Supplemental Filing, Statement of Compliance Registry Criteria 

(Revision 3), at 8-9. 
Docket No. RM06-16-000 - 38 - 

3. Definition of User of the Bulk-Power System 

110. In the NOPR, the Commission did not propose a generic definition of the term 

“User of the Bulk-Power System.” Rather, the Commission stated that it would 

determine applicability on a standard-by-standard basis.69 The NOPR explained that § 

40.1(b) of the proposed regulations would require the ERO to 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, which is NERC’s 

current practice. The NOPR also stated that entities concerned that a particular proposed 

Reliability Standard would apply more broadly than the statute allows may raise their 

concerns in the context of the specific Reliability Standard. 

a. Comments

111. APPA disagrees with a standard-by-standard approach to defining the term “user 

of the Bulk-Power System” because it would go beyond those facilities that are required 

to maintain the reliability of the high-voltage, bulk transmission system and intrude into 

state and local matters and trespass on state jurisdiction. According to APPA, the 

Reliability Standards themselves state their applicability in terms of the Functional 

Model, which does not include size limitations in the various functional categories 

included in it. Without some type of outer limit on the “user of the Bulk-Power System” 

definition, all such entities regardless of size or their impact on the Bulk-Power System, 

must review every proposed Reliability Standard and protest every time they have a 

“concern in the context of the specific Reliability Standard.” They must also retain 

permanent staff or consultants to evaluate new or revised standards. Rather, APPA, as 

does TANC, urges the Commission to support NERC’s registry criteria to make the 

definition of “users of the Bulk-Power System” co-extensive with the users on NERC’s 

compliance registry. 

112. SMA is concerned that not specifically defining who is a “user of the Bulk-Power 

System” will not provide timely notice to entities that are not the parties historically 

responsible for implementing NERC’s prior reliability standards. SMA states that NERC 

must identify the subset of users that must comply with any given Reliability Standard at 

a sufficiently early stage for all such affected parties to have an opportunity to raise 

objections to the sweep or content of the Reliability Standard while approval of that 

Reliability Standard is under consideration. SMA also argues that NERC’s Rules of 

Procedure must require actual notice to an entity before it is placed on the compliance 

registry. 

 69 NOPR at P 43. 
Docket No. RM06-16-000 - 39 - 

113. Southwest TDUs urges the Commission to clarify that “users” are entities that 

have more involvement with it than merely receiving power from it. Since these 

Reliability Standards will become mandatory and violation of any of them can be 

accompanied by economically significant penalties, Southwest TDUs urges the 

Commission to make every effort to be specific about what constitutes a “user.” 

114. California Cogeneration states that the Commission has not provided any detail as 

to how a “user” will be identified. The NOPR and the NERC Reliability Standards it 

proposes to adopt rely on the broad entities identified in the NERC Functional Model. 

According to California Cogeneration, using only the NERC Functional Model provides 

no detail and no differentiation in the applicability of each Reliability Standard. While a 

single definition of “user” may not be appropriate, California Cogeneration maintains that 

using only the fixed designations within the NERC Functional Model does not provide 

sufficient specificity. The terms “Generator Owner” and “Generation Operator” also 

must be qualified so that they only apply to generation operations that utilize the grid and 

exclude generation output dedicated to on-site consumption. 

b. Commission Determination

115. The Commission’s determination above to rely on the ERO’s compliance registry 

process to identify users, owners and operators of the Bulk-Power System that must 

comply with new mandatory and enforceable Reliability Standards should resolve the 

concerns expressed by APPA, SMA and others regarding the need to identify and provide 

timely notice to those users of the Bulk-Power System that are expected to comply with 

specific Reliability Standards. 

116. While we recognize the desire of some commenters for a concise, generic 

definition of “user of the Bulk-Power System,” we are concerned that any attempt to 

define the term at this time will either be overly broad so as not to provide any helpful 

guidance or overly narrow so as to exclude entities that should be covered. The 

Commission believes that it has employed a reasonable approach by endorsing NERC’s 

compliance registry process and requiring that each Reliability Standard identify the 

subset of users, owners and operators to whom that particular Reliability Standard 

applies. 

4. Use of the NERC Functional Model

117. NERC has developed a “Functional Model” that defines the set of functions that 

must be performed to ensure the reliability of the Bulk-Power System. The Functional 

Model identifies 14 functions and the name of a corresponding entity responsible for 

fulfilling each function. 
Docket No. RM06-16-000 - 40 - 

118. In the NOPR, the Commission proposed to use the NERC Functional Model to 

identify the applicable entities to which each Reliability Standard applies.70 The 

Commission explained that focusing on the functions an entity performs to identify what 

entities are users, owners and operators of the Bulk-Power System, and thus what entities 

are subject to the Reliability Standards, provides a useful level of detail and appears to be 

more practical than simply identifying an applicable entity as a user, owner or operator. 

In addition, the NOPR recognized concerns that the Functional Model may contain 

ambiguities and proposed to require NERC to specifically address these concerns. 

119. The Commission proposed that, because the Functional Model is linked to 

applicability of the Reliability Standards, the ERO should submit for Commission 

approval any future modifications to the Functional Model that may affect the 

applicability of the Reliability Standards. 

a. Filing the Functional Model with the Commission

i. Comments

120. NERC states that, while it believes that the Functional Model should be filed for 

informational purposes only, it will submit any changes to the Functional Model to the 

Commission for approval as requested. While NERC states that the Functional Model 

will not function as a legally binding document like a Reliability Standard, the 

Commission’s approval of this reference document and of any changes to the Functional 

Model will support the development of high quality, enforceable and technically 

sufficient standards. 

121. Several commenters, including NERC, EEI, APPA, MidAmerican, National Grid 

and MRO state that the Functional Model is not part of the Reliability Standards and 

should be filed with the Commission for informational purposes only. They generally 

state that the Functional Model is not a definitive guide to the “users, owners and 

operators” of the Bulk-Power System and should not be used to establish obligations 

under section 215, which should be established within each individual Commissionapproved Reliability Standard. 

122. Northeast Utilities is concerned with the Commission’s proposal to use the NERC 

Functional Model to identify applicable entities. It believes that the Functional Model 

can be useful in drafting standards, but it is not a substitute for having clear definitions of 

the entities responsible for compliance with the requirements for each Reliability 

 70 NOPR at P 46-48. 
Docket No. RM06-16-000 - 41 - 

Standard within a region. The entities responsible for meeting the standard may vary 

depending on how the Bulk-Power System is operated. FirstEnergy states that the 

Functional Model may not clearly or correctly identify the entities to which a Reliability 

Standard applies and maintains that the Functional Model should be applied only where 

all of the affected stakeholders agree on the final classifications of each Registered 

Entity’s roles and responsibilities. 

123. In contrast, TANC and ISO-NE state that the Commission should require that any 

future modification to the Functional Model that could affect the categories of entities 

that must comply with a particular Reliability Standard be approved by the Commission 

because the Functional Model is so closely interrelated with the applicability of each 

Reliability Standard. 

124. APPA, TAPS and ReliabilityFirst maintain that any modification to the NERC 

Functional Model should be reviewed and approved through the Reliability Standards 

development process. According to ReliabilityFirst, any change to the Functional Model 

is essentially an amendment to the Reliability Standard made outside the ERO process. 

TANC asserts that a Reliability Standard will only be complete if the definitions of the 

Functional Model are developed through the Reliability Standards development process 

just like any Reliability Standard. APPA would allow NERC to issue interpretations of 

the Functional Model, but these interpretations should then be confirmed through NERC 

procedures. 

125. TAPS cautions that, because the Functional Model includes no express size 

limitations, NERC and the Commission can rely on the Functional Model to define 

applicability of standards only if such limits are imposed by NERC’s compliance registry 

criteria and its bulk electric system definition. The Small Entities Forum is concerned 

because smaller entities have historically performed only a subset of functions. For 

example, it states that some joint action agencies invest in transmission facilities that are 

operated by others, but that these joint action agencies, under the Functional Model, 

would have to verify that these facilities, operated by others, are being operated and 

maintained according to applicable Reliability Standards. 

126. Several commenters argue that the Functional Model contains a number of 

ambiguities. MISO argues that the definition of the term planning coordinator is circular 

and may lead to one subset of the transmission system having multiple Planning 

Coordinators. MISO recommends that the Commission direct NERC to survey the 

industry to identify the planning roles that actually exist in the industry and clarify the 

role of the wide-area Planning Coordinator. MISO and Wisconsin Electric note that the 

proposed Reliability Standards do not specify who fulfills the Interchange Authority or 

Planning Authority roles, and there is no common industry understanding of those roles. 

Finally, California Cogeneration states that the definition of LSE is too inclusive and 
Docket No. RM06-16-000 - 42 - 

should be modified to exclude entities providing service only to loads on-site or pursuant 

to private contract. 

ii. Commission Determination

127. The Commission accepts the characterization offered by numerous commenters 

that the Functional Model is an evolving guidance document that is not intended to 

convey firm rights and responsibilities. Further, we agree that the applicability section of 

a particular Reliability Standard should be the ultimate determinant of applicability of 

each Reliability Standard. In light of this, we will not require the ERO to submit 

revisions of the Functional Model for Commission approval. While some commenters 

suggest that revisions be filed for informational purposes, we see little value in mandating 

such a filing.71 

128. With regard to the comments of TAPS, APPA, TANC and others on whether 

revisions to the Functional Model should be made through the ERO’s Reliability 

Standards development process, we do not believe that it is necessary under the statute, 

since applicability will be determined at this time by the specifications of the Reliability 

Standards and the compliance registry process. Thus, we leave to the discretion of the 

ERO the appropriate means of allowing stakeholder input when revising the Functional 

Model. To the extent that changes in the Functional Model require revised specification 

in the Reliability Standards, the latter will be addressed in the Reliability Standards 

development process. 

129. While TAPS and Small Entities Forum raise concerns regarding the absence of 

size limitations in the Functional Model and potential negative impacts on small entities, 

we believe that these concerns are addressed above in our decision regarding use of the 

NERC compliance registry process. MISO, Wisconsin Electric and others comment on 

the need to clarify certain ambiguities in the Functional Model. Given that the Functional 

Model is an evolving guidance document, the ERO can address such concerns as it 

updates and revises the Functional Model. 

b. Responsibility for Functions within the Functional Model

130. In the NOPR, the Commission explained that, in the context of an ISO or RTO or 

any organization that pools resources, decision-making and implementation are 

 71 We note that NERC has available on its website, www.nerc.com, the current 

version of the Functional Model. We expect NERC to continue to do so in the future. 
Docket No. RM06-16-000 - 43 - 

performed by separate groups.72 The ISO or RTO typically makes decisions for the 

transmission operator and, to a lesser extent, the generation operator, while actual 

implementation is performed by either local transmission control centers or independent 

generation control centers. The NOPR proposed 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.”73 

i. Comments

131. A number of commenters raise concerns or seek clarification regarding the 

relationship between the Functional Model and existing agreements that set forth the 

responsibility of various entities, particularly in the context of ISO and RTO operations. 

MISO requests the Commission to clarify that nothing in the Functional Model requires 

one entity to be responsible for all of the tasks within a function, regardless of who 

actually performs the task. In those ISOs and RTOs where balancing authorities have 

retained and have never delegated to the RTO certain tasks that fall within the balancing 

authority function, NERC’s Functional Model should only require one responsible entity 

per task rather than one responsible entity for all of the tasks within that function. MISO 

submits that the NERC Functional Model should not play a prescriptive role by assigning 

responsibility for a given task where such an assignment would be inconsistent with a 

Commission-approved regional transmission agreement, RTO tariff, or reliability plan 

filed with NERC, all of which specify the entity performing each task. 

132. PJM states that, while the Commission proposed to assign responsibility for 

reliable operations to multiple entities within an ISO or RTO to address its concern that 

decision making and implementation are performed by separate organizations, it does not 

believe that increasing the number of organizations responsible for a given function for 

the same facilities within the bulk electric system has been shown to be an effective or 

appropriate solution to the concerns cited. PJM states that NERC employs processes that 

successfully manage the delegation of operational tasks while maintaining single entity 

accountability for the reliable performance of those operational tasks. 

 72 NOPR at P 236. 

73 Id. at P 237. Although discussed in the context of the communication (COM) 

Reliability Standards, the NOPR suggested that the proposal would apply to other 

Reliability Standards. Because of the nature of the comments on the issue and its 

relationship to the Functional Model, we discuss the matter here. 
Docket No. RM06-16-000 - 44 - 

133. ATC states that Regional Entities should be given the flexibility to allow some 

“tasks” within a “function” to be performed by one entity, with the remaining tasks to be 

performed by another entity. According to ATC, this would provide entities – 

particularly smaller ones – with the flexibility to transfer their responsibility for a 

reliability task or function to another registered entity that can perform the work more 

effectively. Further, ATC maintains, Regional Entities should ensure that entities be 

given accountability only for systems, facilities and functions over which they actually 

have control. 

134. NPCC states that requirements applicable to local control centers should be 

distinct from requirements applicable to transmission and generation operators under the 

NERC Functional Model. NPCC submits that there is a difference between being 

assigned to do a task and being responsible for the completion of that task. An 

organization that registers with NERC as performing a function is considered a 

responsible entity and must ensure that all tasks are performed. While an organization 

may delegate a task to another organization, it may not delegate its responsibility for 

ensuring that the task is accomplished. 

135. According to Ontario IESO, the Commission’s proposal is inconsistent with the 

NERC Functional Model, which envisions one responsible entity for each reliability 

function. In contrast, the Commission’s proposal would split the same function between 

different organizations such as an ISO and a local control center. PJM claims that, under 

the Functional Model, single entity registration is a foundational cornerstone for ensuring 

clear responsibility and accountability for compliance with Reliability Standards. 

136. Ontario IESO asserts that the Commission’s proposal is also problematic because 

in the event of a violation it will be difficult to determine who violated the Reliability 

Standard - the entity making the decision or the entity implementing the decision. 

Ontario IESO argues that, although the NERC Functional Model is not foolproof, it 

avoids complications by distinguishing between responsibility and performance. The 

ISO is the responsible entity and it delegates some of its tasks to local control centers, but 

retains the overall responsibility. 

137. According to Ontario IESO, NERC has recognized that, although organizations 

such as local control centers play an important role in reliability, they are not responsible 

entities. Therefore, NERC has made such organizations subject to compliance audits and 

placed other requirements on them. In addition, NERC intends that the regional 

reliability plans will document the relationships between the local control centers and the 

entity that delegates its responsibility to such centers. The current framework has a 

mechanism for accommodating reliability considerations for organizations such as local 

control centers. In this regard, NERC’s ongoing formal certification of reliability 

coordinator, balancing authority and transmission provider will be useful in determining 
Docket No. RM06-16-000 - 45 - 

any delegation of tasks to local control centers that must take place for a clear 

demarcation of responsibilities. Ontario IESO advises that, since NERC has not finished 

this task, the Commission should defer its decision in this regard. 

138. ISO/RTO Council states that the Commission should not use the term “local 

control center” because it will cause confusion. The NERC Functional Model does not 

define the term and it means different things in different regions. For example, in MISO, 

which consists of 25 balancing areas, “local control center” is an equivalent term for 

balancing area although this was probably not the Commission’s intent in the NOPR. 

Therefore, ISO/RTO Council argues that the Reliability Standards should be limited to 

defining the tasks in the context of users, owners and operators of the Bulk-Power 

System; any delegation of responsibilities to a local control center or any other 

organization should take place in the context of ISO/RTO governing documents, 

operating agreements, tariffs and other arrangements with transmission owners and 

related stakeholders. This approach, according to ISO/RTO Council will address the 

Commission’s concerns with respect to local control centers without preempting possible 

regional solutions. 

139. FirstEnergy believes that, while independent authority to operate the transmission 

system should be self-evident, in RTO environments with local control centers, the tasks 

performed by each entity do not encompass the entirety of tasks performed by the 

transmission operator under the Functional Model. It suggests that NERC should revise 

the Functional Model to create certification and registration requirements for local 

control authorities within RTOs that perform real-time operations of the transmission 

system. FirstEnergy states that a revised NERC Functional Model should recognize local 

control centers that take some direction from RTOs yet maintain authority to act 

independently to carry-out functional tasks that require real-time operation of the system. 

According to FirstEnergy, the required registration and certification of such entities 

would clearly indicate the need for operational personnel in these control rooms to be 

NERC-certified. It concludes that at a minimum, a NERC certification for the tasks 

performed by such local control center individuals would be an enhancement over the 

current situation. 

140. ISO-NE argues that the Commission should not mandate that the tasks performed 

by local control centers be included in the definition of transmission operator because to 

do so would be to suggest that a local control center has independent autonomy in 

operating the Bulk Power System which would conflict with the “one set of hands on the 

wheel” philosophy. It explains that local control center personnel in New England 

implement tasks delegated to them by ISO-NE for operation of designated transmission 

facilities. Therefore, ISO-NE submits, the scope of the Reliability Standard need not be 

expanded. 
Docket No. RM06-16-000 - 46 - 

ii. Commission Determination

141. In response to the many concerns of commenters, the Commission clarifies that it 

did not intend to change existing contracts, impose new organizational structures or 

otherwise affect existing agreements that set forth the responsibilities of various entities. 

Rather, its intent was to allow enough granularity in the definitions so that the appropriate 

user, owner or operator of the Bulk-Power System would be identified for each 

Reliability Standard. We agree also with MISO’s statement that nothing in the 

Functional Model requires one entity to be responsible for all of the tasks within a 

function, regardless of who actually performs the task. 

142. The Commission’s concern is that, particularly in the ISO, RTO and pooled 

resource context, there should be neither unintended redundancy nor gaps for 

responsibilities within a function. In particular, the Commission is concerned that such 

“gaps” could occur in the context of several Reliability Standards addressing matters 

related to activities other than directing or implementing real-time operations.74 For 

example, the involvement of a transmission operator at an ISO or RTO with respect to the 

requirements related to telecommunications facilities (COM-001-1) from the local 

control room and blackstart restoration plans (EOP-005-0) may be minimal. Because the 

operators at local control centers actually perform all or most of the tasks contemplated 

under various Reliability Standards, we are concerned that there may be unintended gaps 

in such responsibilities if the existing contracts between the ISO or RTO and owners of 

the facilities do not address such responsibilities. 

143. In response to MISO, we did not intend to be prescriptive in assigning tasks to 

specific entities. The intent was to allow flexibility in identifying the actual user, owner 

or operator of the Bulk-Power System that would be responsible for complying with the 

Requirements in the Reliability Standards. One approach could be that the RTO, ISO or 

other pooled resource registers as the transmission operator pursuant to the NERC 

compliance registry process and, while retaining ultimate responsibility, assigns specific 

 74 See, e.g., CIP-001 – Sabotage Reporting; COM-001 – Telecommunications; 

EOP-003 –Load Shedding Plans; EOP-004 - Disturbance Reporting; EOP-005 – System 

Restoration Plans; EOP-008 – Plans for Loss of Control Center Functionality; PRC-001 – 

System Protection Coordination; PRC-007 – Assessing Consistency with Entity 

Underfrequency Load Shedding Programs with Regional Reliability Organizations UFLS 

Program Requirements; PRC-009 – Analysis and Documentation of Underfrequency 

Load Shedding Performance Following an Underfrequency Event; PRC-010 – Technical 

Assessment of the Design and Effectiveness of Undervoltage Load Shedding Program; 

PRC-022 – UFLS Program Performance; and TOP-006 – Monitoring System Conditions. 
Docket No. RM06-16-000 - 47 - 

tasks to be performed by what are sometimes known as local control centers or other 

relevant organizations. Alternatively, the local control center operators could register 

together with the RTO, ISO or pooled resources as transmission operators clearly 

delineating their specific responsibilities with regard to the Requirements of particular 

Reliability Standards. Such joint registration must assure that there is no overlap between 

the decisionmaking and implementation functions, i.e., that there are not two sets of 

hands on the wheel. Again, our intent is to ensure that there is neither redundancy nor 

gap in responsibility for compliance with the Requirements of a Reliability Standard, 

while allowing entities flexibility to determine how best to accomplish this goal. 

144. Consistent with our above explanation, we agree with NPCC that there is a 

difference between being assigned to perform a task and being responsible for completing 

the task. The organization that registers with NERC to perform a function will be the 

responsible entity and, while it may delegate the performance of that task to another, it 

may not delegate its responsibility for ensuring the task is completed. 

145. Accordingly, the Commission directs that the ERO, in registering RTOs, ISOs and 

pooled resource organizations (or, indeed in registering any entity), assure that there is 

clarity in the assigning responsibility and that there are no gaps or unnecessary 

redundancies with regard to the entity or entities responsible for compliance with the 

Requirements of each relevant Reliability Standard. Accordingly, although the 

Commission is not requiring NERC to amend the Functional Model, we believe our 

concerns can be addressed by having the ERO, through its compliance registry process, 

ensure that each user, owner and operator of the Bulk-Power System is registered for 

each Requirement in the Reliability Standards that relate to transmission owners to assure 

there are no gaps in coverage of the type discussed here. 

5. Regional Reliability Organizations

146. The NOPR stated that 28 proposed Reliability Standards would apply, in whole or 

in part, to a regional reliability organization.75 Further, many of the proposed Reliability 

Standards that have compliance measures refer to the regional reliability organization as a 

compliance monitor. The Commission stated in the NOPR that it was not persuaded that 

a regional reliability organization’s compliance with a Reliability Standard can be 

enforced as proposed by NERC because it does not appear that a regional reliability 

organization is a user, owner or operator of the Bulk-Power System. 

 75 NOPR at P 54. 
Docket No. RM06-16-000 - 48 - 

147. The Commission proposed to approve and direct modification of five Reliability 

Standards that apply partially to regional reliability organizations. For the other 

Reliability Standards that apply to regional reliability organizations, the Commission 

proposed, as an interim measure, 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 information related to data gathering, data maintenance, 

reliability assessments and other process-type functions. The NOPR explained that this 

approach is necessary to ensure that there will be no gap during the transition from the 

current voluntary system to a mandatory system in which Reliability Standards are 

enforced by the ERO and Regional Entities. The NOPR proposed that, in the long run, 

Regional Entities should be made responsible, through delegation from the ERO, for the 

functions currently performed by the regional reliability organizations. To implement 

this, the Commission proposed the modification of delegation agreements to require the 

Regional Entities to assume responsibility for noncompliance. In addition, the 

Commission proposed that the Reliability Standards should be modified to apply to the 

users, owners and operators of the Bulk-Power System that are responsible for providing 

information. The Commission proposed 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. 

148. The Commission stated that, 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, the Commission does 

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. The Commission sought 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. 

a. Comments

149. NERC believes it can remove references to regional reliability organizations and 

Regional Entities from the Reliability Standards, with the exception of retaining the 

Regional Entities as the compliance enforcement authorities. However, NERC and 

California PUC request that the Commission reconsider its proposal to direct that the 

ERO be listed as the compliance monitor in each Reliability Standard. California PUC 

states that naming NERC as the compliance monitor deprives the Regional Entities of 

their enforcement role under section 215. NERC believes it will be clearer, and 

consistent with the delegation agreements, to designate the Regional Entity as the 

compliance monitor in almost all Reliability Standards. According to NERC, this would 

also be helpful to distinguish those few Reliability Standards that are monitored directly 

by NERC. 
Docket No. RM06-16-000 - 49 - 

150. ReliabilityFirst, TANC and SoCal Edison agree with the Commission that regional 

reliability organizations and Regional Entities cannot be users, owners or operators of the 

Bulk-Power System and should not be subject to compliance with Reliability Standards. 

TANC states that Reliability Standards that reference a regional reliability organization 

need to be revised to reference a user, owner or operator of the Bulk-Power System in 

order to comply with the statute. 

151. EEI agrees with the Commission’s proposal to direct the ERO to require users, 

owners and operators to provide the information related to data gathering, data 

maintenance, reliability assessments and other process-type functions that previously 

have applied to regional reliability organizations. EEI also agrees that, in the long run, it 

is appropriate to make the Regional Entities responsible through delegation from the 

ERO for various functions now performed by regional reliability organizations. In doing 

so, and during the transition in particular, EEI maintains that it is important that functions 

now performed by the regional councils, such as planning, be continued. 

152. A number of commenters discuss the possible ongoing role for a regional 

reliability organization. For example, Ontario IESO, NPCC and National Grid state that 

the Commission should recognize that the regional reliability organizations will continue 

to play a role in areas including developing regional reliability plans and adequacy 

requirements that are outside the jurisdiction of the ERO. NPCC states that enforcement 

of adequacy requirements should continue to reside with the regional reliability 

organization. National Grid states that the role of regional reliability organizations can be 

preserved in a variety of ways, including requiring obligations currently imposed upon 

regional reliability organizations to be included in the regional delegation agreements. 

153. NPCC further maintains that regional reliability organizations should continue to 

function as regional sites for technical expertise for enhanced reliability requirements 

through adopting regionally-specific criteria. According to NPCC, eliminating the ability 

for regions to develop and propose new criteria that enhance system reliability would 

edge the system closer towards the lowest common denominator rather than striving 

towards operational excellence. Further, Ontario IESO and NPCC state that regional 

reliability organizations should be allowed to perform certain functions for their 

members, such as system operator workshops, forums for coordination of operations and 

planning and operational readiness conference calls. 

154. Massachusetts DTE comments that a regional reliability organization should be 

allowed to propose a Reliability Standard that may exceed or enhance the proposed 

mandatory Reliability Standards to ensure regional reliability. It further states that any 

regional reliability criteria proposed by a regional reliability organization should be 

vetted through a regional stakeholder process and then specifically adopted by the 

appropriate state regulatory authorities. 
Docket No. RM06-16-000 - 50 - 

155. Although MRO does not oppose regional reliability organizations, with regard to 

establishing and enforcing mandatory Reliability Standards, MRO, Constellation and 

Xcel state that there is no need to maintain a separate role for regional reliability 

organizations. Because Regional Entities may perform non-reliability functions, 

Constellation states that maintaining regional reliability organizations will result in 

unnecessary cost. While Constellation has no objection to the Regional Entities 

performing non-statutory functions, it states that the Commission should not allow 

Regional Entities to impose Reliability Standards developed by the regional reliability 

organizations as mandatory Reliability Standards. 

156. MidAmerican believes that it will be important to separate the compliance 

functions of the Regional Entities from non-compliance functions currently assigned to 

the regional reliability organizations. It states that this can be done by: (1) separating 

these functions internally in the Regional Entities; (2) separating these functions in 

different organizations; or (3) separating these functions by assigning non-compliance 

related functions currently assigned to the regional reliability organizations to other users, 

owners and operators. This will minimize conflicts between the Regional Entity core 

compliance function and the non-compliance regional reliability organization 

requirements. 

b. Commission Determination

157. The Commission adopts the NOPR proposal to eliminate references to the regional 

reliability organization as a responsible entity in the Reliability Standards. We conclude 

that this approach is appropriate because, as explained in the NOPR, such entities are not 

users, owners or operators of the Bulk-Power System. NERC indicates that it can remove 

such references, except that the Regional Entity should be identified as the compliance 

monitor where appropriate. While the Commission originally proposed that the ERO 

should be designated as the compliance monitor, we agree with NERC’s approach and 

believe that identifying the Regional Entity as the compliance monitor will provide useful 

specificity as to which entity will be immediately tasked with monitoring compliance 

with a particular Reliability Standard. However, as we stated in Order No. 672, the ERO 

retains responsibility to ensure that a Regional Entity implements its enforcement 

program in a consistent manner, and to periodically review the Regional Entity’s 

enforcement activities.76

 76 Order No. 672 at P 654. 
Docket No. RM06-16-000 - 51 - 

158. For those Reliability Standards that identify the regional reliability organization as 

the sole applicable entity, and that relate to data gathering, data maintenance, reliability 

assessments and other process-type functions,77 the NOPR proposed: 

as an interim measure . . . to direct the ERO to use its authority pursuant to 

§ 39.2(d) of our regulations to require users, owners and operators to 

provide to the regional reliability organizations the information related to 

data gathering, data maintenance, reliability assessments and other 

“process”-type functions. 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.[78] 

159. We continue to believe that this is a reasonable interim measure, and note that EEI 

and others support this approach. To ensure that the ERO properly and timely addresses 

this matter, we direct the ERO to submit an informational filing within 90 days of the 

Final Rule that describes its plan and schedule for developing both an interim and longterm resolution based upon the above direction. 

160. In response to the Commission’s inquiry in the NOPR, commenters identify a 

number of possible continuing roles for regional reliability organizations. Such activities 

are beyond the scope of this proceeding. Clearly, any such role must be limited to nonstatutory functions. Some commenters suggest that regional reliability organizations may 

have a role in developing voluntary criteria. Regional reliability organizations should not 

develop voluntary criteria that address the same or similar matters as mandatory and 

 77 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. 

78 NOPR at P 57 (footnotes omitted). 
Docket No. RM06-16-000 - 52 - 

enforceable Reliability Standards, because that is the responsibility of the Regional 

Entities.79

D. Mandatory Reliability Standards

1. Legal Standard for Approval of Reliability Standards

161. The NOPR explained that section 215(d)(2) of the FPA states that the Commission 

may approve a Reliability Standard if it determines that it is just, reasonable, not unduly 

discriminatory or preferential and in the public interest. Further, Order No. 672 laid out a 

series of factors it would consider when assessing whether to approve or remand a 

Reliability Standard.80 

162. In response to NERC’s suggestion that a proposed Reliability Standard developed 

through its open and inclusive process is assured to be “just, reasonable, and not unduly 

discriminatory or preferential,” the NOPR explained that: 

While an open and transparent process certainly is extremely important to 

the overall success of implementing section 215 of the FPA, an evaluation 

of any proposed Reliability Standard must focus primarily on matters of 

substance rather than procedure. We will, therefore, review each 

Reliability Standard in addition to the process through which it was 

approved by NERC to ensure that the Reliability Standard is just, 

reasonable, not unduly discriminatory or preferential, and in the public 

interest.[81] 

163. Further, with regard to NERC’s “benchmarks” for evaluating a proposed 

Reliability Standard,82 the Commission explained that it would not be constrained by 

such benchmarks in approving or remanding a proposed Reliability Standard. Rather, 

 79 See ERO Certification Order at P 281. 

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

81 NOPR at P 74. 

82 Id. at P 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. 
Docket No. RM06-16-000 - 53 - 

Order No. 672 identified factors that the Commission will consider when determining 

whether a proposed Reliability Standard satisfies the statutory requirements. 

a. Comments

164. NERC states that 83 of the Reliability Standards are “just, reasonable, not unduly 

discriminatory or preferential, and in the public interest,” and should therefore be 

approved and made effective as mandatory Reliability Standards. NERC believes that, 

by following NERC’s Reliability Standards development process, a Reliability Standard 

should meet the requirement that a standard be “just, reasonable, not unduly 

discriminatory or preferential.” Further, NERC asserts that, by filing with the 

Commission the written record of development for each Reliability Standard, NERC has 

given the Commission strong evidence that those 83 Reliability Standards are just, 

reasonable, and not unduly discriminatory or preferential. 

165. NERC states that the requirement that a Reliability Standard be “in the public 

interest” provides the Commission with broad discretion to review and approve a 

Reliability Standard. According to NERC, implicit in the “public interest” test is that a 

Reliability Standard is technically sound and ensures an adequate level of reliability, and 

that the Reliability Standards provides a comprehensive and complete set of technically 

sound requirements that establish an acceptable threshold of performance necessary to 

ensure reliability of the Bulk-Power System. NERC states that it believes that approving 

those 83 Reliability Standards as enforceable as NERC begins operating as the ERO 

meets this objective and will achieve an adequate level of reliability as required by law. 

NERC asserts that adopting fewer of the Reliability Standards would both create potential 

reliability risks and communicate that some aspects of reliability are not viewed as 

important enough to be the subject of mandatory and enforceable Reliability Standards 

under the FPA. 

166. FirstEnergy states that each proposed standard should be reviewed against the 

following criteria: (1) clarity; (2) technical means to comply; (3) practicability; (4) 

consistency and (5) costs. 

b. Commission Determination

167. The Commission agrees with NERC that an open and transparent process is 

important in implementing section 215 of the FPA and developing proposed mandatory 

Reliability Standards. However, in Order No. 672, the Commission rejected the 

presumption that a proposed Reliability Standard developed through an ANSI-certified 
Docket No. RM06-16-000 - 54 - 

process automatically satisfies the statutory standard of review.83 The Commission 

reiterates that simply because a proposed Reliability Standard has been developed 

through an adequate process does not mean that it is adequate as a substantive matter in 

protecting reliability. We will, therefore, review each Reliability Standard to ensure that 

the Reliability Standard is just, reasonable, not unduly discriminatory or preferential, and 

in the public interest, giving due weight to the ERO. 

168. In response to FirstEnergy, the Commission has already laid out the factors against 

which to review a Reliability Standard, as well as other considerations.84 The 

Commission has no need to revisit this issue. 

2. Commission Options When Acting on a Reliability Standard

169. In the NOPR, the Commission proposed that, for this rulemaking, it would take 

one of four actions with regard to each proposed Reliability Standard: (1) approve; (2) 

approve as mandatory and enforceable; and direct modification pursuant to section 

215(d)(5); (3) request additional information; or (4) remand. In fact, the NOPR did not 

propose to remand any proposed Reliability Standard.85 

170. With regard to the second category, the Commission explained that it 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. 

 83 Order No. 672 at P 338. 

84 Id. at P 262, 321-37. (A proposed Reliability Standard must: (1) provide for the 

Reliable Operation of Bulk-Power System facilities; (2) be designed to achieve a 

specified reliability goal and must contain a technically sound means to achieve this goal; 

(3) be clear and unambiguous regarding what is required and who is required to comply; 

(4) clearly state the possible consequences for violating the proposed Reliability 

Standard; (5) include a clear criterion or measure of whether an entity is in compliance 

with a proposed Reliability Standard; (6) achieve its reliability goal effectively and 

efficiently; (7) not reflect the “lowest common denominator.”) 

85 NOPR at P 78-82. 
Docket No. RM06-16-000 - 55 - 

171. With regard to the third category, “request additional information,” the NOPR 

explained that some Reliability Standards do not contain sufficient information to enable 

the Commission to propose a disposition. For those Reliability Standards, the 

Commission identified the needed information, and proposed not to approve or remand 

these Reliability Standards until all the relevant information is received. As an example, 

the NOPR explained that many of the fill-in-the-blank standards would not be approved 

or remanded until the Commission had received all the necessary information. 

a. Comments

172. Most commenters generally support the Commission’s proposal to have four 

courses of action it may take on a Reliability Standard. However, Xcel has concerns 

about the legality of approving many of the proposed Reliability Standards as mandatory 

but, at the same time, ordering the ERO to make specific modifications to them. 

According to Xcel, section 215(d) does not expressly create this “approve but modify” 

option. To the contrary, section 215(d)(4) suggests that the Commission should remand 

to the ERO a standard that it disapproves “in whole or in part.” 

173. While many commenters support the Commission proposal to approve certain 

Reliability Standards as mandatory and enforceable; and direct NERC to modify them 

pursuant to section 215(d)(5), they are concerned that the Commission’s directives to 

modify certain Reliability Standards are too prescriptive.86 They contend that, in 

prescribing particular requirements, metrics, or specific language to be used, the 

Commission is setting the Reliability Standard outside the open Reliability Standards 

development process and not giving due weight to the ERO under section 215 of the 

FPA. NRECA, for example, argues there is a major distinction between (a) requiring a 

Reliability Standard to address a specific matter and (b) requiring (as opposed to 

suggesting) a specific Reliability Standard or requiring a reliability matter to be addressed 

in a specific way. These commenters ask that the Final Rule state that a directive to 

improve a Reliability Standards be in the form of an objective to be achieved or concern 

or deficiency to be resolved within the Reliability Standard, rather than a particular 

requirement, metric, or specific language to be used. 

174. Many commenters request that the Commission require that changes to any 

Reliability Standard be made through NERC’s Reliability Standard development 

 86 See, e.g., NERC, Entergy, EEI, APPA, National Grid, NRECA, TAPS, ISO-NE 

and Duke. 
Docket No. RM06-16-000 - 56 - 

procedure.87 NERC states that there are areas where the Commission proposes a specific 

directive on a particular Reliability Standard that is well beyond the bounds of current 

utility practice. According to NERC, these recommendations are often derived from the 

Staff Preliminary Assessment or are based on a limited number of comments to that 

assessment. NERC anticipates that the issue of concern with respect to these Reliability 

Standards will be addressed, but the results may be somewhat different than anticipated 

by the Commission. Similarly, EEI and Progress state that NERC should not predetermine the outcome of the Reliability Standard development procedure in response to 

the Commission’s guidance. Ontario IESO states that the Commission should allow its 

detailed input on the proposed Reliability Standards to be considered through Reliability 

Standards development process. 

175. According to EEI, NERC should be permitted to provide, if the Commission’s 

guidance for modification of a proposed Reliability Standard is not adopted in the 

Reliability Standard development procedure, an explanation for that outcome when it 

submits the modified standard to the Commission for approval. Constellation asks the 

Commission to clarify that, if the ERO Reliability Standards development process does 

not result in a Reliability Standard that includes the Commission’s proposed 

modifications, the existing Reliability Standard would remain in effect until such time as 

NERC proposes and the Commission approves a different Reliability Standard (approved 

through the Reliability Standards development process). 

176. Manitoba and Northwest Requirements Utilities disagree with the Commission’s 

proposal to approve certain Reliability Standards and, separately, direct NERC to make 

modifications. Some commenters, such as California PUC, Northwest Requirements 

Utilities and SMA state that the users, owners and operators of the Bulk-Power System 

should not be expected to comply with Reliability Standards that are not finalized or need 

modification. Northwest Requirements Utilities contends that complete and clear 

Reliability Standards and requirements are necessary to fair enforcement, particularly if 

monetary sanctions may apply. Manitoba and California PUC state that approving 

Reliability Standards that still require modification would lead to differing interpretations 

of the Reliability Standards and confusion. 

177. CEA asserts that the proposed directives to modify certain Reliability Standards, 

while not remands, reflect engagement in the standards-setting process that may interfere 

with the ERO’s ability to effectively function as an international body. For example, 

Manitoba states that the Commission’s proposed modifications without industry input 

 87 See, e.g., NERC, EEI, ELCON, CEA, NYSRC, TVA, LPPC, NPCC, Ontario 

IESO, Constellation, Progress and Dynegy. 
Docket No. RM06-16-000 - 57 - 

may unintentionally place Manitoba in a position where it must recommend that the 

Government of Manitoba disallow the Commission’s prescribed modifications to several 

NERC Reliability Standards, thus creating discrepancies between Reliability Standards 

across North America. 

178. FirstEnergy agrees with the Commission’s rejection of the concept of “conditional 

approval” in favor of approve but modify to ensure that enforceable standards are in 

place. However, it asks that the Commission consider waiving, or at least substantially 

reducing, penalties for violations of some enforceable, but yet-to-be-completed or 

modified Reliability Standards because compliance with such Reliability Standards may 

prove difficult to determine. FirstEnergy therefore suggests that the Commission 

exercise due discretion in enforcing affected Reliability Standards, especially where the 

Commission itself has found that a standard is incomplete or ambiguous. International 

Transmission agrees that in instances where the Commission has proposed material 

changes to a Reliability Standard and its associated measurements, risk factors and 

Levels of Non-Compliance, it may be appropriate for the ERO to exercise enforcement 

discretion on a case-by-case basis. 

179. SoCal Edison is concerned that entities may not have an opportunity to (1) review 

the Reliability Standards that are adopted in the Final Rule and (2) make any necessary 

changes in their operating or planning practices in order to incorporate differences 

between the NOPR and the Final Rule. SoCal Edison recommends the Commission 

specifically state the “effective date” for compliance with each Reliability Standard in its 

Final Rule. SoCal Edison is concerned because some standards have a proposed NERC 

“effective” date after the Final Rule. 

180. Northern Indiana states it is concerned how a June 2007 effective date will impact 

electric system reliability during the critical summer peak demand period, particularly 

given the many problems with the standards that have been identified. Northern Indiana 

believes the Commission’s current actions may, in the near term, create a lower 

probability of success in achieving the Commission’s stated objectives. Northern Indiana 

suggests that the traditional summer peak season is not a good time to implement broad 

changes in electric system operations, procedures and protocols. 

181. NRECA states it is concerned by the NOPR’s efforts to establish specific one and 

three year time frames for resolution of various matters. It states that the Commission is 

authorized to comment on priorities and suggest timing, it must allow NERC to follow its 

ANSI-certified Reliability Standards development process. 

182. NERC requests that the Commission provide a directive in the Final Rule 

requiring NERC to address both the Commission’s concerns with the existing Reliability 

Standards and all comments filed in this rulemaking proceeding suggesting specific 
Docket No. RM06-16-000 - 58 - 

improvements to the Reliability Standards. NERC states that if the Commission acts on 

the views expressed on a specific Reliability Standards by an individual commenter in 

this rulemaking, it may encourage others to avoid participating in the NERC process and 

instead wait until a proposed new or modified Reliability Standard reaches the 

Commission approval stage to express their views on the standards. NERC states that no 

commenter should be entitled to have its comments on a specific Reliability Standard 

resolved by the Commission in this rulemaking proceeding. 

183. NERC maintains that referring all comments to the NERC Reliability Standards 

development process for resolution is consistent with NERC’s obligation to facilitate an 

open stakeholder process for the development of Reliability Standards. NERC asserts 

that it gives fair consideration to all comments and objections on a proposed new or 

revised Reliability Standard and such comments are either resolved to the satisfaction of 

the commenter, or reasons are stated as to why the commenter’s recommendation should 

not be adopted. 

b. Commission Determination

184. The Commission affirms the four possible courses of action that it will take with 

regard to each proposed Reliability Standard: (1) approve; (2) approve as mandatory and 

enforceable; and direct modification pursuant to section 215(d)(5); (3) request additional 

information; or (4) remand. Each course of action is justified and has a sound basis in the 

statute. Xcel questions the legality of the second option above, which it incorrectly 

equates to “conditional acceptance.” Rather, as explained in the NOPR,88 the 

Commission is taking two independent actions, both authorized by the statute. First, we 

are exercising our authority, contained in section 215(d)(2) of the FPA, to approve a 

proposed Reliability Standard. Second, we are directing the ERO 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.89 Accordingly, we reject 

Xcel’s contention and adopt the NOPR proposal on this matter. 

 88 See NOPR at P 79-80. 

89 16 USC 824o(d)(5) ( “[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 - 59 - 

185. With regard to the many commenters that raise concerns about the prescriptive 

nature of the Commission’s proposed modifications, the Commission agrees that a 

direction for modification should not be so overly prescriptive as to preclude the 

consideration of viable alternatives in the ERO’s Reliability Standards development 

process. However, in identifying a specific matter to be addressed in a modification to a 

Reliability Standard, it is important that the Commission provide sufficient guidance so 

that the ERO has an understanding of the Commission’s concerns and an appropriate, but 

not necessarily exclusive, outcome to address those concerns. Without such direction and 

guidance, a Commission proposal to modify a Reliability Standard might be so vague that 

the ERO would not know how to adequately respond. 

186. Thus, in some instances, while we provide specific details regarding the 

Commission’s expectations, we intend by doing so to provide useful guidance to assist in 

the Reliability Standards development process, not to impede it.90 We find that this is 

consistent with statutory language that authorizes the Commission to order the ERO to 

submit a modification “that addresses a specific matter” if the Commission considers it 

appropriate to carry out section 215 of the FPA.91 In the Final Rule, we have considered 

commenters’ concerns and, where a directive for modification appears to be 

determinative of the outcome, the Commission provides flexibility by directing the ERO 

to address the underlying issue through the Reliability Standards development process 

without mandating a specific change to the Reliability Standard. Further, the 

Commission clarifies that, where the Final Rule identifies a concern and offers a specific 

approach to address the concern, we will consider an equivalent alternative approach 

provided that the ERO demonstrates that the alternative will address the Commission’s 

underlying concern or goal as efficiently and effectively as the Commission’s proposal. 

187. Consistent with section 215 of the FPA and our regulations, any modification to a 

Reliability Standard, including a modification that addresses a Commission directive, 

must be developed and fully vetted through NERC’s Reliability Standard development 

process. The Commission’s directives are not intended to usurp or supplant the 

Reliability Standard development procedure. Further, this allows the ERO to take into 

consideration the international nature of Reliability Standards and incorporate any 

 90 Moreover, in the NOPR, the Commission first discussed in detail its substantive 

concerns regarding a particular proposed Reliability Standard and, to provide greater 

clarity regarding the Commission proposal, then summarized the proposed findings and 

modifications. It appears that such summaries of broader and fuller discussions led to 

misunderstandings of the NOPR proposals. 

91 16 USC 824o(d)(5). 
Docket No. RM06-16-000 - 60 - 

modifications requested by our counterparts in Canada and Mexico. Until the 

Commission approves NERC’s proposed modification to a Reliability Standard, the 

preexisting Reliability Standard will remain in effect. 

188. We agree with NERC’s suggestion that the Commission should direct NERC to 

address NOPR comments suggesting specific new improvements to the Reliability 

Standards, and we do so here. We believe that this approach will allow for a full vetting 

of new suggestions raised by commenters for the first time in the comments on the NOPR 

and will encourage interested entities to participate in the ERO Reliability Standards 

development process and not wait to express their views until a proposed new or 

modified Reliability Standard is filed with the Commission. As noted throughout the 

standard-by-standard analysis that follows, various commenters provide specific 

suggestions to improve or otherwise modify a Reliability Standard that address issues not 

raised in the NOPR. In such circumstances, the Commission directs the ERO to consider 

such comments as it modifies the Reliability Standards during the three-year review cycle 

contemplated by NERC’s Work Plan through the ERO Reliability Standards development 

process. The Commission, however, does not direct any outcome other than that the 

comments receive consideration. 

189. We disagree with commenters, such as Xcel, suggesting that the Commission 

should not approve Reliability Standards that we require NERC to modify. The 

Commission is only approving those Reliability Standards that it has determined to be 

just, reasonable, not unduly discriminatory or preferential, and in the public interest. As 

discussed more fully in the discussion of the individual Reliability Standards, we have 

determined that each approved Reliability Standard is sufficiently clear and 

independently enforceable. Because we believe that these Reliability Standards are 

enforceable as written, the Commission will not exempt them from enforcement. 

190. The Commission disagrees with Northern Indiana that the Reliability Standards 

should not be implemented in summer of 2007.92 Most or all users, owners and operators 

of the Bulk-Power System have participated in NERC’s voluntary reliability regime for 

years and are familiar with the proposed Reliability Standards. Others have had notice of 

the Reliability Standards since they were filed by NERC in April 2006. We are not 

persuaded that making Reliability Standards enforceable, most of which were being 

complied with on a voluntary basis, will require broad changes in electric system 

operations, procedures and protocols. Therefore, we do not see any reason to further 

delay implementation of the mandatory Reliability Standards. 

 92 See discussion below regarding the Trial Period, section II.D.4. 
Docket No. RM06-16-000 - 61 - 

191. In response to SoCal Edison, Reliability Standards will become effective the latter 

of the effective date of this Final Rule or the ERO’s proposed NERC effective date. The 

Commission disagrees with SoCal Edison that users, owners and operators of the BulkPower System will not have an opportunity to review the Reliability Standards that are 

adopted in the Final Rule and incorporate differences between the NOPR and the Final 

Rule into their operating practices. The Reliability Standards approved in this Final Rule 

are approved as proposed by the ERO. No changes will be made immediately based on 

the Commission’s direction to modify those Reliability Standards. Any modifications 

will be developed through the ERO’s Reliability Standards development process and 

should have a proposed effective date that will take into account any time needed for 

users, owners and operators of the Bulk-Power System to incorporate the necessary 

changes. Therefore, there is no need for any entity to make any changes based on 

differences between the NOPR and the Final Rule. 

192. NRECA’s assertion that the Commission should not establish timelines to resolve 

matters is a collateral attack on Order No. 672. In that order, the Commission adopted its 

regulations to provide that the Commission, when ordering the ERO to submit to the 

Commission a proposed Reliability Standard or proposed modification to a Reliability 

Standard that addresses a specific matter, may order a deadline by which the ERO must 

submit a proposed or modified Reliability Standard.93

3. Prioritizing Modifications to Reliability Standards

193. As discussed above, the Commission proposed to approve certain Reliability 

Standards and, as a separate action, proposed to direct the ERO to modify many of the 

same Reliability Standards pursuant to section 215(d)(5) of the FPA. In the NOPR, the 

Commission recognized that it is not reasonable to expect the modification of such a 

substantial number of Reliability Standards in a short period of time. Thus, the NOPR 

provided guidance on the prioritization of needed modifications.94

194. The NOPR proposed that NERC first focus its resources on modifying those 

Reliability Standards that have the largest impact on near-term Bulk-Power System 

reliability, including many of the proposed modifications that reflect Blackout Report 

recommendations. Further, the Commission identified a group of Reliability Standards 

that it believes should be given the highest priority by the ERO based on the above 

 93 See 18 CFR 39.5(g). 

94 NOPR at P 85-87. 
Docket No. RM06-16-000 - 62 - 

guidance.95 The NOPR explained that the list is not meant to be exclusive or inflexible 

and solicited ERO and commenter input. The NOPR proposed that NERC address the 

“high priority” modifications within one year of the effective date of the Final Rule. 

195. In addition, the NOPR proposed that the ERO promptly address certain proposed 

modifications that are not necessarily identified as “high priority” but may be addressed 

in a relatively short time frame because the proposed modifications are relatively minor 

or “administrative” in nature. The NOPR further proposed 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 would take a staggered approach and complete 

all the proposed modifications within either two or three years from the effective date of 

the Final Rule. 

196. As noted above, on December 1, 2006, NERC submitted its Work Plan as an 

informational filing. According to the Work Plan, NERC will revise the existing 

Reliability Standards to incorporate improvements. A total of 31 different projects will 

be completed over a three year period.96 Some of the projects address revising a single 

Reliability Standard. The largest project includes revising 19 Reliability Standards 

focusing on related topics. NERC asserts that grouping the Reliability Standards in this 

manner will be the most efficient use of the resources and will allow consistency in 

requirements on related standards. NERC states that the Work Plan incorporates 

modifications that were proposed in the NOPR, but it will modify its Work Plan to align 

it with the modifications the Commission orders in the Final Rule. In addition, the Work 

Plan will remain dynamic as new Reliability Standards are proposed and priorities 

evolve. The Work Plan will be updated on an annual basis, and more frequently if 

needed. 

197. According to the Work Plan, NERC will periodically report progress and revisions 

to the Work Plan and timetable to the Commission. NERC’s intent is to provide 

accountability for the revision and development of Reliability Standards, while 

recognizing it is impossible to have a fixed schedule when working in a consensus-driven 

process addressing complex technical matters. 

 95 Id. at Appendix D (High Priority List). 

96 Some projects relate to new Reliability Standards that are not before the 

Commission in the instant rulemaking. 
Docket No. RM06-16-000 - 63 - 

a. Comments

198. NERC states that it is pleased that the Commission did not propose specific 

deadlines in the NOPR for completing the directives to improve the Reliability Standards. 

NERC requests that the Commission not state specific delivery dates, because developing 

consensus Reliability Standards on complex technical matters within fixed time frames 

may not be realistic in all cases. NERC states that it will report the reasons for any 

delays in the schedule and will work to ensure that no unnecessary delays occur due to 

lack of attention or effort. 

199. NERC expresses concern that the Commission suggests in the NOPR that it may 

direct some early modifications to the Reliability Standards that appear to provide quick 

results.97 According to NERC, because of the procedural requirements of the Reliability 

Standards development process, this would delay work that is more important. NERC 

states that it can make such changes quickly for a particular Reliability Standard if there 

are no other changes to that standard. However, NERC’s Work Plan contemplates that 

almost every Reliability Standard is to be upgraded; modifying each standard in multiple 

steps would add significant delay. 

200. APPA similarly cautions the Commission that the industry does not have 

unlimited ability to simultaneously reevaluate the Reliability Standards, prepare for 

NERC’s and the Regional Entities’ compliance monitoring and enforcement programs, 

and actually plan and operate their utility systems on a reliable basis. According to 

APPA, NERC should promptly address the administrative elements of those Reliability 

Standards that are now at best incomplete, with missing Compliance Measures, Levels of 

Non-Compliance and Violation Risk Factors. NERC must also deal with the regional 

fill-in-the-blank standards and criteria that have not yet been submitted to either NERC or 

to the Commission for review and approval. 

201. International Transmission states that the Commission should not direct NERC to 

make changes to the Reliability Standards within a specific time frame because this 

would circumvent the Reliability Standard development process. It asks the Commission 

to instruct the ERO to initiate the Reliability Standards development process in a time 

frame that would likely result in their presentation to the Commission by a desired date, 

acknowledging that a revised Reliability Standard may not reach industry consensus and 

thus not meet the Commission’s desired time frame. Further, International Transmission 

believes that the priority of a Reliability Standard for subsequent modification should be 

based on the standard’s “Violation Risk Factor.” Reliability Standards that have the 

 97 NOPR at P 86. 
Docket No. RM06-16-000 - 64 - 

greatest impact on bulk electric system reliability should be addressed first. All high risk 

requirements should be addressed in the 2007 Work Plan. International Transmission 

states the addition of Measures and Levels of Non-Compliance is neither minor nor 

administrative in nature, although designated by the Commission as such and called for 

an accelerated time period for their addition. 

202. MRO recommends that the Commission place a greater emphasis on directing 

NERC to develop clear and measurable Requirements. If the Requirements are not clear 

and measurable, the Measures and Levels of Non-Compliance will be fundamentally 

flawed. MRO also states that there are numerous Requirements that are now part of the 

Reliability Standards that came from elements of the former NERC Operating Manual 

that were never intended as Requirements. It believes that this, in part, has created 

certain difficulties that have resulted in a lack of Measures or Levels of Non-Compliance 

in the Reliability Standards. MRO provides examples of such difficulties in its comments 

regarding specific Reliability Standards. MRO suggests grouping each Requirement with 

its associated Measure and Level of Non-Compliance thus making it clear to the user, 

owner or operator as to which Requirements, Measures and Levels of Non-Compliance 

are related thereby reducing confusion. 

203. APPA and Alcoa state that the Commission did not give sufficient time for 

comments on NERC’s submitted Work Plan. APPA notes that the Work Plan will have 

to be revised following issuance of the Final Rule. 

b. Commission Determination

204. Given the concerns raised by commenters, the Commission will not adopt the 

NOPR’s proposal to direct some early modifications to the Reliability Standards. We 

agree with NERC that modifying each Reliability Standard first to address administrative 

concerns, then sending it back to the Reliability Standards development process to 

address any modifications directed by the Commission or requested by stakeholders, 

might lead to an unacceptable delay. 

205. While the Commission agrees with International Transmission that a good starting 

point for prioritizing modifications to a Reliability Standard could be based on the 

Reliability Standard’s “Violation Risk Factor,” the Commission will not mandate that the 

ERO do so. The ERO should take into account the views of its stakeholders, including 

the concerns raised in this proceeding by APPA, International Transmission and MRO, in 

revising its Work Plan following issuance of this Final Rule. 
Docket No. RM06-16-000 - 65 - 

206. In Order No. 890, the Commission directed public utilities, working through 

NERC, to modify the ATC-related Reliability Standards within 270 days of publication 

of Order No. 890 in the Federal Register.

98 Our action there affects approximately nine 

MOD Reliability Standards and one FAC Reliability Standard that are before us in this 

proceeding. The ERO must submit its revised Work Plan within 90 days of the effective 

date of the Reliability Standards approved in this order as an informational filing to: (1) 

reflect modification directives contained in the Final Rule; (2) include the timeline for 

completion of ATC-related Reliability Standards as ordered in Order No. 890 and (3) 

account for the views of its stakeholders, including those raised in this proceeding. 

207. The Commission disagrees with NERC that we should not set specific delivery 

dates. A Work Plan with specific target dates will provide a valuable tool and incentive 

to timely address the modifications directed in this Final Rule. We note that the ERO 

previously prepared and submitted to the Commission for informational purposes one 

iteration of such a Work Plan that identifies target dates for the modification of 

Reliability Standards. Accordingly, we direct the ERO to submit as an informational 

filing, within 90 days of the effective date of this Final Rule, a Work Plan that identifies a 

plan for addressing the modifications to the Reliability Standards directed by the 

Commission in this Final Rule and a schedule with delivery dates for completing such 

modifications. The ERO should make every effort to meet such delivery dates. 

However, we understand that there may be certain cases in which the ERO is not able to 

meet a Commission’s deadline. In those instances, the ERO must inform the 

Commission of its inability to meet the specified delivery date and explain why it will not 

meet the deadline and when it expects to complete its work. 

4. Trial Period

208. NERC and some commenters to the Staff Preliminary Assessment recommended 

that the Commission establish a “trial period” during which time the ERO would 

determine, but not collect, monetary penalties. In the NOPR, the Commission expressed 

concern that a trial period that commences with the effective date of mandatory and 

enforceable Reliability Standards may interfere with their being made effective by 

summer 2007. Thus, the NOPR did not propose a trial period.99 

 98 Preventing Undue Discrimination and Preference in Transmission Service, 

Order No. 890, 72 FR 12266(March 15, 2007), FERC Stats. & Regs. ¶ 31,241 (2007) at 

P 223. 

99 Id. at P 92-93. 
Docket No. RM06-16-000 - 66 - 

209. However, the Commission recognized that there are entities that have not 

historically participated in the pre-existing voluntary reliability system (including some 

relatively small entities) that may not be familiar with what is required for compliance 

with the proposed mandatory Reliability Standards. For such entities, the NOPR 

proposed that the ERO and Regional Entities use their 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. 

a. Comments

210. Most commenters request that the Commission reconsider the proposal to reject a 

trial period during which the Reliability Standards are mandatory and enforceable but 

during which penalties would not be assessed for violating a Reliability Standard.100 EEI, 

for example, notes that the compliance enforcement program and the delegation 

agreements have not yet been approved by the Commission and there may be a short time 

between their approval and the projected start date for enforcing the Reliability 

Standards. Therefore, commenters generally state that a trial period is appropriate to 

ensure that the compliance monitoring and enforcement processes work as intended and 

that entities have time to implement new processes, such as required data systems; after 

June 2007, commenters generally state that NERC and the Regional Entities would be 

able to require remedial actions where there is an immediate actual or potential risk to 

reliable interconnected operations. Further, some state that a trial period would allow 

NERC to resolve issues with unfinished standards or ambiguous standards for which the 

Commission has directed improvements. If the Commission rejects a six-month trial 

period, several entities, such as EEI, PG&E, Xcel and NYSRC, request that the 

Commission extend NERC’s discretionary enforcement to all entities, not just those new 

to the Reliability Standards. 

211. NPCC essentially agrees with the Commission that there should be no trial period, 

but if the definition of Bulk-Power System is substantially altered to draw in a broad 

range of entities that have not traditionally been subject to pre-existing reliability 

standards, a transition period is appropriate to bring them into compliance. Where a 

Reliability Standard has missing or incomplete compliance measures, ATC states that the 

Commission should make these standards mandatory to avoid gaps, but not assess 

monetary penalties for non-compliance. ATC agrees with the Commission that the new 

mandatory reliability regime should be operational by June 2007, noting that it has been 

 100 See, e.g., EEI, APPA, TAPS, EPSA, CAISO, Bonneville, California PUC, 

Cleveland, Otter Tail, Northwest Requirements Utilities, TVA and SMA. 
Docket No. RM06-16-000 - 67 - 

over three years since the August 2003 Blackout and over a year since EPAct 2005 was 

enacted. 

212. Several entities state that the Commission’s proposal to allow the ERO and 

Regional Entities discretion in setting penalties does not go far enough, even if it is 

applied to all users, owners and operators of the Bulk-Power System. For example, 

SERC maintains that its proposed delegation agreement and the NERC Compliance 

Monitoring and Enforcement Program may not allow discretion in imposing penalties. 

213. NERC states that it understands and supports the importance the Commission 

places on the ERO having the ability to impose a financial penalty if a Bulk-Power 

System user, owner or operator violates a mandatory Reliability Standard that is in effect, 

especially for egregious behavior. However, NERC continues to maintain that a 

validation period for the compliance process and the calculation of penalties is important 

and proposes a modified approach to that taken by the Commission. NERC asks the 

Commission to authorize NERC and the Regional Entities to exercise discretion to 

calculate financial penalties, but not collect them in the case of most violations through 

December 31, 2007. At the same time it asks the Commission to specify that in a 

situation in which an entity violates a clear and well-understood Reliability Standard that 

causes a significant disturbance on the Bulk-Power System, or in the face of other 

aggravating circumstances such as repeated or intentional violations, the ERO and the 

Regional Entities would have the authority and responsibility to hold the offending entity 

fully accountable for the violation, by the assessment of financial penalties. 

214. NERC states that this alternative approach is supported by the newness of the 

compliance enforcement program, the Sanctions Guidelines and the penalty matrix, and 

the Violation Risk Factors, which have not been approved by the Commission. Further, 

NERC claims that initiating operations under mandatory Reliability Standards with the 

collection of penalties as the rule rather than the exception may increase the risk of 

numerous legal challenges occurring in the early stages of implementing mandatory 

Reliability Standards, whereas NERC would expect a rapid decline in such challenges 

after its proposed validation period. In a reply comment, Xcel supports NERC’s 

proposed approach. 

215. If the Commission rejects NERC’s proposed modified approach, NERC asks that 

it and the Regional Entities be given broad discretion in setting penalties during this time 

period and that this discretion not be limited to small entities or those who are new to 

Reliability Standards. Avista/Puget also urges the Commission, the ERO and the 

Regional Entities to exercise enforcement discretion more broadly than proposed in the 

NOPR. Penalties should be waived for an initial period in several situations, including 

where a Reliability Standard is applied based on new or different interpretations. 
Docket No. RM06-16-000 - 68 - 

216. Some commenters request that the Commission grant a longer trial period in 

certain cases. For instance, TANC believes that for smaller entities the Commission 

should, at a minimum, adopt a trial period of at least one year to provide adequate time to 

evaluate and comply with the new mandatory Reliability Standards. Bonneville and 

NPCC suggest that, for Reliability Standards that have an annual reporting requirement, 

the compliance cycle should start on June 2007 so that a Reliability Standard that relies 

on data reporting back into the prior year should have an initial compliance measurement 

date of June 2008. AMP-Ohio states that the Commission’s proposal does not go far 

enough and suggests a “ramp-up” period for entities that are new to standards, through 

and including the entity’s first compliance audit or, if the Commission rejects this 

proposal, the Commission should extend the trial period from six to twelve months. 

Reliant also advocates a phase-in of penalties over six to twelve months, with an 

increasing scale of penalties over time. 

217. Portland General and Tacoma request that the Commission institute a one-year 

trial period to allow the industry time to finalize the language of the mandatory 

Reliability Standards and to allow users, owners and operators time to adapt to the final 

language. For any Reliability Standard that requires modification, Tacoma requests that 

the Commission provide a six-month trial period beyond the date when the Reliability 

Standard is completed. Bonneville asks that the Commission extend the trial period for 

Reliability Standards that have missing or ambiguous measures or severity levels until 

those issues are resolved. National Grid states that enforcement discretion should not be 

limited in scope or duration and should be extended to any situation in which a 

Reliability Standard is applied in a novel manner, including when a Reliability Standard 

is interpreted for the first time. 

218. PG&E asserts that NERC and the Regional Entities should have discretion in 

imposing fines for violations of Reliability Standards during a transition period. Where 

an entity shows a good faith effort to comply with a new or changed Reliability Standard 

promptly and thoroughly, NERC and/or the Regional Entity should be permitted to 

consider those efforts in assessing fines. PG&E suggests a transition period of three to 

six months. Without such discretion, entities may be pressured to implement Reliability 

Standards hastily and inadequately. PG&E also notes that some entities in WECC have 

voluntarily participated in WECC’s enforcement program. The new regime entails 

procedural and substantive changes. Entities that have complied voluntarily should not 

be penalized by denying them an opportunity to adjust. 

219. WECC states that it continues to believe that a trial period of more than six 

months is appropriate, but it is not requesting that the Commission revisit its decision on 

this issue. WECC asks that Regional Entities have somewhat greater flexibility in 

monitoring and enforcing compliance during the initial period of implementation. 

According to WECC, the Commission should recognize that, in the early stages of 
Docket No. RM06-16-000 - 69 - 

implementation, penalties should be reserved for clear situations where Registered 

Entities are refusing to comply. Unreasonably harsh enforcement in the early stages of 

implementation may damage the current level of reliability by diverting resources away 

from developing solutions in order to avoid fines and support litigation. This flexibility 

should continue beyond six months after the effective date, if necessary, for those 

Reliability Standards requiring modification, until such modifications have become 

effective. 

220. According to WECC, it is extremely important that United States, Canadian and 

Mexican authorities enforce their respective standards within WECC in a way that avoids 

conflicting obligations. WECC thus suggests that the Commission grant WECC 

substantial discretion to focus on education and facilitation of compliance with NERC 

Reliability Standards while it seeks to promote consistent enforcement internationally. 

b. Commission Determination

221. The Commission adopts its proposal not to institute a formal trial period. As we 

explained in the NOPR, a trial period is inconsistent with mandatory and enforceable 

Reliability Standards taking effect in a timely manner.101 The Commission’s overriding 

concern is the reliability of the Bulk-Power System, and mandatory and enforceable 

Reliability Standards becoming effective in a timely manner are essential to ensuring the 

reliability of the Bulk-Power System. Accordingly, the Commission will not adopt a 

formal trial period. 

222. The Commission is, however, also cognizant of commenters’ concerns. In the 

NOPR, the Commission proposed that the ERO and Regional Entities use their 

enforcement discretion in imposing penalties on entities that historically had not 

participated in the pre-existing voluntary reliability regime, although authority to impose 

a penalty on such an entity would be retained “if warranted by the circumstances.”102 In 

light of commenters’ concerns, including the fact that there are new aspects to the 

Reliability Standards and the proposed compliance program that will apply to all users, 

owners and operators of the Bulk-Power System, the Commission directs the ERO and 

Regional Entities to focus their resources on the most serious violations during an initial 

period through December 31, 2007. This thoughtful use of enforcement discretion should 

apply to all users, owners and operators of the Bulk-Power System, and not just those 

new to the program as originally proposed in the NOPR. This approach will allow the 

 101 NOPR at P 92. 

102 Id. at P 93. 
Docket No. RM06-16-000 - 70 - 

ERO, Regional Entities and other entities time to ensure that the compliance monitoring 

and enforcement processes work as intended and that all entities have time to implement 

new processes. 

223. By directing the ERO and Regional Entities to focus their resources on the most 

serious violations through the end of 2007, the ERO and Regional Entities will have the 

discretion necessary to assess penalties for such violations, while also having discretion 

to calculate a penalty without collecting the penalty if circumstances warrant. Further, 

even if the ERO or a Regional Entity declines to assess a monetary penalty during the 

initial period, they are authorized to require remedial actions where a Reliability Standard 

has been violated. Furthermore, where the ERO uses its discretion and does not assess a 

penalty for a Reliability Standard violation, we encourage the ERO to establish a process 

to inform the user, owner or operator of the Bulk-Power System of the violation and the 

potential penalty that could have been assessed to such entity and how that penalty was 

calculated. We leave to the ERO’s discretion the parameters of the notification process 

and the amount of resources to dedicate to this effort. Moreover, the Commission retains 

its power under section 215(e)(3) of the FPA to bring an enforcement action against a 

user, owner or operator of the Bulk-Power System. 

224. The Commission believes that the goal should be to ensure that, at the outset, the 

ERO and Regional Entities can assess a monetary penalty in a situation where, for 

example, an entity’s non-compliance puts Bulk-Power System reliability at risk. 

Requiring the ERO and Regional Entities to focus on the most serious violations will 

allow the industry time to adapt to the new regime while also protecting Bulk-Power 

System reliability by allowing the ERO or a Regional Entity to take an enforcement 

action against an entity whose violation causes a significant disturbance. Our approach 

strikes a reasonable balance in ensuring that the ERO and Regional Entities will be able 

to enforce mandatory Reliability Standards in a timely manner, while still allowing users, 

owners and operators of the Bulk-Power System time to acquaint themselves with the 

new requirements and enforcement program. In addition, our approach ensures that all 

users, owners and operators of the Bulk-Power System take seriously mandatory, 

enforceable reliability standards at the earliest opportunity and before the 2007 summer 

peak season. 

225. National Grid, among others, states that the Commission should allow 

enforcement discretion on an ongoing basis, for example, when the ERO or a Regional 

Entity interprets a Reliability Standard for the first time. The Commission agrees that, 

separate from our specific directive that all concerned focus their resources on the most 

serious violations during an initial period, the ERO and Regional Entities retain 

enforcement discretion as would any enforcement entity. Such discretion, in fact, already 

exists in the guidelines; as we stated in the ERO Certification Order, the Sanction 
Docket No. RM06-16-000 - 71 - 

Guidelines provide flexibility as to establishing the appropriate penalty within the range 

of applicable penalties.103

5. International Coordination 

226. In response to concerns regarding international coordination of action on proposed 

Reliability Standards, the Commission reaffirmed its recognition of the importance of 

international coordination, previously discussed in both Order No. 672104 and the ERO 

Certification Order.

105 

a. Comments

227. Ontario IESO agrees with the Commission “that NERC’s development of a 

coordination process, together with the existing means of communications and 

coordination such as the United States – Canada Bilateral Electric Oversight Group will 

provide the necessary mechanisms for international coordination” and supports the 

coordination process proposed by NERC in its October 18, 2006 filing in Docket No. 

RR06-1-003.106

228. EEI and National Grid state that it is not sufficient to coordinate remands through 

NERC alone because both the Commission and Canadian provincial authorities have the 

ultimate say in approving applicable Reliability Standards. They advocate that the 

various regulators commit to coordinate through a formal mechanism, such as a 

memorandum of understanding. According to EEI, the Commission should coordinate 

with its international counterparts when directing modifications to Reliability Standards 

to ensure that the resulting Reliability Standards are uniform to the greatest extent 

possible. NPCC adds that the Commission should coordinate with its international 

counterparts when proposing to hold, remand or reject a proposed Reliability Standard to 

avoid inconsistencies in Reliability Standards application. 

 103 ERO Certification Order at P 451. 

104 See Order No. 672 at P 400. 

105 ERO Certification Order at P 286. 

106 Compliance Filing of the North American Electric Reliability Council and the 

North American Electric Reliability Corporation Addressing Non-Governance Issues, 

Appendix 3C, Docket No. RR06-1-000 (October 18, 2006). 
Docket No. RM06-16-000 - 72 - 

229. National Grid states that, where similar interpretations and modifications to 

Reliability Standards are not adopted by the provincial authorities in Canada, there is 

potential for conflicting requirements for interconnected facilities. The Alberta ESO is 

also concerned that, due to regulatory/legislative requirements and industry structures in 

Canada, some of the Reliability Standards may not be implemented as they are written. 

Therefore it requests that the Commission require that the international coordination 

process include a provision where variances are identified by these international 

governmental authorities to minimize the possibility of a governmental authority 

remanding a Reliability Standard. According to Alberta ESO, while the goal should be 

consistent, North America-wide Reliability Standards, there will be instances where this 

is not achievable. 

230. WIRAB advises that some Canadian provinces or Mexican authorities may 

approve NERC-proposed Reliability Standards with changes or modifications. It is 

important to allow minor variations across such jurisdictions to minimize the possibility 

of a governmental authority remanding a Reliability Standard. According to WIRAB, the 

goal should be a consistent system throughout North America with enough flexibility for 

some jurisdictional variation when uniformity is not immediately possible. 

b. Commission Determination

231. In the January 2007 Compliance Order, the Commission stated that, to minimize 

the possibility of a governmental authority directing a remand, it seemed appropriate for 

such governmental authorities to have an opportunity to provide NERC with input prior 

to its filing for governmental approval of a proposed Reliability Standard.107 In that 

order, the Commission agreed with NERC’s proposal to facilitate informal conferences to 

provide an opportunity for governmental authorities to consult with NERC and 

stakeholder representatives regarding Reliability Standard development work-plans, 

objectives and priorities, and emerging Reliability Standards.108 While we did not initiate 

a formal mechanism for coordination as EEI and National Grid now suggest, we did state 

that we anticipate that the Commission and counterpart governmental authorities in 

Canada and Mexico will convene regular meetings to coordinate on issues relating to 

reliability. We reaffirm that approach as an appropriate framework for addressing 

matters of international coordination in the context of continent-wide Reliability 

Standards. 

 107 January 2007 Compliance Order at P 44.

108 Id. 
Docket No. RM06-16-000 - 73 - 

232. We agree with Alberta ESO and WIRAB that the goal should be consistent, North 

America-wide Reliability Standards, but that this may not be achievable in all instances. 

For example, in this rulemaking the Commission is approving several regional 

differences in Reliability Standards; in the United States, NERC identifies regional 

variations by submitting them to the Commission in the form of a Reliability Standard.109 

233. In response to WIRAB, if a governmental authority in Canada or Mexico requests 

that NERC modify a continent-wide Reliability Standard rather than create a regional 

variance, NERC must submit any revised Reliability Standard to the Commission. The 

Commission will then have an opportunity to review the proposed revised Reliability 

Standard, taking into account the request of the foreign governmental authority. 

E. Common Issues Pertaining to Reliability Standards

1. Blackout Report Recommendation on Liability Limitations

234. In the NOPR, the Commission stated that the Blackout Report recommendations, 

many of which address key issues for assuring Bulk-Power System reliability, have 

received international support and represent a well-reasoned and sound basis for action. 

Thus, in the discussion of a particular proposed Reliability Standard, the NOPR often 

recognized the merit of a specific Blackout Report recommendation and reaffirmed the 

reasoning behind such recommendation in proposing to approve, with a proposed 

directive to modify, a specific Reliability Standard. Further, the Commission indicated 

that a modification to a proposed Reliability Standard based on a Blackout Report 

recommendation should receive the highest priority in terms of NERC’s Work Plan.110

235. The Blackout Report’s Recommendation No. 8 recognized that timely and 

sufficient action to shed load on August 14, 2003 would have prevented the spread of the 

blackout beyond northern Ohio, and recommended that legislative bodies and regulators 

should: (1) establish that operators (whether organizations or individuals) who initiate 

load shedding pursuant to operational guidelines are not subject to liability suits and (2) 

affirm publicly that actions to shed load pursuant to such guidelines are not indicative of 

operator failure.111

 109 Order No. 672 at P 296. 

110 NOPR at P 99-100. 

111 Blackout Report at 147. 
Docket No. RM06-16-000 - 74 - 

a. Comments

236. EEI states that the Commission should adopt OATT liability limitations to 

implement Blackout Report Recommendation No. 8 because compliance with mandatory 

Reliability Standards may expose transmission operators to liability for actions required 

by a Reliability Standard; Blackout Report Recommendation No. 8 identified this 

concern and recommended that legislative bodies and regulators establish that operators 

who initiate load shedding are not subject to liability. EEI disagrees with the suggestion 

that the Commission cannot shield operators from liability suits. EEI states that the 

Commission has the authority under FPA sections 205 and 206 to provide liability 

protection and has done so for several transmission operators in several cases by 

approving amendments to open access transmission tariffs providing for liability 

limitations.112 However, it notes that the Commission has rejected efforts by other parties 

to implement similar protections.113 

b. Commission Determination

237. Consistent with Order No. 890, the Commission does not adopt new liability 

protections.114 The Commission does not believe any further action is needed to 

implement Blackout Report Recommendation No. 8. First, the Task Force found that no 

further action is needed.115 Further, the Blackout report indicated that some states already 

have appropriate protection against liability suits.116 Finally, in Order No. 888, the 

Commission declined to adopt a uniform federal liability standard and decided that, while 

 112 EEI at 16, citing Southwest Power Pool, Inc., 112 FERC ¶ 61,100 (2005); 

Midwest Independent Transmission System Operator, Inc., 110 FERC ¶ 61,164 (2005);

ISO New England, Inc., 106 FERC ¶ 61,280, order on reh’g, 109 FERC ¶ 61,147 (2004). 

113 Id., citing Southern Company Services, Inc., 113 FERC ¶ 61,239 (2005). 

114 Order No. 890 at P 1671-77. 

115 US-Canada Power System Outage Task Force, Final Report on Implementation 

of Task Force Recommendations at 22 (Oct. 3, 2006), available at 

http://www.oe.energy.gov/news/blackout.htm (“Action Required to Fully Implement 

Recommendation 8: No further action under this recommendation is needed”). 

116 Id. (“In the United States, some state regulators have informally expressed the 

view that there is appropriate protection against liability suits for parties who shed load 

according to approved guidelines.”) 
Docket No. RM06-16-000 - 75 - 

it was appropriate to protect the transmission provider through force majeure and 

indemnification provisions from damages or liability when service is provided by the 

transmission provider without negligence, it would leave the determination of liability in 

other instances to other proceedings.117 Order No. 890 reaffirmed this decision. EEI has 

offered no arguments that demonstrate that an OATT limit on liability is warranted. 

2. Measures and Levels of Non-Compliance

238. The NOPR noted that, according to the Staff Preliminary Assessment, a number of 

proposed Reliability Standards do not contain Measures118 or Levels of NonCompliance,119 or both. NERC, in its petition, identified 21 Reliability Standards that 

lack Measures or Levels of Non-Compliance and indicated that it planned to file 

modified Reliability Standards that include the missing Measures and Levels of NonCompliance in November 2006. On November 15, 2006, NERC made this filing. 

239. In the NOPR, while the Commission recognized the importance of having 

Measures and Levels of Non-Compliance specified for each Reliability Standard, the 

Commission also stated that the absence of these two elements is not critical to the 

determination of whether to approve a proposed Reliability Standard. Rather, the most 

critical elements of a Reliability Standard are the Requirements, and, if properly drafted, 

a Reliability Standard may be enforced even in the absence of specified Measures or 

Levels of Non-Compliance.120 Thus, the NOPR proposed to approve a Reliability 

Standard even though it may lack Measures or Levels of Non-Compliance, or where 

these elements contain ambiguities, provided that the Requirement is sufficiently clear 

 117 Order No. 888-B, 81 FERC ¶ 61,248 at 62,081 (1997), order on reh’g, Order 

No. 888-C, 82 FERC ¶ 61,046 (1998), aff’d in relevant part sub nom. Transmission 

Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. New 

York v. FERC, 535 U.S. 1 (2002). 

118 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 to the Staff Preliminary Assessment at 104. 

119 “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. 

120 NOPR at P 105-07. 
Docket No. RM06-16-000 - 76 - 

and enforceable. Where a Reliability Standard would be improved by providing missing 

Measures or Levels of Non-Compliance or by clarifying ambiguities with respect to 

Measures or Levels of Non-Compliance, the NOPR proposed to approve the Reliability 

Standard and concurrently direct NERC to modify the Reliability Standard accordingly. 

240. The NOPR explained that the common format of NERC's proposed Reliability 

Standards calls for a “data retention” metric. Yet, some proposed Reliability Standards 

either do not contain a data retention requirement or state that no record retention period 

applies. In the NOPR, the Commission requested comment on: (1) whether the retention 

time periods specified in various Reliability Standards proposed by NERC are sufficient 

to foster effective enforcement and (2) what, if any, additional records retention 

requirements should be established for the proposed Reliability Standards. 

a. Improving Measures and Levels of Non-Compliance

i. Comments

241. A number of commenters raise concerns regarding the adequacy of current 

Measures and Levels of Non-Compliance. Some commenters, such as Nevada 

Companies, state that some Reliability Standards do not need multiple Measures and 

multiple Levels of Non-Compliance when such items do not fit the context of the specific 

Reliability Standard. According to Nevada Companies, some proposed Reliability 

Standards are more like business practices that are susceptible to a pass/fail test, and are 

not necessarily amenable to multiple Measures and Levels of Non-Compliance. Progress 

and Xcel maintain that Measures and Levels of Non-Compliance do not necessarily need 

to be added to every Reliability Standard. 

242. Constellation is concerned that the Levels of Non-Compliance do not appear to be 

based on objective criteria, but rather appear to be based on arbitrary criteria and 

assumptions regarding the impact on reliability, which could lead to penalties that are 

excessive compared to the violation. MISO states that the original intent of the Levels of 

Non-Compliance was to assign a scale based on the impact on the Interconnection. 

MISO asserts that many Requirements are rated at too high a level and that many events 

that would be rated “level 4” are really just administrative requirements. It asserts that 

there are more “level 4” events than other categories, when logic would imply a pyramid 

structure with only a few items at the highest “level 4.” MISO states there should be a 

simplified process that measures the true impact on reliability. MISO and Dynegy state 

that there should also be an “administrative infraction” category created in addition to the 

current “low,” “medium” and “high,” so that the enforcement of supporting tasks can be 

handled expeditiously. 
Docket No. RM06-16-000 - 77 - 

243. NYSRC states that, in NERC’s rush to file with the Commission the 20 revised 

Reliability Standards with new Measures and Levels of Non-Compliance, the revised 

Reliability Standards were submitted to the NERC ballot body as a group, rather than 

individually. It maintains that the group treatment prevented stakeholders from providing 

the careful attention that each revised Reliability Standard deserves. NYSRC believes 

that, as a result, Requirements for a number of these Reliability Standards are flawed. 

While their prompt approval may be justified to have them in place for the upcoming 

summer, there is not a sufficient basis for the Commission to conclude that the 

weaknesses identified in these 20 Reliability Standards have been adequately addressed. 

NYSRC recommends that the Commission approve the 20 revised Reliability Standards 

and direct the ERO to more carefully address the weaknesses identified in those standards 

and to individually submit each revised standard to a ballot for separate consideration. 

244. MISO, International Transmission and Constellation also raise concerns with 

NERC’s Violation Risk Factors. They are concerned that risk is, in some cases, being 

confused with importance. For example, MISO states that NERC appears to be assigning 

risk to every sentence in each proposed Reliability Standard, including explanatory 

information and administrative requirements, thereby confusing risk with importance. 

MISO states that, while there may be many things that a transmission operator does that 

are important, failure to do an important thing one time would not necessarily jeopardize 

the Interconnection or cause a cascading failure. 

245. MISO believes the definition of risk should reflect the likelihood that something 

serious is likely to happen if an event occurs. International Transmission, Constellation 

and MISO believe that a high risk event should, in and of itself, pose a significant threat 

to reliability and should not assume that multiple events occur simultaneously. 

According to MISO, only a small number of Requirements in the Reliability Standards fit 

the true definition of high risk. Constellation maintains that rating too many 

Requirements as high risk will water down the Requirements, and could shift the focus of 

attention away from the truly high risk Requirements, leading to a less effective, less 

efficient reliability program. 

ii. Commission Determination

246. With regard to the comments of Nevada Companies, Progress and others, we 

believe that the ERO should have flexibility in initially developing appropriate Measures 

and Levels of Non-Compliance. For example, the ERO in the first instance should 

determine whether a Measure is necessary for every Requirement of a particular 

Reliability Standard, or whether every Reliability Standard must have the same number 

of Levels of Non-Compliance. Entities interested in developing meaningful Measures 

and Levels of Non-Compliance should, we find, participate in the ERO’s Reliability 

Standards development process to ensure that their opinions are considered. 
Docket No. RM06-16-000 - 78 - 

247. With regard to the concerns of MISO and Constellation, we agree as a general 

principle that Levels of Non-Compliance should be based on objective criteria and that a 

“level 4” violation should reflect a commensurate level of severity in its impact on BulkPower System reliability. However, we will allow the ERO in the first instance to 

determine whether specific revisions to particular Reliability Standards are needed to 

address these concerns. While we consider the appropriateness of Measures and Levels 

of Non-Compliance in our standard-by-standard review, we believe in the first instance it 

is the responsibility of the ERO to develop meaningful Measures and Levels of NonCompliance, and those seeking to influence the process, as we have already found, should 

participate in the ERO’s Reliability Standards development process. Likewise, we leave 

it to the ERO to determine initially whether there is any merit in developing a category of 

“administrative infraction” as suggested by some commenters. 

248. The Commission agrees with NYSRC that, as a general matter, each Reliability 

Standard should be independently balloted in the Reliability Standards development 

process. However, the Commission will not require the ERO to resubmit each of the 20 

revised Reliability Standards to the Reliability Standards development process for 

separate consideration. We do not believe such an action is required by the statute and 

would otherwise unnecessarily delay implementation of the proposed Reliability 

Standards. However, we expect that the ERO’s Reliability Standards development 

process will provide adequate opportunity for independent consideration by stakeholders 

of each standard under consideration in the future. 

249. MISO, International Transmission and Constellation raise concerns with NERC’s 

Violation Risk Factors. The NERC board approved the Violation Risk Factors for 

Version 0 Reliability Standards and submitted them to the Commission on February 23, 

2007. The Commission is reviewing the Violation Risk Factors in a seprate proceeding 

in Docket No. RR07-9-000. Thus, these issues are not ripe for consideration in this Final 

Rule. MISO, International Transmission and Constellation may raise concerns they have 

with the Violation Risk Factors in that separate proceeding. 

b. Enforcement Implications

i. Comments

250. Certain commenters, such as EEI, Northeast Utilities, APPA and TAPS, state that 

Reliability Standards that lack clear Measures or Levels of Non-Compliance should not 

be fully enforced because they are not just and reasonable and raise potential due process 

concerns. APPA states that this is equally true of Reliability Standards that lack 

Violation Risk Factors or Violation Severity Levels because there is not proper notice as 

to the amount or range of monetary penalties to be assessed for a particular violation. 

APPA recommends that the Commission approve Reliability Standards that lack 
Docket No. RM06-16-000 - 79 - 

Measures and Violation Severity Levels, but that, until the deficiencies are corrected, 

require NERC and Regional Entities to waive imposition of monetary penalties. APPA 

would, however, reserve the Commission’s right to impose monetary sanctions where 

warranted and also require compliance with NERC and Regional Entity remedial action 

directives for these Reliability Standards. 

251. WIRAB disagrees that Reliability Standards can be consistently enforced based 

solely on sufficiently clear and enforceable Requirements. According to WIRAB, Levels 

of Non-Compliance are needed to inform parties of the consequences of non-compliance. 

WIRAB is concerned that a complex penalty structure that requires Regional Entities to 

consider multiple subjective mitigating and aggravating factors will compound the 

problems of missing and ambiguous Measures and Levels of Non-Compliance. A simple 

penalty structure would reduce enforcement ambiguities, increase uniformity and 

promote greater clarity. FirstEnergy states that, without Measures and Levels of NonCompliance, a Reliability Standard cannot meet the Commission’s requirement that a 

Reliability Standard must have a “clear criterion or measure of whether an entity is in 

compliance with a proposed Reliability Standard.”121

252. Progress and Xcel state that the Commission should clarify that the Measures and 

Levels of Non-Compliance are included solely for guidance and that only violations of 

the Requirements are subject to penalties. Portland General maintains that the Measures 

are an integral part of each Reliability Standard because entities will need to know the 

Measures so that they can build them into their compliance efforts from the beginning. In 

a similar vein, National Grid states that the lack of clear Measures or Levels of NonCompliance also makes it difficult for users, owners and operators to tailor their 

businesses and practices toward compliance or to track ongoing compliance. 

ii. Commission Determination

253. The Commission disagrees with commenters that a Reliability Standard cannot 

reasonably be enforced, or is otherwise not just and reasonable, solely because it does not 

include Measures and Levels of Non-Compliance. The Commission adopts the position 

it took in the NOPR that, 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 given the specific facts and 

circumstances of its use, ownership or operation of the Bulk-Power System. As we 

explained in the NOPR, and reiterate here: 

 121 FirstEnergy at 10-11, citing NOPR at P 16; see also Order No. 672 at P 262, 

321-37. 
Docket No. RM06-16-000 - 80 - 

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.” If properly drafted, a 

Reliability Standard may be enforced in the absence of specified Measures 

or Levels of Non-Compliance.122

254. APPA, WIRAB and others contend that, without Measures and Levels of NonCompliance, a Reliability Standard should not be enforced. We disagree. Where a 

Reliability Standard has Requirements that are sufficiently clear so that an entity is aware 

of what it must do to comply, sufficient notice has been provided. While it can be helpful 

to provide additional guidance regarding the amount or range of monetary penalties that 

may be assessed for a particular violation, the absence of such information is not a defect 

that renders a Reliability Standard unenforceable. Where the Requirement in a 

Reliability Standard is sufficiently clear, an entity will know what it should be doing to 

comply and will know that there are consequences for failure to comply. Therefore, 

where a Requirement in a Reliability Standard is sufficiently clear, we approve the 

Reliability Standard even though it may lack Measures or Levels of Non-Compliance. 

Where a Reliability Standard can 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 approve the Reliability Standard and concurrently direct NERC to 

modify it accordingly.123

255. In response to FirstEnergy, where the Requirement in a Reliability Standard is 

sufficiently clear, that Reliability Standard meets the requirement that it must have a 

“clear criterion or measure of whether an entity is in compliance with a proposed 

Reliability Standard.” The fact that NERC, in certain circumstances, did not include 

Measures and Levels of Non-Compliance does not make an otherwise clear Requirement 

 122 NOPR at P 105 (footnote omitted). 

123 APPA raises concerns regarding the completeness or adequacy of Measures 

and Levels of Non-Compliance in its discussion of specific Reliability Standards. In such 

instances, APPA argues that the Reliability Standard should not be enforced until current 

Measures and Levels of Non-Compliance are improved or, where incomplete, new ones 

developed. Applying our above rationale to these particular circumstances, while the 

ERO should improve or develop Measures and Levels of Non-Compliance where 

necessary, we will not delay the enforcement of such Reliability Standards until the ERO 

develops such improvements or additions. 
Docket No. RM06-16-000 - 81 - 

unenforceable. Neither section 215 nor the Commission’s regulations require the level of 

specificity sought by FirstEnergy in order for a Reliability Standard to be enforceable. 

256. Progress and Xcel seek clarification that Measures and Levels of Non-Compliance 

are included solely for guidance and that only violations of the Requirements are subject 

to penalties. While the Commission generally agrees that it is a violation of the 

Requirements that is subject to a penalty, we recognize that because Measures are 

intended to gauge or document compliance, failure to meet a Measure is almost always 

going to result in a violation of a Requirement. 

257. While we applaud NERC for adding additional levels of detail to its compliance 

enforcement program, we note that NERC and the Regional Entities should have further 

guidance as to how to use their enforcement discretion from the Commission’s Policy 

Statement on Enforcement.

124 Further, if NERC does not submit Violation Risk Factors 

and Violation Severity Levels before NERC’s enforcement program becomes effective, 

the Commission has reserved the ability to take appropriate action to ensure that the 

penalty-setting process described in the Sanction Guidelines is operative.125 

c. Data Retention

i. Comments

258. In the NOPR, the Commission solicited comments regarding the sufficiency of 

data retention requirements in the Reliability Standards.126 NERC states that the 

compliance data retention requirement is a defined element in the Reliability Standard 

template and that all data retention requirements, even those that are currently missing, 

will be reviewed and updated as part of the Reliability Standards Work Plan. NERC 

requests that the Commission not attempt to fix specific data retention requirements on 

the basis of comments received during this proceeding. NERC would prefer that the 

Commission direct those comments and any goals the Commission may have with regard 

to data retention back to NERC for resolution through the Reliability Standards 

development process. 

 124 Enforcement of Statutes, Orders, Rules, and Regulations, 113 FERC ¶ 61,068 

(2005) (Policy Statement on Enforcement). 

125 January 2007 Compliance Order at P 93. 

126 NOPR at P 107. 
Docket No. RM06-16-000 - 82 - 

259. SoCal Edison supports the data retention requirements in the Reliability Standards. 

APPA and SERC recommend that data retention requirements should be stated in each 

Reliability Standard and determined on a case-by-case basis through the Reliability 

Standards development process. 

260. SERC agrees with NERC that an appropriate retention period is five years unless 

otherwise specified in a Reliability Standard. ISO-NE submits that any data retention 

policy established by the ERO should be in line with the five year civil penalty statute of 

limitations for violations of NERC Standards, while APPA cautions that detailed 

operational data may be so voluminous that a five-year retention requirement would be 

burdensome and of questionable value. MRO believes that the Reliability Standards 

retention period should be commensurate with operating and planning horizons, 

documentation related to a planning standard should be retained longer and that there 

should be a retention period of at least three years. 

261. FirstEnergy states that individual record retention requirements on a standard-bystandard basis will create confusion and will be difficult to track. It therefore suggests 

that the Commission establish a uniform records retention standard of “current calendar 

year plus three years” for all proposed Reliability Standards that include a data retention 

requirement. Similarly, Entergy states that data retention requirements established for the 

Reliability Standards should be uniform and asks the Commission to direct the ERO to 

implement records retention requirements of no longer than three years. 

262. International Transmission and Entergy comment that only the relevant core 

reliability requirements of the Reliability Standards should be subject to data retention 

requirements. International Transmission states that, in instances where retaining 

evidence of compliance is impractical or where no evidence exists of compliance, it is 

appropriate that no documentation be retained. Otherwise the record retention period 

should be no less than the prevailing audit frequency. Progress and Xcel agree that 

inclusion of data retention metrics in the Reliability Standards would be useful, but the 

Commission should make clear that violations of the data retention metrics are not 

subject to separate penalties under section 215 of the FPA. 

ii. Commission Determination

263. The Commission agrees that it is appropriate for each Reliability Standard to have 

a data retention requirement. We are not persuaded that a one-size fits all approach to 

data retention is appropriate, however, because different Reliability Standards may 

require data to be retained for shorter or longer periods. Nor are we persuaded that the 

Commission should set a data retention requirement for any Reliability Standard for 

which one is currently lacking. Therefore, the Commission will not prescribe a set data 

retention period to apply to all Reliability Standards. Instead, the Commission directs the 
Docket No. RM06-16-000 - 83 - 

ERO to review and update the data retention requirements in each Reliability Standard as 

it is reevaluated through its Reliability Standards development process and submit the 

result for Commission approval. In doing so, NERC should take into account the 

comments raised in this proceeding and should seek input from other industry 

stakeholders. 

3. Ambiguities and Potential Multiple Interpretations

264. In the NOPR, the Commission proposed that a proposed Reliability Standard that 

has Requirements that are so ambiguous as to not be enforceable should be remanded.127 

A Reliability Standard that has sufficiently clear Requirements, Measures and Levels of 

Non-Compliance language and otherwise satisfies the statutory standard of review should 

be approved. A proposed Reliability Standard that has sufficiently clear 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 Levels of Non-Compliance language. 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, the Commission proposed to adopt that 

interpretation in the NOPR. 

a. Comments

265. NERC maintains that, even if the Commission believes that there is some degree 

of ambiguity in some of the Reliability Standards, making the Reliability Standards 

mandatory enables NERC and Regional Entities to respond to questionable performance 

by clarifying to the responsible entity, and others, on a going-forward basis what 

behavior would constitute compliance with the Reliability Standards. Thereafter, 

participants would know how NERC and the Regional Entities were interpreting the 

Reliability Standards. According to NERC, this information would become part of the 

public record and help to eliminate any ambiguity as to what constitutes compliant and 

noncompliant behavior under a Reliability Standard. In contrast, if the Reliability 

Standards remain voluntary or temporarily unapproved, NERC contends that it and the 

Regional Entities will lack a legal basis to compel corrective behavior. 

266. In contrast, Reliant urges the Commission to either not approve ambiguous 

Reliability Standards or approve them without subjecting entities to penalties. The level 

of ambiguity in many cases appears to violate the “just and reasonable” criteria for 

 127 NOPR at P 110-12. 
Docket No. RM06-16-000 - 84 - 

approval. It states that entities should not be found in violation based on retroactive 

interpretation of a Reliability Standard. 

267. EEI expresses concern that approval and enforcement of a Reliability Standard 

that includes ambiguous requirements or lacks certain technical features or specificity 

may raise due process concerns if the required performance or performance 

measurements are not “clear and unambiguous.” Both in this docket and on a going 

forward basis, EEI questions whether proposed Reliability Standards with various 

shortcomings or deficiencies are sufficiently clear to meet the legal standard of review. 

268. EEI and Wisconsin Electric state that it is not clear what “common interpretations” 

the Commission refers to in the NOPR or whether they are accepted or known across the 

industry. Wisconsin Electric states that common interpretations and best practices must 

be clearly spelled out and made available for review. These interpretations should be 

incorporated into the audit guidelines. Further, EEI states that common interpretations 

should not supersede provisions that are clearly stated in a Reliability Standard. 

According to EEI, if part of a proposed Reliability Standard is not clear, the NERC 

Reliability Standards development process should be used to clarify it. Further, EEI 

maintains that the Commission should require the ERO to review all existing industry 

sources, such as the NERC glossary or Institute of Electrical and Electronics Engineers 

(IEEE) standards, to supplement the interpretation of Reliability Standards. 

Undocumented “common interpretations” should be relied on only as a last resort. 

Moreover, EEI contends that, if such interpretations are to be used as a basis for assessing 

compliance and enforcement, they must be clearly spelled out and made available in 

advance. 

269. MISO notes that some Reliability Standards may have portions applicable to five 

or more entities and that there are situations where a particular functional entity is not 

mentioned in the “Applicability” section of the Reliability Standard, but they show up in 

the Requirements. It believes that the industry needs a database-style tool that is a 

companion to the Reliability Standards that permits any functional entity to sort and find 

all requirements and supporting compliance information applicable to it. Such a tool 

would help entities prevent oversights and also help NERC eliminate redundancy in the 

Reliability Standards. 

270. MISO also states that, in developing the Version 0 Reliability Standards, there was 

a conscious decision to include supporting information in the Reliability Standards 

themselves. As a result, there is now explanatory material in the Reliability Standards 

that is presented in context as Requirements. According to MISO, users now are trying 

to figure out how to measure Requirements that are really supporting text. MISO 

believes that the process should be simplified by separating each Reliability Standard into 

its core requirements and supporting information. 
Docket No. RM06-16-000 - 85 - 

271. Similarly, Constellation, International Transmission and Dynegy comment that the 

Commission should distinguish between those Requirements in each Reliability Standard 

that are core requirements as opposed to supporting information, an explanatory 

statement, or an administrative process. International Transmission and Dynegy state 

that Measures should only apply to these core reliability requirements. Reliant is also 

concerned that each Reliability Standard contains a great deal of explanatory text, 

formatted to appear as enforceable obligations. 

272. International Transmission, Reliant and MISO note that the proposed Reliability 

Standards contain many inherently ambiguous phrases or terms that can be misapplied, 

including “adequate” or “adequately,” “sufficient,” “immediate,” “where technically 

feasible,” “as soon as possible” and “where practical.” Reliant states that all ambiguous 

language must be eliminated before penalties can be assessed. MISO and Wisconsin 

Electric state that, while use of such terms may be acceptable in explanatory information, 

if a term cannot be definitively and objectively defined, it should not appear in the core 

Requirements of a Reliability Standard. 

273. Alcoa reiterates its concern that the Commission has not defined the target level of 

reliability of the Bulk-Power System that the Reliability Standards are intended to 

achieve. Further, Alcoa is concerned that the proposed Reliability Standards are 

fragmented and overlap and in some cases may result in inconsistent treatment of the 

same issue. Alcoa states that the ERO should move towards a more encompassing 

approach for developing Reliability Standards in which a reliability goal is addressed 

from all aspects in a more consistent manner. Therefore, Alcoa maintains that the 

Commission should require NERC to engage in advance planning, mapping out what 

kind of reliability is adequate for the Bulk-Power System and then developing a plan to 

get there. 

b. Commission Determination

274. The Commission finds that 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 approve the Reliability Standard. 

Upon review of the Reliability Standards and the comments submitted in response to the 

NOPR, the Commission finds that none of the Reliability Standards that we approve 

today contain an ambiguity that renders it unenforceable or otherwise unjust and 

unreasonable. As discussed in our standard-by-standard review, each Reliability 

Standard that we approve contains Requirements that are sufficiently clear as to be 

enforceable and do not create due process concerns. 
Docket No. RM06-16-000 - 86 - 

275. The underlying assumption of many of the commenters seems to be that the 

Reliability Standards must spell out in minute detail all factual scenarios that might 

violate a Requirement and the precise consequences of that violation. But due process 

requirements do not go so far. Indeed, many government regulatory schemes provide far 

less specificity in terms of what is required or proscribed, and yet those regulations are 

routinely enforced.128 Indeed, many tariffs on file with the Commission do not specify 

every compliance detail, but rather provide some level of discretion as necessary to carry 

out a particular act. This does not mean the tariffs are unenforceable; rather, it means 

that, if a dispute arises over compliance and there is a legitimate ambiguity regarding a 

particular fact or circumstance, that ambiguity can be taken into account in the exercise 

of the Commission's enforcement discretion. Therefore, we find that the Reliability 

Standards must strike a balance between a level of specificity that places users, owners 

and operators on notice of what is required, and a level of generality that encompasses 

unanticipated but serious actions or omissions that could affect Bulk-Power System 

reliability. We are satisfied that the Requirements portions of each Reliability Standard 

that we approve in this Final Rule appropriately strike this balance. 

276. Some commenters argue that certain Reliability Standards require additional 

specificity or else users, owners and operators will not understand the consequences of a 

violation. This notion is similarly misplaced because the potential (if not actual) 

consequences for any violation are clearly spelled out – the statute permits the ERO to 

assess civil penalties of up to “$1 million per violation, per day” in addition to other 

remedies. The Commission has explained how it will approach civil penalties in its 

Enforcement Policy Statement. The ERO has provided guidance in its compliance 

filings, and will continue to do so, as to how it will administer compliance and 

enforcement functions. Clarity should not be confused with certainty. The former is 

provided by the statute, the Final Rule and the aforementioned authorities. The latter is 

simply unavailable in this context. Indeed, guaranteeing in advance specific enforcement 

outcomes hampers necessary and appropriate enforcement flexibility and poses the 

danger of users, owners and operators of the Bulk-Power System simply calculating the 

cost of a violation into the cost of doing business – a dynamic that would frustrate the 

very purpose of a mandatory Reliability Standards system, which is to promote 

reliability. 

277. The Commission agrees with NERC that, even if some clarification of a particular 

Reliability Standard would be desirable at the outset, making it mandatory allows the 

ERO and the Regional Entities to provide that clarification on a going-forward basis 

 128 Many sections of the FPA, including section 215, use such terms as just and 

reasonable or unduly discriminatory or preferential or even the public interest. 
Docket No. RM06-16-000 - 87 - 

while still requiring compliance with Reliability Standards that have an important 

reliability goal. Further, we support the ERO’s efforts to review each of the current 

Reliability Standards to improve them and provide yet further clarity. We encourage all 

interested entities, especially those that have identified specific suggestions for 

improvement, to participate in the ERO’s Reliability Standards development process. 

278. The Commission finds that these Reliability Standards, with the interpretations 

provided by the Commission in the standard-by-standard discussion, meet the statutory 

criteria for approval as written and should be approved. In any event, penalties are 

warranted under section 215 only when an entity knew or reasonably should have known 

that its acts or omissions were contrary to the Reliability Standards. Wisconsin Electric 

seems to interpret the Commission as requiring that users, owners and operators of the 

Bulk-Power System comply with best practices under the Reliability Standards. We 

disagree. While we appreciate that many entities may perform at a higher level than that 

required by the Reliability Standards, and commend them for doing so, the Commission 

is focused on what is required under the Reliability Standards, we do not require that they 

exceed the Reliability Standards. We agree with EEI that a common interpretation 

cannot supplant a provision that is clearly stated in a Reliability Standard. We also agree, 

however, that, over time, these interpretations could be incorporated either into the 

Reliability Standard itself through the Reliability Standards development process or the 

ERO and Regional Entity audit guidelines. 

279. The Commission disagrees with MISO that some Reliability Standards as 

proposed are unclear with respect to applicability. In certain situations, Bulk-Power 

System reliability depends on more than one entity complying with a Reliability 

Standard. Further, in certain situations, the Requirement of a Reliability Standard may 

reference an entity that is not itself responsible for compliance with the Reliability 

Standard, for example, where an entity responsible for compliance must report 

information to or communicate with another entity, without that other entity being 

required to comply with the Reliability Standard. However, in its review of Reliability 

Standards, the ERO should ensure that, if a functional entity must comply with the 

Reliability Standards, it must be mentioned in the Applicability section. In this regard, 

we encourage the ERO to consider development of a database-style tool that is a 

companion to the Reliability Standards that permits any user, owner or operator to sort 

and find all Requirements applicable to it. 

280. In response to MISO, Constellation, International Transmission and Dynegy, the 

Commission believes that the Requirements in each Reliability Standard are core 

obligations and that the Measures and Levels of Non-Compliance provide useful 

guidance to the industry and can be supporting information, an explanatory statement or 

an administrative process. As discussed above, NERC is to enforce the Requirements in 
Docket No. RM06-16-000 - 88 - 

a Reliability Standard. The Measures are part of the Reliability Standards and, if not met, 

are almost always going to result in a violation of a Requirement. 

281. The Commission has previously addressed Alcoa’s concerns about defining the 

target level of reliability of the Bulk-Power System that the Reliability Standards are 

intended to achieve. In the January 2007 Compliance Order, the Commission directed 

the ERO to establish a stakeholder process to define adequate level of reliability.129 

While the Commission agrees that this is a worthwhile effort, we disagree with Alcoa 

that Reliability Standards cannot be approved until this analysis is done. Such analysis is 

not required by the statute, and Alcoa has not identified any compelling reason why the 

proposed Reliability Standards are defective without the benefit of such analysis. 

4. Technical Adequacy

282. In the NOPR, we stated that 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. 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.130 

a. Comments

283. NYSRC shares the Commission’s concerns regarding the use of a "lowest 

common denominator" approach in the development of Reliability Standards and agrees 

that this concern can be addressed only on a standard-by-standard basis. NYSRC 

maintains that, in commenting on pending ERO Reliability Standards, the NYSRC 

believed could weaken existing Reliability Standards, the NERC drafting team responded 

that a region is free to develop more stringent Reliability Standards. NYSRC maintains 

that the ability of a Regional Entity to propose more stringent Reliability Standards to 

meet the reliability needs of that region does not justify the weakening of continent-wide 

Reliability Standards by use of a "lowest common denominator" approach to achieve 

greater support for a proposed Reliability Standard. NYSRC recommends that the 

Commission reaffirm that it will carefully review subsequent proposed ERO Reliability 

 129 January 2007 Compliance Order at P 16. 

130 NOPR at P 115. 
Docket No. RM06-16-000 - 89 - 

Standards to ensure that they are technically adequate and do not weaken the current level 

of reliability. 

284. ATC agrees with the Commission that the industry, organized in Regional Entities 

under the ERO, must continue to be wholly accountable for the technical adequacy of the 

Reliability Standards. ATC thus suggests that the Commission’s efforts to 

“independently assess the technical adequacy of any proposed Reliability Standard” focus 

on Commission participation in and support of the Reliability Standards development 

processes at NERC and at the regions. 

b. Commission Determination

285. The Commission fully intends to address technical adequacy on a standard-bystandard basis and the Commission agrees that the ability of a Regional Entity to propose 

more stringent Reliability Standards to meet the reliability needs of that region does not 

justify the weakening of continent-wide Reliability Standards. In this regard, we note 

that, in the January 2007 Compliance Order, we directed the ERO to closely monitor the 

voting results for Reliability Standards and to report to us quarterly for the next three 

years its analysis of the voting results, including trends and patterns that may signal a 

need for improvement in the voting process, such as the rejection of a Reliability 

Standard and subsequent ballot approval of a less stringent version of the Reliability 

Standard.131 The Commission will use this information to evaluate whether it needs to 

re-examine the Reliability Standard development procedure. In doing so, the 

Commission will also be sensitive to concerns that “lowest common denominator’ 

Reliability Standards are being developed. 

286. The Commission agrees that its staff should participate in and support the 

Reliability Standards development processes, to the extent consistent with its regulatory 

role. The Commission’s participation in those processes will not constitute its entire 

assessment of the technical adequacy of a proposed Reliability Standard. The 

Commission will also conduct an assessment during its rulemaking or order process after 

the Reliability Standard is submitted by the ERO to the Commission for approval. 

5. Fill-in-the-Blank Standards

287. The NOPR explained that certain Reliability Standards, referred to as fill-in-theblank standards, require the regional reliability organizations to develop criteria for use 

 131 January 2007 Compliance Order at P 18. 
Docket No. RM06-16-000 - 90 - 

by users, owners or operators within each region.132 In the NOPR, the Commission 

expressed concern regarding the potential for the fill-in-the-blank standards to undermine 

uniformity. With regard to NERC’s stated intention to submit an action plan and 

schedule for completing the fill-in-the-blank standards, the NOPR explained that NERC’s 

plan must be consistent with the discussion in Order No. 672 regarding uniformity and 

the limited circumstances in which a regional difference would be permitted.133 

288. Further, the NOPR proposed to require supplemental information regarding any 

Reliability Standard that requires a regional reliability organization to fill in missing 

criteria or procedures. The Commission explained that, “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.”134 Therefore, the NOPR proposed to not approve 

or remand such Reliability Standards until all necessary information is provided, although 

compliance would still be expected as a matter of good utility practice.

a. Comments

289. NERC, APPA and TAPS support the Commission’s proposal to defer 

consideration of fill-in-the-blank standards. APPA believes that the Commission’s 

proposal balances the need for greater uniformity against the need for regional flexibility. 

290. NERC agrees with the Commission’s proposal to hold 24 Reliability Standards 

(mainly fill-in-the-blank standards) as pending at the Commission until further 

information is provided, and to require that Bulk-Power System users, owners and 

operators follow these pending standards as “good utility practice” pending their approval 

by the Commission. NERC also agrees that it and the Regional Entities can monitor 

compliance with these pending standards using the ERO’s authority pursuant to § 39.2(d) 

of the Commission’s regulations. NERC believes this approach is necessary to ensure 

that there will be no gap during the transition from the current voluntary reliability 

regime to mandatory and enforceable Reliability Standards. 

291. While TAPS supports deferring consideration of fill-in-the-blank standards, it 

urges the Commission to view with skepticism regional differences within an 

Interconnection that are not justified by physical differences. It states that such regional 

 132 NOPR at P 116. 

133 Id. at P 121, citing Order No. 672 at P 292; ERO Certification Order at P 274. 

134 NOPR at P 123. 
Docket No. RM06-16-000 - 91 - 

Reliability Standards, even if more stringent, can wreak havoc on competitive markets, 

especially where entities within the same transmission system or RTO footprint are 

subject to different regional Reliability Standards. For example, TAPS maintains that 

inconsistent regional underfrequency load shedding (UFLS) Reliability Standards not 

justified by physical differences impose unjust burdens on joint action agencies whose 

integrated load is split between NERC regions. Further, according to TAPS, a region’s 

choice may reflect the historical lack of a balanced process for developing Reliability 

Standards at the regional level, allowing certain classes of market participants to 

determine the region’s choice. 

292. According to ISO-NE, if the Commission withholds approval of these 24 

Reliability Standards, the Commission should also withhold approval of Reliability 

Standards that rely, by reference, on such fill-in-the-blank Reliability Standards.135 ISONE submits that, until the missing information has been provided in the cross-referenced 

fill-in-the-blank Reliability Standard, it will be impossible for the applicable entities to 

determine exactly what criteria they are expected to satisfy. APPA raises similar 

concerns, and suggests that the Commission approve such Reliability Standards but not 

enforce them until the cross-referenced fill-in-the-blank Reliability Standards are 

approved. 

293. MISO and Wisconsin Electric believe that the fill-in-the-blank standards may be 

acceptable in certain situations. They give regions some flexibility in implementation, 

and allow the deployment of a Reliability Standard where it would be difficult to get 

consensus across several regions. They also move the reliability agenda forward on 

issues that are historically under state jurisdiction, and some are an accommodation to 

those regions that want to have a higher Reliability Standard. 

294. EEI agrees with the NOPR that, regarding Reliability Standards for which the 

Commission needs additional information, compliance in the interim would be expected 

as a matter of good utility practice. While EEI agrees with this approach, it also cautions 

that the good utility practice provision of an OATT should not be used as an alternative 

means of enforcement outside of section 215 of the FPA. Similarly, FirstEnergy posits 

that good utility practice is subject to interpretation and by itself does not provide the 

level of guidance needed for a mandatory and enforceable Reliability Standard. It asserts 

that the Commission should not impose compliance burdens indirectly where it has not 

 135 ISO-NE and ISO/RTO Council state that the following Reliability Standards 

are dependent upon “fill-in-the-blank” standards: FAC-013-1, MOD-010-0, MOD-012-

0, MOD-016-1, MOD-017-0, MOD-018-0, MOD-019-0, MOD-021-0, PRC-004-1, PRC007-0, PRC-008-0, PRC-009-0, PRC-015-0, PRC-016-0, PRC-018-1 and PRC-021-0. 
Docket No. RM06-16-000 - 92 - 

imposed them directly. Xcel asserts that the Commission should rescind the Reliability 

Policy Statement that defines good utility practice under the pro forma OATT, effective 

when the Reliability Standards become mandatory in June 2007, because a reliabilityrelated violation should not be subject to two separate enforcement schemes. 

295. NPCC recommends that any of the 24 fill-in-the-blank standards that are required 

to be Reliability Standards should be developed as regional Reliability Standards by the 

Regional Entity for compliance monitoring and enforcement, backed by the Commission 

and Canadian provincial regulatory and/or governmental authorities. 

296. California PUC states that the NOPR seeks national uniformity notwithstanding 

regional differences. It states that, in the Western Interconnection, there are 15 existing, 

enforceable WECC standards pursuant to the WECC Reliability Management System 

(RMS) that overlap the proposed mandatory Reliability Standards. Five of these WECC 

standards fall into the fill-in-the-blank standards category. However, there are three 

additional WECC RMS standards already in effect in the Western Interconnection that do 

not have a corresponding proposed Reliability Standard. California PUC asks that the 

Commission consider approving these additional three standards for enforcement in the 

Western Interconnection. California PUC states that there is no reason for the 

Commission to exclude any WECC standard already in effect, and that ignoring these 

established standards when the Reliability Standards are scheduled to go into effect can 

threaten reliability already being achieved in the Western Interconnection. 

b. Commission Determination

297. The Commission requires supplemental information for any Reliability Standard 

that currently requires a regional reliability organization to fill in missing criteria or 

procedures. Where important information has not yet been provided to us to enable us to 

complete our review, we are not in a position to approve or remand those Reliability 

Standards.136 Accordingly, we will not approve or remand such Reliability Standards 

until the ERO submits further information. Until such information is provided, 

compliance with fill-in-the-blank standards should continue on a voluntary basis, and the 

Commission considers compliance with such Reliability Standards to be a matter of good 

utility practice. 

298. As noted above, some commenters such as TAPS urge the Commission to view 

most regional differences with skepticism, while others such as MISO and Wisconsin 

Electric favor some regional variation. The Commission affirms the approach that it 

 136 NOPR at P 123. 
Docket No. RM06-16-000 - 93 - 

articulated in the NOPR.137 We share commenters’ concerns regarding the potential for 

fill-in-the-blank standards to undermine uniformity. While uniformity is the goal with 

respect to Reliability Standards, we recognize that it may not be achievable overnight. 

Over time, we would expect that the regional differences will decline and uniform and 

best practices will develop. In Order No. 672, the Commission identified two instances 

where regional differences may be permitted, i.e., regional differences that are more 

stringent than continent-wide Reliability Standards (including those that address matters 

not addressed by a continent-wide Reliability Standard) and a regional difference 

necessitated by a physical difference in the Bulk-Power System. 

299. The ERO should develop the needed information for the Commission to act on the 

fill-in-the-blank standards consistent with these criteria. If a regional difference is 

warranted, a regional fill-in-the-blank proposal must be developed through an approved 

regional Reliability Standards development process, and submitted to the ERO. If 

approved by the ERO, the ERO will then submit it to the Commission for approval. 

300. The Commission disagrees with ISO-NE, ISO/RTO Council and APPA that 16 

additional Reliability Standards should not be acted on or enforced at this time. The fact 

that a Reliability Standard simply references another, pending Reliability Standard, one 

that is not being approved or remanded here, does not alone justify not approving the 

former Reliability Standard. Rather, such a reference may be considered in an 

enforcement action, if relevant, but is not a reason to delay approval of enforcement of 

the Reliability Standard. We find that the Reliability Standards that reference a pending 

Reliability Standard contain the appropriate level of specificity necessary to provide 

notice to users, owners and operators of the Bulk-Power System as to what is required. 

301. The Commission has reviewed the 16 Reliability Standards identified by 

commenters as referencing a Reliability Standard that the Commission proposed not to 

approve or remand. It appears that many of these Reliability Standards either refer to the 

process of collecting data or reference Requirements that entities are generally aware of 

because they have already been following these Reliability Standards on a voluntary 

basis. For example, MOD-012-0 requires transmission and generator owners to provide 

data to the regional reliability organization to support system modeling required by 

MOD-013-0. The NOPR proposed not to approve or remand MOD-013-0 partly because 

MOD-013-0 requires development of dynamics data requirements and reporting 

procedures that have not been submitted for our review. In addition, we proposed not to 

act on MOD-013-0 partly because it applies to a regional reliability organization and the 

Commission was not persuaded that a regional reliability organization’s compliance with 

 137 Id. at P 121 (footnote omitted). 
Docket No. RM06-16-000 - 94 - 

a Reliability Standard can be enforced by NERC. That is not the case with MOD-012-0, 

which applies to entities that are clearly users, owners and operators of the Bulk-Power 

System. Although MOD-012-0 references MOD-013-0, its applicability to a subset of 

users, owners and operators is not at issue. Accordingly, the Commission denies the 

requests to leave pending this and similar data-related Reliability Standards and reaffirms 

the NOPR approach described above. 

302. While EEI and others agree with the proposal that, in the interim, compliance with 

Reliability Standards for which the Commission needs additional information should 

continue as a matter of good utility practice, they caution that this should not lead to an 

alternative means of enforcement outside of section 215 of the FPA. In our Reliability 

Policy Statement, we explained that compliance with NERC Reliability Standards (or 

more stringent regional standards) is expected as a matter of good utility practice as that 

term is used in the pro forma OATT.138 The Commission continues to expect compliance 

with such Reliability Standards as a matter of good utility practice. That being said, the 

Commission agrees that retaining a dual mechanism to enforce Reliability Standards both 

as good utility practice and under section 215 of the FPA is inappropriate; the OATT 

only applies to entities subject to our jurisdiction as public utilities under the FPA, while 

section 215 defines more broadly our jurisdiction with respect to mandatory Reliability 

Standards. We therefore do not intend to enforce, as an OATT violation, compliance 

with any Reliability Standard that has not been approved by the Commission under 

section 215. 

303. With regard to California PUC’s comments, we recognize the desire to retain 

certain existing regional standards that apply to the Western Interconnection, which are 

currently enforceable pursuant to WECC’s RMS program. However, these regional 

Reliability Standards have not been submitted to the Commission by the ERO pursuant to 

the process set forth in Order No. 672. Accordingly, California PUC’s concerns are 

beyond the scope of this proceeding. The Commission will review the WECC standards 

once they are approved by the ERO and submitted to the Commission for approval. 

F. Discussion of Each Individual Reliability Standard 

304. The NOPR reviewed each proposed Reliability Standard and provided an analysis 

by chapter according to the categories of Reliability Standards defined in NERC’s 

petition. Each chapter began with an introduction to the category, followed by a 

 138 Policy Statement on Matters Related to Bulk Power System Reliability, 

107 FERC ¶ 61,052 at P 23-26 (2004) (Reliability Policy Statement). 
Docket No. RM06-16-000 - 95 - 

discussion of each proposed Reliability Standard. The Final Rule takes a similar 

approach. 

1. BAL: Resource and Demand Balancing

305. The six Balancing (BAL) Reliability Standards address balancing resources and 

demand to maintain interconnection frequency within prescribed limits. 

a. Real Power Balancing Control Performance (BAL-001-0)

306. 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. 

The proposed Reliability Standard would apply to balancing authorities. In the NOPR, 

the Commission proposed to approve BAL-001-0 as mandatory and enforceable.139

i. Comments

307. APPA agrees with the Commission that BAL-001-0 is sufficient for approval as a 

mandatory Reliability Standard. 

ii. Commission Determination

308. For the reasons stated in the NOPR, the Commission approves BAL-001-0 as 

mandatory and enforceable. 

b. Regional Difference to BAL-001-0: ERCOT Control 

Performance Standard 2

309. NERC approved a regional difference for ERCOT by allowing it to be exempt 

from Requirement R2 in BAL-001-0, which requires that the average area control error 

(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. This Requirement 

is referred to as Control Performance Standard 2 (CPS2). 

310. NERC explains that ERCOT requested a waiver of CPS2 because: (1) ERCOT, as 

a single control area140 asynchronously connected to the Eastern Interconnection, cannot 

 139 NOPR at P 136. 

140 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 - 96 - 

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 that it performed showing that under the new market 

structure, the ten control areas in its region individually were able to meet CPS2 

standards while the aggregate performance of the ten control areas was not in 

compliance. Since requesting the waiver from CPS2, ERCOT has adopted section 5 of 

the ERCOT protocols which identify the necessary frequency controls needed for reliable 

operation in ERCOT. 

311. In the NOPR, the Commission proposed to approve the ERCOT regional 

difference and have the ERO submit a modification of the ERCOT regional difference to 

include the requirements concerning frequency response contained in section five of the 

ERCOT protocols.141

i. Comments

312. No comments were filed on this regional difference. 

ii. Commission Determination

313. The Commission approves the ERCOT regional difference as mandatory and 

enforceable. Order No. 672 explains that “uniformity of Reliability Standards should be 

the goal and the practice, the rule rather than the exception.”142 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.143 Regional differences 

must still be just, reasonable, not unduly discriminatory or preferential and in the public 

interest.144 

314. The Commission finds that ERCOT’s approach under section 5 of the ERCOT 

protocols appears to be a more stringent practice than Requirement R2 in BAL-001-0 and 

therefore approves the regional difference. 

 141 Id. at P 143. 

142 Order No. 672 at P 290. 

143 Id. at P 291. 

144 Id. 
Docket No. RM06-16-000 - 97 - 

315. As proposed in the NOPR, the Commission directs the ERO to file a modification 

of the ERCOT regional difference to include the requirements concerning frequency 

response contained in section 5 of the ERCOT protocols. As with other new regional 

differences, the Commission expects that the ERCOT regional difference will include 

Requirements, Measures and Levels of Non-Compliance sections. 

c. Disturbance Control Performance (BAL-002-0)

316. The stated purpose of this Reliability Standard is to use contingency reserves to 

balance resources and demand to return Interconnection frequency to within defined 

limits following a reportable disturbance. The proposed Reliability Standard would apply 

to balancing authorities, reserve sharing groups145 and regional reliability organizations. 

317. In the NOPR, the Commission proposed to approve Reliability Standard BAL002-0 as mandatory and enforceable.146 In addition, pursuant to section 215(d)(5) of the 

FPA and § 39.5(f) of our regulations, the Commission proposed to direct NERC to 

submit a modification to BAL-002-0 that: (1) includes a Requirement that explicitly 

allows demand-side management (DSM) to be used as a resource for contingency 

reserves; (2) develops a continent-wide contingency reserve policy;147 (3) includes a 

Requirement that measures response for any event or contingency that causes a frequency 

deviation;148 (4) substitutes the ERO for the regional reliability organization as the 

compliance monitor and (5) refers to the ERO rather than the NERC Operating 

Committee in Requirements R4.2 and R6.2. 

 145 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 15. 

146 NOPR at P 151. 

147 The NOPR explained that this could be accomplished by modifying 

Requirement R2 or developing a new Reliability Standard. 

148 This proposed Requirement addressed modifications to Requirement R3.1 

which are described in the “Disturbance Control Standard and the Associated Reserve 

Requirement” section of this Final Rule. 
Docket No. RM06-16-000 - 98 - 

i. General Comments

318. Constellation supports the Commission’s proposals with respect to BAL-002-0. 

319. Xcel notes that this Reliability Standard would apply to a reserve sharing group, 

which is not defined in the NERC Functional Model but generally consists of a group of 

separate entities. Xcel states it is not clear how compliance and penalties would be 

applied to a reserve sharing group and seeks clarification from the Commission. As a 

second concern, Xcel states it is not clear who calculates ACE between a balancing 

authority and a reserve sharing group and states that the Commission should require the 

ERO to clarify this issue when modifying the Reliability Standard. 

ii. Commission Determination

320. The Commission approves BAL-002-0. With regard to Xcel’s concern, the NERC 

glossary defines a reserve sharing group as “two or more balancing authorities that 

collectively maintain, allocate, and supply operating reserves required for each balancing 

authority’s use in recovering from contingencies within the group.”149 The Commission 

notes that the Reliability Standard’s Requirements and Levels of Non-Compliance are 

applicable to both balancing authorities and reserve sharing groups and are clear as to the 

roles and responsibilities of these entities. The ERO will be responsible for ensuring 

compliance with this Reliability Standard for all applicable entities. A reserve sharing 

group, however, as an independent organization, is able to determine on its own as a 

commercial matter whether any penalties related to non-compliance should be reapportioned among the members of the group. With regard to Xcel’s concern about 

which entity calculates ACE, it is not clear from Xcel’s comments what it believes needs 

clarification. In general, we understand that all balancing authorities are required to 

calculate ACE with the exception of balancing authorities that use dynamic schedules to 

provide all regulating reserves from another balancing authority. As such, reserve 

sharing groups will not calculate ACE; they will rely on balancing authorities to do so. 

321. The Commission adopts the NOPR’s proposal to require the ERO to develop a 

modification to the Reliability Standard that refers to the ERO rather than to the NERC 

Operating Committee in Requirements R4.2 and R6.2. The ERO has the responsibility to 

assure the reliability of the Bulk-Power System and should be the entity that modifies the 

Disturbance Recovery Period as necessary. As identified in the Applicability Issues 

section, the Commission directs the ERO to modify this Reliability Standard to substitute 

 149 NERC Glossary at 15. 
Docket No. RM06-16-000 - 99 - 

Regional Entity for regional reliability organization as the compliance monitor.150 The 

remaining modifications to this Reliability Standard proposed in the NOPR are discussed 

below. 

iii. Including Demand-Side Management as a Resource

(a) Comments

322. SMA supports the Commission’s proposed requirement explicitly allowing 

demand-side response as a resource and agrees with the Commission that DSM and direct 

load control should be considered on the same basis as conventional generation or any 

other technology with respect to contingency reserves. SMA states that nationwide its 

members provide over 1,300 MW of demand that is curtailable on 10 minutes notice or 

less and indicates that most of this curtailable capacity is committed to utilities pursuant 

to retail tariffs or contracts for operating reserves. 

323. FirstEnergy states that demand-side resources should be included as another tool 

for the balancing authority to use in meeting the control performance and disturbance 

control standards. According to FirstEnergy, demand-side resources should mimic the 

requirements of generation resources but with a decrease in load rather than an increase 

in generation response. 

324. Process Electricity Committee generally supports the proposal to treat demand 

response resources in a manner similar to conventional generation so long as such 

demand resources participate in such DSM programs voluntarily and comply with all 

applicable Reliability Standards and requirements. Process Electricity Committee 

recommends that the Commission modify its proposal to clarify that any such demand 

response resources may be used only with the end-user’s express written agreement 

pursuant to clear contractual rights and obligations. 

325. NY Major Consumers states that many large end use customers currently have the 

ability to provide all ancillary services, or are capable of providing these services in the 

near future and that this capability has been recognized by Commission staff in Docket 

No. AD06-2-000, Assessment of Demand Response Resources. NY Major Consumers 

further states that there remains some ambiguity in the proposed Reliability Standards as 

to the eligibility of technically-qualified loads to provide these services and requests that 

 150 See Applicability Issues: Regional Reliability Organizations, supra section 

II.C.5. This directive applies generically to all Reliability Standards that identify the 

regional reliability organization as the compliance monitor. 
Docket No. RM06-16-000 - 100 - 

the Commission eliminate any such uncertainty and amend the proposed Reliability 

Standards as further described in its comments. 

326. Some commenters151 disagree with the Commission’s proposal to add a 

requirement explicitly allowing DSM as a resource for contingency reserves. NERC, 

APPA and ISO-NE state that this requirement is too prescriptive. NERC maintains that 

explicitly allowing DSM goes well beyond the bounds of current utility practice and 

suggests an improved directive would simply place DSM on the same basis as other 

resources. APPA states that DSM resources should be included as an option for a 

balancing authority to use in meeting its reserve obligations, but that the Commission 

should not require NERC to modify the Reliability Standard to explicitly identify DSM 

or any other type of capacity as a resource for meeting reserve contingencies. 

327. In addition, ISO-NE states that DSM, to which it has access, responds to capacity 

requirements and may not provide relief on a contingency basis, but states that it has a 

limited number of resources that could meet this requirement. SDG&E argues that DSM 

participation in real-time is often unknown in comparison to conventional generation and 

further states that the NOPR does not explain how DSM could be used in real-time 

dispatch. Further, SDG&E maintains that the Commission has not established a clear and 

workable definition of DSM. 

328. MISO states that it is not clear about the meaning and questions the value of the

Commission’s proposed requirement to include DSM as a contingency reserve 

resource.152 

329. While EEI and MRO do not disagree with the Commission’s proposed 

requirement to include DSM, EEI states that both generation and controllable load should 

comply with the same requirements to the maximum extent possible, while MRO 

suggests that this requirement should also include study and testing requirements. 

(b) Commission Determination

330. We direct the ERO to submit a modification to BAL-002-0 that includes a 

Requirement that explicitly provides that DSM may be used as a resource for 

contingency reserves, subject to the clarifications provided below. 

 151 See NERC, ISO-NE, APPA and SDG&E. 

152 MISO-PJM comments jointly with respect to IRO-006-3 only. 
Docket No. RM06-16-000 - 101 - 

331. The Commission disagrees with APPA that we should not explicitly identify any 

type of capacity as a resource for meeting reserve contingencies. The Commission 

believes that listing the types of resources that can be used to meet contingency reserves 

makes the Reliability Standard clearer, provides users, owners and operators of the BulkPower System a set of options to meet contingency reserves, and treats DSM on a 

comparable basis with other resources. 

332. Many commenters argue that the Commission’s proposed directive that would 

explicitly allow DSM as a resource for contingency reserves is too prescriptive. 

Concerns in this area generally fall into three categories: (1) that DSM should be treated 

on a comparable basis as other resources; (2) that the Reliability Standard should be 

based on meeting an objective as opposed to stating how that objective is met and (3) that 

DSM may not be technically capable of providing this service. 

333. With regard to the first concern, the Commission clarifies that the purpose of the 

proposed directive is to ensure comparable treatment of DSM with conventional 

generation or any other technology and to allow DSM to be considered as a resource for 

contingency reserves on this basis without requiring the use of any particular contingency 

reserve option.153 The proposed directive as written achieves that goal. With regard to 

the second concern, we believe that this Reliability Standard is objective-based and we 

reiterate that we are simply attempting to make it inclusive of other technologies that may 

be able to provide contingency reserves, and are not directing the use of any particular 

type of resource. By specifying DSM as a potential resource for contingency reserves, 

the Commission is clarifying the substance of the Reliability Standard.154 

334. With regard to commenters’ concern that DSM may not be technically possible, 

we first clarify that in order for DSM to participate, it must be technically capable of 

providing contingency reserve service. We expect that the ERO would determine what 

technical requirements DSM would need to meet to provide contingency reserves.155 

While ISO-NE, APPA and SDG&E suggest that there is limited access to qualified DSM 

or that DSM may not be optimal from a technical standpoint, we note that SMA’s 

comments state that its members are currently providing over 1,300 MW of contingency 

reserve service through retail tariffs or contracts. Alcoa states that it could use the digital 

 153 NOPR at P 157. 

154 Order No. 672 at P 260. 

155 Id. (“We leave it to the ERO to develop proposed Reliability Standards that 

appropriately balance reliability principles and implementation features.”) 
Docket No. RM06-16-000 - 102 - 

controls of its aluminum smelters to provide load control that would be superior to 

conventional generation in terms of ramp rate and speed of response. Also, the 

Commission notes that New Zealand is currently using DSM for contingency reserves.156 

Nonetheless, our requirement is that BAL-002-0 explicitly provides that demand 

resources may be used as a resource for contingency reserves without requiring the use of 

a specific resource or type of resource. 

335. Accordingly, the Commission directs the ERO to explicitly allow DSM as a 

resource for contingency reserves, and clarifies that DSM should be treated on a 

comparable basis and must meet similar technical requirements as other resources 

providing this service.157 

iv. Continent-Wide Contingency Reserve Policy

(a) Comments

336. The Commission proposed in the NOPR to direct the ERO to develop one uniform 

continent-wide contingency reserves policy. Specifically, the Commission noted that the 

appropriate mix of operating reserves, spinning reserves and non-spinning reserves 

should be addressed on a consistent basis and consideration should be given to the 

amount of frequency response from generation or load needed to assure reliability. The 

Commission proposed that this policy be neutral as to the source of the contingency 

reserves in terms of ownership or technology. 

337. SMA supports the Commission’s proposal to develop a continent-wide 

contingency reserve policy and agrees with the Commission that the policy should be 

neutral as to the source of the contingency reserves in terms of ownership or technology. 

EEI and FirstEnergy both support development of a continent-wide contingency reserve 

policy but suggest the need for regional variations across the Bulk-Power System. For 

instance, FirstEnergy suggests that a one percent peak load spinning requirement in the 

Eastern Interconnection could be the equivalent of a two percent spinning requirement in 

the Western Interconnection. 

 156 See

http://www.electricitycommission.govt.nz/pdfs/rulesandregs/rules/rulespdf/Part-C-schedC5-1Dec06.pdf. 

157 ERCOT presently uses “Load Acting as a Resource” as part of its reserves 

which are triggered at a specified frequency. This is similar to but not the same as 

generation and is an example of how load can perform as a resource. 
Docket No. RM06-16-000 - 103 - 

338. Other commenters158 disagree with the Commission’s proposal to have NERC 

develop a continent-wide contingency reserve policy and instead support an 

Interconnection-wide or regional approach. APPA, LPPC and MISO state that a 

continent-wide policy would not work because of regional differences such as size, 

topology, mix of resources and likely contingencies. While APPA supports the 

Commission’s proposal that contingency reserves should be based on the reliability risk 

of a balancing authority not meeting load, it favors an Interconnection-wide approach. 

MISO suggests that defining certain terms such as “spinning,” “non-spinning,” 

“contingency” and “replacement” and having common calculations would be of value. It 

contends, however, that EPAct does not apply to resource adequacy requirements, 

implying that the Commission therefore is prevented from directing the development of a 

continent-wide contingency reserve policy. International Transmission shares this view. 

339. California PUC states that some customers can tolerate a limited number of 

outages and suggests that it may be more cost-effective to provide back-up power to 

customers with high reliability needs rather than designing the entire system to a very 

high and expensive level. California PUC disagrees with the Commission that 

contingency reserves should be based only on the reliability risk of a balancing authority 

not meeting load. It suggests that certain other relevant factors should be considered, 

such as the number of customers or MW lost, the value that customers in a certain area 

place on reliability and the costs of avoiding outages (the cost of reserves). 

(b) Commission Determination

340. We direct the ERO to submit a modification to BAL-002-0 to include a continentwide contingency reserve policy. We are not prescribing the details of that policy. As 

the Commission stated in the NOPR, “[w]hile 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.”159 In addition, the 

contingency reserves should include sufficient frequency responsive resources such that 

the net frequency response of the balancing authority is sufficient for either 

 158 See APPA, International Transmission, MISO-PJM, LPPC and California PUC. 

159 NOPR at P 156. 
Docket No. RM06-16-000 - 104 - 

interconnected or isolated operation.160 The Commission agrees with MISO that certain 

terms such as “spinning” and “non-spinning” or any other term used to describe 

contingency or operating reserves could be developed continent-wide. Additionally, we 

believe the technical requirements for resources that provide contingency reserves should 

not change from region to region. 

341. We believe a continent-wide contingency reserves policy would assure that there 

are adequate magnitude and frequency responsive contingency reserves in each balancing 

authority. This will improve performance so that no balancing authority will be doing 

less than its fair share. 

342. With regard to California PUC’s concerns regarding the cost of providing 

reserves, and the suggestion that loss of firm load may be an acceptable alternative to 

enhanced reliability of the system, the Commission disagrees. Loss of firm load should 

not be permitted in planning the system for a single contingency. However, the 

Commission recognizes the appropriate concern of California PUC regarding costs. The 

California PUC can have a strong role in this area by encouraging or requiring DSM 

programs that can reduce the demand on the transmission system. 

343. With regard to statements that EPAct does not apply to resource adequacy, we 

note that this Reliability Standard does not concern resource adequacy, but addresses 

contingency reserves, which are operating and not planning reserves. Operating reserves 

are not the same as resource adequacy, a planning element. Section 215 authorizes the 

Commission to approve Reliability Standards for contingency reserves because they are 

necessary for real-time Reliable Operation of the Bulk-Power System. 

344. Accordingly, the Commission requires the ERO to develop a continent-wide 

contingency reserve policy through the Reliability Standards development process, which 

should include uniform elements such as certain definitions and requirements as 

discussed in this section. The Commission clarifies that the continent-wide policy can 

allow for regional differences pursuant to Order No. 672, but that the policy should 

include procedures to determine the appropriate mix of operating reserves, spinning and 

non-spinning, as well as requirements pertaining to the specific amounts of operating 

reserves based on the load characteristics and magnitude, topology, and mix of resources 

available in the region.

 160 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 

reserves have adequate frequency response to assure recovery immediately following an 

incident. 
Docket No. RM06-16-000 - 105 - 

v. Disturbance Control Standard and the Associated 

Reserve Requirement

(a) Comments

345. The Commission identified two items in the Disturbance Control Standard section 

of the NOPR. In the first item, the Commission agreed with the interpretation that the 15 

minute limit on a reportable disturbance was “absolute, objective, and measurable” and 

therefore enforceable in the present Reliability Standard. The second item resulted in a 

proposal to modify Requirement R3.1, which currently requires that a balancing authority 

to carry at least enough contingency reserves to cover “the most severe single 

contingency.” The Commission proposed to change the Requirement to include enough 

contingency reserves 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. The Commission noted that this approach 

would address staff’s concern with Requirement R3.1—specifically, addressing the 

ambiguity over whether the Requirement meant the loss of generation or the loss of 

supply resulting from a transmission or generation contingency.161

346. Most commenters162 express concern over the Commission’s proposal to add a 

Requirement that measures response for any event or contingency that causes a frequency 

deviation. NERC states that this proposed directive is overly prescriptive and suggests 

that an improved modification would be to direct the ERO to resolve the ambiguity in 

Requirement R3.1 as pointed out in the Staff Preliminary Assessment. APPA suggests 

that the Commission should not require NERC to modify the Reliability Standard, but 

should allow NERC to address the Commission’s concerns in its Reliability Standards 

development process and, while doing so, NERC should consider defining “Most Severe 

Single Contingency” contained in the WECC Frequency Response Standard White 

Paper.163 Xcel has concerns about the compliance aspects of this proposed modification 

stating that there is no equitable method to assess an individual entity’s performance for 

an occurrence that is potentially Interconnection-wide. 

347. NRC notes the NERC and Commission observations regarding the declining trend 

in frequency response and states that this Reliability Standard provides the opportunity to 

 161 NOPR at P 153. 

162 See NERC, APPA, Xcel, MRO, ISO-NE, EEI and Nevada Companies. 

163 See NOPR at n.116. 
Docket No. RM06-16-000 - 106 - 

establish a frequency response performance standard. NRC staff suggests that a Measure 

be added to establish a frequency response. 

348. MRO suggests that, if this requirement is adopted, a clear definition of the event 

that causes a frequency deviation will be required. ISO-NE comments that Requirement 

R3.1 is already clear and the suggested modification is not clear because: (1) it is not 

possible to plan for all such events and (2) it is not clear what is a “significant deviation.” 

EEI states that a requirement to measure frequency response for any event or contingency 

could provide beneficial information for system operators but states that there is presently 

no requirement for generators to report all outages so measurements cannot be made. 

EEI further states that the compliance costs of this requirement may outweigh the 

benefits. The Nevada Companies disagree with the proposed modification and state that 

the Reliability Standard must instead focus strictly on the loss of supply. The Nevada 

Companies further state that, for purposes of this Reliability Standard, WECC’s present 

contingency reserve criterion, which requires consideration of loss of generation that 

would result from the most severe single contingency, is most applicable. 

349. Georgia Operators comment that the Commission’s intent in this proposed 

modification should not be interpreted to require a balancing authority to carry enough 

reserves to cover any event resulting in a significant deviation in frequency and should 

not be read to suggest that frequency rather than ACE should be used to measure a 

balancing authority’s deployment of reserves for contingencies. 

350. MISO and ERCOT comment on the Commission’s suggestion that NERC should 

consider defining a frequency deviation of 20 milli Hertz lasting longer than the 15 

minute recovery period as a significant deviation. MISO argues that the value could vary 

in different Interconnections and believes the current method is acceptable. ERCOT 

states that it is not feasible to apply a single frequency-deviation number to ERCOT and 

the other Interconnections and asks the Commission to instead consider a Reliability 

Standard that is proportional to the size of each Interconnection. ERCOT notes that 20 

milli Hertz would be far more strict than ERCOT’s historic frequency performance. 

(b) Commission Determination

351. On this issue, the Commission will not direct the ERO to modify BAL-002-0 in 

the manner proposed in the NOPR. Rather, the Commission directs the ERO to address 

the concerns expressed by the Commission about having enough contingency reserves to 

respond to an event on the system in Requirement R3.1 and how such reserves are 

measured. The ERO should address this through adoption or modification of 

Requirements and metrics in the Reliability Standards development process. 
Docket No. RM06-16-000 - 107 - 

352. NERC correctly points out that the Commission’s proposal on this point stemmed 

from the ambiguity in Requirement R3.1 that Commission staff highlighted in the Staff 

Preliminary Assessment. Requirement R3.1 currently requires that a balancing authority 

carry at least enough contingency reserves to cover “the most severe single contingency.” 

The Commission emphasizes that the goal of this Reliability Standard is to insure against 

the reliability risk of not serving load by matching generation and load following any 

disturbance or event that results in a significant deviation in frequency. Consistent with 

this goal, the Commission believes that this Reliability Standard should be inclusive of all 

events, i.e., loss of supply, loss of load or significant scheduling problems, which can 

cause frequency disturbances and should address how balancing authorities should 

respond. The Commission notes that PJM recently issued a paper addressing frequency 

excursion related to scheduling problems.164 

353. In the NOPR, the Commission identified two concerns in the Disturbance Control 

Standard section of BAL-002-0. The first discussed NERC’s comment that the 

Reliability Standard is “absolute, objective, and measurable” because it allows up to 15 

minutes for the recovery from a reportable disturbance,165 and second, the Commission 

asked 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.166 No 

commenters address the first concern but many commented on the second. 

354. First, the Commission directs the ERO to develop a modification to the Reliability 

Standard requiring that any single reportable disturbance that has a recovery time of 15 

minutes or longer be reported as a violation of the Disturbance Control Standard. This is 

consistent with our position in the NOPR and NERC’s position in response to the Staff 

Preliminary Assessment of the Requirements in BAL-002-0, and was not disputed or 

commented upon by any NOPR commenters. 

355. Taking into account commenters’ concerns about defining a significant deviation 

as a frequency deviation of 20 milli Hertz lasting longer than the 15 minute recovery 

period, the Commission will not direct a specific change. Instead, we direct the ERO, 

through the Reliability Standards development process, to modify this Reliability 

Standard to define a significant deviation and a reportable event, taking into account all 

events that have an impact on frequency, e.g., loss of supply, loss of load and significant 

 164 Id. at n.134. 

165 NERC Comments on the Staff Preliminary Assessment at 41. 

166 NOPR at P 153. 
Docket No. RM06-16-000 - 108 - 

scheduling problems, which can cause frequency disturbances and to address how 

balancing authorities should respond. As suggested by NRC, this or a related Reliability 

Standard should also include a frequency response requirement. The present Control 

Performance Standards represent the monthly and yearly averages which are appropriate 

for measuring long-term trends but may not be appropriate for measuring short-term 

events. In addition, the measures should be available to the balancing authorities to assist 

in real-time operations.167

vi. Summary of Commission Determination 

356. The Commission approves Reliability Standard BAL-002-0 as mandatory and 

enforceable. In addition, the Commission directs the ERO to develop a modification to 

BAL-002-0 through the Reliability Standards development process that: (1) includes a 

Requirement that explicitly provides that DSM may be used as a resource for 

contingency reserves; (2) develops a continent-wide contingency reserve policy;168 and 

(3) refers to the ERO rather than the NERC Operating Committee in Requirements R4.2 

and R6.2. In addition, the Commission directs the ERO to modify the Reliability 

Standard in a manner that recognizes the loss of transmission as well as generation, 

thereby providing a realistic simulation of possible events that might affect the 

contingency reserves. 

d. Frequency Response and Bias (BAL-003-0)

357. The purpose of BAL-003-0 is to ensure that a balancing authority’s frequency bias 

setting169 is accurately calculated to match its actual frequency response.170 In the NOPR, 

 167 It is the Commission’s understanding that the Balancing Authority ACE Limit 

Standards that are currently being field tested are triggered on frequency deviations and 

can be used as feedback to the real-time operations personnel. 

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

new Reliability Standard. 

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

authority ACE algorithm, which allows the balancing authority to contribute its 

frequency response to the Interconnection. See NERC glossary at 7. 

170 The actual frequency response is the increase in output from generators after 

the loss of a generator and determines the frequency at which generation and load return 

to balance. 
Docket No. RM06-16-000 - 109 - 

the Commission proposed to approve Reliability Standard BAL-003-0 as mandatory and 

enforceable. In addition, pursuant to section 215(d) of the FPA and § 39.5(f) of our 

regulations, the Commission proposed to direct NERC to submit a modification to BAL003-0 that: (1) includes Levels of Non-Compliance and (2) modifies Measure M1 to 

include yearly surveys of frequency response.171

358. The Commission further requested comments on whether BAL-003-0 

appropriately addresses frequency bias setting during normal as well as emergency 

conditions and whether a requirement should 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.172 

i. Comments

359. Several commenters address the Commission’s proposal to direct the ERO to 

modify Measurement M1 to include yearly surveys. 

360. LPPC agrees with the Commission’s proposed directive. EEI states that NERC 

currently conducts an annual frequency response characteristic survey that appears to 

address the Commission’s proposed directive. If the yearly survey would replace the 

frequency response characteristic survey, EEI states that the survey should include 

questions regarding the scope of potential new requirements. ISO/RTO Council believes 

that yearly surveys are unnecessary and would prefer that NERC focus on surveying 

balancing authority responses to large frequency disturbances. 

361. APPA agrees that the Commission has correctly identified shortcomings in this 

Reliability Standard and states that, while the Commission may have identified 

appropriate modifications, the determination should be left to NERC to address in the 

first instance. APPA supports the development of a consistent Interconnection-wide 

policy and suggests that NERC should consider procedures similar to those used in 

ERCOT and WECC. 

362. FirstEnergy suggests that Requirements R5 and R5.1 of this Reliability Standard 

should be required in lieu of Requirement R2 if a balancing authority has load but no 

generation (R5) or if a balancing authority has generation but no load (R5.1). 

 171 NOPR at P 177. 

172 Id. at P 175. 
Docket No. RM06-16-000 - 110 - 

FirstEnergy states that without this change the Reliability Standard is not clear because it 

implies that a balancing authority could choose between two options. Most commenters 

responded to the Commission’s request for comments in the NOPR by stating that 

additional requirements do not need to be added for balancing authorities to calculate the 

frequency response necessary for reliability in each of the Interconnections. NERC states 

that frequency bias is currently over-compensated across the Interconnections and that 

requiring frequency bias to be actual frequency response may reduce control 

performance. Additionally, NERC states that some studies have shown a decline in 

frequency (e.g., governor) response over several decades and that it is addressing this 

issue through the request for a new Reliability Standard on frequency response. NERC 

also notes that BAL-003-0 will be replaced soon by the new balancing Reliability 

Standards that are approaching ballot. 

363. In general, EEI believes that systemic over-biasing does not present a reliability 

problem and the Commission should exercise caution in requesting changes to this 

Reliability Standard. EEI states that the frequency bias varies continuously in terms of 

the type and magnitude of load changes, and the types and loading of generation 

resources. Therefore, EEI suggests that the accuracy of any estimate of frequency bias is 

highly questionable. Further, EEI states that the one percent default value was 

deliberately set to over-bias the system to ensure adequate frequency response. EEI is 

unaware of any evidence of undamped oscillations due to this over-biasing and states that 

the one percent floor should be recognized by the Commission as just and reasonable 

until an optimum frequency bias value can be studied. EEI sees the potential need for 

developing requirements for modifying frequency bias during emergency conditions, 

citing evidence from the August 2003 blackout suggesting that oscillations following the 

ISO New England separation from the Eastern Interconnection may have been caused by 

over-biasing. 

364. ISO/RTO Council comments that the details of the procedures that are used to 

ensure frequency bias are appropriate and no additional requirements for balancing 

authorities are needed. It disagrees with the Commission’s proposal to develop uniform 

requirements for frequency bias.173 ISO/RTO Council states that there is no single right 

way to develop and apply a frequency bias setting and no universally accepted norm. 

ISO/RTO Council believes the key point is that the frequency bias setting be greater than 

the natural frequency response of the system and believes that the percent minimum 

currently in place is sufficient. ISO/RTO Council recommends that NERC investigate 

(1) reliability issues associated with low natural response; (2) causes of decreasing 

 173 See id. at P 129. 
Docket No. RM06-16-000 - 111 - 

natural response and (3) possible opportunities for creating markets for load and 

generator response to frequency changes. 

365. Xcel responds that there is no need for this Reliability Standard to address 

frequency bias during black start, restoration and islanding due to the transitional nature 

of those events. Northern Indiana opposes imposing greater restrictions on frequency 

bias and frequency response calculations, stating that they could be counter-productive by 

making procedural errors more likely, which could harm reliability. Northern Indiana 

suggests that the approach suggested in the NOPR would require frequency response to 

be calculated based on various contingencies in a way that, if a particular contingency 

does not occur, the balancing authority might contribute to an incorrect frequency 

response. Northern Indiana maintains that the existing Reliability Standard is appropriate 

because it reflects the unique characteristics of each utility’s operating characteristics and 

allows experienced, certified operators to act to avoid adverse effects on the electric 

system. 

366. MidAmerican believes that a requirement for balancing authorities to calculate the 

necessary frequency response is not necessary for reliability, nor should balancing 

authorities be required to identify the method to obtain that frequency response. 

MidAmerican states that the bias settings addressed in BAL-003-0 are appropriate for 

normal and emergency conditions. It further explains that large disturbances resulting in 

large frequency shifts can only be corrected by bringing load and generation into balance. 

MidAmerican further states that the annual review of bias settings uses tie line and 

frequency deviations during large disturbances to provide bias settings representative of 

relatively large frequency excursions and adds that these settings, along with automatic 

generation control and governor response, provide an over-biased response to steadystate frequency deviations. MidAmerican states that as long as system disturbances are 

continually tracked to ensure frequency decay is sufficiently mitigated, enough frequency 

bias will be on the system and the current Reliability Standard can be considered 

sufficient. 

367. MISO states that it expects the Commission’s concerns with the frequency 

response and bias standard to be addressed in NERC’s frequency response Reliability 

Standard Authorization Request. 

ii. Commission Determination

368. The Commission approves Reliability Standard BAL-003-0 as mandatory and 

enforceable. In addition, the Commission directs the ERO to develop a modification to 

BAL-003-0 as discussed below.
Docket No. RM06-16-000 - 112 - 

369. With respect to the frequency of frequency response surveys, EEI states that 

NERC currently conducts an annual frequency response characteristic survey that appears 

to address the Commission’s concern. The Commission disagrees. The surveys that 

were performed on a yearly basis are not available on NERC’s website and the ISO/RTO 

Council believes that more frequent analysis after large frequency disturbances is 

appropriate. The Commission understands that the last analysis was performed in 2002. 

Currently, Measure M1 only requires balancing authorities to perform surveys when 

requested by the NERC operating committee. As identified in Order No. 672, the 

Reliability Standards should be based on actual data.174 Therefore, on further 

consideration, instead of requiring yearly surveys as proposed in the NOPR, the 

Commission believes that the frequency of these surveys should be based on the data 

requirements that will assist the ERO to determine if the balancing authorities are 

providing adequate and equitable frequency response to disturbances on the Bulk-Power 

System. Accordingly, we direct the ERO to determine the optimal periodicity of 

frequency response surveys necessary to ensure that Requirement R2 and other 

Requirements of the Reliability Standard are being met and to modify Measure M1 based 

on this determination.175

370. With respect to FirstEnergy’s comment, Requirement R2 states that the frequency 

bias setting should be as close as practical to, or greater than, the balancing authority’s 

frequency response. That is the Requirement concerning the relationship between 

frequency response and frequency bias, with Requirement R5 and R5.1 providing 

minimum frequency bias values for specific types of balancing authorities. The three 

Requirements do not conflict. A balancing authority must use a frequency bias of at least 

one percent and they must have a frequency bias that is as close as practical to, or greater 

than, the balancing authority’s actual frequency response. As will be discussed more 

fully below, the Commission expects each balancing authority to meet these 

Requirements to be in compliance with the existing BAL-003-0. 

371. With respect to the Commission’s request for comments, most commenters are 

opposed to additional requirements for balancing authorities to calculate the frequency 

response necessary for reliability in each of the Interconnections. NERC states that 

frequency bias is currently over-compensated across the Interconnections, while EEI 

states that the one percent default value was deliberately set to over-bias the system to 

 174 Order No. 672 at P 324. 

175 As input to the Reliability Standards development process, the Commission 

suggests that the ERO perform sufficient analysis to understand how the frequency 

response varies between balancing authorities and Interconnections. 
Docket No. RM06-16-000 - 113 - 

ensure adequate Frequency Response. The ISO/RTO Council comments that frequency 

bias settings are appropriate and all agree that no additional requirements are needed. 

However, NERC acknowledges that the frequency response of the Eastern and Western 

Interconnection is decreasing and states it will address the issue with a new frequency 

response Reliability Standard. There is no similar need in ERCOT because ERCOT has 

adopted an approach to calculate the necessary frequency response needed for Reliable 

Operation and has identified a method of obtaining the necessary frequency response as 

discussed in BAL-001-0 regional difference. The Commission understands that this 

approach was based on lessons learned from the May 15, 2003 event176 that resulted in 

larger than anticipated amounts of firm load shedding by underfrequency relays operation 

due to less than desirable amounts of frequency response. 

372. The Commission is not persuaded by the commenters. We conclude that the 

minimum frequency response needed for Reliable Operation should be defined and 

methods of obtaining the frequency response identified. In addition to the ERCOT 

experience, EEI provides an additional example that underscores the Commission’s 

concern in this area with its discussion of the ISO-NE frequency oscillations resulting 

from the August 14, 2003 blackout. Severe oscillations were observed in the ISO-NE 

frequency when it separated from the Eastern Interconnection during the August 14, 2003 

blackout.177 The ISO-NE operators acted quickly to reduce the bias setting so as to 

eliminate the self-induced frequency oscillations before they affected system reliability. 

This apparent mismatch between the bias and the actual frequency response might have 

caused the ISO-NE system to cascade if it had not been for the quick actions of its 

operators. Therefore, we direct the ERO to either modify this Reliability Standard or 

develop a new Reliability Standard that defines the necessary amount of frequency 

response needed for Reliable Operation and methods of obtaining and measuring that 

frequency response is available. 

 176 See Underfrequency Load Shedding 2006 Assessment and Review by ERCOT 

Dynamics Working Group, available at 

http://www.ercot.com/meetings/ros/keydocs/2007/0111/10a._DWG_2006_UFLS_Assess

ment_12-18-06.doc. 

177 See Performance of the New England and Maritimes Power Systems During 

the August 14, 2003 Blackout by Independent System Operator New England, available 

at 

https://www.npcc.org/publicFiles/blackout/archives/Restoration_of_the_NPCC_Areas.pd

f. 
Docket No. RM06-16-000 - 114 - 

373. As the Commission noted in the NOPR and in our response to FirstEnergy, 

Requirement R2 of this Reliability Standard states that “[e]ach Balancing Authority shall 

establish and maintain a Frequency Bias Setting that is as close as practical to, or greater 

than, the Balancing Authority’s Frequency Response.” The Commission believes that the 

achievement of this Requirement is fundamental to the tie line bias control schemes that 

have been in use to assist in balancing generation and load in the Interconnections for 

many years.178 We understand that the present Reliability Standard sets the required 

frequency response of the balancing authorities to be approximately one percent or 

greater by requiring that the frequency bias shall not be less than one percent and that the 

frequency bias be as close as practical to, or greater than, the actual frequency response. 

374. While EEI supports additional requirements related to frequency bias during 

emergency conditions, Xcel states that frequency response during black start, restoration 

and islanding situations need not be addressed in a Reliability Standard due to the 

transient nature of these events. The Commission disagrees with Xcel and agrees with 

EEI. The Bulk-Power System should be operated in a reliable manner at all times. 

375. Accordingly, the Commission approves Reliability Standard BAL-003-0 as 

mandatory and enforceable. In addition, the Commission directs the ERO to develop a 

modification to BAL-003-0 through the Reliability Standards development process that: 

(1) includes Levels of Non-Compliance; (2) determines the appropriate periodicity of 

frequency response surveys necessary to ensure that Requirement R2 and other 

requirements of the Reliability Standard are being met, and to modify Measure M1 based 

on that determination and (3) defines the necessary amount of Frequency Response 

needed for Reliable Operation for each balancing authority with methods of obtaining 

and measuring that the frequency response is achieved. 

e. Time Error Correction (BAL-004-0)

376. 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.179 In the 

NOPR, the Commission proposed to approve Reliability Standard BAL-004-0 as 

 178 Cohn, Nathan, Control of Generation and Power Flow on Interconnected 

Systems, (John Wiley and Sons 1966). 

179 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 18. Time error is caused by the accumulation 

of frequency error over a given period. 
Docket No. RM06-16-000 - 115 - 

mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and 

§ 39.5(f) of our regulations, the Commission proposed to direct that NERC submit a 

modification to BAL-004-0 that includes Levels of Non-Compliance and additional 

Measures.180 

377. Further, the Commission noted that WECC has implemented an automatic time 

error correction procedure181 that, according to data on the NERC website, is more 

effective in minimizing both time error corrections and inadvertent interchange.182 The 

NOPR asked for comment on whether the Commission should require NERC to adopt 

Requirements similar to those in the WECC automatic time error correction procedure. 

i. Comments

378. MISO states that it is unclear what the Commission had in mind with its proposed 

directive to include Levels of Non-Compliance and additional Measures and that the 

reliability benefit of such Levels of Non-Compliance and additional Measures is also 

unclear. 

379. While APPA and EEI favor adopting the WECC approach to time error correction, 

NERC and the majority of other commenters183 are either opposed to adopting the WECC 

automatic time error correction procedure in other regions or think time error correction 

is more appropriately addressed as a business practice. NERC notes that the WECC 

procedure is in lieu of an equivalent procedure contained within the business practices of 

the North American Energy Standards Board (NAESB) and suggests that instructions for 

implementing a time error correction are more appropriately addressed as a business 

practice. Northern Indiana maintains that WECC-type procedures are unnecessary, and 

could result in unintended process errors or operational problems. It urges the 

Commission to allow time error issues to remain within the jurisdiction of NAESB and 

suggests that time error correction is not essential to reliability and is more appropriately 

 180 NOPR at P 184. 

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

Procedure_10-04-02.pdf. 

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

data) and http://www.nerc.com/~filez/timerror.html (regarding time error correction). 

183 See Xcel, Northern Indiana, ISO-NE, LPPC and MISO-PJM. 
Docket No. RM06-16-000 - 116 - 

treated as a non-essential guide. ISO-NE agrees that time error correction is not a 

reliability issue. 

380. Xcel states that its operating company located in WECC has experienced problems 

with WECC’s automatic time error correction procedure and therefore does not support 

adoption of this procedure by other regions. In addition, Xcel states that time error 

correction is not necessary for utilities in regional markets where imbalances are settled 

financially and the regional market operator manages the scheduled interchange offsets. 

LPPC suggests that there is not enough evidence to show that WECC’s time error 

correction procedure is appropriate for the Eastern Interconnection. LPPC adds that the 

choice of switching to the WECC procedure should be left up to the NERC Reliability 

Standards development process. 

381. MISO states that, while the WECC procedure has advantages with regard to 

reducing inadvertent interchange values, it does not reduce the number of time error 

corrections because WECC monitors and performs time error correction on a shorter time 

frame than the Eastern Interconnection. MISO argues that this is more of a technical 

requirement and not a Reliability Standard and suggests there are simpler ways to control 

time error and manage inadvertent balances. MISO states that NERC previously allowed 

unilateral payback of inadvertent balance of up to 20 percent of bias when the payback is 

in a direction to reduce time error and states that this reduced the number of time error 

corrections while giving balancing authorities a tool to balance their accounts. In its 

comments addressing BAL-006-1, MISO suggests that the number of time error 

corrections could be reduced by following the European methodology which has a wider 

window of allowable time and implements full clock-day, but with a smaller offset. 

ii. Commission Determination 

382. The Commission approves Reliability Standard BAL-004-0 as mandatory and 

enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our 

regulations, the Commission directs the ERO to develop a modification to BAL-004-0 

through the Reliability Standards development process that includes Levels of NonCompliance and additional Measures for Requirement R3. Further, based on 

commenters’ concerns that there is no engineering basis for changing the time error 

correction to the WECC approach or any other approach, when reviewing the Reliability 

Standard during the ERO’s scheduled five-year cycle of review, we direct the ERO to 

perform research that would provide a technical basis for the present approach or for any 

alternative approach. 

383. Many commenters aver that the time error correction procedure belongs within the 

realm of NAESB and is not a reliability issue. The Commission disagrees, as BAL-004-0 

is intended to ensure that time error corrections are performed in a manner that does not 
Docket No. RM06-16-000 - 117 - 

adversely affect the reliability of the Interconnection. The financial aspects of time error 

correction such as MISO’s concern about the unilateral payback of interchange 

imbalances remain with NAESB. However, the technical details, including the means to 

carry out the procedure, are a reliability issue. 

384. We believe that the efficiency of the time error correction can be viewed as a 

measure of whether all balancing authorities are participating in time error correction. 

Requirement R3 states that each balancing authority, when requested, shall participate in 

a time error correction. The Commission believes that this is a critical requirement, but 

the data on the NERC website indicates that efficiency is decreasing, indicating that 

fewer balancing authorities are employing time error correction.184 Therefore, the 

Commission affirms its preliminary finding that the efficiency of time error corrections 

has decreased over the last ten years and that participation in time error corrections may 

be lacking.185 Accordingly, we direct the ERO to develop additional Measures and add 

Levels of Non-Compliance to assure that the requirements in Requirement R3 are 

achieved. One approach to achieving this would be to use the existing measurement of 

efficiency as a metric of participation of all balancing authorities. If the efficiency is 

significantly less than 100 percent, the Measures should provide a process to identify 

which balancing authorities are not meeting the requirements of the Reliability Standard. 

385. Although the Commission noted in the NOPR that WECC’s time error correction 

procedure appears to serve as a more effective means of accomplishing time error 

correction, based on concerns that there is no engineering basis for changing the time 

error correction to the WECC approach, the Commission will not direct the ERO to adopt 

requirements similar to WECC’s procedure. With the exception of comments from 

APPA and EEI, most commenters do not believe or are uncertain about whether the 

WECC procedure is appropriate for the Eastern Interconnection. However, when this 

Reliability Standard is scheduled for its regular five-year cycle of review, the 

Commission directs the ERO to perform whatever research it and the industry believe is 

necessary to provide a sound technical basis for either continuing with the present 

practice or identifying an alternative practice that is more effective and helps reduce 

inadvertent interchange. 

386. The Commission agrees with MISO regarding the number of time error 

corrections using WECC’s procedure. However, the magnitude of the frequency change 

 184 See W.R. Prince, et al., Cost Aspects of AGC, Inadvertent Energy and Time 

Error, IEEE Transactions on Power Systems, February 1990, at 111. 

185 NOPR at P 179, 183. 
Docket No. RM06-16-000 - 118 - 

in the WECC automatic time error correction is smaller than the manual correction and 

timing of the corrections are better correlated to when the error was created. These two 

characteristics of the WECC procedure avoid placing the system in less secure conditions 

and tie the payback to the initiating action, both of which appear to better serve both 

reliability and equity. 

f. Automatic Generation Control (BAL-005-0)

387. The 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. 

388. In the NOPR, the Commission proposed to approve Reliability Standard BAL005-0 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the 

FPA and § 39.5(f) of our regulations, the Commission proposed to direct NERC to 

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 additional Levels of NonCompliance 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.186

389. Further, the NOPR stated that the Commission is interested in knowing whether 

any balancing authority is experiencing or is predicting any difficulty in obtaining 

sufficient automatic generation control. 

i. Minimum Amount of Regulating Reserves

(a) Comments

390. South Carolina E&G and SMA support the Commission’s proposal to include a 

requirement that addresses minimum regulating reserves. It states that the control 

performance standard metric is a lagging indicator of necessary reserves and other 

standards such as frequency response may eventually provide a more dynamic real-time 

 186 NOPR at P 197. 
Docket No. RM06-16-000 - 119 - 

indicator. South Carolina E&G believes the Commission’s proposal provides a good 

interim solution. 

391. Alcoa comments that, in establishing a minimum amount of reserves, NERC 

should be required to consider the quality of each source of reserves. Alcoa suggests that 

digitally controlled DC loads, such as an aluminum smelter, could respond much more 

rapidly and accurately than thermal generators and that using such resources could 

reduce the response time for recovery, allowing thermal units to carry fewer spinning 

reserves and increasing operating efficiencies of the grid. 

392. NERC and other commenters187 suggest that the Commission’s proposed directive 

to have NERC include “Requirements that identify the minimum amount of automatic 

generation control or regulating reserves a balancing authority must have at any given 

time” is too prescriptive. They also object to this proposed requirement since a balancing 

authority’s failure to maintain sufficient regulating reserves will result in violations of 

control performance standard criteria already found in BAL-001-0. 

393. NERC further states that a requirement to have a minimum amount of regulating 

reserves would result in an arbitrary constraint that would not add to reliability and 

suggests that the Commission instead direct NERC to consider the issue of a minimum 

requirement in its Reliability Standards process in order to determine the reliability 

benefit. 

394. EEI states that the industry currently has no consensus-based, sound engineering 

methodology for determining a minimum regulating reserve requirement given widely 

varying needs throughout the country. Nonetheless, EEI offers several guidelines that it 

says could be used to provide estimates for minimum regulating reserves. Similarly, 

MidAmerican states that normal regulating margins can vary from one balancing 

authority to another, and even within one balancing authority, due to frequently changing 

load characteristics making it extremely difficult to quantify an hourly required level of 

reserves. MidAmerican suggests that instead of prescriptively quantifying reserve levels, 

the ERO should continue to allow the industry to find efficient ways to comply with the 

control performance standards of BAL-001-0. 

395. FirstEnergy suggests that a single entity should have the responsibility to establish, 

through an annual review process, the level of regulating reserves that a balancing 

authority must maintain pursuant to the control performance standard requirements. 

 187 See APPA, EEI, International Transmission, MISO-PJM, MidAmerican and 

LPPC. 
Docket No. RM06-16-000 - 120 - 

FirstEnergy suggests that all generators and technically qualified DSM that participate in 

energy markets should install automatic generation control as a condition of market 

participation. In non-market areas, FirstEnergy suggests that balancing authorities could 

meet requirements through bilateral contracts or the normal scheduling process and 

suggests that the Commission might have to assert its jurisdiction and order technically 

qualified DSM providers to install automatic generation control at their facilities. 

FirstEnergy states that further work would need to be conducted on the technical 

qualifications and capacity thresholds that would control whether installation of 

automatic generation control would be required. 

(b) Commission Determination

396. On this issue, the Commission directs the ERO to modify BAL-005-0 through the 

Reliability Standards development process to develop a process to calculate the minimum 

regulating reserve for a balancing authority, taking into account expected load and 

generation variation and transactions being ramped into or out of the balancing authority. 

397. As a general matter, the Commission believes that a single entity should establish 

the level of regulating reserve required based on the generation mix and ramping rates in 

the region. We disagree with commenters that minimum regulating reserve requirements 

are not necessary. As South Carolina E&G correctly points out, the control performance 

standard metric is a lagging indicator and, as such, does not provide a good indication 

that the necessary amounts of regulating reserve are being carried at all times. The 

Commission notes that Requirement R2 requires maintenance of a level of regulating 

reserves in order to prospectively meet the control performance standard but does not 

provide a calculation for the exact level which would be required. In particular, the 

Commission believes that, while the control performance standard metric is useful in 

identifying trends relating to poor regulating practices, specification of minimum reserve 

requirements to be maintained at all times would complement the control performance 

standard metrics by providing real-time requirements necessary for proper control. 

398. With regard to Alcoa’s comment, the Commission agrees that the quality of 

reserves is relevant in determining if the resource is able to technically qualify as 

regulation. 

399. Nevertheless, the Commission recognizes commenters’ concerns related to the 

calculation of minimum regulation. EEI has offered several possible methods to 

calculate the minimum amount of regulation needed for reliability, which may or may not 

be consistent with others in the industry. The fundamental reason for regulating reserves 

is to balance load and generation in the short term due to the random variations in the 

balancing authorities’ loads and to accommodate ramping of transactions. The 

Commission therefore directs the ERO to develop a process to calculate the minimum 
Docket No. RM06-16-000 - 121 - 

regulating reserve for a balancing authority, taking into account expected load and 

generation variation and transactions being ramped into or out of the balancing authority. 

ii. Title Change and Inclusion of DSM.

(a) Comments

400. As an initial matter, many commenters express confusion about the Commission’s 

proposal to require NERC to change the title of the Reliability Standard to be neutral as 

to the source of the reserves, and include DSM and direct control load management as 

part of contingency reserves.188 In particular, these commenters argue that this 

Reliability Standard pertains to regulating reserve and not contingency reserves. 

401. Constellation agrees with the Commission that DSM and direct control load 

management should be included as viable options for regulating reserves.189 

MidAmerican agrees with the Commission on the proposed title change to allow it to be 

neutral as to the source of reserves but cautions the Commission on including DSM as a 

source of contingency reserves. While MidAmerican believes it proper to include direct 

control load management, which is under direct control of the system operator in 

contingency reserves, it states that the term DSM (as defined in the NERC glossary) is 

too general and includes programs that cannot contribute toward contingency reserves. 

402. APPA and International Transmission both disagree with the Commission’s 

proposals to change the title of this Reliability Standard and to include DSM and direct 

control load management. APPA suggests that DSM and direct control load management 

are not operationally equivalent to dispatchable generation resources and does not believe 

these programs are an effective source of regulating reserve given the current state of 

technology. International Transmission simply states that regulating reserves required by 

BAL-005-0 are specifically responsive to automatic generation control. 

403. ISO-NE disagrees with the Commission’s proposal to include DSM and direct 

control load management as part of this service, stating that responsive load has not 

demonstrated the load following capability necessary to provide regulation and that it is 

not aware of any load-based resources that can closely follow automatic generation 

 188 EEI, TVA, International Transmission, Multiple Interveners, MISO-PJM, 

South Carolina E&G and Wisconsin Electric. 

189 Since the Commission used the term “contingency reserves” inappropriately in 

this section, we assume that Constellation intended this to be regulating reserves. 
Docket No. RM06-16-000 - 122 - 

control signals sent every four seconds. As an alternative to the Commission’s approach, 

ISO-NE suggests that the Reliability Standard should define the reliability purpose or 

objective and then be resource-neutral. 

(b) Commission Determination

404. At the outset, the Commission agrees with commenters that this Reliability 

Standard applies to regulating reserves and not contingency reserves. The references to 

contingency reserves under this Reliability Standard in the NOPR are confusing. The 

Commission clarifies that its direction to the ERO in this section is for it to develop a 

modification to BAL-005-0 through the Reliability Standards development process that 

changes the title of the Reliability Standard to be neutral as to the source of regulating 

reserves and allows the inclusion of technically qualified DSM and direct control load 

management as regulating reserves, subject to the clarifications provided in this section. 

405. We disagree that it is not possible to use DSM and direct control load management 

as a source of regulating reserves or any other type of operating reserves. The 

Commission notes that, while DSM and direct control load management may not be 

widely used today as a source of operating reserves, comments received and other 

evidence suggest that certain types of loads are technically capable of providing this 

service. For example, comments received from Alcoa suggest that certain loads, such as 

digitally controlled DC loads, are capable of responding much faster than generation to a 

reserve need. 

406. Given that most of the commenters’ concerns over the inclusion of DSM as part of 

regulating reserves relate to the technical requirements, the Commission clarifies that to 

qualify as regulating reserves, these resources must be technically capable of providing 

the service. In particular, all resources providing regulation must be capable of 

automatically responding to real-time changes in load on an equivalent basis to the 

response of generation equipped with automatic generation control. From the examples 

provided above, the Commission understands that it may be technically possible for DSM 

to meet equivalent requirements as conventional generators and expects the Reliability 

Standards development process to provide the qualifications they must meet to 

participate. These qualifications will be reviewed by the Commission when the revised 

Reliability Standard is submitted to the Commission for approval. 
Docket No. RM06-16-000 - 123 - 

iii. Whether Balancing Authorities are Experiencing or 

Predicting Difficulty in Obtaining Sufficient 

Automatic Generation Control

(a) Comments

407. Constellation states that its ability to obtain regulating reserves is hampered by a 

lack of resources that qualify as regulation and the practices that some transmission 

service providers have adopted in implementing dynamic transfers needed to procure 

regulating reserves from other balancing authorities. In particular, Constellation states 

that many transmission service providers impose a requirement that regulation services 

must be provided using firm transmission. Constellation suggests that purchasing 

regulation from another balancing authority using non-firm transmission service is 

allowed under the Reliability Standards and that Requirement R5 of BAL-005-0 provides 

that balancing authorities must have back-up plans to provide replacement regulation 

service if the purchased regulation service is lost. Constellation requests that the 

Commission clarify that the transmission providers may not impose a requirement to rely 

exclusively on firm transmission for the dynamic transfers of regulating reserves. 

(b) Commission Determination

408. In response to Constellation’s concerns, the Commission notes that, if regulation is 

being provided over non-firm transmission service, the entity receiving the regulation 

should be responsible for having a back-up plan to include loss of the non-firm 

transmission service as referenced in Requirement R5. The Commission believes that a 

balancing authority may use non-firm transmission service for procuring regulation, so 

long as that balancing authority has a back-up plan that it can implement to include loss 

of non-firm transmission service. 

iv. Other Comments 

(a) Comments

409. MISO states that it is uncertain of the basis of the claim that there have been an 

increased number of “[automatic generation control] controllable” frequency 

excursions.190 MISO further states that data in the Eastern Interconnection shows the 

number of larger-slower excursions has decreased over the past few years. 

 190 NOPR at P 194. 
Docket No. RM06-16-000 - 124 - 

410. Xcel requests that the Commission reconsider Requirement R17 of this Reliability 

Standard stating that the accuracy ratings for older equipment (current and potential 

transformers) may be difficult to determine and may require the costly replacement of 

this older equipment on combustion turbines and older units while adding little benefit to 

reliability. Xcel states that the Commission should clarify that Requirement R17 need 

only apply to interchange metering of the balancing area in those cases where errors in 

generating metering are captured in the imbalance responsibility calculation of the 

balancing area. 

411. FirstEnergy states that Requirement R17 should include only “control center 

devices” instead of devices at each substation. FirstEnergy states that accuracy at the 

substation level is unnecessary and the costs to install automatic generation control 

equipment at each substation would be high. FirstEnergy also states that the term 

“check” in Requirement R17 needs to be clarified. 

412. California Cogeneration states that the Commission has previously ruled that 

separate metering for the gross generation of a customer-owned generator is not proper or 

necessary, and states that the Commission should clarify that this Reliability Standard 

does not establish metering requirements for individual generators, and does not allow 

separate metering of generation and load on an end-user’s site.191 

413. LPPC notes that BAL-005-0 has 17 requirements but no Measures, and that it uses 

phrases such as “adequate metering” and “burden on the interconnection.” LPPC 

contends that there is no definition for these ambiguous terms and that there is no way to 

determine if terms like “adequate metering” will mean the same thing in different parts of 

the country or ensure consistent penalties will be assessed for the same violation. 

(b) Commission Determination

414. The Commission agrees with MISO that, while the number of frequency 

deviations due to loss of generation has decreased, the Commission is concerned with the 

implications of the actual data presented by PJM that shows two frequency deviations 

each week day without the loss of generation.192 This concern is supplemented by 

 191 See California Cogeneration at 6, citing California Independent System 

Operator Corp., Opinion No. 464, 104 FERC ¶ 61,196 (2003). 

192 NOPR at n.134. 
Docket No. RM06-16-000 - 125 - 

documents that identify that some balancing authorities are restricting automatic 

generation control actions during schedule changes.193 

415. Both Xcel and FirstEnergy question Requirement R17 but do not oppose the 

Commission’s proposal to approve this Reliability Standard. Earlier in this Final Rule, 

we direct the ERO to consider the comments received to the NOPR in its Reliability 

Standards development process. Thus, the comments of Xcel and FirstEnergy should be 

addressed by the ERO when this Reliability Standard is revisited as part of the ERO’s 

Work Plan. 

416. California Cogeneration requests clarification that Commission rulings made prior 

to the enactment of FPA section 215 would still be applicable. The case cited by 

California Cogeneration was issued before EPAct 2005 was enacted and gave the 

Commission direct responsibility over Bulk-Power System reliability. By its terms, 

BAL-005-0 requires each generator operator with generating facilities operating within 

an Interconnection to ensure that those generating facilities are included within the 

metered boundaries of a balancing authority area. Therefore, any generator that is subject 

to the Reliability Standards, as discussed in the Applicability Issues section of this Final 

Rule,194 is subject to the metering requirements in this Reliability Standard. Our 

conclusion, however, does not determine the appropriate ratemaking treatment. 

417. With respect to LPPC’s concern that terms used in the Reliability Standard are not 

definitive when viewed individually, and LPPC’s statement that the Reliability Standard 

is ambiguous because it does not include Measures, we disagree. The Commission finds 

each Requirement of BAL-005-0 is clear and enforceable. The Requirements provide 

sufficient guidance for an entity to understand its obligations. When Measures are 

incorporated into the Reliability Standard, the Measures will provide guidance on 

assessing non-compliance with the Requirements. For these reasons and as previously 

addressed in the NOPR, the Commission disagrees that the enforceable obligations set 

forth in Requirements are unclear absent Measures. 

418. The Commission notes that no one commented on the proposal to include 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 

 193 See R. L. Vice, Frequency Issues 2005, available at: 

http://www.wecc.biz/documents/library/RITF/Frequency_Issues_2005_rev_0.pdf 

194 See Applicability Issues: Bulk-Power Ststem v. Bulk Electric System and 

Applicability to Small Entities, supra sections II.C.1-2. 
Docket No. RM06-16-000 - 126 - 

balancing authority maintains. The Commission adopts the NOPR proposal to require 

the ERO to modifiy the Reliability Standards to include a Measure that provides for a 

verification process over the minimum required automatic generation control or 

regulating reserves a balancing authority maintains. However, as discussed in the 

Common Issues section of this Final Rule, we will leave it to the discretion of the ERO 

whether to include other Measuers.195

419. FirstEnergy has a number of suggestions to improve the existing Reliability 

Standard and the ERO is directed to consider those suggestions in its Reliability 

Standards development process. 

v. Summary of Commission Determinations

420. The Commission approves 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 directs the ERO to develop a modification to BAL-002-0 

through the Reliability Standards development process that: (1) develops a process to 

calculate the minimum regulating reserve a balancing authority must have at any given 

time taking into account expected load and generation variation and transactions being 

ramped into or out of the balancing authority; (2) changes the title of the Reliability 

Standard to be neutral as to the source of regulating reserves and to allow the inclusion of 

technically qualified DSM and direct control load management; (3) clarifies Requirement 

R5 of this Reliability Standard to specify the required type of transmission or backup 

plans when receiving regulation from outside the balancing authority when using nonfirm service and (4) includes Levels of Non-Compliance and a Measure that provides for 

a verification process over the minimum required automatic generation control or 

regulating reserves a balancing authority must maintain. 

g. Inadvertent Interchange (BAL-006-1)

421. BAL-006-1 requires that each balancing authority calculate and record inadvertent 

interchange on an hourly basis. 

422. In the NOPR, the Commission proposed to approve Reliability Standard BAL006-1 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the 

FPA and § 39.5(f) of our regulations, the Commission proposed to direct that NERC 

submit a modification to BAL-006-1 that adds Measures and additional Levels of Non-

 195 See Common Issues Pertaining to Reliability Standards: Measures and Levels 

of Non-Compliance, supra section II.E.2. 
Docket No. RM06-16-000 - 127 - 

Compliance including Measures concerning the accumulation of large inadvertent 

imbalances.196 

423. In addition, the NOPR solicited comment on whether accumulation of large 

amounts of inadvertent imbalances is a concern to the industry and if so, options to 

address the accumulation. 

i. Measures and Additional Levels of NonCompliance Including Measures Concerning the 

Accumulation of Large Inadvertent Imbalances

(a) Comments

424. Certain commenters197 do not support the Commission’s proposal to add Measures 

and additional Levels of Non-Compliance, including Measures concerning the 

accumulation of large inadvertent imbalances. Xcel states that such a measure would not 

enhance reliability and involves primarily a commercial matter. MRO suggests that large 

inadvertent balances are an equity issue and as such should be addressed through 

business practices and not through the Reliability Standards. MidAmerican states that no 

additional measures addressing inadvertent imbalances are needed in this Reliability 

Standard because the issue is adequately addressed in other Reliability Standards.198 

MidAmerican states that if the Commission proceeds to require Measures and Levels of 

Non-Compliance for large accumulations, it must insure that no “double penalties” are 

imposed. 

425. EEI believes that the need to set a Measure for the accumulation of large 

inadvertent imbalances may be premature. EEI suggests that inadvertent energy is not a 

problem in real-time operations and is the result of frequency over-bias. EEI further 

states that if the Commission believes the industry should address both inadvertent 

energy and frequency bias, the clear consequence is a fundamental reconsideration of the 

 196 NOPR at P 212. 

197 Xcel, MRO, MidAmerican and MISO-PJM. 

198 MidAmerican explains that large interchange imbalances are a result of 

telemetry failures, AGC misoperation or scheduling errors and further states that BAL001 addresses AGC performance and the INT standards handle compliance with 

scheduling requirements. 
Docket No. RM06-16-000 - 128 - 

control performance standard. EEI strongly recommends that the Commission clarify 

whether it intends for the industry to reconsider this fundamental reliability principle. 

426. Constellation states some concern regarding the ability of balancing authorities to 

make appropriate arrangements to settle inadvertent imbalances. In particular, 

Constellation states that in arranging bilateral paybacks, it is difficult to find a 

counterparty with an opposite balance and there are transmission fees that further hinder 

the process of these paybacks. Constellation states that the Commission should require 

the industry to adopt procedures that will better facilitate bilateral payback of inadvertent 

energy, such as waiving the scheduling requirement for small bilateral paybacks (such as 

WECC has implemented). 

427. TAPS repeats the arguments it made in its comments on the Staff Preliminary 

Assessment that the existing treatment of balancing authority inadvertent interchange is 

not comparable to the treatment of energy imbalances. TAPS suggests that the 

Commission has an obligation to do more than what is proposed in the NOPR, which 

states that the issue is being addressed in the OATT reform docket199 while approving 

Reliability Standards that perpetuate the preferential treatment of balancing authority 

inadvertent interchange.200

(b) Commission Determination

428. The Commission directs the ERO to develop a modification to BAL-006-1 that 

adds Measures concerning the accumulation of large inadvertent imbalances and Levels 

of Non-Compliance. While we agree that inadvertent imbalances do not normally affect 

the real-time operations of the Bulk-Power System and pose no immediate threat to 

reliability, we are concerned that large imbalances represent dependence by some 

balancing authorities on their neighbors and are an indication of less than desirable 

balancing of generation with load. The Commission also notes that the stated purpose of 

this Reliability Standard is to define a process for monitoring balancing authorities to 

ensure that, over the long term, balancing authorities do not excessively depend on other 

balancing authorities in the Interconnection for meeting their demand or interchange 

obligations. 

429. The Commission disagrees with MidAmerican that having Measures in this 

Reliability Standard will result in double penalties. The Commission believes that this 

 199 OATT Reform NOPR at P 208. 

200 NOPR at P 206. 
Docket No. RM06-16-000 - 129 - 

Reliability Standard has an independent reliability goal that “define[s] a process for 

monitoring balancing authorities to ensure that, over the long term, balancing authorities 

do not excessively depend on other balancing authority areas in the Interconnection for 

meeting their demand or interchange obligations.”201 

430. The Commission agrees with EEI that one of the root causes of inadvertent 

interchange is the difference between the actual frequency response and the existing bias 

settings. The Commission has directed that this cause be addressed in other BAL 

Reliability Standards. If the industry wishes to propose alternative metrics to the control 

performance Reliability Standards, the Commission suggests that it does so through the 

ERO processes and that such changes include an explanation of how the revised metrics 

would better measure the ability of an individual balancing authority to match load and 

generation. 

431. In response to Constellation’s comment about the fees associated with the 

settlement of inadvertent imbalances, the Commission notes that this issue relates to 

business practices and should be brought before NAESB or otherwise addressed in 

contexts other than section 215 of the FPA. 

432. With respect to TAPS’ concerns regarding disparate treatment of imbalances for 

non-control area utilities, the Commission is not convinced that this is a reliability issue. 

As identified in Order No. 890, inadvertent interchange is not comparable to 

imbalances.202 

433. Accordingly, the Commission adopts the proposal in the NOPR to direct the ERO 

to develop Measures under this Reliability Standard to ensure balancing authorities will 

not have large inadvertent imbalances. 

ii. Whether the Accumulation of Large Amounts of 

Inadvertent Imbalances is a Concern and Potential 

Options

(a) Comments

434. LPPC states that its members are concerned that large inadvertent imbalances 

would be an indication of an underlying issue related to overall balancing of resources 

 201 See BAL-006-1 (Inadvertent Interchange, Purpose Statement). 

202 See Order No. 890 at P 702-03. 
Docket No. RM06-16-000 - 130 - 

and demand and suggests that options to address these large inadvertent imbalances 

should be addressed through the Reliability Standards development process. 

435. NERC states that the performance requirements that relate to reliability are 

addressed in BAL-001-0 and BAL-002-0 and the new Reliability Standards which will 

replace them. Further, NERC states that if the Commission wishes to direct 

consideration of limits on the amount of inadvertent imbalances, such directive should be 

in the form of an issue to be resolved or reliability objective to be achieved rather than a 

specific requirement to set a fixed limit on inadvertent accumulation. 

436. TVA, MISO and MidAmerican state that the accumulation of large inadvertent 

balances over time does not raise grid reliability issues. TVA asserts that this is largely a 

financial matter. In addition, TVA comments that if a balancing authority inappropriately 

uses the interconnection in a way which results in a large inadvertent imbalance this 

behavior should be reflected in the balancing authority’s control performance standard 

compliance. MISO states that some large amounts of inadvertent imbalance are due to a 

balancing authority fulfilling its bias obligation. MISO states that an arbitrary cap should 

not be a part of this Reliability Standard. 

(b) Commission Determination

437. As stated previously, while the Commission agrees that these imbalances do not 

present an immediate reliability problem, we believe, as stated by LPPC, that large 

interchange imbalances are indicative of an underlying problem related to balancing of 

resources and demand. It would be worthwhile for the ERO to examine the WECC time 

error correction procedure. 

438. Since the ERO indicates that the reliability aspects of this issue will be addressed 

in a Reliability Standards filing later this year, the Commission asks the ERO, when 

filing the new Reliability Standard, to explain how the new Reliability Standard satisfies 

the Commission’s concerns. 

iii. Summary of Commission Determinations

439. Accordingly, the Commission approves 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 directs the ERO to develop a modification to 

BAL-006-1 through the Reliability Standards development process that includes 

Measures concerning the accumulation of large inadvertent imbalances and additional 

Levels of Non-Compliance. 
Docket No. RM06-16-000 - 131 - 

h. Regional Differences to BAL-006-1: Inadvertent 

Interchange Accounting and Financial Inadvertent 

Settlement

440. The NOPR explained that BAL-006-1 provides for two regional differences.203 

First, a regional difference is provided 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 

locational marginal pricing could be implemented to meet their Commission directed 

market obligations. Subsequently, Southwest Power Pool (SPP) requested, and NERC 

approved, the same regional difference for.204

441. Second, the NOPR explained that a regional difference would apply to the control 

area participants of MISO and SPP that would allow each 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 therefore accumulation of net-interchange would not affect 

the non-participant control areas. 

442. The Commission proposed to approve these regional differences, explaining that 

the two proposed regional differences relate solely to facilitating financial settlements of 

accumulated inadvertent interchange due to the physical differences of these areas and 

have minimal, if any, reliability implications. 

i. Comments

443. FirstEnergy notes that the two proposed regional differences reference the Version 

0 policies instead of the NERC Reliability Standards and requests that the Commission 

direct NERC to revise the regional differences accordingly. In addition, FirstEnergy 

states that the Commission should direct NERC to define the function of a waiver. 

FirstEnergy agrees that transferring responsibility for the tasks under these waivers to the 

RTO is appropriate. 

 203 NOPR at P 216. 

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

SPP. 
Docket No. RM06-16-000 - 132 - 

ii. Commission Determination

444. No commenter objected to the regional differences to BAL-006-1. However, the 

Commission agrees with FirstEnergy that the regional differences incorrectly reference 

retired policy terminology. Therefore, the Commission approves the regional differences 

as mandatory and enforceable under Order No. 672 as necessary due to the physical 

differences between multiple balancing authorities and a single market205 but the 

Commission directs the ERO to modify the regional differences so that they reference the 

current Reliability Standards and are in the standard form, which includes Requirements, 

Measures and Levels of Non-Compliance. The ERO should explore FirstEnergy’s 

request to define the function of a waiver in its Reliability Standards development 

process. 

2. CIP: Critical Infrastructure Protection

445. The goal of CIP-001-1 is to ensure that operating entities recognize sabotage 

events and inform appropriate authorities and each other to properly respond to the 

sabotage to minimize the impact on the Bulk-Power System.206 The Reliability Standard 

requires that each reliability coordinator, balancing authority, transmission operator, 

generation operator and LSE have procedures for recognizing and for making operating 

personnel aware of sabotage events, and communicating information concerning sabotage 

events to appropriate “parties” in the Interconnection.207 

446. In the NOPR, the Commission proposed to approve Reliability Standard CIP-001-

0 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA 

and § 39.5(f) of our regulations, the Commission proposed 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 

 205 Order No. 672 at P 291. 

206 The NOPR addressed CIP-001-0. On November 15, 2006, NERC submitted 

for approval proposed Reliability Standard CIP-001-1, which revised and replaced the 

previous version of the Reliability Standard to include Measures and Levels of NonCompliance. 

207 On August 28, 2006, NERC submitted for approval proposed Reliability 

Standards CIP-002-1 through CIP-009-1. These proposed Reliability Standards, which 

relate to cybersecurity, are being addressed in a separate rulemaking proceeding in 

Docket No. RM06-22-000. 
Docket No. RM06-16-000 - 133 - 

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. 

447. In the NOPR, the Commission explained that the Requirements of CIP-001-0 refer 

to a “sabotage event” but do not define that term. The Commission stated that, while 

“sabotage” is a commonly understood term and the common understanding should 

suffice in most circumstances, it was concerned that situations may arise in which it is not 

clear whether action pursuant to CIP-001-0 is required. Thus, the NOPR proposed that 

the ERO provide guidance clarifying the triggering event for an entity to take action 

pursuant to CIP-001-0. 

a. Comments

448. EEI and Entergy comment that they generally agree with the Commission’s 

perspective. While APPA and Six Cities support approving CIP-001-1 as mandatory and 

enforceable, they ask that the Commission defer the application of monetary penalties 

until further guidance is provided on what events are reportable and what steps an entity 

must take to be certain it is in compliance with the Reliability Standard. Claiming that 

CIP-001-1 is too vague to be enforceable, TAPS opposes approval until NERC has 

further defined “sabotage” and the facilities to which the Reliability Standard applies. 

449. APPA questions whether CIP-001-1 should apply to LSEs (LSEs) contending that, 

unlike transmission owners and generators, LSEs do not own or operate “hard assets” that 

are normally thought of “at risk” to sabotage. It claims that compliance would be 

particularly burdensome for small LSEs, such as the requirement to provide a preliminary 

report within one hour of an event. APPA states that NERC should therefore reconsider 

whether LSEs should be required to comply with this Reliability Standard. Further, 

while APPA supports the application of CIP-001-1 to larger generators and any unit 

required for reliable interconnected operations, it questions whether it is critical to extend 

the Reliability Standard to all generator operators – noting that there are 3,564 generating 

plants in the United States with a total capacity of 75 MW or less. APPA contends that 

the incremental benefits of requiring all generators to comply with CIP procedures seem 

minimal since many facilities are unlikely to have a material impact on Bulk-Power 

System reliability or be a target for sabotage in the first place. APPA suggests that the 

Commission defer action on CIP-001-1 while it implements a prioritization plan. 

450. TAPS and California Cogeneration are also concerned about applicability and 

contend that compliance should be limited to those that have a significant or material 

impact on Bulk-Power System reliability. Both are concerned that compliance with this 

Reliability Standard would create significant administrative burdens and documentation 

requirements that are not justified where a facility does not have a material impact on the 
Docket No. RM06-16-000 - 134 - 

Bulk-Power System. California Cogeneration suggests that CIP-001-1 be revised to: 

(1) exclude generator output used on-site and (2) provide a mechanism for determining 

that a facility has no material impact and thus is exempt from compliance. 

451. A number of commenters agree with the Commission’s concern that the term 

“sabotage” needs to be better defined and guidance provided on the triggering events that 

would cause an entity to report an event.208 FirstEnergy states that this definition should 

differentiate between cyber and physical sabotage and should exclude unintentional 

operator error. It advocates a threshold of materiality to exclude acts that do not threaten 

to reduce the ability to provide service or compromise safety and security. SoCal Edison 

states that clarification regarding the meaning of sabotage and the triggering event for 

reporting would be helpful and prevent over-reporting. 

452. APPA comments that Requirement R1 of CIP-001-1, which provides that an entity 

must have procedures for recognizing sabotage events and making its personnel aware of 

sabotage events, while a “good first step,” lacks sufficient detail upon which the ERO can 

base compliance and enforcement efforts. It characterizes CIP-001-1 as an “entityspecific ‘fill-in-the-blank’ standard” that does not provide sufficient direction or guidance 

for an entity to determine whether it is in compliance. APPA further states that Measure 

M1 provides no criteria for a Regional Entity, acting in its capacity as a compliance 

monitor, to make an objective determination that an entity’s sabotage procedure is 

adequate. 

453. In response to the Commission’s concern regarding the need for periodic review of 

sabotage response procedures, FirstEnergy suggests that CIP-001-1 should define what 

time period is sufficient for periodic reviews and suggests that a bi-annual review would 

be appropriate. MRO believes that a requirement to annually review the sabotage 

response procedures should be added to the Reliability Standard. 

454. NERC objects to the wording of the Commission’s proposed directive that NERC 

modify CIP-001-1 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. NERC states the Commission’s directive is overly 

prescriptive because it specifies language to be included in the standard and thereby 

circumvents the Reliability Standards development process. Further, NERC objects that 

this directive would require entities in other nations such as Canada or Mexico to report 

to the U.S. Department of Homeland Security. Santa Clara suggests that Requirement R4 

(and corresponding measure M3) should be modified to state that “...contacts should be 

 208 See, e.g., APPA, FirstEnergy, SoCal Edison, Six Cities and TAPS. 
Docket No. RM06-16-000 - 135 - 

established with the appropriate public safety officials or directly with the local Federal 

Bureau of Investigation (FBI) or Royal Canadian Mounted Police (RCMP) such that 

communication channels are established to report incidents to the appropriate authority.” 

It states that, in the case of a municipal utility that is part of a local governmental agency 

that already has a public safety department which is in regular contact with the local FBI, 

and where clear communication channels already exist between the public safety 

department and the utility, it would be redundant for the utility to establish a direct link to 

the FBI for reporting purposes. Xcel also suggests that the term “appropriate federal 

authorities” should be modified to avoid conflict with established processes now in place, 

and that the term should be specifically identified so the Requirements on affected 

entities are clear. 

455. Process Electricity Committee advocates approval of CIP-001-0 as initially 

proposed by NERC without modification, but it objects to the revised CIP-001-1 as 

placing an undue burden on smaller entities. It is concerned that the Commission’s 

proposal to require mandatory reporting to appropriate federal authorities within a 

specific time frame will impose substantial burdens on end users with little or no 

discernable benefit. It states that there is no evidence that any entities – both regulated 

and unregulated – under-report sabotage events. Further, according to Process Electricity 

Committee, the adoption of uniform requirements could require end users to modify 

existing security programs and procedures that are designed to protect industrial facilities, 

whereas the utility generator requirements could be conflicting or duplicative. 

456. Entergy and FirstEnergy express concern that there is a potential for redundancy 

between CIP-001-1 and other related federal reporting standards. Entergy states that 

NERC should consider ensuring that CIP-001-1 is consistent with, but not duplicative of, 

these other requirements. FirstEnergy states that both the Department of Energy (DOE) 

and the Energy Information Administration (EIA) impose reporting requirements that are 

similar to CIP-001-1 and suggests that to avoid conflicts the reporting requirements under 

this Reliability Standard should be conformed to the existing DOE and EIA requirements. 

It also states that nuclear units have their own set of operating requirements, including 

procedures for reporting sabotage, and suggests that a company’s compliance with NRC 

procedures should be presumed to meet NERC standards. EEI, FirstEnergy and Xcel 

suggest greater coordination, possibly with all events being reported to NERC, which 

would then coordinate with federal authorities. Xcel suggests the development of a 

single sabotage reporting form to streamline the reporting process and make it easier for 

affected entities to provide reports in a timely manner. 

457. APPA and FirstEnergy express concern about a requirement to report an act of 

sabotage within a fixed period of time. Xcel states that the triggering event for disclosure 

of an act of sabotage often will be unclear and that an investigation will take time 

especially if the event occurs at an unstaffed or remote facility. Thus, Xcel does not 
Docket No. RM06-16-000 - 136 - 

believe that the standard should contain an express time limit for reporting an act of 

sabotage since the amount of time necessary to make that report may vary depending on 

the circumstances. FirstEnergy suggests that CIP-001-1 should define the specified 

period for reporting an incident beginning from when the event is discovered or 

suspected to be sabotage. APPA is also concerned that a specific time limit for a report 

(such as a 60 minute requirement) would be burdensome to meet for a small LSE that is 

not continuously staffed when a triggering event occurs outside staffed hours. 

b. Commission Determination

i. Applicability to Small Entities

458. The Commission acknowledges the concerns of the commenters about the 

applicability of CIP-001-1 to small entities and has addressed the concerns of small 

entities generally earlier in this Final Rule. Our approval of the ERO Compliance 

Registry criteria to determine which users, owners and operators are responsible for 

compliance addresses the concerns of APPA and others. 

459. However, the Commission believes that there are specific reasons for applying this 

Reliability Standard to such entities, as discussed in the NOPR. APPA indicates that 

some small LSEs do not own or operate “hard assets” that are normally thought of as “at 

risk” to sabotage. The Commission is concerned that, an adversary might determine that 

a small LSE is the appropriate target when the adversary aims at a particular population 

or facility. Or an adversary may target a small user, owner or operator because it may 

have similar equipment or protections as a larger facility, that is, the adversary may use 

an attack against a smaller facility as a training “exercise.” The knowledge of sabotage 

events that occur at any facility (including small facilities) may be helpful to those 

facilities that are traditionally considered to be the primary targets of adversaries as well 

as to all members of the electric sector, the law enforcement community and other critical 

infrastructures. 

460. For these reasons, the Commission remains concerned that a wider application of 

CIP-001-1 may be appropriate for Bulk-Power System reliability. Balancing these 

concerns with our earlier discussion of the applicability of Reliability Standards to 

smaller entities, we will not direct the ERO to make any specific modification to CIP001-1 to address applicability. However, we direct the ERO, as part of its Work Plan, to 

consider in the Reliability Standards development process, possible revisions to CIP-001-

1 that address our concerns regarding the need for wider application of the Reliability 

Standard. Further, when addressing such applicability issues, the ERO should consider 

whether separate, less burdensome requirements for smaller entities may be appropriate 

to address these concerns. 
Docket No. RM06-16-000 - 137 - 

ii. Definition of Sabotage

461. Several commenters agree with the Commission’s concern that the term 

“sabotage” should be defined. For the reasons stated in the NOPR, we direct that the 

ERO further define the term and provide guidance on triggering events that would cause 

an entity to report an event.209 However, we disagree with those commenters that suggest 

the term “sabotage” is so vague as to justify a delay in approval or the application of 

monetary penalties. As explained in the NOPR, we believe that the term sabotage is 

commonly understood and that common understanding should suffice in most 

instances.210 Further, in the interim while the matter is being addressed by the Reliability 

Standards development process, we direct the ERO to provide advice to entities that have 

concerns about the reporting of particular circumstances as they arise. 

462. Further, in defining sabotage, the ERO should consider FirstEnergy’s suggestions 

to differentiate between cyber and physical sabotage and develop a threshold of 

materiality. However, regarding the latter suggestion, the Commission directs that 

guidance for a threshold of materiality must be designed carefully to mitigate the risk that 

an unsuccessful sabotage event is not correctly reported because it did not cause 

sufficient harm. 

iii. Procedures for Recognizing Sabotage Events

463. Requirement R1 of CIP-001-1 provides that an applicable entity must have 

procedures “for the recognition of and for making their operational personnel aware of 

sabotage events on its facilities and multi-site sabotage affecting larger portions of the 

Interconnection.” The NOPR expressed concern that the provision does not establish 

baseline requirements regarding what issues should be addressed by the developed 

procedures. APPA goes even further and, characterizing it as an entity specific fill-inthe-blank standard, contends that it lacks sufficient detail upon which the ERO can base 

compliance and enforcement efforts. 

464. While the Commission believes that this Reliability Standard can and should be 

enhanced by specifying baseline requirements regarding what issues should be addressed 

in the procedures for recognizing sabotage events and making personnel aware of such 

events, it disagrees with APPA that Requirement R1 lacks sufficient detail on which to 

 209 See NOPR at P 224. 

210 Id. at P 224, n.140, quoting a dictionary definition of “sabotage” as “destruction 

of property or obstruction of normal operations, as by civilians or enemy agents . . ..” 
Docket No. RM06-16-000 - 138 - 

base ERO compliance and enforcement efforts. As indicated in Measure M1, an 

applicable entity must have and maintain the procedure as defined by Requirement R1. 

Thus, if an applicable entity cannot provide the required procedure to the ERO or a 

Regional Entity auditor upon request, it would likely be subject to an enforcement action. 

While we expect that an applicable entity that has made a good faith effort to develop a 

meaningful procedure to comply with Requirement R1 (and Measure M1) would not be 

subject to an enforcement action, an ERO or Regional Entity audit team may provide 

steps to improve the individual entity’s procedure, which would serve as a baseline for 

that entity for any subsequent audit. Such an approach would be acceptable and allow for 

meaningful compliance in the interim until CIP-001-1 is modified pursuant to our 

directive. 

iv. Periodic Review of Sabotage Reporting Plans

465. The Commission was concerned that CIP-001-1 did not include a requirement for 

the periodic review or updating of sabotage reporting plans or procedures, or for the 

periodic testing of the sabotage reporting procedures to verify that they achieve the 

desired result.211 In response, FirstEnergy suggests that a bi-annual review would be 

appropriate and MRO believes that an annual review requirement should be added to the 

Reliability Standard. Periodic testing of the procedures through an exercise would assist 

in determining if the procedures are adequate for achieving the desired result. Lessons 

learned from these events would help in developing or modifying the sabotage reporting 

procedures. 

466. The Commission affirms the NOPR directive and directs the ERO to incorporate a 

periodic review or updating of the sabotage reporting procedures and for the periodic 

testing of the sabotage reporting procedures. At this time, the Commission does not 

specify a review period as suggested by FirstEnergy and MRO and, rather, believes that 

the appropriate period should be determined through the ERO’s Reliability Standards 

development process. However, the Commission directs that the ERO begin this process 

by considering a staggered schedule of annual testing of the procedures with 

modifications made when warranted formal review of the procedures every two or three 

years. 

v. Mandatory Reporting Of a Sabotage Event

467. CIP-001-1, Requirement R4, requires that each applicable entity establish 

communications contacts, as applicable, with the local FBI or Royal Canadian Mounted 

 211 NOPR at P 228. 
Docket No. RM06-16-000 - 139 - 

Police officials and develop reporting procedures as appropriate to its circumstances. 

The Commission in the NOPR expressed concern that the Reliability Standard does not 

require an applicable entity to actually contact the appropriate governmental or regulatory 

body in the event of sabotage. Therefore, the Commission proposed that NERC 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.”212 

468. As mentioned above, NERC and others object to the wording of the proposed 

directive as overly prescriptive and note that the reference to “appropriate federal 

authorities” fails to recognize the international application of the Reliability Standard. 

The example of the Department of Homeland Security as an “appropriate federal 

authority” was not intended to be an exclusive designation. Nonetheless, the 

Commission agrees that a reference to “federal authorities” could create confusion. 

Accordingly, we modify the direction in the NOPR and now direct the ERO to address 

our underlying concern regarding mandatory reporting of a sabotage event. The ERO’s 

Reliability Standards development process should develop the language to implement this 

directive. 

469. As noted above, FirstEnergy, EEI and others express concern regarding the 

potential for redundant reporting under CIP-001-1 and other government reporting 

standards, and the need for greater coordination. The Commission understands the 

concern about multiple reporting channels that may arise and the burden that this may 

present to applicable entities. We direct the ERO to explore ways to address these 

concerns – including central coordination of sabotage reports and a uniform reporting 

format – in developing modifications to the Reliability Standard with the appropriate 

governmental agencies that have levied the reporting requirements. 

470. The Commission stated that the reporting of a sabotage event should occur within 

a fixed period of time, and referred to a Homeland Security procedure that references a 

60-minute period for submitting a preliminary report and a follow-up report within four 

to six hours.213 While commenters raise a number of concerns about the need for fairness 

in the implementation of such a requirement, they do not challenge the NOPR’s 

underlying concern or the appropriateness of such a provision. The Commission believes 

that an applicable entity should report a sabotage event in a timely manner to allow 

government authorities and critical infrastructure members the opportunity to react in a 

 212 Id. at P 231. 

213 Id. at n.142. 
Docket No. RM06-16-000 - 140 - 

meaningful manner to such information. Thus, the Commission directs the ERO to 

modify CIP-001-1 to require an applicable entity to contact appropriate governmental 

authorities in the event of sabotage within a specified period of time, even if it is a 

preliminary report. The ERO, through its Reliability Standards development process, is 

directed to determine the proper reporting period. In doing so, the ERO should consider 

suggestions raised by commenters such as FirstEnergy and Xcel to define the specified 

period for reporting an incident beginning from when an event is discovered or suspected 

to be sabotage, and APPA’s concerns regarding events at unstaffed or remote facilities, 

and triggering events occurring outside staffed hours at small entities. 

c. Summary of Commission Determinations

471. As explained in the NOPR, while the Commission has identified concerns 

regarding CIP-001-1, 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. Accordingly, the Commission approves 

Reliability Standard CIP-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 directs the 

ERO to develop the following modifications to the Reliability Standard through the 

Reliability Standards development process: (1) further define sabotage and provide 

guidance as to the triggering events that would cause an entity to report a sabotage event; 

(2) specify baseline requirements regarding what issues should be addressed in the 

procedures for recognizing sabotage events and making personnel aware of such events; 

(3) incorporate a periodic review or updating of the sabotage reporting procedures and for 

the periodic testing of the sabotage reporting procedures and (4) require an applicable 

entity to contact appropriate governmental authorities in the event of sabotage within a 

specified period of time. In addition, we direct the ERO, as part of its Work Plan, to 

consider revisions to CIP-001-1 that address our concerns regarding applicability to 

smaller entities. The ERO should also consider consolidation of the sabotage reporting 

forms and the sabotage reporting channels with the appropriate governmental authorities 

to minimize the impact of these reporting requirements on all entities. 

3. COM: Communications 

472. The Communications (COM) group contains two Reliability Standards. The first 

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 

to address real-time emergencies and that operating personnel carry out effective 

communications. 
Docket No. RM06-16-000 - 141 - 

473. The NOPR contained a discussion of how the transmission operator and generator 

operator function would apply to RTO, ISO and pooled resource organizations. In this 

Final Rule, conclusions concerning those issues are covered in the Applicability Issues 

section.214 In essence, an organization may, but does not have to, accept compliance 

responsibility on behalf of its members. Since telecommunication is vital to the Reliable 

Operation of the Bulk-Power System, the Commission finds that it is not permissible to 

have either unnecessary overlaps or gaps in telecommunications. 

a. Telecommunications (COM-001-1)

474. COM-001-0215 seeks to ensure coordinated telecommunications among operating 

entities, which are fundamental to maintaining grid reliability. This proposed Reliability 

Standard establishes general telecommunications requirements for specific operating 

entities, including equipment testing and coordination. It also establishes English as the 

common language between and among operating personnel, and sets policy for using the 

NERCNet telecommunications system. COM-001-0 applies to transmission operators, 

balancing authorities, reliability coordinators and NERCNet user organizations. 

475. The Commission proposed to approve Reliability Standard COM-001-0 as 

mandatory and enforceable. In addition, the Commission proposed to direct that NERC 

submit a modification to COM-001-0 that: (1) includes Measures and Levels of NonCompliance; (2) includes generator operators and distribution providers as applicable 

entities and (3) includes Requirements for communication facilities for use during 

emergency situations. 

476. In addition, the Commission sought comments on specific requirements or 

performance criteria for telecommunications facilities, noting that COM-001-0 might be 

improved by providing specific requirements for adequacy, redundancy, diverse routing, 

and periodic testing. The Commission also sought comments on whether the relative 

roles of applicable entities should be considered when setting down requirements for 

telecommunication facilities, since the needs will vary based on role. 

 214 See Applicability Issues: Use of the NERC Functional Model, supra section 

II.C.4. 

215 In its November 15, 2006, filing, NERC submitted COM-001-1, which 

supercedes the Version 0 Reliability Standard. COM-001-1 adds Measures and Levels of 

Non-Compliance to the Version 0 Reliability Standard. In this Final Rule, we review the 

November version, COM-001-1. 
Docket No. RM06-16-000 - 142 - 

477. Most comments address the specific modifications and concerns raised by the 

Commission in the NOPR. Below, we address each topic separately, followed by a 

summary of our conclusions. 

i. Applicability to Generator Operators and 

Distribution Providers and their 

Telecommunications Facility Requirements 

478. The Commission stated in the NOPR that communications with generator 

operators and distribution providers are necessary to maintain system reliability during 

normal and emergency situations, while recognizing that telecommunication facility 

needs will vary between these two entities and other reliability entities such as reliability 

coordinators, transmission operators and balancing authorities. The Requirements for 

each of these entities will vary according to its respective roles. 

(a) Comments

479. EEI supports the goals stated by the Commission with regard to COM-001-1, in 

particular, the need to apply this Reliability Standard to distribution providers. TVA 

agrees with the Commission’s reasoning that generator operators and distribution 

providers should be subject to this Reliability Standard, but seeks clarification that such 

entities may transfer their responsibility for data sharing with and reporting to NERC and 

Regional Entities by contract to another entity. 

480. In contrast, MRO, APPA, TAPS and SDG&E indicate that applying this 

Reliability Standard to generator operators and distribution providers may not be 

appropriate. APPA argues generator operators and distribution providers do not affect 

the Bulk-Power System in the same manner as a reliability coordinator, balancing 

authority or transmission provider does, since generator operators and distribution 

providers only have a secondary or support role with respect to reliability of the BulkPower System. 

481. Further, APPA and SDG&E are concerned that the Commission’s proposal would 

unnecessarily subject generator operators and distribution providers to Requirements that 

were designed for transmission operators. For example, APPA indicates that NERCNet 

was designed as part of the NERC Interregional Security Network for communications 

among reliability coordinators, balancing authorities and transmission operators, and was 

not designed to connect generators to their balancing authorities and distribution 

providers to their transmission operators. Further, SDG&E submits that, while generator 

operators and distribution providers may logically have some role in enabling 

communications that help ensure reliability, SDG&E sees no basis for subjecting such 

entities to the same, extensive requirements incumbent on transmission operators. 
Docket No. RM06-16-000 - 143 - 

482. APPA argues that, while telecommunications Reliability Standards with generator 

operators and distribution providers as applicable entities may be needed, they are 

already subject to telecommunications requirements as part of their bilateral 

interconnection agreements with balancing authorities and transmission providers. It 

contends that if NERC deems it necessary, a separate Reliability Standard should be 

developed to govern telecommunications between balancing authorities and generator 

operators, and between transmission operators and distribution providers under their 

respective footprints. 

483. TAPS states that Requirement R1.4 has an ambiguous requirement216 that, if 

applied to distribution providers and generator operators, would impose redundancy 

requirements well beyond what is reasonably necessary for Bulk-Power System 

reliability. Further it asserts that the NOPR provides no basis for expanding the 

Reliability Standard to small entities, such as a 2-MW distribution provider or generator, 

much less than one that has no connection to the bulk transmission system. Finally, 

TAPS contends that, in making this proposal, the Commission is “over-stepping its 

bounds” by not leaving it to the ERO’s expert judgment whether COM-001-1 has 

sufficient coverage to protect Bulk-Power System reliability and states that, in any event, 

applicability should be limited through NERC’s registry criteria and definition of bulk 

electric system. 

484. MRO further states that applying this Reliability Standard to generator operators 

and distribution providers and including Requirements for communication facilities for 

use during emergency situations may also not be appropriate if the distribution provider 

does not operate its own systems. 

485. California PUC believes that the Commission’s assertion of authority to impose 

Reliability Standards applicable to either generator operators or distribution providers 

should be extremely limited, and should be based on an essential nexus between the 

proposed Reliability Standard and the operation of the Bulk-Power System. It contends 

that this aspect of the Commission’s proposed directive is duplicative and unnecessary 

when applied to entities in California, and risks being counterproductive unless applied 

with considerable restraint since California PUC’s Operation Standards require power 

plants to maintain the ability to communicate with the balancing authority at all times, 

and to plan for the continuity of communications during emergencies. 

 216 COM-001-1 Requirement R1.4 states: “Where applicable, these 

[telecommunications] facilities shall be redundant and diversely routed.” 
Docket No. RM06-16-000 - 144 - 

486. Process Electricity Committee agrees that the extent and maintenance of 

telecommunication facilities should vary based on the operator’s potential affect on 

system reliability. It points out that existing regulations and contractual obligations 

already require end users to maintain adequate communications facilities. Further, it 

states that on-site generation interconnected with the electricity grid typically is required 

to maintain sufficient telecommunications facilities between the generator owner or 

operator and the grid operator. In the absence of evidence that this arrangement is 

inadequate, Process Electricity Committee recommends that the amended COM 

Reliability Standards be clarified so that they do not impose new requirements on end 

users and other entities that have only minimal impact on the reliability of the 

interconnected transmission network. 

(b) Commission Determination

487. The Commission reaffirms its position that generator operators and distribution 

providers should be included as applicable entities in COM-001-1 to ensure there is no 

reliability gap during normal and emergency operations. For example, during a blackstart 

when normal communications may be disrupted, it is essential that the transmission 

operator, balancing authority and reliability coordinator maintain communications with 

their distribution providers and generator operators. However, the current version of 

Reliability Standard COM-001-1 does not require this because it does not include 

generator operators and distribution providers as applicable entities. We clarify that the 

NOPR did not propose to require redundancy on generator operators’ or distribution 

providers’ telecommunication facilities or that generator operators or distribution 

providers be trained on anything not related to their functions during normal and 

emergency conditions. We expect the telecommunication requirements for all applicable 

entities will vary according to their roles and that these requirements will be developed 

under the Reliability Standards development process. 

488. As stated in the Applicability Issues section of this Final Rule, entities may share 

responsibility for complying with Reliability Standards and the ERO’s registration 

process takes this into account.217 We believe that this satisfies TVA’s concern about 

data sharing and reporting responsibilities and MRO’s concern about applying this 

Reliability Standard to distribution providers only if they operate their own systems. 

489. The Commission agrees with APPA that the primary purpose of Requirement R6 

is to provide information to ensure reliable interregional operations and therefore should 

not apply to generator operators and distribution providers. However, we disagree that 

 217 See Applicability Issues: Applicability to Small Entities, supra section II.C.2. 
Docket No. RM06-16-000 - 145 - 

this leads to the conclusion that generator operators and distribution providers should not 

be included in COM-001-1. As we have stated, telecommunication requirements for all 

applicable entities will vary according to their roles. In modifying COM-001-1 through 

the Reliability Standards development process, the Commission believes that the ERO 

should create appropriate telecommunications requirements for generator operators and 

distribution providers, which may be additional and separate Requirements to COM-001-

1 or, alternatively, a new Reliability Standard as suggested by APPA. 

490. In response to SDG&E, the Commission’s intent is not to subject generator 

operators and distribution providers to the same requirements placed on transmission 

operators. As part of the modification of this Reliability Standard or development of a 

new Reliability Standard to include the appropriate telecommunications facility 

requirements for generator operators and distribution providers, the ERO should take into 

account what would be required of generator operators and distribution providers in terms 

of telecommunications for the Reliable Operation of the Bulk-Power System, instead of 

applying the same requirements as are placed on other reliability entities such as 

reliability coordinators, balancing authorities and transmission operators. 

491. With regard to TAPS’s comment, the Commission has identified a concern and 

directs that the ERO address the matter through its Reliability Standards development 

process. This comports with section 215(d)(5) of the FPA which authorizes the 

Commission, upon its own motion, to order the ERO “to submit to the Commission a 

proposed Reliability Standard or a modification to a Reliability Standard that addresses a 

specific matter if the Commission considers such a new or modified Reliability Standard 

appropriate to carry out this section.” We have identified such a matter and have left to 

the ERO to develop a specific proposal by invoking its Reliability Standards development 

process. Further, consistent with our discussion above regarding applicability of 

Reliability Standards, applicability would be limited through NERC’s registry criteria 

and definition of bulk electric system at this time. 

492. In response to California PUC, in this Final Rule we are initially limiting the 

applicability of these Reliability Standards to those users, owners and operators of the 

Bulk-Power System on the ERO’s compliance registry. The Commission notes that it has 

jurisdiction under section 215 of the FPA over all users, owners and operators of the 

Bulk-Power System to ensure Reliable Operation of the Bulk-Power System. To ensure 

reliability, it is important to include appropriate generator operators and distribution 

providers as applicable entities in Reliability Standard COM-001-1. However, any 

generator operator or distribution provider that is not a user, owner or operator of the 

Bulk-Power System will not be included. Also, at this time, the Bulk-Power System is 

defined on the basis of the ERO’s definition of the “bulk electric system.” The 

Commission believes that this should satisfy California PUC’s concern that this 
Docket No. RM06-16-000 - 146 - 

Reliability Standard be limited to Bulk-Power System operations. We will not further 

limit our directive as to which entities this Reliability Standard should apply. 

493. As we explained in the NOPR, communication with generator operators and 

distribution providers becomes especially important during an emergency when 

generators with black start capability must be placed in service and nearby loads restored 

as an initial step in system restoration. This occurs at a critical time when normal 

communication paths may be disrupted. While many generator operators and distribution 

providers may have telecommunications requirements pursuant to a bilateral contract as 

indicated by APPA, it is important that all generator operators and distribution providers 

identified by the ERO through its registration process are subject to uniform 

telecommunications requirements. Therefore, we adopt our proposal to require the ERO 

to modify COM-001-1 to apply to generator operators and distribution providers. 

However, we recognize that some of the existing requirements (such as Requirement R6 

related to NERCNet) need not apply to generator operators and distribution providers. In 

light of commenters’ concerns, as an alternative, it would be acceptable for the ERO to 

develop a new Reliability Standard that would specifically address an appropriate range 

of Requirements for telecommunication facilities of generator operators and distribution 

providers that reflect their respective roles on Reliable Operation of the Bulk-Power 

System. 

ii. Requirements for Telecommunications Facilities

494. The Commission sought comment on specific requirements or performance 

criteria for telecommunication facilities and whether the modified Reliability Standard 

should provide requirements that also consider the relative role of applicable entities. 

(a) Comments

495. A number of commenters agree with the Commission that the relative role of an 

entity should be taken into account when specifying the requirements for its 

telecommunications facilities.218 For example, ISO-NE states that a single generator 

operator will not need the level of redundancy and diverse routing that a reliability 

coordinator needs. 

496. Many commenters recommend that telecommunications facilities requirements 

should be specified in broad terms. EEI, APPA, Alcoa, International Transmission, 

 218 See, e.g., EEI, International Transmission, ISO-NE, Process Electricity 

Committee and SoCal Edison. 
Docket No. RM06-16-000 - 147 - 

LPPC and SoCal Edison believe that revision to COM-001-1 should provide specific or 

minimum requirements for adequacy, redundancy and diverse routing. However, EEI, 

Alcoa and Northern Indiana maintain that entities should have flexibility in meeting the 

requirements and to allow for innovative technological advancements. Alcoa and 

Northern Indiana maintain that without flexibility, an applicable entity may choose a less 

optimal solution just to comply with the Reliability Standard. EEI asserts that such 

flexibility will also permit alternative means of implementing the requirements that will 

translate into cost savings. International Transmission cautions that we should not 

prejudice the modification of this Reliability Standard by indicating the specific 

requirements or the performance criteria. 

497. APPA states that, because the communications requirements for an entity that is 

responsible for serving 3,000 MW of load is distinctly different from another entity that 

serves 30 MW of load, the ERO should take the size of the entity into consideration. 

498. NERC believes that the questions posed by the NOPR regarding performance 

criteria should be considered through the Reliability Standards development process, in 

accordance with NERC’s Work Plan, which will allow a broader industry debate on the 

requirements for telecommunications facilities. This approach will avoid any potential 

conflicts with the requirements already established in the telecommunications industry 

and by the Institute of Electrical and Electronics Engineers. 

499. Entergy states that it is unclear what cyber assets are covered by COM-001-0. 

Entergy believes that the Reliability Standard should focus on telecommunications that 

support the operation of critical assets. Entergy also believes that COM-001-0 should be 

expanded to include advances in communications technology. It states that NERC should 

consider addressing the following in a way that will facilitate an understanding of the 

Reliability Standards’ requirements: (1) voice communications; (2) command and 

control data communications; (3) security coordination data communications; (4) digital 

messaging communications; (5) human linguistic convention and (6) other types of 

communications, including video conferencing and communications with remote security 

cameras. Entergy believes that this could be accomplished through an enhancement to 

the definition of communications in the NERC glossary and recasting COM-001-0 to 

improve the specificity of requirements for each form of communication. Finally, 

Entergy believes that Requirement R4 of COM-001-0, which requires reliability 

coordinators, transmission operators and balancing authorities to use English in all types 

of communications, should apply only to verbal and written communications. 

500. FirstEnergy asserts that the Requirement R2 is unclear because it does not specify 

whether the phrase “telecommunication facilities” covers both voice and data facilities in 

the context of alarms. It states that, although the word “telecommunications facilities” is 

generally understood to mean both voice and data facilities, the current practice is to 
Docket No. RM06-16-000 - 148 - 

display alarms only for data facilities. Requirement R2 could be misinterpreted to require 

alarms on voice facilities as well, which would be impractical. 

501. Six Cities is concerned that the scope of improper conduct under the “NERCNet 

security policy” in Attachment 1 is virtually limitless 219 Six Cities recognizes that it 

would be difficult to provide a comprehensive and detailed list of all conduct that might 

be considered a misuse of NERCNet data, but that difficulty does not justify exposing 

NERCNet users to the risk of monetary penalties based on amorphous and unbounded 

descriptions of potentially violative conduct. Six Cities states that one solution would be 

to limit the imposition of monetary penalties for misuse of NERCNet data to instances 

where such misuse is intentional or grossly negligent. According to Six Cities, it would 

be appropriate to exact a monetary penalty where a NERCNet user deliberately uses 

NERCNet data for unauthorized or unreasonable purposes. Six Cities asks that it be 

modified to provide for a warning for the improper disclosure of NERCNet data where 

the disclosure was not intentional or grossly negligent. 

(b) Commission Determination

502. The Commission adopts its NOPR proposal that telecommunications facility 

requirements must reflect the roles of the respective operating or reliability entities that 

are included in the applicability section in this Reliability Standard and how they would 

affect the reliability of the Bulk-Power System. We note that most commenters agree 

with this approach. 

503. The Commission agrees with commenters that flexibility is important in setting 

telecommunications requirements in order to foster innovation, allow the adoption of new 

technologies and provide for cost-effective solutions for compliance with the Reliability 

 219 Attachment 1 provides that Violations of the NERCNet Security Policy shall 

include, but not be limited to any act that: 

Exposes NERC or any user of the NERCNet to actual or potential monetary 

loss through the compromise of data security or damage. 

Involves the disclosure of trade secrets, intellectual property, confidential 

information or the unauthorized use of data. 

Involves the use of data for illicit purposes, which may include violation of 

any law, regulation or reporting requirement of any law enforcement or 

government body. 
Docket No. RM06-16-000 - 149 - 

Standard. However, the Commission finds that certain modifications to COM-001-1 are 

necessary to ensure system reliability. We believe that the ERO must specify 

requirements for using telecommunications facilities during normal and emergency 

conditions that: (1) reflect the roles of the applicable entities and their impact on Reliable 

Operation and (2) include adequate flexibility. Accordingly, the Commission directs the 

ERO to modify COM-001-1 through the Reliability Standards development process to 

address our concerns. The Commission believes that the concerns of Entergy and 

FirstEnergy are best addressed by the ERO in the Reliability Standards development 

process. 

504. Six Cities suggests specific new improvements to COM-001-1. As stated above, 

such comments should be addressed as the ERO modifies the Reliability Standards in the 

Reliability Standards development process. 

iii. Measures and Levels of Non-Compliance

505. In its November 15, 2006, filing, NERC submitted COM-001-1, which supersedes 

the Version 0 Reliability Standard. COM-001-1 adds Measures and Levels of NonCompliance to the Version 0 Reliability Standard. 

(a) Comments 

506. ISO-NE notes that Compliance 1.1 of COM-001-0 specifies that “Regional 

Reliability Organizations shall be responsible for compliance monitoring ....” ISO-NE 

suggests that since NERC designed and created NERCNet, NERC should be responsible 

for maintaining and ensuring the compliance with the Reliability Standard rather than 

regional reliability organizations. ISO-NE recommends that the Commission direct 

NERC to modify Compliance 1.1 to provide that NERC shall be responsible for 

monitoring compliance of the NERCNet user organizations. 

(b) Commission Determination

507. With respect to ISO-NE’s comment, we find that a regional reliability organization 

does not have any role with compliance matters; that role is reserved for the ERO or the 

Regional Entities. However, we disagree with ISO-NE that the ERO must replace the 

regional reliability organization as the compliance monitor. The fact that NERC 

designed and created NERCNet does not require the ERO to be the compliance monitor. 

Section 215 of the FPA states that the ERO may delegate compliance and enforcement 

authority to a Regional Entity, even if the ERO creates the Reliability Standards. 

Therefore, although we direct that the regional reliability organization should not be the 

compliance monitor for NERCNet, we leave it to the ERO to determine whether it is the 
Docket No. RM06-16-000 - 150 - 

appropriate compliance monitor or if compliance should be monitored by the Regional 

Entities for NERCNet User Organizations. 

iv. Summary of Commission Determination 

508. While the Commission has identified a number of concerns with regard to COM001-1, this Reliability Standard is independently enforceable without the modifications 

we are directing. Therefore, the Commission approves Reliability Standard COM-001-1 

as mandatory and enforceable. Because of the importance of this Reliability Standard in 

requiring transmission operators and others to have necessary telecommunications 

equipment, we additionally, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our 

regulations, direct the ERO to develop a modification to COM-001-1 through the 

Reliability Standards development process that: (1) expands the applicability to include 

generator operators and distribution providers and includes Requirements for their 

telecommunications facilities; (2) identifies specific requirements for telecommunications 

facilities for use in normal and emergency conditions that reflect the roles of the 

applicable entities and their impact on Reliable Operation and (3) includes adequate 

flexibility for compliance with the Reliability Standard, adoption of new technologies and 

cost-effective solutions. As an alternative to applying this Reliability Standard to 

generator operators and distribution providers, the ERO may develop a new Reliability 

Standard that will address the Requirements for telecommunication facilities applicable 

to generator operators and distribution providers. 

b. Communications and Coordination (COM-002-2)

509. COM-002-2220 seeks 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 authorities and transmission operators to notify 

others through pre-determined communication paths of any condition that could threaten 

the reliability of their areas or when firm load shedding is anticipated. 

510. The Commission proposed in the NOPR to approve Reliability Standard COM002-1 as mandatory and enforceable. In addition, the Commission proposed to direct that 

NERC submit a modification to COM-002-1 that: (1) includes Measures and Levels of 

 220 In its November 15, 2006, filing, NERC submitted COM-002-2, which 

supercedes the Version 1 Reliability Standard. COM-002-2 adds Measures and Levels of 

Non-Compliance to the Version 1 Reliability Standard. In this Final Rule, we review the 

November version, COM-002-2. 
Docket No. RM06-16-000 - 151 - 

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; (3) includes distribution providers as applicable entities and 

(4) requires tightened communications protocols, especially for communications during 

alerts and emergencies. With respect to this final issue, the Commission proposed 

alternatively to direct NERC to develop a new Reliability Standard that responds to 

Blackout Report Recommendation No. 26, which deals with the need for tightened 

communications protocols. 

i. Applicability to Distribution Providers 

(a) Comments

511. While EEI states that there is a clear need to apply the Reliability Standard to 

distribution providers, APPA finds the proposal problematic because it would mean that 

close to 2,000 public power systems would have to be added to the compliance registry. 

APPA argues that the Commission should instruct NERC to consider the applicability of 

COM-002-2 to distribution providers through its Reliability Standards development 

process. MRO requests that the Commission clarify whether the distribution providers 

will continue to operate their own systems in the future. 

(b) Commission Determination

512. The Commission finds that, during both normal and emergency operations, it is 

essential that the transmission operator, balancing authority and reliability coordinator 

have communications with distribution providers. In response to APPA, as discussed 

above, any distribution provider that is not a user, owner or operator of the Bulk-Power 

System would not be required to comply with COM-002-2, even though the Commission 

is requiring the ERO to modify the Reliability Standard to include distribution providers 

as applicable entities. APPA’s concern that 2,000 public power systems would have to 

be added to the compliance registry is misplaced, since, as we explain in our 

Applicability discussion above, we are approving NERC’s registry process, including the 

registry criteria. Therefore, we adopt our proposal to require the ERO to modify COM002-2 to apply to distribution providers through its Reliability Standards development 

process. 

513. The Commission believes that this Reliability Standard does not alter who would 

operate a distribution provider’s system. It only concerns communications, not the 

operation of the distribution system. 
Docket No. RM06-16-000 - 152 - 

ii. Measures and Levels of Non-Compliance 

(a) Comments

514. APPA notes that the Levels of Non-Compliance for COM-002-2 are inadequate in 

two respects: (1) reliability coordinators are not included in any Level of NonCompliance and (2) the Levels of Non-Compliance for transmission operators and 

balancing authorities in Compliance D.2 do not reference Requirements R1 and R2. 

Therefore, APPA would support approval of COM-002-2 as a mandatory Reliability 

Standard, but would not support levying penalties for violating incomplete portions of the 

Reliability Standard. 

(b) Commission Determination

515. As stated in the Common Issues section, a Reliability Standard is enforceable even 

if it does not contain Levels of Non-Compliance.221 However, the Commission agrees 

with APPA that this Reliability Standard could be improved by incorporating the changes 

proposed by APPA. Therefore, when reviewing the Reliability Standard through the 

Reliability Standards development process, the ERO should consider APPA’s concerns. 

iii. Reliability Coordinator Assessment and Approval 

of Actions that have Impacts Beyond the Area 

Views of Transmission Operators and Balancing 

Authorities

(a) Comments

516. Alcoa argues that there is a need for communication regarding operating actions 

taken by transmission operators and balancing authorities that may have impacts beyond 

their area views. However, a number of commenters oppose the Commission’s proposal 

to modify the Reliability Standard to require reliability coordinators to assess and 

approve actions that have impacts beyond the area views of transmission operators or 

balancing authorities and seek clarifications.222 Alcoa, California PUC, SDG&E and 

Xcel are concerned that obtaining approval from reliability coordinators could create 

delays in completing the operating action in emergency situations. Xcel and Alcoa 

 221 See Common Issues Pertaining to Reliability Standards: Measures and Levels 

of Non-Compliance, supra section II.E.2. 

222 See, e.g., APPA, EEI, California PUC, ISO-NE and SDG&E. 
Docket No. RM06-16-000 - 153 - 

request that the Commission clarify that this requirement would not prevent timely 

performance by a transmission operator of actions necessary to maintain the reliability of 

its system under emergency conditions.223 Both Alcoa and Xcel are concerned that 

waiting for an assessment and approval by a reliability coordinator may not be feasible, 

especially during emergencies. Xcel further asks the Commission to clarify that the 

entity taking operating actions should not be held responsible for delays caused by the 

reliability coordinator’s assessment and approval. Alcoa suggests that there should be a 

clear definition of what actions have an impact beyond the area views of transmission 

operators or balancing authorities. SDG&E further states that serious damage to 

transmission equipment could occur if the transmission operator is not able to take 

immediate action during an emergency. 

517. ISO-NE is concerned that the Commission proposal goes too far and if 

implemented, will prevent capable transmission operators from quickly addressing 

reliability problems that may arise. It maintains that transmission operators usually do 

not have enough time to inform the reliability coordinator, who must then “assess and 

approve” the proposed action. If the Commission’s proposal is implemented, 

transmission operators will doubt themselves and delay necessary action. However, it 

does not see any problem for the New England balancing area and the NPCC region, 

because ISO-NE serves as the New England reliability coordinator, balancing authority 

and transmission operator. 

518. APPA contends that the Commission’s proposed directive appears to have been 

covered under Reliability Standard IRO-005-1. EEI agrees, stating that IRO-005-1 

already requires a reliability coordinator to ensure that transmission operators and 

balancing authorities operate to prevent action or non-action that will impact neighboring 

areas.

224 

 223 Alcoa notes that this is consistent with the Requirements in TOP-001-1, which 

provides transmission operators and balancing authorities wide latitude to preserve 

reliability of their area. 

224 The Requirement R13 of IRO-005-1 provides that “[e]ach reliability 

coordinator shall ensure that Transmission Operators, Balancing Authorities ... operate to 

prevent the likelihood that a disturbance, action or non-action in its Reliability 

Coordinator Area will result in a SOL or IROL violation in another area of the 

Interconnection.” 
Docket No. RM06-16-000 - 154 - 

(b) Commission Determination

519. The Commission reaffirms its belief that Reliable Operation of the Bulk-Power 

System can only be achieved by coordinated efforts of all operating entities, such as 

reliability coordinators, transmission operators and balancing authorities in operating 

their respective systems and performing their respective functions in accordance with 

their responsibilities and authorities. Most operating actions taken by transmission 

operators and balancing authorities in real-time would only affect their own areas and 

equipment and have no adverse impacts on the interconnection reliability operating 

limits, and therefore they have unilateral authority to act. However some operating 

actions that would have impacts beyond their own areas must involve the reliability 

coordinator who has the wide-area views and the necessary operating tools, including 

monitoring facilities and real-time analytic tools with wide-area representation to enable 

the reliability coordinator to fulfill its responsibility.225 In response to Alcoa, the 

Commission believes that actions that have an impact beyond an area will, in general, 

vary based on the conditions at the time of the action. 

520. Further, we clarify that we did not propose to require an entity to inform its 

reliability coordinator of every action it takes. Instead, the proposed directive included a 

Requirement for the reliability coordinator to assess and approve only those actions that 

have impacts beyond the area views of transmission operators and balancing authorities. 

We remain convinced that it is the reliability coordinator’s responsibility to ensure 

Reliable Operation of its reliability coordinator area. The reliability coordinator must 

also ensure that actions taken by operating entities under its authority will not have widearea impacts that would adversely impact Reliable Operation of the Bulk-Power System. 

Therefore, we adopt the proposed directive as stated in the NOPR. 

521. In response to commenters, the Commission clarifies that the proposed directive 

does not conflict with the transmission operators’ and balancing authorities’ rights to take 

actions necessary to preserve reliability of their areas and alleviate operating 

 225 The NERC glossary states that A reliability coordinator is the “entity that is the 

highest level of authority who is responsible for the reliable operation of the bulk electric 

system, has the wide-area view of the bulk electric system, and has the operating tools, 

processes and procedures, including the authority to prevent or mitigate emergency 

operating situations in both next-day analysis and real-time operations. The reliability 

coordinator has the purview that is broad enough to enable the calculation of IROLs, 

which may be based on the operating parameters of transmission systems beyond any 

transmission operator’s vision.” NERC Glossary at 15. 
Docket No. RM06-16-000 - 155 - 

emergencies, consistent with Requirement R1 and R2 in TOP-001-1.226 Further, the 

proposed directive does not in any way diminish their operating authority regarding local 

area reliability for normal and emergency situations, a responsibility that is under the 

responsibility of a transmission operator or a balancing authority. However, the majority 

of their operating actions are not emergency actions and would only affect a transmission 

operator’s or balancing authority’s area of responsibilities. Since these actions are 

expected to have little impact outside of the transmission operator’s or balancing 

authority’s area, the authority to take unilateral actions remains with the transmission 

operator or balancing authority. Other non-emergency actions should be coordinated 

with the reliability coordinator prior to taking action. 

522. Regarding SDG&E’s concern that serious damage to transmission equipment 

could occur if the transmission operator is not able to take immediate action during an 

emergency, we believe this is adequately addressed under Requirement R3 of TOP-001-0 

which provides that operating entities need not comply with directives from reliability 

coordinators when such actions would violate safety, equipment, regulatory or statutory 

requirements. 

523. NERC should consider Xcel’s suggestion that the entity taking operating actions 

should not be held responsible for delays caused by the reliability coordinator’s 

assessment and approval in the Reliability Standards development process. We note that 

the operating entity has the authority to take emergency actions to protect its system that 

may circumvent or preempt the reliability coordinator’s approval process under TOP001-1 Requirement R3 in cases of personnel safety, potential equipment failure or 

environmental needs. 

524. We disagree with commenters that the Commission’s proposed directive is already 

covered under Requirement R13 of IRO-005-1, which requires each reliability 

coordinator to ensure that all transmission operators, balancing authorities and others 

operate to prevent the likelihood that a disturbance, action, or non-action in its reliability 

coordinator area will result in a SOL and IROL violation in another area of the 

Interconnection. In order for the reliability coordinator to carry out its function under 

IRO-005-1, it must have information from the transmission operators and balancing 

authorities. However, IRO-005-1 does not require transmission operators and balancing 

authorities to provide the reliability coordinator with the information it would need to 

 226 TOP-001-1, R1 states in part “Each transmission operator shall have the 

responsibility and clear decision-making authority to take whatever actions are needed to 

ensure the reliability of its area ....” and R2 states in part “Each transmission operator 

shall take immediate actions to alleviate operating emergencies ....” 
Docket No. RM06-16-000 - 156 - 

prevent the likelihood that an action from these two entities will result in a SOL or IROL 

violation in another area of the Interconnection. The Commission’s directive ensures that 

the reliability coordinator has such information. Therefore, we do not believe that COM002-2 is duplicative of IRO-005-1. 

525. Accordingly, we direct the ERO to include a Requirement for the reliability 

coordinator to assess and approve actions that have impacts beyond the area views of 

transmission operators or balancing authorities, including how to determine whether an 

action needs to be assessed by the reliability coordinator. This Requirement is best 

developed under the Reliability Standards development process including the 

consideration whether this Requirement should be included in this communications 

Reliability Standard or an operating Reliability Standard. 

iv. Tightened Communications Protocols

526. The Blackout Report cited ineffective communications as a factor common to the 

August 14, 2003 blackout and other previous major outages in North America.227 In 

addition, Recommendation No. 26 of the Blackout Report instructed NERC, working 

with reliability coordinators and control area operators, to “[t]ighten communications 

protocols, especially for communications during alerts and emergencies....”228 In the 

NOPR, the Commission endorsed Blackout Recommendation No. 26 and proposed to 

direct the ERO to require tightened communications protocols, especially for 

communications during alerts and emergencies. Alternatively, we proposed to direct the 

ERO to develop a new Reliability Standard that responds to the Blackout Report 

Recommendation. 

(a) Comments

527. In its response to the Staff Preliminary Assessment, NERC agreed with the need to 

develop additional Reliability Standards addressing consistent communications protocols 

among personnel responsible for the reliability of the Bulk-Power System.229 

528. EEI supports the Commission in its concerns regarding Blackout 

Recommendation No. 26 on emergency communications. However, EEI states that 

 227 Blackout Report at 107. 

228 Id. at 141. 

229 NOPR at P 255. 
Docket No. RM06-16-000 - 157 - 

Requirement R4 of EOP-001-0, Emergency Operations Planning, addresses the 

Commission’s concerns about communication protocols during emergency conditions.230 

EEI recommends that, instead of duplicating the same requirement in COM-002-2, the 

Commission should consider directing NERC to provide an interpretation on the 

elements of such protocols. 

529. APPA believes that the communications protocols to be used during emergencies 

should be included in the relevant Reliability Standard that governs each type of 

emergency, rather than in COM-002-2. For example, Requirement R3 of Reliability 

Standard VAR-002-1 establishes the protocol for communication with the transmission 

operator if a generator loses its ability to provide voltage control. By keeping the 

necessary communication protocols clustered with the events to which they apply, NERC 

would make the Reliability Standards more user-friendly. 

530. MISO claims that Blackout Report Recommendation No. 26 on tightened 

communications protocols dealt primarily with NERC infrastructure and has been fully 

implemented. It is concerned that developing measures that require ongoing 

administration will impede rather than improve timely communications in an emergency. 

(b) Commission Determination

531. We adopt our proposal to require the ERO to establish tightened communication 

protocols, especially for communications during alerts and emergencies, either as part of 

COM-002-2 or as a new Reliability Standard. We note that the ERO’s response to the 

Staff Preliminary Assessment supports the need to develop additional Reliability 

Standards addressing consistent communications protocols among personnel responsible 

for the reliability of the Bulk-Power System. 

532. While we agree with EEI that EOP-001-0, Requirement R4.1 requires 

communications protocols to be used during emergencies, we believe, and the ERO 

agrees, that the communications protocols need to be tightened to ensure Reliable 

Operation of the Bulk-Power System. We also believe an integral component in 

tightening the protocols is to establish communication uniformity as much as practical on 

a continent-wide basis. This will eliminate possible ambiguities in communications 

 230 EOP-001-0, Requirement R4 provides, in relevant part, that: “[e]ach 

Transmission Operator and Balancing Authority shall have emergency plans that will 

enable it to mitigate operating emergencies. At a minimum, Transmission Operator and 

Balancing Authority emergency plan shall include [c]ommunication protocols to be used 

during emergencies.” 
Docket No. RM06-16-000 - 158 - 

during normal, alert and emergency conditions. This is important because the BulkPower System is so tightly interconnected that system impacts often cross several 

operating entities’ areas. 

533. Regarding APPA’s suggestion that it may be beneficial to include communication 

protocols in the relevant Reliability Standard that governs those types of emergencies, we 

direct that it be addressed in the Reliability Standards development process. 

534. In response to MISO’s contention that Blackout Report Recommendation No. 26 

has been fully implemented, we note that Recommendation No. 26 addressed two 

matters. We believe MISO is referring to the second part of the recommendation 

requiring NERC to “[u]pgrade communication system hardware where appropriate” 

instead of tightening communications protocols. While we commend the ERO for taking 

appropriate action in upgrading its NERCNet, we remind the industry to continue their 

efforts in addressing the first part of Blackout Recommendation No. 26. 

535. Accordingly, we direct the ERO to either modify COM-002-2 or develop a new 

Reliability Standard that requires tightened communications protocols, especially for 

communications during alerts and emergencies. 

v. Other Issues

(a) Comments 

536. Santa Clara requests clarification whether the phrase “Such communications shall 

be staffed and available” in Requirement R1 applies only to operating staff available on 

site at all times or includes repair personnel who are available only on an on-call basis. 

537. FirstEnergy asks that the Reliability Standard specify what is meant by “staffed” 

and states that the term should not require a physical presence at all facilities at all times 

because some units, such as peaking units, are not staffed 24 hours a day. In addition, 

FirstEnergy suggests that, because nuclear units are already subject to communications 

requirements in their operating procedures, their compliance with NRC operating 

procedures should be deemed in compliance with the NERC Reliability Standards. 

538. Similarly, Six Cities states that, to avoid unnecessary staffing burdens, particularly 

for smaller entities, the Commission should direct NERC to clarify COM-002-2 by 

providing that identification of an emergency contact person on call to respond to realtime emergency conditions will constitute adequate compliance. 
Docket No. RM06-16-000 - 159 - 

(b) Commission Determination 

539. Santa Clara, FirstEnergy and Six Cities suggest specific new improvements to the 

Reliability Standards. As stated above, such comments should be considered as the ERO 

modifies the Reliability Standards in the Reliability Standards development process. 

vi. Summary of Commission Determination

540. While the Commission identified concerns regarding COM-002-2, the proposed 

Reliability Standard serves an important purpose by requiring users, owners and 

operators to implement the necessary communications and coordination among entities. 

Accordingly, the Commission approves Reliability Standard COM-002-2 as mandatory 

and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of 

our regulations, the Commission directs the ERO to develop a modification to COM-002-

2 through the Reliability Standards development process that: (1) expands the 

applicability to include distribution providers as applicable entities; (2) includes a new 

Requirement for the reliability coordinator to assess and approve actions that have 

impacts beyond the area view of a transmission operator or balancing authority231 and 

(3) requires tightened communications protocols, especially for communications during 

alerts and emergencies. Alternatively, with respect to this final issue, the ERO may 

develop a new Reliability Standard that responds to Blackout Report Recommendation 

No. 26 in the manner described above. Finally, we direct the ERO to include APPA’s 

suggestions to complete the Measures and Levels of Non-Compliance in its modification 

of COM-002-2 through the Reliability Standards development process. 

4. EOP: Emergency Preparedness and Operations

541. 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. 

a. Emergency Operations Planning (EOP-001-0)

542. 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 

 231 This Requirement could, for example, be included in COM-002-2 or in an 

operating Reliability Standard. 
Docket No. RM06-16-000 - 160 - 

mitigate operating emergencies. These plans must be coordinated with other 

transmission operators and balancing authorities and the reliability coordinator. 

543. In the NOPR, the Commission proposed 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, the Commission proposed to direct that NERC 

submit a modification to EOP-001-0 that: (1) includes the reliability coordinator as an 

applicable entity with responsibilities as described above; (2) clarifies the 30-minute 

requirement in Requirement R2 of the Reliability Standard to state that load shedding 

should be capable of being implemented as soon as possible and much less than 30 

minutes and (3) includes definitions of system states to be used by the operators, such as 

transmission-related “normal,” “alert,” and “emergency” states, provides criteria for 

entering into these states and identifies the authority that will declare these states. 

544. Most of the comments address the specific modifications and concerns raised by 

the Commission in the NOPR. Below, we address each topic separately, followed by an 

over-all conclusion and summary. 

i. Applicability to reliability coordinators

(a) Comments

545. MRO states that it is necessary to include reliability coordinators as applicable 

entities because reliability coordinators have a wide-area view. FirstEnergy also supports 

making the proposed Reliability Standard applicable to the reliability coordinator. 

FirstEnergy states the reliability coordinator should take an active role and should have 

clearly defined, specific responsibilities for coordinating and implementing emergency 

operations plans. In addition, FirstEnergy states that inclusion of the reliability 

coordinator as an applicable entity removes ambiguity that may exist concerning the 

reliability coordinator’s role and its responsibilities during restoration activities. 

546. SoCal Edison agrees that certain aspects of EOP-001-0 should be applicable to 

reliability coordinators; however, it proposes that NERC, through the stakeholder 

process, should receive input from stakeholders on which requirements should be 

exclusive to the transmission operator or balancing authority with the reliability 

coordinator responsible only for collecting and incorporating this information into its 

overarching plan. MISO, on the other hand, questions the need for the proposed 

modification, contending that the reliability coordinators have parallel responsibilities 

laid out in other EOP Reliability Standards. 
Docket No. RM06-16-000 - 161 - 

(b) Commission Determination

547. In the NOPR, we stated that the proposed Reliability Standard applies to 

transmission operators and balancing authorities, that the applicability portion of the 

Reliability Standard is sufficiently clear as to who must comply with the filed version of 

the Reliability Standard and that the Reliability Standard can be enforced against these 

entities.232 However, we recognized commenters’ concerns that the Reliability Standard 

does not assign a role to the reliability coordinator, which is the highest level of authority 

responsible for reliable operation of the Bulk-Power System and which has a wide-area 

view. MISO contends that EOP-001-0 need not apply to reliability coordinators because 

they have parallel responsibilities in other EOP Reliability Standards. We disagree. 

Given the importance NERC attributes to the reliability coordinator in connection with 

matters covered by EOP-001-0, the Commission is persuaded that specific 

responsibilities for the reliability coordinator in the development and coordination of 

emergency plans must be included as part of this Reliability Standard. While balancing 

authorities and transmission operators are capable of developing, maintaining and 

implementing plans to mitigate operating emergencies for their specific areas of 

responsibility, unlike reliability coordinators, they do not have wide-area views. 

548. Further we agree with SoCal Edison that clear direction is needed on which 

requirements should be exclusive to transmission operators and balancing authorities with 

the reliability coordinator being responsible for incorporating this information into its 

overarching plan. Accordingly, the Commission finds the reliability coordinator is a 

necessary entity under EOP-001-0 and directs the ERO to modify the Reliability Standard 

to include the reliability coordinator as an applicable entity. In addition, the ERO should 

consider SoCal Edison’s suggestion in the ERO’s Reliability Standards development 

process. 

ii. Clarification of the 30-minute Load Shedding 

Requirement

(a) Comments

549. NERC comments that the proposed directive to clarify the 30-minute requirement 

in Requirement R2 presumes that all manual load shedding can be performed by 

supervisory control. It states that, in many systems, shedding load requires actions by 

field personnel who must be dispatched to a site. NERC recognizes the reliability benefit 

of being able to shed greater amounts of load in seconds or minutes but contends that the 

 232 NOPR at P 272. 
Docket No. RM06-16-000 - 162 - 

amount of load shedding under remote supervisory control and the timing requirements 

should be vetted through industry experts based on good utility practice. While 

acknowledging that the proposed modification is appropriate because it corresponds to 

current good utility practice and widely held interpretations of the requirement to shed 

load, FirstEnergy, like NERC, notes that load that does not have SCADA cannot be shed 

within 30 minutes because field staff must be dispatched. It proposes that the Reliability 

Standard should specify that, for loads that do not have SCADA, the implementation plan 

must be initiated, but not necessarily completed, within 30 minutes. Similarly, 

MidAmerican is concerned that if load shedding is to be performed in much less than 30 

minutes it will require automatic load shedding which may trigger when not required 

leading to less reliability under certain conditions. MidAmerican proposes a modification 

to specifically permit load shedding with non-automatic schemes. 

550. Xcel states that the proposed modification is unnecessary because there are many 

different options besides load shedding that could be implemented to alleviate IROL 

violations within 30 minutes. It adds that load shedding is the option of last resort and 

that the timing for implementation of load shedding would be better addressed in 

proposed Reliability Standard EOP-003-1. EEI and California PUC state that not all load 

reduction schemes should be required to be operable within 30 minutes; only those used 

for emergency operations. APPA states that the 30-minute interval was selected based on 

industry consensus and, rather than dismiss this consensus, the Commission should 

instruct NERC to reconsider the 30-minute requirement and either modify it or better 

explain why it is the appropriate time period for the requirement. MISO questions what 

would be achieved by the proposed modification and states that operators do not 

intentionally delay taking action when required. 

551. International Transmission and PG&E state that shedding load “as soon as 

possible and much less than 30 minutes” is vague and unenforceable. International 

Transmission proposes shedding of load “as soon as possible when required to mitigate 

an IROL violation, but in no case in more than 30 minutes.” 

(b) Commission Determination

552. The proposed Reliability Standard states that the transmission operator shall have 

an emergency load reduction plan for all identified IROLs and that the load reduction 

plan must be capable of being implemented within 30 minutes. In the NOPR, we 

proposed to direct NERC to modify EOP-001-0 to clarify the 30-minute requirement in 

Requirement R2 to state that load shedding should be capable of being implemented as 
Docket No. RM06-16-000 - 163 - 

soon as possible and in much less than 30 minutes.233 The intent was to have a 

requirement that precludes waiting until the 29th minute to begin implementation. 

553. In response to the concerns of commenters, the Commission clarifies that the 

proposed modification does not require that SCADA or its equivalent be installed for all 

loads. Rather, SCADA would be required only for those loads necessary to mitigate 

IROL violations and to maintain reliable operations. As we stated in the NOPR, the 

Commission understands that it is not the intent of the Reliability Standard to require the 

shedding of all available load within 30 minutes, but rather only the amount necessary to 

correct system emergencies.234 Thus the Commission agrees with EEI and California 

PUC that not all load reduction schemes should be required to be operable within 30 

minutes but only those used for emergency operations. 

554. Further, as Xcel recognizes, load shedding is the option of last resort and there 

may be other options available to alleviate IROL violations within 30 minutes. The ERO 

should consider these other options as it works through the Reliability Standards 

development process to modify EOP-001-0. 

555. With regard to the wording of the proposed modification stating that load shedding 

should be capable of being implemented “as soon as possible and in much less than 30 

minutes,” the Commission agrees with PG&E and International Transmission that this 

language may be unclear and unduly subjective. In the NOPR, we stated that the 

reference to 30 minutes could suggest that anything up to that limit was acceptable and 

proposed the modification to emphasize our concern that implementation was expected 

much sooner than in 30 minutes. International Transmission’s suggested rewording 

addresses our concern. Accordingly, we direct the ERO to develop a modification 

through the Reliability Standards development process clarifying that when the load 

reduction plan of Requirement R2 involves load shedding, such load shedding be capable 

of being implemented as soon as possible when required to mitigate an IROL violation 

but in no case in more than 30 minutes. 

556. Finally, in response to APPA’s comments, as stated in the NOPR,235 the 

Commission accepts the 30 minute requirement as a reasonable period within which 

operators should return the system to a reliable operating state. However in order to 

 233 Id. at P 273. 

234 Id.

235 Id. at P 995. 
Docket No. RM06-16-000 - 164 - 

satisfy this Requirement, when load shedding is the only viable option, the Commission 

believes that operators must have the capability through SCADA or other equivalent 

means to shed appropriate amounts of load in the desired locations as soon as possible to 

mitigate IROL violations but in no case in more than 30 minutes.236 

iii. Definitions of System States

(a) Comments

557. FirstEnergy states that it may be difficult to define system states that cover all 

operating conditions, but nonetheless recognizes that the standardization of these states is 

a first step to bringing clarity to operators concerning system conditions and the resulting 

actions they are expected to take. California PUC, on the other hand, states that imposing 

uniform definitions for “normal,” “alert” and “emergency” states is impractical and 

counterproductive. California PUC claims that trying to define in advance all 

contingencies that the system may face is probably infeasible and argues that improved 

real-time monitoring of the grid is the preferred approach for quick identification and 

correction of problems. 

558. ISO-NE states that it is important to define system states but that such definitions 

should not be implemented until a “pilot program” is field tested. ISO-NE explains that 

after such a pilot program is conducted operators would need to make changes to their 

policies and procedures, including operator training, to make sure that their practices are 

administered in a secure and well-understood fashion. 

(b) Commission Determination

559. In the NOPR, the Commission stated that clearly defined system states 

incorporated into real-time operation can significantly improve operator recognition of 

emergency conditions, rapid and accurate response and recovery to normal system 

conditions.237 

560. The Commission recognizes that the triggering events and the nature of the 

emergency states may be different for different systems; however, we find that a clearly 

defined set of system states will help operators proactively avert escalations of system 

disturbances and cascading outages. Further, operators, the ERO and regulators will 

 236 Id.

237 Id. at P 275. 
Docket No. RM06-16-000 - 165 - 

better understand how reliably the system is operating and how it performed historically 

if statistics can be collected based on well-defined system states. We find it reasonable 

for the ERO, through the stakeholder process, to develop a well-defined set of uniform, 

continent-wide system states that can be understood by transmission operators, balancing 

authorities, reliability coordinators and the ERO to correspond to specific, predetermined 

levels of urgency. 

561. As we noted in the NOPR, some control areas define and effectively use more 

than the “normal,” “alert” and “emergency” system states included in the Blackout 

Report recommendation.238 We proposed that the ERO determine the optimum number 

of system states to be employed continent-wide and to consider the addition of the 

restoration state.239 Accordingly, we direct the ERO to determine the optimum number of 

continent-wide system states and their attributes and to modify the Reliability Standard 

through the Reliability Standards development process to accomplish this objective. 

562. Further, we agree with ISO-NE that the proposed modification should be fieldtested and that policies and procedure be put in place, including operator training, before 

any processes for continent-wide system states are implemented. Such testing will help 

assure that all applicable entities and their personnel understand how the terms will be 

used and will allow operators to train staff to make any necessary changes to their 

policies and procedures. We direct the ERO to consider such a pilot program as it 

modifies EOP-001-0 through the Reliability Standards development process. 

iv. Other issues 

(a) Comments

563. ISO-NE raises two additional concerns with the proposed Reliability Standard. 

First, it states that activities outlined in Requirement R7.4, including coordinating fuel 

conservation and arranging for fuel deliveries, are not functions that independent 

transmission operators and balancing authorities typically perform. Second, ISO-NE 

notes that Requirement R5 provides that each transmission operator and balancing 

authority must include applicable elements of Attachment 1 of EOP-001-0 in an 

emergency plan. However, according to ISO-NE, the elements identified in Attachment 

1 are characterized as “for consideration” and are not mandatory. ISO-NE argues that the 

proposed Reliability Standard should be clarified to indicate that the actual emergency 

 238 Id. at P 276. 

239 Id.
Docket No. RM06-16-000 - 166 - 

plan elements, and not the “for consideration” elements of Attachment 1, should be the 

basis for compliance. 

(b) Commission Determination

564. With regard to ISO-NE’s concern that certain activities outlined in Requirement 

R7.4 are not functions normally performed by independent transmission operators and 

balancing authorities, the Commission understands that this Requirement covers either 

delivery of fuel or delivery of electrical energy from remote systems. While arranging 

for fuel deliveries may be outside of the functions that ISOs and RTOs perform, the 

requirement to arrange deliveries of electrical energy from remote systems is a function 

they normally perform. Because an ISO or RTO may choose to either deliver fuel or 

electrical energy from remote systems, Requirement R7.4 will not burden ISOs and 

RTOs with functions they do not normally perform. 

565. The Commission agrees with ISO-NE that the Reliability Standard should be 

clarified to indicate that the actual emergency plan elements, and not the “for 

consideration” elements of Attachment 1, should be the basis for compliance. However, 

all of the elements should be considered when the emergency plan is put together. 

v. Summary of Commission Determination

566. Accordingly, the Commission concludes that Reliability Standard EOP-001-0 is 

just, reasonable, not unduly discriminatory or preferential and in the public interest and 

approves it as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of 

the FPA and § 39.5(f) of our regulations, the Commission directs the ERO to develop a 

modification to EOP-001-0 through the Reliability Standards development process 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 but in no more than 30 minutes; (3) includes definitions of system 

states to be used by the operators, such as transmission-related “normal,” “alert” and 

“emergency” states, provides criteria for entering into these states, and identifies the 

authority that will declare these states and (4) clarifies that the actual emergency plan 

elements, and not the “for consideration” elements of Attachment 1, should be the basis 

for compliance. Further, the Commission directs the ERO to consider a pilot program for 

system states, as discussed above. 
Docket No. RM06-16-000 - 167 - 

b. Capacity and Energy Emergencies (EOP-002-2)

567. EOP-002-2 applies to balancing authorities and reliability coordinators and is 

intended to ensure that they are prepared for capacity and energy emergencies.240 The 

Reliability Standard requires that balancing authorities have the authority to bring all 

necessary generation on line, communicate about the energy and capacity emergency 

with the reliability coordinator and coordinate with other balancing authorities. EOP002-2 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 LSE. 

568. In the NOPR, the Commission proposed to approve the Reliability Standard as 

mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and 

§ 39.5(f) of our regulations, the Commission proposed to direct that NERC submit a 

modification to the Reliability Standard 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 DSM in Requirement R6 as one 

possible remedy that a balancing authority may use to bring it in compliance with control 

performance and disturbance control Reliability 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. 

569. Most of the comments address the specific modifications and concerns raised by 

the Commission in the NOPR. Below, we address each topic separately, followed by an 

over-all conclusion and summary. 

i. Insufficient Transmission Capability

(a) Comments

570. MRO believes that the definition for the term “insufficient transmission 

capability” should be clarified because insufficient transmission capability could be due 

to a thin spot in the interconnection, prior outages or storm damage. 

 240 In its November 15, 2006, filing, NERC submitted EOP-002-2, which 

supercedes the Version 1 Reliability Standard. EOP-002-2 adds Measures and Levels of 

Non-Compliance to the Version 0 Reliability Standard. In this Final Rule, we review the 

November version, EOP-002-2. 
Docket No. RM06-16-000 - 168 - 

(b) Commission Determination

571. As we stated in the NOPR, neither EOP-002-2 nor any other Reliability Standard 

addresses the impact of inadequate transmission during generation emergencies.241 The 

Commission agrees with MRO that “insufficient transmission capability” could be due to 

various causes. The ERO should examine whether to clarify this term in the Reliability 

Standards development process. 

ii. Demand-Side Management

(a) Comments

572. FirstEnergy states that it is appropriate to include demand-side resources as 

another tool for balancing authorities to use in meeting control performance and 

disturbance control Reliability Standards. It states, however, that in order to qualify, the 

demand-side resource options must meet similar technical requirements as generation 

resource options. Comverge recommends that the terms “demand response” and 

“curtailable loads” be specifically added to R3, R4 and R6.3 and Alert Level 1 to ensure 

that they are included in the list of resources that will be controlled during capacity and 

energy emergencies. APPA contends that Requirement R6.6 adequately accounts for the 

use of demand-side remedies to address emergencies. As such, APPA opposes the 

Commission’s proposal as being unduly prescriptive. Also ISO-NE contends that the 

proposed modifications effectively dictate a specific means to solve the underlying 

problems instead of leaving it to the responsible entities to determine how to achieve the 

reliability objective. A proper recommendation would be to make the requirement 

resource-neutral. 

(b) Commission Determination 

573. The Commission agrees with FirstEnergy that for demand-side resources to 

qualify as another tool for balancing authorities to use in meeting control performance 

and disturbance control Reliabilty Standards, they must meet comparable technical 

performance requirements as generation resource options. In response to comments from 

Comverge and APPA, the Commission believes that curtailable loads are adequately 

addressed in Requirement R6 of the Reliability Standard but that demand response is not 

 241 NOPR at P 284. 
Docket No. RM06-16-000 - 169 - 

covered.242 Demand response covers considerably more resources than interruptible load. 

Accordingly, the Commission directs the ERO to modify the Reliability Standard to 

include all technically feasible resource options in the management of emergencies. 

These options should include generation resources, demand response resources and other 

technologies that meet comparable technical performance requirements. 

iii. Warning regarding TLR procedure

(a) Comments

574. MRO states that it is very important that all concerned parties realize that TLR is 

not a first line of defense to mitigate IROL violations. Entergy and MidAmerican agree 

that TLR procedures are not effective to mitigate IROL violations or for use in 

emergency situations. EEI supports the Commission’s proposed modifications to the 

Reliability Standard; however, EEI along with Entergy, MidAmerican and APPA, 

believes that the TLR process is effective in avoiding and mitigating potential IROL 

violations. These commenters request that the Commission clarify the proposed 

modification so that it does not foreclose such use of the TLR process. 

575. International Transmission states that TLR can be an effective and appropriate 

means to mitigate IROL violations or for use in emergency situations and therefore EOP002-2 should not preclude the use of TLR when its use is warranted. MISO states that, 

while TLR is not the preferred method of responding to emergencies, an operator should 

not be precluded from implementing TLR during emergencies. It argues that TLR may 

be appropriate when events develop slowly or when an entity is affected by external 

transactions and has exhausted all control actions or needs to reserve some control 

actions for contingencies. 

576. APPA contends that the specific direction provided in this proposed modification 

intrudes on NERC’s role as a standard setting agency and would be better framed as a 

direction to NERC to investigate the concern and revise the Reliability Standard 

accordingly. Similarly, while ISO-NE supports the Commission’s conclusion that 

reliance on TLR procedures can be inappropriate, it recommends that the proposed 

Reliability Standard would be improved if it did not specify the operating method 

required to achieve compliance. ISO-NE also believes that the Commission should direct 

 242 Requirement R6 provides, in pertinent part: “R6. If the Balancing Authority 

cannot comply with the Control Performance and Disturbance Control Standards, then it 

shall immediately implement remedies to do so. These remedies include, but are not 

limited to: R6.3. Interrupting interruptible load and exports.” 
Docket No. RM06-16-000 - 170 - 

NERC to allow the responsible entities flexibility in the means by which they achieve 

compliance with the Reliability Standard.243

(b) Commission Determination

577. A number of commenters agree that the TLR procedure is an inappropriate and 

ineffective tool for mitigating actual IROL violations or for use in emergency 

situations.244 On the other hand, International Transmission believes the TLR procedure 

can be an appropriate and effective tool to mitigate IROL violations or for use in 

emergency situations and MISO argues that operators should not be precluded from 

implementing the TLR procedure during emergencies. The Commission disagrees. As 

explained in the NOPR and in the Blackout Report, actions undertaken under the TLR 

procedure 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. As such the Commission 

cannot agree with International Transmission and MISO. However, the Commission 

agrees with APPA, EEI, Entergy and MidAmerican that the TLR procedure may be 

appropriate and effective for use in managing potential IROL violations. Accordingly, 

the Commission will maintain its direction that the ERO modify the Reliability Standard 

to ensure that the TLR procedure is not used to mitigate actual IROL violations. 

578. As to APPA’s comment that we are intruding on NERC’s role as a standardsetting agency, we have authority to direct the ERO to submit a modification and, in this 

instance, requiring the ERO to “investigate the concern” first is unnecessary. The issue is 

narrowly-framed and the comments identify no points requiring the approach suggested 

by APPA. In response to ISO-NE, we are precluding use of TLR procedures at times of 

actual IROL violations, but are not otherwise specifying permissible responses. 

iv. Other issues 

579. ISO-NE states that Requirement R2 essentially requires the same actions covered 

by ISO-NE Operating Procedure No. 4. ISO-NE is concerned that a strict approach to 

auditing compliance with the Reliability Standard could result in a finding that ISO-NE 

was in violation of the Reliability Standard if it skipped a particular action under its 

emergency plan even though that action was not called for under ISO-NE procedures. 

ISO-NE requests that the Commission direct NERC to clarify that a system operator has 

 243 ISO-NE also notes that in the first line of Requirement R7 the reference to 

“R7” should be to “R6.” 

244 See, e.g., APPA, EEI, Entergy and MidAmerican. 
Docket No. RM06-16-000 - 171 - 

discretion not to implement every action specified in its capacity and energy emergency 

plans when other appropriate actions are possible. 

580. FirstEnergy claims that Requirement R1 may impose overlapping obligations and 

authority on reliability coordinators and balancing authorities who may have the same, 

partial or whole footprint and who are both likely to respond to the same emergency. 

581. APPA notes that revised Reliability Standard EOP-002-2, filed by NERC on 

November 15, 2006, includes new Measures for some of the requirements but not all the 

requirements. APPA states that NERC should be directed to include Measures related to 

Requirements R4, R5, R6, R7 and R9.1. 

(a) Commission Determination

582. The Commission finds that the issues raised by ISO-NE should be addressed 

through the Reliability Standards development process. As to FirstEnergy’s concern with 

Requirement R1, the reliability coordinator has the highest level of authority. 

Accordingly, the Commission directs that the ERO, through the Reliability Standards 

development process, address ISO-NE’s concern. Further, we direct the ERO to consider 

adding Measures and Levels of Non-Compliance in the Reliability Standard. 

v. Summary of Commission Determination

583. Accordingly, the Commission approves Reliability Standard EOP-002-2 as 

mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 

39.5(f) of our regulations, the Commission directs the ERO to develop a modification to 

EOP-002-2 through the Reliability Standards development process that: (1) addresses 

emergencies resulting not only from insufficient generation but also from insufficient 

transmission capability particularly where this affects the implementation of the capacity 

and energy emergency plan; (2) includes all technically feasible resource options, 

including demand response and generation resources, in the management of emergencies 

and (3) ensures that the TLR procedure is not used to mitigate actual IROL violations. 

c. Load Shedding Plans (EOP-003-1)

584. EOP-003-1 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 
Docket No. RM06-16-000 - 172 - 

Interconnection.245 It includes requirements to establish plans for automatic load 

shedding for underfrequency or undervoltage, manual load shedding to respond to realtime emergencies and communication with other balancing authorities and transmission 

operators. 

585. In the NOPR, the Commission proposed to approve the Reliability Standard as 

mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 

39.5(f) of our regulations, the Commission proposed 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. 

586. Most of the comments address the specific modifications and concerns raised by 

the Commission in the NOPR. Below, we address each topic separately, followed by an 

over-all conclusion and summary. 

i. Minimum load shedding and maximum delay 

(a) Comments

587. FirstEnergy and APPA agree that NERC should modify EOP-003-1 to specify the 

minimum load shedding capability and the maximum amount of delay. However, 

FirstEnergy adds that Requirement R8, which states that load shedding actions must be 

taken in a “time frame adequate for responding to the emergency,” is ambiguous and 

difficult to substantiate. NERC acknowledges that significant improvements can be made 

to the EOP Reliability Standards to establish criteria for the provision of load shedding 

capability, but it states that requiring a specific minimum amount of load (MW) or 

percentage of load that must be capable of being shed and the maximum amount of time 

delay is as likely to reduce reliability as it is to increase it. NERC contends that the 

electric characteristics of local systems and loads must be considered in designing manual 

and automatic load shedding capabilities. Accordingly, it proposes that the Commission 

direct NERC to review industry best practices and propose requirements in the Reliability 

Standards to ensure that adequate load shedding capabilities are provided to protect the 

 245 In its November 15, 2006, filing, NERC submitted EOP-003-1, which 

supercedes the Version 0 Reliability Standard. EOP-003-1 adds Measures and Levels of 

Non-Compliance to the Version 0 Reliability Standard. In this Final Rule, we review the 

November version, EOP-003-1. 
Docket No. RM06-16-000 - 173 - 

Bulk-Power System without causing adverse impacts associated with unnecessary 

shedding of firm load. 

588. SoCal Edison states that in certain circumstances, but not in all cases, it would be 

valuable to have a minimum limit established for the amount of load shedding an entity is 

to accomplish. It suggests that the specific requirements should be derived based on 

studied conditions. 

589. Xcel, ISO-NE, TVA and International Transmission do not support a nationwide 

Reliability Standard for minimum load shedding and maximum delay for implementing 

load shedding because there are large variations in load, resources and system 

configuration and characteristics across the continent. TVA states that these parameters 

should be determined based on studies of the specific transmission systems and 

applicable contingency events. MISO states that it is not clear what is intended or 

achieved by this requirement because balancing authorities and transmission operators 

should already have the ability to shed, by some means, all load within their area and the 

timing requirements are specified in the IROL-related Reliability Standards. 

590. California PUC is concerned that the proposed modification assumes that load 

shedding at the transmission level is the only or the primary way to address system 

emergencies. SDG&E recommends that the maximum delay for shedding load should 

begin when the transmission operator or balancing authority has actual knowledge of the 

circumstances that would precipitate load shedding. 

(b) Commission Determination

591. Shedding of firm load is an operating measure of last resort to contain system 

emergencies and prevent cascading. System operators must have the capability to shed 

load in a timely manner to return the system to a stable condition. The Commission 

disagrees with NERC’s contention that requiring a specific minimum amount of load that 

must be capable of being shed and the maximum amount of delay is as likely to reduce 

reliability as it is to increase it. As stated in the NOPR, the actual amount of load to be 

shed, the location and the time frame will be at the discretion of the system operator 

based on the nature of the system problem and the operator’s assessment of corrective 

actions required.246 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. 

 246 NOPR at P 294. 
Docket No. RM06-16-000 - 174 - 

592. While the Reliability Standard requires transmission operators and balancing 

authorities to be capable of load shedding in a time frame adequate for responding to 

emergencies, this could be clearer, as noted by FirstEnergy. As mentioned by NERC, 

significant improvements can be made to the Reliability Standard to establish criteria for 

the provision of load shedding capability. We agree. 

593. Several commenters state that they do not support a nationwide Reliability 

Standard for minimum load shedding capability and maximum delay in implementing 

load shedding because these parameters are dependent on system configurations and load 

and resource characteristics across the continent, and as such, must be determined based 

on system studies.247 The Commission agrees that the minimum load shedding capability 

must take into account system characteristics and topology, however the maximum time 

delay before load shedding can be implemented is independent of system characteristics 

and is governed by what is considered to be feasible. 

594. California PUC is concerned that the proposed modification on load shedding 

assumes that load shedding at the transmission level is the only or preferred way to 

address system emergencies. The Commission clarifies that this assumption is incorrect 

and agrees with California PUC that load shedding at the distribution level has the 

minimum societal and economic impact. 

595. The Commission concludes that the Reliability Standard needs to be modified to 

ensure that adequate load shedding capabilities are provided so that system operators 

have an effective operating measure of last resort to contain system emergencies and 

prevent cascading. The Commission recognizes that the amount of load shedding 

capability required is dependent on system characteristics and therefore it may not be 

feasible to have a uniform nationwide load shedding capability. This, however, does not 

preclude a uniform nationwide criterion on the methodology for establishing load 

shedding capability that would specify the minimum amount of load shedding capability 

that should be provided based on system characteristics and conditions and the maximum 

amount of delay before load shedding can be implemented. The Commission directs the 

ERO to address the minimum load and maximum time concerns of the Commission 

through the Reliability Standards development process. We suggest that a review of 

industry best practices would be useful in developing nationwide critera. 

 247 See Xcel, ISO-NE, TVA, International Transmission and MISO. 
Docket No. RM06-16-000 - 175 - 

ii. Periodic drills of simulated load shedding

(a) Comments

596. California PUC states that, since load shedding at the distribution level has the 

minimum societal and economic impact, the Reliability Standard should require all 

neighboring distribution or transmission utilities to participate in annual drills when 

requested by an ISO or other bulk power authority. Northern Indiana and FirstEnergy 

support mandating periodic drills of simulated load shedding; however, FirstEnergy 

states that the drill requirements should include simulated load shed via a simulator or 

table-top exercise, not an actual deployment of manpower, and that these drill 

requirements should be included in the PER-005-0 Reliability Standard instead of EOP003-1. PER-005-0 only involves training of control room personnel, whereas these drills 

should also include testing the readiness and functionality of procedures and personnel 

outside of the control room. 

(b) Commission Determination

597. As suggested by California PUC, periodic drills of simulated load shedding should 

involve all participants required to ensure successful implementation of load shedding 

plans. As such, the drills should extend beyond system operators to distribution operators 

and LSEs. The Reliability Standard should require periodic drills by entities subject to 

section 215, and require those entities to seek participation by other entities. The drills 

should test the readiness and functionality of the load shedding plans, including, at times, 

the actual deployment of personnel. Therefore the Commission disagrees with 

FirstEnergy that the requirement for periodic drills of simulated load shedding should be 

incorporated into the new PER-005-0 Reliability Standard that is currently being drafted 

to address operator training. 

iii. Other issues 

(a) Comments

598. Santa Clara states that since automatic load shedding for undervoltage conditions 

is not required in most parts of the West and possibly in other areas of the country, 

Requirement R2 should be modified to include the words “as applicable per the Regional 

Reliability Organization.” In addition, APPA states that NERC should consider requiring 

balancing authorities and transmission operators to expand coordination and planning of 

their automatic and manual load shedding plans to include their respective Regional 

Entities, reliability coordinators and generation owners. ISO-NE proposes that NERC 

establish coordinated trip settings within and among balancing authorities for each 

interconnection. 
Docket No. RM06-16-000 - 176 - 

599. While EEI generally supports the proposed modifications, it believes that the 

proposal for senior management to post letters to safeguard operators who shed load in 

accordance with approved guidelines does not respond to or meet the needs reflected in 

the Blackout Recommendation No. 8. EEI points out that, under other provisions of the 

FPA, the Commission has approved liability limiting provisions for some operators that 

appears to be consistent with the Blackout Report Recommendation No. 8, but has 

rejected other similar protections. EEI requests that the Commission explicitly state that 

transmission operators taking action in compliance with the load shedding provisions of 

Commission approved Reliability Standards will be protected from retaliatory actions, 

including legal actions. 

(b) Commission Determination

600. Regarding Santa Clara’s concern that undervoltage load shedding is not required 

in most parts of WECC and that Requirement R2 should be modified to reflect this, the 

Commission notes that Requirement R2 states that each transmission operator and 

balancing authority shall establish plans for automatic load shedding for underfrequency 

or undervolatge conditions. The Commission clarifies that the Reliability Standard does 

not mandate undervoltage load shedding unless needed for Reliable Operation. 

601. We also note that APPA and ISO-NE raise issues regarding coordination of trip 

settings and automatic and manual load shedding plans. The Commission directs the 

ERO to consider these comments in future modification to the Reliability Standard 

through the Reliability Standards development process. 

602. EEI seeks adoption of a provision to shield transmission operators from liability 

when they take action in compliance with the load shedding provisions of the Reliability 

Standards. Consistent with our discussion of Blackout Report Recommendation No. 8 in 

the Common Issues section of this Final Rule, the Commission will not adopt new 

liability protections.248 According to the Task Force, no further action is needed to 

implement that recommendation because some states already have appropriate protection 

against liability suits.249 Further, in Order No. 890, we have already declined to provide a 

uniform federal liability standard. 

 248 See Common Issues Pertaining to Reliability Standards: Blackout Report 

Recommendation on Liability Limitations, supra section II.E.1. 

249 US-Canada Power System Outage Task Force, Final Report on Implementation 

of Task Force Recommendations at 22 (Oct. 3, 2006), available at 

http://www.oe.energy.gov/news/blackout.htm (“In the United States, some state 

(continued) 
Docket No. RM06-16-000 - 177 - 

iv. Summary of Commission Determination

603. The Commission approves proposed Reliability Standard EOP-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 directs the ERO to develop a modification 

to EOP-003-1 through the Reliability Standards development process that: (1) includes a 

requirement to develop specific minimum load shedding capability that should be 

provided and the maximum amount of delay before load shedding can be implemented 

based on an overarching criteria that take into account system characteristics and 

(2) requires periodic drills of simulated load shedding. 

d. Disturbance Reporting (EOP-004-1)

604. EOP-004-1 establishes requirements for reporting system disturbances to the 

regional reliability organization and the ERO.250 It also establishes requirements for the 

analysis of these disturbances. 

605. In the NOPR, the Commission proposed to approve the Reliability Standard as 

mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and 

§ 39.5(f) of our regulations, the Commission proposed to direct that NERC submit a 

modification to the Reliability Standard 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. 

i. Comments

606. EEI and FirstEnergy support the Commission’s proposed modifications to the 

Reliability Standard. EEI states that data reporting requirements and other process 

requirements should be contained in enforceable Reliability Standards. FirstEnergy 

states that the proposed modification corresponds to good utility practice and that 

 

regulators have informally expressed the view that there is appropriate protection against 

liability suits for parties who shed load according to approved guidelines.”) 

250 In its November 15, 2006, filing, NERC submitted EOP-004-1, which 

supercedes the Version 0 Reliability Standard. EOP-004-1 adds Measures and Levels of 

Non-Compliance to the Version 0 Reliability Standard. In this Final Rule, we review the 

November version, EOP-004-1. 
Docket No. RM06-16-000 - 178 - 

explicitly stating the requirement to provide data to NERC brings clarity to the 

expectations of NERC and the Commission. 

607. APPA is concerned about the scope of Requirement R2 because, in its opinion, 

Requirement R2 appears to impose an open-ended obligation on entities such as 

generation operators and LSEs that may have neither the data nor the tools to promptly 

analyze disturbances that could have originated elsewhere. APPA proposes that 

Requirement R2 be modified to require affected entities to promptly begin analyses to 

ensure timely reporting to NERC and DOE. 

608. Xcel expresses concern regarding what constitutes a reportable event for each 

applicable entity and recommends that the Reliability Standard be revised to define what 

a reportable event is for each entity that has reporting obligations. Further, Xcel states 

that the requirement in Requirement R3.4 for a final report within 60 days may not be 

feasible given the current WECC process, which among other things, requires the 

creation of a group to prepare the report and a 30-day posting of a draft report before it 

becomes final. Xcel also states that if the ultimate purpose of the report is to provide 

information to avoid a recurrence of a system disturbance, then the Reliability Standard 

should be revised to require the distribution of the report to similarly situated entities. 

609. FirstEnergy states that, since nuclear units have their own NRC reporting 

procedures covering the Requirements under EOP-004-1, the Reliability Standard should 

specify that compliance with such operating procedures is sufficient to satisfy the 

requirements of EOP-004-1. FirstEnergy also states that the title of this Reliability 

Standard should be changed to “Disturbance Event Reporting” to indicate that the events 

covered under this Reliability Standard include a broad range of events that go beyond 

the events for which reports may be required under Reliability Standard BAL-002-0. 

610. APPA states that NERC’s November 15, 2006 revision partially fulfills the 

proposed modification to include Measures and Levels of Non-Compliance. APPA notes 

that EOP-004-1 did not provide Measures for R2, R3.2, R3.4, R4 and R5. 

ii. Commission Determination

611. Complete and timely data is essential for analyzing system disturbances. In the 

NOPR, the Commission proposed modifying this disturbance Reporting Standard to 

include requirements necessary for users, owners and operators of the Bulk-Power 

System to provide disturbance data, voice recordings and other information collected 

during the disturbance to assist NERC in the investigation of the blackout or 
Docket No. RM06-16-000 - 179 - 

disturbance.251 While some commenters agree with this proposal, APPA and Xcel 

express concerns regarding the scope and applicability of some of the Requirements of 

the Reliability Standard. 

612. Requirement R2 of the Reliability Standard requires reliability coordinators, 

balancing authorities, transmission operators, generator operators and LSEs to promptly 

analyze disturbances on their system or facilities. APPA is concerned that generator 

operators and LSEs may be unable to promptly analyze disturbances, particularly those 

disturbances that may have originated outside of their systems, as they may have neither 

the data nor the tools required for such analysis. The Commission understands APPA’s 

concern and believes that, at a minimum, generator operators and LSEs should analyze 

the performance of their equipment and provide the data and information on their 

equipment to assist others with their analyses. The Commission directs the ERO to 

consider this concern in future revisions to the Reliability Standard through the 

Reliability Standards development process. 

613. The Commission disagrees with Xcel that the Reliability Standard is unclear about 

what constitutes a reportable event. Attachment 1 of the Reliability Standard details the 

various events that would trigger the reporting requirement under this Reliability 

Standard. 

614. FirstEnergy states that since nuclear units have their own NRC reporting 

requirements the Reliability Standard should specify that compliance with NRC 

procedures is sufficient to satisfy the obligations of this Reliability Standard. The 

Commission disagrees with FirstEnergy because there are situations where the ERO 

Reliability Standards are more stringent than the NRC procedures. In such cases, the 

ERO Reliability Standards must apply in addition to the NRC requirements. Also, the 

Commission disagrees with FirstEnergy’s comment on changing this Reliability 

Standard’s name to avoid confusion with BAL-002-0. The purpose of the Reliability 

Standard is clear as to the extent of the disturbances to be reported. 

615. The Commission declines to address Xcel’s concerns about the current WECC 

process. These issues should be addressed in the Reliability Standards development 

process or submitted as a regional difference. The Commission directs the ERO to 

consider all comments in future modifications of the Reliability Standard through the 

Reliability Standards development process. 

 251 NOPR at P 304. 
Docket No. RM06-16-000 - 180 - 

616. In response to APPA’s concern that NERC did not provide a Measure for each 

Requirement, we reiterate that it is in the ERO’s discretion whether each Requirement 

requires a corresponding Measure. The ERO should consider this issue through the 

Reliability Standards development process. 

617. While the Commission has identified concerns with regard to EOP-004-1, we 

believe that the proposal serves an important purpose in establishing requirements for 

reporting and analysis of system disturbances. Accordingly, the Commission approves 

Reliability Standard EOP-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 directs the 

ERO to develop a modification to EOP-004-1 through the Reliability Standards 

development process that 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 

618. Requirement R3 addresses the reporting of disturbances to the regional reliability 

organizations and NERC. The Commission directs the ERO to change its Rules of 

Procedure to assure that the Commission also receives these reports within the same time 

frames as DOE. 

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

619. EOP-005-1 deals with system restoration plans and requires that plans, procedures, 

and resources be available to restore the electric system to a normal condition in the event 

of a partial or total system shut down. The Reliability Standard requires transmission 

operators, balancing authorities, and reliability coordinators to have effective restoration 

plans, to test those plans, and to be able to restore the interconnection using them 

following a blackout. It also requires operating personnel to be trained in these plans. 

620. In the NOPR, the Commission proposed to approve Reliability Standard EOP005-1 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the 

FPA and § 39.5(f) of our regulations, the Commission proposed 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. 

i. Comments

621. APPA and EEI state that Reliability Standard EOP-005-1 is sufficient for approval 

as a mandatory Reliability Standard and requests that the Commission direct NERC to 

address missing Measures and training requirements. In addition, APPA notes that the 

Reliability Standard is applicable to both balancing authorities and transmission operators 
Docket No. RM06-16-000 - 181 - 

but the Measures and Levels of Non-Compliance elements refer only to transmission 

operators. 

622. ISO-NE does not support adoption of the proposed Reliability Standard because, 

while Requirement R1 requires transmission operators to include applicable elements 

from Attachment 1 of EOP-005-1 in their restoration plans, Requirement R1 appears to 

indicate that the elements in Attachment 1 are to be included in the emergency plan only 

“as applicable.” ISO-NE states that the Reliability Standard should be clarified to 

indicate that the actual emergency plan elements should be the basis for compliance. 

623. EEI and FirstEnergy note that the proposed modification to identify time frames 

for training and review of restoration plan requirements is being addressed in the 

proposed Reliability Standard PER-005-1 and that including this requirement in EOP005-1 would be redundant. MISO also believes that the proposed modification is 

unnecessary. It states that there are already requirements for simulation-based training on 

emergencies and restoration and it is unclear what is meant by conducting training to 

prepare operators for unforeseen events. 

624. FirstEnergy states that Requirement R1 calls for a plan for a partial shutdown of 

the system and that there is an infinite set of events that can cause a partial shutdown. 

According to FirstEnergy, because the borders of a partial shutdown are difficult, if not 

impossible, to foresee, the Reliability Standard should specify some boundaries for 

analysis of partial shutdowns including an appropriate definition of the term “partial 

shutdown.” In addition, FirstEnergy states that one uniform plan for all systems is not 

feasible; rather the Reliability Standard should recognize that some companies already 

have existing plans that could be used for analyzing events. FirstEnergy also states that 

the Reliability Standard should provide a uniform checklist of factors to analyze, 

developed on a company-specific basis. 

625. NRC suggests that this Reliability Standard include: (1) a requirement to record 

the time it takes to restore power to the auxiliary power systems of nuclear power plants; 

(2) a provision stating that the affected transmission operators shall give high priority to 

restoration of off-site power to nuclear power plants whether or not a nuclear power plant 

is being powered from the nuclear power plant’s onsite power supply and (3) a provision 

stating that restoration shall not violate nuclear power plant minimum voltage and 

frequency requirements. 

626. While not commenting on the substance of Reliability Standard EOP-005-1, MRO 

states that EOP-005-1, EOP-006-1 and EOP-007-0 are ordered in a confusing manner and 

should be renumbered. MRO reasons that since the regional coordinator has oversight 

responsibility for system restoration, EOP-006-1 should be first in the system restoration 

sequence of Reliability Standards (i.e., EOP-006-1 should precede EOP-005-1). Further, 
Docket No. RM06-16-000 - 182 - 

MRO recommends that EOP-005-1 follow EOP-006-1 because transmission owners and 

balancing authorities are responsible for submitting restoration plans to the regional 

coordinator. MRO requests that if a reason exists for the current order, NERC should 

provide that reason to the Commission. 

ii. Commission Determination

627. With regard to comments that the Commission’s concerns are being addressed in 

NERC’s drafting of proposed PER-005-1 Reliability Standard on operator training, we 

note PER-005-1 only includes Requirements on the control room personnel and not those 

outside of the control room. System restoration requires the participation of not only 

control room personnel but also those outside of the control room. These include 

blackstart unit operators and field switching operators in situations where SCADA 

capability is unavailable. As such, the Commission believes that inclusion of periodic 

system restoration drills and training and review of restoration plans in a system 

restoration Reliability Standard is the most effective way of achieving the desired goal of 

ensuring that all participants are trained in system restoration and that the restoration 

plans are up to date to deal with system changes. 

628. Several commenters raise issues that should be addressed by the ERO through the 

Reliability Standards development process.252 For example: whether the Measures and 

Levels of Non-Compliance should refer to balancing authorities; clarification of the 

elements that form the basis for compliance with the requirements of Attachment 1; what 

constitutes a partial shutdown for which restoration plans must be developed and 

recognition that some companies already have existing plans that could be used for 

analyzing events; and that the Reliability Standard should provide a uniform checklist of 

factors to analyze, developed on a company-specific basis. We find that consideration of 

these issues could be helpful in meeting the objectives of the Reliability Standard. 

Accordingly, the ERO should consider these concerns in future revisions of the 

Reliability Standard through the Reliability Standards development process. 

629. NRC raises several issues concerning the role and priority that nuclear power 

plants should have in system restorations. The Commission shares these concerns and 

directs the ERO to consider the issues raised by NRC in future revisions of the Reliability 

Standard through the Reliability Standards development process. In addition the 

Commission directs the ERO to gather data, pursuant to § 39.5(f) of the Commission’s 

regulations, from simulations and drills of system restoration on the time it takes to 

 252 See APPA, ISO-NE, FirstEnergy and MRO. 
Docket No. RM06-16-000 - 183 - 

restore power to the auxiliary power systems of nuclear power plants under its data 

gathering authority and report that information to the Commission on a quarterly basis. 

630. We find that the Reliability Standard adequately addresses operating personnel 

training and system restoration plans to ensure that transmission operators, balancing 

authorities and reliability coordinators are prepared to restore the Interconnection 

following a blackout. Accordingly, the Commission approves Reliability Standard EOP005-1 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the 

FPA and § 39.5(f) of our regulations, the Commission directs the ERO to develop a 

modification to EOP-005-1 through the Reliability Standards development process that 

identifies time frames for training and review of restoration plan requirements to simulate 

contingencies and prepare operators for anticipated and unforeseen events and gathers the 

data from simulations and drills of system restoration on the time it takes to restore power 

to the auxiliary power systems of nuclear power plants under its data gathering authority 

and report that information to the Commission on a quarterly basis. 

f. Reliability Coordination-System Restoration (EOP-006-1)

631. Proposed Reliability Standard EOP-006-1 addresses reliability coordination and 

system restoration.253 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. 

632. In the NOPR, the Commission proposed to approve the Reliability Standard as 

mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and 

§ 39.5(f) of our regulations, the Commission proposed to direct that NERC submit a 

modification to the Reliability Standard that: (1) requires that the reliability coordinator 

be involved in the development of and approves restoration plans and (2) includes 

Measures and Levels of Non-Compliance. 

i. Comments

633. APPA states that Reliability Standard EOP-006-1, which NERC filed on 

November 15, 2006, includes the required Measures and Levels of Non-Compliance and 

 253 In its November 15, 2006, filing, NERC submitted EOP-006-1, which 

supercedes the Version 0 Reliability Standard. EOP-006-1 adds Measures and Levels of 

Non-Compliance to the Version 0 Reliability Standard. In this Final Rule, we review the 

November version, EOP-006-1. 
Docket No. RM06-16-000 - 184 - 

as such APPA agrees that EOP-006-1 should be approved as mandatory and enforceable. 

In addition, APPA does not oppose industry consideration of a requirement that 

reliability coordinators be involved in the development and approval of restoration plans. 

634. EEI states that Requirements R4 and R11 of EOP-005-1 already address reliability 

coordinator involvement in the development and approval of transmission operator 

system restoration plans. Further, while EEI agrees that the reliability coordinator’s role 

is appropriate, it believes that the asset owner, as the entity that ultimately bears 

responsibility for restoration capabilities, should also have authority to develop and 

maintain the plans. MISO believes that it is unnecessary to modify the Reliability 

Standard to involve the reliability coordinator because there is already a requirement in 

EOP-005-1 for balancing authorities and transmission operators to coordinate their plans 

with the reliability coordinator. 

635. Xcel disagrees that the reliability coordinator should be involved with the 

development of restoration plans because the reliability coordinator typically does not 

have the knowledge of the details necessary to develop the plans in contrast to the 

balancing authorities and the transmission operators. Instead it proposes that the 

reliability coordinator develop its own plans and coordinate that with the balancing 

authority and transmission operator’s plans. 

ii. Commission Determination

636. The reliability coordinator is the highest level of authority that is responsible for 

the reliable operation of the Bulk-Power System. Given the importance of this role in 

connection with matters covered by EOP-006-1, the Commission believes that the 

reliability coordinator must be involved in the development and approval of the 

restoration plans. The current Reliability Standard only requires that the reliability 

coordinator be aware of the restoration plan of each transmission operator in its area. The 

Commission disagrees with EEI and MISO who contend that the reliability coordinator’s 

role in the transmission operator’s restoration plan is covered in EOP-005-1. EOP-005-1 

only requires coordination with the reliability coordinator, and during actual system 

restoration, EOP-005-1 requires approval from the reliability coordinator to 

resynchronize isolated areas with other isolated areas. 

637. In response to comments by Xcel, the Commission believes that while the 

reliability coordinator may not have the level of detailed knowledge that the balancing 

authorities and transmission operators may have for setting-up the stable islands required 

under restoration plans, the reliability coordinator is in the best position to determine how 

those stable islands should be resynchronized with each other and the rest of the 

interconnected system. 
Docket No. RM06-16-000 - 185 - 

638. The Commission finds that the Reliability Standard adequately addresses the goals 

of effective and efficient reliability coordination and system restoration. Accordingly, 

the Commission approves Reliability Standard EOP-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 directs the ERO to develop a modification to EOP-006-1 through the 

Reliability Standards development process that ensures that the reliability coordinator, 

which is the highest level of authority responsible for reliability of the Bulk-Power 

System, is involved in the development and approval of system restoration plans. 

g. Establish, Maintain, and Document a Regional Blackstart 

Capability Plan (EOP-007-0)

639. 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. 

640. The NOPR did not propose to approve or remand EOP-007-0, because it applies 

only to regional reliability organizations. 

i. Comments

641. APPA agrees that EOP-007-0 should not be approved as a mandatory Reliability 

Standard and states that in the interim the regional reliability organizations and Regional 

Entities should continue to perform this function. In addition, APPA proposes that, in the 

interim, an umbrella organization composed of representatives from each regional 

reliability organization and Regional Entity should be formed to establish operation 

planning rules, including blackstart requirements, across the Eastern Interconnection. 

APPA suggests that such an effort would go a long way in identifying critical facilities, 

using consistent and transparent study assumptions and minimizing seams during system 

emergencies throughout the Interconnection. 

642. TANC states that the number of blackstart units and their locations depend heavily 

on regional characteristics and cannot be prescribed in a uniform, continent-wide manner. 

It proposes that regional flexibility be afforded to provide an appropriate mix of facilities 

to achieve the reliability objectives. EEI suggests that EOP-007-0 be rewritten so that 

compliance obligations are assigned directly to those entities that provide the data and 

other information. 

643. FirstEnergy and MRO state that the reliability coordinator, not the Regional 

Entity, should be responsible for the regional blackstart plan for its area of responsibility. 

Further, FirstEnergy states that the blackstart plan developed for a region should be 
Docket No. RM06-16-000 - 186 - 

consistent with NRC requirements, should recognize that nuclear units have no blackstart 

capability and should recognize that nuclear units must have priority access to off-site 

power for safety reasons. FirstEnergy requests that the Commission direct NERC to 

revise the definition of a blackstart unit to mean a “diesel, hydro, pump storage, or the 

combustion turbine generating unit that is used to provide cranking power to a larger 

steam generating unit designed to restore load” or to mean a “larger steam generating unit 

designed to restore load.”254 MRO states that arrangements for coordination of blackstart 

capability should be addressed in a contract between appropriate entities. 

ii. Commission Determination

644. The Commission will not approve or remand EOP-007-0, because it applies only 

to regional reliability organizations. However, the Commission provides guidance for the 

ERO’s future consideration. 

645. The Commission disagrees with APPA that an umbrella organization is needed for 

the Eastern Interconnection while the Reliability Standard is pending final approval. The 

Commission is persuaded that FirstEnergy’s and MRO’s comments concerning the 

reliability coordinator being responsible for regional blackstart plans have merit. The 

Commission has directed that the reliability coordinator approve the system restoration 

plans and this is a logical extension of that direction. However, until such time as the 

Reliability Standard has been revised and approved by the ERO and the Commission, the 

regional reliability organization (or Regional Entity, depending on the organization of a 

particular region) should continue to perform this role as it has in the past.255 

646. With regard to TANC’s request for regional flexibility in determining the 

appropriate mix of facilities needed to achieve the reliability objectives, it is our 

understanding that the Reliability Standard provides for the number and location of 

blackstart units to vary depending on the specific requirements of each system. We 

believe that uniformity will be required, however, in the criteria used to determine the 

number and location of blackstart units and testing requirements. 

647. EEI, FirstEnergy and MRO offer suggestions for improving the Reliability 

Standard. The Commission directs the ERO to consider these suggestions in future 

revisions to improve EOP-007-0, through the Reliability Standards development process. 

 254 See FirstEnergy at 35. 

255 See NOPR at P 328. 
Docket No. RM06-16-000 - 187 - 

648. Accordingly, the Commission will not approve or remand EOP-007-0 at this time. 

h. Plans for Loss of Control Center Functionality (EOP-008-

0)

649. EOP-008-0 addresses plans for loss of control center functionality. It requires 

each reliability coordinator, transmission operator and balancing authority to have a plan 

to continue reliable operations and to maintain situational awareness in the event its 

control center is no longer operable. 

650. The Commission proposed five modifications to the Reliability Standard and 

requested additional comments on other issues. We have grouped the comments into two 

general categories: (1) capabilities of backup control centers and (2) which entities should 

have full backup centers. Below, we address each topic separately, followed by an overall conclusion and summary. 

i. Capabilities of backup control centers

651. In the NOPR, the Commission proposed to approve Reliability Standard EOP008-0 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the 

FPA and § 39.5(f) of our regulations, the Commission proposed to direct that NERC 

submit a modification to EOP-008-0 that includes a Requirement that provides for 

backup capabilities that, 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.256 In addition to these three capabilities requirements, the 

Commission solicited comments concerning other specific capabilities. 

(a) Comments

652. EEI, Entergy, FirstEnergy and Northern Indiana support the proposed 

modifications to EOP-008-0. Entergy agrees with the Commission’s proposed 

modifications to include more Requirements regarding backup capabilities. 

653. APPA, Nevada Companies and TAPS caution that costs must be considered and 

compared to possible benefits. APPA states that it would take some time to implement 

the proposed modifications and therefore specific requirements for backup control 

 256 The term “facility” in this context includes, but is not limited to, 

telecommunications, backup power supplies, computer systems and security systems. 

NOPR at P 335 & n.159. 
Docket No. RM06-16-000 - 188 - 

facilities and capabilities should be left to the Reliability Standard development process. 

Nevada Companies cautions that utilities that have invested millions of dollars in back-up 

capabilities may find these facilities to be non-compliant with the proposed Reliability 

Standard. It suggests that cost/benefits analyses be conducted and that a grandfathering 

provision be adopted to protect investments in backup systems that were made in a good 

faith effort to comply with rules in place in the past, but which may not comply with the 

Reliability Standard. 

654. MRO requests clarification of the term “capability” because it is unsure if the term 

is intended to refer to a facility, what such a facility should consist of and what operators 

should be capable of doing from that facility. 

655. In response to the request for comments on backup capabilities, NERC states that 

these are best addressed through the Reliability Standards development process. 

656. SoCal Edison suggests that a risk-based assessment be considered to determine the 

requirements for backup. MISO, TAPS and International Transmission note that work is 

underway by NERC to address the provisions for redundancy and backup control 

capabilities via the Operating Committee Backup Control Task Force and that the focus 

is on functionality rather than physical requirements. TAPS states that, rather than 

directing NERC to adopt specific modifications to the Reliability Standard that would 

inappropriately burden small systems with the cost of dual facilities, the Commission 

should identify objectives to the Task Force. TAPS also states that a small balancing 

authority might be able to meet the functional requirements for a backup control center 

with a contract with another entity while larger entities might need a physical backup 

center. 

657. Northern Indiana states that the Commission’s proposal appears to eliminate an 

entity’s opportunity to contract for backup capabilities from others who already have full 

backup control centers. FirstEnergy and Northern Indiana advocate for flexibility in the 

means used to meet the backup requirements and request that the Commission clarify that 

a “full backup center” can include providing full redundancy by contract rather than 

physical backup center facilities. SoCal Edison states that when entities utilize the 

services of another entity for backup, they should be required to test the backup 

capability a minimum number of times during the year and that all system operators 

should be required to participate in such testing over a specified time period. 

658. NRC suggests that this Reliability Standard require: (1) a list of the nuclear power 

plants and their voltage, thermal, and/or frequency limits and (2) provisions to notify 

nuclear power plants of the loss of control center functionality. 
Docket No. RM06-16-000 - 189 - 

(b) Commission Determination

659. As we stated in the NOPR, the goal of the Reliability Standard is the continuation 

of reliable operations and the maintenance of situational awareness in the event that the 

primary control center is no longer operational.257 Some commenters support the 

proposal to require backup capabilities while others including APPA, Nevada Companies 

and TAPS caution that the cost of the proposal may not be justified. In addition, some 

commenters, including FirstEnergy and Northern Indiana, advocate for flexibility in 

meeting the backup requirements and suggest that entities should be able to contract for 

full redundancy. MRO seeks clarification regarding the use of the term “capability.” 

660. In the NOPR, we found that the provision of backup capabilities should be an 

explicit Requirement to meet the objectives of the Reliability Standard. We chose to use 

the word “capabilities” to avoid defining particular facilities or preclude other options, 

including arranging for backup capabilities by contracting with others. We stated that the 

mechanism to provide these capabilities may include building fully redundant physical 

backup control centers, contracting for backup control services or using backup 

equipment within a separate existing facility.258 In addition, regardless of the means used 

to provide the backup capabilities, as we stated in the NOPR, the time period for which 

backup capability is required should correspond to the time it would take to replace the 

primary control center. 

661. On the issue of additional backup capabilities, NERC, MISO, TAPS and 

International Transmission propose that the functional requirements for backup 

capabilities be determined by the NERC Backup Control Task Force. NRC offers 

requirements it believes should be added to the Reliability Standard. 

662. The Commission disagrees with the Nevada Companies’ proposal for 

grandfathering. The Reliability Standards must define the minimum functions that are 

necessary for the Reliable Operation of the Bulk-Power System. The flexibility 

described above on how capabilities are provided should mitigate any costs incurred to 

upgrade older centers. 

663. Given the importance to reliability of maintaining situational awareness in the 

event of loss of the primary control center operations, the Commission believes that, at a 

minimum, the three requirements — independence from the primary control center, 

 257 NOPR at P 329. 

258 See Id. at P 336. 
Docket No. RM06-16-000 - 190 - 

capability to operate for a prolonged period corresponding to the time it would take to 

replace the primary control center, and the provision of a minimum set of tools and 

facilities to replicate the critical reliability functions of the primary control center – must 

be included as explicit requirements in the Reliability Standard. Other additional 

Requirements may be developed by the Backup Control Task Force for inclusion in the 

Reliability Standard. The Commission directs the ERO to develop modifications to the 

requirements in future revisions to the Reliability Standard through the Reliability 

Standards development process. 

ii. Which entities should have full backup centers 

664. In the NOPR , the Commission proposed to direct that NERC submit a 

modification to EOP-008-0 that: (1) provides 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 and (2) includes a Requirement that all reliability 

coordinators have full backup control centers. The Commission also requested comments 

on what other entities, such as balancing authorities and large transmission operators, 

should have full backup centers. 

(a) Comments

665. International Transmission, MISO and FirstEnergy state that in addition to 

reliability coordinators, large balancing authorities and transmission operators need full 

backup control centers. MISO states that there are certain situations where large 

generation fleets that are controlled centrally would also warrant full backup systems and 

that small entities can operate reliably with less robust systems. Further, it argues that the 

ERO needs latitude to decide from a reliability standpoint how much redundancy is 

needed. FirstEnergy states that in place of full backup control facilities it should be 

acceptable to have standing contracts in place to provide backup services in the event of a 

loss of a control center. 

666. NERC states that the proposed directive presumes that the only way to achieve 

highly reliable and independent backup capability to perform reliability coordinator 

functions in an emergency is to have a redundant control center. NERC contends that 

while this may be an option, it may not be the only one for achieving the necessary 

reliability objective. NERC proposes that the Reliability Standard be modified to define 

the performance results expected rather than how an entity should meet the requirements. 

667. NERC, SoCal Edison and Otter Tail state that the question of what other entities 

should have full backup centers is best addressed through the Reliability Standards 

development process. Otter Tail requests that the Commission not require all balancing 

authorities to have full backup centers since the loss of a small balancing authority’s 
Docket No. RM06-16-000 - 191 - 

control center would not have a substantial impact on the reliability of the Bulk-Power 

System. Northern Indiana states that requiring transmission operators and balancing 

authorities to have full backup centers would result in significant unnecessary facility 

duplication, at great cost to consumers, and without a material increase in reliability. 

668. FirstEnergy comments that the Reliability Standard should not require a fully 

redundant SCADA system for the backup control center for balancing authorities or 

transmission operators because the cost would be prohibitive. It states that balancing 

authorities, transmission operators and centrally-located generation owners should be 

permitted to have a single distributed computer system in place to diminish the 

probability of a complete system shutdown due to a natural disaster or a single man-made 

physical act of sabotage. 

669. Nevada Companies also questions whether the significant cost of full replication 

could ever be cost-effective, especially considering the very high level of control center 

reliability achieved now with the existing solution of a single control center plus backup 

of critical systems. 

(b) Commission Determination

670. Several commenters agree with the Commission that reliability coordinators at a 

minimum should have full backup control centers. They also propose that this 

requirement be extended to large balancing authorities, transmission operators and 

centrally dispatched generation facilities. Others caution on the cost implications of 

requiring full duplication given the very high level of control center reliability achieved 

with the existing technology and backup of critical systems. Having carefully considered 

all the issues raised by commenters and taking into account the reliability impacts of loss 

of primary control centers and the role of reliability coordinators as the highest level of 

authority responsible for reliability of the Bulk-Power System, the Commission is 

persuaded that all reliability coordinators must have fully redundant independent backup 

control centers. In response to NERC, any proposed modification that is independent 

from the primary center, provides for continuous monitoring and has the full functionality 

of the primary center would satisfy our concerns. Other entities, including balancing 

authorities, transmission operators and centrally dispatched generation control centers, 

must provide for the minimum backup capabilities discussed above but may do so 

through other means, such as contracting for these services instead of through dedicated 

backup control centers. 

671. In addition, in response to FirstEnergy’s concern regarding balancing authorities 

and transmission operators having fully redundant SCADA systems and distributed 

computer systems, the Commission requires the primary and backup capabilities to 

replicate critical reliability functionalities and be independent from the primary control 
Docket No. RM06-16-000 - 192 - 

center, including telemetered data and control from remote terminal units. This can be 

achieved through a variety of design alternatives, e.g., developing a SCADA 

management platform that will allow telemetered data and control to be shared among 

SCADA systems so that data and control is not lost during a SCADA or communications 

failure.. The Commission’s focus is on function, not design. 

iii. Summary of Commission Determination

672. Accordingly, the Commission approves Reliability Standard EOP-0081-0 as 

mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and 

§ 39.5(f) of our regulations, the Commission directs the ERO to develop a modification 

to EOP-008-0 through the Reliability Standards development process that includes a 

Requirement that provides for backup capabilities that, at a minimum, must: (1) be 

independent of the primary control center; (2) be capable of operating for a prolonged 

period of time, generally defined by the time it takes to restore the primary control center; 

(3) provide for a minimum functionality to replicate the critical reliability functions of the 

primary control center; (4) provides 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; (5) includes a Requirement that all reliability coordinators have full 

backup control centers and (6) requires transmission operators and balancing authorities 

that have operational control over significant portions of generation and load to have 

minimum backup capabilities discussed above but may do so through contracting for 

these services instead of through dedicated backup control centers. 

i. Documentation of Blackstart Generating Unit Tests 

Results (EOP-009-0)

673. Proposed Reliability Standard EOP-009-0 deals with documentation of blackstart 

generating unit test results. In the NOPR, the Commission proposed to approve EOP009-0 as mandatory and enforceable without modifications. 

i. Comments

674. APPA agrees that EOP-009-0 is sufficient for approval as a mandatory and 

enforceable Reliability Standard. Xcel states that the Reliability Standard should provide 

details on what constitutes a blackstart test and FirstEnergy states that EOP-009-0 should 

be consolidated with EOP-007-0 because the Requirements of EOP-009-0 already exist 

in EOP-007-0. 
Docket No. RM06-16-000 - 193 - 

ii. Commission Determination

675. The Commission believes that this Reliability Standard sufficiently addresses 

documentation of blackstart generating unit test results. Accordingly, the Commission 

approves Reliability Standard EOP-009-0 as mandatory and enforceable. 

676. Two commenters made suggestions for improving the Reliability Standard. The 

Commission directs the ERO to take these suggestions into consideration when revising 

the Reliability Standard through the Reliability Standards development process. 

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

Transfer Capabilities

677. The nine Facility (FAC) Reliability Standards address topics such as facility 

connection requirements, facility ratings, system operating limits and transfer 

capabilities. The FAC Reliability Standards also establish requirements for maintaining 

equipment and rights-of-way, including vegetation management. The NOPR provided 

direction for seven of the nine FAC Reliability Standards; NERC withdrew two others, 

Reliability Standards FAC-004-0 and FAC-005-0. NERC, in its November 15, 2006 

filing requests approval of three additional FAC Reliability Standards: FAC-010-0, FAC011-0 and FAC-014-0. These Reliability Standards are being addressed in a separate 

docket. 

a. Facility Connection Requirements (FAC-001-0)

678. 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. In the NOPR, the Commission proposed to approve 

FAC-001-0 as mandatory and enforceable. 

i. Comments

679. APPA agrees with the Commission’s proposal to approve FAC-001-0 as 

mandatory and enforceable. 

ii. Commission Determination

680. As discussed in the NOPR, the Commission believes that Reliability Standard 

FAC-001-0 is just, reasonable, not unduly discriminatory or preferential and in the public 

interest and approves it as mandatory and enforceable. 
Docket No. RM06-16-000 - 194 - 

b. Coordination of Plans for New Generation, Transmission, 

and End-User Facilities (FAC-002-0)

681. Proposed Reliability Standard FAC-002-0 requires that each generation owner, 

transmission owner, distribution provider, LSE, transmission planner and planning 

authority assess the impact of integrating generation, transmission and end-user facilities 

into the interconnected transmission system. 

682. In the NOPR, the Commission proposed to approve Reliability Standard FAC002-0 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the 

FPA and § 39.5(f) of our regulations, the Commission proposed to direct that NERC 

submit a modification to FAC-002-0 that amends Requirement R1.4 to require evaluation 

of system performance under both normal and contingency conditions by referencing 

TPL-001 through TPL-003. 

i. Applicability and Assessment Responsibility

(a) Comments

683. APPA, Xcel and FirstEnergy state that this Reliability Standard is not clear about 

who will perform the required assessment and how many assessments are required under 

this Reliability Standard. APPA requests that the Reliability Standard be clarified to state 

that the required assessment must be performed only by the transmission planner and the 

planning authority. Xcel requests that the Commission clarify that only one required 

assessment needs to be done when new facilities are added, and that all the listed entities 

should participate in that single assessment. 

684. FirstEnergy requests that NERC clarify what is considered a new facility and asks 

if, for example, up-rates should be included as new facilities. MRO is concerned that the 

impact of the Commission’s directive is too broad and may have a substantial affect on 

those individual entities that are responsible for performing the studies; MRO asks the 

Commission to clarify FAC-002-0 to the extent necessary, but does not propose a specific 

change. 

685. Six Cities requests that this Reliability Standard clarify that all applicable entities 

must make available data necessary for all other responsible entities to perform the 

required assessment. Six Cities also suggests that the transmission operator be added as 

an entity to which this Reliability Standard is applicable, at least from the perspective that 

it make necessary data available to all other entities responsible for assessment. TAPS 

believes that this Reliability Standard seems to assume that the LSE and distribution 

provider actively participate in planning of new facilities in the Bulk-Power System. 

TAPS states that very few LSEs or distribution providers have the expertise to perform 
Docket No. RM06-16-000 - 195 - 

the tasks outlined in this Reliability Standard and that these two entities provide only 

certain data regarding certain new facilities to some or all of the other entities identified 

in this Reliability Standard. TAPS therefore believes that it would be unreasonable to 

require LSEs to provide the transmission planning evaluations and assessments called for 

by R1. California Cogeneration believes that the Reliability Standard implies that 

generator owners will perform an independent assessment and if so, it believes that such 

task is impossible, since generators do not have the relevant information about the power 

system to perform such evaluations. California Cogeneration believes that the Reliability 

Standard should be clarified so that generator owners cooperate with and provide input to 

the assessment performed by the transmission operator and the balancing authority. 

686. FirstEnergy states that both MISO and PJM already have Large Generator 

Interconnection Procedures (LGIP) in place that provide a formal process that meets the 

requirements listed under R1, and asks that the Commission state that complying with the 

interconnection agreement and/or OATT satisfies this requirement. MISO states that 

their procedures for coordinating plans for new generation, transmission and end-user 

facilities includes modeling of normal system and contingency conditions. 

(b) Commission Determination

687. All of the above commenters request clarification of Requirement R1 in the 

Reliability Standard that states that various functional entities “shall each coordinate and 

cooperate on its assessments with its transmission planner and planning authority.”259 

The Commission believes that all entities listed in the Applicability section have a stake 

in the performance of the system and should have the opportunity to provide input in the 

assessment under R1. The Commission believes that commenters have raised valid 

concerns that, if addressed, would make the Reliability Standard better. The wording 

would allow a number of organizational approaches to achieving the goal of performing 

an analysis. The Commission does not intend to limit which organizational approach is 

used by the entities, only to assure that a single competent and collaborative analysis is 

performed. Therefore, the Commission directs the ERO to address these concerns in the 

Reliability Standards development process. 

688. FirstEnergy asks the Commission to state that complying with MISO’s and PJM’s 

interconnection agreements and/or OATT satisfies requirement R1 under this Reliability 

Standard. We will not make that determination here. If FirstEnergy believes that 

complying with the MISO and PJM interconnection procedures meets the applicable 

 259 FAC-002-0. 
Docket No. RM06-16-000 - 196 - 

Reliability Standards, then it should follow those procedures, it should not be concerned 

about violating the Reliability Standard. 

ii. Standards of Conduct

(a) Comments

689. Xcel and MidAmerican believe that the assessment required under this Reliability 

Standard may conflict with the Commission’s Standards of Conduct260 since the 

assessment requires coordination among several different functional groups within a 

vertically integrated public utility. MidAmerican asserts that, since direct communication 

between the generation and transmission entities would result in more efficient overall 

planning, the Commission should clarify its intended application of Standards of Conduct 

restrictions on joint planning activities. Xcel asks the Commission to clarify that actions 

taken to comply with this Reliability Standard will not result in a transmission provider 

being in violation of the Standards of Conduct. 

(b) Commission Determination

690. The Commission disagrees with MidAmerican and Xcel that this Reliability 

Standard may conflict with the Standards of Conduct. This type of system assessment is 

being performed today with the cooperation of the entities listed in the Applicability 

section. Further, we note that the Standards of Conduct were designed to address such 

interactions. The entities participating in the assessment effort can continue to contribute 

to this assessment and observe the Standards of Conduct at the same time. If any entity 

finds an area where it believes the Standards of Conduct prevent it from cooperating with 

the assessment process, it may seek clarification from the Commission as to whether that 

area of involvement is in conflict with the Standards of Conduct. 

iii. Reference to TPL Reliability Standards

(a) Comments

691. While APPA and EEI agree with the Commission’s proposal to direct NERC to 

submit a modification to FAC-002-0 that amends Requirement R1.4 to require evaluation 

 260 Standards of Conduct for Transmission Providers, Order No. 2004, FERC 

Stats. & Regs., Regulations Preambles ¶ 31,155 (2003), order on reh'g, Order No. 2004-

A, III FERC Stats. & Regs. ¶ 31,161 (2004), order on reh'g, Order No. 2004-B, III FERC 

Stats & Regs. ¶ 31,166 (2004). 
Docket No. RM06-16-000 - 197 - 

of system performance under both normal and contingency conditions by referencing 

TPL-001-0 through TPL-003-0, Entergy disagrees and proposes that evaluation of system 

performance under Reliability Standards TPL-001-0 and TPL-002-0 should be sufficient. 

Entergy states that given the large number of small end-user requests that transmission 

operators may receive, expanding the scope of Requirement R1.4 may lead to additional 

work and documentation that ultimately will not benefit reliability. First Entergy states 

that the proposed reference to TPL Reliability Standards should be expanded to include 

TPL-001-0 through TPL-004-0. 

(b) Commission Determination

692. The Commission notes that APPA and EEI agree with the Commission’s proposed 

directive to NERC to modify FAC-002-0 to require evaluation of system performance 

under both normal and contingency conditions by referencing TPL-001-0 through TPL003-0. The Commission also notes that NERC, in response to the Staff Preliminary 

Assessment, has also agreed with the same proposal.261 These three TPL Reliability 

Standards cover normal operation, first contingency operation and multiple contingency 

operations respectively. The Commission disagrees with Entergy that TPL-001-0 and 

TPL-002-0 are sufficient because it is important to plan for new facilities taking into 

account not only normal circumstances but also contingencies. In addition, we note that 

including TPL-001-0 through TPL-003-0 will result in the FAC-002 Reliability Standard 

being consistent with Order No. 2003, which requires interconnecting entities to take into 

account multiple contingencies in interconnection studies. With respect to FirstEnergy’s 

suggestion to also include a reference to Reliability Standard TPL-004-0, we direct the 

ERO to consider it through the Reliability Standards development process. 

693. Accordingly, the Commission approves 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 directs the ERO to develop a modification 

to FAC-002-0 through the Reliability Standards development process that amends 

Requirement R1.4 to require evaluation of system performance under both normal and 

contingency conditions by referencing TPL-001 through TPL-003. Further, the 

Commission also directs the ERO to consider the above commenters’ concerns through 

the Reliability Standards development process. 

 261 NOPR at P 352. 
Docket No. RM06-16-000 - 198 - 

c. Transmission Vegetation Management Program (FAC003-1)

694. According to NERC, FAC-003-1 is designed to minimize transmission outages 

from vegetation located on or near transmission rights-of-way by maintaining safe 

clearances between transmission lines and vegetation, and establishing a system for 

uniform reporting of vegetation-related transmission outages. FAC-003-1 would apply 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). 

It would require each transmission owner to have a documented vegetation management 

program in place, including records of its implementation. Each program must be 

designed for the geographical area and specific design configurations of the transmission 

owner’s system. 

695. 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 IEEE Standard 516-2003 (IEEE Guide for 

Maintenance Methods on Energized Power Lines).”262

696. In the NOPR, the Commission proposed to approve Reliability Standard FAC003-1 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the 

FPA and § 39.5(f) of our regulations, the Commission proposed to direct NERC to 

submit a modification to FAC-003-1 that: (1) requires the ERO develop a minimum 

vegetation inspection cycle that allows variation for physical differences and (2) removes 

the general limitation on 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 on reliability as determined by the ERO. 

i. Applicability

(a) Comments

697. Entergy agrees with the Commission’s proposal and supports applying the 

Reliability Standard to only those lines that have an impact on reliability as determined 

 262 FAC-003-1 (Requirement R1.2.2). 
Docket No. RM06-16-000 - 199 - 

by the ERO, as supported by reliability studies using consistent reliability contingency 

criteria. 

698. LPPC supports using an impact-based definition of the Bulk-Power System to 

determine applicability and suggests that the definition of significant adverse impact 

should be determined through the NERC process. Further, LPPC asserts that actual 

facilities meeting that criteria should be determined by Regional Entities, which best 

understand the impacts of facilities on the regional system. LPPC notes that Regional 

Entities can continue to use such tools as modeling and power flow analyses to determine 

which facilities are critical to the reliability of the Bulk-Power System. 

699. APPA and Avista believe that Regional Entities should determine what 

transmission facilities this standard applies to, since Regional Entities have detailed 

knowledge regarding the transmission facilities within their regions. APPA would have 

the Regional Entities create a regional Reliability Standard to do so, subject to ERO 

review for reasonableness and consistency. Avista points out that WECC and the other 

Regional Entities have already reviewed and designated critical lower voltage 

transmission facilities, and the Reliability Standards currently apply to such facilities. 

700. MISO asks for clarification with respect to the intent of adding transmission lines 

below 200 kV “that impact reliability” and whether the included lines are IROL-related 

facilities263 or some other facilities. Progress and SERC suggest that it may be 

appropriate to limit the applicability of the Reliability Standard to all lines that are 

operated at 200 kV and above and to operationally significant circuits between 100 kV 

and 200 kV that are elements of IROLs. 

701. California PUC believes that discretion about determining which lines are critical 

to the Bulk-Power System should be left to the individual state (working in concert with 

RTOs and ISOs), which has much greater knowledge of what is needed on the local level, 

rather than to NERC or the Regional Reliability Organization. 

702. Progress, SERC, FirstEnergy and Avista argue that automatically subjecting lines 

below 200 kV to Reliability Standard FAC-003-1 would increase maintenance, 

documentation and reporting costs and impacts to land owners, but would not necessarily 

increase the reliability of the grid. LPPC does not object to eliminating the 200 kV bright 

line threshold, but believes that extending vegetation management practices to all 

facilities of 100 kV and above would unnecessarily extend the scope of the vegetation 

 263 An IROL-related facility is a facility whose outage would result in an 

Interconnection Reliability Operating Limit (IROL) violation. 
Docket No. RM06-16-000 - 200 - 

management requirements, creating large cost increases for many utilities without 

creating a material increase in the reliability of the Bulk-Power System. FirstEnergy 

recommends that if the voltage level is lowered, implementation, especially for reporting 

requirements, should be spread over at least one year. Similarly, Xcel asks the 

Commission to allow flexibility in complying with this Reliability Standard for lowervoltage facilities that previously were not subject to this Reliability Standard. 

703. EEI maintains that not changing this Reliability Standard would best maintain 

reliability, since removing the existing 200 kV threshold requirement could inadvertently 

expose the Bulk-Power System to a new set of risks. SoCal Edison argues that the 

Reliability Standard already covers transmission lines rated less than 200 kV, because 

Requirement 4.3 of FAC-003-1 states that this Reliability Standard “shall apply 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 the reliability of the 

electric system in the region.” 

704. APPA opposes the Commission’s proposal to direct NERC to change the 

applicability of this Reliability Standard. APPA argues that the Commission should deal 

with this concern by having NERC reevaluate the Reliability Standard. National Grid 

argues that expanding the applicability of Reliability Standards would not be appropriate 

because it could dramatically change the meaning of the Reliability Standards and would 

undermine the Reliability Standard development process which yielded the careful 

balances struck in developing the standards. 

705. NERC argues that the Commission’s proposed modification should be vetted 

through the Reliability Standards development process to better understand what will be 

gained in terms of impacts to the reliability of the Bulk-Power System. NERC notes that 

the current applicability of the Reliability Standard to 200 kV and above transmission 

lines was debated extensively by the industry, and any change to this requirement should 

be vetted again. 

(b) Commission Determination

706. We will not direct NERC to submit a modification to the general limitation on 

applicability as proposed in the NOPR. However, we will require the ERO to address the 

proposed modification through its Reliability Standards development process. As 

explained in the NOPR, 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, 

none have designated any operationally significant lines even though there are lower 

voltage lines involving IROL as suggested by Progress and SERC. We continue to be 
Docket No. RM06-16-000 - 201 - 

concerned that this approach will not prospectively result in the inclusion of all 

transmission lines that could impact Bulk-Power System reliability. In proposing to 

require the ERO to modify the Reliability Standard to apply to Bulk-Power System 

transmission lines that have an impact on reliability as determined by the ERO, we did 

not intend to make this Reliability Standard applicable to fewer facilities than it currently 

is with the 200 kV bright line applicability, but to extend the applicability to lowervoltage facilities that have an impact on reliability. We support the suggestions by 

Progress Energy, SERC and MISO to limit applicability to lower voltage lines associated 

with IROL and these suggestions should be part of the input to the Reliability Standards 

development process. Similarly, the ERO should evaluate the suggestions proposed by 

LPPC, APPA and Avista. 

707. California PUC suggests that states should have discretion over what lines are 

critical to Bulk-Power System reliability. The Commission has been given the 

responsibility to approve Reliability Standards that assure the Reliable Operation of the 

Bulk-Power System, including which facilities are covered by the Reliability Standards. 

We cannot delegate that responsibility as proposed by California PUC. Further, since 

many transmission facilities traverse multiple states, we are concerned that this proposal 

could result in the Reliability Standard applying to a section of a line in one state but not 

applying to the same line in a neighboring state. Since a vegetation-related outage affects 

all customers connected to that transmission line, customers in both states could 

potentially have lower reliability as a result of one state having a less stringent standard 

than another. 

708. Avista, LPPC, Progress and SERC raise concerns about the cost of implementing 

this Reliability Standard if the applicability is expanded to lower-voltage facilities. We 

recognize these concerns, and this was one of the reasons we proposed to apply this 

Reliability Standard to Bulk-Power System transmission lines that have an impact on 

reliability as determined by the ERO. We recognize that many commenters would like a 

more precise definition for the applicability of this Reliability Standard, and we direct the 

ERO to develop an acceptable definition that covers facilities that impact reliability but 

balances extending the applicability of this standard against unreasonably increasing the 

burden on transmission owners. 

709. FirstEnergy and Xcel suggest that if the applicability of this Reliability Standard is 

expanded, the Commission should allow flexibility in complying with this Reliability 

Standard for lower-voltage facilities, or allow lower-voltage facilities one year before the 

Reliability Standard is implemented. The ERO should consider these comments when 

determining when it would request that the modification of this Reliability Standard to go 

into effect. 
Docket No. RM06-16-000 - 202 - 

710. In response to EEI’s concerns that removing the existing 200 kV threshold could 

expose the Bulk-Power System to a new set of risks, we clarify that we are not 

immediately modifying this Reliability Standard. Instead, it will go into effect as written 

and the ERO will revise it through the Reliability Standards development process, with 

the expectation that the applicability of this Reliability Standard will expand to include 

additional facilities that impact reliability that currently are not covered by this Reliability 

Standard. A modification that reduces the applicability of this Reliability Standard would 

not meet the Commission’s directives. In response to SoCal Edison’s argument that the 

Reliability Standard already addresses the Commission’s concerns, the Commission 

agrees that while there appears to be a mechanism for inclusion of additional lines, none 

have been included. This lack of inclusion is in spite of the evidence that some lower 

voltage lines can have significant impacts on the Bulk-Power System, including IROLs 

and SOLs. 

711. In response to APPA, NRECA and NERC we agree that the proposed 

modifications should be vetted through the Reliability Standards development process. 

The Commission’s goal is to promote the Reliable Operation of the Bulk-Power System 

by including all of those entities necessary to comply with this Reliability Standard. We 

believe that requiring the Reliability Standard to include a greater number of entities and 

exclude those that will not affect reliability will more effectively sustain reliability than 

an overly exclusive list of applicable entities. 

ii. Inspection Cycles

712. In the NOPR, the Commission proposed to direct NERC to submit a modification 

to FAC-003-1 that requires the ERO to develop a minimum vegetation inspection cycle 

that allows variation for physical differences. 

(a) Comments

713. FirstEnergy states that a designation of a minimum annual inspection cycle is 

appropriate and the method of inspection (aerial or by ground) should be left to the 

transmission owner. Dominion cautions that if there is a requirement for annual 

inspections, it should be flexible and allow for different approaches to transmission line 

inspections. 

714. APPA, Entergy, EEI, LPPC, Progress Energy, SERC and SoCal Edison disagree 

with the Commission’s proposal to require the ERO to set minimum vegetation 

inspection cycles that allow for physical differences. APPA, Entergy and LPPC say that, 

instead of proposing the development of a Reliability Standard for minimum vegetation 

inspection cycles, the Commission should permit the transmission system owner or local 
Docket No. RM06-16-000 - 203 - 

utility to determine the inspection cycle best suited for its system and adhere to that cycle, 

with compliance enforcement performed by the Regional Entities and the ERO. 

715. Progress Energy and SERC believe that the Reliability Standard as written 

provides flexibility regarding vegetation inspection cycles and that the Commission 

should not impose requirements on the ERO to develop minimum inspection intervals on 

a continent with such regional diversity in climate and vegetation. In addition, Progress 

Energy argues that, where a particular region is heavily forested and has heavy rainfall 

along with extended or year round growing seasons, a “back stop” minimum inspection 

frequency could lead transmission owners to conduct inspections less frequently than 

what the local conditions require, which would lead to a lowest common denominator 

Reliability Standard. This could result in a transmission owner complying with the 

Reliability Standard while not adequately protecting the reliability of that region’s 

transmission system. 

716. Progress Energy and SERC argue that, since the performance metrics in FAC-003-

1 require reporting of applicable transmission interruptions caused by vegetation, the 

compliance process associated with this Reliability Standard should appropriately 

identify transmission owners’ inspection cycles that are not adequate, and the ERO can 

use its authority to remedy any vegetation-related outage that is attributed to the 

transmission owner’s inspection frequency. 

717. SoCal Edison states that transmission owners are already obligated by 

Requirement R1.1 to establish a minimum vegetation inspection schedule that allows 

adjustment for changing conditions. SoCal Edison believes that the best measure of an 

effective transmission vegetation management program is whether or not tree-to-line 

contacts are occurring. SoCal Edison recommends the Commission rescind the two 

proposed directives and order no further revisions to FAC-003-1 until such time as 

Reliability Standard is deemed unenforceable by the ERO or is not otherwise achieving 

its stated goals. 

718. APPA and Progress Energy state that a minimum vegetation inspection cycle 

could result in an undue financial burden for some regions of the country, because they 

would be forced into a minimum cycle that might be inappropriate for their own region. 

For example, Progress Energy states that, where a particular region is arid, sparsely 

forested or has a minimum growing season, a “back stop” minimum could require a more 

frequent interval than is realistically needed. This would result in increased and 

unnecessary costs to the transmission owner and its customers without providing a 

comparable increase in reliability. EEI believes that a minimum inspection cycle will add 

nothing to the strength of the existing practices and could add a requirement that is not 

merited by actual circumstances in many locations. 
Docket No. RM06-16-000 - 204 - 

(b) Commission Determination

719. The Commission is concerned about minimizing outages and supports a realistic 

inspection cycle. In the NOPR, the Commission proposed a minimum inspection cycle 

that takes account of physical differences as one way to address this concern. However, 

we recognize that there may be other options to achieve the same reliability goal. For 

example, the ERO could determine whether a prepared company-tailored inspection 

cycle is appropriate given the physical and geographic factors and, through audits, inspect 

individual vegetation management programs for compliance. 

720. While the Commission disagrees that incorporating a backstop would lead to a 

lowest common denominator Reliability Standard, the Commission is dissuaded from 

requiring the ERO to create a backstop inspection cycle at this time. Instead, the 

Commission agrees that an entity’s vegetation management program should be tailored to 

anticipated growth in the region and take into account other environmental factors. The 

goal is to assure that transmission owners conduct inspections at reasonable intervals. In 

the Commission’s Vegetation Management Report, we found that many entities 

performed aerial or ground inspections less than every three years or even “as needed.”264 

721. The Commission continues to be concerned with leaving complete discretion to 

the transmission owners in determining inspection cycles, which limits the effectiveness 

of the Reliability Standard. Accordingly, the Commission directs the ERO to develop 

compliance audit procedures, using relevant industry experts, which would identify 

appropriate inspection cycles based on local factors. These inspection cycles are to be 

used in compliance auditing of FAC-003-1 by the ERO or Regional Entity to ensure such 

inspection cycles and vegetation management requirements are properly met by the 

responsible entities. 

iii. Minimum Clearances on National Forest Service 

Lands

722. In the NOPR, the Commission did not propose to modify the ERO’s general 

approach with respect to clearances. However, the Commission expressed its belief that 

any potential issues regarding minimum clearances on National Forest Service (Forest 

Service) lands should be dealt with on a case-by-case basis. The Commission requested 

comments on whether another approach would be more appropriate to address this issue. 

 264 Utility Vegetation Management snd Bulk Electric Reliability Report at 10-11, 

available at http://www.ferc.gov/industries/electric/indus-act/reliability/2004.asp

(Vegetation Management Report). 
Docket No. RM06-16-000 - 205 - 

(a) Comments

723. APPA believes that a case-by-case approach may have to be employed, since 

Forest Service lands are located all across the country and have different regional 

characteristics. APPA notes that U.S. Fish and Wildlife Service personnel have begun to 

take action regarding vegetation management on non-federal lands, and reports that 

APPA members have been told by U.S. Fish and Wildlife personnel to refrain from 

cutting vegetation at certain times of the year in the absence of an imminent reliability 

threat. APPA concludes that this information conflicts with specifying minimum nationwide vegetation inspection/cutting cycles and clearances. In addition, APPA requests 

clarification of the Commission interpretation "we interpret the FAC-003-1 to require 

trimming that is sufficient to prevent outages due to vegetation management practices 

under all applicable conditions." 

724. Several commenters express concern about the Commission’s position that any 

potential issues regarding minimum clearances on National Forest Service lands should 

be dealt with on a case-by-case basis.265 EEI, Progress Energy and SERC believe that 

this approach is inconsistent with the Reliability Standard’s intent to use consistent 

approaches in setting minimum vegetation clearance distances on both private and public 

lands and the Commission’s statement that this Reliability Standard requires minimum 

clearances that are “sufficient to prevent outages due to vegetation management practices 

under all applicable conditions.”266 Therefore, International Transmission, EEI, LPPC, 

Progress Energy and SERC assert that Reliability Standard FAC-003-1 should be 

applicable to all responsible entities including those with transmission on both private 

and public lands because consistency is the only way to provide a uniform and reliable 

electrical system. Dominion suggests the Commission defer to NERC and the 

stakeholder process to develop specifications for clearances. 

725. Progress Energy and SERC note that EEI and certain federal agencies267 have 

jointly addressed the issue of consistency in vegetation management work on federal 

 265 See, e.g., EEI, Energy, International Transmission, Progress Energy, SERC, 

LPPC and MISO. 

266 The NOPR states that “Accordingly, we interpret the FAC-003-1 to require 

trimming that is sufficient to prevent outages due to vegetation management practices 

under all applicable conditions...” NOPR at P 380. 

267 Forest Service, Bureau of Land Management, Fish & Wildlife Service, 

National Park Service, and U.S. Environmental Protection Agency. 
Docket No. RM06-16-000 - 206 - 

lands, and developed a memorandum of understanding (Vegetation MOU) which sets the 

framework for managing vegetation on transmission line rights-of-way under federal 

agency jurisdiction.268 Progress Energy and SERC recommend using the EEI’s 

Vegetation MOU framework for managing vegetation on transmission line rights-of-way 

under federal agency jurisdiction rather than the case-by-case approach proposed in the 

NOPR. LPPC recommends creating a bright-line when it comes to utilities’ obligations 

(and rights) for trimming vegetation located on Forest Service lands. Avista and Portland 

General ask that the Vegetation MOU be affirmed by the Commission and permitted to 

govern transmission line rights-of-ways located on lands managed by federal land 

management agencies. 

726. SoCal Edison believes that transmission owners should be allowed the latitude to 

establish measures/procedures for less rigid tree-to-line clearances in response to state 

and federal agency demands or requests but is concerned that these measures/procedures 

will prove to be of little or no value in the event of an ERO investigation into a tree-toline contact occurring within national/state forestry boundaries or on private property. 

727. California PUC points out that California already has requirements applicable to 

minimum vegetation clearance, and that the Commission must take care to assure that 

any mandatory Reliability Standard does not preempt the ability of California (and other 

states with similar state standards) to impose stricter requirements that have no adverse 

impacts on reliability. 

728. FirstEnergy states that the standard should define rights-of-way to encompass the 

required clearance area instead of the corresponding legal land rights. Some rights-ofway may be larger to accommodate future needs and therefore may exceed clearances 

needed for existing lines. FirstEnergy believes that Reliability Standards should not 

require clearing entire rights-of-way when the required clearance for existing lines does 

not take up the entire right-of-way. 

(b) Commission Determination

729. As proposed in the NOPR, the Commission approves Reliability Standard FAC003-1 with no proposed modification on the issue of clearances. The Commission 

reaffirms its interpretation that FAC-003-1 requires sufficient clearances to prevent 

outages due to vegetation management practices under all applicable conditions. As to 

 268 The Vegetation MOU is available at 

http://www.eei.org/industry_issues/environment/land/vegetation_management/EEI_MO

U_FINAL_5-25-06.pdf 
Docket No. RM06-16-000 - 207 - 

APPA’s requests for clarification concerning the term "under all applicable conditions," 

the Reliability Standard already addresses this issue in Requirement R3.2 by allowing for 

exceptions for natural disasters (including wind shears and major storms) that cause 

vegetation to fall into the transmission lines from outside the ROW. The Commission 

therefore finds that no clarification is required in response to APPA. 

730. The Commission agrees that ownership of the land does not change the impact of 

a vegetation-related outage on the Bulk-Power System. However, the present Reliability 

Standard leaves the determination and documentation of "clearance 1" to transmission 

owners. As such, there are no specific clearances, or criteria/procedures to develop 

clearances, before the Commission for approval. What is in front of the Commission 

relative to "locations on the right-of-way where the Transmission Owner is restricted 

from attaining the clearances specified in Requirement R1.2.1" is addressed 

in Requirement R1.4. Requirement R1.4 states that “Each Transmission Owner shall 

develop mitigation measures to achieve sufficient clearances for the protection of the 

transmission facilities when it identifies locations on the right-of-way where the 

Transmission Owner is restricted from attaining the clearances specified in Requirement 

R1.2.1.” This Requirement addresses the instances when an entity cannot attain the 

clearances that it needs on land that it controls. Since there are multiple mitigation 

measures that the entity can employ to achieve the goal of preventing outages due to 

vegetation management practices, the Commission has stated that any potential issues 

regarding minimum clearances on Forest Service lands should be dealt with on a case-bycase basis. 

731. Avista and Portland General ask the Commission to endorse the Vegetation MOU. 

The Commission reiterates its direction that the minimum clearances must be sufficient to 

avoid any sustained vegetation-related outages for all applicable conditions. The 

Vegetation MOU references IEEE 516 as the only way to determine applicable minimum 

clearances. The Commission declines to endorse the use of IEEE 516 as the only 

minimum clearance because it is intended for use as a guide by highly-trained 

maintenance personnel to carry out live-line work using specialized tools under 

controlled environments and operating conditions, not for those conditions necessary to 

safely carry out vegetation management practices.269 Further, the allowable clearances in 

the IEEE standard are significantly lower than those specified by the relevant U.S. safety 

codes. As such, use of IEEE clearance provision as a basis for minimum clearance prior 

to the next tree trimming as a Requirement in vegetation management is not appropriate 

for safety and reliability reasons. For example, the IEEE Standard 516-2003 specifies a 

 269 Controlled environments and operating conditions include clear days without 

precipitation, high winds or lightning. 
Docket No. RM06-16-000 - 208 - 

2.45-foot clearance from a live conductor for the 120 kV voltage class,270 whereas the 

ANSI Z-133 standard specifies 12 feet, 4 inches as the approach distance for the 115 kV 

voltage class.271

732. Accordingly, the Commission directs the ERO to develop a Reliability Standard 

that defines the minimum clearance needed to avoid sustained vegetation-related outages 

that would apply to transmission lines crossing both federal land and non-federal land. 

While this consensus is developed, the Commission directs the ERO to address any 

potential issues regarding mitigation measures needed to assure these minimum 

clearances on Forest Service lands are appropriate on a case-by-case basis. The 

Commission also directs the ERO to collect outage data for transmission outages of lines 

that cross both federal and non-federal lands, analyze it, and use the results of this 

analysis and information to develop a Reliability Standard that would apply to 

transmission lines crossing both federal and non-federal land. 

733. In regard to California PUC’s concern about its ability to impose stricter 

requirements on vegetation clearances, the Commission notes that section 215(i)(3) of the 

FPA states that nothing in section 215 shall be construed to preempt the authority of a 

state to take action to ensure the reliability of electric service within that state, as long as 

the action is not inconsistent with any Reliability Standard. Therefore, the State of 

California may set its own vegetation management requirements that are stricter than 

those set by the Commission as long as they do not conflict with those set by the 

Commission. Further, the Commission notes that once a Reliability Standard is 

established, California PUC can develop stricter rules to be applied within the state of 

California, and if it wants them to be enforceable under section 215 of the FPA, could 

submit those Reliability Standards to the ERO and the Commission for approval as a 

regional difference. 

734. FirstEnergy suggests that rights-of-way be defined to encompass the required 

clearance areas instead of the corresponding legal rights, and that the standards should 

not require clearing the entire right-of-way when the required clearance for an existing 

line does not take up the entire right-of-way. The Commission believes this suggestion is 

 270 Institute of Electrical and Electronics Engineers, Inc. (IEEE) Standard 516-

2003, IEEE Guide for Maintenance Methods at 20. 

271 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 - 209 - 

reasonable and should be addressed by the ERO. Accordingly, the Commission directs 

the ERO to address this suggestion in the Reliability Standards development process. 

iv. Summary of Commission Determinations

735. The Commission approves FAC-003-1 as mandatory as enforceable. In addition, 

while we do not direct the ERO to submit a modification to the general limitation on 

applicability as proposed in the NOPR, we require the ERO to address the proposed 

modification through its Reliability Standards development process as discussed above. 

Further, while the Commission is dissuaded from requiring the ERO to create a backstop 

inspection cycle at this time, it directs the ERO to develop compliance audit procedures 

to identify appropriate inspection cycles based on local factors. These inspection cycles 

are to be used in compliance auditing of FAC-003-1 by the ERO or Regional Entity to 

ensure such inspection cycles and vegetation management requirements are properly met 

by the responsible entities. Finally, the Commission directs the ERO to develop a 

Reliability Standard through the Reliability Standard development process that defines 

the minimum clearance needed to avoid sustained vegetation-related outages that would 

apply to transmission lines crossing both federal land and non-federal land. While this 

consensus is developed, the Commission directs the ERO to address any potential issues 

regarding mitigation measures needed to assure these minimum clearances on Forest 

Service lands are appropriate on a case-by-case basis. The Commission also directs the 

ERO to collect outage data for transmission outages of lines that cross both federal and 

non-federal lands, analyze it, and use the results of this analysis and information to 

develop a Reliability Standard that would apply to transmission lines crossing both 

federal and non-federal land. 

d. Facility Ratings Methodology (FAC-008-1)

736. FAC-008-1 requires each transmission owner and generation owner to develop a 

facility rating methodology for its facilities, which should consider manufacturing data, 

design criteria (such as IEEE, ANSI or other industry methods), 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. 

737. In the NOPR, the Commission proposed to approve Reliability Standard FAC008-1 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the 

FPA and § 39.5(f) of our regulations, the Commission proposed to direct NERC to 

develop a modification to FAC-008-1 through the Reliability Standards development 

process that requires transmission and generation facility owners to: (1) document 

underlying assumptions and methods used to determine normal and emergency facility 
Docket No. RM06-16-000 - 210 - 

ratings; (2) develop facility ratings consistent with industry standards developed through 

an open process such as IEEE or CIGRE and (3) identify the limiting component(s) and 

define the increase in rating based on the next limiting component(s) for all critical 

facilities. 

i. Methodology Used To Determine Facility Ratings 

and Documentation of Underlying Assumptions

(a) Comments

738. EEI, Valley Group, MidAmerican and TANC support the Commission’s proposal 

to require additional documentation as a reasonable means to provide more transparency 

and consistency. EEI suggests that this requirement could be accommodated with a 

provision for the disclosure of such information upon request by a registered user, owner 

or operator. TANC supports the Commission’s proposal to not require a uniform facility 

rating methodology and recommends that the Commission adopt a policy that provides 

for each transmission owner and generation owner to develop and document a facility 

rating methodology, which is consistent with industry methodologies, for their facilities. 

TANC also states that the methodology used for developing facility ratings should 

include a description of and justification for all of the assumptions. Valley Group states 

that it is extremely important that the underlying assumptions and methods are 

documented and known to all parties. Valley Group maintains that this will also ensure 

that the rating assumptions used by operating and planning functions are consistent with 

each other. Valley Group emphasizes that making these assumptions open is important, 

especially regarding paths between different transmission owners, to ensure that 

transmission owners cannot exercise market power. It argues that open assumptions will 

also provide rational grounds for dispute resolution. 

(b) Commission Determination

739. As EEI, TANC, Valley Group and MidAmerican discuss in their comments, the 

Commission’s proposal to modify FAC-008-1 to require additional documentation 

supports the Commission’s goals of improving uniformity and transparency in the facility 

ratings process. EEI’s suggestion that having this information available for review upon 

request of a registered user, owner or operator should be considered by the ERO in its 

Reliability Standards development process. As proposed in the NOPR, the Commission 

directs the ERO to submit a modification to FAC-008-1 that requires transmission and 

generation facility owners to document underlying assumptions and methods used to 

determine normal and emergency facility ratings. As stated in the NOPR, the 

Commission believes that this added transparency will allow customers, regulators and 

other affected users, owners and operators of the Bulk-Power System to understand how 
Docket No. RM06-16-000 - 211 - 

facility owners set facility ratings through differing methods that provide equivalent 

results. 

ii. Rating Facilities Consistent with Industry 

Standards Developed Through an Open Process 

such as IEEE and CIGRE

(a) Comments

740. The Valley Group states that the Commission correctly identifies IEEE and 

CIGRE as examples of open process methodologies suitable for overhead transmission 

line ratings calculations. It claims that IEEE and CIGRE are the only methodologies 

which make their algorithms available to everybody, and clearly document their 

assumptions. Valley Group notes that both of these methodologies will undergo a 

revision for accuracy regarding calculations for high temperatures and high current 

densities in the next two years, which may lead in some cases to slightly lower line 

ratings, although the changes are not expected to be substantial. 

741. APPA suggests that the proposal to rate facilities consistent with industry 

methodologies developed through an open process such as IEEE and CIGRE should be 

considered in the ERO’s Reliability Standards development process rather than ordered 

by the Commission. LPPC asks the Commission to require only that facility ratings be 

consistent with good utility practice. According to LPPC, to the extent facility rating 

methodologies need to be more prescriptive than good utility practice, the details must be 

spelled out in the ERO Reliability Standards themselves, not by reference to other 

unspecified industry methodologies. LPPC believes that it would be poor policy for the 

Commission to endorse these methodologies since it would be impossible to police the 

processes by which such organizations develop their methodologies. MidAmerican states 

that the Commission should recognize that the proposal to require facility ratings be 

consistent with industry methodologies developed through an open process is potentially 

problematic, noting that certain aspects of the development of facility ratings are based 

on industry standards that are not developed through an open process, such as 

information provided by engineering textbooks or manufacturer information that is not 

specifically referenced in any current standard. MidAmerican recommends that the 

Commission delete the requirement that facility ratings be “developed through an open 

process such as IEEE or CIGRE” or add other sources that the Commission would find 

appropriate, such as the results of accepted scientific and engineering investigations and 

common sense. MRO requests that the Commission clarify whether its directive to 

modify FAC-008-1 to develop facility ratings consistent with industry standards 

developed through an open process such as IEEE or CIGRE would allow for legitimate 

regional differences such as climate, terrain or population density. 
Docket No. RM06-16-000 - 212 - 

(b) Commission Determination

742. In the NOPR, the Commission stated, “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.”272 These processes have been validated through actual testing and have been 

shown to provide appropriate results. Information from engineering textbooks, common 

sense or manufacturer information would be part of the underlying assumptions. The 

Commission’s intent in the NOPR was to require that FAC-008-1 be modified to require 

that facility ratings be developed consistent with industry standards developed through an 

open, transparent and validated process. The Commission agrees with Valley Group that 

IEEE and CIGRE are two examples of such processes and disagrees with LPPC that 

reference to industry standards is poor policy. Industry standards that have been verified 

by actual testing are appropriate. However, the Commission agrees with MidAmerican 

that IEEE and CIGRE are just two examples of such bodies; any other open process that 

has been technically validated for its provision of accurate, consistent ratings is also 

acceptable. The ERO should consider the concerns raised by LPPC and MRO in its 

Reliability Standards development process, and is hereby directed to do so. The 

Commission does not expect there to be any regional differences because the only 

differences should be from different underlying assumptions that are not defined by the 

Reliability Standard. 

iii. Identify the Limiting Component(s) and Define for 

all Critical Facilities the Rating Based on the Next 

Limiting Component within the Same Facility

(a) Comments

743. TANC maintains that the rating information provided by the transmission owners 

and generator owners should include additional information about all of the limiting 

components of the elements (e.g., transmission lines, transformers, etc.) for all critical 

facilities. Access to such information will enable neighboring systems to accurately 

study the effects of other facilities on their own systems and determine the critical 

elements for increasing facility ratings. 

744. Valley Group states that identifying the limiting elements is an excellent objective 

for reliability enhancement, but notes that its granularity must be limited to major 

elements of the circuits, such as transformers and breakers, while treating the 

 272 NOPR at P 404. 
Docket No. RM06-16-000 - 213 - 

transmission lines as single elements. Valley Group also notes that, of the two examples 

discussed in the NOPR, the example regarding relay settings is technically well justified, 

whereas rating the line based on a single limiting span is generally impractical because 

line design engineers add to the National Electric Safety Code minimum requirements 

“safety buffers,” which vary depending on their confidence in the accuracy of design 

calculations. 

745. APPA is concerned about the possible “unintended consequences” of this 

modification and questions whether this proposed Requirement can be done as a practical 

matter; how many critical facilities and limiting components would have to be modeled 

to meet such a Requirement; and whether the cost of such modeling is justified by the 

reliability benefits. Dynegy, MISO and Wisconsin Electric also oppose this requirement 

because it is ambiguous, the additional work required to identify the increase in rating 

based on the next limiting component(s) is unwarranted and potentially costly, and the 

need for any such specific information is questionable. Dynegy and Wisconsin Electric 

do not believe there is a widespread need for this type of information and recommend 

that the need for it be explored on a case-by-case basis rather than including a global 

requirement in the standards. 

746. Dynegy, FirstEnergy and MISO state that it is not clear what specific criteria 

would be used to define “critical facilities” and “limits.” EEI also states that developing 

a practical definition of “critical facilities” presents a challenge, and that compliance 

would require the analysis of possibly hundreds of thousands of “limiting” transmission 

elements to determine whether a limit is of primary concern or is contingent on the status 

of other nearby elements or system conditions at a particular time. EEI suggests that, 

rather than requesting that the industry develop a definition, it may be more useful for the 

Commission to recommend that the industry develop a set of high-level criteria that could 

be used to identify those transmission elements that create significant potential limits that 

are independent of other factors and considerations. 

747. EEI and TVA assert this recommendation does not seem to be intended to enhance 

reliability but to provide additional commercial information to the market, and may not 

be appropriate to include in a Reliability Standard. Portland General further points out 

that this information can be obtained from a transmission provider by submitting a 

transmission or interconnection request when ATC is not posted or not available. TVA 

comments that, since the focus of this proceeding is the Reliable Operation of the BulkPower System, changes to a proposed Reliability Standard, such as FAC-008-1, that 

appear designed to promote maximum commercial use of the grid are unwarranted in this 

proceeding and could jeopardize, rather than further, reliable transmission system 

operations. 
Docket No. RM06-16-000 - 214 - 

748. MRO seeks clarification about whether the proposed modification will require that 

all limiting facilities elements be published. MRO believes that serious confidentiality 

issues are raised due to the security-sensitive nature of the information and urges the 

Commission not to require the publication of such information. 

749. Dominion states that the Commission should exclude from this requirement 

facilities that are covered under an open, regional transmission expansion planning 

process, such as the Regional Transmission Expansion Plan process in PJM, where any 

interested party can be involved in the studies and determine what the limitations are and 

what could be done to increase transmission capacity. 

750. International Transmission states that, if the Commission were to require defining 

the increase in facility rating based on the next limiting element, it should restrict such 

application to transmission elements where the conductor itself is not the limiting 

element. International Transmission explains that in cases where the line must be 

completely rebuilt, it would not be feasible to estimate the increase in facility rating, 

since the new line could be specified to carry virtually any amount of power. 

751. MISO questions how a generator operator or generation owner would identify the 

increase in rating based on the next most limiting component(s) associated with generator 

output. FirstEnergy believes that this modification should recognize that generators may 

need to rely on transmission owners to point out facilities that are more limiting than the 

generator facilities. 

752. Manitoba’s technical experts disagree with the Preliminary Staff Assessment 

regarding FAC-008-1. The Reliability Standard properly places the responsibility of 

determining facility ratings with the facility owners. Manitoba also states that, since this 

Reliability Standard requires that the “Facility Rating shall be equal to the most limiting 

applicable Equipment Rating of the individual equipment that comprises that Facility,” 

information on the next limiting component is already identified. Contrary to the 

Commission’s view, Manitoba does not believe it would be appropriate in this Reliability 

Standard to identify the increase in rating for all critical facilities based on the next 

limiting component. In a networked system, there may be other limitations that set the 

current carrying capability of the critical facility. 

753. Manitoba further notes that the Commission proposal may lead to international 

conflicts in Reliability Standards. Manitoba states that a mandated change to FAC-008-1, 

which forces an entity to accept facility ratings beyond its risk tolerance, would be 

grounds for Manitoba to recommend that the provincial government of Manitoba not 

approve this Reliability Standard because it would degrade reliability. 
Docket No. RM06-16-000 - 215 - 

754. APPA suggests that the proposal to identify the limiting component and define for 

all critical facilities the rating based on the next limiting component be considered in the 

ERO’s Reliability Standards development process rather than ordered by the 

Commission. 

(b) Commission Determination

755. The Commission agrees with TANC that this modification would provide useful 

information to neighboring systems and users, owners and operators of the Bulk-Power 

System. The Commission also agrees with Valley Group that identifying the limiting 

elements of facilities enhances reliability by providing operators specific information 

about the limiting elements and therefore allowing them to assess the risks associated 

with circuit loadings. 

756. In response to the comments of APPA, Dynegy, EEI, MISO and Wisconsin 

Electric, the Commission clarifies that this Reliability Standard and the Commission’s 

proposed modification apply to facilities. As defined in the NERC glossary, a facility is 

“a set of electrical equipment that operates as a single Bulk Electric System Element273

(e.g., a line, a generator, a shunt compensator, transformer, etc.).” The most limiting 

component in a facility determines its rating, just like the rating of a chain is determined 

by the weakest link. The Commission’s proposed modification would require identifying 

and documenting the limiting component for all facilities and the increase in rating if that 

component were no longer the most limiting component; in other words, the rating based 

on the second-most limiting component. The Commission further clarifies that this 

Reliability Standard will require this additional thermal rating information only for those 

facilities for which thermal ratings cause the following: (1) an IROL; (2) a limitation of 

TTC; (3) an impediment to generation deliverability or (4) an impediment to service to 

major cities or load pockets. 

757. EEI and TVA raise concerns that this modification promotes commercial use of 

the grid rather than ensuring Reliable Operation of the Bulk-Power System, and relates 

more to transmission access than reliable operations. The Commission disagrees that this 

modification relates primarily to transmission access. When the transmission operators 

know which component within the transmission element is limiting they have more 

information to inform their decisions about how to provide for the Reliable Operation of 

the Bulk-Power System. Our proposed modification does not require any entity to invest 

in equipment to increase ratings of any facility; it simply requires the next limiting 

componet of each facility to be identified in order to understand what components are 

 273 An element is made up of one or more components. 
Docket No. RM06-16-000 - 216 - 

causing the limits that are to be used in reliability mitigation assessments. The 

identification of the first limiting component is already an inherent requirement in the 

existing rating process. As clarified above, the modification to identify an increase in 

rating of the transmission element that would result from removing the first limitating 

component applies only to critical facilities whose thermal ratings have been reached 

causing an SOL or IROL condition. As Dominion highlights in its comments, this 

information is already identified in the planning processes of some RTOs and ISOs. 

758. In response to the concerns raised by EEI and MRO about sharing confidential, 

market-sensitive information, the Commission disagrees that ratings information is 

confidential or market-sensitive. All users, owners and operators should have access to 

the facility ratings in order to operate the system reliably. Section 215(a)(4) of the FPA 

defines Reliable Operation, in part, as operating the elements of the Bulk-Power System 

within equipment and electric system thermal stability limits.274 Without knowing the 

ratings, it is not possible to know whether this requirement is being met. As to the 

argument that this information is confidential, the Commission clarifies that, as with the 

other information required by this Reliability Standard, the additional information 

required by this modification would be shared only with users, owners and operators of 

the Bulk-Power System. 

759. In response to Dominion’s comments, if the PJM Regional Transmission 

Expansion Planning process meets the criteria, there is no need to exclude facilities 

covered by that process from this requirement. 

760. The Commission directs the ERO to consider International Transmission’s 

comments regarding requiring information about the increase in facility rating based on 

the next limiting element only for lines where the conductor itself is not the limiting 

element in its Reliability Standards development process. Similarly, the ERO should also 

consider the comments from MISO and FirstEnergy that generators will have difficulty 

determining the increase in ratings due to the next limiting element, since in most cases 

the generator itself would be the most limiting element. 

761. We agree with Manitoba that this Reliability Standard properly places the 

responsibility to determine facility ratings on the facility owner. The Commission is not 

proposing to change this. We also agree with Manitoba that the most limiting component 

is already identified when facility ratings are determined. The Commission is only 

directing transmission and generation owners to provide additional information on the 

next limiting component within the facility so that facility ratings are more transparent. 

 274 16 U.S.C. 824o(a)(4). 
Docket No. RM06-16-000 - 217 - 

762. In response to Manitoba’s and APPA’s concerns, we recognize that this is an 

additional requirement with some complexities, and this modification will go through the 

ERO Reliability Standards development process. We do not intend to usurp the 

Reliability Standards development process, where Manitoba may raise its concerns for 

the ERO to consider. 

iv. Applicability to Generator Owners

(a) Comments

763. Xcel states that this Reliability Standard should not apply to generator owners 

because capability testing, rather than using mathematical calculations, is the preferred 

method of determining generating unit capability. Capability testing clearly includes the 

capability of all the supporting components behind the generator that are required to 

produce a MW of capability. Xcel also states that this proposed Reliability Standard, if 

applied to generating units, would not improve system reliability and could result in 

conflicting and confusing unit capability ratings. Xcel notes that generating units already 

are required to be capability-tested on a periodic and seasonal basis to demonstrate unit 

gross and net capability in accordance with proposed standards MOD-024-1 and MOD025-1. 

764. FirstEnergy also points out that facility ratings for nuclear units are part of NRC 

license agreements and that the ratings methodologies included in NRC license 

agreements are approved by NRC. FirstEnergy proposes that compliance with NRC 

ratings methodology requirements should be assumed to comply with this Reliability 

Standard. 

(b) Commission Determination

765. The Commission agrees with Xcel that an actual test could be used as a substitute 

for a mathematical calculation of capability, and we ask the ERO to consider these 

comments in its Reliability Standards development process. The Commission 

understands that NRC provides ratings methodologies for nuclear power plants and not 

for the transmission system. Capacity ratings of nuclear generators determined using this 

methodology are acceptable for reliability purposes. We also direct the ERO to consider 

FirstEnergy’s comments in its Reliability Standards development process. 
Docket No. RM06-16-000 - 218 - 

v. Compliance with Blackout Report 

Recommendation No. 27

(a) Comments

766. Manitoba believes this Reliability Standard meets the requirement of Blackout 

Report Recommendation No. 27 because the recommendation does not require a uniform 

set of methodologies for rating facilities, but instead only recommends that there be a 

clear, unambiguous requirement to rate transmission lines. 

767. Valley Group notes that, while the Commission’s proposal would direct the ERO 

to respond to a part of Blackout Report Recommendation No. 27, it does not address the 

important second part of the Recommendation, namely dynamic ratings. Valley Group 

notes that dynamic ratings offer a very powerful tool both for maximizing the capabilities 

of transmission paths and for avoiding unnecessary transmission line loading relief. 

Valley Group also notes that dynamic ratings, based either on ambient-adjusted ratings or 

ratings generated by real-time monitoring systems, are widely used in the PJM system, 

while broader real-time ratings are applied on certain lines in SPP and ERCOT and at 

several individual utilities. Valley Group states that controlling unnecessary operator 

interventions with dynamic ratings both increases the reliability of Bulk-Power System 

and improves its economy. Valley Group concludes that it would be highly desirable for 

the ERO to establish policies and procedures regarding dynamic ratings – as 

recommended by the Blackout Report, and recommends that the Commission include 

such guidance in its Final Rule. 

(b) Commission Determination

768. The Commission believes that implementation of the modifications discussed 

earlier to Reliability Standard FAC-008-1 meets our goal of implementing Blackout 

Report Recommendation No. 27, which is to “develop enforceable standards for 

transmission line ratings.”275 To achieve a clear and unambiguous Requirement to rate 

transmission lines, it is important to understand the underlying assumptions and the 

methodologies that will be used to develop those ratings. The Commission recognizes 

that dynamic line ratings are an innovative application, and directs the ERO to consider 

the comments from Valley Group in future revisions of this Reliability Standard. 

 275 Blackout Report at 162. 
Docket No. RM06-16-000 - 219 - 

vi. General Comments 

769. APPA notes that FAC-008-1 should be revised to replace Levels of NonCompliance with Violation Security Levels, and to include Violation Risk Factors on all 

FAC-008-1 requirements. 

(a) Commission Determination

770. The Commission acknowledges that the Reliability Standards are changing. In 

this Final Rule, we are ruling on the Reliability Standards as they were filed, and these 

documents use the term Levels of Non-Compliance. The ERO should address APPA’s 

comments in its Reliability Standards development process. 

vii. Summary of Commission Determination

771. Accordingly, as discussed in the responses to comments above, the Commission 

approves FAC-008-1 as mandatory and enforceable. In addition, we direct the ERO to 

develop modifications to FAC-008-1 through its Reliability Standards development 

process requiring transmission and generation facility owners to: (1) document 

underlying assumptions and methods used to determine normal and emergency facility 

ratings; (2) develop facility ratings consistent with industry standards developed through 

an open, transparent and validated process and (3) for each facility, identify the limiting 

component and, for critical facilities, the resulting increase in rating if that component is 

no longer limiting. 

e. Establish and Communicate Facility Ratings (FAC-009-1)

772. FAC-009-1 requires each transmission owner and generation owner to establish 

facility ratings consistent with its associated facility ratings methodology and provide 

those ratings to its reliability coordinator, transmission operator, transmission planner and 

planning authority. In the NOPR, the Commission proposed to approve FAC-009-1 as 

mandatory and enforceable. 

i. Comments

773. APPA supports approval of FAC-009-1 as a mandatory and enforceable 

Reliability Standard. 

ii. Commission Determination

774. 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 
Docket No. RM06-16-000 - 220 - 

guidance for compliance. Accordingly, the Commission approves Reliability Standard 

FAC-009-1 as mandatory and enforceable. 

f. Transfer Capability Methodology (FAC-012-1)

775. Proposed Reliability Standard FAC-012-1 requires each reliability coordinator and 

planning authority to document the methodology used to develop its 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. 

776. In the NOPR, the Commission explained that, because 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. 

Thus, the NOPR did not propose to approve or remand this Reliability Standard until the 

regional procedures are submitted. 

777. The NOPR explained that FAC-012-1 only requires that the regional reliability 

organization provide documentation on transfer capability methodology and provide it to 

entities such as the relevant 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. The NOPR suggested that FAC-012-1 should, as a minimum, provide a 

framework for the transfer capability calculation methodology including data inputs and 

modeling assumptions. In addition, the NOPR asked for comments on the most efficient 

way to make the above information transparent for all participants. 

i. Methodology

(a) Comments

778. APPA, International Transmission and MidAmerican agree that the proposed 

FAC-012-1 is not sufficient and should not be accepted for approval as a mandatory 

Reliability Standard. They suggest that, at a minimum, this Reliability Standard should 

provide a framework for the transfer capability calculation methodology, including data 

inputs and modeling assumptions. APPA notes that, in the Western Interconnection and 

ERCOT, the sets of rules for long-range and operational planning studies are transparent 

to all users, owners and operators and suggests that in the Eastern Interconnection, where 

multiple regions exist, the Regional Entities should consider developing an umbrella 
Docket No. RM06-16-000 - 221 - 

organization or process comprised of representatives from each of the Eastern 

Interconnection’s Regional Entities to establish the planning and operational rules for the 

Interconnection. APPA suggests that this approach would work well to identify critical 

facilities, by using consistent and transparent study assumptions, and it would also 

minimize seams issues when establishing facility rating and transfer capabilities 

throughout the entire Interconnection. International Transmission states that this 

Reliability Standard should identify the performance that is required, that specifics of 

how transfer capability should be calculated do not belong in this Reliability Standard, 

and that a reference document could be developed for this purpose. 

(b) Commission Determination

779. Although we are not proposing to approve or remand this Reliability Standard, 

because it is applicable to the regional reliability organization, the Commission agrees 

with APPA, International Transmission and MidAmerican that, at a minimum, this 

Reliability Standard should provide a framework for the transfer capability calculation 

methodology, including data inputs and modeling assumptions. The Commission agrees 

with APPA that there should be an umbrella organization to assure consistency within the 

Eastern Interconnection and the other interconnections. We believe that the best 

organization to do this would be the ERO, because it is the only organization with 

knowledge of all of the individual Regional Entities that can carry out this function. 

Therefore, we direct the ERO to modify this Reliability Standard to provide such a 

framework. 

ii. Transparency and Confidentiality

(a) Comments

780. International Transmission cautions that, in making information regarding the 

framework for calculating transfer capability transparent to all participants, a balance 

must be maintained between the need for transparency and the need to maintain the 

confidentiality of sensitive critical energy infrastructure information (CEII). The results 

of certain critical contingency analyses would not be appropriate for public disclosure, 

but may be the basis for transfer capability limits imposed on some interfaces. 

781. MidAmerican suggests that transparency could be provided in the Eastern 

Interconnection by each reliability coordinator and each planning authority posting the 

transfer capability calculations performed pursuant to FAC-012-1, along with a document 

outlining how they were determined and the purposes for which they are used on a 

protected website. The protected site should be accessible only to qualified entities. 

MidAmerican suggests that the Western Interconnection’s approach, the WECC message 

system used for certain qualified paths, is an appropriately transparent system. 
Docket No. RM06-16-000 - 222 - 

(b) Commission Determination

782. Although we are not proposing to approve or remand this proposed Reliability 

Standard, the Commission believes that it can be improved. The Commission believes 

that the process used to determine transfer capabilities should be transparent to the 

stakeholders, and agrees with International Transmission and MidAmerican that the 

results of those calculations should not be available for public disclosure but only for 

qualified entities on a confidential basis. In addition, the process and criteria used to 

determine transfer capabilities must be consistent with the process and criteria used for 

other users of the Bulk-Power System. Simply stated, the criteria used to calculate 

transfer capabilities for use in determining ATC must be identical to those used in 

planning and operating the system. The Commission directs the ERO to take this into 

account in its Reliability Standards development process, and to modify the Reliability 

Standard consistent with Order No. 890 in Docket No. RM05-25-000. 

783. Accordingly, the Commission affirms the NOPR proposal to not approve or 

remand this Reliability Standard. We understand that the ERO implemented its 

Reliability Standards development process to revise the Reliability Standard and will be 

submitting it in accordance with the schedule identified in Order No. 890. 

g. Establish and Communicate Transfer Capability (FAC013-1)

784. FAC-013-1 requires either the reliability coordinator or the planning authority, as 

determined by the regional reliability organization, to calculate transfer capabilities 

consistent with its transfer capability methodology and provide those capabilities to its 

transmission operators, transmission service providers and planning authorities. 

785. In the NOPR, the Commission proposed to approve Reliability Standard FAC013-1 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the 

FPA and § 39.5(f) of our regulations, the Commission proposed to direct NERC to 

develop 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. 

i. Comments

786. APPA supports the Commission’s proposal to approve FAC-013-1 as a mandatory 

and enforceable Reliability Standard, but disagrees with the Commission’s proposed 

modification to remove the regional reliability organization as the entity that determines 

whether a planning authority has a role in determining transfer capabilities. APPA 

believes that regional committee processes are essential to determine, through their 
Docket No. RM06-16-000 - 223 - 

planning and operating committees, which planning authorities and reliability 

coordinators are responsible for determining and distributing each of the specific transfer 

capability values within each regional footprint. APPA proposes that in the Eastern 

Interconnection, where multiple regional reliability organizations and Regional Entities 

exist, the Regional Entities should consider developing an umbrella organization or 

process comprised of representatives from each of the Eastern Interconnection’s Regional 

Entities, to establish the planning and operational planning rules for the Interconnection. 

APPA believes that such a program would minimize seams issues when establishing 

facility ratings and transfer capabilities throughout the entire Interconnection. 

787. MidAmerican supports the Commission’s proposal to make this Reliability 

Standard applicable to all reliability coordinators and planning authorities. MidAmerican 

believes in a clear separation of responsibilities between the reliability coordinators and 

planning authorities. MidAmerican believes that reliability coordinators should calculate 

transfer capabilities in the operating horizon, while planning authorities calculate transfer 

capabilities in the planning horizon, and would support additional clarification of the 

standard by explicitly stating the continued responsibility of planning authorities to 

calculate transfer capabilities for the planning horizon. 

788. TANC is concerned that, if the transmission service provider and the transmission 

operators are specifically named in Requirement R2.1 of this Reliability Standard, but are 

not included in the Applicability section, this will cause ambiguity. TANC questions 

whether a transmission service provider or transmission operator that does not receive the 

transfer capabilities from the reliability coordinator will be held accountable and 

penalized for not producing the transfer capabilities when the reliability coordinator 

never provided them. If this is the case, TANC questions whether there will be different 

penalties for the transmission service provider and transmission operator, or whether they 

will be subject to the same penalties as the entities listed in the Applicability section. 

789. EEI believes that the full range of issues discussed here are currently under review 

under Docket No. RM05-25 and proposes that these issues remain in a single forum to 

avoid confusion. 

ii. Commission Determination

790. The Commission does not believe that the regional reliability organization should 

be able to decide the type of entity to which this Reliability Standard applies. The 

Commission disagrees with APPA that regional committee processes are essential to 

determine which planning authorities and reliability coordinators are responsible for 

determining and distributing each of the specific transfer capability values. Reliability 

coordinators have a wider-area view of the transmission system than planning authorities, 

which is important in calculating inter- and intra-regional transfer capabilities. 
Docket No. RM06-16-000 - 224 - 

Therefore, the Commission agrees with MidAmerican that reliability coordinators should 

calculate transfer capabilities in the operating horizon. The Commission will not address 

MidAmerican’s proposal regarding calculating transfer capabilities in the planning 

horizon because those Reliability Standards are being considered in Docket No. RM07-3-

000 and are therefore beyond the scope of this proceeding. 

791. The Commission, as discussed elsewhere in this Final Rule, has considered 

APPA’s proposal concerning creating an umbrella organization in regard to FAC-012-

001.276 

792. In regard to TANC’s concern that transmission service providers and transmission 

operators may be liable because they are specifically named in Requirement R2.1, the 

Commission clarifies that, because the Reliability Standard only provides that the 

transmission service providers and transmission operators receive information regarding 

transfer capabilities, and does not require an affirmative action on the part of transmission 

service providers or transmission operators, a transmission service provider or 

transmission operator cannot be liable for violating the Reliability Standard. 

793. The Commission disagrees with EEI that these matters should be evaluated only in 

the OATT Reform Proceeding. In Order No. 890, the Commission directed transmission 

owners to use the ERO’s Reliability Standards development process to implement 

changes required in that Final Rule.277

794. Accordingly, the Commission approves Reliability Standard FAC-013-1 as 

mandatory and enforceable, and, pursuant to section 215(d)(5) of the FPA and § 39.5(f) 

of our regulations, the Commission directs the ERO to develop a modification to FAC013-1 through the Reliability Standards development process that makes it applicable to 

reliability coordinators. 

6. INT: Interchange Scheduling and Coordination

795. The Interchange Scheduling and Coordination (INT) group of Reliability 

Standards addresses interchange transactions,278 which occur when electricity is 

transmitted from a seller to a buyer across the power grid. Specific information regarding 

 276 See supra P 779. 

277 Order No. 890 at P 196. 

278 The NERC glossary defines “interchange” as “Energy transfers that cross 

Balancing Authority boundaries.” NERC Glossary at 9. 
Docket No. RM06-16-000 - 225 - 

each transaction must be identified in an accompanying electronic label, known as a 

“Tag” or “e-Tag” which is used by affected reliability coordinators, transmission service 

providers and balancing authorities to assess the transaction for reliability impacts. 

Communication, submission, assessment and approval of a Tag must be completed for 

reliability consideration before implementation of the transaction. 

a. Interchange Authority

796. The Version 1 INT Reliability Standards submitted with NERC’s August 28, 2006 

supplemental filing include a new entity, the interchange authority, which oversees 

interchange transactions and is included as an applicable entity or referenced in the 

Requirements sections of INT-005-1, INT-006-1, INT-007-1, INT-008-1, INT-009-1 and 

INT-010-1.279 The Commission requested in the NOPR that NERC provide additional 

information regarding the role of the interchange authority so that the Commission could 

determine whether the interchange authority is a user, owner or operator of the BulkPower System required to comply with mandatory Reliability Standards. 

i. Comments

797. ISO-NE states that it is unclear who the interchange authority should be, how its 

tasks could be performed operationally and how the interchange authority function relates 

to other reliability and market functions. ISO-NE states that NERC has not yet fully 

incorporated the concept of an interchange authority into its Functional Model and has 

not provided a means for an entity to register as an interchange authority under the 

Functional Model. Finally, ISO-NE states that NERC must still create a process to allow 

the appropriate entities to register as interchange authorities so that their status is clear to 

all applicable entities, and it urges that approval of the Reliability Standards that have the 

interchange authority as an applicable entity be withheld until these issues are resolved. 

798. APPA agrees that applicability of the Reliability Standards to the interchange 

authority is confusing. However, APPA suggests the best approach to the problem is for 

NERC to identify the source and sink balancing authorities as the applicable entity in 

these Reliability Standards until the Functional Model is revised to better specify the 

status and responsibility of interchange authorities. 

 279 The NERC Glossary defines an “interchange authority” as “the 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.” Id.
Docket No. RM06-16-000 - 226 - 

799. EEI observes that there is considerable confusion throughout the industry 

regarding the registration process and the relationship between registration and 

applicability of standards, with the interchange authority being an example of that 

confusion. However, EEI states it understands that the role of an interchange authority is 

currently being addressed and revisions to the Functional Model are currently moving 

through the approval process. If Version 3 of the Functional Model is approved by the 

NERC Board, EEI believes it will clarify that a sink balancing authority performing a 

Tag authority service could serve as an interchange authority and this modification would 

address the Commission’s concern. 

800. The CAISO suggests that it is premature to place any INT Reliability Standards 

involving an interchange authority into effect until more information is provided 

concerning the interchange authority’s role. 

ii. Commission Determination

801. The NERC glossary definition of interchange authority indicates that it is intended 

to provide essentially a quality control function in verifying and approving interchange 

schedules and communicating that information. Our understanding is that, in the interim, 

sink and source balancing authorities will serve as interchange authorities until the ERO 

has further clarified an interchange authority’s role and responsibility in the modification 

of the Functional Model and in the registration process. The new interchange authority 

function allows an entity other than a balancing authority to perform this function in the 

future; the pre-existing INT-001-1 Reliability Standard identified the balancing authority 

as the responsible entity to perform this function. Any such entity should be registered 

by the ERO in the ERO compliance registry, so that the responsibility of an entity, other 

than a balancing authority, that takes on this role in the future would be clear. 

802. In short, there is sufficient clarity concerning the nature and responsibilities of this 

function for it to be implemented at this time. Withholding approval of INT Reliability 

Standards pending further clarification on this matter would create an unnecessary gap in 

the coverage of the Reliability Standards that potentially could threaten the reliability of 

the Bulk-Power System. 

b. Interchange Information (INT-001-2)

803. INT-001-1 seeks to ensure that interchange information is submitted to the 

reliability analysis service identified by NERC.280 This Reliability Standard applies to 

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

Distribution Calculator. 
Docket No. RM06-16-000 - 227 - 

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. The Requirements apply to all dynamic schedules, 

delivery from a jointly owned generator and bilateral inadvertent interchange payback. 

804. The Commission proposed in the NOPR 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 its regulations, the Commission proposed to direct NERC to submit a 

modification to INT-001-1 that: (1) includes Measures and Levels of Non-Compliance 

and (2) includes a Requirement that interchange information must be submitted for all 

point-to-point transfers entirely within a balancing authority area, including all 

grandfathered and “non-Order No. 888” transfers.281 

805. The Commission also noted in the NOPR that certain Requirements of INT-001-0 

that relate to the timing and content of e-Tags had been deleted in the Version 1 

Reliability Standard. NERC indicated that these Requirements are business practices that 

would be included in the next version of the NAESB Business Practices. The 

Commission stated in the NOPR that NERC’s explanation of this change was acceptable 

and proposed to approve INT-001-1 with the deletion of Requirements R1.1, R3, R4 and 

R5. However, the Commission also noted that NAESB had not yet filed the e-Tagging 

requirements as part of its business practices, and that if no such business practice has 

been submitted at the time of the Final Rule, the Commission may reinstate these 

Requirements in the Final Rule. 

806. NERC submitted INT-001-2, which supersedes the Version 1 Reliability 

Standards, in its November 15, 2006 filing. INT-001-2 adds Measures and Levels of 

Non-Compliance to the Version 0 Reliability Standard. In this Final Rule, the 

Commission addresses INT-001-2, as filed with the Commission on November 15, 2006. 

i. Comments

807. APPA states that NERC’s submission of INT-001-2 on November 15, 2006 has 

fulfilled the Commission’s proposed directive to include Measures and Levels of NonCompliance in this Reliability Standard. APPA also states that, while it does not oppose 

NERC consideration of the Commission’s proposed directive regarding the submission of 

interchange information for all point-to-point transfers entirely within a balancing 

 281 This Requirement was included in INT-001-0 as Requirement R1.2. 
Docket No. RM06-16-000 - 228 - 

authority area, it does not understand the Commission’s reliability concerns in this 

connection. 

808. MidAmerican states that it favors the Commission’s proposed directive to NERC 

for a modification of the Reliability Standard as a substantial improvement for reliability. 

Constellation supports this proposal and states that the proposal, together with other 

initiatives, such as OATT reform, represent additional steps to achieving not only BulkPower System reliability, but also a reduction of undue discrimination in transmission 

services. 

809. NERC disagrees with the Commission’s proposal to direct the submission of 

interchange information on all point-to-point transfers within a balancing area. NERC 

contends that this issue was discussed at great length in the Reliability Standards 

development process and the vast majority of commenters and voters agreed that such a 

requirement would have no merit from a reliability perspective. It also states that such 

data is not used today by the NERC interchange distribution calculator for reliability.282 

Finally, NERC concludes that while it may be appropriate for this issue to be 

reconsidered in revisions to the Reliability Standards, a Commission directive to include 

a requirement that the collective expertise and the consensus of the industry have 

determined to be unnecessary for reliability constitutes “setting the standard.” 

810. LPPC agrees with the Commission that Requirements R1.1, R3, R4 and R5 are 

good business practices, and it states that for this reason they should not be included in 

the Reliability Standards. These business practices should more appropriately be 

contained in NAESB standards, or perhaps the pro forma OATT. 

811. ERCOT maintains that INT-001-1 is not appropriate for the ERCOT region. 

ERCOT states that it is a single balancing authority. To the extent that INT-001-1 

requires tagging transfers within a single balancing authority, it cannot be applied to 

ERCOT as written because all point-to-point transfers within ERCOT are financial 

transactions only. ERCOT notes that it tags transfers outside the ERCOT region. 

812. Allegheny states that the requirement to tag point-to-point transactions cannot be 

met in the PJM market where Tags are not used when a transaction’s source and sink are 

 282 The NERC glossary defines the interchange distribution calculator as “[t]he 

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 9. 
Docket No. RM06-16-000 - 229 - 

within the PJM footprint. Such transactions are reported through the PJM eSchedule 

system, which already provides adequate information for the PJM region to conduct 

reliability and curtailment analyses. Allegheny states that there is no reliability gap in the 

PJM market arising from this issue. 

813. Santa Clara submits that LSEs should be applicable entities under proposed 

revised INT-001-2 to ensure that they have adequate notice of the requirements of this 

Reliability Standard. It states that the actions of LSEs are implicated in Requirement R1 

of this proposed Reliability Standard.283 

ii. Commission Determination

814. The Commission approves INT-001-2 as a mandatory and enforceable Reliability 

Standard. In addition, we direct the ERO to develop modifications to the Reliability 

Standard through the Reliability Standards development process, as discussed below. 

815. We agree with APPA that INT-001-2, submitted on November 15, 2006 includes 

Measures and Levels of Compliance, and we will not direct any further action regarding 

Measures and Levels of Compliance at this time. 

816. MidAmerican and Constellation support the Commission’s proposal that this 

Reliability Standard include a Requirement that interchange information must be 

submitted for all point-to-point transfers entirely within a balancing authority area, 

including all grandfathered and “non-Order No. 888” transfers. The Commission points 

out that unless these grandfathered and “non-Order No. 888” transfers are included in one 

of the INT Reliability Standards, they might not be subject to appropriate curtailment as 

necessary due to system conditions. Curtailments are determined using the interchange 

distribution calculator. Unless transactions internal to a balancing authority area are 

included in the calculator as we proposed, they are not recognized by the calculator and 

may never be curtailed. For instance, even if a transaction internal to a balancing 

authority area is non-firm and some inter-balancing authority trades are firm, the latter 

could be cut before the former, despite the curtailment priorities in the Order No. 888 

tariff. While we recognize that most trades internal to a balancing authority area do not 

affect interchange, some do, since electricity flows do not necessarily follow the contract 

path. 

 283 INT-001-2 Requirement R1 provides that the LSE and purchasing-selling entity 

shall ensure that arranged interchange is submitted to the interchange authority. 
Docket No. RM06-16-000 - 230 - 

817. In addition, e-Tagging of such transfers was previously included in INT-001-0 and 

the Commission is aware that such transfers are included in the e-Tagging logs. In short, 

the practice already exists, but if this Requirement is removed from INT-001-2, no 

Reliability Standard would require that such information be provided. We therefore will 

adopt the directive we proposed in the NOPR and direct the ERO to include a 

modification to INT-001-2 that includes a Requirement that interchange information must 

be submitted for all point-to-point transfers entirely within a balancing authority area, 

including all grandfathered and “non-Order No. 888” transfers. 

818. The Commission agrees with ERCOT’s conclusion that the Reliability Standard 

does not apply to financial point-to-point transfers within the ERCOT region. This 

interpretation is consistent with the proposed INT Reliability Standards. Likewise, 

Allegheny’s views on tagging point-to-point transactions within the PJM market are 

consistent with the proposed INT Reliability Standards. 

819. With respect to Santa Clara’s position that LSEs should be applicable entities 

under the Reliability Standard, the Commission notes that in situations where a LSE is 

securing energy from outside the balancing authority to supply its end-use customers, it 

would function as a purchasing-selling entity, as defined in the NERC glossary, and 

would be included in the NERC registry on that basis. This interpretation flows from the 

language of the Reliability Standards, and the Commission does not perceive any 

ambiguity in this connection. Nevertheless, the Commission directs the ERO to consider 

Santa Clara’s comments, and whether some more explicit language would be useful, in 

the course of modifying INT-001-2 through the Reliability Standards development 

process. 

820. The Commission accepts NERC’s explanation that Requirements R1.1, R3, R4 

and R5 of INT-001-0 that were deleted in INT-001-1 are business practices. NAESB 

voluntarily filed “Standards for Business Practices and Communication Protocols for 

Public Utilities” in Docket No. RM05-5-000 on November 16, 2006. This filing contains 

wholesales electric business practice standards that incorporate e-Tagging requirements 

and is the subject of a separate rulemaking process that is expected to result in rules that 

will become effective on or about the same time as the Reliability Standard becomes 

mandatory. 

821. Accordingly, the Commission approves Reliability Standard INT-001-2 as 

mandatory and enforceable. In addition, the Commission directs the ERO to develop a 

modification to INT-001-2 through its Reliability Standards development process that 

includes a Requirement that interchange information must be submitted for all point-to-
Docket No. RM06-16-000 - 231 - 

point transfers entirely within a balancing authority area, including all grandfathered and 

“non-Order No. 888” transfers.284 

c. Regional Difference to INT-001-2 and INT-004-1: WECC 

Tagging Dynamic Schedules and Inadvertent Payback 

822. NERC proposed a regional difference that would exempt WECC from 

requirements related to tagging dynamic schedules and inadvertent payback. The 

Commission noted in the NOPR that WECC is developing a tagging requirement for 

dynamic schedules. The Commission requested 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 an exemption would cease 

when the tagging requirements become effective. The Commission stated that it would 

not approve or remand an exemption until NERC submits this information.285 Rather, we 

stated that we would consider any regional differences contained in a proposed WECC 

tagging requirement for dynamic schedules when submitted by NERC for Commission 

review. 

i. Comments

823. APPA agrees with the Commission’s proposed course of action addressing this 

regional difference. 

824. Xcel requests that the Commission accept the proposed regional difference; 

tagging requirements for dynamic schedules do not apply now in WECC, and it would be 

burdensome and would provide little reliability benefit to apply those requirements to 

WECC by June 2007. The Commission therefore should approve the proposed variance 

for an interim period until WECC’s tagging requirements for dynamic schedules are 

developed and approved. 

ii. Commission Determination

825. The Commission stressed in Order No. 672 that uniformity of Reliability 

Standards should be the goal and practice, “the rule rather than the exception.”286 The 

Commission therefore stated in the NOPR that the absence of a tagging requirement for 

 284 The Requirement was included in INT-001-0 as Requirement R1.2. 

285 To date, the Commission has not received the requested information. 

286 Order No. 672 at P 290. 
Docket No. RM06-16-000 - 232 - 

dynamic schedules in WECC is a matter of concern, and that for this reason it could not 

approve or remand this regional difference without the additional information it 

requested. To date the Commission has not received this information. Of particular 

importance in this compliance filing will be the ERO’s demonstration that this practice is 

due to a physical difference in the system or results in a more stringent Reliability 

Standard. Without this information, we are unable to address Xcel’s comments further. 

The Commission therefore directs the ERO to submit a filing within 90 days of the date 

of this order either withdrawing this regional difference or providing additional 

information. 

d. Regional Difference to INT-001-2 and INT-003-2: MISO 

Energy Flow Information

826. NERC proposed a regional difference that would allow MISO to provide market 

flow information in lieu of tagging intra-market flows among its member balancing 

authorities; 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 affected. The waiver request text 

includes a condition specifying that the “Midwest ISO must provide equivalent 

information to Reliability Authorities as would be extracted from a transaction tag.” The 

Commission proposed in the NOPR to approve this regional difference. It explained 

there that, based on the information provided by NERC, the proposed regional difference 

is necessary to accommodate MISO’s Commission-approved, multi-control area energy 

market. Thus, the Commission stated it believed that the regional difference is 

appropriate, because it is more stringent than the continent-wide Reliability Standard and 

otherwise satisfies the statutory standard for approval of a Reliability Standard. 

i. Comments

827. APPA agrees with Commission’s proposed course of action in approving this 

regional difference. 

ii. Commission Determination

828. The information received by the Commission demonstrates that the proposed 

regional difference to INT-001-2 and INT-003-2, as filed on November 15, 2006, is 

necessary to accommodate MISO’s Commission-approved, multi-control area energy 

market. The Commission concludes that the regional difference is appropriate, because it 

is more stringent than the continent-wide Reliability Standard and otherwise satisfies the 
Docket No. RM06-16-000 - 233 - 

statutory standard for approval of a Reliability Standard, and therefore approves it as 

mandatory and enforceable. 

e. Interchange Transaction Implementation (INT-003-2)

829. The purpose of INT-003-1 is to ensure that balancing authorities confirm 

interchange schedules with adjacent balancing authorities before implementing the 

schedules in their area control error equations. INT-003-1 contains a Requirement that 

focuses on ensuring that a sending balancing authority confirms interchange schedules 

with its receiving balancing authority before 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. 

830. The Commission proposed in the NOPR to approve Reliability Standard INT003-1 as mandatory and enforceable. In addition the Commission proposed to direct 

NERC to submit a modification to INT-003-1 that includes Measures and Levels of NonCompliance. 

831. NERC filed INT-003-2 with the Commission on November 15, 2006. This 

Reliability Standard supersedes the Version 1 Reliability Standard INT-003-1 and adds 

Measures and Levels of Non-Compliance. 

i. Comments

832. APPA states that INT-003-2 fulfils the Commission’s proposed directive to 

include Measures and Levels of Non-Compliance. 

ii. Commission Determination

833. INT-003-1 serves an important purpose in requiring receiving and sending 

balancing authorities to confirm and agree on interchange schedules. With the addition 

of Measures and Levels of Non-Compliance, INT-003-2 addresses the Commission’s 

only reservation regarding this Reliability Standard. Accordingly, the Commission 

approves Reliability Standard INT-003-2, as filed with the Commission on November 15, 

2006, as mandatory and enforceable. 
Docket No. RM06-16-000 - 234 - 

f. Regional Differences to INT-003-2: MISO/SPP Scheduling 

Agent and MISO Enhanced Scheduling Agent

834. NERC proposed a regional difference that would provide MISO and SPP with a 

variance from INT-003-1 to permit a market participant to use a scheduling agent to 

prepare a transaction Tag on its behalf.287 In addition, NERC proposed the MISO 

Enhanced Scheduling Agent Waiver, whichcreates a variance from INT-003-1 for MISO 

that permits an enhanced single point of contact scheduling agent. 

835. The Commission proposed in the NOPR to approve these two additional regional 

differences. The Commission explained that, based on the information provided by 

NERC, the proposed regional differences for this INT Reliability Standard would provide 

administrative efficiency, and provide equal or greater amounts of information to the 

appropriate entities as required in MISO’s Commission-approved multi-control area 

energy market. The NOPR stated that the regional difference is appropriate because it is 

more stringent than the continent-wide Reliability Standard and otherwise satisfies the 

statutory standard for approval of a Reliability Standard. 

i. Comments

836. APPA agrees with the Commission’s proposed approval of these regional 

differences. 

837. FirstEnergy states that it would be helpful if NERC clarified the function and 

effect of these waivers. FirstEnergy states that, where a specific task will be performed 

by another entity on behalf of the transferor, the transferor entity needs a delegation 

agreement, whereas in transferring a responsibility, the transferor entity needs a waiver. 

FirstEnergy states that currently balancing authorities are held accountable by regional 

reliability organizations for those functions the waivers transfer to the regional reliability 

organization. FirstEnergy suggests that NERC should clarify that, under these waivers, 

responsibility for complying with these Reliability Standards should be transferred to the 

RTOs that actually perform the tasks associated with these requirements. 

 287 NERC proposed three regional differences for INT-003-1 that would apply to 

MISO. One proposed regional difference was addressed in Reliability Standard INT001-1. The remaining two are discussed here. 
Docket No. RM06-16-000 - 235 - 

ii. Commission Determination

838. These two variances from INT-003-2, as filed with the Commission on November 

15, 2006, permit a market participant to use a scheduling agent to prepare a transaction 

tag on its behalf, providing administrative efficiency and providing equal or greater 

amounts of information to the appropriate entities as required in MISO’s Commissionapproved multi-control area energy market. This regional difference is appropriate 

because it is more stringent than the continent-wide Reliability Standard and otherwise 

satisfies the statutory standard for approval of a Reliability Standard. The Commission 

therefore approves the MISO/SPP Scheduling Agent Waiver and the MISO Enhanced 

Scheduling Agent Waiver as mandatory and enforceable regional differences to INT-003-

2. 

839. FirstEnergy may raise its suggestions in the Reliability Standards development 

process. However, we find that FirstEnergy’s suggestion does not affect our decision to 

approve these two regional differences. 

g. Dynamic Interchange Transaction Modifications (INT004-1)

840. INT-004-1 seeks 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 Tags for 

dynamic schedules. 

841. In the NOPR, the Commission proposed to approve Reliability Standard INT-004-

1 as mandatory and enforceable. The Commission also proposed to direct NERC to 

submit a modification to INT-004-1 that includes Levels of Non-Compliance. 

i. Comments

842. APPA agrees with the Commission that INT-004-1 can be approved as a 

mandatory and enforceable Reliability Standard. However, it suggests that the missing 

Levels of Non-Compliance should be developed and submitted for Commission approval 

before penalties are levied for violations. 

ii. Commission Determination

843. As explained in the NOPR, 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. Further, the Requirements set forth in INT-004-1 are sufficiently 
Docket No. RM06-16-000 - 236 - 

clear and objective to provide guidance for compliance. Accordingly, the Commission 

approves Reliability Standard INT-004-1 as mandatory and enforceable. In addition, the 

Commission directs the ERO to consider adding these Measures and Levels of NonCompliance to the Reliability Standard. 

h. Interchange Authority Distributes Arranged Interchange 

(INT-005-1)

844. INT-005-1 seeks to ensure the implementation of interchange between source and 

sink balancing authorities and that interchange information is distributed by an 

interchange authority to the relevant entities for reliability assessments. 

845. The Commission proposed in the NOPR to approve Reliability Standard INT-005-

1 as mandatory and enforceable. The Commission also proposed to direct NERC to 

submit a modification to INT-005-1 that includes Levels of Non-Compliance. Further, 

the Commission noted that INT-005-1 is applicable to the “interchange authority” and 

requested 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. 

i. Comments

846. Comments on the interchange authority have been discussed above under the 

heading “INT Reliability Standards General Issues.” No other comments on INT-005-1 

have been submitted. 

ii. Commission Determination 

847. The Commission has set forth above its analysis and conclusion on interchange 

authorities. Our understanding is that, in the interim, source and sink balancing 

authorities will serve as interchange authorities until the ERO has clarified the role and 

responsibility of an interchange authority in the modification of the Functional Model and 

in the registration process. 

848. The Commission is satisfied that the Requirements of INT-005-1 are appropriate 

to ensure that interchange information is distributed timely and available for reliability 

assessment. Accordingly, the Commission approves Reliability Standard INT-005-1 as 

mandatory and enforceable. In addition, the Commission directs the ERO to consider 

adding additional Measures and Levels of Non-Compliance to the Reliability Standard. 
Docket No. RM06-16-000 - 237 - 

i. Response to Interchange Authority (INT-006-1)

849. INT-006-1 applies to balancing authorities and transmission service providers, and 

requires these entities to evaluate the energy profile and ramp rate of generation that 

supports interchange transactions in response to a request from an interchange authority 

to change the status of an interchange from an arranged interchange transaction to a 

confirmed interchange. 

850. The Commission proposed in the NOPR to approve Reliability Standard INT-006-

1 as mandatory and enforceable. In addition, the Commission proposed to direct NERC 

to submit a modification to INT-006-1 that: (1) makes it applicable to reliability 

coordinators and transmission operators and (2) requires reliability coordinators and 

transmission operators to review composite transactions from the wide-area reliability 

viewpoint and, where their review indicates a potential detrimental reliability impact, 

communicate to the sink balancing authorities necessary transaction modifications before 

implementation. 

i. Comments

851. APPA agrees that INT-006-1 is sufficient for approval as a mandatory and 

enforceable reliability standard. However, APPA states that the Commission should 

merely instruct NERC to respond to the Commission’s concerns and refrain from 

directing NERC to make specific changes to the Reliability Standard; APPA states that 

while the changes the Commission proposes may be appropriate, it should be left to 

NERC’s expertise and the Reliability Standards development process to address the 

Commission’s concerns. 

852. FirstEnergy agrees that it is appropriate for the reliability coordinator to be 

included in the applicability section. However, it argues that it is impracticable in large 

organized markets, such as those of MISO and PJM, for a local entity, such as a 

transmission operator, to review wide-area transactions, and it does not improve 

reliability to do so. Transactions occurring totally within the market operation are 

provided as part of network service net scheduled interchange. 

853. EEI states that the “wide-area reliability impact” review envisioned by the 

Commission, which involves review of the composite energy interchange transactions, 

probably already takes place under Reliability Standards INT-005 through INT-009 in a 

cost-effective manner. EEI explains that since most transactions submitted by wholesale 

markets to the transactions tagging process span multiple hours with varying sizes (in 

MW), and are often submitted days before transaction start times, the wide-area review 

consists of ensuring that sufficient generator ramping capability exists, as well as 

examining for limits on transfer capabilities. This review is generally considered 
Docket No. RM06-16-000 - 238 - 

sufficient to the extent that analyses are taking place on the basis of projected system 

conditions. EEI suggests that the Commission-proposed review and validation of 

composite energy interchange transactions by reliability coordinators might be more 

effectively addressed through “near real-time” system review. It explains that, at this 

time, the broad range of system condition parameters is better known, and the reliability 

coordinators can make use of the TLR process to maintain system reliability. 

854. Entergy disagrees with the Commission’s proposed modifications. It contends 

that they will require substantial changes to the tagging specifications. Entergy believes 

that the Commission’s concerns may already be addressed by Reliability Standards INT005 through INT-009. 

855. MISO believes the Reliability Standards and e-Tag specifications already require 

reliability entities to evaluate and approve e-Tags. It questions the value of specifying 

reliability coordinators and transmission operators as applicable entities because their 

responsibilities are already laid out in the Reliability Standards. 

856. Northern Indiana contends that the NOPR’s discussion of INT-006-1 is unclear 

and confusing. It states that it does not understand what the Commission means by 

“validate” when the Commission proposes that reliability coordinators and transmission 

operators review and validate composite arranged interchanges. Northern Indiana also 

questions whether both reliability coordinators and transmission operators would be 

required to validate and approve the Tags and what the basis for approval would be. It 

questions what falls within the term “potential detrimental reliability impact,” what 

happens if a Tag is not validated within 20 minutes to the hour, and whether all schedules 

are canceled outright or passively approved. 

857. TVA suggests that the term “composite Tag” should be defined as part of the 

proposed modifications. CAISO also questions the meaning of “composite Tag” and 

seeks clarification on that issue. TVA notes that depending on the type of reliability 

analysis required to validate a “composite Tag,” it may prove impractical to conduct this 

evaluation for hourly transactions. 

858. CAISO states that neither NERC nor the Commission has identified a deficiency 

in the current interchange reliability assessment process or a pressing reliability need for 

this Reliability Standard. CAISO also has concerns about meeting the Commissionproposed directives regarding INT-006-1 since reliability coordinators and transmission 

operators within the Western Interconnection currently do not have a common database 

from which to draw the information needed to review composite transactions from a 

wide-area reliability viewpoint. CAISO requests the Commission to consider whether the 

Western Interconnection should comply with these proposed Requirements at all or 

whether a transition period is appropriate. 
Docket No. RM06-16-000 - 239 - 

ii. Commission Determination 

859. The Commission approves INT-006-1 as mandatory and enforceable. In addition, 

we direct that NERC develop modifications to the Reliability Standard, as discussed 

below. 

860. The Commission remains convinced that a proactive approach is superior to a 

reactive approach in maintaining system reliability. While EEI and Entergy claim that 

reliability coordinators and transmission operators’ involvement in reliability reviews of 

interchange transactions are covered in INT-005 through INT-010, and MISO claims that 

such review is covered in other Reliability Standards, we note the following: References 

to reliability coordinator and transmission operator involvement are virtually absent from 

the INT Reliability Standards. One finds such references only in Requirement R2 of 

INT-010, which deals with interchange coordination exemptions, and there the 

involvement of reliability coordinators is restricted to situations that involve current or 

imminent reliability-related reasons for action. We cannot find any Requirements in the 

remaining INT Reliability Standards that require a wide-area reliability assessment, 

regardless of the time periods, by a reliability coordinator; wide-area reliability 

assessment, moreover, can only be carried out by reliability coordinators. 

861. With respect to MISO’s comment on the value of applying the Reliability 

Standard to reliability coordinators and transmission operators given that the Reliability 

Standards and the e-Tag specification already require evaluation and active approval of 

reliability entities on e-Tags, we note that none of the INT Reliability Standards have 

those requirements and that the e-Tag specification is not part of the mandatory 

Reliability Standards. Like reliability coordinators who are responsible for reliable 

operation of entire reliability coordinator areas, a transmission operator is the reliability 

entity responsible for its local area operations. Interchange transactions would be likely 

to reduce system reliability if those transactions are not reviewed and approved by the 

appropriate reliability entities before implementation. 

862. With respect to the question raised by TVA and CAISO on the definition of 

“composite Tags,” we expressed our reliability concerns in the NOPR and explained that 

reliability coordinators and transmission operators should review composite energy 

interchange transaction information (composite Tags) for wide-area reliability impact. In 

addition, we stated that 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 before 
Docket No. RM06-16-000 - 240 - 

implementation.288 While we did not require a specific notification time prior to actual 

transactions, this proactive approach should promote system reliability. 

863. We agree with FirstEnergy that it is appropriate to include reliability coordinators 

as applicable entities for purposes of conducting wide-area reliability assessments; in 

large organized markets transmission operators may not be appropriate for this purpose 

because they do not have a wide-area view. 

864. While we did not address review time frames in the NOPR, we are in general 

agreement with EEI’s suggestion that “near-real time” system review by reliability 

coordinators may be more practical, while still being efficient and effective in achieving 

reliability goals. A proactive approach, i.e. one that involves reliability coordinators in a 

way that permits them to make wide-area assessments of composite interchange 

transactions for purposes of evaluating reliability impact, including identifying potential 

IROL violations and mitigating them using TLR procedures before they become actual 

IROL violations, is far superior to a reactive approach, i.e., one that brings reliability 

coordinators in after the fact to invoke TLR procedures to avoid an IROL violation or 

other operating actions to extricate the system from reliability problems such as an actual 

IROL violation. 

865. The Commission stated in Order No. 672 that it expected entities to use the 

Reliability Standards development process to address their concerns about a Reliability 

Standard. With respect to CAISO’s request that the Commission consider whether the 

Western Interconnection needs to comply with these Requirements at all or whether a 

transition period is appropriate, since CAISO did not raise either concern in the 

Reliability Standards development process, and others in the Western Interconnection 

have not raised a similar concern, CAISO should raise this issue in the Reliability 

Standards development process in the first instance. Reliability Standard INT-006-1 will 

apply to CAISO. 

866. Accordingly, the Commission approves Reliability Standard INT-006-1 as 

mandatory and enforceable. In addition, the Commission directs the ERO to develop a 

modification to INT-006-1 through the Reliability Standards development process that: 

(1) makes it applicable to reliability coordinators and transmission operators and (2) 

requires reliability coordinators and transmission operators to review energy interchange 

transactions from the wide-area and local area reliability viewpoints respectively and, 

where their review indicates a potential detrimental reliability impact, communicate to 

the sink balancing authorities necessary transaction modifications before implementation. 

 288 NOPR at P 219. 
Docket No. RM06-16-000 - 241 - 

We also direct that the ERO consider the suggestions made by EEI and TVA and address 

the questions raised by Entergy and Northern Indiana in the course of the Reliability 

Standards development process. 

j. Interchange Confirmation (INT-007-1)

867. Reliability Standard INT-007-1 requires that before changing the status of 

submitted arranged interchanges to confirmed interchanges, the interchange authority 

must verify that the submitted arranged interchanges are valid and complete with relevant 

information and approvals from the balancing authorities and transmission service 

providers. The Commission proposed in the NOPR to approve INT-007-1 as mandatory 

and enforceable. 

i. Comments

868. APPA agrees with the Commission that INT-007-1 is sufficient for approval as a 

mandatory and enforceable Reliability Standard, subject to NERC’s plans for the 

registration of entities as interchange authorities. 

ii. Commission Determination 

869. The Commission approves Reliability Standard INT-007-1 as mandatory and 

enforceable. The Commission has set forth above its analysis and conclusion on 

interchange authorities. Our understanding is that in the interim source and sink 

balancing authorities will serve as interchange authorities until the ERO has clarified the 

role and responsibility of an interchange authority in the modification of Functional 

Model and in the registration process. 

k. Interchange Authority Distribution of Information (INT008-1)

870. INT-008-1 requires the interchange authority to distribute information to all 

balancing authorities, transmission service providers and purchasing-selling entities 

involved in the arranged interchange when the status of the transaction has changed from 

arranged interchange to confirmed interchange. The Commission proposed in the NOPR 

to approve INT-008-1 as mandatory and enforceable. 

i. Comments

871. APPA agrees with the Commission that INT-008-1 is sufficient for approval as a 

mandatory and enforceable Reliability Standard, subject to NERC’s plans for the 

registration of entities as interchange authorities. It suggests that NERC should clarify 

which reliability entities have the responsibility for ensuring that interchange information 
Docket No. RM06-16-000 - 242 - 

is coordinated between the source and sink balancing authorities before implementing the 

Reliability Standard. APPA also states that NERC should modify this Reliability 

Standard to make clear what entities it in fact would apply to. 

ii. Commission Determination 

872. The Commission approves Reliability Standard INT-008-1 as mandatory and 

enforceable. The Commission has set forth above its analysis and conclusion on 

interchange authorities. Our understanding is that a source and sink balancing authority 

will serve as the interchange authority until the ERO has clarified the role and 

responsibility of an interchange authority in the modification of the Functional Model and 

in the registration process. Finally, we direct the ERO to consider APPA’s suggestions in 

the Reliability Standards development process. 

l. Implementation of Interchange (INT-009-1)

873. Reliability Standard INT-009-1 seeks to ensure that the implementation of an 

interchange between source and sink balancing authorities is coordinated by an 

interchange authority. The Commission proposed in the NOPR to approve INT-009-1 as 

mandatory and enforceable. 

i. Comments

874. APPA agrees with the Commission that INT-009-1 is sufficient for approval as a 

mandatory and enforceable Reliability Standard, subject to NERC’s plans for the 

registration of entities as interchange authorities. It suggests that NERC modify its 

Functional Model to clarify which reliability entities have the responsibility for ensuring 

proper implementation of interchange transactions that have received reliability 

assessments. APPA also suggests that NERC modify this Reliability Standard to make 

clear what entities it in fact would apply to. 

ii. Commission Determination 

875. The Commission approves Reliability Standard INT-009-1 as mandatory and 

enforceable. The Commission has set forth above its analysis and conclusion on 

interchange authorities. Our understanding is that a source and sink balancing authority 

will serve as the interchange authority until the ERO has clarified the role and 

responsibility of an interchange authority in the modification of the Functional Model and 

in the registration process. Finally, we direct the ERO to consider APPA’s suggestions 

concerning this Reliability Standard in the Reliability Standards development process. 
Docket No. RM06-16-000 - 243 - 

m. Interchange Exemptions (INT-010-1) 

876. INT-010-1 allows reliability entities to initiate or modify certain types of 

interchange schedules under abnormal operating conditions and to be exempt from 

compliance with other INT Reliability Standards. 

877. The Commission explained in the NOPR that 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. The Commission interpreted 

these current or imminent reliability-related reasons as not including actual IROL 

violations, since they require immediate action so that the system can be returned to a 

secure operating state as soon as possible and no longer than 30 minutes after a 

reliability-related system interruption – a period that is much shorter than the time that is 

expected to be required for new or modified transactions to be implemented. 

878. The Commission proposed to approve INT-010-1, interpreted as set forth above, 

as mandatory and enforceable. 

i. Comments

879. Northern Indiana supports the Commission’s interpretation of INT-010-1, but it 

requests that the Reliability Standard be modified to explicitly state that it does not 

include actual IROL violations.

880. ISO-NE supports Commission approval of INT-010-1, but does not share the 

Commission’s concerns regarding the initiation or modification of interchange schedules 

to address SOL or IROL violations. It states that interchange schedules can in certain 

circumstances provide an additional effective tool to help prevent an SOL and IROL 

violation. While ISO-NE recognizes that other tools may in certain circumstances be 

more effective, it states that this neither diminishes the value nor precludes the use of the 

tools contained in INT-010-1. ISO-NE also notes that section 2.4 of INT-010-1, which 

describes Level 4 Non-Compliance, should be edited to state that “[t]here shall be a level 

four non-compliance. . . ” instead of “[t]here shall be a level three non-compliance. . . .” 

881. APPA agrees with the Commission that INT-010-1 is sufficient for approval as a 

mandatory and enforceable Reliability Standard, but APPA does not agree with the 

Commission’s interpretation of the Reliability Standard. APPA explains that the stated 

purpose of INT-010-1 is to allow certain types of interchange schedules to be initiated or 

modified by reliability entities and to be exempt from compliance with other interchange 

standards under abnormal operating conditions. This Reliability Standard in effect 

authorizes reliability coordinators to direct, and balancing authorities to take, remedial 
Docket No. RM06-16-000 - 244 - 

actions to adjust interchange schedules immediately and then document these actions 

after the fact. INT-010-1 thus provides the emergency waiver from other INT Reliability 

Standards that makes adjusting interchange schedules the appropriate response to a SOL 

or IROL. APPA states that the Commission’s proposed interpretation therefore should 

not be adopted. 

882. EEI cautions against adopting the Commission’s interpretation of INT-010-1. EEI 

believes that the existing standard meets the Commission’s expectation, i.e., permitting 

and encouraging immediate action to alleviate an SOL or IROL. EEI explains that 

without INT-010-1, all interchange scheduling and schedule modifications would go 

through the normal process contained in INT-005 through INT-009. Only INT-010 

would allow a balancing authority to make an immediate interchange action without 

obtaining a Tag. Within 60 minutes of the action, the balancing authority would follow 

up with the necessary documentation and carry forward the action, if necessary. In the 

absence of INT-010-1, a balancing authority taking such action would be in violation of 

INT-009 for failing to comply with the normal process requirements. 

883. EEI notes by way of example that, to relieve an SOL or IROL, a reliability 

coordinator requires immediate offsetting changes in the net scheduled interchange of 

ACE equations of source and sink balancing authorities. Within 60 minutes following 

the action, the reliability authority directs the balancing authority to reflect the schedule 

change event using an arranged interchange. The tagging activity ensures coordination 

going forward and provides a written record. All of this takes place after the operational 

tasks pertaining to the action to alleviate the SOL or IROL, consistent with Commission 

expectations. 

ii. Commission Determination 

884. For the reasons and interpretation noted in the NOPR, the Commission approves 

INT-010-1 as mandatory and enforceable. 

885. The Commission believes that our interpretation of INT-010-1 is consistent with 

the way APPA and EEI understand the Reliability Standards. The Commission believes 

that making a modification to an existing interchange schedule on paper for current or 

imminent reliability-related situations involving actual IROL violations is ineffective 

because its implementation usually takes much longer than the 30 minutes period that is 

allowed in the relevant IRO or TOP Reliability Standards. However, the Commission 

interprets INT-010-1 as allowing the actual physical transaction to be modified to 

alleviate an IROL event without first documenting the modification. The interchange 

schedule would then be modified after the fact to document the physical actions taken. 
Docket No. RM06-16-000 - 245 - 

886. With regard to ISO-NE’s statement that interchange schedules can, in certain 

circumstances, provide an additional effective tool to help prevent SOL and IROL 

violations while other tools may, in certain circumstances, be more effective, the 

Commission clarifies that our concern is related to using interchange schedules to address 

actual IROL violations. We have no concern in using this as a tool help prevent potential 

SOL and IROL violations as asserted by ISO-NE. We further note that the phrase in 

Requirements R2 and R3 “current or imminent reliability-related reasons” can be 

interpreted as potential or actual IROL violations set forth in the comments from 

Northern Indiana, ISO-NE, APPA and EEI, and therefore modifications to INT-010-1 are 

needed. 

887. Accordingly, the Commission approves Reliability Standard INT-010-1 as 

mandatory and enforceable. In addition, we adopt the interpretation set forth in the 

NOPR that these current or imminent reliability-related reasons do not include actual 

IROL violations, since 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 

after a reliability-related system interruption – a period that is much shorter than the time 

that is expected to be required for new or modified transactions to be implemented. 

Finally, we direct the ERO to consider Northern Indiana and ISO-NE’s suggestions in the 

Reliability Standards development process. 

7. IRO: Interconnection Reliability Operations and Coordination

888. The Interconnection Reliability Operations and Coordination (IRO) group of 

Reliability Standards detail the responsibilities and authorities of a reliability 

coordinator.289 The IRO Reliability Standards establish requirements for data, tools and 

wide-area view, all of which are intended to facilitate a reliability coordinator’s ability to 

perform its responsibilities and ensure the reliable operation of the interconnected grid. 

 289 According to the NERC glossary, at 15, a reliability coordinator is “the entity 

with the highest level of authority who is responsible for the reliable operation of the 

Bulk Electric System, has the Wide Area view of the Bulk Electric System, and has the 

operating tools, processes and procedures, including the authority to prevent or mitigate 

emergency operating situations in both next-day analysis and real-time operations....” 
Docket No. RM06-16-000 - 246 - 

a. Reliability Coordination – Responsibilities and 

Authorities (IRO-001-1)

889. IRO-001-1 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. 

890. In November 2006, NERC submitted IRO-001-1, which includes Measures and 

Levels of Non-Compliance.290 In addition, while the Version 0 Reliability Standard 

applied to reliability coordinators and regional reliability organizations, IRO-001-1 would 

in addition apply to transmission operators, balancing authorities, generator operators, 

transmission service providers, LSEs and purchasing-selling entities. The Version 1 

Reliability Standard does not modify or add any Requirements, and it appears that the 

change in applicability corresponds to existing Requirement R8, which provides that 

transmission operators, balancing authorities, generator operators, transmission service 

providers, LSEs and purchasing-selling entities “shall comply with Reliability 

Coordinator directives unless such actions would violate safety, equipment, or regulatory 

or statutory requirements.” 

891. In the NOPR, the Commission proposed to approve the Reliability Standard as 

mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 

39.5(f) of our regulations, the Commission proposed to direct NERC to 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. 

i. Comments

892. APPA supports the approval of the Reliability Standard but expresses concern that 

the Version 1 standard does not include Measures that correspond to Requirements R2 

and R9. APPA emphasizes the need for Measures corresponding to Requirement R9, 

which requires the reliability coordinator to act in the interests of reliability for the 

overall reliability coordinator area and the Interconnection before the interests of any 

other entity. APPA supports Requirement R8 with the extended applicability, provided 

that applicability is determined by reference to the NERC compliance registry. APPA 

agrees that the regional reliability organization should be eliminated as an applicable 

entity and suggests it be replaced with Regional Entities. 

 290 IRO-001-1 supercedes the Version 0 Reliability Standard. In this Final Rule, 

we review the November version, IRO-001-1. 
Docket No. RM06-16-000 - 247 - 

893. FirstEnergy suggests that NERC clarify whether Requirement R8, which requires 

entities to comply with a reliability coordinator directive “unless such actions would 

violate safety, equipment or regulatory or statutory requirements,” refers to personnel 

safety, equipment safety or both. In addition, it suggests the establishment of a chain of 

command so that, for example, if a generator receives conflicting instructions from a 

balancing authority and a transmission operator, it can determine which instruction 

governs. 

894. Requirement R3 provides that a reliability coordinator “shall have clear decisionmaking authority to act and direct actions to be taken” by applicable entities to “preserve 

the integrity and reliability of the Bulk Electric System and these actions shall be taken 

without delay but no longer than 30 minutes.” Santa Clara contends that some actions 

would require driving to a remote site and therefore, mandating completion of the 

required action within 30 minutes would be unreasonable. Thus, it recommends that 

NERC modify Requirement R3 to provide that “actions shall commence without delay, 

but in any event shall commence within 30 minutes.” 

895. California Cogeneration comments that the Reliability Standard fails to address 

the operational limitations of QFs because they have contractual obligations to provide 

thermal energy to their industrial hosts. It contends that a QF can be directed to change 

operations only in the case of a system emergency, pursuant to 18 CFR § 292.307. 

ii. Commission Determination

896. In the NOPR, the Commission proposed to approve the Reliability Standard as 

mandatory and enforceable. In addition, as a separate action under section 215(d)(5), the 

NOPR proposed to direct the ERO to develop modifications to Requirement R1291 to 

substitute “Regional Entity” for “regional reliability organization” and reflect NERC’s 

Rules of Procedure for registering, certifying and verifying entities, including reliability 

coordinators. Commenters do not raise any concerns regarding the proposed action. 

Accordingly, for the reasons stated in the NOPR, the Commission approves IRO-001-1 as 

mandatory and enforceable. In addition, for the reasons discussed in the NOPR, the 

Commission directs the ERO to develop modifications to the Reliability Standard 

through the Reliability Standards development process that reflect the process set forth in 

 291 Requirement R1 of IRO-001-1 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. See NOPR at P 506. 
Docket No. RM06-16-000 - 248 - 

the NERC Rules of Procedures and eliminate the regional reliability organization as an 

applicable entity.292 

897. While APPA, FirstEnergy and California Cogeneration suggest possible changes 

to IRO-001-1, they do not suggest that the proposed Reliability Standard should not be 

approved. The ERO should consider the commenters’ suggestions when modifying the 

Reliability Standard pursuant to its Reliability Standards development process. Further, 

the Commission directs the ERO to consider adding Measures and Levels of NonCompliance in the Reliability Standard as requested by APPA. 

898. However, we disagree with Santa Clara’s suggested change regarding the 30-

minute limit to implement a corrective control action in Requirement R3. When system 

integrity or reliability is jeopardized, e.g., exceeding IROLs or SOLs, the relevant 

reliability entities must take corrective control actions to return the system to a secure and 

reliable state as soon as possible and in no longer than 30 minutes. This is important to 

satisfy the relevant Reliability Standards such as IRO-005-0 and TOP-004-0 to minimize 

the amount of time the system operates in an insecure mode and is vulnerable to 

cascading outages. 

b. Reliability Coordination – Facilities (IRO-002-1)

899. IRO-002-1 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, to act in addressing real-time emergency 

conditions and to control analysis tools.293 

900. In the NOPR, the Commission proposed to approve the Reliability Standard as 

mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and 

§ 39.5(f) of our regulations, the Commission proposed to direct NERC to submit a 

modification 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. 

 292 See NOPR at P 505-06. 

293 In its November 15, 2006, filing, NERC submitted IRO-002-1, which 

supercedes the Version 0 Reliability Standard. IRO-002-1 adds Measures and Levels of 

Non-Compliance to the Version 0 Reliability Standard. In this Final Rule, we review the 

November version, IRO-002-1. 
Docket No. RM06-16-000 - 249 - 

i. Comments

901. Dominion agrees with the proposal to require a minimum set of tools for 

reliability coordinators, explaining that such specificity is needed to ensure that proactive 

efforts to maintain reliability are being continuously pursued. According to Dominion, a 

general requirement for “adequate” tools is insufficient and the proposal to modify IRO002-1 is appropriate since it will ensure that operators have a minimum set of tools with 

which to perform their duties. 

902. In contrast, both APPA and LPPC ask the Commission to reject the proposal to 

require a minimum set of tools because flexibility is needed to allow change as 

technology improves over time. LPPC states that the Commission should, instead, 

require a listing of capabilities that is not tied to a particular product or tool. APPA 

contends that, because the Measures now require the reliability coordinator to provide 

specifications to the Regional Entity to be in compliance, the Regional Entity will set the 

minimum standards for reliability tools. Further, according to APPA, setting a minimum 

requirement would establish a “lowest common denominator” that might prove 

counterproductive. 

903. MRO states that IRO-002-0 is another Reliability Standard for which it will be 

difficult to identify Measures and Levels of Non-Compliance because the Requirements 

include terms like “adequate,” “potential,” “could result” and “as required.” 

ii. Commission Determination

904. NERC’s November 2006 revision to the Reliability Standard satisfies the proposal 

to include Measures and Levels of Non-Compliance. While MRO comments that it will 

be difficult to identify Measures and Levels of Non-Compliance, it does not provide any 

specific suggestions for changes to NERC’s proposal. 

905. Further, consistent with the NOPR, the Commission directs the ERO to modify 

IRO-002-1 to require a minimum set of tools that must be made available to the 

reliability coordinator. We believe that this requirement will ensure that a reliability 

coordinator has the tools it needs to perform its functions. Further, as noted by 

Dominion, such a requirement promotes a more proactive approach to maintaining 

reliability. 

906. With respect to the concerns of APPA and LPPC, the Commission clarifies that 

the Commission’s intent is to have the ERO develop a requirement that identifies 

capabilities, not actual tools or products. The Commission agrees that the latter approach 

is not appropriate as a particular product could become obsolete and technology improves 

over time. We disagree with APPA that our concern is addressed by the new Measures 
Docket No. RM06-16-000 - 250 - 

as they neither specify a minimum set of capabilities nor require any uniformity among 

reliability coordinators or Regional Entities. We do not believe that the identification of 

minimum capabilities translates to “lowest common denominator” as suggested by 

APPA. If the Reliability Standards development process results in developing a “lowest 

common denominator” Reliability Standard that is geared toward guaranteeing 

compliance and avoiding penalties as opposed to ensuring reliability, the Commission 

could remand such a Reliability Standard.294

907. We disagree with MRO that it will be difficult to identify Measures and Levels of 

Non-Compliance since the Requirements include terms like “adequate,” “potential,” 

“could result” and “as required.” Many tariffs on file with the Commission do not 

specify every compliance detail, but rather provide some level of discretion as necessary 

to carry out a particular act. This does not mean the tariffs are unenforceable; rather, it 

means that, if a dispute arises over compliance and there is a legitimate ambiguity 

regarding a particular fact or circumstance, that ambiguity can be taken into account in 

the exercise of the Commission's enforcement discretion. 

908. As we stated in the NOPR,295 Reliability Standard IRO-002-1 serves an important 

purpose in ensuring that reliability coordinators have the information, tools and 

capabilities to perform their functions. The Measures and Levels of Non-Compliance 

submitted by NERC further enhance the Reliability Standard. Accordingly, the 

Commission approves Reliability Standard IRO-002-1 as mandatory and enforceable. In 

addition we direct the ERO to develop a modification to IRO-002-1 through the 

Reliability Standards development process that requires a minimum set of tools that 

should be made available to reliability coordinators.

c. Reliability Coordination – Wide Area View (IRO-003-2)

909. The purpose of IRO-003-2 is for a reliability coordinator to have a wide-area view 

of its own and adjacent areas to maintain situational awareness. Wide-area view also 

 294 See Order No. 672 at P 329. 

295 NOPR at P 511. 
Docket No. RM06-16-000 - 251 - 

facilitates a reliability coordinator’s ability to calculate SOL and IROL as well as 

determine potential violations in its own area.296 

910. In the NOPR, the Commission proposed to approve the Reliability Standard as 

mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA and 

§ 39.5(f) of our regulations, the Commission proposed to direct NERC to submit a 

modification 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. 

i. Comments

911. APPA agrees that IRO-003-2 is sufficient for approval as a mandatory and 

enforceable Reliability Standard. However, APPA suggests that, instead of merely 

including criteria to define critical facilities as proposed, NERC and each Regional Entity 

should establish, document, use and make transparent the methodology, data and 

procedures they use to determine “critical facilities.” 

912. Entergy agrees with the need for the criteria, but cautions that it must be flexible 

enough to allow for changing conditions experienced in real-time operations. Xcel notes 

that the term “critical facilities” is not defined and suggests that the Reliability Standard 

not be approved until the term is defined. 

ii. Commission Determination 

913. For the reasons stated in the NOPR,297 the Commission approves proposed 

Reliability Standard IRO-003-2 as mandatory and enforceable. NERC’s November 2006 

revision to the Reliability Standard satisfies the proposal to include Measures and Levels 

of Non-Compliance. 

914. Further, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, 

we adopt in the Final Rule the proposal to direct that the ERO develop a modification to 

the Reliability Standard through the Reliability Standards development process to create 

criteria to define the term “critical facilities” in a reliability coordinator’s area and its 

 296 In its November 15, 2006, filing, NERC submitted IRO-003-2, which 

supercedes the Version 0 Reliability Standard. IRO-003-2 adds Measures and Levels of 

Non-Compliance to the Version 0 Reliability Standard. In this Final Rule, we review the 

November version, IRO-003-2. 

297 See NOPR at P 519. 
Docket No. RM06-16-000 - 252 - 

adjacent systems. In developing the required modification, the ERO should consider the 

suggestions of APPA, Entergy and Xcel. 

d. Reliability Coordination – Operations Planning (IRO-004-

1)

915. The purpose of IRO-004-1 is to require each reliability coordinator to conduct 

next-day operations reliability analyses to ensure that the system can be operated reliably 

in anticipated normal and contingency system conditions. Operations plans must be 

developed to return the system to a secure operating state after contingencies and shared 

with other operating entities. 

916. In the NOPR, the Commission proposed 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 proposed to direct NERC to 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. 

i. Comments

917. APPA agrees that IRO-004-1 is sufficient for approval as a mandatory Reliability 

Standard and that the Requirements are sufficiently clear and objective to provide a basis 

for issuing a remedial action directive. However, it contends that many Requirements 

lack Measures and Levels of Non-Compliance, and the ERO and Regional Entities 

should not assess penalties until additional Measures and Levels of Non-Compliance are 

developed. 

918. Entergy agrees that a mitigation plan for potential operating problems identified in 

the next-day analysis may be an appropriate requirement, but cautions that it would be 

inappropriate to penalize an entity that chooses an alternate mitigation strategy when the 

issues arise in real time based on system conditions prevalent at that time. 

919. APPA, in contrast, disagrees with the proposed directive to identify effective 

control actions in the next-day analysis. It contends that real-time conditions are seldom 

the same as predicted in the day-ahead schedule, and state estimators using real-time 

operating conditions are much more accurate than analyses based on day-ahead 

schedules. 

920. FirstEnergy contends that IRO-004-1 should require a day-ahead planning process 

and reflect activities inherent within a market operation. 

921. Northern Indiana contends that the Commission’s proposed directive is unclear. 

It asks whether the Commission is requiring the reliability coordinator to secure the 
Docket No. RM06-16-000 - 253 - 

system to an N-2 state, rather than an N-1 state within the next-day planning analysis. It 

contends that currently the Reliability Standard is N-1, and requests clarification that the 

Commission did not intend to mandate an increase in security from N-1 to N-2 in the 

NOPR. 

922. California PUC agrees that there is merit in requiring system operators to assess 

the outlook for the following day, but nevertheless is concerned with the Commission’s 

proposed directive. Its main concern is that the list of identified control actions can be 

too long or too generic to be effective to address the myriad potential system 

contingencies that could arise on the next day. 

923. California Cogeneration states that the proposed Reliability Standard allows 

reliability coordinators to require data on gross load and generation behind the site 

boundary meter, which is contrary to a prior Commission order.298

ii. Commission Determination

924. For the reasons stated in the NOPR,299 the Commission approves proposed 

Reliability Standard IRO-004-1 as mandatory and enforceable. In addition, the 

Commission directs the ERO to develop modifications to the Reliability Standard, as 

discussed below. 

925. We agree with Entergy that system operators must make their decision to use the 

most effective control action based on the prevailing system conditions, to return the 

system to a secure state following a contingency. Therefore, the chosen control action 

may be different than those identified in next-day operations planning. We reiterate that 

our intent is to require a comprehensive next-day operations planning study that includes 

identification of effective solutions to aid system operators in real-time operations. 

926. We disagree with APPA’s comment that day-ahead planning to identify effective 

control actions would not enhance system reliability because we believe this is also the 

intent of the ERO for including such a Requirement in this Reliability Standard.300 Our 

 298 California Independent System Operator Corp., 96 FERC ¶ 63,015 at 7 (2001). 

It states in part “The intent of the Commission’s directive was to remove the requirement 

to provide any behind-the-meter information, whether on generation or load.” 

299 See NOPR at P 529. 

300 IRO-004-1 Purpose Statement states in part “Plans must be developed to 

alleviate SOL and IROL violations.” 
Docket No. RM06-16-000 - 254 - 

proposed directive is to augment the Requirement that the plans to alleviate SOL and 

IROL violations are assessed to ensure that the control actions can be implemented and 

effective within 30 minutes after a contingency. 

927. We agree with APPA that state estimators and real-time contingency analyses 

using real-time operating conditions produce more accurate study results compared to 

those from next-day operations planning analyses that are based on day-ahead schedules 

and forecast conditions. However, we remain convinced that a proactive approach that 

includes identification of effective operating solutions to deal with contingencies is far 

superior to a reactive approach that identifies solutions when the system conditions 

prevail in real-time operations. The former can identify solutions that may not be 

otherwise available to the system operators – e.g. certain planned generation or 

transmission outages are approved conditional upon re-affirmation prior to their removal 

from service or a short recall time subject to certain system conditions developing in realtime operations. 

928. We disagree with FirstEnergy that IRO-004-1 should include the day-ahead 

planning process and reflect activities inherent in a market operation because day-ahead 

planning includes financial activities that may not occur in real-time. The Commission 

believes that, for reliability purposes, the simulation should include only what will 

actually occur. 

929. The proposed Reliability Standards IRO-005-1 and TOP-004-0 require that in the 

event of an IROL violation, i.e. power flow on an interface exceeding its IROL, the 

system must be returned to a secure state within 30 minutes regardless of the cause of the 

violation, so that the system is once again capable of withstanding the next contingency 

without resulting in cascading failures. 

930. In response to Northern Indiana, our intent is not to mandate an increase in 

security from N-1 to N-2, but rather is to ensure there is no reliability gap in the IROLrelated Reliability Standards. To do this, the Commission believes it is necessary to 

provide operators with control actions needed to mitigate an IROL violation while within 

the 30 minute period after a first contingency. We are not requiring an increase to N-2, 

which would require planning the system for any two contingencies at all times. 

931. With respect to California PUC’s comment, we note that it is just as important for 

day-ahead operation planners to review and derive system operating limits to deal with a 

myriad of contingencies for different system configurations and generation dispatches, as 

it is for them to assess the feasibility of returning the system to a secure operating state 

after these contingencies have occurred. Similar to reviewing and deriving SOLs and 

IROLs to ascertain that system reliability will be maintained based on the most onerous 

forecast conditions and critical contingencies, identifying corrective control actions 
Docket No. RM06-16-000 - 255 - 

would not encompass each and every contingency and system condition. This is because 

previous operating experiences and established operating practices would have covered a 

significant portion of the contingencies and the corresponding control actions already. 

932. We further note that for those few IROL contingencies under the forecast and 

most onerous system conditions, if operation planners equipped with a suite of off-line 

analytical tools, but without any burden, distraction or interference from real-time 

operations, cannot identify the effective control actions, it can be argued that it would be 

unrealistic to expect system operators to do so with an additional requirement – i.e.

identification and implementation of an effective control action all within 30 minutes. In 

addition, the control actions identified in the next-day analysis may quite often provide 

relevant information to the system operators of the control options they have available. 

933. We believe that our use of NERC’s definition of bulk electric system in 

combination with its registration process should assuage California Cogeneration’s 

concerns. 

934. In response to APPA’s concern that NERC did not provide a Measure for each 

Requirement, we reiterate that it is in the ERO’s discretion whether each Requirement 

requires a corresponding Measure. The ERO should consider this issue through the 

Reliability Standards development process. 

935. Accordingly, we approve Reliability Standard IRO-004-1 as mandatory and 

enforceable. Further, we direct the ERO to modify IRO-004-1 through the Reliability 

Standards development process to require the next-day analysis to identify control actions 

that can be implemented and effective within 30 minutes after a contingency. The 

Commission also directs the ERO to consider adding Measures and Levels of NonCompliance to the Reliability Standard as requested by APPA. 

e. Reliability Coordination – Current Day Operations (IRO005-1)

936. IRO-005-1 ensures energy balance and transmission reliability for the current day 

by identifying tasks that reliability coordinators must perform throughout the day. 

937. In the NOPR, the Commission proposed 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 proposed to direct NERC to submit a 

modification to IRO-005-1 that includes Measures and Levels of Non-Compliance. The 

Commission proposed that the Measures and Levels of Non-Compliance specific to 

IROL violations should be commensurate with the magnitude, duration, frequency and 

causes of the violation. Further, the Commission proposed to direct the ERO to conduct 
Docket No. RM06-16-000 - 256 - 

a survey on IROL practices and actual operating experiences, and indicated that it may 

propose further modifications to IRO-005-1 based on the survey results.301

i. Comments

938. FirstEnergy supports the approval of the proposed Reliability Standard as 

mandatory and enforceable as interpreted by NERC (i.e., that exceeding IROL for less 

than 30 minutes is not a violation), pending further action through the NERC Reliability 

Standards development process. 

939. MidAmerican supports the Commission’s proposed survey and notes that based on 

its experience, IROL violations have been faithfully reported across NERC. 

940. The CAISO urges the Commission to proceed with caution if headed in the 

direction of absolute compliance with IROL. However, it supports the survey to 

determine the extent to which systems are actually “drifting” in and out of IROL limits. 

941. APPA indicates its support of the Commission’s directive to undertake a survey 

regarding IROL practices and experiences. However it feels that it should be NERC’s 

role to decide on the survey. It contends that, based on the survey results and using the 

Reliability Standard development process, NERC would decide what modifications to 

IRO-005-2 are appropriate.

942. Entergy agrees that it is appropriate to use a mitigation plan to resolve an SOL or 

IROL violation when the actual contingency that causes an SOL or IROL violation is 

experienced. However, with an acceptable mitigation plan, it is not necessary to require 

transmission operators to keep facility loading below a level where a potential SOL or 

IROL violation would occur assuming a low probability of the contingency. Entergy 

requests clarification that the Commission’s guidance is not intended to preclude the use 

of such alternative procedures. The Commission should be cautious not to restrictively 

define SOL or IROL in a manner that causes the system operator to take preemptive 

action through this Reliability Standard to address events that may technically be SOL or 

 301 NOPR at P 545 (“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 reliability coordinators to report 

any violations of IROLs, their causes, the date and time of the violations, 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 - 257 - 

IROL violations, but which have a low probability of occurrence and can be mitigated 

through other proven procedures. 

943. ISO-NE agrees that NERC should promptly address the ambiguities in the current 

definition of an IROL. It has a concern that the phrase “The Transmission Service 

Provider shall respect these SOLs and IROLs” in Requirement R14 may cause confusion 

that this entity is expected to respect SOLs and IROLs in the operating time frame.302

944. TAPS raises an issue with Requirement R13 that states in part “[i]n instances 

where there is a difference in derived limits,...Load-Serving Entities...shall always 

operate the Bulk Electric System to the most limiting parameter.” TAPS further states 

that, since LSEs do not operate the system within SOLs or IROLs, the only thing such 

entities, particularly small ones, can do is shed load. It contends that if the Reliability 

Standard is mandatory, it should apply only within the parameters proposed by NERC—

subject to its Bulk Electric System definition and its June registry criteria. Further, given 

the apparent error in the Reliability Standard, the Commission should ask NERC to reexamine it. 

ii. Commission Determination

945. The Commission approves proposed Reliability Standard IRO-005-1 as mandatory 

and enforceable. In addition, the Commission directs the ERO to develop modifications 

to the Reliability Standard through the Reliability Standards development process, as 

discussed below. 

946. The Commission clarifies the intent of and need for the proposed survey. We 

reiterate that the intent is to learn about the operating experiences and practices of 

operating entities; specifically, how they operate their systems to respect IROLs in the 

normal system conditions, i.e. prior to a contingency. The survey results will facilitate 

future development and modifications of IROL-related Reliability Standards to better 

clarify and eliminate potential multiple interpretations of respecting IROLs that may exist 

 302 IRO-005-1 Requirement R14 states “Each Reliability Coordinator shall make 

known to Transmission Service Providers within its Reliability Coordinator Area, SOLs 

or IROLs within its wide-area view. The Transmission Service Provider shall respect 

these SOLs or IROLs in accordance with filed tariffs and regional Total Transfer 

Calculation and Available Transfer Calculation processes.” 
Docket No. RM06-16-000 - 258 - 

in the proposed Reliability Standards.303 In addition, the survey will identify the 

reliability risks and the frequency and number of operating practices involving drifting in 

and out of IROL.304 The survey results will also provide guidance on the frequency, 

duration and magnitude of IROL violations, their causes and whether these IROL 

violations occur during normal or contingency conditions. 

947. We note the support from FirstEnergy, MidAmerican, CAISO and APPA for our 

proposed survey. Regarding MidAmerican’s comment that reporting on IROL violations 

is a routine practice, we note that the proposed Reliability Standards only require 

reporting on those violations that have exceeded IROLs for longer than 30 minutes. The 

current reporting requirements and results will not provide an adequate assessment of the 

existing operating practices regarding IROLs and the reliability risks and the extent of 

drifting in and out of IROLs. 

948. In response to Entergy, the Commission believes that operating the system within 

IROL under normal system condition and 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, may be appropriate. This mode of operation will minimize the system 

risk of being one contingency away from potential cascading failures. 

949. ISO-NE asks that the ERO should promptly clarify the current definition for 

IROL violations. However, we do not share ISO-NE’s concern that transmission service 

providers may be responsible for respecting SOLs and IROLs in real-time operation. 

Requirement R14 only requires a transmission service provider to use the SOLs and 

IROLs provided by the reliability coordinator in its tariff, it does not require any action in 

the operating time frame. 

 303 NOPR at P 540: IRO-005-1 could be interpreted as allowing a system operator 

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. 

304 The term “drifting in and out of IROLs” refers to operating the normal system 

(i.e. prior to a contingency) with frequent occurrences in which IROLs are exceeded, but 

each occurrence lasting less than 30 minutes. Currently, this mode of operation is not 

considered as a violation of NERC Reliability Standards. 
Docket No. RM06-16-000 - 259 - 

950. We do not share TAPS’ concern regarding LSEs initiating load shedding as their 

own control action to respect IROLs or SOLs. The appropriate control actions to respect 

IROLs and SOLs are the responsibilities of a reliability coordinator and transmission 

operator. If load shedding is required, it is the responsibility of a reliability coordinator 

or a transmission operator to direct the appropriate entities including LSEs to carry it out. 

However, we urge the ERO to provide further clarification in this regard and include 

TAPS’ concern in developing the modification of this Reliability Standard. 

951. Accordingly, the Commission approves Reliability Standard IRO-005-1 as 

mandatory and enforceable. Further, because IRO-005-1 has no Measures or Levels of 

Non-Compliance, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our 

regulations, the Commission directs the ERO to develop a modification to IRO-005-1 

through the Reliability Standards development process that includes Measures and Levels 

of Non-Compliance. The Commission further directs that the Measures and Levels of 

Non-Compliance specific to IROL violations must be commensurate with the magnitude, 

duration, frequency and causes of the violations and whether these occur during normal 

or contingency conditions. Finally, the Commission directs the ERO to conduct a survey 

on IROL practices and actual operating experiences by requiring reliability coordinators 

to report any violations of IROL, their causes, the date and time, the durations and 

magnitudes in which actual operations exceeds IROLs to the ERO on a monthly basis for 

one year beginning two months after the effective date of the Final Rule. We may 

propose further modifications to IRO-005-1 based on the survey results. 

f. Reliability Coordination – Transmission Loading Relief 

(IRO-006-3)

952. 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.305 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. It also includes by 

reference the equivalent Interconnection-wide congestion management methods used in 

the WECC and ERCOT regions. 

 305 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. 
Docket No. RM06-16-000 - 260 - 

953. In the NOPR, the Commission proposed 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 proposed to direct NERC to submit a 

modification to IRO-006-3 that: (1) includes a clear warning that a 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. In addition, the Commission proposed to approve the WECC and ERCOT 

load relief procedures as superior to the national standard. 

i. Comments

954. APPA agrees that IRO-006-3 is sufficient for approval as a mandatory Reliability 

Standard. It suggests that the ERO should consider development of detailed Measures 

and Levels of Non-Compliance that address each Requirement in IRO-006-3. Until then, 

penalties should not be imposed except for egregious violations and the associated 

penalties should be imposed by the Commission. 

955. APPA, Entergy and MidAmerican agree that the TLR procedure is an 

inappropriate and ineffective tool to mitigate actual IROL violations and that a clear 

warning to that effect should be included. MidAmerican specifically suggests that the 

warning must also apply to actual emergency situations in addition to actual IROL 

violations.

956. Similarly, ISO-NE supports the Commission’s conclusions with regard to reliance 

on TLRs to address actual IROL violations. Further, it supports the Commission’s 

proposal that the ERO should modify the Reliability Standard to provide flexibility for 

ISOs and RTOs to rely on redispatch as a means to mitigate an IROL violation. 

957. Xcel suggests that instead of the proposed modification of a clear warning, it 

should include a requirement that TLR procedures should not be used for alleviating 

actual IROL violations. It asserts that the latter approach would be more measurable than 

the Commission’s proposed modification. 

958. Entergy and MidAmerican believe that TLR procedures can be an effective 

mechanism to avoid potential SOL and IROL violations or potential emergency 

situations. 

959. In contrast, Progress Energy disagrees with the Commission’s reasoning on the 

ineffectiveness of using TLR procedures to alleviate actual IROL violations. 
Docket No. RM06-16-000 - 261 - 

ii. Commission Determination

960. The Commission approves IRO-006-3 as mandatory and enforceable. In addition, 

we direct the ERO to develop modifications to the Reliability Standard as discussed 

below. 

961. The Commission remains convinced, based on Blackout Recommendation No. 

31,306 the submissions from APPA, Entergy, MidAmerican, ISO-NE and Xcel, and 

NERC’s comments on the Staff Preliminary Assessment,307 that proposed directives to 

include a clear warning that a TLR procedure is an inappropriate and ineffective tool to 

mitigate IROL violations and to identify the available alternatives to use of the TLR 

procedure to mitigate an IROL violation are the appropriate improvements to address the 

deficiencies in using TLR procedures to mitigate actual IROL violations or actual 

emergency situations. The Commission endorses Blackout Recommendation No. 31. 

962. The Commission agrees with Entergy and MidAmerican that TLR procedures can 

be an effective mechanism to avoid potential IROL violations and potential emergencies. 

Regarding this, we reiterate that our concerns have always been on the use of TLR to 

mitigate actual IROLs or actual emergencies, and not on potential IROLs or emergencies, 

as indicated in the Blackout Report, Staff Assessment and the NOPR. 

963. We do not understand Progress Energy’s disagreement because no reason is 

provided. 

964. Accordingly, in addition to approving the Reliability Standard, the Commission 

directs the ERO to develop a modification to IRO-006-3 through the Reliability 

Standards development process that (1) includes a clear warning that the TLR procedure 

is an inappropriate and ineffective tool to mitigate actual IROL violations and (2) 

identifies in a Requirement the available alternatives to mitigate an IROL violation other 

than use of the TLR procedure. In developing the required modification, the ERO should 

consider the suggestions of MidAmerican and Xcel. In addition, the Commission 

 306 Blackout Recommendation No. 31, at 163 is to “Clarify that the transmission 

loading relief (TLR) process should not be used in situations involving an actual violation 

of an Operating Security Limit.” 

307 The NERC comments to Staff Assessment at 49 state that “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.” 
Docket No. RM06-16-000 - 262 - 

approves the WECC and ERCOT load relief procedures as superior to the national 

Reliability Standard. As identified in the NOPR, the Commission directs the ERO to 

modify the WECC and ERCOT procedures to ensure consistency with the standard form 

of the Reliability Standards including Requirements, Measures and Levels of NonCompliance.308 

g. Regional Difference to IRO-006-3: PJM/MISO/SPP 

Enhanced Congestion Management 

(Curtailment/Reload/Reallocation)

i. Background

965. As explained in the NOPR, IRO-006-003 provides for a regional difference for 

MISO, PJM and SPP.309 According to NERC, the 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. 

966. The regional difference to IRO-006-3 applies the congestion management process 

included in Joint Operating Agreements filed by MISO, PJM and SPP and specified in 

seams agreements reached among MISO, PJM, and their neighboring non-market areas 

during the RTOs’ market formation and expansions. Under the congestion management 

process in the waiver, each RTO calculates an amount of energy (market flow) flowing 

across coordinated flowgates. These market flows are separated into their appropriate 

priorities based on the RTO’s schedules and reservations and are available for curtailment 

under the appropriate TLR Levels in the NERC interchange distribution calculator. 

Under the TLR method for curtailing interchange transactions and in the per generator 

method for generation-to-load impacts, NERC uses a five percent curtailment threshold, 

but in the waiver, the RTO’s market flows with an impact of greater than zero percent on 

a coordinated flowgate are represented and made available for curtailment under the 

appropriate TLR priorities. 

967. In their comments on the Staff Preliminary Assessment, MISO-PJM contended 

that there is unduly discriminatory treatment of the market flows of MISO and PJM 

versus the generation-to-load impacts of non-market entities because the waiver subjects 

 308 See NOPR at P 564-65. 

309 NOPR at P 568. 
Docket No. RM06-16-000 - 263 - 

the RTOs to curtailment (and the corresponding redispatch costs) in circumstances where 

the non-market entities would not be subject to curtailment. 

968. In the NOPR, the Commission did not propose to approve or remand this regional 

difference. 

ii. Comments

(a) Application of the Regional Difference

969. MISO-PJM contends that there is unduly discriminatory treatment against market 

flows of MISO and PJM during the application of the TLR Standard. The RTOs argue 

that NERC should modify IRO-006-3 and the MISO and PJM regional difference to 

require modifying the market flow threshold used by the interchange distribution 

calculator to assign relief obligations to MISO, PJM, and SPP from zero to a standard 

percentage that is technically feasible to implement on a non-discriminatory basis, netting 

of market flow impacts, tag impacts, and generation-to-load impacts, and reporting to the 

interchange distribution calculator all net generation-to-load impacts for both market and 

non-market transmission providers. Constellation supports MISO-PJM’s argument that 

there is unduly discriminatory treatment of the MISO and PJM market flows compared to 

the generation-to-load impacts of non-market entities in the application of the TLR 

standard. 

970. MISO-PJM indicates that they have raised the equity issue with the NERC 

Operating Reliability Subcommittee (Operating Subcommittee), that their markets 

currently are being asked to curtail market flow impacts down to zero percent while 

tagged transactions and generation-to-load impacts during TLR 5 are being asked to 

curtail impacts that are five percent or greater. MISO-PJM states that the NERC 

Operating Subcommittee has indicated that they will address reliability issues only and 

that they are not the appropriate group to address equity issues. 

(b) Seams Agreements

971. Several entities argue that the Commission should not overturn the existing IRO006-3 regional difference. MidAmerican states that MISO and PJM should continue to 

pursue a negotiated solution to the issues outlined in MISO-PJM’s filings. MidContinent states that the Commission should reject the MISO-PJM proposal to require 

NERC to allow them to report only the transactions with five percent or greater impacts 

on flowgates rather than report all transactions for curtailments, since MISO and PJM 

offered to report all transactions to avoid negative impacts on the reliability of the 

transmission system. Mid-Continent argues that not doing so would impact the reliability 

of the transmission system. 
Docket No. RM06-16-000 - 264 - 

972. Mid-Continent asks the Commission to not implement MISO and PJM’s proposal 

to modify NERC’s proceduresand to not override seams agreements. MidAmerican 

claims that MISO-PJM comments amount to an abrogation of existing seams agreements. 

MidAmerican states that the seams agreements were negotiated in a give-and-take 

process between the parties resulting in the existing waiver which was proposed by PJM 

and MISO in response to Commission orders. MidAmerican states that if any changes 

are sought to these waivers, they should be addressed in negotiation with the appropriate 

parties. MidAmerican suggests that any changes should be requested by way of the 

NERC process for developing Reliability Standards and that any negotiated agreements 

should be presented to the Commission for approval. Mid-Continent claims that MISOPJM have not provided valid reasons to replace the current Reliability Standards or to 

take actions that would modify existing seams agreements signed by MISO and PJM. 

Mid-Continent asks the Commission not to short-circuit the NERC Reliability Standards 

process which will give full consideration to the reliability implications of MISO’s and 

PJM’s proposal. 

973. APPA agrees with the Commission’s proposed approach in allowing MISO, PJM, 

NERC and other “relevant entities” to continue their negotiations regarding this regional 

difference. APPA cautions that any agreement reached by NERC and approved by the 

Commission regarding a regional difference for this Reliability Standard should be 

governed by reliability considerations and should not permit market design 

considerations to override NERC’s Reliability Standards. MidAmerican suggests a 

process where the RTOs invite parties to reconsider the seams agreements, the parties 

negotiate changes, the Commission approves new agreements and waivers are then 

sought from NERC to the extent necessary. MidAmerican argues that since the RTOs do 

not allege any reliability problem there is no need to reject or upend the existing NERC 

waiver. 

(c) Modifying the Congestion Management 

Process and Alternatives for Temporary 

Application of the Waiver

974. Mid-Continent states that it agrees with the Commission’s proposal to not adopt 

MISO and PJM’s request to instruct NERC to modify the current waiver to the TLR in 

the RTOs and believes that instead the Commission should direct NERC to address these 

issues through the Reliability Standards development process with input from 

neighboring systems. Mid-Continent states that changes to the waiver must not 

discriminate against non-market regions; must not negatively impact the reliability of 

neighboring systems and must be consistent with seams agreements signed by the RTOs. 

975. NRECA claims that issues associated with market flows and generation-to-load 

impacts have not been resolved and is concerned that MISO-PJM’s suggestion that 
Docket No. RM06-16-000 - 265 - 

“consensus” has been reached on the issues is premature. NRECA is also concerned that 

implementation of the MISO and PJM proposal could increase reliance on TLRs. 

NRECA urges the Commission to not short circuit or circumvent the Reliability 

Standards development process or the RTO stakeholders process and states that the 

Commission should permit the stakeholders to reach full consensus. 

976. MISO-PJM indicates that they have been working with both the NERC Operating 

Subcommittee and the Congestion Management Process Working Group (Congestion 

Working Group) to achieve a consensus on these changes, and that based on this, the 

Commission stated in the NOPR that it prefers that MISO, PJM and others continue 

negotiations to resolve these issues rather than imposing a solution on market 

participants. MISO-PJM state that they have held extensive discussions with a group 

composed of NERC Operating Subcommittee and Congestion Working Group 

participants. MISO-PJM indicates that detailed analyses has been performed to evaluate 

the effect of changing the market flow threshold from zero percent to five percent in one 

percent increments and that the NERC Operating Subcommittee has recommended that 

the market flow threshold used by the interchange distribution calculator to assign relief 

obligations to the MISO, PJM, and SPP be changed from zero percent to three percent for 

a 12 month interim period. MISO-PJM assert that at the end of the 12 months, a decision 

will be made whether to recommend a permanent change to the market flow threshold 

from zero percent to three percent or a change to some other value. MISO-PJM state that 

according to the NERC Operating Subcommittee, this recommendation is to only address 

the reliability issue raised by MISO, PJM and SPP so that they are able to meet their 

relief assignment during TLR. 

977. MISO-PJM also state sthat to receive congestion management process Council 

endorsement and support for the change being developed by the NERC Operating 

Subcommittee group, it requires unanimous approval by the congestion management 

process Council and that, though the 12 month field test to change the market flow 

threshold from zero percent to three percent has the support of MISO, PJM, SPP and 

TVA, it does not have the unanimous approval of all signatories to the seams agreements. 

MISO-PJM states that MAPPCOR (MAPP) has not agreed to the field test recommended 

by the NERC Operating Subcommittee and that MAPP has asserted that MISO should 

continue to honor their contractual obligation and report market flow impacts down to 

zero percent for relief assignments as specified in the MISO-MAPP Seams Operating 

Agreement. MISO is concerned that once the field test is complete and the NERC 

Operating Subcommittee recommends the use of a three percent threshold or some other 

threshold to address the reliability issue, the MISO may still have a contractual obligation 

with MAPP to use market flows down to zero percent for relief assignments. MISO-PJM 

states that this contractual obligation can only be altered if MISO and MAPP can agree 

on a change to the Seams Operating Agreement but expects resistance to change the 
Docket No. RM06-16-000 - 266 - 

Seams Operating Agreement. MISO and PJM do not believe they can address the equity 

issue by continuing discussions with the NERC Operating Subcommittee. 

978. MISO-PJM also state that by continuing to use market flows down to zero percent 

for relief assignments on reciprocally coordinated flowgates between MISO and MAPP, 

there will be situations where MISO is unable to meet its relief obligation. MISO-PJM 

states that they have sought unsuccessfully to execute redispatch agreements with those 

parties who have direct counter-flow on the identified flowgates where the MISO is 

unable to meet its relief obligation. MISO-PJM believe that the Commission should 

address this continuing discriminatory treatment of the market impacts on flowgates. 

MISO-PJM state that of the three areas where MISO-PJM raised comments on 

discriminatory treatment of the markets, only one area (changing the market flow 

threshold for a 12 month field test) has resulted in steps being taken to address the 

discriminatory treatment and that even this one area can only be considered a partial 

success because there is only a solution to address the reliability issue, but not the equity 

issue. 

979. MISO-PJM explain in their supplemental comments that NERC has demonstrated 

a willingness to consider the reliability issue by authorizing a 12 month field test 

allowing PJM, MISO and SPP market flows to use a three percent threshold, to observe 

the impact on reliability, but will not address what it refers to as “equity issues.” MISOPJM explains the field test has been approved by all the reciprocal entities that have 

signed seams agreements except MAPP. MISO-PJM state that, at the end of the 12 

months, a decision will be made whether to use a three percent threshold or some other 

threshold to address the reliability concerns. MISO-PJM explain that the same entities 

that make up the Mid-Continent objected to the field test because they asserted MISO has 

a contractual obligation under the MAPP Seams Operating Agreement to continue 

reporting its market flows down to zero percent. MISO-PJM contend that because the 

MISO has agreed to honor its contractual obligation during the field test and will 

continue to use a zero percent threshold for all flowgates that are reciprocal between 

MISO and MAPP, this means that the flowgates under the control of the Mid-Continent 

parties will not participate in the field test and NERC will have no data to show the 

impact of changing the market flow threshold to three percent on these flowgates. 

980. MISO-PJM state that as long as the regional difference does not become a 

mandatory standard during the field test, they are satisfied that appropriate steps are being 

taken to address reliability. 
Docket No. RM06-16-000 - 267 - 

(d) Reporting of Generator to Load Impacts by 

Non Market Areas

981. MISO-PJM supports modifications to the TLR process that would require all 

participants (both market and non-market) to report their market flow impacts and 

generator-to-load impacts to the interchange distribution calculator and honor their 

allocations when they report their firm versus their non-firm usage. MISO-PJM believes 

that taking this step would also address the threshold equity issue and the netting issue 

because all entities would be subject to the same treatment. MISO-PJM requests that the 

Commission to either direct NERC to initiate a process to modify the interchange 

distribution calculator such that market flows and generator-to-load impacts from nonmarket areas are both reported to the interchange distribution calculator and are subject to 

curtailment based on their priorities from the allocations or that the Commission take 

action to do so. 

982. MISO-PJM states that the reporting of generator-to-load impacts by the nonmarket entities is the one area that is not currently under discussion with a stakeholder 

group. MISO-PJM explains that both the market and non-market entities receive an 

allocation on flowgates and that both the market entities and the non-market entities use 

the allocations when selling firm transmission service. MISO-PJM states that only the 

market entities report their market flows to the interchange distribution calculator and use 

their allocations to determine what portion of market flows will be considered firm and 

believe that the non-market entities could also report their firm and non-firm generatorto-load usage to the interchange distribution calculator and receive relief assignments 

based on this usage. MISO-PJM indicates that this would remove the assumption that all 

generator-to-load impacts from the non-market entities represent firm usage. MISO-PJM 

states that reporting relief obligations by one group of participants and not reporting by 

the other results in conflicting actions during the TLR process because market entities 

suffer the financial consequences of redispatch at the same time reliability is not being 

accomplished due to off-setting actions by non-market entities. 

983. MISO-PJM states that, to address the discriminatory treatment of the markets, the 

Commission could order the TLR Reliability Standard to be modified to have the market 

entities discontinue reporting their market flows to the interchange distribution calculator. 

MISO-PJM believes that instead of this order, the preference is to have the market 

entities continue reporting their market flow impacts and the non-market entities report 

their generator-to-load impacts to the interchange distribution calculator. The allocations 

would be used to set the priority of these impacts. 

984. Mid-Continent states that the regional difference requiring PJM and MISO to 

report all flows instead of net flows was part of the commitments MISO and PJM made 

to meet NERC’s tagging requirements. Mid-Continent contends that it is appropriate to 
Docket No. RM06-16-000 - 268 - 

treat MISO-PJM market flows differently because they are greater than the system flows 

that resulted from control area-based system operation. Mid-Continent further claims 

that MISO cannot achieve the redispatch the interchange distribution calculator requires 

because of MISO’s own actions since MISO does not report actual flows to the 

interchange distribution calculator and MISO and PJM’s congestion management tools 

do not utilize all redispatch options. 

(e) Accounting for Counter Flows during TLR

985. MISO-PJM state that there have been discussions at the NERC Operating 

Subcommittee about taking into account counter-flows during TLR when assigning 

relief. MISO-PJM contend sthat by considering counter-flows, those entities that are 

responsible for the loading problem on a net basis will be responsible for fixing the 

loading problem during TLR. MISO-PJM states that the MISO, PJM and SPP markets 

operate on a net flow basis and, therefore, have additional reasons for wanting to consider 

counter-flows. MISO-PJM expects that by summer 2007, the Task Force will have a 

recommendation on netting in the interchange distribution calculator for the NERC 

Operating Subcommittee to consider. MISO-PJM state that it is premature to speculate 

on the outcome of the discussions with the NERC Operating Subcommittee at this time. 

MISO-PJM clarifies that they are not asking the Commission to take any action on this 

issue but to let the NERC Operating Subcommittee address the technical merits of netting 

impacts in the interchange distribution calculator. 

986. Mid-Continent states that eliminating the requirements to report flows in both 

directions may adversely impact reliability because the interchange distribution calculator 

will not have enough information to assign responsibilities to the contributors of a 

constraint. 

iii. Commission Determination

987. The Commission will not approve or remand this regional difference. The 

treatment of the market flows of MISO-PJM versus the generation-to-load impacts of 

non-market entities in the application of the TLR standard has been addressed by the 

Commission in a number of cases.310 In approving the plans of various transmission 

owning utilities to join PJM, the Commission attached several conditions including a 

requirement that certain non-market utilities be held harmless from effects of loop flow 

 310 See Alliance Companies, 100 FERC ¶ 61,137 (2001) and Midwest Independent 

Transmission System Operator, Inc. and PJM Interconnection, L.L.C., 106 FERC ¶ 

61,251 (2004). 
Docket No. RM06-16-000 - 269 - 

and congestion resulting from the utilities' RTO choices.311 Further, during MISO’s 

market start up,312 the Commission determined that the markets could not start without 

the MISO having at least a specific, transparent plan for how it will handle the interface 

of multiple transmission tariffs and market-to-non-market seams313 and required the 

MISO to file any resolution of seams, or a status report of progress on seams resolution 

including detailed plans as to how MISO will address seams absent agreements, within 

60 days of the date of the order. The regional difference to IRO-006-3 applies the 

congestion management process that was included in the Joint Operating Agreement filed 

by MISO, PJM and SPP and that was specified in the seams agreements reached between 

MISO, PJM, and their neighboring non-market areas in order to meet the Commission’s 

requirements described above.314 

988. The Commission recognizes MISO-PJM’s concerns that: (1) the congestion 

management process process could be placing an undue burden on the RTO regions to 

provide redispatch especially on remote flowgates where an RTO’s dispatch has a small 

impact and (2) under the congestion management process, the calculation of market flows 

for relief assignments on Reciprocal Coordinated Flowgates between the MISO and 

MAPP could create situations where MISO is unable to meet its relief obligation without 

curtailing load. We also understand that these concerns are exacerbated by the possibility 

of civil penalties for non-compliance with the requirement to use market flows down to 

zero percent for relief assignments on reciprocal coordinated flowgates between MISO 

and MAPPCOR. Especially during transitions when markets with multiple control areas 

are started up, markets are expanded to include other control areas, or non-market control 

areas are consolidated, this can have an effect on the loop flows experienced by 

 311 Commonwealth Edison Company and American Electric Power Service 

Corporation, 106 FERC ¶ 61,250 (2004). This order required ComEd to demonstrate that 

its proposal held utilities in Wisconsin and Michigan harmless from all adverse impacts 

associated with loop flow or congestion that would result from its choice to join PJM. 

312 See Midwest Independent Transmission System Operator, Inc., 108 FERC ¶ 

61,163 (2004). 

313 To resolve this issue, the Commission encouraged market participants to use 

the PJM-Midwest ISO joint operating agreement as a model or starting point for seams 

agreements, particularly with respect to the seams with the various utilities in the MAPP 

region. 

314 See Midwest Independent Transmission System Operator, Inc., 110 FERC ¶ 

61,290 (2005). 
Docket No. RM06-16-000 - 270 - 

neighboring regions and the redispatch required by the neighboring regions due to fewer 

tagged transactions reported to the interchange distribution calculator. The Commission 

recognizes that there are concerns by neighboring entities to be held harmless from 

increased redispatch responsibility caused by these transitions. 

989. The Commission concludes that the issues described by MISO-PJM (i.e., defining 

the obligation of a certain region to provide redispatch when a flowgate becomes 

congested) are best handled through seams agreements rather than being subject to the 

NERC processes. We recognize that the two areas of seams agreements and Reliability 

Standards could overlap if the agreements reached do not allow for reliable outcomes 

where parties can achieve the relief assigned. As such, the Commission will neither 

approve nor remand the waiver of the regional difference to IRO-006-3 while the 12 

month field test allowing PJM, MISO and SPP market flows to use a three percent 

threshold is being conducted. After the 12 month field test is complete, the Commission 

will reexamine approving the waiver as a mandatory and enforceable Reliability 

Standard. 

990. The Commission instructs the RTOs to continue working with the non-market 

regions to develop revised seams agreements that allow for equitable and feasible 

treatment of market flows in the NERC TLR/redispatch process. The solution should not 

harm system reliability and should not subject either non-RTO transmission owners or 

the RTO markets to unreasonable redispatch responsibilities. We note that if consensus 

cannot be reached, the RTOs may file a section 205 or section 206 proposal to revise the 

terms and conditions of the congestion management process if the terms agreed on in the 

seams agreements and Joint Operating Agreement have become unjust or unreasonable or 

may file to terminate the agreements as allowed in the seams agreements. 

991. The Commission will not adopt MISO-PJM’s proposal to require non-market 

entities to report their generator-to-load impacts to the interchange distribution calculator 

with the allocations used to set the priority of these impacts in this Reliability Standards 

process. If NERC determines that this information and corresponding curtailment 

options are needed for reliability, NERC should file to modify IRO-006-3 to include 

these additions. However, the economic implications of the reporting of generator-to 

load impacts by non-market entities are not in the scope of the reliability process and are 

better addressed on a case-by-case basis or, as appropriate, in the proceeding on RTO 

Border Utility Issues.315

 315 See RTO Border Utility Issues, Notice of Technical Conference on Seams 

Issues for RTOs and ISOs in the Eastern Interconnections (Docket No. AD06-9-000) 

(issued Jan. 25, 2007). 
Docket No. RM06-16-000 - 271 - 

992. In addressing MISO-PJM’s claim that the ERO should modify IRO-006-3 and the 

MISO-PJM regional difference to require netting generation-to-load impacts to recognize 

counterflow, we will let the ERO Operating Subcommittee address the technical merits of 

netting flow impacts in the interchange distribution calculator. 

h. Procedures, Processes, or Plans to Support Coordination 

between Reliability Coordinators (IRO-014-1)

993. The stated purpose of IRO-014-1 is to ensure that each reliability coordinator’s 

operations are coordinated so 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 exchange 

of operating information and coordination of operating plans. 

994. In the NOPR, the Commission proposed to approve IRO-014-1 as mandatory and 

enforceable. 

i. Comments

995. APPA agrees with the Commission’s proposed approval of IRO-014-1 as 

mandatory and enforceable. 

ii. Commission Determination

996. For the reasons stated in the NOPR, the Commission approves IRO-014-1 as 

mandatory and enforceable. 

i. Notifications and Information Exchange between 

Reliability Coordinators (IRO-015-1)

997. IRO-015-1 establishes Requirements for a reliability coordinator to share and 

exchange reliability-related information among its neighbors and participate in agreedupon conference calls and other communication forums with adjacent reliability 

coordinators. 

998. In the NOPR, the Commission proposed to approve IRO-015-1 as mandatory and 

enforceable. 

i. Comments

999. APPA agrees with the Commission’s proposed approval of IRO-015-1 as 

mandatory and enforceable. 
Docket No. RM06-16-000 - 272 - 

ii. Commission Determination

1000. For the reasons stated in the NOPR, the Commission approves IRO-015-1 as 

mandatory and enforceable.

j. Coordination of Real-Time Activities between Reliability 

Coordinators (IRO-016-1)

1001. 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. 

1002. In the NOPR, the Commission proposed to approve IRO-016-1 as mandatory and 

enforceable. 

i. Comments

1003. APPA agrees with the Commission’s proposed approval of IRO-015-1 as 

mandatory and enforceable. However, it indicates that it is unclear in Level of NonCompliance 2.1, how a reliability coordinator can demonstrate that it coordinated with 

other reliability coordinators without having retained evidence such as detailed logs or 

telephone recordings of having done so.316

ii. Commission Determination

1004. For the reasons stated in the NOPR, the Commission approves IRO-016-1 as 

mandatory and enforceable. 

1005. We construe Level of Non-Compliance 2.1 as requiring evidence of coordination, 

but allowing flexibility on the type of evidence. 

8. MOD: Modeling, Data, and Analysis

1006. The Modeling, Data and Analysis group of Reliability Standards is intended to 

standardize methodologies and system data needed for traditional transmission system 

 316 IRO-016-1 Level of Non-Compliance 2.1 states: “For potential, actual or 

expected events which required Reliability Coordinator-to-Reliability Coordinator 

coordination, the Reliability Coordinator did coordinate, but did not have evidence that it 

coordinated with other Reliability Coordinators.” 
Docket No. RM06-16-000 - 273 - 

operation and expansion planning, reliability assessment and the calculation of available 

transfer capability (ATC) in an open access environment. The 23 MOD Reliability 

Standards may be grouped into four distinct categories. The first category covers 

methodology and associated documentation, review and validation of Total Transfer 

Capability (TTC), ATC, Capacity Benefit Margin (CBM) and Transmission Reliability 

Margin (TRM) calculations.317 The second category covers steady-state and dynamics 

data and models.318 The third category covers actual and forecast demand data.319 The 

fourth category covers verification of generator real and reactive power capability.320 

1007. In the NOPR, the Commission proposed that one out of 23 MOD Reliability 

Standards be approved unconditionally, nine be approved with direction for modification 

and 13 remain pending with direction for modification.321 The Commission, describing 

these 13 pending standards as fill-in-the-blank Reliability Standards, generally proposed 

to seek additional information before acting on them. Responding to CenterPoint’s 

proposal to exempt ERCOT from the MOD Reliability Standards that address available 

transfer capability, the Commission explained that it would consider any regional 

difference at the time NERC submits one for Commission review. Therefore, the 

Commission stated that if ERCOT wished to request a regional difference, it should do so 

through the ERO process. 

i. Comments 

1008. ISO/RTO Council and ISO-NE agree with the Commission’s proposal to neither 

approve nor remand the 13 MOD Reliability Standards until NERC supplies additional 

information. ISO/RTO Council and ISO-NE also recommend that the Commission go 

further and defer its approval of the MOD Reliability Standards that incorporate 

references to the 13 fill-in-the-blank Reliability Standards until those 13 are approved 

 317 MOD-001-0 through MOD-009-0. 

318 MOD-010-0 through MOD-015-0. 

319 MOD-016-0 through MOD-021-0. 

320 MOD-024-1 through MOD-025-1. 

321 Approved: MOD-018-0; approved with modification: MOD-06-0, MOD-007-0, 

MOD-010-0, MOD-012-0, MOD-016-1, MOD-017-0, MOD-019-0 through MOD-021-0; 

and pending: MOD-001-0 through MOD-005-0, MOD-08-0, MOD-09-0, MOD-011-0, 

MOD-013-1 through MOD-015-0, MOD-024-1 and MOD-025-1. 
Docket No. RM06-16-000 - 274 - 

unconditionally. ISO/RTO Council and ISO-NE believe that the following Reliability 

Standards are dependent upon the 13 fill-in-the-blank standards: MOD-010-0, MOD-012-

0, MOD-016-1, MOD-017-0, MOD-018-0, MOD-019-0, and MOD-021-0 and as such, 

the Commission should not approve and make them enforceable at this time. ISO-NE 

warns that these listed standards share the same infirmities as the 13 the Commission 

found it could not yet approve. ISO-NE cautions that until the missing information is 

provided in the 13 cross-referenced standards, it will be impossible for the affected 

entities to determine what criteria they are expected to satisfy. 

1009. EPSA, in contrast to ISO/RTO Council and ISO-NE, expresses its concern with 

the Commission’s proposal not to act on the 13 fill-in-the-blank standards. EPSA 

considers the fill-in-the-blank standards vitally important to reliability and competitive 

markets and worries that progress may be lost while the regions endeavor to file the 

additional required information. 

ii. Commission Determination 

1010. The Commission will adopt the NOPR proposal and retain the same disposition of 

the MOD Reliability Standards that it proposed there. We confirm in this Final Rule that 

one out of 23 MOD standards is approved unconditionally, nine are approved with 

direction for modification and 13 remain pending with direction for modification. We 

will discuss our rationale for this decision in the Commission Determination section for 

each particular Reliability Standard. 

1011. We reject ISO/RTO Council and ISO-NE’s request that we defer our approval of 

Reliability Standards from the MOD group that incorporate references to the 13 fill-inthe-blank standards. While we understand ISO/RTO Council and ISO-NE’s concern 

about cross-referencing pending Reliability Standards, the data that is needed will be 

provided as described in the Common Issues section.322 In the interim, compliance with 

the pending Reliability Standards should continue on a voluntary basis, and the 

Commission considers compliance with them a matter of good utility practice. The 

Commission believes, moreover, that the blanks will be filled in in a timely manner, since 

in this rule we require the ERO to develop a Work Plan and submit a compliance filing 

describing the process for collection of the information set forth in the deferred standards. 

1012. In response to EPSA’s concern that opportunities for discrimination and concerns 

about reliability remain while we await additional information, we emphasize that the 

 322 See Common Issues Pertaining to Reliability Standards: Fill-in-the-Blank 

Standards, supra section II.E.5. 
Docket No. RM06-16-000 - 275 - 

Commission has provided specific direction regarding appropriate modifications to the 

MOD standards here and in Order No. 890, and has required the submission of a Work 

Plan for completion of that work within 90 days.323 Moreover, the OATT and OASIS 

transparency reforms adopted in Order No. 890 will ensure that opportunities for 

discrimination will be minimized while NERC completes work on the MOD Reliability 

Standards. 

b. MOD Standards Related to ATC, TTC, CBM and TRM

i. OATT Reform and the MOD Standards 

1013. As pointed out in the NOPR, the Commission has been considering ATC, TTC, 

CBM and TRM calculation issues in Docket Nos. RM05-17-000 and RM05-25-000, and 

addressed them in Order No. 890. In order to maintain a consistent approach with regard 

to ATC issues, we confirm here the determinations made in Order No. 890. Each such 

determination is addressed below. 

1014. In Order No. 890, the Commission addressed the potential for undue 

discrimination by requiring industry-wide consistency and transparency of all 

components of ATC calculation methodology and certain definitions, data and modeling 

assumptions. The Commission also indicated there that the lack of consistent, industrywide ATC calculation standards poses a threat to the reliable operation of the Bulk-Power 

System, particularly with respect to the inability of one transmission provider to know 

with certainty its neighbors’ system conditions affecting its own ATC values. As a result 

of this reliability component, the Commission asserted that the proposed ATC reforms 

are also supported by FPA section 215, through which the Commission has the authority 

to direct the ERO to submit a Reliability Standard that the Commission considers 

appropriate to implement FPA section 215.324 

1015. In Order No. 890, the Commission directed public utilities, working through 

NERC and NAESB, to develop Reliability Standards and business practices to improve 

the consistency and transparency of ATC calculations. The Commission required public 

utilities, working through NERC, to modify the ATC-related Reliability Standards within 

270 days of publication of Order No. 890 in the Federal Register. The Commission also 

directed public utilities to work through NAESB to develop business practices that 

complement NERC’s new Reliability Standards within 360 days of publication of Order 

 323 OATT Reform Final Rule, Order No. 890, issued February 15, 2007. 

324 FPA section 215(d)(5). 
Docket No. RM06-16-000 - 276 - 

No. 890 in the Federal Register. Finally, the Commission directed NERC and NAESB to 

file a joint status report on standards and business practices development, and a Work 

Plan for completion of this task, within 90 days of publication of Order No. 890 in the 

Federal Register. 

1016. The electric utility industry has also acknowledged this problem and has taken 

steps to address the lack of consistency and transparency in the way ATC is calculated. 

NERC formed a Long-Term Available Flowgate Capacity Task Force to review NERC’s 

standards on ATC, which issued a final report in 2005.325 Based on the recommendations 

in the NERC Report, NERC has begun two Standards Authorization Request proceedings 

to revise the standards on ATC.326 NAESB has also begun a proceeding to develop 

business practice standards to enhance the processing of transmission service requests 

that affect ATC calculation. Following the issuance of the OATT Reform NOPR on 

May 19, 2006, and the Reliability Standards NOPR on October 19, 2006, NERC 

accelerated development of these standards in accordance with the guidelines provided in 

these NOPRs. NERC and NAESB representatives participated in the Commission’s 

Technical Conference held on October 12, 2006, and informed the Commission on the 

status of Reliability Standards development.327 NERC posted the Draft Standard MOD-

 325 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. 

326 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. 

327 Technical Conference regarding Preventing Undue Discrimination and 

Preference in Transmission Service under RM05-25 et al. (October 12, 2006). 
Docket No. RM06-16-000 - 277 - 

001-1, proposing ATC/TTC/AFC (Available Flowgate Capability) revisions, on its 

website on February 15, 2007.328 

(a) Comments 

1017. EPSA commends the Commission for recognizing the direct connection between 

the MOD group of Reliability Standards and the initiative to reform Order No. 888 to 

address existing opportunities to discriminate against competitive power suppliers in 

access to the transmission system. TAPS and EPSA note that in both the OATT Reform 

NOPR and the Reliability Standards NOPR, the Commission has articulated serious 

concerns about the lack of clarity, transparency and uniformity in the critical calculations 

pertaining to one of the most fundamental aspects of the wholesale bulk power 

transmission system, and urge the Commission to make these calculations transparent, 

consistent, and better yet, regional. TAPS agrees with Staff’s concerns raised in the 

NOPR about ATC, TTC, CBM and TRM standards. Constellation particularly supports 

the proposed changes to MOD-001-0, MOD-004-0, MOD-006-0 and MOD-007-0 

because these Reliability Standards, as modified, will provide more information to users 

regarding ATC, TTC, existing transmission commitments (ETC), AFC, CBM and TRM, 

and that information will begin the process of providing consistent standards for their 

calculation. 

1018. Constellation agrees with EPSA and cautions that it will take time for NERC to 

develop, and for the Commission to definitively approve, ATC-related standards. 

Constellation therefore proposes that the Commission should, upon issuance of a Final 

Rule, require transmission providers to post the information that the Commission directs 

regarding these values, even if work toward more consistency is not yet complete. 

Constellation believes that this will aid in ensuring that users request and receive more 

reliable transmission service on a nondiscriminatory basis. 

1019. Contrary to the majority of commenters that support Commission action regarding 

ATC issues, MISO states that a Reliability Standard is not the place to address perceived 

comparability issues. MISO states that NERC is responsible for Reliability Standards, 

but not for tariffs and business practices that deal with market and equity issues. 

 328 That posting preceded by one day the issuance of Order No. 890. Therefore, 

the posted draft Standard MOD-001-1 does not reflect the requirements of Order No. 

890, but rather is guided by the NOPR issued in the OATT Reform and Reliability 

Standards proceedings. 
Docket No. RM06-16-000 - 278 - 

(b) Commission Determination 

1020. We agree with the many commenters that recognize the direct connection between 

the MOD group of Reliability Standards and available transfer capability methodologies 

addressed in Order No. 890, in which we developed policies to lessen, if not fully 

eliminate, opportunities to discriminate against competitive power suppliers in access to 

the transmission system. 

1021. We recognize the concerns raised by EPSA and Constellation that opportunities 

for discrimination and related reliability concerns may remain during the interim 

Reliability Standards modification process, in part because of the discretion that 

transmission service providers will retain in calculating ATC values. We point out, 

however, that all transmission providers are required to file a modified Attachment C to 

their OATTs detailing their ATC calculation methodologies in advance of the 

development of the new Reliability Standards. All transmission providers are required to 

comply with their OATTs, and are subject to the filing of a complaint or Commissioninitiated enforcement action if discrimination occurs. Regarding Constellation’s 

recommendation that the Commission act in advance, and require transmission service 

providers to post the information that the Commission directs regarding ATC values, 

even if work toward more consistency is not yet complete, we clarify that we will require 

transmission service providers to comply with existing ATC-related posting obligations 

on OASIS as supplemented by Order No. 890. These requirements are not subject to 

standardization by the ERO, and will be effective in accordance with the timeline stated 

in Order No. 890. 

1022. We disagree with MISO’s contention that the Reliability Standards are an 

inappropriate venue for addressing ATC comparability issues. ATC raises both 

comparability and reliability issues, and it would be irresponsible to take action under 

FPA section 206 to require consistency in ATC calculations without considering the 

reliability impact of those decisions. Therefore, the Commission in Order No. 890 

provided direction to public utilities, working through NERC and NAESB, regarding 

development of the ATC-related Reliability Standards and business practices, and we 

repeat that direction here. 

c. Documentation of Total Transfer Capability and 

Available Transfer Capability Calculation Methodologies 

(MOD-001-0)

1023. 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 each regional reliability organization to develop a regional TTC and 

ATC methodology in conjunction with its members and to post the most recent version of 
Docket No. RM06-16-000 - 279 - 

its TTC and ATC methodologies on a website accessible by NERC, the regional 

reliability organization, and transmission users. 

1024. In the NOPR, the Commission identified MOD-001-0 as 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. The NOPR stated that the Commission would not propose to approve 

or remand MOD-001-0 until the ERO submits additional information. 

1025. Although the Commission did not propose any action with regard to MOD-001-0, 

it addressed a number of concerns regarding the Reliability Standard, consistent with 

those proposed in the OATT Reform NOPR. The Commission proposed that this 

standard should: (1) at a minimum, provide a framework for ATC, TTC and ETC 

calculation; (2) require disclosure of algorithms and processes used in ATC calculation; 

(3) identify a detailed list of information to be exchanged among transmission providers 

for the purposes of ATC modeling; (4) include requirements that the assumptions used in 

ATC and AFC calculations be consistent with those used for planning expansion or 

operation of the Bulk-Power System to the maximum extent practicable;329 (5) include a 

requirement that applicable entities make available assumptions and contingencies 

underlying ATC and TTC calculations; (6) address only ATC while the TTC should be 

addressed under FAC-012-1; and (7) identify to whom MOD-001-0 standards apply, i.e., 

users, owners and operators of the Bulk-Power System.330 We will discuss the comments 

and Commission conclusions for each of these modifications separately below. 

i. Comments 

1026. APPA agrees with the Commission that MOD-001-0 in its current form is a fill-inthe-blank standard, is not sufficient in its current form and should not be accepted for 

approval as a mandatory Reliability Standard until the accompanying regional procedures 

are submitted and approved. 

 329 NOPR at P 609. 

330 Id. at P 610. We note that our observation regarding applicable entities here 

also applies to MOD-002-0, MOD-003-0, MOD-004-0, MOD-005-0, MOD-008-0, 

MOD-009-0, MOD-011-0, MOD-013-0, MOD-014-0, MOD-015-0, MOD-016-0, MOD024-0 and MOD-025-0. 
Docket No. RM06-16-000 - 280 - 

ii. Commission Determination

1027. The Commission adopts the NOPR proposal not to approve or remand MOD-001-

0 until the ERO submits additional information. Consistent with Order No. 890, and 

comments received in response to the NOPR, the Commission directs the ERO to 

consider modifications of MOD-001-0 through the Reliability Standards development 

process as discussed below. 

iii. Provide a framework for ATC, TTC and ETC 

calculation

(a) Comments

1028. APPA supports the Commission’s proposal that NERC modify MOD-001-0 to, at 

a minimum, provide a framework for ATC, TTC and ETC calculation. 

(b) Commission Determination

1029. We continue to believe that MOD-001-0 should, at a minimum, provide a 

framework for ATC, TTC and ETC calculations. This framework should consider 

industry-wide consistency of all ATC components and certain data inputs and exchange, 

modeling assumptions, calculation frequency, and coordination of data relevant for the 

calculation of ATC. Consistent with Order No. 890, we do not require a single 

computational process for calculating ATC for several reasons. First, it is not our intent 

to require transmission providers to incur the expense of developing and adopting a new 

one-size-fits-all software package to calculate ATC without proven benefits. More 

importantly, we find that the potential for discrimination and decline in reliability level 

does not lie primarily in the choice of an ATC calculation methodology, but rather in the 

consistent application of its components, and input and exchange data, along with 

modeling assumptions. Consistent and transparent ATC calculation will provide 

equivalent results between regions and will therefore prevent transmission service 

providers from overselling transfer capability that can stress conditions on their own and 

adjacent systems, and jeopardize reliability. In addition, we are especially concerned 

with the lack of data exchange between neighboring transmission service providers, 

which is a prerequisite for accurate calculation of ATC. 

1030. The Commission understands that the ERO currently is developing three ATC 

calculation methodologies (contract or rating path ATC, network ATC, and network 
Docket No. RM06-16-000 - 281 - 

AFC).331 If all of the ATC components, and certain data inputs and assumptions are 

consistent, the three ATC calculation methodologies will produce predictable and 

sufficiently accurate, consistent, equivalent and replicable results. It is therefore not 

necessary to require a single industry-wide ATC calculation methodology. 

1031. In addition, consistent with Order No. 890, we note that there is neither a 

definition of AFC/TFC (Total Flowgate Capability) in the ERO’s glossary nor an existing 

Reliability Standard that discusses AFC. Consistent with our approach to achieving 

consistency and transparency, we direct the ERO to develop AFC/TFC definitions and 

requirements used to identify a particular set of transmission facilities as flowgates. We 

extend the same requirements for industry-wide consistency of all AFC components and 

certain data inputs and exchange, modeling assumptions, calculation frequency, and 

coordination of data relevant for the calculation of AFC as we stated above for ATC. 

However, we remind transmission providers that our regulations require the posting of 

ATC values associated with a particular path, not AFC values associated with a flowgate. 

Accordingly, transmission providers using an AFC methodology must convert flowgate 

(AFC) values into path (ATC) values for OASIS posting. In order to display consistent 

posting of ATC and TTC values on OASIS, we direct the ERO to develop a Requirement 

in the Reliability Standard for conversion of AFC into ATC values for use by 

transmission providers that currently apply flowgate methodology. 

1032. We underscore Order No. 890’s objective of greater consistency in ETC 

calculations. The Commission directs the ERO to develop a consistent approach for 

determining the amount of transfer capability a transmission provider may set aside for 

its native load and other committed uses. We expect that the ERO will address ETC 

through the MOD-001-0 Reliability Standard rather than through a separate Reliability 

Standard. By using MOD-001-0, the ETC calculation principles can be adjusted to apply 

 331 October 12, 2006 Technical Conference regarding Preventing Undue 

Discrimination and Preference in Transmission Service under RM05-25 et al. These 

three methodologies are different computational processes to determine a transmission 

system’s ATC. The first, contract path, examines TTC for every A-to-B path on the 

system in concert with all others, reduces ATC by path for ETC, TRM and CBM, as 

appropriate, and produces ATC for each path. The second method, network ATC, uses a 

simulator to look not at each path, but at each transmission element (line, substation, etc.) 

and run first contingency simulations to establish ATC on a network basis, rather than a 

path basis. The third method, network AFC, uses a simulator to examine critical 

flowgates over a wider area, then requires a second step to convert AFC values to 

particular path ATC values. 
Docket No. RM06-16-000 - 282 - 

to each of the three ATC methodologies being developed by the ERO. In order to 

provide specific direction to public utilities and the ERO, we determine that ETC should 

be defined to include committed uses of the transmission system, including: (1) native 

load commitments (including network service); (2) grandfathered transmission rights; (3) 

firm and non-firm point-to-point reservations; (4) rollover rights associated with longterm firm service and (5) other uses identified through the ERO process. ETC should not 

be used to set aside transfer capability for any type of planning or contingency reserve; 

these are to be addressed through CBM and TRM.332 In addition, in the short-term ATC 

calculation, all reserved but unused transfer capability (non-scheduled) must be released 

as non-firm ATC. 

1033. We reiterate the finding in Order No. 890 that including all requests for 

transmission service in ETC is likely to overstate usage of the system and understate 

ATC. Accordingly, we find that reservations that have the same point of receipt (POR) 

(generator) but different point of delivery (POD) (load), for the same time frame, should 

not be modeled in the ETC calculation simultaneously if their combined reserved 

transmission capacity exceeds the generator’s nameplate capacity at a POR. This will 

prevent unrealistic use of transmission capacity associated with power output from a 

generator identified as a POR. One approach that could be used is examining historical 

patterns of actual reservation use during a particular season, month, or time of day. 

1034. In summary, we direct the ERO to modify MOD-001-0 to provide a framework for 

ATC, TTC and ETC calculation that, consistent with the discussion above: (1) requires 

industry-wide consistency of all ATC components and certain data inputs and exchange, 

modeling assumptions, calculation frequency, and coordination of data relevant for the 

calculation of ATC; (2) provides predictable and sufficiently accurate, consistent, 

equivalent, and replicable ATC calculations regardless of the methodology used by the 

region; (3) provides the definition of AFC and method for its conversion to ATC; (4) lays 

out clear instructions on how ETC should be defined and (5) identifies to whom MOD001-0 Reliability Standards apply, i.e., users, owners and operators of the Bulk-Power 

System.

 332 TRM also includes such things as loop flow and parallel path flow. 
Docket No. RM06-16-000 - 283 - 

iv. Require disclosure of algorithms and processes 

used in ATC calculation

(a) Comments

1035. APPA supports the Commission’s proposal that NERC modify MOD-001-0 to 

require documentation including mathematical algorithms, process flow diagrams, data 

inputs and identification of flowgates. 

(b) Commission Determination

1036. The Commission adopts the proposal from the NOPR to direct the ERO to modify 

Reliability Standard MOD-001-0 to require disclosure of the algorithms and processes 

used in ATC calculation. In addition, consistent with Order No. 890, the Commission 

believes that further clarification is necessary regarding the ATC calculation algorithm 

for firm and non-firm ATC.333 Currently, the ERO has no specifications for calculating 

non-firm ATC. We find that the same potential for discrimination exists for non-firm 

transmission service as for firm service, and greater uniformity in both firm and non-firm 

ATC calculations will substantially reduce the remaining potential for undue 

discrimination. Therefore, we direct the ERO to modify Reliability Standard MOD-001-

0 to require disclosure of the algorithms and processes used in ATC calculation, and also 

to implement the following principles for firm and non-firm ATC calculations: (1) for 

firm ATC calculations, the transmission provider shall account only for firm 

commitments and (2) for non-firm ATC calculations, the transmission provider shall 

account for both firm and non-firm commitments, postbacks of redirected service, 

unscheduled service and counterflows. 

 333 The NERC ATC definition does not differentiate firm and non-firm ATC from 

the following high level generic ATC definition: A measure of the transfer capability 

remaining in the physical transmission network for further commercial activity over and 

above already committed uses. It is defined as Total Transfer Capability less existing 

transmission commitments (including retail customer service), less a Capacity Benefit 

Margin, less a Transmission Reliability Margin. . 
Docket No. RM06-16-000 - 284 - 

v. Identify a detailed list of information to be 

exchanged among transmission providers for the 

purposes of ATC modeling

(a) Comments

1037. APPA supports the Commission’s proposal that NERC modify MOD-001-0 to 

require applicable entities to identify a detailed list of information to be shared. 

(b) Commission Determination

1038. The Commission adopts the NOPR proposal and reiterates the requirement in 

Order No. 890 that the ERO must revise the MOD Reliability Standards to require the 

exchange of data and coordination among transmission providers. We direct the ERO to 

modify MOD-001-0 to ensure that the following data, at a minimum, 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 recalculation frequency and times and (7) source/sink modeling 

identification.334 The Commission concludes that the exchange of such data is necessary 

to support the reforms requiring consistency in the determination of ATC adopted in this 

Final Rule. As explained above, transmission providers are required to coordinate the 

calculation of TTC/TFC and ATC/AFC with others, and this requires a standard means of 

exchanging data. 

vi. Include requirements that the assumptions used in 

ATC and AFC calculations should be consistent, to 

the maximum extent practicable, with those used 

for planning the expansion or operation of the 

Bulk-Power System 

(a) Commission Determination

1039. The Commission adopts the NOPR’s proposal to require transmission providers to 

use data and modeling assumptions for short- and long-term ATC calculations that are 

consistent with those used for the planning of operations and system expansion, to the 

maximum extent practicable. This includes, for example: (1) load levels; (2) generation 

dispatch; (3) transmission and generation facilities maintenance schedules; 

 334 NOPR at P 169. 
Docket No. RM06-16-000 - 285 - 

(4) contingency outages; (5) topology; (6) transmission reservations; (7) assumptions 

regarding transmission and generation facility additions and retirements and (8) 

counterflows, which must be the same in the models used in the transmission operational 

and planning studies performed for the transmission providers’ native load. We find that 

requiring consistency in the data and modeling assumptions used for ATC calculation 

will remedy the potential for undue discrimination by eliminating discretion and ensuring 

comparability in the manner in which a transmission provider operates and plans its 

system to serve native load, and the manner in which it calculates ATC for service to 

third parties. 

1040. We clarify that we require consistent use of assumptions underlying operational 

planning for short-term ATC and expansion planning for long-term ATC calculation. We 

also clarify that there must be a consistent basis for or approach to determining load 

levels in each of these sets of calculations. For example, one approach may be for 

transmission providers to calculate load levels using an on- and off-peak model for each 

month when evaluating yearly service requests and calculating yearly ATC. The same 

(peak- and off-peak) or alternative approaches may be used for monthly, weekly, daily 

and hourly ATC calculations. Regardless of the ultimate choice, it is imperative that all 

transmission providers use the same approach to modeling load levels to eliminate undue 

discrimination and enable the meaningful exchange of data among transmission 

providers. Accordingly, we direct the ERO to develop consistent requirements for 

modeling load levels in MOD-001-0. 

1041. With respect to modeling of generation dispatch, we direct the ERO to develop 

requirements in MOD-001-0 specifying how transmission providers should determine 

which generators should be modeled in service, including guidance on how independent 

generation should be considered. Accordingly, we direct the ERO to revise Reliability 

Standard MOD-001-0 by specifying that base generation dispatch will model: (1) all 

designated network resources and other resources that are committed to or have the legal 

obligation to run, as they are expected to run and (2) all uncommitted resources that are 

deliverable within the control area, economically dispatched as necessary to meet 

balancing requirements. 

1042. Regarding transmission reservations modeling, we direct the ERO to develop 

requirements in Reliability Standard MOD-001-0 that specify: (1) a consistent approach 

on how to simulate reservations from points of receipt to points of delivery when sources 

and sinks are unknown and (2) how to model existing reservations. 

1043. Consistent with Order No. 890, the Commission directs the ERO to modify 

Reliability Standard MOD-001-0 to require ATC to be updated by all transmission 

providers on a consistent time interval and in a manner that closely reflects the actual 

topology of the system, e.g., generation and transmission outages, load forecasts, 
Docket No. RM06-16-000 - 286 - 

interchange schedules, transmission reservations, facility ratings and other necessary 

data. This process must also consider whether ATC should be calculated more frequently 

for constrained facilities. 

1044. In conclusion, we direct the ERO to modify MOD-001-0 to require that: (1) 

assumptions used for short-term ATC calculations be consistent with those used for 

operation planning to the maximum extent practicable; (2) assumptions used for longterm ATC calculations be consistent with those used for system planning to the 

maximum extent practicable and (3) ATC be updated by all transmission providers on a 

consistent time interval. 

vii. Include a Requirement That Applicable Entities 

Make Available Assumptions and Contingencies 

Underlying ATC and TTC Calculations

(a) Comments

1045. APPA supports the Commission’s proposal that NERC modify MOD-001-0 to 

include a requirement that applicable entities make available a comprehensive list of 

assumptions and contingencies underlying ATC and TTC calculations. 

(b) Commission Determination

1046. We adopt the NOPR’s proposal that this Reliability Standard should include a 

requirement that applicable entities make available a comprehensive list of assumptions 

and contingencies underlying ATC/AFC and TTC/TFC calculations. While we require 

the submission of contingency files under MOD-010-0, here we only direct the ERO to 

consider development of a requirement that the transmission service provider declare 

what type of contingencies it uses for specific calculations of ATC/AFC and TTC/TFC, 

and release the contingency files upon request if not submitted with the data filed with 

the ERO in compliance with MOD-010-0. 

1047. In order to increase the transparency of ATC calculations, we adopt the NOPR’s 

proposal and direct the ERO to develop in MOD-001-0 a requirement that each 

transmission service provider provide on OASIS its OATT Attachment C, in which Order 

No. 890 requires transmission providers to include a detailed description of the specific 

mathematical algorithm the transmission provider uses to calculate both firm and nonfirm ATC for various time frames such as: (1) the scheduling horizon (same day and realtime), (2) operating horizon (day ahead and pre-schedule) and (3) planning horizon 

(beyond the operating horizon). In addition, a transmission provider must include a 

process flow diagram that describes the various steps that it takes in performing the ATC 

calculation. 
Docket No. RM06-16-000 - 287 - 

viii. Address only ATC while TTC should be addressed 

under FAC-012-1 

(a) Comments

1048. APPA concurs with the NOPR’s proposal that TTC should be standardized under 

FAC-012-1, and that there appears to be little or no distinction between the definitions for 

TTC (MOD-001-0) and TC (FAC-012-1). APPA anticipates that this distinction will 

either be clarified or eliminated through ongoing Reliability Standards development 

activity. 

1049. Conversely, MidAmerican notes that the transfer capability covered by FAC-012-

1 may not relate to the TTC that is the subject of the MOD-001-0 standard. 

MidAmerican opines that the purpose of the FAC-012-1 standard is to ensure that each 

reliability coordinator and planning authority documents the methodology used to 

develop inter- and intra-regional transfer capabilities used in the reliable planning and 

operation of the Bulk-Electric System. MidAmerican further details that transfer 

capabilities that are covered by FAC-012-1 could be used by a reliability coordinator to 

operate the system in a temporary situation or by the planning authority as the basis for a 

sensitivity case. It adds that in neither of these cases would these transfer capabilities 

necessarily be included in calculations for ATC that would be used for offering 

transmission capacity for sale. 

(b) Commission Determination

1050. We adopt the NOPR proposal and require that TTC be addressed under the 

Reliability Standard that deals with transfer capability such as FAC-012-1, rather than 

MOD-001-0. The FAC series of standards contain the Reliability Standards that form the 

technical and procedural basis for calculating transfer capabilities. FAC-008-1 provides 

the basis for determining the thermal ratings of facilities while FAC-009-1 provides the 

basis for communicating those ratings. FAC-010-1 and FAC-011-1 provide the system 

operating limits methodologies for the planning and operational horizon respectively and 

FAC-014 provides for the communication of those ratings.335 

1051. The Commission directs the ERO, through the Reliability Standards development 

process, to modify FAC-012-1 and any other appropriate Reliability Standards to assure 

 335 FAC-010, FAC-011, and FAC-014 are addressed in Docket No. RM07-03 

because they were submitted later than the original 107 Reliability Standards and we did 

not have sufficient time to allow appropriate review and comment. 
Docket No. RM06-16-000 - 288 - 

consistency in the determination of TTC/TFC for services provided under the pro forma

OATT, and requires that those processes be the same as those used in operation and 

planning for native load and reliability assessment studies. Changes to the process of 

calculating TTC are appropriate if implementation is coordinated with revisions to the 

other applicable operating or planning standards. We acknowledge that reliability 

regions have historically calculated transfer capability using different approaches, and we 

agree that regional differences should be respected.336 However, as already discussed 

above regarding ATC, TTC requirements will be determined in the ERO Reliability 

Standards development process, and any request for a regional difference from the 

Reliability Standards must take place through the ERO process. 

1052. We disagree with MidAmerican’s opinion that transfer capabilities that are 

addressed by FAC-012-1 are necessarily different from TTC used for ATC calculation. 

The NERC glossary defines transfer capability (TC)337 as essentially identical to TTC.338 

We believe that modeling principles for simulating power transfers and determination of 

transfer capabilities should be the subject of a single standard. Those principles should 

be the same regardless of whether transfer capability is used for the purpose of 

operations, planning or offering for sale. By modeling principles we refer to the way 

transfers are simulated and the type of analysis that should be performed, such as steadystate, dynamic stability or voltage stability. We are certain that consistent calculation of 

transfer capabilities will prevent over- and under-estimation of the total transfer 

capability available for sale. We agree with APPA that this distinction should either be 

clarified or eliminated through the ongoing Reliability Standards development process, 

 336 For example, WECC has a documented open process for establishing TTC for 

the Western Interconnection. 

337 Transfer Capability is defined in the 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 18. 

338 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.” Id.. 
Docket No. RM06-16-000 - 289 - 

and therefore direct the ERO to modify MOD-001-0 to address TTC under transfer 

capability-related standards such as the FAC group of Reliability Standards. 

ix. Identify the entities to whom the MOD Standards 

apply 

(a) Comments

1053. APPA agrees in part with the Commission’s conclusion that “NERC should 

identify the applicable entities in terms of users, owners and operators of the Bulk-Power 

Systems.” 339 APPA, however, is concerned that this approach may confuse rather than 

clarify compliance responsibilities. According to APPA, a regional organization in 

conjunction with entities that plan, own, operate (and use) transmission facilities within 

each region must be involved in the development of any regional TTC and ATC 

methodology. In this context, APPA views the “regional reliability organization” as the 

technical arm of the reliability region, made up of the various committees whose 

members are users, owners and operators of the Bulk-Power System, along with support 

from the regional reliability organization staff. Further, APPA notes that ultimately, it is 

these core users, owners and operators of the Bulk-Power System that are responsible for 

the development of and adherence to the ATC methodology, and that the regional 

reliability organization, as an organization, is responsible for ensuring that the 

methodology is developed (under R1) and publicly posted (under R2). 

1054. In addition, APPA states that under the statutory framework established in FPA 

section 215, as interpreted by the Commission in Order No. 672, it is clear that the 

compliance monitor within each region is the Regional Entity, and the Regional Entity is 

not a user, owner or operator of the Bulk-Power System. APPA notes that while regional 

delegation agreements may be used to impose certain reliability compliance functions 

upon Regional Entities and their affiliates, no Regional Entity should be charged with 

enforcing compliance against itself. Ultimately, APPA is concerned that the quality of 

regional modeling and technical assessments will be diminished if the collaborative 

efforts used for the past 50 years of interconnected operations are displaced due to 

pressures to identify a single entity or class of entities with direct compliance 

responsibilities for regional modeling standards. APPA states that identifying all users, 

owners and operators as responsible entities does not answer the question either. APPA 

expresses its intention that it will work with NERC and with other stakeholders to ensure 

that this industry-based expertise is maintained and enhanced, while ensuring that 

responsible entities are identified in this and other NERC standards. 

 339 NOPR at P 610. 
Docket No. RM06-16-000 - 290 - 

(b) Commission Determination

1055. APPA is suggesting that respective regional organizations, their technical staff, 

and committees of users, owners and operators of the Bulk-Power System be charged 

with developing the methodologies. We disagree. These Reliability Standards should be 

developed through the Commission-approved Reliability Standards development process 

which will identify the entities that should implement the Reliability Standards, the 

Requirements necessary to achieve the goals identified in Order No. 890, and the 

Measures necessary to monitor compliance. 

1056. The Commission agrees with APPA that the collaborative efforts and knowledge 

developed over decades of interconnected operation should not be wasted. We do not 

believe that will happen through the Reliability Standards development process and that 

all of the applicable entities will have significant roles to play in achieving the goal the 

Commission has set out in Order No. 890. Therefore, we adopt the proposal in the 

NOPR and direct the ERO to modify MOD-001-0 to reflect the users, owners and 

operators to which the Reliability Standard will apply. 

x. Summary of Commission Determination 

1057. Accordingly, the Commission neither accepts nor remands MOD-001-0 until the 

ERO submits additional information. Although the Commission does not propose any 

action with regard to MOD-001-0, we address above a number of concerns regarding the 

Reliability Standard, consistent with those set forth in Order No. 890. We direct the ERO 

to develop modifications to the Reliability Standard through the Reliability Standards 

development process that: (1) provide a framework for ATC, TTC and ETC calculation, 

developing industry-wide consistency of all ATC components; (2) require disclosure of 

algorithms, for both firm and non-firm ATC and processes used in the ATC calculation; 

(3) identify a detailed list of information to be exchanged among transmission providers 

for the purposes of ATC modeling; (4) include a requirement that the assumptions used in 

ATC and AFC calculations should be consistent with those used for planning the 

expansion or operation of the Bulk-Power System to the maximum extent practicable; (5) 

include a requirement that ATC be updated by all transmission providers on a consistent 

time interval; (6) include a requirement that applicable entities make available 

assumptions and contingencies underlying ATC and TTC calculations; (7) address only 

ATC/AFC while TTC/TFC should be addressed under transfer capability standards such 

as FAC-012-1 and (8) identify the applicable entities in terms of users, owners and 

operators of the Bulk-Power System. 
Docket No. RM06-16-000 - 291 - 

d. Review of Transmission Service Provider Total Transfer 

Capability and Available Transfer Capability 

Calculations and Results (MOD-002-0)

1058. 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 and (3) 

provide the results of its most current reviews to NERC upon request. 

1059. In the NOPR, the Commission identified MOD-002-0 as a fill-in-the-blank 

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. 

The NOPR stated that the Commission would not propose to approve or remand MOD002-0 until the ERO submits additional information. 

i. Comments 

1060. APPA agrees that MOD-002-0 is a fill-in-the-blank standard. It is not sufficient in 

its current form and should not be approved as a mandatory Reliability Standard until the 

accompanying regional procedures are submitted and approved. 

ii. Commission Determination 

1061. The Commission adopts the NOPR proposal not to approve or remand MOD-002-

0 until the ERO submits additional information. 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 neither approves nor remands 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 - 292 - 

e. Regional Procedure for Input on Total Transfer 

Capability and Available Transfer Capability 

Methodologies and Values (MOD-003-0)

1062. MOD-003-0 requires each regional reliability organization to: (1) develop and 

document a procedure on how a transmission user can present its 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. 

1063. In the NOPR, the Commission identified MOD-003-0 as a fill-in-the-blank 

standard that requires each regional reliability organization to develop and document a 

procedure on how a transmission user can present its concerns regarding the TTC and 

ATC methodologies of a transmission service provider. The NOPR stated that the 

Commission would not propose to approve or remand MOD-003-0 until the ERO submits 

additional information. 

i. Comments 

1064. APPA agrees that MOD-003-0 is a fill-in-the-blank standard. It notes that it is not 

sufficient in its current form and should not be approved as a mandatory Reliability 

Standard until the accompanying regional procedures are submitted and approved. In 

addition, APPA hopes that if NERC develops the MOD-001-0 Reliability Standard 

properly, it will include a reporting procedure for addressing shortcomings in information 

for all transmission customers (LSE, generator owner and purchasing-selling entity) in 

the MOD-001-0 Standard. APPA argues that, as a result, MOD-003-0 may be redundant 

and should be eliminated. 

ii. Commission Determination 

1065. The Commission adopts the NOPR proposal not to approve or remand MOD-003-

0 until the ERO submits additional information. 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 neither accepts nor remands 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. 
Docket No. RM06-16-000 - 293 - 

1066. We direct the ERO to consider APPA’s suggestion that MOD-003-0 may be 

redundant and should be eliminated if the ERO develops a modification to the MOD-001-

0 Reliability Standard through the Reliability Standards development process that 

includes reporting requirements. 

f. Documentation of Regional Reliability Organization 

Capacity Benefit Margin Methodologies (MOD-004-0)

1067. MOD-004-0 requires each regional reliability organization to: (1) develop and 

document a regional CBM340 methodology in conjunction with its members and (2) post 

the most recent version of its CBM methodology on a website accessible by NERC, 

regional reliability organizations and transmission users. 

1068. In the NOPR, the Commission identified MOD-004-0 as a fill-in-the-blank 

standard that requires each regional reliability organization to develop and document a 

regional CBM methodology. The NOPR stated that because the regional CBM 

methodologies had not been submitted, the Commission would not propose to approve or 

remand MOD-004-0 until the ERO submits the additional information. 

1069. Although not proposing any action, the Commission nonetheless indicated that 

MOD-004-0 could be improved by: (1) providing more specific requirements on how 

CBM should be determined and allocated to interfaces and (2) including a provision 

ensuring that CBM, TRM and ETC cannot be used for the same purpose, such as the loss 

of an identical generation unit. Further, the Commission expressed concern that the 

Reliability Standard may unduly impact competition because of the lack of consistent 

criteria and clarity with regard to the entity on whose behalf CBM has been set aside. 

This lack of consistent criteria has the potential to result in the transmission provider’s 

setting aside capacity that it might not otherwise need to set aside, thus increasing costs 

for native load customers and blocking third party uses of the transmission system. 

 340 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 - 294 - 

i. Comments 

1070. APPA agrees with the Commission that MOD-004-0 should not be approved as a 

mandatory Reliability Standard until the relevant regional procedures are submitted and 

approved.341 

1071. FirstEnergy states that transmission capacity margins such as CBM and TRM are 

vitally important to the reliability of the system, and any methodology that would unduly 

limit these margins could create a danger of limiting transmission capacity over 

interconnected facilities that would limit the ability of balancing authorities and others to 

obtain generation reserves needed from the grid during contingency events. In contrast, 

TAPS questions how TRM or, especially, CBM, can be viewed as Reliability Standards if 

they are optional for the transmission provider. 

1072. MidAmerican supports greater uniformity of CBM definitions and calculations 

and states that the revised standard and/or new standards should support transparency and 

uniformity by encouraging increased availability of information and consistent data input 

and modeling assumptions. EEI emphasizes that additional data and information-sharing 

requirements would improve the transparency of various calculations and assumptions 

related to CBM, including this standard and the other CBM-related standards. EEI 

believes that, similar to the peer review processes of the planning studies carried out 

under the TPL standards, industry participants are best suited to developing the totality of 

assumptions, system conditions and other input variables that support the calculations. 

1073. EEI notes that, with respect to the Commission’s particular concern about criteria 

in determining resources and loads used in the CBM methodology, NERC’s “ATC 

Definitions and Determination”342 document clearly delineates the purpose and intent of 

the calculation of CBM and TRM. EEI states that CBM is intended to provide generation 

reliability, and TRM is intended to provide transmission reliability. EEI believes that, to 

the extent capacity capable of supplying CBM is located in the vicinity of the designated 

facility experiencing an outage, transmission may or may not be available under the 

 341 APPA notes that it has expressed its own concerns with CBM calculations and 

set-asides in its August 7, 2006 Initial Comments filed in Docket No. RM05-25-000, at 

31–55. APPA is hopeful these concerns can be addressed through NERC’s Reliability 

Standards development process. 

342 NERC, Available Transfer Capability Definitions and Determination - A 

Framework for Determining Available Transfer Capabilities of the Interconnected 

Transmission Networks for a Commercially Viable Electricity Market (June 1996). 
Docket No. RM06-16-000 - 295 - 

native load reservation normally used for the facility. Therefore, EEI argues, CBM may 

be needed on an interface where capacity is available for use as CBM, and not allowing 

all generation to be considered in this manner may unduly increase the generation reserve 

requirement within the transmission provider’s system. 

1074. EEI agrees with the Commission’s concern about double-counting TRM for those 

transmission providers who do not opt to use CBM. However, EEI argues that for 

transmission providers who do opt to use CBM, it may be appropriate in some 

circumstances to use the same generation unit outage to determine the impact on both 

generation and transmission reliability because the impacts are different. EEI cautions 

that artificially restricting such use is not appropriate, especially before NERC’s 

development of TRM and CBM standards and their presentation to FERC through the 

Reliability Standards development process. EEI recommends that the Commission 

encourage transmission providers to make CBM and TRM capacity available to 

wholesale markets for purchase on a non-firm basis, because doing so would ensure that 

both CBM and TRM capacity are available to the transmission provider during system 

emergencies, as intended. EEI notes that at other times the transfer capability associated 

with TRM and CBM would be available to the market, alleviating the concern of possible 

double-counting. MidAmerican also supports the Commission’s conclusion that doublecounting would be inappropriate, although MidAmerican states that it is not aware of any 

cases of double-counting of margins. 

1075. TAPS notes the significant potential for abuse343 that could result from the current 

flexibility afforded transmission providers in the calculation of CBM and TRM, and 

proposes innovative approaches344 to take CBM and (to the extent it is intended to cover 

transmission required for reserve sharing) TRM out of the hands of individual 

transmission providers, and to therefore reduce the opportunity for abuse. 

ii. Commission Determination 

1076. The Commission adopts the NOPR proposal not to approve or remand MOD-004-

0 until the ERO submits additional information. Because the regional procedures have 

not been submitted to the Commission, it is not possible to determine at this time whether 

MOD-004-0 satisfies the statutory requirement that a proposed Reliability Standard be 

 343 Documented by NERC’s April 14, 2005 Long-Term AFC/ATC Task Force 

Final Report. 

344 TAPS refers the Commission to its August 7, 2006 comments in Docket No. 

RM05-25-000 at 21-24. 
Docket No. RM06-16-000 - 296 - 

“just, reasonable, not unduly discriminatory or preferential, and in the public interest.” 

Accordingly, the Commission neither accepts nor remands 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. Consistent with Order No. 

890 and comments received in response to the NOPR, the Commission directs the ERO, 

through the Reliability Standards development process, to modify MOD-004-0 as 

discussed below. 

1077. We agree with FirstEnergy that CBM is important for system reliability by 

allowing the LSEs to meet their historical, state, RTO or regional generation reliability 

criteria requirement such as reserve margin, loss of load probability, loss of largest units, 

etc. We agree with EEI and MidAmerican that transparency of the studies supporting 

CBM determination will reduce the opportunity for transmission service providers to 

overestimate the amount of CBM and misuse transfer capability. We therefore direct the 

ERO to develop Requirements regarding transparency of the generation planning studies 

used to determine CBM values. We also clarify that CBM should only be set aside upon 

request of any LSE within a balancing area to meet its verifiable historical, state, RTO or 

regional generation reliability criteria requirement such as reserve margin, loss of load 

probability, loss of largest units, etc. We expect verification of the CBM values to be 

part of the Requirements with appropriate Measures and Levels of Non-Compliance. 

1078. We continue to believe this Reliability Standard should be modified to include a 

provision ensuring that CBM, TRM and ETC cannot be used for the same purpose, such 

as loss of the identical generating unit. In order to limit misuse of transfer capability set 

aside as CBM, we direct the ERO to provide more specific requirements for how CBM 

should be determined and allocated across transmission paths or flowgates. As we stated 

in Order No. 890, we do not mandate a particular methodology for allocating CBM to 

paths or flowgates. For example, one approach could be based on the location of the 

outside resources or spot market hubs that a LSE has historically relied on during 

emergencies resulting from an energy deficiency, but we agree with EEI that flexible 

rules should be allowed to prevent unnecessary increase of the generation reserve 

requirement within the transmission provider’s system. Therefore, we support flexibility, 

but expect that the ERO, using its Reliability Standards development process, will 

adequately approach these complex technical issues and propose a new version of MOD004-0 that addresses the methods for CBM determination and allocation on paths that 

will reduce reliability and discrimination concerns. 

1079. In response to TAPS’s question asking how CBM can be viewed as a Reliability 

Standard if it is optional to the transmission provider, our understanding is that 

transmission providers that have opted not to use CBM have instead set aside 
Docket No. RM06-16-000 - 297 - 

transmission margin (needed to bring in outside power to meet generation reliability 

criteria) either through ETC or TRM. CBM is not the only way to reserve transmission 

capacity for a margin. However, if the Reliability Standard is not clear regarding the 

method of calculating transmission margins, it may cause double-counting of 

transmission margins and reduction of ATC. As we stated in Order No. 890, we find that 

clear specification of the permitted purposes for which entities may reserve CBM and 

TRM will virtually eliminate double-counting of TRM and CBM. Therefore, we direct 

the ERO to modify its standard in order to prevent setting aside transfer capability for the 

same purposes. 

1080. We share TAPS’s concern that there is a significant potential for abuse as a result 

of the current flexibility afforded to transmission providers in the calculation of both 

CBM and TRM. In response to TAPS’s concern, we clarify that in accordance with the 

OATT Reform Final Rule and the ERO CBM definition, each LSE has the right to 

request CBM be set aside and use it to meet its verifiable historical, state, RTO or 

regional generation reliability criteria requirement such as reserve margin, loss of load 

probability, loss of largest units, etc. As such, the LSEs that request CBM be set aside 

must be identified as applicable entities with identified Requirements, including 

Requirements on generation studies to verify the set aside, Measures and Levels of NonCompliance. We direct the ERO to modify the Reliability Standard accordingly. 

1081. We agree with TAPS that there is a need for clearer requirements in the standard 

regarding to whom and how to submit a request for CBM set-aside, and what the 

transmission service provider should do if the sum of all CBM requirements exceeds the 

amount of available transfer capability. We direct the ERO to address the reliability 

aspects in the Reliability Standards development process and explore with NAESB 

whether business practices would be required. 

1082. Accordingly, the Commission neither accepts nor remands MOD-004-0 until the 

ERO submits additional information. 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. Although the Commission did 

not propose any action with regard to MOD-004-0, it addressed above a number of 

concerns regarding the Reliability Standard, consistent with those set forth in Order No. 

890. Therefore, we direct the ERO to develop modifications to the Reliability Standard 

through the Reliability Standards development process to: (1) clarify that CBM shall be 

set aside upon request of any LSE within a balancing area to meet its verifiable historical, 

state, RTO or regional generation reliability criteria; (2) develop requirements regarding 

transparency of the generation planning studies used to determine CBM value; (3) modify 

the current Requirements to make clear the process for how CBM is allocated across 

transmission paths or flowgates; (3) modify its standard in order to prevent setting aside 
Docket No. RM06-16-000 - 298 - 

CBM and TRM for the same purposes; (4) modify the standard by adding LSE as an 

applicable entity and (5) coordinate with NAESB business practice standards. 

1083. We direct the ERO to consider APPA’s suggestion that MOD-004-0 may be 

redundant and should be eliminated if the ERO develops a modification to the MOD-002-

0 Reliability Standard that includes reporting requirements 

g. Procedure for Verifying Capacity Benefit Margin Values 

(MOD-005-1)

1084. MOD-005-1 specifies the requirements regarding the periodic review of a 

transmission service provider’s adherence to the regional reliability organization’s CBM 

methodology. It requires each regional reliability organization to: (1) develop and 

implement a procedure to review at least annually the CBM calculations and the resulting 

values determined by member transmission service providers; (2) document its CBM 

review procedure and (3) make the results of the most current CBM review available to 

NERC upon request. 

1085. In the NOPR, the Commission identified MOD-005-0 as a fill-in-the-blank 

standard that requires each regional reliability organization to develop and implement a 

procedure to review CBM calculations and the resulting values and to make the 

documentation of the results of the CBM review available to NERC and others. The 

NOPR stated that because the regional procedures had not been submitted, the 

Commission would not propose to approve or remand MOD-005-0 until the ERO submits 

the additional information. 

i. Comments 

1086. APPA agrees that MOD-005-0 is a fill-in-the blank standard, and that in its current 

form, it is not sufficient and should not be accepted for approval as a mandatory 

Reliability Standard until the necessary regional procedures have been submitted and 

approved. APPA suggests that NERC modify MOD-006-0, so that MOD-004-0 and 

MOD-005-0 could be eliminated. 

ii. Commission Determination

1087. The Commission adopts the NOPR proposal not to approve or remand MOD-005-

0 until the ERO submits additional information. 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 neither accepts nor remands this Reliability Standard until 
Docket No. RM06-16-000 - 299 - 

the regional procedures are submitted. 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. 

1088. As to APPA’s comment on incorporating MOD-004 and MOD-005 into MOD006, we direct the ERO to consider those comments through the Reliability Standards 

development process. 

h. Procedure for Use of Capacity Benefit Margin Values 

(MOD-006-0)

1089. The purpose of MOD-006-0 is to promote the consistent and uniform use of 

transmission CBM calculations among transmission system users. MOD-006-0 requires 

that each transmission service provider document its procedure for the scheduling of 

energy against a CBM reservation and make the procedure available on a website 

accessible by the regional reliability organization, NERC and transmission users. 

1090. In the NOPR, the Commission proposed to approve Reliability Standard MOD006-0 as mandatory and enforceable. In addition, the Commission proposed to direct 

NERC to submit a modification to MOD-006-0 that: (1) includes a provision that will 

ensure that CBM and TRM are not used for the same purpose; (2) modifies Requirement 

R1.2 so that concurrent occurrence of generation deficiency and transmission constraints 

is not a required condition for CBM usage; (3) modifies Requirement R1.2 to define 

“generation deficiency” based on a specific energy emergency alert level and (4) expands 

the applicability section to include the entities that actually use CBM, such as LSEs. 

1091. In addition, the Commission proposed 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. The Commission provided guidance expressing its belief that 

CBM should be used only when the LSE’s local generation capacity is insufficient to 

meet balancing Reliability Standards, and that CBM should have a zero value in the 

calculation of non-firm ATC. 

i. Comments 

1092. APPA supports the Commission’s proposal to approve MOD-006-0. Moreover, 

APPA agrees with the Commission’s proposed directives345 that the standard should 

address the use of CBM and TRM for the same purpose. However, APPA believes that 

 345 NOPR at P 642. 
Docket No. RM06-16-000 - 300 - 

the specificity of the Commission’s proposed directives to NERC, if implemented, would 

undermine NERC’s role as the approved ERO with the technical expertise to develop and 

revise standards for the Commission’s subsequent review. APPA therefore suggests that 

the Commission in its Final Rule make clear to NERC its concerns about MOD-006-0, 

but then let NERC address those concerns through its Reliability Standard development 

process. 

1093. Regarding the Commission’s proposal that MOD-006-0 R1.2 be modified "so that 

concurrent occurrence of transmission constraints and a generation deficiency is not a 

requirement for CBM usage," WEPCO asserts that the Commission is misinterpreting 

CBM. WEPCO states that if there is no transmission constraint then there is no need to 

use CBM. In that case, transmission capacity exists for a LSE to import energy. If there 

is a transmission constraint, CBM reserves transmission capacity that the LSE can use to 

import energy for reliability needs. 

1094. EEI points out that the explicit intention for CBM is that it be used only during 

conditions where there are emergency generation deficiencies. However, EEI 

emphasizes that the Commission’s recommendation does not consider that the LSE’s 

supply and demand balance varies season to season, over time, and with supply and 

demand uncertainties. EEI says that the development of CBM quantities must be carried 

out in a manner that sets aside transmission capability for forecasted conditions and 

uncertainties much like the native load reservations necessary for serving reasonablyforecasted native load. An argument may be made that during a period of time when a 

LSE's expected reserves are substantially greater than its targeted reserves, the need for 

CBM set-aside decreases. However, should the LSE foresee that this "excess" would 

occur substantially in the future, a reduction in CBM would not be warranted since 

substantial uncertainties still exist. 

1095. Additionally, regarding the Commission’s proposal that a LSE that “has sufficient 

generation resources within its balancing authority to meet the balancing Reliability 

Standards, should not need to preserve capacity for CBM at all," WEPCO argues that just 

because the balancing authority has sufficient generation does not mean that there is 

sufficient transmission capacity to deliver the energy to the LSE. WEPCO states that the 

LSE may be remote from the bulk of the balancing authority, so there may be occasions 

when a LSE that has sufficient generation resources within its balancing authority to meet 

the balancing Reliability Standards may still need to reserve capacity for CBM. In 

addition, EEI argues that the Commission’s viewpoint does not take into account the 

availability of these resources unless they are under contract with the LSE to provide this 

service. EEI contends that the implication of this suggestion is to unduly restrict the 

sources of generation capacity available for CBM during times of generation shortage, 

which results in the LSE’s being captive to local generation that is available and does not 
Docket No. RM06-16-000 - 301 - 

allow access to the market outside of the LSE’s balancing authority. Additionally, EEI 

cautions that this action may require the LSE to develop contractual agreements with 

local generation and thus increase costs to the LSE’s rate payers. 

1096. Given the strong direction on CBM issues in the OATT Reform NOPR, TAPS 

assumes that the Commission would not be approving the Version 0 standards on these 

competitively crucial issues, but would continue to address them forcefully in the OATT 

Reform proceeding. TAPS notes that, although that is the course largely adopted by the 

NOPR in this proceeding, the NOPR346 proposes to approve MOD-006-0 and MOD-007-

0, with directions to improve these standards. TAPS notes that such action is inconsistent 

with the Commission’s general approach to ATC/TTC/TRM/CBM standards in this 

docket and the OATT Reform NOPR. TAPS further states that, given the absence of 

clear access of non-transmission owner LSEs to CBM, the proposed expansion of MOD007-0 to include such LSEs in the NOPR347 seems bizarre. 

ii. Commission Determination 

1097. The Commission adopts the NOPR proposal to approve MOD-006-0 as mandatory 

and enforceable. Consistent with Order No. 890 and comments received in response to 

the NOPR, the Commission directs the ERO to modify MOD-006-0 as discussed below. 

1098. Consistent with the views of many commenters, we adopt the NOPR proposal that 

requires a provision that will ensure that CBM and TRM are not used for the same 

purpose. As discussed under MOD-004-0 concerning the reservation of transfer capacity, 

we believe that if the Reliability Standard is not clear regarding the conditions specifying 

both the reservation and the use of CBM, it may cause double-counting. Such doublecounting will lead to an unnecessary reduction of ATC, and create opportunities for 

discrimination. Therefore, we direct the ERO to modify its standard to prevent use of 

CBM and TRM for the same purposes. We agree with APPA that the ERO should use its 

Reliability Standards development process to address the double-counting problem. 

1099. We adopt the NOPR’s proposal and direct the ERO to modify Requirement R1.2 

so that a transmission constraint is not a required condition for CBM usage. The glossary 

definition and the use as defined in Order No. 890 is that CBM “is intended to be used by 

 346 Id. at P 642, 648. 

347 Id. at P 647-48. 
Docket No. RM06-16-000 - 302 - 

the LSE only in time of emergency generation deficiencies.”348 Therefore we direct the 

ERO to modify the standard in the manner proposed in the NOPR. 

1100. We adopt the NOPR proposal that requires modification of Requirement R1.2 to 

define “generation deficiency” based on a specific energy emergency alert level. This 

approach will provide clarity as to when the use of CBM may be permitted. We therefore 

direct the ERO to modify the Reliability Standard to include a specific energy emergency 

alert level that will trigger CBM usage. 

1101. We also reiterate the direction in Order No. 890 that CBM should have a zero 

value in the calculation of non-firm ATC because non-firm service may be curtailed so 

that CBM can be used. CBM is reserved as part of the firm transfer capability so that it is 

available when needed for energy emergencies. We determine that each LSE should be 

permitted to call for use of CBM, provided all of the other Requirements of R1.1 are met. 

We direct that CBM may be implemented up to the reserved value when a LSE is facing 

firm load curtailments. 

1102. We adopt the NOPR proposal that CBM should be used only when the LSE’s local 

generation capacity is insufficient to meet balancing Reliability Standards, with the 

clarification that the local generation is that generation capacity that is either owned or 

contracted for by the LSE. We disagree with WEPCO that just because the balancing 

authority has sufficient generation does not mean that there is transmission capacity to 

deliver the energy to the LSE. The Commission finds that such a scenario would violate 

existing transmission operating and transmission planning Reliability Standards. There is 

an explicit requirement in the transmission operating standards that generation reserves 

must be deliverable to load.349 Also, there is an explicit requirement in the transmission 

planning standards that all firm load must be supplied under various system conditions 

with and without contingencies.350 The Commission is not prescribing how these 

requirements should be met. There are a variety of approaches to do so, including 

adequate transmission capability, local or dynamic generation transfers into the area or 

DSM. To clarify for EEI, our proposal does not take into account the availability of these 

resources unless they are under contract with the LSE to provide this service. We 

developed our NOPR proposal on the rationale derived from the CBM concept, and 

 348 See NERC Glossary at 2. 

349 TOP-002-2. 

350 TPL-002-0. 
Docket No. RM06-16-000 - 303 - 

believe that if there are enough resources to meet generation reliability criteria within the 

balancing authority, there is no need to request CBM. 

1103. We also adopt the NOPR proposal to require the applicability section to include 

the entities that actually use CBM, such as LSEs. The current CBM definition in the 

NERC glossary determines that LSEs are users of CBM. Load-serving entities determine 

when to use CBM, initiate CBM use and call for its end. Load-serving entities therefore 

have to comply with the standard requirements that specify the conditions under which 

CBM will be used. We direct the ERO to modify the standard accordingly. 

1104. With regard to TAPS’s comments concerning its assumption that the Commission 

would not be approving the Version 0 standards on these issues, but would continue to 

address them in the OATT Reform proceeding, the Commission finds that MOD-006-0 

and MOD-007-0 do not establish CBM values, but rather address CBM implementation 

and documentation. The implementation of CBM has critical implications for the reliable 

operation of the Bulk-Power System and we find that these Reliability Standards should 

be mandatory and enforceable. The competitively significant issue is to assure that there 

is no double-counting of CBM and to determine the magnitude of CBM which is 

addressed in other Reliability Standards that the Commission has not approved or 

remanded. 

1105. The Commission approves MOD-006-0 as mandatory and enforceable. In 

addition, the Commission directs the ERO to develop a modification to Reliability 

Standard MOD-006-0 through the Reliability Standards development process that: (1) 

includes a provision that will ensure that CBM and TRM are not used for the same 

purpose; (2) provides that CBM should be used for emergency generation deficiencies; 

(3) modifies Requirement R1.2 to define “generation deficiency” based on a specific 

energy emergency alert level; (4) includes a provision that CBM should have a zero value 

in the calculation of non-firm ATC and (5) expands the applicability section to include 

the entities that actually use CBM, such as LSEs. 

i. Documentation of the Use of Capacity Benefit Margin 

(MOD-007-0)

1106. MOD-007-0 requires transmission service providers that use CBM to report and 

post its use. 

1107. In the NOPR, the Commission proposed to approve Reliability Standard MOD007-0 as mandatory and enforceable. In addition, the Commission proposed to direct 

NERC to submit a modification to MOD-007-0 that expands the applicability section to 

include the entities that actually use CBM, such as LSEs. 
Docket No. RM06-16-000 - 304 - 

i. Comments 

1108. APPA supports the Commission’s proposed approval of MOD-007-0. However, it 

believes that the issue of whether LSEs should be made subject to MOD-007-0 should be 

left to NERC in the first instance to decide. In so doing, NERC should consider 

expanding MOD-007-0 to cover not only LSEs, but also balancing authorities. Under 

NERC’s Functional Model, the balancing authority is the entity that would schedule 

energy over transmission capacity reserved as CBM. Moreover, it is the balancing 

authority that would know the information necessary to report an incident during which 

the balancing authority had to import energy from outside the balancing authority’s own 

area from a resource designated as operating reserves and change the net scheduled 

interchange with the neighboring balancing authorities to allow the energy to flow into 

the balancing authority’s area. 

ii. Commission Determination 

1109. The Commission approves MOD-007-0 as mandatory and enforceable. Consistent 

with the comments received in response to the NOPR, the Commission directs the ERO 

to modify the standard as discussed below. 

1110. We also adopt the NOPR’s proposal to require the applicability section to include 

the entities that actually use CBM and report on their CBM use, such as LSEs. The 

current CBM definition in the NERC glossary determines when a LSE is a CBM user. 

The LSE determines how much CBM will be set aside, when CBM use will start and 

when it will end. The LSE must therefore comply with the standard requirements that 

require reporting and posting of CBM use. We direct the ERO to modify the standard to 

include the entities that actually use CBM, such as LSEs. In addition, we agree with 

APPA that the Reliability Standard should apply to balancing authorities and direct the 

ERO to include balancing authorities within the entities to which this standard is 

applicable. 

1111. Accordingly, the Commission approves MOD-007-0 as mandatory and 

enforceable. In addition, the Commission directs the ERO to develop a modification 

through its Reliability Standards development process that expands the applicability of 

MOD-007-0 to include the entities that actually use CBM, such as LSEs and balancing 

authorities. 
Docket No. RM06-16-000 - 305 - 

j. Documentation and Content of Each Regional 

Transmission Reliability Margin Methodology (MOD008-0)

1112. MOD-008-0 requires the development and posting of a regional methodology for 

TRM, which is transmission capacity that is reserved to provide reasonable assurance that 

the interconnected transmission network will remain secure under various system 

conditions. The Reliability Standard requires each regional reliability organization to: (1) 

develop and document a regional TRM methodology in conjunction with its members 

and (2) post on a website the most recent version of its TRM methodology. 

1113. In the NOPR, the Commission identified MOD-008-0 as a fill-in-the-blank 

standard, proposing that because the regional methodologies had not been submitted, the 

Commission would not propose to approve or remand MOD-008-0 until the ERO 

submitted the additional information. The Commission expressed concern about the lack 

of: (1) clear requirements on how TRM should be calculated and allocated across paths 

and (2) consistent criteria and clarity with regard to the entity on whose behalf TRM had 

been set aside. 

1114. The Commission requested comment in the NOPR on how TRM is currently 

calculated and allocated across paths, and what would be a recommended approach for 

the future. 

i. Comments 

1115. APPA agrees that MOD-008-0 is a fill-in-the-blank standard, is not sufficient as 

currently drafted, and should not be approved as a mandatory Reliability Standard until 

NERC and the regional reliability organizations and regional entities develop the 

necessary regional methodologies and the Commission approves them. 

1116. MISO adds that there should be a consistent framework to be followed by entities 

in determining TRM. It states that relevant MOD standards should be revised if such a 

framework is not clearly delineated. However, MISO cautions that a Reliability Standard 

should not be used to address a perceived equity concern. MidAmerican also supports 

greater uniformity of TRM definitions and calculations, and proposes that a revised 

standard and/or new standards should encourage transparency with increased availability 

of information, consistent data input and certain modeling assumptions. International 

Transmission agrees and proposes that TRM consistency should be addressed either on a 

regional basis or on an Interconnection-wide basis. 

1117. In response to the Commission’s request for comments on the current calculation 

of TRM, and recommended approaches for the future, International Transmission 
Docket No. RM06-16-000 - 306 - 

provides a description of the MISO approach to TRM. International Transmission states 

that during the operating horizon (next 48 hours), TRM is limited to a reserve sharing 

component which only applies to flowgates that are not based on transmission outages 

(unit tripping and transmission outages are considered a double contingency). 

International Transmission states that the logic behind this approach is that there are 

fewer uncertainties in the operating horizon because schedules and market flows are 

known. International Transmission explains that during the planning horizon (next 48 

hours), a two percent TRM component for uncertainty is used on all flowgates, including 

those requiring reserve sharing TRM. In addition, other assumptions regarding the sale 

of transmission service enter into the need for TRM to cover “uncertainties.” In addition, 

International Transmission cautions that MISO’s minimal two percent margin may not be 

sufficient for long-term planning horizon requests (i.e., over 13 months) if planning 

“assumptions” are not reasonable. International Transmission argues that MISO must 

also employ proper sensitivity studies to other system variables for a two percent margin 

to be sufficient. TRMs in the five to ten percent range are not necessarily unreasonable if 

a wide range of potential system operating conditions is not studied. Regardless of the 

ultimate approach adopted in future standards, International Transmission proposes that 

all entities follow a consistent framework when calculating TRM. 

1118. MidAmerican responds with a discussion of its current approach to TRM 

calculation, which has been performed in accordance with MAPP-approved 

methodologies. MidAmerican states that these methodologies include an amount to 

allow for both the delivery of operating reserves and for uncertainties. Since delivery of 

operating reserves keeps the interconnected network in service, benefiting all market 

participants, MidAmerican contends that it is appropriate for TRM to include an amount 

to allow for the delivery of operating reserves. The allowance for uncertainty is 

calculated as a percentage of TTC required to protect reliability. All market participants 

benefit from the provision of an appropriate margin for uncertainty because the reliability 

of the interconnected network is maintained and service interruptions are reasonably 

minimized. 

1119. With respect to applicable entities, APPA proposes the addition of two new 

functional entities. Specifically, APPA believes that NERC should expand the 

applicability section of MOD-008-0 to include planning authorities and reliability 

coordinators. APPA points out that these are the only entities that can evaluate the 

amount of error in their transfer capability predictions. 

1120. ERCOT states that the Commission’s concerns about TRM do not apply to 

ERCOT, because ERCOT has a balanced grid in which all transmission is firm, no 

transmission is reserved and there are no transmission paths. 
Docket No. RM06-16-000 - 307 - 

ii. Commission Determination 

1121. The Commission does not approve or remand MOD-008-0 until the ERO submits 

additional information. Consistent with Order No. 890 and comments received in 

response to the NOPR, the Commission directs the ERO to modify MOD-008-0 through 

the Reliability Standards development process, as discussed below. 

1122. Consistent with the NOPR proposal and Order No. 890, the Commission directs 

the ERO to modify standard MOD-008-0 to clarify how TRM should be calculated and 

allocated across paths or flowgates. We understand that the standards drafting process is 

underway as a joint project with NAESB. We agree with International Transmission, 

MidAmerican and MISO about the need for more uniformity and transparency in TRM 

calculation methodology and use, in order to eliminate potential reliability and 

discrimination concerns. Consistent with Order No. 890, the Commission directs the 

ERO to specify the parameters for entities to use in determining uncertainties for which 

TRM can be set aside and used, such as: (1) load forecast and load distribution error; (2) 

variations in facility loadings; (3) uncertainty in transmission system topology; (4) loop 

flow impact; (5) variations in generation dispatch; (6) automatic reserve sharing and (7) 

other uncertainties as identified through the NERC Reliability Standards development 

process. We find that clear specification in this Final Rule of the permitted purposes for 

which entities may reserve CBM and TRM will also virtually eliminate double-counting 

of TRM and CBM. Therefore, we direct the ERO to determine clear requirements 

regarding permitted uses for TRM through its Reliability Standards development process. 

1123. We agree with the commenters that the percentage reduction of line rating can be 

one way to establish an appropriate maximum TRM if thermal considerations are the 

only limiting factors. While this is a relatively simple method, it ignores limitations 

relative to voltage or stability limitations which are the more typical reasons for 

transmission limitations. If adopted as the Reliability Standard method, it should not 

restrict a transmission provider from using a more sophisticated method that may allow 

for greater ATC without reducing overall reliability. However, we disagree with the use 

of an arbitrary percentage over a long time frame that is not based on either proven 

historical need or sensitivity studies that support that determination. Therefore, 

consistent with our OATT Reform Final Rule, we direct the ERO to develop 

requirements regarding transparency of the documentation that supports TRM 

determination. 

1124. We agree with APPA that NERC should revise the applicability section of this 

standard to add planning authorities and reliability coordinators, and in addition, any 

other entities that may be identified in the Reliability Standards development process. 
Docket No. RM06-16-000 - 308 - 

1125. Regarding ERCOT’s statement that TRM does not apply to ERCOT, we reiterate 

our position that any request for a regional exemption from the applicable Reliability 

Standards must take place in the Reliability Standards development process. 

1126. The Commission neither accepts nor remands MOD-008-0 until the ERO submits 

additional information. In the interim, compliance with MOD-008-0 should continue on 

a voluntary basis, and the Commission considers compliance with the Reliability 

Standard to be a matter of good utility practice. Although the Commission did not 

propose any action with regard to MOD-008-0, it addressed above a number of concerns 

regarding the Reliability Standard, consistent with those proposed in Order No. 890. 

Accordingly, we direct the ERO to develop modifications to the Reliability Standard 

through the Reliability Standards development process including: (1) clear requirements 

on how TRM should be calculated, including a methodology for determining the 

maximum TRM value, and allocated across paths; (2) clear requirements for permitted 

purposes for which TRM can be set aside and used; (3) clear requirements for availability 

of documentation that supports TRM determination and (4) expanding the applicability to 

add planning authorities and reliability coordinators and any other appropriate entity 

identified in the Reliability Standards development process. 

k. k. Procedure for Verifying Transmission Reliability

Margin Values (MOD-009-0)

1127. MOD-009-0 requires 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. 

1128. In the NOPR, the Commission identified MOD-009-0 as a fill-in-the-blank 

standard that requires each regional reliability organization to develop a procedure for 

review of TRM calculations and the resulting values. In the NOPR, the Commission 

stated that because the regional procedures had not been submitted, the Commission 

would not propose to approve or remand MOD-009-0 until the ERO submits the 

additional information. 

i. Comments 

1129. APPA agrees that MOD-009-0 is a fill-in-the-blank standard, is not sufficient as 

currently drafted, and should not be approved as a mandatory Reliability Standard until 

NERC and the regional reliability organizations and regional entities develop the 

necessary regional methodologies and the Commission approves them. 
Docket No. RM06-16-000 - 309 - 

ii. Commission Determination

1130. The Commission will not approve or remand MOD-009-0 until the ERO submits 

additional information. 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 neither approves nor remands this Reliability Standard until the regional 

procedures are submitted. In the interim, compliance with MOD-009-0 should continue 

on a voluntary basis, and the Commission considers compliance with the Reliability 

Standard to be a matter of good utility practice. 

l. Steady-State Data for Modeling and Simulation of 

Interconnected Transmission System (MOD-010-0)

1131. The purpose of this Reliability Standard is to establish consistent data 

requirements, reporting procedures and system models for use in 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 other specified entities. 

1132. In the NOPR, the Commission proposed to approve Reliability Standard MOD010-0 as mandatory and enforceable. In addition, the Commission proposed to direct 

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. 

i. Comments 

1133. APPA agrees with the Commission that MOD-010-0 is sufficient for approval as a 

mandatory and enforceable Reliability Standard. APPA believes, however, that the 

Commission’s proposed directives to NERC to revise this standard are unduly 

prescriptive, and may not in fact be the best way to revise the standard. 

1134. ISO/RTO Council and ISO-NE do not support adoption of this standard because 

its requirements refer several times to the data requirements and reporting procedures 

specified in MOD-011-0, which has been identified by the Commission as a fill-in theblank standard. ISO/RTO Council and ISO-NE argue that demonstrating compliance 

with MOD-010-0 is dependent on an unapproved standard, that the unapproved standard 

lacks some required criteria or procedures that must be developed by the regional 
Docket No. RM06-16-000 - 310 - 

reliability organization, that MOD-010-0 cannot be effectively implemented, and that 

responsible entities therefore should not be subject to compliance with an incomplete 

standard. 

1135. Constellation strongly supports the Commission's proposals with respect to MOD010-O and MOD-012-0 because these proposals, together with other initiatives, such as 

OATT reform, represent additional steps not only to achieving a reliable bulk power 

system, but also to reducing undue discrimination in transmission services. Constellation 

supports the Commission's proposals because they will involve generation owners in 

facility ratings discussions and discussions of other limiting components and will provide 

more clarity in the requirements of the Reliability Standard, making enforcement more 

objective and robust. 

1136. Many commenters submitted comments both supporting and opposing the 

Commission’s proposal to modify the standard to require listing the contingencies that 

transmission owners use when they perform system operation and planning studies. 

1137. FirstEnergy supports the Commission’s proposal to require transmission owners to 

provide the list of contingencies used in performing system operation and planning 

studies. FirstEnergy emphasizes that such a requirement, however, should accommodate 

various electronic formats that are commonly used in industry simulation tools. 

FirstEnergy states that compliance with this Reliability Standard should not require 

transmission owners to replace existing computer and/or software systems, and that the 

new standard should also require the regional reliability organizations (or Regional 

Entities) to coordinate the lists of contingencies across wide-areas. 

1138. In its support of the Commission’s proposal, MidAmerican and TANC stress that 

a requirement that the transmission owner provide a list of contingencies to neighboring 

systems will benefit reliability by enabling neighboring systems to accurately study the 

effects of contingencies on their own systems. In its concurring comments, TANC 

recommends that the Commission clarify that the list of the contingencies that are used in 

performing system operation and planning studies include all the contingencies, N-1, N2, as well as multiple contingencies. 

1139. MidAmerican cautions that a list of contingencies could be used in a “cook-book” 

manner to reach the wrong conclusions. A contingency must be modeled in specific and 

appropriate conditions to understand the reliability issues associated with the 
Docket No. RM06-16-000 - 311 - 

contingency.351 Similarly, NERC states that there may be a need to better understand the 

reliability need for transmission owners to provide a list of contingencies and to whom 

the list should be provided. 

1140. Northern Indiana and MidAmerican note that such a list of contingencies should 

be considered a particularly sensitive form of CEII since it would be a list of events that, 

when they occur, cause critical situations on a system. Northern Indiana and 

MidAmerican argue that the Commission should include the need to provide for 

protection against public disclosure through the NERC administrative process in its 

discussion of any final Reliability Standard. In addition, California Cogeneration states 

that Requirements R1 and R2 of this standard should not apply to entities that have no 

material impact on the grid. California Cogeneration warns that the standard may also 

require generator owners to provide data on behind-the-meter operations, the provision of 

which should be seriously limited, and data on future interchange schedules, the 

confidentiality of which should be maintained. 

1141. PG&E and Xcel oppose the proposed modification requiring a list of 

contingencies stating that the requirement is unnecessary and would be unduly 

burdensome. Xcel also states that the modification would not prove to be useful to 

neighboring systems. No such lists are currently developed or maintained today. Rather, 

the contingencies are reflected in the computerized models used by transmission 

providers for both transmission planning and operations. The models are regularly 

updated as new facilities are installed. If transmission operators are required to develop 

such lists, they would be so long and subject to constant change that they would not only 

be burdensome to develop and maintain, but also unlikely to provide useful information 

for other transmission owners. 

 351 MidAmerican further cautions that other contingencies exist that must be 

studied under still-different conditions. Advanced applications associated with real-time 

contingency analysis review an extensive list of events in combination with other events. 

Ahead of time, there is no way to be sure exactly which events are the worst in any given 

operating condition. A single reliability standard cannot contain all the coordination that 

is needed to allow a system to fully understand all the reliability challenges of a 

neighboring system. Thus, MidAmerican contends that a better approach is to continue 

the joint operational and long-term planning that planning authorities, reliability 

coordinators and other regional entities are currently conducting with transmission 

planners, transmission owners and others to ensure that the interconnected network is 

operated and planned in a coordinated way. 
Docket No. RM06-16-000 - 312 - 

1142. In its opposition to releasing a list of contingencies, PG&E states that performing 

transmission planning studies is an ambiguous part of the duties of a transmission owner 

under the NERC Functional Model. Further clarification and refinement of the 

responsibilities of each entity under the NERC Functional Model may indicate that such 

studies are among a transmission owner’s duties. Until that happens, however, requiring 

transmission owners to provide contingencies used in performing system operation and 

planning studies is inappropriate. 

1143. SoCal Edison and TVA state that the entity that should be responsible for 

providing a list of contingencies in performing planning and operation studies is the 

transmission planner, not the transmission owner. APPA also believes that the 

transmission operator should be one of the entities required to list contingencies used to 

perform studies, and that the transmission owner function should be removed as an 

applicable entity. APPA further notes that the transmission owner does no studies 

regarding operations or planning. A transmission owner merely owns transmission 

facilities and maintains those facilities. Moreover, APPA argues that existing studies 

performed by the transmission planner for the regional reliability organization or 

planning authority will include a list of contingencies. 

1144. Regarding the Commission’s proposal to expand the applicability section of this 

Reliability Standard to include the planning authority, APPA disagrees and recites the 

comments of MRO, Reliability First and PG&E on the Staff Preliminary Assessment,352

that to require the planning authority to provide all of this information is duplicative and 

unnecessary. APPA believes that NERC, as the entity charged with developing 

standards, is best-suited to address all of these concerns and to develop a consensus 

standard using its Reliability Standard development process. 

1145. TAPS states that this standard would impose unnecessary costs on small systems 

without improving reliability if applied without the limitation of NERC’s bulk electric 

system definition and NERC’s June registry criteria. TAPS opines that modeling will be 

complicated by the incorporation of low voltage or radial transmission facilities or small 

generators that have no material impact on bulk transmission system reliability, without 

improving the results. TAPS further argues that NERC and the Regional Entities – not 

the Commission – should determine the level of modeling required for reliability. 

 352 NOPR at P 663. 
Docket No. RM06-16-000 - 313 - 

ii. Commission Determination 

1146. The Commission approves MOD-010-0. In addition, the Commission requires the 

ERO to modify MOD-010-0 as described below. 

1147. As an initial matter, the Commission disagrees that MOD-010-0 cannot be 

implemented until MOD-011-0 is modified. We have directed that data collection and 

reporting procedures not be interrupted while MOD-011-0 is being modified. Therefore 

it is possible to implement MOD-010-0. Failure to have the data needed for the steadystate analysis would halt regional reliability assessment processes and hinder planners 

from accurately predicting future system conditions, which would be detrimental to 

system reliability. We therefore 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 Entity 

the information related to data gathering, data maintenance, reliability assessments and 

other process-type functions. As we discuss below in the section on MOD-011-0, we 

direct the ERO to develop a Work Plan that will facilitate ongoing collection of the 

steady-state modeling and simulation data set forth in MOD-011-0, and submit a 

compliance filing with that Work Plan. 

1148. Supported by many commenters, we adopt the NOPR proposal to direct the ERO 

to modify MOD-010-0 to require filing of all of the contingencies that are used in 

performing steady-state system operation and planning studies. We believe that access to 

such information will enable planners to accurately study the effects of contingencies 

occurring in neighboring systems on their own systems, which will benefit reliability. 

Because of the lack of information on contingency outages and the automatic actions that 

result from these contingencies, planners have not been able to analyze neighboring 

conditions accurately, thereby potentially jeopardizing reliability on their own and 

surrounding systems. This requirement will make transmission planning data more 

transparent, consistent with Order No. 890 requiring greater openness of the transmission 

planning process. 

1149. With respect to TANC’s recommendation to modify the standard to require 

utilities to provide lists of all contingencies they use to operate and plan their systems (N1, N-2, multiple), we clarify that our requirement specifies contingency files used for all 

operations and planning. We do not limit the provision of contingency information to 

single, double or multiple outages. Utilities must provide lists of all the contingencies 

they use in operations and planning, provided in their original format, regardless of how 

this data is organized. 

1150. In response to MidAmerican, NERC and TANC’s concerns that the contingency 

lists could be used as a “cook-book,” our expectation is that utility planners that use these 

files will have sufficient experience to use them appropriately. We expect that most 
Docket No. RM06-16-000 - 314 - 

utility planners are already familiar with their neighbors’ system topologies, and have the 

means, such as bus abbreviation directories and switching diagrams, to identify facilities 

listed in contingency files. 

1151. We agree with FirstEnergy’s comments regarding the importance of using 

existing data collection systems so as to not impose any additional costs on entities. They 

may file the contingency files in the electronic format in which they were created, along 

with any necessary decoding instructions. We therefore disagree with PG&E, TAPS and 

Xcel that this Reliability Standard will be unduly burdensome since it only requires the 

provision of files that must be developed during the utility’s usual planning and 

operations study process. 

1152. Consistent with California Cogeneration, Northern Indiana and MidAmerican’s 

concerns, we determine that those data that a company considers confidential, 

commercially-sensitive or security-sensitive should be released in accordance with the 

CEII process or subject to confidentiality agreements. We direct the ERO to address 

confidentiality issues and modify the Reliability Standard as necessary through its 

Reliability Standards development process. 

1153. We disagree with commenters that generators or small entities that do not have a 

material impact on grid reliability should be automatically exempt from providing the 

data required by this Reliability Standard. The Commission believes that all entities that 

are required to register under the registration process that we have approved must provide 

data requested by the ERO or the Regional Entity. 

1154. We agree with APPA, SoCal Edison and TVA that the functional entity 

responsible for providing the list of contingencies in performing planning studies should 

be the transmission planner, instead of the transmission owner, as proposed in the NOPR. 

We also agree with APPA that the transmission operator should be one of the entities 

required to list contingencies used to perform operational studies. Transmission 

operators are usually responsible for compiling the operational contingency lists for both 

normal and conservative operation. Therefore, we direct the ERO to modify MOD-010-0 

to include transmission operators as an applicable entity. 

1155. We adopt our NOPR proposal that the planning authority should be included in 

this 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. We disagree with 

APPA that it is duplicative and unnecessary to require the planning authority to provide 

all of this information. However, we direct the ERO, as the entity charged with 

developing Reliability Standards, to address all of these concerns and to develop a 

consensus standard using its Reliability Standard development process. 
Docket No. RM06-16-000 - 315 - 

1156. Accordingly, the Commission approves MOD-010-0 as mandatory and 

enforceable. In addition, the Commission directs the ERO to develop a modification to 

MOD-010-0 through the Reliability Standards development process that: (1) adds a new 

requirement in MOD-010-1 for transmission planners to provide the contingency lists 

they use in performing system operation and planning studies, contained in the electronic 

format in which they were created, along with any necessary decoding instructions and 

(2) expands the applicability section to include transmission operators and the planning 

authority. We also direct the ERO to address confidentiality and small entity issues 

through the Reliability Standards development process. 

m. Maintenance and Distribution of Steady-State Data 

Requirements and Reporting Procedures (MOD-011-0)

1157. The purpose of MOD-011-0 is to establish consistent data requirements, reporting 

procedures and system models for use in reliability analysis. This Reliability Standard 

requires the regional reliability organizations to develop comprehensive steady-state data 

requirements and reporting procedures needed to model and analyze the steady-state 

conditions for each Interconnection. 

1158. In the NOPR, the Commission identified MOD-011-0 as a fill-in-the-blank 

standard that requires each regional reliability organization to develop comprehensive 

steady-state data requirements and reporting procedures needed to model and analyze the 

steady-state conditions for each Interconnection. The NOPR stated that because the 

regional methodologies had not been submitted, the Commission would not propose to 

approve or remand MOD-011-0 until the ERO submits the additional information. In 

addition, the NOPR suggested that the planning authority plays a significant role in 

integration of data and thus should be included in the applicability section of MOD-011-

0. 

i. Comments

1159. APPA agrees with the Commission that this standard is a fill-in-the-blank 

standard, is not sufficient as currently drafted and should not be approved as a mandatory 

reliability standard until NERC and the Regional Entities develop the necessary 

methodologies and the Commission approves them. 

1160. TANC supports replacing the term regional reliability organization with an entity 

from the NERC Functional Model. 
Docket No. RM06-16-000 - 316 - 

ii. Commission Determination

1161. The Commission will not approve or remand MOD-011-0 until the ERO submits 

additional information. The Commission directs the ERO to modify MOD-011-0 as 

discussed below. 

1162. We reiterate our position stated in the NOPR that the planning authority should be 

included in this Reliability Standard because the planning authority is the entity 

responsible for the coordination and integration of transmission facilities and resource 

planning, as well as one of the entities responsible for the integrity and consistency of the 

data. Therefore, we direct the ERO to add the planning authority to the applicability 

section of this Reliability Standard. 

1163. In response to concerns raised in MOD-010-0 about implementing MOD-010-0 

without the data to be collected when MOD-011-0 is modified, we direct the ERO to 

develop a Work Plan that will facilitate ongoing collection of the steady-state modeling 

and simulation data specified in MOD-011-0. 

1164. Accordingly, the Commission neither accepts nor remands MOD-011-0 until the 

ERO submits additional information. Because the regional procedures have not been 

submitted to the Commission, it is not possible to determine at this time whether MOD011-0 satisfies the statutory requirement that a proposed Reliability Standard be “just, 

reasonable, not unduly discriminatory or preferential, and in the public interest.” In the 

interim, compliance with MOD-011-0 should continue on a voluntary basis, and the 

Commission considers compliance with the Reliability Standard to be a matter of good 

utility practice. We direct the ERO to modify the Reliability Standard through the 

Reliability Standards development process to expand the applicability section to include 

the planning authority. Additionally, we direct the ERO to develop a Work Plan and 

submit a compliance filing that will facilitate ongoing collection of the steady-state 

modeling and simulation data specified in MOD-011-0. 

n. Dynamics Data for Modeling and Simulation of the 

Interconnected Transmission System (MOD-012-0)

1165. The purpose of MOD-012-0 is to establish consistent data requirements, reporting 

procedures and system models for use in 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 other specified 

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

1166. In the NOPR, the Commission proposed to approve Reliability Standard MOD012-0 as mandatory and enforceable. In addition, the Commission proposed to direct 

NERC to 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 

dynamics system modeling analysis for system operation and planning and (2) expands 

the applicability section to include the planning authority. 

i. Comments

1167. APPA and PG&E agree that the Commission should approve MOD-012-0 as a 

mandatory and enforceable Reliability Standard. However, PG&E requests the 

Commission to approve this standard without any modifications. In addition, APPA 

states that the Commission’s proposed directives to NERC to revise this standard are 

unduly prescriptive, and may not in fact be the best way to revise the standard. APPA 

notes that NERC, as the technical expert body charged with developing standards, is the 

entity best suited to hear all of these concerns, and to develop a consensus standard using 

its Reliability Standards development process. 

1168. ISO/RTO Council and ISO-NE disagree with the Commission’s proposal to 

approve this standard, and state that the MOD-012-0 requirements refer several times to 

the “data requirements and reporting procedures of MOD-013-0,” which has been 

identified by the Commission as a fill-in-the-blank standard, and is pending. 

Consequently, they argue that MOD-012-0 cannot be effectively implemented, and 

responsible entities should therefore not be subject to compliance with an incomplete 

standard. 

1169. With respect to the Commission’s proposal for adding a new requirement to this 

standard, FirstEnergy notes that it is appropriate for the Commission to require 

transmission owners to provide the list of faults or disturbances used in performing 

dynamics system studies. However, FirstEnergy cautions that such requirement should 

accommodate various electronic formats that are commonly used in industry simulation 

tools. FirstEnergy states that compliance with this provision should not require 

transmission owners to replace existing computer and/or software systems, and that the 

new standard should also require the regional reliability organizations (or Regional 

Entities) to coordinate the lists of faults or disturbances across wide-areas. 

1170. MidAmerican agrees that requiring transmission owners to provide a list of faults 

or disturbances to neighboring systems would provide for additional coordination 

between neighboring utilities, and therefore, would be an improvement to the standard. 
Docket No. RM06-16-000 - 318 - 

However, MidAmerican warns that a list of faults and disturbances could be used in a 

“cook-book” manner to reach the wrong conclusions.353 

1171. Northern Indiana and MidAmerican note that such a list of faults and disturbances 

should be considered a particularly sensitive form of CEII since it would be a list of 

events that, when they occur, cause critical problems on the system. Northern Indiana 

and MidAmerican request the Commission to protect sensitive information through the 

NERC administrative process discussed in the TOP-005-1 Reliability Standard. 

1172. Xcel raises the same concern it stated about MOD-010-0 that the proposed 

modification related to a list of faults and disturbances is unduly burdensome and would 

not prove useful to neighboring systems. Xcel states that no such lists are currently 

developed or maintained today, but that the faults and disturbances are reflected in the 

computerized models used by transmission providers for both transmission planning and 

operations, which are regularly updated as new facilities are installed. Xcel cautions that 

the lists, as proposed by the Commission, would be so long and subject to constant 

change that they would not only be burdensome to develop and maintain, but also 

unlikely to provide usable information for other transmission owners. 

1173. PG&E disagrees with the Commission’s proposal related to lists of faults and 

disturbances, and repeats its comments from MOD-010-0 that this new requirement is 

unnecessary. 

1174. Regarding the functional entities to which this standard applies, APPA notes that 

the transmission operator and transmission planner, as functions required to provide 

information regarding stability studies, should be added to the list of applicable entities, 

while transmission owners should be removed from such list. Under the NERC 

 353 MidAmerican further discusses that the Commission should recognize that 

caution must be taken in assuming that no other faults and disturbances exist that must be 

studied under other conditions. MidAmerican states that like with MOD-010-0, ahead of 

time, there is no way to be sure exactly which faults and disturbances are the worst under 

given operating conditions. A single reliability standard cannot contain all the 

coordination needed to allow each system operator to fully understand all the reliability 

challenges of a neighboring system. Perhaps a better approach is to continue the joint 

operational and long-term planning that is currently being conducted by planning 

authorities, reliability coordinators and other regional entities with transmission planners, 

transmission owners and others to ensure that the interconnected network is operated and 

planned in a coordinated way. 
Docket No. RM06-16-000 - 319 - 

Functional Model, transmission owners do not perform any studies related to MOD-012-

0. Rather, a transmission owner merely owns transmission facilities and maintains them. 

1175. California Cogeneration states that this standard raises concerns about data 

collection and the cost of compliance, and therefore a mechanism for determining no 

material impact and a provision for exemption is essential for this standard. California 

Cogeneration also believes that it is unclear what data is included in “dynamics system 

modeling and simulation data,” and whether independent generators would have such 

data. 

ii. Commission Determination

1176. The Commission approves MOD-012-0 as mandatory and enforceable. The 

Commission directs the ERO to modify MOD-012-0 as discussed below. 

1177. As an initial matter, the Commission disagrees that MOD-012-0 cannot be 

implemented until MOD-013-1 is modified. We have directed that data collection and 

reporting procedures not be interrupted while MOD-013-1 is being revised, therefore it is 

possible to implement MOD-012-0. Failure to provide the data needed for dynamics 

system modeling and simulation would halt regional reliability assessment processes and 

impede planners from accurately predicting future system conditions, which would be 

detrimental to system reliability. We therefore 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 Entities the information related to data gathering, data maintenance, 

reliability assessments and other process type functions. As we will discuss in the next 

section on MOD-013-1, we require the ERO to develop a Work Plan and submit a 

compliance filing that will facilitate ongoing collection of the dynamics system modeling 

and simulation data specified by the deferred MOD-013-1 Reliability Standard, which is 

necessary for implementation of MOD-012-0. 

1178. Supported by several commenters, we adopt the NOPR proposal and direct the 

ERO to modify MOD-012-0 by adding a new requirement to provide a list of the faults 

and disturbances used in performing dynamics system studies for system operation and 

planning. We believe that access to such information will enable planners to accurately 

study the effects of disturbances occurring in neighboring systems on their own systems, 

which will benefit reliability. This requirement will also make transmission planning 

data more transparent, consistent with Order No. 890, which calls for greater openness of 

the transmission planning process on a regional basis. 

1179. In response to MidAmerican’s concern that fault and disturbance information 

could be used as a “cook-book,” our expectation is that utility planners who use this data 

have sufficient experience to use it and interpret the results correctly. We expect that 
Docket No. RM06-16-000 - 320 - 

most utility planners are already familiar with their neighbors’ system topologies, and 

will be capable of identifying facilities on fault and disturbance lists. 

1180. We agree with FirstEnergy’s concerns regarding the importance of using existing 

data collection systems so as to not impose any additional costs on entities. They may 

file the fault and disturbance information in the electronic format in which they were 

created, along with any necessary decoding instructions. Compliance with this provision 

should not require transmission planners to replace existing computer and/or software 

systems. Therefore, we disagree with PG&E and Xcel that this standard modification 

will be unduly burdensome. 

1181. Consistent with California Cogeneration, Northern Indiana and MidAmerican’s 

concerns, we determine that the data that a company considers confidential, marketsensitive or security-sensitive should be released in accordance with the CEII process or 

subject to confidentiality agreements. We direct the ERO to address confidentiality 

issues and modify the standard as necessary through its Reliability Standards 

development process. 

1182. We disagree with commenters that generators or small entities that do not have a 

material impact on grid reliability should be automatically exempt from providing the 

data required by this Reliability Standard. The Commission believes that all entities that 

are required to register under the registration process that we have approved must provide 

data requested by the ERO or the Regional Entity. 

1183. We agree with APPA that the functional entity responsible for providing the fault 

and disturbance list should be the transmission planner, instead of the transmission 

owner, as proposed in the NOPR. We also agree with APPA that the transmission 

operator should be added to the list of applicable entities in the Reliability Standards 

development process. Therefore, we direct the ERO to modify MOD-012-0 to require 

the transmission planner to provide fault and disturbance lists. 

1184. We adopt our NOPR proposal that planning authorities should be included in this 

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. We therefore 

direct the ERO to add the planning authority to the list of applicable entities. 

1185. Accordingly, the Commission approves MOD-012-0 as mandatory and 

enforceable. In addition, the Commission directs the ERO to develop a modification to 

MOD-012-0 through the Reliability Standards development process that: (1) adds a new 

requirement for transmission planners to provide the list of faults and disturbances they 
Docket No. RM06-16-000 - 321 - 

use in performing dynamic stability analysis in the electronic format in which they were 

created, along with any necessary decoding instructions and (2) expands the applicability 

section to include transmission operators, planning authorities and transmission planners. 

We expect the ERO to address confidentiality issues and modify the Reliability Standard 

as necessary through the Reliability Standards development process. 

o. Maintenance and Distribution of Dynamics Data 

Requirements and Reporting Procedures (MOD-013-1)

1186. 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 

Interconnection. More specifically, the regional reliability organization, in coordination 

with its transmission owners, transmission planners, generator owners and resource 

planners within an Interconnection, is required to: (1) participate in development of 

documentation for their Interconnection data requirements and reporting procedures; (2) 

participate in the review of those data requirements and reporting procedures at least 

every five years and (3) make the data requirements and reporting procedures available to 

NERC and other specified entities upon request. 

1187. In the NOPR, the Commission identified MOD-013-1 as a fill-in-the-blank 

standard that requires each regional reliability organization within an Interconnection to 

develop comprehensive dynamics data requirements and reporting procedures needed to 

model and analyze the dynamic behavior and response for each of the three NERC 

Interconnections. The NOPR stated that because the regional methodologies had not 

been submitted, the Commission would not propose to approve or remand MOD-013-1 

until the ERO submits additional information. In addition, in the NOPR we agreed that 

the Reliability Standard should apply to the planning authority. 

1188. In the NOPR, the Commission expressed a concern regarding the 1990 cut-off 

date,354 and shared PG&E’s concern 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 requested comment whether it is reasonable to permit entities to 

estimate dynamics data if they are unable to obtain unit specific data for any reason. The 

Commission believes that to achieve the goal of this Reliability Standard of having the 

ability to accurately model and analyze the dynamic behavior and response of each 

Interconnection, it is necessary to have accurate data. Inaccurate data can lead to 

 354 Requirement R1.1.1 allows for the use of estimated or typical manufacturer’s 

data on pre-1990 units to model dynamic behavior when unit-specific data is unavailable. 
Docket No. RM06-16-000 - 322 - 

unrealistic simulations and inappropriate actions by responsible entities which may 

jeopardize the reliability of the Bulk-Power System. 

i. Comments

1189. APPA agrees with the Commission that MOD-013-1 is a fill-in-the-blank 

standard, is not sufficient as currently drafted, and should not be approved as a mandatory 

Reliability Standard until NERC and the regional reliability organizations/Regional 

Entities develop the necessary regional methodologies and the Commission approves 

them. 

1190. In response to the Commission’s request for comments on whether it is reasonable 

to permit entities to estimate dynamics data if they are unable to obtain unit specific data 

for any reason, many commenters responded that it is reasonable to allow estimation of 

dynamics data for older units where data is not available.355 The Small Entities Forum 

expects that the Reliability Standard ultimately will include requirements that such 

estimates be based on sound engineering principles and be subject to technical review 

and approval of any estimates at the regional level. 

1191. MidAmerican explains that there may be safety or system conditions and/or the 

loss of records that do not permit gathering unit-specific information, and that in such 

cases, computations and engineering reports of estimated capability should be sufficient. 

MidAmerican also requests that if there is a farm of similar generation units (such as 

wind turbines) or synchronous condensers located in the same general area, providing 

unit-specific information for a number of identical units is not necessary. Instead, 

MidAmerican proposes that information about a sample of the identical units (such as 

two) should be sufficient to provide enough unit-specific information to be representative 

of the farm. MidAmerican also notes that if units are located in a part of the system that 

does not typically demonstrate instability, the value of unit-specific data is reduced, and 

that there are a number of such circumstances in which provision of unit-specific data 

should not be required. 

1192. International Transmission, stating that the age of the unit alone may not be the 

only reason why unit-specific data might be unavailable, cautions that there should be a 

requirement in every case that unit data actually be sought for all generating units before 

estimates of dynamics data are used. International Transmission believes that achieving 

the most accurate possible picture of the dynamic behavior of the Interconnection 

 355 EEI, LPPC, MidAmerican, Small Entities Forum and TVA. 
Docket No. RM06-16-000 - 323 - 

requires the use of actual data, and that, at a minimum, entities should be required to 

document the steps taken to obtain unit-specific data. 

1193. APPA, however, expresses its concern regarding the difficulties in obtaining 

accurate unit-specific data to model dynamic behavior. APPA recommends to NERC 

that the regional reliability organizations/Regional Entities and the reliability 

coordinators review this type of data on a case-by-case basis to test it for accuracy and to 

determine whether estimated data will produce outputs from the models within 

acceptable limits. International Transmission confirms that testing is easily 

accomplished, and provides up-to-date dynamics data reflective of the natural 

degradation of generating units over their lifetimes. However, International Transmission 

says that this effort could be tied to the Generator Model Validation Reliability Standards 

(MOD-024-1 and MOD-025-1). 

1194. TANC agrees with the Commission that the standard requirement is arbitrary in 

imposing the 1990 cut-off with regard to modeling dynamic behavior. TANC believes 

that this requirement allows for the use of estimated or typical manufacturer's data on 

pre-1990 units to model dynamic behavior when unit-specific data is unavailable. TANC 

notes that difficulty in obtaining unit specific data is not limited to the age of the unit but 

also unit configuration. TANC therefore recommends that the 1990 cut-off be removed 

from the proposed Reliability Standard because there is no justifiable basis for the 

arbitrary cut-off and that the Reliability Standard be revised to allow the generallyaccepted use of estimated or typical manufacturer data where unit-specific data is 

impractical to obtain. TVA agrees that the 1990 cut-off date is unnecessary. 

1195. In contrast to those who support rejecting the 1990 cut-off requirement, 

FirstEnergy states that unit-specific data should be required for all units installed after 

1990. EEI confirms that unit-specific information should be available for most units 

placed in service since 1990. 

ii. Commission Determination

1196. The Commission will not approve or remand MOD-013-1 until the ERO submits 

additional information. The Commission directs the ERO to modify MOD-013-1 through 

the Reliability Standards development process as discussed below. 

1197. We agree with many commenters and direct the ERO to modify the Reliability 

Standard to permit entities to estimate dynamics data if they are unable to obtain unitspecific data for any reason, not just for units constructed prior to 1990. Achieving the 

most accurate possible picture of the dynamic behavior of the Interconnection requires 

the use of actual data. We disagree with FirstEnergy and EEI and reject the 1990 cut-off 

date, because the age of the unit alone may not be the only reason why unit-specific data 
Docket No. RM06-16-000 - 324 - 

is unavailable. We agree with the Small Entities Forum that the Reliability Standard 

should include Requirements that such estimates be based on sound engineering 

principles and be subject to technical review and approval of any estimates at the regional 

level. That said, the Commission directs that this Reliability Standard be modified to 

require that the results of these dynamics models be compared with actual disturbance 

data to verify the accuracy of the models. 

1198. With respect to small units installed in wind farms, we agree with MidAmerican 

that data for one unit to represent all identical units at wind farms is acceptable. The 

Commission understands that this is the current approach with any generator that is 

manufactured in quantity such as multiple generators used in combined cycle plants. 

1199. We adopt our NOPR proposal and direct the ERO to expand the applicability 

section in this Reliability Standard to include planning authorities because they are the 

entities 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. 

1200. Accordingly, the Commission neither accepts nor remands MOD-013-1 until the 

ERO submits additional information. Because the regional procedures have not been 

submitted to the Commission, it is not possible to determine at this time whether MOD013-1 satisfies the statutory requirement that a proposed Reliability Standard be “just, 

reasonable, not unduly discriminatory or preferential, and in the public interest.” In the 

interim, compliance with MOD-013-1 should continue on a voluntary basis, and the 

Commission considers compliance with the Reliability Standard to be a matter of good 

utility practice. Although the Commission does not approve or remand MOD-013-1, we 

direct the ERO to modify it through the Reliability Standards development process to: 

(1) permit entities to estimate dynamics data if they are unable to obtain unit specific data 

for any reason; (2) require verification of the dynamic models with actual disturbance 

data and (3) expand the applicability section to include the planning authority, 

transmission operator and transmission planner. As discussed above in MOD-012-0, we 

direct the ERO to develop a Work Plan that will facilitate ongoing collection of the 

dynamics system modeling and simulation data specified in MOD-013-1, and submit a 

compliance filing containing this Work Plan to the Commission. 

p. Development of Steady-State System Models (MOD-014-

0)

1201. MOD-014-0 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 
Docket No. RM06-16-000 - 325 - 

long-term planning horizons representing system conditions for various demand levels. 

The models are to be updated annually. 

1202. In the NOPR, the Commission identified MOD-014-0 as a fill-in-the-blank 

standard that requires the regional reliability organizations within an Interconnection to 

develop, coordinate and maintain a library of solved Interconnection-specific steady-state 

models. The NOPR stated that because the regional procedures had not been submitted, 

the Commission would not propose to approve or remand MOD-014-0 until the ERO 

submits the additional information. In addition, in the NOPR the Commission stated its 

belief that the Reliability Standard should be modified to include a requirement to verify 

that steady-state models are accurate. 

1203. In the NOPR, the Commission expressed concern 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 MOD014-0. The NOPR suggested that the Reliability Standard contain a requirement 

specifying the time period and planning years be identical to those found in FERC Form 

715.356 Further, the Commission requested comments on any incompatibility between 

requirements under FERC Form 715 and MOD-014-0. 

i. Comments

1204. APPA agrees with the Commission that MOD-014-0, a fill-in-the-blank standard, 

is not sufficient as currently drafted, and should not be approved as a mandatory 

Reliability Standard until NERC and the regional reliability organizations/Regional 

Entities develop the necessary regional methodologies and the Commission approves 

them. 

1205. NRC suggests that a periodic verification against field data needs to be included in 

this Reliability Standard. 

1206. Regarding the Commission’s request for comments on any incompatibility 

between requirements under FERC Form 715 and MOD-014-0, International 

Transmission states that the language in MOD-014-0 would allow the regional reliability 

organization and the transmission owner to develop separate base cases. International 

Transmission notes that its experience with current practice suggests, however, that this is 

not a significant concern. Transmission owners now develop the information for 

 356 FERC Form 715 is available at http://www.ferc.gov/docs-filing/ 

eforms.asp#715. 
Docket No. RM06-16-000 - 326 - 

inclusion in a regional base case, and the regional base case is rolled up into a FERC 

Form 715 filing by a regional entity. International Transmission expects that this process 

would continue in the future. 

1207. MISO believes that FERC should revisit the need for transmission owners to have 

base case information available for replication. MISO states that the current 

Interconnection trend is for transmission owners to work together more closely in 

developing large assessments based on a large model, and that these large assessments 

are better guides to the overall capability of the transmission grid to move power. MISO 

believes that these assessments should be filed as part of FERC Form 715. 

1208. Although Northern Indiana does not see any duplication or incompatibility with 

FERC Form 715, Northern Indiana is concerned that the proposed Reliability Standard 

envisions the use of steady-state models and benchmarking for long-term planning. 

Northern Indiana believes that benchmarking of planning models should be directed 

towards validation of line constraints and general comparison of modeled to actual load 

levels. Northern Indiana suggests that this could be accomplished through validation 

processes that would first evaluate the data used to model the transformers and the lines 

and determine that such data is correct, and then compare the loads in total against the 

actual loads, followed by an examination of individual load points on a system. 

ii. Commission Determination

1209. The Commission will not approve or remand MOD-014-0 until the ERO submits 

additional information. 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.” The Commission 

directs the ERO to modify MOD-014-0 as discussed below. 

1210. We maintain our position set forth in the NOPR that analysis of the 

Interconnection system behavior requires the use of accurate steady-state models. 

Therefore, we direct the ERO to modify the Reliability Standard to include a requirement 

that the models be validated against actual system responses. We understand that NERC 

is incorporating recommendations from the Blackout Report357 and developing models 

for the Eastern Interconnection. 

 357 Recommendation Number 24 of the Blackout Report at 160. 
Docket No. RM06-16-000 - 327 - 

1211. Further, the maximum discrepancy between the model results and the actual 

system response should be specified in the Reliability Standard. The Commission 

believes that the maximum discrepancy between the actual system performance and the 

model should be small enough that decisions made by planning entities based on output 

from the model would be consistent with the decisions of operating entities based on 

actual system response. We direct the ERO to modify MOD-014-0 through the 

Reliability Standards development process to require that actual system events be 

simulated and if the model output is not within the accuracy required, the model shall be 

modified to achieve the necessary accuracy. 

1212. We believe that steady-state model validation should not be interrupted while 

MOD-014-0 is being modified. The lack of accurate models needed for the simulations 

would halt regional reliability assessment processes and hinder planners from accurately 

predicting future system conditions, which would be detrimental to system reliability. 

We therefore direct the ERO to use its authority pursuant to § 39.2(d) of our regulations 

to require users, owners and operators to provide the validated models to regional 

reliability organizations. We direct the ERO to develop a Work Plan that will facilitate 

ongoing validation of steady-state models and submit a compliance filing containing the 

Work Plan with the Commission. 

1213. Consistent with many commenters’ responses, we find changes to FERC Form 

715 are not necessary at this time, because there is no conflict between data gathering and 

model construction with the FERC Form 715 process. 

1214. The Commission neither accepts nor remands MOD-014-0. 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.” In the interim, compliance with MOD-014-0 should continue on a 

voluntary basis, and the Commission considers compliance with the Reliability Standard 

to be a matter of good utility practice. We direct the ERO to: (1) modify the Reliability 

Standard through the Reliability Standards development process to require actual system 

events be simulated and model output validated against actual system responses and (2) 

develop a Work Plan and submit a compliance filing that will enable validation of the 

steady-state models while MOD-014-0 is being modified. 

q. Development of Dynamics System Models (MOD-015-0)

1215. MOD-015-0 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 dynamics system models. 
Docket No. RM06-16-000 - 328 - 

These models represent near-term years and the years chosen from the longer-term 

planning horizon. 

1216. In the NOPR, the Commission identified MOD-015-0 as a fill-in-the-blank 

standard that requires the regional reliability organizations within an Interconnection to 

develop, coordinate and maintain a library of initialized Interconnection-specific 

dynamics system models. The NOPR stated that because the regional procedures had not 

been submitted, the Commission would not propose to approve or remand MOD-015-0 

until the ERO submits the additional information. In addition, the Commission stated 

that MOD-015-0 should include a requirement to verify accuracy of dynamics system 

models. 

i. Comments

1217. APPA agrees that MOD-015-0 is a fill-in-the-blank standard, is not sufficient as 

currently drafted and should not be approved as a mandatory reliability standard until 

NERC and the regional reliability organizations/Regional Entities develop the necessary 

regional methodologies and the Commission approves them. 

1218. EEI agrees with the Commission’s proposal that a new requirement for 

verification of the accuracy of dynamics system models should be a part of this 

Reliability Standard. In addition, EEI states that the validation of models is a valid 

concern, but that any requirement in this area should be carefully considered, and that any 

requirement should be related to using the models to replicate events that occur on the 

system instead of developing separate testing procedures to verify the models. EEI 

believes that it would not be reasonable to subject generation units to artificial 

disturbances to validate the models. NRC recommends periodic verification against field 

data. APPA notes that if NERC modifies MOD-015-0 as APPA anticipates, a 

requirement to verify the accuracy of the dynamics system model would be included and 

the Regional Entity would be the compliance monitor. 

ii. Commission Determination

1219. The Commission will not approve or remand MOD-015-0 until the ERO submits 

additional information. Because the 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.” The Commission 

directs the ERO to modify MOD-015-0 through the Reliability Standards development 

process as discussed below. 
Docket No. RM06-16-000 - 329 - 

1220. We maintain our position set forth in the NOPR that the analysis of 

Interconnection system behavior requires the use of accurate dynamics system models. 

Therefore, we direct the ERO to modify the Reliability Standard to include a requirement 

that the models be validated against actual system responses. We agree with EEI and 

NRC and confirm our position that a requirement to verify that dynamics system models 

are accurate should be a part of this Reliability Standard. We agree with EEI that this 

new requirement should be related to using the models to replicate events that occur on 

the system instead of developing separate testing procedures to verify the models. We 

direct the ERO to modify the standard to require actual system events be simulated and 

dynamics system model output be validated against actual system responses. 

1221. We believe that dynamics system model validation should not be interrupted while 

MOD-015-0 is in the modification process. The lack of accurate models needed for the 

simulations would halt regional reliability assessment processes and hinder planners from 

accurately predicting future system conditions, which would be detrimental to system 

reliability. We therefore 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 Entity the 

validated dynamics system models while MOD-015-0 is being modified. We require the 

ERO to develop a Work Plan that will enable continual validation of dynamics system 

models and submit a compliance filing with the Commission. 

1222. The Commission neither accepts nor remands MOD-015-0 until the ERO submits 

additional information. Because the 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.” 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. 

We direct the ERO to: (1) modify the Reliability Standard through the Reliability 

Standards development process to require verification of the accuracy of dynamics 

system models and (2) develop a Work Plan and submit a compliance filing that will 

facilitate ongoing verification of the accuracy of dynamics system models while MOD015-0 is being modified. 

r. Documentation of Data Reporting Requirements for 

Actual and Forecast Demands, Net Energy for Load and

Controllable Demand-Side Management (MOD-016-1)

1223. The purpose of MOD-016-1 is to ensure that past and forecasted demand data is 

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 
Docket No. RM06-16-000 - 330 - 

load data, and controllable DSM data to be reported for system modeling and reliability 

analysis. 

1224. In the NOPR, the Commission proposed to approve Reliability Standard MOD016-1 as mandatory and enforceable. In addition, the Commission proposed to direct 

NERC to submit a modification to MOD-016-1 that expands the applicability section to 

include the transmission planner. 

i. Comments

1225. APPA agrees that MOD-016-1 is sufficient for approval as a mandatory and 

enforceable reliability standard. 

1226. In contrast, ISO/RTO Council and ISO-NE do not support adoption of this 

standard because it is contingent on standards that are pending approval by the 

Commission based on their characterization as applying only to regional reliability 

organizations, or because they have been categorized as fill-in-the-blank standards. 358 

ISO/RTO Council and ISO-NE agree that as a result, MOD-016-1 cannot be effectively 

implemented. 

1227. APPA and FirstEnergy agree with the Commission’s proposal to direct NERC to 

add the transmission planner function to the applicability section of the standard, 

although they argue that NERC, as the standards-setting entity, should make the decision. 

1228. TAPS does not oppose the proposed applicability of MOD-016-1, but opposes 

regional interpretations that apply the standard more broadly. TAPS criticizes SERC’s 

supplement to MOD-016-1 that makes the standard applicable to LSEs, even though 

LSEs do not have the ability to identify the scope and details of the data required to be 

reported for system modeling and reliability analyses. TAPS contends that there are no 

physical differences that make SERC LSEs more capable in this regard than LSEs in 

other regions. TAPS recommends that the Commission clarify that it expects standards 

to be applied in a consistent and uniform manner as written, and will look closely at 

regional variations not justified by physical differences. 

1229. In contrast to APPA, FirstEnergy and TAPS, EEI believes that the standard 

assigns appropriate responsibility, and that the transmission planner should not be added 

to the applicability section of this standard. According to EEI, the transmission planner 

 358 TPL-005-0, TPL-006-0, MOD-011-0, MOD-013-0, MOD-014-0 and MOD015-0. 
Docket No. RM06-16-000 - 331 - 

has no specific responsibilities for ensuring data integrity in day-to-day practice. EEI 

understands that data integrity falls within the daily responsibilities of data management 

functions, such as metering. EEI states that the NERC Functional Model does not 

describe technical functions at this level of detail. EEI notes, as it also notes in its 

comments on the TPL standards, that load-related DSM data of the type and specificity 

stated in the NOPR, such as load control of customer-owned appliances, is related to 

distribution system and operations planning, and not to transmission system planning. 

ii. Commission Determination

1230. The Commission approves MOD-016-1 as mandatory and enforceable. In 

addition, the Commission directs the ERO to modify MOD-016-1 as discussed below. 

1231. As an initial matter, we disagree that MOD-016-1 cannot be implemented until 

other unapproved standards are modified. As previously stated, we are requiring the 

ERO to provide a Work Plan and compliance filing regarding collection of information 

specified under standards that are deferred, and believe there should be no difficulties 

complying with this Reliability Standard. We reiterate that continual collection of data is 

necessary to maintain system reliability, and approval of MOD-016-1 will help to achieve 

this objective. 

1232. Supported by many commenters, the Commission directs the ERO to modify 

MOD-016-1 and expand the applicability section to include the transmission planner, on 

the basis that under the NERC Functional Model the transmission planner is responsible 

for collecting system modeling data, including actual and forecast load, to evaluate 

transmission expansion plans. We disagree with EEI that this Reliability Standard should 

not be applied to the transmission planner because load-related data for controllable DSM 

is not only needed for distribution and transmission operations, but is also necessary for 

the transmission planner to take controllable DSM into account in planning the 

transmission system. Requirement R1.1 relates to data submittal, and requires data to be 

consistent with that supplied for the TPL-005 and TPL-006 standards, which clearly 

apply to transmission planners. We approve the ERO’s definition in the glossary of DSM 

as “all activities or programs undertaken by a Load-Serving Entity or its customers to 

influence the amount or timing of electricity they use.” Only activities or programs that 

meet the ERO definition, with the modification directed below, may be treated as DSM 

for purposes of the Reliability Standards. Recognizing the potential role that industrial 

customers who do not take service through an LSE and load aggregators, for example, 

may play in meeting the Reliability Standards, we direct the ERO to modify the 

definition of DSM. Specifically, we direct the ERO to add to its definition of DSM “any 

other entities” that undertake activities or programs to influence the amount or timing of 

electricity they use without violating other Reliability Standard Requirement. 
Docket No. RM06-16-000 - 332 - 

1233. In response to TAPS’s criticism of SERC’s desire to expand its regional standards 

relative to actual and forecast load to include LSEs, we clarify that we can only act on the 

standards before us. We do not make a decision on SERC’s standards in this rule. We 

therefore recommend that TAPS raise this issue in the Reliability Standards development 

process. 

1234. The Commission approves Reliability Standard MOD-016-1 as mandatory and 

enforceable and directs the ERO to develop a modification to MOD-016-0 through the 

Reliability Standards development process to include the transmission planner in the 

applicability section. 

s. Aggregated Actual and Forecast Demands and Net 

Energy for Load (MOD-017-0)

1235. The purpose of MOD-017-0 is to ensure that past and forecasted demand data is 

available for past event validation and future system assessment. MOD-017-0 requires 

LSEs, 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 

forecasts and net load energy for the next two years and (4) annual peak demand 

forecasts (summer and winter) and annual net load energy for at least five and up to ten 

years into the future. 

1236. In the NOPR, the Commission proposed to approve Reliability Standard MOD017-0 as mandatory and enforceable. In addition, the Commission proposed to direct 

NERC to submit a modification to MOD-017-0 that includes new requirements for: (1) 

reporting of temperature and humidity along with peak loads and (2) reporting of the 

accuracy, error and bias of load forecasts compared to actual loads while taking 

temperature and humidity variations into account. 

i. Comments

1237. APPA agrees that the Commission should approve MOD-017-0 as mandatory 

and enforceable. 

1238. In contrast to APPA, ISO-NE does not support approval of this standard because 

MOD-017-0 depends on MOD-016-0, which further depends on various unapproved 

standards. ISO-NE believes that this makes MOD-017-0 dependent on unapproved 

standards, and that consequently, MOD-017-0 cannot be effectively implemented. 

Similarly, ISO/RTO Council states that if the Commission does not approve MOD-016-0, 

then MOD-017-0 will refer to an unapproved standard. 
Docket No. RM06-16-000 - 333 - 

1239. Although MidAmerican does not oppose the Commission’s proposal regarding 

reporting of temperature and humidity along with peak loads, it finds it of only limited 

value. MidAmerican notes that there are typically other explanatory variables, such as 

economic variables, that are needed to understand the relationship between system load 

and temperature and humidity. In addition, the relationship and the importance of 

temperatures are different for every utility, which limits the effectiveness of 

standardization. FirstEnergy suggests that NERC should allow for a transition period for 

entities that currently do not track temperature and humidity along with peak load. 

1240. Xcel states that in many areas of the country, humidity is not a weather-indicator 

for peak load. Xcel therefore suggests that instead of including a reporting requirement 

for humidity, the standard be revised to include a more generic term, such as “peak 

producing weather conditions.” Alcoa requests that the Commission clarify that these 

requirements would only apply to load that varies with temperature and humidity.359

1241. Regarding the Commission’s proposal for reporting of the accuracy, error and bias 

of load forecasts compared to actual loads while taking temperature and humidity 

variations into account, APPA disagrees that the Commission should direct NERC to 

modify MOD-017-0 to include these requirements. APPA argues that requiring the type 

and granularity of forecast information and data the Commission proposes would not 

necessarily increase the reliability of load forecasts. APPA believes that it should be up 

to NERC, as the expert standards-setting entity, to decide whether such information 

would yield enough useful data to make it worth mandating. 

1242. TAPS is concerned that the NOPR’s recommendation for reporting the accuracy, 

error and bias of load forecasts compared to actual loads may be interpreted to mean that 

measuring compliance is a function of forecast accuracy. TAPS contends that reliance on 

percentage-based deviations as a measurement of compliance is inappropriate when 

applied to very small entities because an error that in absolute terms is too small to affect 

the Bulk-Power System might be a significant percentage of the entity’s load. 

1243. EEI notes that the direction of the NOPR proposal seems to suggest an expansion 

of the current reporting processes required under the Energy Information Administration 

section 411 process. EEI suggests that such a proposal should consider whether the 

section 411 process itself requires change or provides for an adequate level of reporting, 

 359 Alcoa states that because its smelting load (the vast majority of its load) does 

not vary in accordance with temperature and humidity, comparing Alcoa's load forecasts 

to actual loads taking this information into account would be burdensome without being 

useful. 
Docket No. RM06-16-000 - 334 - 

and the extent to which an explicit NERC process requirement could distract or confuse 

industry participants. 

1244. FirstEnergy states that the transmission planner should be added to the list of 

applicable entities for this standard. FirstEnergy also states that it may be reasonable to 

interpret or apply this Reliability Standard in a manner to permit an affected entity that is 

a subsidiary in a utility holding company corporate structure to satisfy its reporting 

requirements by means of a corporate affiliate. Adopting this interpretation or 

application would promote efficiency and decrease confusion in circumstances where 

several utility subsidiaries in the same corporate family are subject to this Reliability 

Standard. 

1245. MISO recommends that the Commission direct NERC to change the requirement 

of this standard so that aggregated actual hourly demand data (at the balancing authority 

level) are to be provided within 30 calendar days of a request from NERC. MISO 

believes that load aggregated at this level should be sufficient for the modeling activities 

associated with system reliability. MISO understands that hourly data is collected by 

those utilities that have balancing authority responsibilities, and that these utilities can 

report aggregated hourly loads for their responsibility area within 30 days. MISO notes 

that some balancing authority utilities provide energy services to smaller municipal or 

distribution cooperative utilities where the metering system records only the peak 

demand and total energy supplied over approximately 30 days. MISO cautions that the 

balancing authority will usually have hourly data for demand and energy within a 

segment of the network, but may have no hourly metering on a specific customer served 

by that segment. 

ii. Commission Determination

1246. The Commission approves MOD-017-0 as mandatory and enforceable. In 

addition, the Commission directs the ERO to modify MOD-017-0 as discussed below. 

1247. As an initial matter, we disagree that MOD-017-0 cannot be implemented because 

it is dependent on MOD-016-0, which further depends on various unapproved standards. 

As previously stated, we direct the ERO to provide a Work Plan and compliance filing 

regarding the collection of information specified under standards that are deferred, and 

believe there should be no difficulty complying with this Reliability Standard. We 

reiterate that ongoing collection of data is necessary to maintain system reliability, and 

approval of MOD-017-0 will help achieve this goal. 
Docket No. RM06-16-000 - 335 - 

1248. As a general matter, the Commission is required to insure that the Reliability 

Standards are sufficient to adequately protect Bulk-Power System reliability.360 One of 

the main drivers in achieving Reliable Operation is to accurately predict the firm 

transactions and native load that must be served. Understanding the accuracy, error and 

bias of the forecast and taking action to minimize them would improve the Reliability 

Standards and achieve the goal. 

1249. The Commission also directs the ERO to modify the Reliability Standad to require 

reporting of temperature and humidity along with peak load because actual load must be 

weather normalized for meaningful comparison with forecasted values.361 In response to 

MidAmerican’s observation that it sees little value in collecting this data, we believe that 

collecting it will allow all load data to be weather-normalized, which will provide greater 

confidence when comparing data accuracy, which ultimately will enhance reliability. As 

a result, we reject Xcel’s proposal that the standard be revised to include only the generic 

term “peak producing weather conditions” because it is too generic for a mandatory 

Reliability Standard. 

1250. We also reject Alcoa’s proposal that the reporting of temperature and humidity 

along with peak loads should apply only to load that varies with temperature and 

humidity because it essentially is a request for an exemption from the requirements of the 

Reliability Standard and should therefore be directed to the ERO as part of the Reliability 

Standards development process. We agree, however, with APPA that certain types of 

load are not sensitive to temperature and humidity. We therefore find that the ERO 

should address Alcoa’s concerns in its Reliability Standards development process. 

1251. The Commission adopts the NOPR proposal directing the ERO to modify the 

Reliability Standard to require reporting of the accuracy, error and bias of load forecasts 

compared to actual loads with due regard to temperature and humidity variations. This 

requirement will measure the closeness of the load forecast to the actual value. We 

understand that load forecasting is a primary factor in achieving Reliable Operation. 

Underestimating load growth can result in insufficient or inadequate generation and 

transmission facilities, causing unreliability in real-time operations. Measuring the 

accuracy, error and bias of load forecasts is important information for system planners to 

include in their studies, and also improves load forecasts themselves. 

 360 Order No. 672 at P 329. 

361 See Brattle Group Report on PJM Load Forecast Model, available at 

http://www.pjm.com/planning/res-adequacy/load-forecast.html. 
Docket No. RM06-16-000 - 336 - 

1252. The Commission agrees with APPA that accuracy, error and bias of load forecasts 

alone will not increase the reliability of load forecasts, and, as a result, will not affect 

system reliability. Understanding of the differences without action based on that 

understanding would not change anything. Therefore, we direct the ERO to add a 

Requirement that addresses correcting forecasts based on prior inaccuracies, errors and 

bias. 

1253. Regarding TAPS’s concern that accuracy of reporting may be used as a 

compliance Measure, we clarify that the compliance Measures for this Reliability 

Standard do not measure accuracy as a compliance Measure. Any change in the 

Measures would be arrived at in the Reliability Standards development process. 

1254. The Commission acknowledges EEI’s concern that a requirement for additional 

information may impose an expansion of existing Energy Information Administration 

section 411 reporting requirements.362 We believe, however, that the ERO can ensure 

that the additional reporting of temperature and humidity along with peak loads does not 

conflict with or jeopardize the Energy Information Administration section 411 reporting 

process. 

1255. We agree with FirstEnergy that transmission planners should be added as 

reporting entities, and direct the ERO to modify the standard accordingly. We agree that 

in the NERC Functional Model, the transmission planner is responsible for collecting 

system modeling data including actual and forecast demands to evaluate transmission 

expansion plans. 

1256. The Commission disagrees in general with MISO’s recommendation to allow 

some exceptions to the requirement to provide hourly demand data. However, the 

metering for some customer classes may not be designed to provide certain types of data. 

The Commission therefore directs the ERO to consider MISO’s concerns in the 

Reliability Standards development process. 

1257. The Commission approves Reliability Standard MOD-017-0 as mandatory and 

enforceable. In addition, the Commission directs the ERO to develop a modification to 

MOD-017-0 through the Reliability Standards development process that includes 

requirements for: (1) reporting of temperature and humidity along with the peak loads; 

 362 Form EIA-411, “Coordinated Bulk Power Supply Program Report” collects 

information about regional electric supply and demand projections for a five-year 

advance period as well as information on the transmission system and supporting 

facilities. See http://www.eia.doe.gov/cneaf/electricity/page/forms.html. 
Docket No. RM06-16-000 - 337 - 

(2) reporting of accuracy, error and bias of load forecasts compared to actual loads taking 

temperature and humidity variations into account; (3) addressing methods to correct 

forecasts to minimize prior inaccuracies, errors and bias and (4) including the 

transmission planner in the applicability section. 

t. Treatment of Nonmember Demand Data and 

Uncertainties in the Forecasts of Demand and Energy for 

Load (MOD-018-0)

1258. The purpose of MOD-018-0 is to ensure that past and forecasted demand data are 

available for past event validation and future system assessment. MOD-018-0 requires 

LSEs, planning authorities, transmission planners and resource planners to submit load 

data reports that: (1) indicate whether the demand data includes the regional reliability 

organization’s non-members’ demands and (2) addresses how assumptions, methods and 

uncertainties are treated. 

1259. In the NOPR, the Commission proposed to approve MOD-018-0 as mandatory and 

enforceable. 

i. Comments

1260. APPA agrees that MOD-018-0 is sufficient for approval as a mandatory and 

enforceable reliability standard. 

1261. In contrast to APPA, ISO/RTO Council and ISO-NE view MOD-018-0 as 

dependent upon fill-in-the-blank NERC standards, and as such, argue that the 

Commission should refrain from approving the Reliability Standard at this time. ISO-NE 

states that approval of this standard would create dependency of MOD-018-0 on other 

unapproved standards. Consequently, ISO-NE contends that MOD-018-0 cannot be 

effectively implemented. 

1262. TAPS reiterates a similar concern it expressed with regard to MOD-017-0. TAPS 

notes that uncertainty in a small entity’s forecast is insignificant. TAPS recommends that 

load forecast uncertainty should be addressed at an aggregate level on a regional basis (as 

is often done in the establishment of reserve obligations). 

ii. Commission Determination

1263. The Commission approves MOD-018-0 as mandatory and enforceable. 

1264. As an initial matter, we disagree that MOD-018-0 cannot be implemented because 

it is dependent on various unapproved standards. As previously stated, we direct the 
Docket No. RM06-16-000 - 338 - 

ERO to provide a Work Plan and compliance filing regarding the collection of 

information specified for standards that are deferred, and believe there should be no 

difficulties complying with this Reliability Standard. We reiterate that ongoing collection 

of data is necessary to maintain system reliability, and approval of MOD-018-0 will help 

to achieve this goal. 

1265. Regarding TAPS’s concern that small entities should not be required to comply 

with MOD-018-0 because their forecasts are not significant for system reliability 

purposes, the Commission directs the ERO to address this matter in the Reliability 

Standards development process. 

u. Reporting of Interruptible Demands and Direct Control 

Load Management (MOD-019-0) 

1266. The purpose of MOD-019-0 is to ensure that past and forecasted demand data is 

available for past event validation and future system assessment. The Reliability 

Standard requires that LSEs, 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. 

1267. In the NOPR, the Commission proposed to approve Reliability Standard MOD019-0 as mandatory and enforceable. In addition, the Commission proposed to direct 

NERC to submit a modification to MOD-019-0 that includes new requirements for 

reporting of the accuracy, error and bias of controllable load363 forecasts. 

i. Comments

1268. APPA agrees that MOD-019-0 should be approved as mandatory and enforceable. 

However, APPA states that the proper entity to decide whether the recommended 

changes to the standards should be made is NERC, through Reliability Standards 

development process. 

 363 While MOD-019-0 and MOD-020-0 use two separate terms, interruptible load 

and direct control load management, the NOPR uses “controllable load” to refer to both 

of them. 
Docket No. RM06-16-000 - 339 - 

1269. The ISO/RTO Council and ISO-NE note that MOD-019-0 is dependent, through 

MOD-016, on various unapproved standards. Consequently, they contend that MOD019-0 cannot be effectively implemented. 

1270. APPA proposes that NERC consider modifying MOD-019-0 to include new 

requirements for reporting on the accuracy, error and bias of controllable load forecasts. 

APPA further believes that NERC should consider adding requirements that would 

require resource planners to analyze differences between actual and forecasted demands 

for the five years of actual controllable load required in MOD-019-0 and identify what 

corrective actions were taken to improve controllable load forecasting for the 10-year 

planning horizon. 

1271. EEI and FirstEnergy state that determining the precise availability and capability 

of direct load control is a difficult management and customer relations exercise, and 

therefore, this requirement should not be included in the Reliability Standard. EEI states 

that, unlike other technical requirements for generation resources to be tested for various 

capabilities and limits under different types of stresses, there are no similar requirements 

for load control equipment. Elsewhere in these comments, EEI supports explicit 

recognition that load control should be recognized on the same terms as generation 

resources for setting reserve requirements. However, EEI cautions against imposing 

requirements to verify load control devices and interruptible loads, because the practical 

complexities of conducting such testing and verification, including customer notification, 

the need to plan, manage, and coordinate testing with critical commercial and industrial 

customer activities, and the need to conduct such tests at times of peak load, make this an 

extremely difficult operational challenge. 

1272. International Transmission notes that many load control applications are not 

individually metered, which means impact can only be estimated within a LSE’s service 

territory. International Transmission believes that accurate reporting may not be feasible. 

1273. TAPS raises concern that the Commission’s recommendation in the NOPR may be 

interpreted to make forecast accuracy a component of Reliability Standards compliance. 

TAPS cautions that reliance on percentage-based deviations as a measurement of 

compliance is inappropriate when applied to very small entities because an error that in 

absolute terms is too small to affect the Bulk-Power System might be a significant 

percentage of the entity’s load. The percentage deviation from a forecasted peak of a 

small (e.g., 10 MW) entity will almost always be significantly higher than the percentage 

deviation of a large (more than 10,000 MW) entity, but the smaller system’s deviation 

will have little if any impact on the bulk transmission system. In other contexts, the 

Commission has recognized that reliance solely on percentage deviations as compliance 

measures can produce discriminatory results, and has applied MW minimums to 

minimize the discrimination that would otherwise result. 
Docket No. RM06-16-000 - 340 - 

ii. Commission Determination

1274. The Commission approves MOD-019-0 as mandatory and enforceable. In 

addition, the Commission directs the ERO to modify MOD-019-0 as discussed below. 

1275. As an initial matter, we disagree that MOD-019-0 cannot be implemented 

because it is dependent on MOD-016-0, which further depends on various unapproved 

standards. As previously stated, we direct the ERO to provide a Work Plan and 

compliance filing regarding the collection of information specified under related 

standards that are deferred, and believe there should be no difficulties complying with 

this Reliability Standard. We reiterate that ongoing collection of data is necessary to 

maintain system reliability, and approval of MOD-019-0 will help to achieve this goal. 

We therefore 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 Entity information 

related to forecasts of interruptible demands and direct control load management. 

1276. The Commission adopts the NOPR proposal directing the ERO to modify this 

standard to require reporting of the accuracy, error and bias of controllable load forecasts. 

This requirement will enable planners to get a more reliable picture of the amount of 

controllable load that is actually available, therefore allowing planners to conduct more 

accurate system reliability assessments. The Commission finds that controllable load can 

be as reliable as other resources, and therefore should also be subject to the same 

reporting requirements. Although we recognize that verifying load control devices and 

interruptible loads may be complex, we do not believe that it is overly so. Further, we 

believe that the ERO, through its Reliability Standards development process can develop 

innovative solutions to the Commission’s concern. We also note that EEI is concerned 

about such testing at times of peak load. We clarify that we are not requiring the testing 

to be conducted at peak load conditions. Consequently, we reject the proposals of EEI, 

FirstEnergy and International Transmission to discard the requirement for reporting of 

the accuracy, error and bias of controllable load forecasts. 

1277. We direct the ERO to include APPA’s proposal in the Reliability Standards 

development process to add a new requirement to MOD-019-0 that would oblige resource 

planners to analyze differences between actual and forecasted demands for the five years 

of actual controllable load and identify what corrective actions should be taken to 

improve controllable load forecasting for the 10-year planning horizon. 

1278. Regarding TAPS’ concern that reporting accuracy could be used as a compliance 

Measure, we clarify that compliance Measures for this Reliability Standard do not 

include accuracy as a compliance measure. Any change in this policy would be arrived at 

in the ERO Reliability Standards development process. 
Docket No. RM06-16-000 - 341 - 

1279. Accordingly, the Commission approves MOD-019-0 as mandatory and 

enforceable. In addition, the Commission directs the ERO to develop a modification to 

MOD-019-0 through the Reliability Standards development process to require: (1) 

reporting of the accuracy, error and bias of controllable load forecasts and (2) analyzing 

differences between actual and forecasted demands for the five years of actual 

controllable load and identify what corrective actions should be taken to improve 

controllable load forecasting for the 10-year planning horizon. 

v. Providing Interruptible Demand and Direct Control Load 

Management Data to System Operators and Reliability 

Coordinators (MOD-020-0)

1280. 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 LSE, planning authority, transmission planner and resource 

planner identify its amount of: (1) interruptible demand and (2) direct control load 

management to transmission operators, balancing authorities and reliability coordinators 

upon request. 

1281. In the NOPR, the Commission proposed to approve Reliability Standard MOD020-0 as mandatory and enforceable. In addition, the Commission proposed to direct 

NERC to 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 in 

its Reliability Standards development process. 

i. Comments

1282. APPA supports approval of MOD-020-0 as mandatory and enforceable, as 

proposed by the Commission. APPA does not oppose NERC’s consideration of possible 

changes to MOD-020-0 regarding the reporting of the accuracy, error and bias of 

controllable load forecasts.

1283. EEI and FirstEnergy state that for practical reasons, determining the precise 

availability and capability of direct load control is a difficult management and customer 

relations exercise. Unlike other technical requirements for generation resources to be 

tested for various capabilities and limits under different types of stresses, there are no 

similar requirements for load control equipment. The practical complexities of 

conducting such testing and verification, including customer notification, the need to 

plan, manage and coordinate testing with critical commercial and industrial customer 

activities, and the need to conduct such tests at times of peak load make this an extremely 

difficult operational challenge. 
Docket No. RM06-16-000 - 342 - 

1284. LPPC opposes the Commission’s proposal for modification to report the accuracy 

of load forecasts. LPPC points out that load reduction forecasts are imprecise by nature, 

and, consequently, some utilities do not undertake them. LPPC also notes that 

interruptible loads are often on one-year contracts and, in some regions, instances of 

entities actually exercising load reduction are rare; in these areas, system operators often 

do not separately forecast interruptible load reductions, and reporting on the accuracy of 

forecasts on interruptible load reductions, even if interruptible load forecasts were done, 

is of little value. LPPC states that in other areas, such as New York, interruptible load 

reductions are more predictable, because many large loads have signed interruptible load 

contracts and have a history of exercising load reductions. LPPC notes that system 

operators in areas similar to New York have sufficient data so that forecasting for 

interruptible loads is a useful exercise, and as a result, a requirement to report on the 

accuracy of forecasts in these regions would be of some value, but not elsewhere. 

Consequently, LPPC recommends that the requirement should be region-specific and 

should only apply to entities that separately forecast interruptible loads. LPPC further 

notes that energy efficiency programs are often built into the larger assumptions in the 

forecast and are not separately forecasted. 

1285. TAPS is concerned that the Commission’s recommendation in the NOPR may be 

interpreted to make forecast accuracy a component of Reliability Standards compliance. 

However, it asserts that reliance on percentage-based deviations as a measurement of 

compliance is inappropriate when applied to very small entities because an error that in 

absolute terms is too small to affect the Bulk-Power System might be a significant 

percentage of the entity’s load. The percentage deviation from a forecasted peak of a 

small (e.g., 10 MW) entity will almost always be significantly higher than the percentage 

deviation of a large (more than 10,000 MW) entity, but the smaller system’s deviation 

will have little if any impact on the bulk transmission system. In other contexts, the 

Commission has recognized that reliance solely on percentage deviations as a compliance 

measure can produce discriminatory results, and has applied MW minimums to minimize 

the discrimination that would otherwise result. 

ii. Commission Determination

1286. The Commission approves MOD-020-0 as mandatory and enforceable. In 

addition, the Commission directs the ERO to modify MOD-020-0 as discussed below. 

1287. We adopt the proposal to direct the addition of a requirement for reporting of the 

accuracy, error and bias of controllable load forecasts because we believe that reporting 

of this information will provide applicable entities with advanced knowledge about the 

exact amount of available controllable load, which will improve the accuracy of system 

reliability assessments. The Commission finds that controllable load in some cases may 

be as reliable as other resources and therefore must also be subject to the same reporting 
Docket No. RM06-16-000 - 343 - 

requirements. We recognize that determining the precise availability and capability of 

direct load control is a difficult management and customer relations exercise, but we do 

not believe that it will be overly so. Further, we believe that the ERO, through its 

Reliability Standards development process can develop innovative solutions to the 

Commission’s concern. Regarding LPPC’s suggestion that this requirement should be 

region-specific and should only apply to entities that separately forecast interruptible 

loads, we note that if a region does not forecast interruptible loads, this Reliability 

Standard does not apply. 

1288. Regarding TAPS’ concern that forecast accuracy may be interpreted as a 

component of Reliability Standards compliance, we clarify that compliance Measures for 

this Reliability Standard do not measure accuracy as a compliance measure. Any change 

in this policy would be arrived at in the ERO Reliability Standards development process. 

1289. The Commission approves Reliability Standard MOD-020-0 as mandatory and 

enforceable and directs the ERO to develop a modification to MOD-020-0 through the 

Reliability Standards development process to require reporting of the accuracy, error and 

bias of controllable load forecasts. 

w. Documentation of the Accounting Methodology for the 

Effects of Controllable Demand-Side Management in 

Demand and Energy Forecasts (MOD-021-0)

1290. MOD-021-0 requires LSEs, transmission planners and resource planners to clearly 

document how each addresses the demand and energy effects of DSM programs. The 

standard also requires an applicable entity to include information detailing how DSM 

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. 

1291. In the NOPR, the Commission proposed to approve Reliability Standard MOD021-0 as mandatory and enforceable. In addition, the Commission proposed to direct 

NERC to 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.” 

i. Comments

1292. APPA supports the Commission’s the approval of MOD-021-0 as mandatory and 

enforceable. 

1293. In contrast, ISO-NE and ISO/RTO Council oppose adoption of this standard by 

the Commission. ISO-NE argues that the LSE, transmission planner and resource 
Docket No. RM06-16-000 - 344 - 

planner should each include information regarding how DSM 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 R1. Therefore, they contend that, because MOD-016-0 is 

dependent on various unapproved Reliability Standards, MOD-021-0 is also dependent 

on unapproved Reliability Standards. Consequently, ISO-NE contends that MOD-021-0 

cannot be effectively implemented. 

1294. FirstEnergy and SMA support the Commission’s proposal to require consistent 

and uniform methods for reporting and validating demand-side information. SMA notes 

that this will provide more consistent and uniform evaluation of demand response data to 

facilitate system operator confidence in relying on such resources for various reliability 

purposes. In addition, APPA believes that NERC should consider adding requirements to 

MOD-021-0 that would provide information to allow resource planners to analyze the 

causes of differences between actual and forecasted demands, and to identify any 

corrective actions that should be taken to improve forecasted demand responses for future 

forecasts. APPA believes that all of these proposals should be submitted to NERC as the 

standards-setting body with technical expertise, and vetted through its Reliability 

Standards development process, rather than being imposed by Commission fiat. 

1295. FirstEnergy adds that MOD-019-0, MOD-020-0 and MOD-021-0 should be 

combined because they all address load forecast inputs, and that combining these 

standards will eliminate any inconsistencies and make compliance easier and more 

efficient. 

ii. Commission Determination

1296. The Commission approves MOD-021-0 as mandatory and enforceable. In 

addition, the Commission directs the ERO to develop a modification to MOD-021-0 

through the Reliability Standards development process as discussed below. 

1297. As an initial matter, we disagree that MOD-021-0 cannot be implemented 

because it is based on MOD-016-0, and through it on various unapproved standards, 

which creates an implementation problem. As previously stated, we direct the ERO to 

provide a Work Plan and compliance filing regarding collection of information specified 

under related standards that are deferred, and believe there should be no difficulty 

complying with this Reliability Standard. We reiterate that ongoing collection of data is 

necessary to maintain system reliability, and approval of MOD-21-0 will help to achieve 

this goal. Therefore, we 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 Entity the 

information required by this Reliability Standard. 
Docket No. RM06-16-000 - 345 - 

1298. We agree with FirstEnergy and SMA that standardization of principles on 

reporting and validating DSM program information will provide consistent and uniform 

evaluation of demand response to facilitate system operator confidence in relying on such 

resources, which will further increase accuracy of transmission system reliability 

assessment and consequently enhance overall reliability. We direct the ERO to modify 

this Reliability Standard to allow resource planners to analyze the causes of differences 

between actual and forecasted demands, and to identify any corrective actions that should 

be taken to improve forecasted demand responses for future forecasts. Therefore, we 

adopt the NOPR proposal and direct the ERO to modify MOD-021-0 by adding a 

requirement for standardization of principles on reporting and validating DSM program 

information. 

1299. With respect to FirstEnergy’s suggestion to combine MOD-019-0, MOD-020-0 

and MOD-021-0, we understand that the ERO intends to consolidate Reliability 

Standards and encourage FirstEnergy to make its suggestion in the Reliability Standards 

development process. 

1300. The Commission directs the ERO to modify the title and purpose statement to 

remove the word “controllable.” We note that no commenter disagrees. 

1301. The Commission approves Reliability Standard MOD-021-0 as mandatory and 

enforceable. We direct the ERO to develop a modification to MOD-021-0 through the 

Reliability Standards development process to (1) add a Requirement standardizing 

principles on reporting and validation of DSM program information; (2) allow resource 

planners to analyze the causes of differences between actual and forecasted demands, and 

to identify any corrective actions that should be taken to improve forecasted demand 

responses for future forecasts and (3) modify the title and purpose statement to remove 

the word “controllable.” 

x. Verification of Generator Gross and Net Real Power 

Capability (MOD-024-1)

1302. The purpose of MOD-024-1 is to ensure that accurate information on generation 

gross and net real power capability is used for reliability assessments. The Reliability 

Standard requires the regional reliability organization to establish and maintain 

procedures to address verification of generator gross and net real power capability. It 

also requires a generator owner to follow its regional reliability organization’s procedure 

for verifying and reporting gross and net real power generating capability. 

1303. In the NOPR, the Commission identified MOD-024-1 as a fill-in-the-blank 

standard that requires the regional reliability organization to establish and maintain 

procedures to address verification of generator gross and net real power capability. The 
Docket No. RM06-16-000 - 346 - 

Commission stated that because the regional procedures had not been submitted, it would 

not propose to approve or remand MOD-024-1 until the ERO submits the additional 

information. In addition, the Commission expressed concern that the Reliability Standard 

is not sufficiently clear because it 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. Further, the 

NOPR stated that Requirement R2 provides that the “regional reliability organization 

shall provide generator gross and net real power capability verification within 30 calendar 

days of approval” and noted that it is not clear what approval is required and when the 

30-day period starts. 

i. Comments

1304. APPA agrees that MOD-024-1 is a fill-in-the-blank standard, is not sufficient as 

currently drafted, and should not be approved as a mandatory Reliability Standard until 

NERC and the regional reliability organizations/Regional Entities develop the necessary 

regional methodologies and the Commission approves them. 

1305. APPA also states that the results of field-testing will enable NERC to refine this 

Reliability Standard in an appropriate manner. APPA further believes that NERC should 

consider modifying this Reliability Standard to provide requirements for this information 

on an Interconnection-wide basis, in the same manner that IRO-006-2 sets the 

requirement for transmission loading relief in each Interconnection. 

1306. Northern Indiana urges the Commission to reconsider the proposed changes at this 

time in favor of continuation of the currently-effective Reliability Standard. Northern 

Indiana states that the NOPR’s suggestion that there should be greater specificity and 

definition of test conditions could potentially create reliability issues, rather than protect 

against them. Northern Indiana explains that certain types of testing, and their 

preparation, can be accomplished more quickly than others, with test duration varying 

from several minutes to several days.364 The problem is compounded if a test takes some 

 364 Northern Indiana states that the longer the duration, the more stressed the units 

– and the system – during these testing intervals. For example, Commission staff 

recommends the use of ambient air temperature and river water temperature as triggering 

tests to verify generator gross and net real power capability. However, temperaturedriven test triggers would result in several neighboring systems in the same region 

undergoing tests at the same time in order to meet the test criteria. For example, a 

temperature trigger of 90 degrees Fahrenheit for a net demonstrated capacity test could 

result in all neighboring generating owners taking their units off of automatic generator 

(continued) 
Docket No. RM06-16-000 - 347 - 

time to complete, and all neighboring generating owners were required to comply at the 

same time. The end result would be a lack of regulating capability in a region. 

1307. Constellation encourages the Commission and NERC to take extra care in 

distinguishing between those requirements in each Reliability Standard that are core 

requirements as opposed to supporting information, explanatory statements or 

administrative processes. For example, Constellation points out that in MOD-024-1, 

NERC proposes that a verification process be made into a Reliability Standard with full 

enforceability. Although Constellation agrees that the verification process spelled out in 

this Reliability Standard is important and should be performed by the industry, the 

Reliability Standard, alone, exclusively provides for an administrative process and, 

therefore, if not strictly complied with, does not necessarily foreshadow an immediate, 

real-time reliability problem on the bulk electric system. Constellation is concerned that 

the Levels of Non-Compliance associated with MOD-024-1 and MOD-025-1 are based 

on arbitrary percentages that have little to do with the impact a failure to perform would 

have on reliability. Constellation believes that these problems ultimately will reduce the 

effectiveness of the Reliability Standards. Consequently, Constellation requests that the 

Commission recognize these concerns and direct NERC to take them into consideration 

during the Reliability Standards development process. 

ii. Commission Determination

1308. The Commission will not approve or remand MOD-024-1 until the ERO submits 

additional information. In order to continue verifying and reporting gross and net real 

power generating capability needed for reliability assessment and future plans, we direct 

the ERO to develop a Work Plan and submit a compliance filing. 

1309. The Commission remains concerned that the Reliability Standard is not 

sufficiently clear because it does not define the test conditions and methodologies for 

calculating de-rating factors. The Commission does not agree with APPA that NERC 

should consider modifying this Reliability Standard to provide requirements for this 

information on an Interconnection-wide basis, in the same manner that IRO-006-3 sets 

the requirements for transmission loading relief in each Interconnection. We believe, 

however, that while the overall methodology for verification of generator gross and net 

real power capability should be the same, test conditions (such as ambient temperature, 

river water temperature, etc.) can vary. 

 

control to reach maximum net demonstrated capacity for the test. By taking units off 

automatic generator control, the generating owners’ regulating capabilities are lost. 
Docket No. RM06-16-000 - 348 - 

1310. In the NOPR, the Commission stated that the Reliability Standard could be 

improved by defining test conditions, e.g., ambient temperature, river water temperature, 

and methodologies for calculating de-rating factors for conditions such as higher ambient 

temperatures than the test temperature. With the test information and methodologies, the 

generator output that can be expected to be available at forecasted weather conditions can 

be determined. The Commission agrees with Northern Indiana that testing all units at the 

same time is not feasible. However, the Commission did not propose simultaneous 

testing. Rather, we direct the ERO to develop appropriate requirements to document test 

conditions and the relationships between test conditions and generator output so that the 

amount of power that can be expected to be delivered from a generator at different 

conditions, such as peak summer conditions, can be determined. Similarly, we respond 

to Constellation that any modification of the Levels of Non-Compliance in this 

Reliability Standard should be reviewed in the ERO Reliability Standards development 

process. 

1311. We repeat our concern that Requirement R2, which specifies that the “regional 

reliability organization shall provide generator gross and net real power capability 

verification within 30 calendar days of approval,” is not clear. The requirement lacks a 

definition of what approval is required and when the 30-day period starts. Therefore, we 

direct the ERO to modify this Reliability Standard by adding information that will clarify 

this requirement. 

1312. The Commission neither accepts nor remands MOD-024-1 until the ERO submits 

additional information. Although the Commission did not propose any action with regard 

to MOD-024-1, it addressed above a number of concerns regarding the Reliability 

Standard. We therefore direct the ERO to use its authority pursuant to § 39.2(d) of our 

regulations to require users, owners and operators to provide this information. In the 

interim, compliance with MOD-024-0 should continue on a voluntary basis, and the 

Commission considers compliance with it to be a matter of good utility practice. 

y. Verification of Generator Gross and Net Reactive Power 

Capability (MOD-025-1)

1313. MOD-025-1 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 of the Reliability Standard. 
Docket No. RM06-16-000 - 349 - 

1314. In the NOPR, the Commission identified MOD-025-1 as a fill-in-the-blank 

standard that requires the regional reliability organization to establish and maintain 

procedures to address verification of generator gross and net reactive power capability. 

The NOPR stated that because the regional procedures had not been submitted, the 

Commission would not propose to approve or remand MOD-025-1 until the ERO submits 

the additional information. In addition, the Commission suggested that MOD-025-1 

could be clearer by requiring a minimum reactive power (MVAR) capability throughout a 

unit’s real power operating range. Further, the NOPR stated that requirement R2 

provides that the “regional reliability organizations shall provide generator gross and net 

real power capability verification within 30 calendar days of approval” and noted that it is 

not clear what approval is required and when the 30-day period starts. 

i. Comments 

1315. APPA agrees that the Commission should not approve this Reliability Standard 

until NERC and the regional reliability organizations/Regional Entities develop the 

necessary regional methodologies and the Commission approves them. 

1316. MidAmerican notes that the Reliability Standard will be clearer if minimum 

reactive power capability is required throughout a unit’s real power operating range. 

However, making this a Requirement for existing units would be a hardship for units not 

built with the Requirement in mind. Therefore, MidAmerican suggests that any such 

requirement should allow existing units to be grandfathered in as they are currently rated 

so that a new minimum reactive power standard is only applicable to new generating 

units or units that are being significantly upgraded. 

1317. Northern Indiana cautions the Commission against the establishment of a 

minimum capability, because it could diminish a unit’s ability to contribute to 

Interconnection reliability, and to maintain its own stability. Northern Indiana points out 

that all generators have reactive capability curves from design manufacturers, and these 

curves provide operators with a range that is considered by the manufacturer to be a safe 

operating limit. Northern Indiana contends that the continued use of reactive capability 

curves is superior to establishment of an MVAR capability, and that operators effectively 

use these curves to maintain unit stability, while also contributing to the reliability of the 

Interconnection. Northern Indiana believes that continued reliance on manufacturer 

reactive capability curves is a technically sound means to achieve the Reliability 

Standard’s stated reliability goal in a manner superior to the establishment of MVAR 

capability. 

1318. Similarly to Northern Indiana, Wisconsin Electric encourages the Commission to 

withdraw this suggested modifications to NERC’s Reliability Standard for several 

reasons. Wisconsin Electric believes that a requirement to test and verify the minimum 
Docket No. RM06-16-000 - 350 - 

reactive capability at multiple points over the operating range as part of the additional 

minimum MVAR capability requirement would be a significant and unnecessary burden 

on utilities. In Wisconsin Electric’s experience, a reactive power test at a single 

operating point is sufficient and more practical to achieve. 

1319. SoCal Edison recommends that the Commission specifically state the effective 

date for compliance with each Reliability Standard in its Final Rule. SoCal Edison states 

that the effective date is critical and gives the example of MOD-025-1, with effective 

dates phased in over several years after they are adopted by the NERC board of trustees, 

and well after the date the Final Rule will be issued. 

ii. Commission Determination

1320. The Commission will not approve or remand MOD-025-1 until the ERO submits 

additional information. In order to continue verifying and reporting gross and net 

reactive power generating capability needed for reliability assessment and future plans, 

we direct the ERO to develop a Work Plan as defined in the Common Issues section. 

1321. We disagree with commenters that verifying generator reactive capability is a 

particularly difficult issue. The capability of generators to produce reactive power is 

essential for real-time analysis and planning. The Reliability Standard addressing this 

issue requires a generator to verify reactive capability only at the unit’s full MW loading. 

However, other than baseload units, most generating units rarely operate at full MW 

loading. It is unclear what reactive capability is available throughout a unit’s real power 

(MW) operating range. Therefore, we believe a clearer standard would require a 

verification of MVAR capability throughout a unit’s real power (MW) operating range. 

However, we share concern with several commenters that such a requirement for all 

generators may not be necessary. Therefore, we adjust the proposal in the NOPR and 

direct the ERO to modify MOD-025-1 to require verification of reactive power capability 

at multiple points over a unit’s operating range. 

1322. We maintain the concern we expressed in the NOPR that Requirement R2 

provides that the “regional reliability organization shall provide generator gross and net 

reactive power capability verification within 30 calendar days of approval” and note that 

it is not clear what approval is required and when the 30-day period starts. We direct the 

ERO to provide clarification on this requirement. 

1323. The Commission neither accepts nor remands MOD-025-1 until the ERO submits 

additional information. Although the Commission did not propose any action with regard 

to MOD-025-1, it addresses above a number of concerns regarding the Reliability 

Standard. We direct the ERO to develop a Work Plan to verify and report on generator 

gross and net reactive power capability while this Reliability Standard is being modified 
Docket No. RM06-16-000 - 351 - 

and to modify this Reliability Standard through the Reliability Standards development 

process to: (1) require verification of a reactive power capability at multiple points over a 

unit’s operating range and (2) clarify Requirement R2 with a definition of what approval 

is needed and when the 30-day period starts. 

9. PER: Personnel Performance, Training and Qualifications

1324. 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 PER 

Reliability Standards address: (1) operating personnel responsibility and authority; (2) 

operating personnel training; (3) operating personnel credentials and (4) reliability 

coordination staffing. 

a. Operating Personnel Responsibility and Authority (PER001-0) 

1325. PER-001-0 requires that transmission operator and balancing authority personnel 

have the responsibility and authority to direct actions in real-time. PER-001-0 also 

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. 

1326. In the NOPR, the Commission proposed to approve PER-001-0 as mandatory and 

enforceable. 

i. Comments

1327. APPA agrees that PER-001-0 is sufficient for approval as a mandatory and 

enforceable Reliability Standard. 

1328. ISO-NE supports the adoption of this Reliability Standard provided that the 

Commission does not mandate that the tasks performed by local control centers be 

included in the definition of transmission operators. It explains that to do so would 

suggest that the local control center has independent autonomy in operating the BulkPower System, which conflicts with the “one set of hands on the wheel” philosophy 

supported by Order No. 2000 and the operating agreements approved by the Commission 

to establish ISO-NE as New England’s RTO. 
Docket No. RM06-16-000 - 352 - 

ii. Commission Determination

1329. The Commission agrees with the “one set of hands on the wheel” philosophy 

described by ISO-NE as it applies to operations of the Bulk-Power System and has no 

intention of deviating from it. Nothing in the Commission’s proposed modifications 

outlined in the NOPR in regard to the PER Reliability Standards is intended to conflict 

with this philosophy. A generic discussion of the local control centers is included in the 

Applicability Issues section and specific implications to operator training are discussed in 

PER-002-0.365 

1330. Accordingly, the Commission approves PER-001-0 as mandatory and enforceable. 

We find that the Reliability Standard is just, reasonable, not unduly discriminatory or 

preferential and in the public interest. 

b. Operating Personnel Training (PER-002-0) 

1331. PER-002-0 requires that transmission operator and balancing authority personnel 

are adequately trained. The Reliability Standard: (1) 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; (2) lists criteria that must be met by the 

training program and (3) requires that operating personnel receive at least five days of 

training in emergency operations each year using realistic simulations. 

1332. In the NOPR, the Commission proposed to approve Reliability Standard PER-002-

0 as mandatory and enforceable. In addition, the Commission proposed to direct that 

NERC submit a modification to PER-002-0 that: (1) identifies the expectations of the 

training for each job function; (2) develops training programs tailored to each job 

function with consideration of the individual training needs of the personnel; (3) expands 

the applicability to include reliability coordinators, generator operators, and operations 

planning and operations support staff with a direct impact on the reliable operation of the 

Bulk-Power System; (4) uses the Systematic Approach to Training (SAT) methodology 

in its development of new training programs and (5) includes performance metrics 

associated with the effectiveness of the training program. In addition, the Commission 

requested comments on the benefits and appropriateness of required “hands-on” training 

using simulators in dealing with system emergencies. 

 365 See Applicability Issues: Use of the NERC Functional Model, supra section 

II.C.4. 
Docket No. RM06-16-000 - 353 - 

i. General Issues

(a) Comments

1333. EEI supports the Commission’s direction for personnel training and generally 

agrees with the Commission’s proposal for PER-002-0. EEI states NERC is developing a 

new Reliability Standard, PER-005-0, which could be filed with the Commission as early 

as July 2007. According to EEI, this new Reliability Standard will respond to the issues 

raised in the NOPR regarding PER-002-0. EEI notes that the ERO plans to retire 

Reliability Standards PER-002-0 and PER-004-1 when proposed PER-005-0 is adopted. 

It recommends that the Commission consider consolidating all training requirements into 

a single Reliability Standard to simplify the Reliability Standards catalog. 

1334. Additional comments received have been grouped as follows: local control center 

personnel; applicability to generator operators; applicability to operations planning and 

operations support staff; implications to small systems; training performance metrics; use 

of SAT methodology; and use of simulators separately, followed by an overall conclusion 

and summary. 

(b) Commission Determination

1335. EEI’s comments concerning a possible PER-005-0 are beyond the scope of this 

proceeding. The Commission will not require the ERO to consolidate all training 

requirements into a single Reliability Standard. We believe that such matters should be 

left to the discretion of the ERO through its Reliability Standards development process. 

ii. Local Control Center Personnel

1336. In the NOPR, the Commission noted that decision making and implementation 

may be performed by separate groups in an ISO or RTO context, as well as other 

organizations that pool resources.366 The Commission proposed that all control centers 

and organizations that are necessary for the actual implementation of the decision or are 

needed for operation and maintenance made by the ISO, RTO or pooled resource 

organization should be part of the transmission or generator operator function. Although 

the NOPR discussed this matter in the context of the Communication (COM) Reliability 

 366 NOPR at P 236-37. 
Docket No. RM06-16-000 - 354 - 

Standards, the NOPR indicated that the proposal would apply in the training and 

certification context, as well.367

(a) Comments

1337. EEI states that the term “operating personnel” as used in the PER group of 

Reliability Standards needs clarification because it may be interpreted to mean any 

person with a capability to take a unilateral action that can have a potentially significant 

effect on the Bulk-Power System. EEI states that the term is open to broad interpretation 

in actual practice, subject to various contracts, operating agreements and ISO/RTO 

procedures. It states, for example, a local control center operator may take instructions 

from and act on those instructions, whereas the ‘transmission operator’ under the 

Functional Model may be viewed as a more centralized authority such as a larger regional 

system operator. EEI contends that some define local control center as a transmission 

operator, while others disagree. 

1338. ISO-NE states the scope of PER-002-0 need not be expanded because local control 

center personnel in its footprint implement tasks delegated to them by ISO-NE for 

operation of designated transmission facilities. NPCC argues that expanding PER-002-0 

beyond the entities identified under the NERC Functional Model (i.e., transmission 

operators, reliability coordinators and balancing authorities) will require substantial cost 

and time but add little value. It states that there are no certification exams for any entities 

other than transmission operators, reliability coordinators and balancing authorities and to 

develop and implement such exams and to have the additional personnel certified would 

take several years. It also states that these personnel already function under the authority 

of NERC-certified operators and act only at the direction of certified operators. It 

concludes that an entity that does not exercise operational authority should not be subject 

to the same requirements as the decisionmaker. 

1339. Northern Indiana states that it is not uncommon in the industry for employees 

who perform switching operations to be supervised by NERC-certified operators and that 

such employees are subject to round-the-clock review by, and communication with, their 

NERC-certified transmission operators. Similarly, SoCal Edison notes that large utilities 

can have operators strategically located throughout a vast service territory at switching 

centers with SCADA capability and that these operators follow the directives of one 

control center responsible for Bulk-Power System reliability. SoCal Edison disagrees 

that the operators of these switching centers, simply because the switching center has 

SCADA capability, must be NERC-certified. 

 367 Id. at P 237, 779. 
Docket No. RM06-16-000 - 355 - 

1340. LPPC states that the training and certification requirements should apply only to 

transmission and generation personnel that are located in the transmission control center 

(i.e., responsible for real-time Bulk-Power System operations). It argues that 

transmission and generation operation employees that are located in remote locations that 

are not directly involved in the real-time scheduling of transactions or Bulk-Power 

System monitoring and control do not need to be certified for real-time operations 

because they are not involved in the type of functions in which regimented training in the 

Reliability Standards would be useful. It suggests that a bright line should be drawn 

between the training of actual system operators and the training for operators of 

generation plants that are not responsible for scheduling. LPPC also states that the 

Commission should clarify the scope of training that the transmission control center realtime operations personnel should receive. 

1341. Entergy asserts that the training program should be tailored to the functions local 

control center operators, generator operators and operations planning staff perform that 

impact the reliable operation of the Bulk-Power System for both normal and emergency 

operations. 

(b) Commission Determination 

1342. In our discussion above regarding the Functional Model, we emphasized our 

concern that there should be no unintentional gaps or redundancies in responsibility for 

compliance with the Requirements of Reliability Standards. This concern arises 

particularly in the context of RTOs, ISOs and other pooled resources that may have 

separate divisions performing decisionmaking functions and implementing functions 

within the transmission operator classification. The topic of training is one such area of 

concern. While PER-002-0 applies to transmission operators, it is important for 

reliability that personnel involved in both decisionmaking and implementation receive 

proper training. 

1343. Clearly, in a region where an RTO or ISO performs the transmission operator 

function, its personnel with primary responsibility for real-time operations must receive 

formal training pursuant to PER-002-0. In addition, personnel who are responsible for 

implementing instructions at a local control center also affect the reliability of the Bulk 

Power System. These entities may take independent action under certain circumstances, 

for example, to protect assets, personnel safety and during system restorations. Whether 

the RTO or the local control center is ultimately responsible for compliance is a separate 

issue addressed above, but regardless of which entity registers for that responsibility, 

these local control center employees must receive formal training consistent with their 

roles, responsibilities and tasks. Thus, while we direct the ERO to develop modifications 

to PER-002-0 to include formal training for local control center personnel, that training 

should be tailored to the needs of the positions. 
Docket No. RM06-16-000 - 356 - 

1344. As noted by SoCal Edison, there are different operating structures and therefore 

there is a need to clarify to which control centers we direct the Reliability Standard apply. 

For example, for a large utility within an RTO or ISO footprint there may be one 

centrally-located control center whose function is to supervise several distributed control 

centers, each with remote monitoring and control capability. In this type of structure, the 

personnel of the centrally-located control center should receive formal training in 

accordance with the Reliability Standard. Personnel at the distributed control centers also 

need to be trained, but the responsibility for this training is outside the scope of the 

Reliability Standard.368 

1345. Another organizational structure, typically representative of relatively smaller 

entities, consists of a single control center that implements operating instructions from its 

transmission operator, e.g., an RTO, ISO or pooled resource. Similar to the discussion 

above, operators at these control centers also may take independent action to protect 

assets, safety and system restoration. Such control center personnel must also receive 

formal training pursuant to PER-002-0. 

1346. Consistent with the comments of SoCal Edison and Northern Indiana, the 

Commission understands that it is common practice to have traveling operators located in 

the local control centers who carry out field switching operations and station inspections 

at the direction of the local control center operators. These personnel are not involved 

with the transmission operator at the ISO or RTO or at organizations with pooled 

resources, and as such, should not be subject to Reliability Standard PER-002-0. 

1347. The Commission disagrees with those commenters who contend that, because 

operators at local control centers take direction from NERC-certified operators at the ISO 

or RTO, they do not need to be addressed by the training requirements of PER-002-0. 

Rather, as discussed above, these operators maintain authority to act independently to 

carry out tasks that require real-time operation of the Bulk-Power System including 

protecting assets, protecting personnel safety, adhering to regulatory requirements and 

establishing stable islands during system restoration. 

1348. Several commenters express concern about requiring local control center operators 

to become fully trained to the same extent as transmission operators, balancing 

authorities and reliability coordinators. This is not the Commission’s intent. As we 

stated in the NOPR, the proposed modifications do not imply a “one-size-fits-all” 

approach but rather ensure the creation of training programs that are structured and 

 368 The Commission expects the entity registered as the transmission operator to 

ensure that these personnel are competent for the tasks that they perform. 
Docket No. RM06-16-000 - 357 - 

tailored to the different functions and needs of the personnel involved.369 Therefore the 

Commission agrees with Entergy that the training program should be tailored to the 

functions local control center operators, generator operators and operations planning staff 

perform that impact the reliable operation of the Bulk-Power System for both normal and 

emergency operations. 

iii. Applicability to generator operators

1349. The Commission proposed in the NOPR a modification to 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.370

(a) Comments

1350. PG&E and FirstEnergy support the Commission’s goal of ensuring appropriate 

training for generator operators. FirstEnergy, however, believes that there is some 

confusion between the Functional Model and the Reliability Standard requirements 

concerning the generator operator classification. FirstEnergy explains that, in some 

contexts, “generator operator” refers to operations personnel who are centrally-located at 

a generation control center (i.e., fleet operators) while in other contexts it refers to 

generator operators located at the generation plant (i.e., unit operator). Further, according 

to FirstEnergy, the NERC glossary defines “generator operator” as the entity that 

operates generating unit(s) and performs the functions of supplying energy and 

interconnected operations services. FirstEnergy requests that the Commission direct 

NERC to revise the Reliability Standard to recognize this distinction. 

1351. Other commenters, including Xcel, California PUC and Entergy, state that the 

Reliability Standard should not apply to generator operators. Xcel argues that generator 

operators take their direction from transmission operators, balancing authorities and 

reliability coordinators, which limits their ability to exercise independent action 

impacting the reliability of the Bulk-Power System. Entergy argues that expanding the 

applicability to generator operators would provide little benefit to those personnel in the 

performance of their own functions, and could distract them from those functions. It also 

argues that such training would be extremely costly and would divert necessary resources 

from more important reliability objectives. 

 369 See NOPR at P 773, 775. 

370 Id. at P 772. 
Docket No. RM06-16-000 - 358 - 

1352. California PUC states that the requirement to include power plant operators in the 

applicability of this Reliability Standard exceeds anything contemplated in the regulation 

of the Bulk-Power System under previous NERC guidelines and what is authorized by 

statute. It contends that impacts of generator operator actions on the Bulk-Power System 

are of a much smaller magnitude and consequence than those of system operators. 

Further, it states that other authorities, such as balancing authorities and state 

governments, may have acted in regard to training of power plant operators and, 

therefore, the Commission should not act where other authorities have already done so. 

In a similar vein, the Nevada Companies state that the activities of generating station 

operations personnel are limited to the confines of the specific generating station. 

Knowledge of or exposure to interconnected grid operating principles is simply not 

applicable to the tasks normally performed at the generating stations. 

1353. Reliant states that the proposed modification fails to clarify how generator 

operators are to satisfy the training program requirement or the scope of generator 

operator personnel that must be trained. It states that the proposed modification could be 

interpreted to require generator operators to train the plant operator as well as the 

dispatcher in the generator operator’s local control center. Reliant believes, however, 

that plant operators should not be subject to the Reliability Standard’s training program 

requirement because personnel employed in plant operating positions are trained in the 

operation of plant equipment and take direction with respect to the operation of the plant 

from management personnel as well as from the local control center. Accordingly, it 

reasons that, because these employees take direction with respect to plant operations from 

elsewhere, they do not have primary responsibility for the real-time operation of the 

Bulk-Power System and should not be responsible for complying with Reliability 

Standards. Reliant suggests that PER-002-0 should specifically target generator operator 

personnel that develop dispatch instructions and the Reliability Standard should be 

modified to accommodate generator operator entities that are members of ISOs and RTOs 

with established NERC-approved certification programs. However, it should exclude 

those personnel who simply take direction on plant operations. 

1354. Dynegy, MISO and Wisconsin Electric state that these Reliability Standards 

should not be extended to all real-time operation positions of a generator operator. They 

state that many real-time operation positions are staffed by long-tenured union personnel 

who routinely operate generating units and take directions from a centralized generation 

control center or the local RTO/ISO. They analogize this type of certification and 

training requirement with requiring the outside field force of a transmission operator, 

including positions that operate and switch electric transmission lines pursuant to 

instructions from a centralized transmission control group, to be NERC-certified. 

Dynegy and MISO support a more limited extension of these Reliability Standards to 
Docket No. RM06-16-000 - 359 - 

real-time operation personnel located in a centralized generation control center that 

interfaces with the plants and the local RTO/ISO but not to personnel at the plant level. 

1355. Some commenters address the appropriate scope of training for generator 

operators. For example, MidAmerican states that experience and knowledge necessary 

for transmission operators may go well beyond what is needed for generation operations. 

It contends that a NERC-approved training course specific to these functions would be an 

appropriate alternative. Entergy comments that, if training of generator operator 

personnel is required, it should focus on the functions generator operators must perform, 

not on the functions that others perform. SDG&E states that training for generator 

operators and others who may directly impact the reliable operations of the Bulk-Power 

System need not be identical to or as extensive as that required of transmission system 

operators, but should be tailored in scope, contents and duration so as to be appropriate to 

the personnel and the object of promoting system reliability. 

1356. FirstEnergy states that there are no universal certification or training programs for 

generator operators; therefore a reasonable transition period should be established to 

allow time for generator operators to comply with this Reliability Standard. It also states 

that nuclear units are already subject to NRC training requirements and that compliance 

with NRC requirements should satisfy this Reliability Standard. 

1357. APPA, Process Electricity Committee and TAPS are concerned that, unless a size 

limitation is included for the generator operators, a substantial number of generator 

operator personnel will have to be enrolled in training programs. They argue that while a 

generator plays an important role in the reliable operations of the bulk electric system, the 

generator operator takes commands from the transmission operator, balancing authority 

or reliability coordinator. TAPS opposes the expanded applicability, especially in the 

case of small systems, because it believes that the requirement would be costly with no 

benefits to reliability. 

1358. Process Electricity Committee is concerned about the effect of the expanded 

requirements on end users who have on-site generation. It argues that the training 

requirements would present an added cost for end users with no apparent added benefit 

and that, in the long term, end users may be discouraged from developing on-site 

generation, which in turn would leave industrial electricity users more vulnerable to 

failures elsewhere on the energy grid. 

(b) Commission Determination

1359. The Commission explained in the NOPR that 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; and included 
Docket No. RM06-16-000 - 360 - 

generator operators among those that have such an impact.371 Xcel and others oppose 

extending the applicability of PER-002-0 to generator operators, because they take 

directions from balancing authorities and others, which limits their ability to impact 

reliability. Although a generator may be given direction from the balancing authority, it 

is essential that generator operator personnel have appropriate training to understand 

those instructions, particularly in an emergency situation in which instructions may be 

succinct and require immediate action. Further, if communication is lost, the generator 

operator personnel should have had sufficient training to take appropriate action to ensure 

reliability of the Bulk-Power System. Thus, we direct the ERO to develop a modification 

to make PER-002-0 applicable to generator operators.

1360. We agree with FirstEnergy and others that some clarification is required regarding 

which generator operator personnel should be subject to formal training under the 

Reliability Standard. As noted above, a generator operator typically receives instructions 

from a balancing authority. Some generator operators are structured in such a way that 

they have a centrally-located dispatch center that receives direction and then develops 

specific dispatch instructions for plant operators under their control. For example, a 

balancing authority may direct a centrally-located dispatch center to deliver 300 MW to 

the grid, and the dispatch center would determine the best way to deliver that generation 

from its portfolio of units. In this type of structure, it is the personnel of the centrallylocated dispatch center that must receive formal training in accordance with the 

Reliability Standard. Plant operators located at the generator plant site also need to be 

trained but the responsibility for this training is outside the scope of the Reliability 

Standard.372 

1361. Other generator operators may be structured in such a way that the dispatch center 

and the single generation plant are at the same site. In this structure as well, some 

personnel will perform dispatch activities while others are designated as plant operators. 

Again, it is the dispatch personnel that must receive formal training in accordance with 

the Reliability Standard. Plant operators also need to be trained but the responsibility for 

this training is outside the scope of the Reliability Standard. 

1362. We disagree with Nevada Companies, Xcel and others that assert that generator 

operator training will provide limited benefit. Rather, we conclude that, with the above 

focused direction regarding the applicability of the Reliability Standard to generator 

 371 NOPR at P 771. 

372 The Commission expects the entity registered as the generator operator to 

ensure that plant operators are competent for the tasks that they perform. 
Docket No. RM06-16-000 - 361 - 

operator personnel, the benefits to the Bulk-Power System will be maximized and the 

cost of formal training limited. Further, our direction addresses California PUC’s 

concerns regarding application to plant operators. In any event, the existence of local 

training requirements in some regions does not supplant the need for uniform training 

requirements for all generator operators developed in a Reliability Standard with 

continent-wide applicability. 

1363. Further, the Commission agrees with MidAmerican, SDG&E and others that the 

experience and knowledge required by transmission operators about Bulk-Power System 

operations goes well beyond what is needed by generation operators; therefore, training 

for generator operators need not be as extensive as that required for transmission 

operators. Accordingly, the training requirements developed by the ERO should be 

tailored in their scope, content and duration so as to be appropriate to generation 

operations personnel and the objective of promoting system reliability. Thus, in addition 

to modifying the Reliability Standard to identify generator operators as applicable 

entities, we direct the ERO to develop specific Requirements addressing the scope, 

content and duration appropriate for generator operator personnel. 

1364. FirstEnergy states that nuclear plant operators are already subject to NRC training 

requirements and thus suggests that compliance with NRC requirements should satisfy 

this Reliability Standard. FirstEnergy does not identify the content of the NRC training 

requirements, and the Commission is unaware whether the NRC training requirements 

adequately address the interaction between a nuclear power plant and the Bulk-Power 

System. Accordingly, without drawing any conclusion on the matter, the Commission 

directs that the ERO consider FirstEnergy’s comments in the Reliability Standards 

development process. 

1365. Commenters’ concerns regarding the need for a size limitation on generator 

operators should be satisfied by our determination that the applicability of particular 

entities should be determined based on the ERO compliance registry criteria, which 

APPA and TAPS support. We believe that limiting the applicability of Reliability 

Standards to NERC’s definition of bulk electric system will alleviate much of Process 

Electricity Committee’s concern regarding the effect of the expanded requirements on 

end users who have on-site generation. For larger end users who have on-site generation, 

the Commission believes that there is an added benefit to including them in the 

Reliability Standards because they sell into the market and should be treated on a similar 

basis as any other generator of a similar size. 
Docket No. RM06-16-000 - 362 - 

iv. Applicability to operations planning and operations 

support staff

1366. As mentioned above, the Commission proposed in the NOPR to direct the ERO to 

develop a modification to PER-002-0 to require training of operations planning and 

operations support staff of transmission operators and balancing authorities who have a 

direct impact on the reliable operation of the Bulk-Power System. 

(a) Comments

1367. Several commenters, including EEI and APPA, oppose the proposed applicability 

of the Reliability Standard to operations planning and operations support staff. Other 

commenters contend that the Commission’s proposal is ambiguous and should be 

clarified. 

1368. EEI states that the extension of the applicability to “operations support personnel” 

could result in a dramatic expansion of industry training requirements with uncertain 

benefits to system reliability. It requests that the Commission reconsider this proposal or 

provide some additional clarity on the definition of the term. APPA also expresses 

concern about expanding the applicability to operations planning and operations support 

staff, especially if the Commission adopts its proposed interpretation of the bulk electric 

system because this would become quite onerous for small utilities. Wisconsin Electric 

states that the Commission’s proposal does not address how to identify the operations 

planning and operations support personnel who would be subject to the Reliability 

Standard and how to develop compliance measures for them. It contends that the 

proposed modification is ambiguous and should not be implemented. 

1369. Avista states that individuals who are responsible for assessing a company’s 

compliance with the Reliability Standards may simply have an administrative and 

coordination role, but have no direct responsibility for reliable operations of the BulkPower System. It argues that such individuals, while operations support staff, should not 

be subject to the proposed Reliability Standard. It therefore requests that the Commission 

clarify that personnel subject to the Reliability Standard may include operations planning 

and operations support staff. 

1370. Entergy believes it is unnecessary to require all staff supporting the transmission 

operator to be trained in the transmission operator’s Reliability Standards responsibilities. 

It states that as long as the supporting personnel work under the direction of a NERCcertified transmission operator, there is no need for duplicative training for supporting 

personnel. Entergy comments that, if such training is required, it should focus on the 

functions operations planning and operations support staff must perform, not on the 

functions that others perform. 
Docket No. RM06-16-000 - 363 - 

1371. Northern Indiana states that expanding application of the Reliability Standard to 

operations support staff “with a direct impact on the reliable operation of the Bulk-Power 

System” is ambiguous. It states that NERC surveyed certified operators for its job 

function analysis related to this Reliability Standard with results due at the end of January 

2007. Northern Indiana recommends that the results of this survey be considered in the 

development and clarification of this proposed Reliability Standard. Further, Northern 

Indiana is concerned about which specific job functions will be addressed and which will 

be exempt, and about what “direct” versus “indirect” impact means. 

(b) Commission Determination

1372. The Commission directs the ERO to develop a modification to PER-002-0 that 

extends applicability to the operations planning and operations support staff of 

transmission operators and balancing authorities, as clarified below. Most commenters 

express concern about extending the applicability of the Reliability Standard because 

they believe “operations planning” and “operations support” are not well-defined and 

could encompass a significant number of operations personnel. In the NOPR, the 

Commission stated that the Reliability Standard should apply to operations planning and 

operations support staff that have a direct impact on the reliable operation of the BulkPower System.373 We clarify that these personnel include those who carry out outage 

coordination and assessments in accordance with Reliability Standards IRO-004-1 and 

TOP-002-2, and those who determine SOLs and IROLs or operating nomograms in 

accordance with Reliability Standards IRO-005-1 and TOP-004-0. The Commission 

directs the ERO to include in PER-002-0, personnel who carry out the above functions. 

1373. In addition, the Commission is aware that the personnel responsible for ensuring 

that critical reliability applications of the EMS, such as state estimator, contingency 

analysis and alarm processing packages, are available, up-to-date in terms of system data 

and produce useable results can also have an impact on the Reliable Operation of the 

Bulk-Power System. Because these employees’ impact on Reliable Operation is not as 

clear, we direct the ERO to consider, through the Reliability Standards development 

process, whether personnel that perform these additional functions should be included in 

mandatory training pursuant to PER-002-0. 

1374. APPA and EEI oppose the proposed extension of the Reliability Standard to 

operations planning and operations support staff, claiming that it could dramatically 

expand industry training requirements with uncertain benefits to system reliability. Our 

clarification above adequately addresses these concerns because we have identified a 

 373 NOPR at P 780. 
Docket No. RM06-16-000 - 364 - 

specific set of such personnel that have a direct impact on reliable operations. With the 

above clarification, our directive is not as expansive as EEI and APPA contemplate, and 

is more clearly connected with Bulk-Power System reliability. Further, since the 

Commission is not adopting the proposed interpretation of the ERO’s definition of bulk 

electric system, as discussed in the Applicability section above, the directed modification 

to PER-002-0 should not be onerous to small entities as suggested by APPA.

1375. Several commenters express concern that the operations planning and operations 

support staffs will be required to be trained on the transmission operators’ 

responsibilities. The Commission clarifies that this is not the case. Training programs 

for operations planning and operations support staff must be tailored to the needs of the 

function, the tasks performed and personnel involved. 

v. Training performance metrics

1376. In the NOPR, we noted the assertion by ISO/RTO Council that there is no 

definition for “adequately trained operating personnel.” ISO/RTO Council suggested 

adoption of performance metrics to ensure that training results in competent operating 

personnel.374 The Commission agreed and proposed to require that the ERO modify 

PER-002-0 to include performance metrics to assess the effectiveness of the training 

program. The Commission also stated that such performance metrics are not a substitute 

for an SAT developed training program.

(a) Comments

1377. Xcel does not agree that performance metrics should be included as part of this 

Reliability Standard. While it believes performance metrics are generally useful, it states 

that in this case it would be difficult to develop the appropriate metrics. MidAmerican 

believes that the proposed performance metrics are not essential to ensuring the 

appropriateness of training because the Reliability Standard already requires NERC 

approval of all training activities, and specifically requires training in certain areas. 

1378. MISO and Wisconsin Electric state that it is unclear how a Reliability Standard to 

measure the effectiveness of a training program would apply to an organization that 

contracts for training services, and that there are many training requirements found in 

other Reliability Standards covering the topics and amount of training. They argue that 

the proposed modification is overly-prescriptive and deviates from a fundamental training 

concept that training should be tailored to the organization and to the individual. 

 374 Id. at P 776. 
Docket No. RM06-16-000 - 365 - 

(b) Commission conclusion

1379. Xcel, MISO and MidAmerican state that performance metrics to assess the 

effectiveness of training programs are unnecessary. The Commission believes that, if 

quantifiable performance metrics can be developed to gauge the effectiveness of a 

Reliability Standard, these performance metrics should be developed, tracked and used to 

continually improve an applicable entity’s performance and the Reliability Standard 

itself. The Commission directs the ERO to explore the feasibility of developing 

meaningful performance metrics for assessing the effectiveness of training programs, and 

if feasible, to develop such metrics for the Reliability Standard as part of the Reliability 

Standards development process. 

vi. Use of Systematic Approach to Training (SAT) 

methodology

1380. In the NOPR, the Commission required the ERO to use the SAT methodology in 

identifying the requirements for a training program because SAT is a proven approach to: 

identify the tasks and associated skills and knowledge necessary to accomplish those 

tasks; determine the competency levels of each operator to carryout those tasks; 

determine the competency gaps; and design, implement and evaluate a training plan to 

address each operator’s competency.375 

(a) Comments 

1381. ISO-NE states that the use of SAT methodology should not be mandated and that 

responsible entities under this Reliability Standard should be allowed the flexibility to use 

the most appropriate training methodology available. Northern Indiana requests 

clarification on about our proposal on the use of SAT methodology. 

(b) Commission Determination

1382. The Commission understands that the new operator training Reliability Standard 

PER-005-1-0 currently under development by the ERO would endorse the use of SAT. 

In response to ISO-NE, training based on SAT is a proven approach to identify the skills 

and knowledge necessary to accomplish particular tasks, evaluate each operator’s 

competency to carry out those tasks, determine any competency competency gaps, and 

design, implement and evaluate a training plan to address such gaps. Since SAT is the 

most appropriate training methodology available, we believe this addresses ISO-NE’s 

 375 Id. at P 775. 
Docket No. RM06-16-000 - 366 - 

comments. Northern Indiana requests clarification about the details of our proposal for 

SAT methodology. The Commission has not directed how the SAT methodology should 

be implemented, but we expect it to be developed through the Reliability Standards 

development process. We encourage Northern Indiana to become involved in the 

process. Thus, we adopt the NOPR proposal to direct that the ERO develop a 

modification to PER-002-2 (or a new Reliability Standard) that uses the SAT 

methodology. 

vii. Use of simulators for training 

1383. The Commission explained in the NOPR that Requirement R4 of the Reliability 

Standard requires training in emergency operations using realistic simulations of system 

emergencies and noted that there are various options available for providing operator 

training simulator capability, including contracting for this service from others who have 

developed the capability. The Commission requested comments on the benefits and 

appropriateness of required “hands-on” training using simulators in dealing with system 

emergencies.376

(a) Comments

1384. While most commenters recognize the benefits of simulator training, they differ on 

whether simulator training should be mandatory. 

1385. NERC comments that there can be significant value gained by training operating 

personnel for emergencies under realistic conditions using training simulators and 

requests that comments on this matter be directed to the Reliability Standards 

development process for consideration. APPA believes that significant reliability 

benefits could result from the use of simulators by reliability coordinators, transmission 

operators and balancing authorities that have operational control over a significant 

portion of load and resources. It does not believe, however, that requiring simulator 

training for smaller entities that do not have operational control over facilities that 

manage SOLs and IROLs would be an effective use of resources. APPA supports 

NERC’s investigating the benefits of simulator training but recommends that any training 

requirements closely consider the costs and benefits of simulator training. 

1386. SoCal Edison and MISO state that, although simulators are valuable training tools, 

not all entities should be compelled to have simulators. MISO comments that simulators 

will become even more critical in the coming years as experienced operators, with first-

 376 Id. at P 778. 
Docket No. RM06-16-000 - 367 - 

hand knowledge of their respective systems, retire. Recognizing that not every company 

can or should build a simulator because of the resources simulators require, MISO 

suggests that the Reliability Standards codify a requirement for operators of companies 

that do not own a simulator to have access to a training simulator. MISO states that while 

simulators are valuable training resources, focusing emergency training solely on fullscale simulators may lead to problems when unforeseen situations arise. It reasons that 

generic, low-cost simulators that teach concepts are a valuable training resource for 

developing skills transferable to events that do not follow a script. 

1387. SDG&E states that simulators would enhance the overall training experience but 

cautions that simulators that accurately model individual systems are resource-consuming 

while less resource-consuming, generic simulators may not mirror the trainee’s actual 

system. As such, it believes that the use of simulators should be encouraged but not 

mandated. Similarly, International Transmission contends that simulators are a useful 

tool in the training of operators and support personnel. However it cautions that 

simulators are not the only means to provide realistic simulation-based training. It argues 

that because alternative simulation-based training means are available and because 

dedicated training simulators are very expensive, the use of dedicated training simulators 

should not be required under the Reliability Standards. 

1388. Otter Tail states that full-scale simulators are effective but costly to develop and 

labor intensive to maintain. It recommends that full-scale simulators should be an option 

but not a requirement for small entities. It proposes instead that the Commission allow 

small entities to continue to use training aids such as generic operator training simulators, 

EXCEL-based interactive training tools and table-top training exercises. Likewise, Alcoa 

also does not believe that simulators are necessary to provide operating personnel with 

training for system emergencies. It supports alternative training methods, such as tabletop exercises or realistic simulated exercises that take into account the physical and 

electrical characteristics of the trainee’s system. Further, it believes that costs associated 

with simulators would not be justified by the impact on reliability. 

1389. Xcel states that to the extent that Reliability Standard PER-002-0 is applicable to 

generator operators, the industry should be able to develop its own ways of administering 

training instead of being required to develop simulators. 

(b) Commission Determination

1390. Most commenters including NERC agree that hands-on training using simulators 

can add significant value to training for emergencies. Yet, we share the commenters’ 

concerns regarding the high cost to develop and maintain full-scale simulators and take 

these concerns into consideration. The Commission finds that significant reliability 

benefits may be derived from requiring simulator training for reliability coordinators, 
Docket No. RM06-16-000 - 368 - 

transmission operators and balancing authorities that have operational control over a 

significant portion of load and generation. 

1391. This does not mean that these entities must develop and maintain full-scale 

simulators but rather they should have access to training on simulators. Further, because 

the cost is likely to outweigh the reliability benefits for small entities, the Commission 

agrees with Alcoa and Otter Tail that small entities should continue to use training aids 

such as generic operator training simulators and realistic table-top exercises. 

Accordingly, the Commission directs the ERO to develop a requirement for the use of 

simulators dependent on the entity’s role and size, as discussed above. 

viii. Summary of Commission Determination

1392. The Commission notes that no commenters specifically addressed the proposed 

modifications directing the ERO to expand the Applicability section to include reliability 

coordinators, and to identify the expectations of the training for each job function and 

develop training programs tailored to each job function with consideration of the 

individual training needs of the personnel. However, in responding to the proposals to 

expand the applicability of the Reliability Standard, many commenters acknowledged the 

need to have clear training expectations and training programs tailored to specific job 

functions. The Commission finds that these two modifications will enhance the training 

by focusing on expectations and tailoring the training to specific job functions; therefore, 

the Commission adopts these modifications to the Reliability Standard. 

1393. Accordingly, the Commission approves Reliability Standard PER-002-0. In 

addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the 

Commission directs the ERO to develop a modification to PER-002-0 through the 

Reliability Standards development process 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 section to include (a) reliability coordinators, (b) local transmission 

control center operator personnel (as specified in the above discussion), (c) generator 

operators centrally-located at a generation control center with a direct impact on the 

reliable operation of the Bulk-Power System and (d) operations planning and operations 

support staff who carry out outage planning and assessments and those who develop 

SOLs, IROLs or operating nomograms for real-time operations; (4) uses the Systematic 

Approach to Training (SAT) methodology in its development of new training programs 

and (5) includes the use of simulators by reliability coordinators, transmission operators 

and balancing authorities that have operational control over a significant portion of load 

and generation. 
Docket No. RM06-16-000 - 369 - 

1394. Further, the Commission directs the ERO to determine whether it is feasible to 

develop meaningful performance metrics associated with the effectiveness of a training 

program required by PER-002-0 and, if so, develop such performance metrics. The 

Commission also directs the ERO to consider through the Reliability Standards 

development process, whether personnel that support EMS applications as discussed 

above should be included in mandatory training pursuant to the Reliability Standard. 

c. Operating Personnel Credentials (PER-003-0)

1395. PER-003-0 requires transmission operators, balancing authorities and reliability 

coordinators to have NERC-certified staff for all operating positions that have a primary 

responsibility for real-time operations or are directly responsible for complying with the 

Reliability Standards. 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. 

1396. In the NOPR, the Commission proposed to approve Reliability Standard PER-003-

0 as mandatory and enforceable. In addition, the Commission proposed to direct NERC 

to submit a modification to PER-003-0 that: (1) includes generator operators as 

applicable entities; (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. 

i. Comments

1397. In addressing this Reliability Standard, many commenters made the same 

arguments they made in connection with the operator training Requirements set forth in 

Reliability Standard PER-002-0. Comments specifically relevant to operator certification 

are reproduced here for completeness. 

1398. EEI, FirstEnergy and PG&E agree that the Reliability Standard should apply to 

generator operators. FirstEnergy believes that the Functional Model and the Reliability 

Standards development process should be used to clarify any confusion about which 

generator operator and transmission operator functions are addressed under this 

Reliability Standard. To further reduce confusion and the need for potentially duplicative 

training, EEI and PG&E comment that operators should not be required to maintain 

multiple certifications. SDG&E states that new certification obligations for generator 

operators must be tailored to the needs of the function and should reflect the limited 

opportunities of generator operators to have an impact on system reliability. Thus, it 

argues that generator operators should not be subject to the same certification 

requirements as transmission operators. MidAmerican echoes this point and adds that 

minimum competencies are currently adequately demonstrated by the completion of 
Docket No. RM06-16-000 - 370 - 

NERC-approved annual certification tests. MidAmerican believes that applicable tests 

should be tailored to specific job duties to ensure effectiveness and Reliability Standard 

compliance. 

1399. Dynegy, MISO, Reliant and Wisconsin Electric are concerned about extension of 

this Reliability Standard to generator operators if it results in every power plant control 

room being staffed by NERC-certified operators. Dynegy supports a limited extension of 

the Reliability Standard to real-time operational personnel located in a centralized 

generation control center that interfaces with the plants and the local RTO/ISO. Reliant 

believes that, under certain circumstances, the dispatcher in the generator operator’s local 

control center should not be subject to NERC certification requirements. It explains that, 

for example, in PJM the dispatcher in a generator operator local control center is a PJMcertified generation dispatcher and that, like the employees in plant operating positions, 

these dispatchers do not take unilateral action but instead act only upon PJM’s 

instructions. 

1400. LPPC states that certification requirements for real-time operations Reliability 

Standards should only be required for transmission and generation personnel that are 

located in the transmission control center (i.e., responsible for real-time Bulk-Power 

System operations). It argues that transmission and generation operation employees that 

are located in remote locations that are not directly involved in the real-time scheduling 

of transactions or Bulk-Power System monitoring and control do not need to be certified 

for real-time operations Reliability Standards because they are not involved in the type of 

functions in which regimented training in the Reliability Standards would be useful. 

LPPC states that requiring certification would be an inefficient result and would distract 

these personnel from their own highly-specialized tasks. 

1401. Although APPA states that PER-003-0 is sufficient for approval as a mandatory 

and enforceable Reliability Standard, it opposes the proposed modification to make 

generator operators subject to the Reliability Standard. Alcoa, Entergy, Northern Indiana 

and Xcel also oppose subjecting generator operators to the Reliability Standard. Given 

that there is no size limitation limiting applicability for generator operators, APPA asks 

the Commission to reconsider the proposed modification and, instead, allow the 

applicability of PER-003-0 to generator operators to be considered through the Reliability 

Standards development process. Alcoa disagrees with the proposed modification because 

generator operators take direction from a NERC-certified transmission operator, 

balancing authority or reliability coordinator and do not operate independently of those 

entities. Similarly, Xcel states generator operators have limited ability to take 

independent action that affects Bulk-Power System reliability. It also states that it is not 

clear whether “generator operator” means plant operator or the transmission operator 

responsible for generation. 
Docket No. RM06-16-000 - 371 - 

1402. Northern Indiana and SoCal Edison oppose a certification requirement for all realtime operating positions in a transmission control center that performs switching 

operations via SCADA for the Bulk-Power System, because these personnel are 

supervised by NERC-certified operators. Northern Indiana states that the costs would far 

outweigh the reliability benefits, if any, that would result from such a certification 

requirement. SoCal Edison recommends that PER-003-0 apply to operators who have the 

authority and are empowered to exercise independent judgment, and who take or direct 

actions to secure Bulk-Power System reliability. It recommends that operators who 

switch Bulk-Power System facilities when their actions are approved and overseen by 

certified operators should be excluded. 

1403. APPA states that if it is required to send its employees for NERC training and 

certification, it would risk losing those employees to larger utilities that can afford to pay 

more, simply because those employees would have acquired a desirable occupational 

credential. It argues that given the substantial workforce issues facing public power 

systems in the next few years, imposing unneeded certification requirements could 

exacerbate an already challenging labor force situation. 

1404. Northern Indiana adds that because some of these employees are members of labor 

unions and subject to existing collective bargaining agreements, it would have to 

renegotiate these agreements to provide for the certification of these employees, and to 

provide for the hiring of relief staff necessary to permit these employees to maintain their 

certification. 

1405. PG&E states that, once the certification requirements are developed by NERC and 

approved by the Commission, sufficient time must be permitted for generator operators to 

attain the necessary certification. It argues that time will be needed to develop the 

process, create appropriate documentation and perform training for appropriate 

personnel. PG&E contends that generator operators should not be penalized for failing to 

achieve certification if they do not have a reasonable period of time to implement the 

training programs. 

1406. EEI believes that the ERO’s Reliability Standards development process should be 

used to sort out the applicability issues. It states that using this process will allow for 

sufficient clarity to reduce the risk of confusion and thus prevent the need for 

interpretations that could change over time. EEI believes this is especially important with 

this PER class of Reliability Standards because operators should have unambiguous 

guidance on what they are expected to do. It states that the Reliability Standards should 

be written so that operating personnel clearly understand their roles and responsibilities, 

and whether or not a specific certification is required. EEI also states that operators 

should not be required to maintain multiple certifications. 
Docket No. RM06-16-000 - 372 - 

ii. Commission Determination

1407. Northern Indiana and APPA raise persuasive arguments regarding labor relations 

and labor retention issues that may arise if generator operators are required to be NERCcertified. The Commission understands theses concerns and is persuaded not to require 

generator operators or transmission operators at local control centers to be NERCcertified at this time. In addition, the Commission understands that there are some long 

tenured unionized transmission operators who are very capable operators but who are 

unable to secure certification. This is not a new problem and has been addressed in 

various collective bargaining negotiations through grandfathering such capable operators 

who are unable to become certified. However, the Commission directs that if 

grandfathering is implemented, the entity must attest that the operators are competent. 

The Commission directs the ERO to consider grandfathering certification requirements 

for these personnel so that the industry can retain the knowledge and skill of these longtenured operators. Personnel that are subject to such grandfathering still must comply 

with applicable training requirements pursuant to PER-002-0. 

1408. No comments were received on the proposed modifications to direct the ERO to 

modify the Reliability Standard to specify the minimum competencies that must be 

demonstrated to become and remain a certified operator and to identify the minimum 

competencies operating personnel must demonstrate to be certified. The Commission 

finds that these modifications improve the Reliability Standard by focusing on necessary 

competencies. Accordingly, the Commission directs the ERO to develop these 

modifications to the Reliability Standard. 

1409. We find that the Reliability Standard serves an important reliability goal in 

requiring applicable entities to staff all operating positions that have a primary 

responsibility for real-time operations or are directly responsible for complying with the 

Reliability Standards with NERC-certified staff. Accordingly, the Commission approves 

Reliability Standard PER-003-0. In addition, pursuant to section 215(d)(5) of the FPA 

and § 39.5(f) of our regulations, the Commission directs the ERO to develop a 

modification to PER-003-0 through the Reliability Standards development process that: 

(1) specifies the minimum competencies that must be demonstrated to become and 

remain a certified operator and (2) identifies the minimum competencies operating 

personnel must demonstrate to be certified. The Commission also directs the ERO to 

consider grandfathering certification requirements for transmission operator personnel in 

the Reliability Standards development process. 

d. Reliability Coordination – Staffing (PER-004-1)

1410. PER-004-1 ensures that reliability coordinator personnel are adequately trained, 

NERC-certified and staffed 24-hours a day, seven days a week, with properly trained and 
Docket No. RM06-16-000 - 373 - 

certified individuals.377 Further, reliability coordinator operating personnel must have a 

comprehensive understanding of the area of the Bulk-Power System for which they are 

responsible. 

1411. In the NOPR, the Commission proposed 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 proposed to direct NERC to submit a 

modification to PER-004-0 that: (1) includes formal training requirements for reliability 

coordinators similar to those addressed under the personnel training Reliability Standard 

PER-002-0; (2) includes requirements pertaining to personnel credentials for reliability 

coordinators similar to those in PER-003-0 and (3) includes Measuers and Levels of NonCompliance that address staffing requirements and the requirement for five days of 

emergency training. 

i. Comments

1412. APPA notes that the revised Reliability Standard PER-004-1 filed by NERC on 

November 15, 2006 partially fulfills the directive to include Measures and Levels of NonCompliance. It states that NERC should be directed to include Measures and Levels of 

Non-Compliance related to all Requirements. 

1413. FirstEnergy seeks revisions to the terms “shall have a comprehensive 

understanding” and “shall have extensive knowledge.” It states that it will be difficult for 

entities to demonstrate compliance with these terms. In addition, FirstEnergy suggests 

that the reliability coordinator staffing requirements should be located in the IRO 

Reliability Standards. 

1414. Xcel states that emergency training requirements should be expressed in hour 

increments rather than days to allow for flexibility in scheduling training and 

coordinating with rotating shift schedules. 

ii. Commission Determination

1415. No comments were received on the proposed modifications to include formal 

training requirements for reliability coordinators similar to those addressed under the 

 377 In its November 15, 2006, filing, NERC submitted PER-004-1, which 

supercedes the Version 0 Reliability Standard. PER-004-1 adds Measures and Levels of 

Non-Compliance to the Version 0 Reliability Standard. In this Final Rule, we review the 

November version, PER-004-1. 
Docket No. RM06-16-000 - 374 - 

personnel training Reliability Standard PER-002-0 and to include requirements pertaining 

to personnel credentials for reliability coordinators similar to those in PER-003-0. The 

Commission finds that these modifications will improve the Reliability Standard because 

they include training requirements for the reliability coordinator who has the highest level 

of authority to assure Reliable Operation of the Bulk-Power System. Accordingly, the 

Commission directs the ERO to develop modifications to the Reliability Standard that 

address these matters. 

1416. With regard to APPA’s comments, consistent with our discussion above regarding 

Measures and Levels of Non-Compliance, we leave it to the discretion of the ERO 

whether it is necessary that each Requirement of this Reliability Standard have a 

corresponding Measure. 

1417. We find that the Reliability Standard adequately addresses reliability coordinator 

staffing. Accordingly, the Commission approves Reliability Standard PER-004-1. In 

addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the 

Commission directs the ERO to develop a modification through the Reliability Standards 

development process to PER-004-1 that: (1) includes formal training requirements for 

reliability coordinators similar to those addressed under the personnel training Reliability 

Standard PER-002-0 and (2) includes requirements pertaining to personnel credentials for 

reliability coordinators similar to those in PER-003-0. Further, we direct the ERO to 

consider the suggestions of FirstEnergy and Xcel in the Reliability Standards 

development process. 

10. PRC: Protection and Control 

1418. Protection and Control systems (PRC) on Bulk-Power System elements are an 

integral part of reliable grid operation. Protection systems are designed to detect and 

isolate faulty elements on a system, thereby limiting the severity and spread of system 

disturbances, and preventing possible damage to protected elements. The function, 

settings and limitations of a protection system are critical in establishing SOLs and 

IROLs. The PRC Reliability Standards apply to transmission operators, transmission 

owners, generator operators, generator owners, distribution providers and regional 

reliability organizations and cover a wide range of topics related to the protection and 

control of power systems. 
Docket No. RM06-16-000 - 375 - 

a. System Protection Coordination (PRC-001-1)

1419. PRC-001-1378 ensures that protection systems are coordinated among operating 

entities by requiring transmission and generator operators to notify appropriate entities of 

relay or equipment failures that could affect system reliability. In addition, transmission 

and generator operators must coordinate with appropriate entities when new protection 

systems are installed, or when existing protection systems are modified. 

1420. In the NOPR, the Commission proposed to approve PRC-001-0 as mandatory and 

enforceable. In addition, the Commission proposed to direct NERC to submit 

modifications to PRC-001-0 (proposed directives) that included: (1) Measures and 

Levels of Non-Compliance; (2) a requirement that transmission and generator operators 

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 could carry out appropriate corrective control actions consistent with those used 

in mitigating IROL violations and (3) clarifying that, after being informed of failures in 

relays or protection system elements on the Bulk-Power System, transmission operators 

or generator operators carry out corrective control actions that return a system to a stable 

state as soon as possible, but no longer than 30 minutes after receiving a notice of failure. 

i. Comments

1421. While Constellation supports the Commission’s proposed directives because they 

represent additional steps to achieving reliability of the Bulk-Power System and 

eliminating undue discrimination, MISO questions the need for the Commission’s 

proposals. MISO notes that virtually all protection schemes have backups. MISO asks 

whether the Commission wants facilities to be removed from service if one of the 

redundant relaying packages has a problem, or whether some other action should be taken 

besides such removal. 

1422. With regard to the NOPR’s direction to the ERO to include Measures and Levels 

of Non-Compliance, APPA states that the new Measures only partially address the 

Requirements, and in some cases, reference non-existent Requirements. For example, 

rather than referencing Requirement R5.1, new Measure M1 incorrectly refers to non-

 378 In its November 15, 2006, filing, NERC submitted PRC-001-1, which 

supercedes the Version 0 Reliability Standard. PRC-001-1 adds Measures and Levels of 

Non-Compliance to the Version 0 Reliability Standard. In this Final Rule, we review the 

November version, PRC-001-1. 
Docket No. RM06-16-000 - 376 - 

existent Requirement R8.1. Similarly, rather than referencing Requirement R5.2, new 

Measure M2 incorrectly refers to non-existent Requirement R8.2. 

1423. APPA states that while it agrees that PRC-001-1 is sufficient for approval, since 

the new Measures only partially address the Requirements, and in some cases refer to 

non-existent Requirements, no penalties should be levied for violations of Requirements 

that have no accompanying Measures. 

1424. WIRAB states that the Requirements, Measures and Levels of Non-Compliance 

do not provide guidance for the length of time – currently stated as “as soon as possible” 

– permitted for corrective actions. 

1425. APPA disagrees with the Commission’s second and third directives to NERC. 

APPA states that the BAL and IRO Reliability Standards already have specific standards 

to notify affected entities and provide directions for recovery time. APPA acknowledges 

that in the NOPR, we stated 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.” 

APPA, however, states that: “If this is the Commission’s view, then it should instruct 

NERC to re-examine the interaction between these two sets of standards [IROL and SOL 

and proposed PRCs] on remand, and to develop the most efficient solution to this 

problem. The Commission should not itself undertake to resolve this problem by issuing 

directives for specific revisions to PRC-001-1, especially if the result might be to have 

local level personnel countermanding the instruction of RC personnel at a time when the 

system is unstable.” APPA asserts that the Commission should modify its proposed 

directives to allow NERC, as technical expert, to address the problems in the Reliability 

Standard that the Commission has identified. 

1426. Dynegy states that in many situations, depending on the particular relay or 

protection system failure, an operator may not be able to complete corrective control 

actions that return the system to a stable state within 30 minutes, including 

troubleshooting of relays or restoring any tripped facilities. Dynegy find that a 30-minute 

time period may thus be overly rigid and punitive. Wisconsin Electric also requests 

further clarification of the 30-minute time limit to carry out corrective actions after a 

relay failure. It has additional concerns about older relays (e.g., electromechanical 

relays) since it is impossible to know when and whether these older relays have failed. 

Wisconsin Electric also states that the NOPR is not clear about which relays threaten 

reliable system operation. 

1427. Northern Indiana states that the NOPR appears to require immediate corrective 

actions whenever failures on relays or protection systems are detected, without regard to 

whether the specific failure detected reduces system reliability. It seeks the 
Docket No. RM06-16-000 - 377 - 

Commission’s clarification that we do not intend to question a certified transmission 

operator’s expertise in assessing whether a particular relay or protection system failure 

reduces system reliability. 

1428. California PUC contends that imposing a time restriction for returning a system to 

a stable state may cause more harm than good since additional information and options 

may be available as time elapses. It repeats its suggestion from its earlier comments on 

the Staff Preliminary Assessment and proposes the following alternative language: 

“Transmission or generation 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, except where a longer response time is feasible, 

or where a longer response is demonstrated to produce a better ultimate solution without 

unacceptable interim risk.” 

1429. A number of commenters raise concerns that the proposal would be unnecessarily 

burdensome on generator operators. For example, Progress Electricity Committee asserts 

that the Commission’s proposal to require generator operators to return the system to a 

stable state as soon as possible and within no longer than 30 minutes may be too 

burdensome for non-energy company users with on-site generation. California 

Cogeneration asserts that PRC-001-1 as a whole may impose unreasonable burdens on 

generators with no material impact on the grid, because most such generators will have 

no knowledge of the protection systems on the grid. 

1430. Allegheny states that since generator operators do not have the same resources as 

transmission operators for taking corrective actions, the Commission’s third proposed 

directive should be modified to apply only to transmission operators. Allegheny states 

that while a transmission operator can direct a generator operator to take specific actions, 

the reverse is not the case. 

1431. FirstEnergy contends that Requirement R2.1 essentially requires generator 

operators to report all protective relay or equipment failures, since generator operators 

may not be able to tell which failures will reduce system reliability. FirstEnergy suggests 

that R2.1 should be revised to require generator operators to report all equipment failures 

or outages. FirstEnergy further suggests that PRC-001-1 be revised to provide that if a 

company performs reasonable testing procedures, undiscoverable equipment failures will 

not be violations of R2.1. 

1432. MidAmerican states that the term “immediately” in the Commission’s second 

directive is ambiguous and unenforceable. It suggests a 30-minute time limit. 
Docket No. RM06-16-000 - 378 - 

ii. Commission Determination

1433. The Commission approves PRC-001-1 as mandatory and enforceable. We also 

direct NERC to develop a modification to PRC-001-1 through the Reliability Standards 

development process, as discussed below. 

1434. The Commission observes that, collectively, the comments raise three general 

questions: (1) Whether relay or equipment failures reduce system reliability and, if so, in 

what circumstances; (2) what are “corrective actions” required to return a system to a 

secure operating state and (3) when is returning a system to a secure operating state “as 

soon as possible.”379 The Commission will discuss each question in turn. 

(a) Whether Relay or Equipment Failures 

Reduce System Reliability and, if so, in What 

Circumstances?

1435. Protection systems on Bulk-Power System elements are an integral part of reliable 

operations. They are designed to detect and isolate faulty elements on a power system, 

thereby limiting the severity and spread of disturbances and preventing possible damage 

to protected elements. If a protection system can no longer perform as designed because 

of a failure of its relays, system reliability is reduced or threatened. In deriving SOLs and 

IROLs, moreover, the functions, settings, and limitations of protection systems are 

recognized and integrated. Systems are only reliable when protection systems perform as 

designed. This is what PRC-001-1 means in linking a reduction in system reliability with 

a protection relay failure or other equipment failure. 

1436. With respect to MISO’s comment that virtually all protection systems have 

backups and therefore the Commission’s proposals are not necessary, unless the backup 

protection has the same design goals and capabilities as the primary protection, a relay 

failure in the primary protection may still threaten system reliability. Further, we note 

that while the PRC Reliability Standards do not specifically require protection systems 

consisting of redundant and independent protection groups for each critical element in the 

 379 PRC-001-1 Requirement R2.2 provides: “If a protective relay or equipment 

failure reduces system reliability, the Transmission Operator shall notify its Reliability 

Coordinator and affected Transmission Operators and Balancing Authorities. The 

Transmission Operator shall take corrective action as soon as possible.” 
Docket No. RM06-16-000 - 379 - 

Bulk-Power System, such requirements are included as one potential solution in the TPL 

Reliability Standards.380 

1437. Finally, MISO’s question seems to imply that if there are redundant relaying 

packages providing redundant protection, and a problem develops with only one of those 

redundant packages, system reliability is not threatened, and therefore, there is no need to 

take corrective control actions within 30 minutes. We agree with MISO’s conclusion for 

this scenario. 

1438. In the case, however, of a system element protected by a single protection system 

with a failed relay that threatens system reliability, that scenario would require the use of 

appropriate operating solutions including removing a system element from service. 

Another possible solution is to operate a system at a lower SOL or IROL that recognizes 

the degraded protection performance. 

(b) What are Corrective Actions?

1439. Corrective actions taken by transmission operators to return a system to a secure 

operating state when a protective relay or equipment failure reduces system reliability 

normally refer to “operator control actions”, consisting of operator actions such as 

removing the facility without protection from service, generation redispatch, transmission 

re-configuration, etc. Corrective action must be completed as soon as possible, but no 

longer than 30 minutes after a notice of protection system failure. Failure to complete 

corrective action within 30 minutes will be considered a violation of the relevant IROL or 

TOP Reliability Standards. In contrast, troubleshooting or replacing failed relays or 

equipment are performed by field maintenance personnel and normally take hours or 

even days to complete. These actions are not normally considered corrective actions in 

the context of real-time operation of the Bulk-Power System. 

1440. We believe that “[t]he transmission operator shall take corrective action as soon as 

possible” refers to transmission operators taking operator control actions. It does not 

refer to troubleshooting, repairing or replacing failed relays or equipment, etc., since 

these time-consuming corrective actions would prolong the risk of cascading failures to 

the Bulk-Power System.

1441. Dynegy, Wisconsin Electric and Northern Indiana are concerned that the time 

required to troubleshoot, repair or replace failed relays and equipment would be 

 380 If delayed clearing results in reliability criateria violations, one solution can be 

the use of redundant relay systems. TPL-002-0 Table 1, footnote e. 
Docket No. RM06-16-000 - 380 - 

substantially longer than the 30 minutes set forth in the Commission’s proposed directive. 

We believe we have alleviated this concern in our discussion, above. In addition, in 

response to Northern Indiana, we clarify that the responsibility for assessing whether a 

particular relay or protective system failure reduces system reliability remains with 

transmission operators. We direct the ERO to clarify the term 

“corrective action” consistent with this discussion when it modifies PRC-001-1 in the 

Reliability Standards development process.

1442. We agree with Allegheny that generator operators do not have the same ability as 

transmission operators to take corrective control actions on the Bulk-Power System, and 

we will modify our third directive as set forth below. We believe this also addresses 

Progress Electricity Committee and California Cogeneration’s similar concerns. 

(c) When is “As Soon as Possible”?

1443. As explained above, the requirement for system operators to take corrective 

control action when protective relay or equipment failure reduces system reliability 

should be treated the same as the requirement for returning a system to a secure and 

reliable state after an IROL violation, i.e., as soon as possible, but no longer than 30 

minutes after a violation. A longer time limit would place an entity in violation of 

relevant IROL or TOP Reliability Standards.

1444. The Commission directs the ERO to consider FirstEnergy and California PUC’s 

comments about the maximum time for corrective action in the ERO Reliability 

Standards development process. 

1445. In response to MidAmerican’s request that we clarify the term “immediately” in 

our proposed second directive, we direct the ERO, in the Reliability Standards 

development process, to determine the appropriate amount of time after the detection of 

relay failures, in which relevant transmission operators must be informed of such failures.

1446. We agree with APPA that the added Measures and Levels of Non-Compliance 

incorrectly reference non-existent requirements. We direct the ERO to revise the 

references accordingly. 

1447. We disagree with APPA that BAL and IRO Reliability Standards already address 

matters contained in PRC-001-1, because BAL and IRO are not related to relay and 

equipment failures, which are specifically addressed in PRC-001-1. 

1448. We disagree with APPA’s assertion 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 failure of relays and protection systems on 
Docket No. RM06-16-000 - 381 - 

critical elements.” The time allowed for mitigating actual IROL violations is very clear: 

as soon as possible and within 30 minutes. We clarify that our concern is not about “field 

protection and control personnel not being alerted about failure of relays and protection 

systems on critical elements.” Our focus, rather, is that upon detection of failure of relays 

and protection systems on critical elements, field personnel must report the failures 

promptly to the transmission operators so that corrective operator control actions can be 

taken as soon as possible and within 30 minutes. Finally, with respect to APPA’s 

contention that our proposed directives would result in local-level personnel undermining 

or not following the instructions of reliability coordinator personnel at a time when the 

system is unstable, we do not understand how local level personnel, who have no 

operating control of a transmission operator’s system or a reliability coordinator’s system 

could do so. 

1449. The Commission approves Reliability Standard PRC-001-1 as mandatory and 

enforceable. In addition, the Commission directs the ERO to develop modifications to 

PRC-001-1 through the Reliability Standards development process that: (1) correct the 

references for Requirements and (2) include a requirement that upon the detection of 

failures in relays or protection system elements on the Bulk-Power System that threaten 

reliable operation, relevant transmission operators must be informed promptly, but within 

a specified period of time that is developed in the Reliability Standards development 

process, whereas generator operators must also promptly inform their transmission 

operators and (3) clarifies that, after being informed of failures in relays or protection 

system elements that threaten reliability of the Bulk-Power System, transmission 

operators must carry out corrective control actions, i.e., return a system to a stable state 

that respects system requirements as soon as possible and no longer than 30 minutes after 

they receive notice of the failure. 

b. Define Regional Disturbance Monitoring and Reporting 

Requirements (PRC-002-1)

1450. 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. 

1451. In the NOPR, the Commission identified PRC-002-1 as a fill-in-the-blank 

standard. The NOPR stated that because the regional requirements for installing DME 

had not been submitted, the Commission would not approve or remand PRC-002-1 until 

the ERO submitted the additional information. 
Docket No. RM06-16-000 - 382 - 

i. Comments

1452. APPA agrees with the Commission’s proposed course of action. It states that 

there are significant and substantive differences between regional procedures due to the 

characteristics of various regional grids. Further it suggests that NERC and the Regional 

Entities consider whether they can attain greater consistency on an Interconnection-wide 

basis in addressing the completion of this Reliability Standard. 

1453. Alcoa suggests that the ERO—instead of a Regional Entity—should define the 

requirements for DME and the type of report it generates. The requirements and 

equipment specifications should be consistent throughout North America. In addition, 

Alcoa suggests that the criteria for installation of such equipment should include the 

necessary monitoring and recording that contribute to analysis and enhance reliability. 

1454. Otter Tail suggests that PRC-002-1 should be developed on an Interconnectionwide basis to ensure consistency and promote reliability of the Bulk-Power System. 

ii. Commission Determination

1455. For the reasons stated in the NOPR, the Commission will not approve or remand 

PRC-002-1. 

1456. We agree with APPA, Alcoa and Otter Tail that the ERO should consider whether 

greater consistency can be achieved in this Reliability Standard. In Order No. 672, the 

Commission also encouraged greater uniformity in the development of Reliability 

Standards.381 Consistent with that goal, the Commission directs the ERO to consider 

APPA, Alcoa and Otter Tail’s suggestions in the Reliability Standards development 

process as it modifies PRC-002-1 to provide missing information needed for the 

Commission to act on this Reliability Standard. 

c. Regional Procedure for Analysis of Misoperations of 

Transmission and Generation Protection Systems (PRC003-1)

1457. 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. This Reliability Standard requires each regional reliability organization to 

 381 Order No. 672 at P 292. 
Docket No. RM06-16-000 - 383 - 

develop a procedure to monitor and review misoperations of protection systems and to 

develop and document corrective actions. 

1458. In the NOPR, the Commission identified PRC-003-1 as a fill-in-the-blank 

standard. The NOPR stated that because the regional procedures had not been submitted, 

the Commission proposed not to approve or remand PRC-003-1 until the ERO submitted 

the additional information. 

i. Comments

1459. APPA agrees with the Commission’s proposed course of action. It states that 

there are significant and substantive differences between regional procedures due to the 

characteristics of various regional grids and industry structures. Further it suggests that 

NERC and the Regional Entities consider whether they can attain greater consistency on 

an Interconnection-wide basis in completing this Reliability Standard. 

ii. Commission Determination

1460. For the reasons stated in the NOPR, the Commission will not approve or remand 

PRC-003-1. 

1461. We agree with APPA that the ERO should consider whether greater consistency 

can be achieved in this Reliability Standard. In Order No. 672, the Commission also 

encouraged greater uniformity in the development of Reliability Standards.382 Consistent 

with that goal, the Commission directs the ERO to consider APPA’s suggestions in the 

Reliability Standards development process as it modifies PRC-003-1 to provide missing 

information needed for the Commission to act on this Reliability Standard. 

d. Analysis and Reporting of Transmission Protection 

System Misoperations (PRC-004-1)

1462. 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. 

 382 Id. at P 292. 
Docket No. RM06-16-000 - 384 - 

1463. In the NOPR, the Commission proposed to approve PRC-004-1 as mandatory and 

enforceable. 

i. Comments

1464. APPA agrees that PRC-004-1 is sufficient for approval as a mandatory and 

enforceable Reliability Standard. 

1465. ISO-NE and ISO/RTO Council oppose the Commission’s proposed approval of 

PRC-004-1 because it relies on PRC-003-1, a fill-in-the-blank standard, which the 

Commission does not propose to approve or remand until the ERO submits additional 

information. 

1466. ISO-NE further requests the Commission to direct NERC to modify PRC-004-1 to 

include LSEs and transmission operators in the applicability section. It states that based 

on current practice in the ISO-NE balancing area, transmission operators, transmission 

owners, LSEs and distribution providers may individually or jointly own and operate a 

protection system. It therefore suggests that transmission operators and LSEs should also 

be included in the applicability section. ISO-NE provides the same suggestion with 

regard to PRC-005-1, PRC-008-0, PRC-011-0, PRC-015-0, PRC-016-0, PRC-017-0 and 

PRC-021-1. 

ii. Commission Determination

1467. The Commission approves Reliability Standard PRC-004-1 as mandatory and 

enforceable. 

1468. We are not persuaded by ISO-NE and ISO/RTO Council’s assertion that PRC004-1 should not be approved because it refers to PRC-003-1, which is a fill-in-the blank 

standard. In part, we neither approve nor remand PRC-003-1 because it applies to a 

regional reliability organization, and we are not persuaded that a regional reliability 

organization’s compliance with a Reliability Standard can be enforced as NERC 

proposes.383 This is not the case with PRC-004-1, which applies to transmission owners, 

distribution providers, and generator owners. Since PRC-004-1 is an existing Reliability 

Standard that has been followed on a voluntary basis, transmission owners, distribution 

providers and generator owners are on notice of requirements related to misoperations of 

transmission and generation protection systems. As stated in the Common Issues section, 

 383 NOPR at P 56-57. 
Docket No. RM06-16-000 - 385 - 

a reference to an unapproved Reliability Standard may be considered in an enforcement 

action, but is not a reason to delay approving and enforcing this Reliability Standard. 

1469. We direct the ERO to consider ISO-NE’s suggestion that LSEs and transmission 

operators should be included in the applicability section, in the Reliability Standards 

development process as it modifies PRC-004-1.384 Further, as the ERO reviews this 

Reliability Standard in its five-year cycle of review, the Regional Entity, rather the 

regional reliability organization, should develop the procedures for corrective action 

plans. 

e. Transmission and Generation Protection System 

Maintenance and Testing (PRC-005-1)

1470. 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. 

1471. In the NOPR, the Commission proposed to approve PRC-005-1 as mandatory and 

enforceable. In addition, the Commission proposed to direct NERC to 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. 

i. Comments

1472. FirstEnergy states that NERC should establish a maximum maintenance interval 

for protection system equipment, and a national limitation taking into account both relay 

type and functional versus calibration testing. Entergy does not object to the 

development of maximum allowable maintenance intervals provided that they are 

developed in NERC’s Reliability Standards development process. 

 384 The same suggestion and therefore same Commission response also applies to 

PRC-005-1, PRC-008-0, PRC-011-0, PRC-015-0, PRC-016-0, PRC-017-0 and PRC-021-

1. 
Docket No. RM06-16-000 - 386 - 

1473. FirstEnergy and ISO-NE suggest that PRC-005-1, PRC-008-0, PRC-011-0 and 

PRC-017-0 should be combined into a single Reliability Standard relating to the 

maintenance of protection and control equipment. 

ii. Commission Determination

1474. For the reasons stated in the NOPR, the Commission approves Reliability 

Standard PRC-005-1 as mandatory and enforceable. 

1475. In addition, for the reasons discussed in the NOPR, the Commission directs the 

ERO to develop a modification to PRC-005-1 through the Reliability Standards 

development process 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. We further direct the ERO to consider FirstEnergy’s and ISO-NE’s 

suggestion to combine PRC-005-1, PRC-008-0, PRC-011-0 and PRC-017-0 into a single 

Reliability Standard through the Reliability Standards development process. 

f. Development and Documentation of Regional UFLS 

Programs (PRC-006-0)

1476. PRC-006-0 ensures the development of a regional UFLS385 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 requires the regional reliability 

organization to develop, coordinate, document and assess UFLS program design and 

effectiveness at least every five years. 

1477. In the NOPR, the Commission identified PRC-006-0 as a fill-in-the-blank 

standard. The NOPR stated that because the regional procedures had not been submitted, 

the Commission would not propose to approve or remand PRC-006-0 until the ERO 

submits the additional information. The Commission commends the ERO and regions’ 

initiative, outlined in the Reliability Standards Work Plan, in adopting an integrated and 

coordinated approach to protection for generators, transmission lines and UFLS and 

UVLS386 programs as part of its work on fill-in-the-blank Reliability Standards.387

 385 Underfrequency load shedding. 

386 Undervoltage load shedding. 

387 NOPR at P 367. 
Docket No. RM06-16-000 - 387 - 

i. Comments 

1478. APPA agrees with the Commission’s proposed course of action. It suggests that in 

completing this Reliability Standard, NERC should strive for greater consistency on an 

Interconnection-wide basis through the use of “base procedures” for each 

Interconnection. 

ii. Commission Determination 

1479. For the reasons stated in the NOPR, the Commission will not approve or remand 

PRC-006-0. 

1480. The Commission understands that UFLS, when properly coordinated with the 

dynamic response of the Bulk-Power System, is one of the safety nets that safeguards the 

system from cascading events, assuming it is properly coordinated with the dynamic 

response of the system. Until this Reliability Standard is submitted to the Commission 

for approval, we do not expect any lapse in the compliance with this Reliability Standard. 

As we stated in the NOPR, it is important that the existing regional reliability 

organizations continue to fulfill their current roles during this time of transition. The 

Commission expects that this function will pass from the regional reliability organization 

to the Regional Entity after they are approved. 

g. Assuring Consistency with Regional UFLS Program 

Requirements (PRC-007-0)

1481. PRC-007-0 requires transmission owners, transmission operators, LSEs and 

distribution providers to provide, and annually update, their underfrequency data to 

facilitate the regional reliability organization’s maintenance of the UFLS program 

database. 

1482. In the NOPR, the Commission proposed to approve PRC-007-0 as mandatory and 

enforceable. 

i. Comments

1483. APPA agrees that PRC-007-0 is sufficient for approval as a mandatory and 

enforceable Reliability Standard. However, it states that actual enforcement cannot take 

place until PRC-006-0 becomes effective. ISO-NE and ISO/RTO Council state that 

PRC-007-0 should not be approved because it refers to PRC-006-0, which we are not 

approving or remanding at this time. 
Docket No. RM06-16-000 - 388 - 

ii. Commission Determination

1484. For the reasons stated in the NOPR, the Commission approves Reliability 

Standard PRC-007-0 as mandatory and enforceable. 

1485. We are not persuaded by APPA, ISO/RTO Council and ISO-NE that PRC-007-0 

cannot be acted on because it relies on PRC-006-0. We proposed to not approve or 

remand PRC-006-0 partly because it applies to a regional reliability organization. The 

Commission was not persuaded that a regional reliability organization’s compliance with 

a Reliability Standard can be enforced as NERC proposed.388 That is not the case with 

PRC-007-0, which applies to transmission owners, transmission operators, distribution 

providers and LSEs. Since PRC-007-0 is an existing Reliability Standard that has been 

followed on a voluntary basis, transmission owners, transmission operators, distribution 

providers and LSEs are generally aware of its requirements. As stated in the Common 

Issues section, a reference to an unapproved Reliability Standard may be considered in an 

enforcement action, but is not a reason to delay approving and enforcing this Reliability 

Standard. The Commission expects that the data will be sent to the Regional Entities 

(instead of the regional reliability organizations) after they are approved. 

h. Underfrequency Load Shedding Equipment Maintenance 

Programs (PRC-008-0)

1486. 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. 

1487. In the NOPR, the Commission proposed to approve Reliability Standard PRC008-0 as mandatory and enforceable. In addition, the Commission proposed to direct 

NERC to 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 BulkPower System. 

i. Comments

1488. Entergy states that it does not object to NERC’s development of maximum 

allowable maintenance intervals for the purpose of evaluating protection system and 

control programs provided that they are developed in NERC’s Reliability Standards 

 388 NOPR at P 56-57. 
Docket No. RM06-16-000 - 389 - 

development process. FirstEnergy states that NERC should establish a maximum 

maintenance interval for protection system equipment and a “national limitation taking 

into account both relay type and functional versus calibration testing.” 

1489. ISO-NE and ISO/RTO Council contend that the Commission should not approve 

PRC-008-0 until it approves PRC-006-0, which the Commission has identified as a fillin-the-blank standard. Similarly, APPA contends that PRC-008-0 cannot be enforced 

until PRC-006-0 has become effective and the required regional UFLS program 

documentation has been submitted by the applicable Regional Entity. It also notes that 

the applicability of PRC-008-0 is limited to transmission owners and distribution 

providers who are required by their regional reliability organization to have a UFLS 

program. 

ii. Commission Determination

1490. FirstEnergy and Entergy agree with the Commission’s proposed directive, whereas 

APPA suggests that the need for the proposal should be established first via the 

Reliability Standards development process. 

1491. We disagree with ISO/RTO Council and others that approval or enforcement of 

PRC-008-0 is linked to approval of PRC-006-0. PRC-008-0 requires that a “transmission 

provider or distribution provider with a UFLS program (as required by its Regional 

Reliability Organization) shall have a UFLS equipment and maintenance testing program 

in place.”389 PRC-006-0 requires each regional reliability organization to develop, 

coordinate and document a UFLS program that includes specified elements. Again, we 

proposed to neither approve nor remand PRC-006-0 because it applies to a regional 

reliability organization and the Commission was not persuaded that a regional reliability 

organization’s compliance with a Reliability Standard can be enforced as proposed by 

NERC.390 That is not the case with PRC-008-0, which applies to transmission owners 

and distribution providers. Since PRC-008-0 is an existing Reliability Standard that has 

been followed on a voluntary basis, transmission owners and distribution providers are 

aware whether they are required to have a UFLS program in place. We approve PRC008-0 as mandatory and enforceable because it requires entities to have equipment 

 

389 See PRC-008-0, Requirement R1. 

390 NOPR at P 56-57. 
Docket No. RM06-16-000 - 390 - 

maintenance and testing of their UFLS programs. As stated in the Common Issues 

section, a reference to an unapproved Reliability Standard may be considered in an 

enforcement action, but is not a reason to delay approving and enforcing this Reliability 

Standard. The Commission expects that the program results will be sent to the Regional 

Entities (instead of the regional reliability organizations) after they are approved. 

1492. The Commission approves Reliability Standard PRC-008-0 as mandatory and 

enforceable. In addition, the Commission directs the ERO to develop a modification to 

PRC-008-0 through the Reliability Standards development process 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. 

i. UFLS Performance Following an Underfrequency Event 

(PRC-009-0)

1493. PRC-009-0 ensures that the performance of a UFLS system is analyzed and 

documented following an underfrequency event by requiring the transmission owner, 

transmission operator, LSE and distribution provider to document the deployment of their 

UFLS systems in accordance with the regional reliability organization’s program. 

1494. In the NOPR, the Commission proposed to approve Reliability Standard PRC009-0 as mandatory and enforceable. 

i. Comments

1495. APPA agrees that PRC-009-0 is sufficient for approval as a mandatory and 

enforceable Reliability Standard. However, it states that actual enforcement cannot take 

place until pending PRC-006-0 becomes effective and notes that the applicability of 

PRC-009-0 is limited to entities that own or operate a UFLS program recognized by their 

regional reliability organization. 

1496. ISO-NE and ISO/RTO Council contend that the Commission should not approve 

PRC-009-0 until it approves PRC-006-0, which the Commission has identified as a fillin-the-blank standard. 
Docket No. RM06-16-000 - 391 - 

ii. Commission Determination

1497. For the reasons stated in the NOPR, the Commission approves Reliability 

Standard PRC-009-0 as mandatory and enforceable.391

1498. We disagree with ISO/RTO Council and others that approval or enforcement of 

PRC-009-0 is linked to approval of PRC-006-0. PRC-009-0 ensures that the performance 

of a UFLS system is analyzed and documented following an underfrequency event by 

requiring the transmission owner, transmission operator, LSE, and distribution provider 

to document the deployment of their UFLS operations. PRC-006-0 requires each 

regional reliability organization to develop, coordinate and document a UFLS program 

that includes specified elements. We proposed to neither approve nor remand PRC-006-0 

because it applies to a regional reliability organization and the Commission was not 

persuaded that a regional reliability organization’s compliance with a Reliability Standard 

can be enforced as NERC proposed.392 That is not the case with PRC-009-0, which 

applies to transmission owners, transmission operators, LSEs and distribution providers 

with UFLS systems. Since PRC-009-0 is an existing Reliability Standard that has been 

followed on a voluntary basis, entities are aware whether they are required to have a 

UFLS program in place. Reporting on their UFLS programs therefore should not be 

burdensome. As stated in the Common Issues section, a reference to an unapproved 

Reliability Standard may be considered in an enforcement action, but is not a reason to 

delay approving and enforcing this Reliability Standard. The Commission expects this 

documentation will be sent to the Regional Entities (instead of the regional reliability 

organizations) after they are approved. 

j. Assessment of the Design and Effectiveness of UVLS 

Program (PRC-010-0)

1499. PRC-010-0 requires transmission owners, transmission operators, LSEs and 

distribution providers to periodically conduct and document an assessment of the 

effectiveness of their UVLS program at least every five years or as required by changes 

 391 NOPR at P 877-80. 

392 NOPR at P 56-57. 
Docket No. RM06-16-000 - 392 - 

in system conditions. The assessment must be conducted with the associated 

transmission planner and planning authority. 

1500. In the NOPR, the Commission proposed to approve Reliability Standard PRC010-0 as mandatory and enforceable. In addition, the Commission proposed to direct 

NERC to submit a modification to PRC-010-0 that requires that an integrated and 

coordinated approach be included in all protection systems on the Bulk-Power System, 

including generators and transmission lines, generators’ low voltage ride-through 

capabilities and UFLS and UVLS programs. 

1501. The Commission commends the initiative and efforts that have been taken by 

NERC and the industry in addressing UVLS requirements as recommended by the 

Blackout Report. 

i. Comments

1502. APPA agrees that PRC-010-0 should be approved. While APPA agrees that 

NERC should re-examine this Reliability Standard to determine whether a more 

integrated and coordinated approach should be included in protection systems on the 

Bulk-Power System, it also asks the Commission not to require a specific approach to 

UVLS and other protection systems. According to APPA, NERC should strive for 

greater consistency on an Interconnection-wide basis through the use of a coordinated 

protection system for the Bulk-Power System in each Interconnection. 

1503. ISO-NE generally supports approval of PRC-010-0, but opposes the 

Commission’s directive to modify the Reliability Standard to include an integrated and 

coordinated approach in all protection systems, particularly for UVLS and UFLS 

programs, because such integration cannot be technologically accomplished. 

1504. FirstEnergy indicates that UVLS is primarily designed to address localized 

problems, and requiring the universal coordination of UVLS across the grid does not 

make sense. FirstEnergy states that it is not clear what type of coordination would be 

useful for a UVLS program. 

 393 “Recommend that NERC determine the goal and principles needed to establish 

an integrated approach to relay protection for generators and transmission lines and the 

use of underfrequency and undervoltage load shedding programs.” Blackout Report at 

159 
Docket No. RM06-16-000 - 393 - 

ii. Commission Determination

1505. We agree with APPA’s comments and reiterate that the directed modification 

should be developed in the Reliability Standards development process. With regard to 

APPA’s concerns, while we direct the ERO to develop modifications that would require 

an integrated and coordinated approach to protection systems, we do not direct a specific 

approach to accomplish such integration and coordination. Rather, the ERO should 

develop an appropriate approach utilizing the Reliability Standards development process. 

1506. With regard to ISO-NE’s disagreement on integration of various system 

protections “because such integration cannot be technologically accomplished”, we note 

that the evidence collected in the Blackout Report indicates that “the relay protection 

settings for the transmission lines, generators and underfrequency load shedding in the 

northeast may not be entirely appropriate and are certainly not coordinated and integrated 

to reduce the likelihood and consequence of a cascade – nor were they intended to do so.” 

In addition, the Blackout Report stated that one of the common causes of major outages 

in North America is a lack of coordination on system protection. The Commission agrees 

with the protection experts who participated in the investigation, formulated Blackout 

Recommendation No. 21 and recommended that UVLS programs have an integrated 

approach.393 

1507. Regarding FirstEnergy’s question of whether universal coordination among UVLS 

programs that address local system problems makes sense, we believe that PRC-010-0’s 

objective in requiring an integrated and coordinated approach is to address the possible 

adverse interactions of these protection systems among themselves and to determine 

whether they could aggravate or accelerate cascading events. We do not believe this 

Reliability Standard is aimed at universal coordination among UVLS programs that 

address local system problems. 

1508. As identified in the NOPR,394 NERC is continuing to develop 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. 

1509. We appreciate MEAG’s feedback to our response in the NOPR. For the reasons 

discussed in the NOPR,395 as well as our explanation above, the Commission approves 

Reliability Standard PRC-010-0 as mandatory and enforceable. In addition, the 

 394 NOPR P 883. 

395 Id. P 891-92. 
Docket No. RM06-16-000 - 394 - 

Commission directs the ERO to develop a modification to PRC-010-0 through the 

Reliability Standards development process that requires that an integrated and 

coordinated approach be included in all protection systems on the Bulk-Power System, 

including generators and transmission lines, generators’ low voltage ride-through 

capabilities, and UFLS and UVLS programs. 

k. UVLS System Maintenance and Testing (PRC-011-0)

1510. PRC-011-0 requires transmission owners and distribution providers to implement 

their UVLS equipment maintenance and testing programs and provide program results to 

regional reliability organizations. 

1511. In the NOPR, the Commission proposed to approve PRC-011-0 as mandatory and 

enforceable. In addition, the Commission proposed to direct NERC to 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 relay type and the potential impact on the Bulk-Power System. 

i. Comments

1512. APPA suggests that, instead of a Commission directive, NERC should be directed 

to consider whether this standard is needed to address the Commission’s concern about 

periodic testing of UVLS equipment. 

1513. FirstEnergy comments that NERC should establish a maximum maintenance 

interval for protection system equipment, and a “national limitation taking into account 

both relay type and functional versus calibration testing.” Entergy states that it does not 

object to NERC’s development of maximum allowable maintenance intervals for the 

purpose of evaluating protection system and control programs. 

ii. Commission Determination

1514. The Commission approves Reliability Standard PRC-011-0 as mandatory and 

enforceable. In addition, we direct the ERO to develop modifications to the Reliability 

Standard through the Reliability Standards development process as discussed below. 

1515. The Commission disagrees with APPA that the decision whether a modification is 

needed should be established first by the ERO in its Reliability Standards development 

process. Our direction identifies an appropriate goal necessary to assure the reliable 

operation of the Bulk-Power System. The details should be developed through the 

Reliability Standards development process. 
Docket No. RM06-16-000 - 395 - 

1516. The Commission believes that the proposal is presently part of the process. The 

Commission approves Reliability Standard PRC-011-0 as mandatory and enforceable. In 

addition, the Commission directs the ERO to submit a modification to PRC-011-0 

through the Reliability Standards development process 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. 

l. Special Protection System Review Procedure (PRC-012-0)

1517. PRC-012-0 requires regional reliability organizations to ensure that all special 

protection systems396 are properly designed, meet performance requirements and are 

coordinated with other protection systems. In the NOPR, the Commission identified 

PRC-012-0 as a fill-in-the-blank standard. The NOPR stated that because the regional 

review procedures on special protection systems have not been submitted, the 

Commission would not propose to approve or remand PRC-012-0 until the ERO submits 

the additional information. 

i. Comments

1519. APPA agrees with the Commission’s proposed course of action. It further 

suggests that NERC, in completing PRC-012-0, should strive for greater consistency on 

an Interconnection-wide basis through the use of “base procedures” for each 

Interconnection. 

ii. Commission Determination

1520. For the reasons stated in the NOPR, the Commission will not approve or remand 

PRC-012-0. The ERO should consider APPA’s suggestions in the Reliability Standards 

development process. 

 

396 A special protection system is designed to automatically take corrective actions 

to protect a particular system under both abnormal and predetermined conditions, 

excluding the coordinated tripping of circuit breakers to isolate faulted components, 

which is typically the purpose of other protection devices. 
Docket No. RM06-16-000 - 396 - 

m. Special Protection System Database (PRC-013-0)

1521. 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 information on special 

protection systems. 

1522. In the NOPR, the Commission identified PRC-013-0 as a fill-in-the-blank 

standard. The NOPR stated that because the regional procedures on maintaining special 

protection system databases have not been submitted, the Commission would not approve 

or remand PRC-013-0 until the ERO submits the additional information. 

i. Comments

1523. APPA agrees with the Commission’s proposed course of action. It suggests 

further that in completing PRC-013-0, NERC should strive for greater consistency on an 

Interconnection-wide basis through the use of “base procedures” for each 

Interconnection. 

ii. Commission Determination

1524. For the reasons stated in the NOPR, the Commission will not approve or remand 

PRC-013-0. The ERO should consider APPA’s suggestions in the Reliability Standards 

development process. 

n. Special Protection System Assessment (PRC-014-0)

1525. 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 

and compliance with NERC Reliability Standards and effectiveness of special protection 

systems at least once every five years. 

1526. In the NOPR, the Commission identified PRC-014-0 as a fill-in-the-blank 

Reliability Standard. The NOPR stated that because the regional procedures on special 

protection system assessment had not been submitted, the Commission would not 

propose to approve or remand PRC-014-0 until the ERO submitted the additional 

information. 

i. Comments

1527. APPA agrees with the Commission’s proposed course of action. It suggests 

further that in completing PRC-014-0, NERC should strive for greater consistency on an 
Docket No. RM06-16-000 - 397 - 

Interconnection-wide basis through the use of “base procedures” for each 

Interconnection. 

ii. Commission Determination

1528. For the reasons stated in the NOPR, the Commission will not approve or remand 

PRC-014-0. The ERO should consider APPA’s suggestions in the Reliability Standards 

development process. 

o. Special Protection System Data and Documentation 

(PRC-015-0) 

1529. Proposed Reliability Standard PRC-015-0 requires transmission owners, generator 

owners and distribution providers to maintain a listing, retain evidence of review and 

provide documentation of existing, new or functionally modified special protection 

systems. 

1530. In the NOPR, the Commission proposed to approve PRC-015-0 as mandatory and 

enforceable. 

i. Comments

1531. APPA agrees that PRC-015-0 is sufficient for approval as a mandatory Reliability 

Standard. However, it states that this Reliability Standard cannot be enforced until two 

pending Reliability Standards, PRC-012-0 and PRC-013-0, become effective. Similarly, 

ISO/RTO Council and ISO-NE contend that the Commission should not approve PRC15-0 until it approves PRC-012-0 and PRC-013-0, identified by the Commission as fillin-the-blank standards. 

ii. Commission Determination

1532. We disagree with APPA, ISO/RTO Council and ISO-NE and conclude that PRC015-0 should be approved and made enforceable on the effective date of this rulemaking. 

As mentioned above, PRC-012-0 and PRC-013-0 apply solely to regional reliability 

organizations. PRC-012 is “process” oriented, as it requires the regional reliability 

organization to develop a review procedure that identifies information relevant to the 

regional reliability organization review of a special protection system. PRC-013-0 

requires the regional reliability organization to maintain a database of information on 

special protection systems. PRC-015-0 requires a transmission owner, generator owner 

or distribution provider that owns a special protection system to maintain a list and 

provide data for existing and planned special protection systems as defined in PRC-013-

0; and have evidence that the entity reviewed new or functionally modified special 

protection systems in accordance with the regional reliability organization procedures 
Docket No. RM06-16-000 - 398 - 

identified in PRC-012-0. As stated in the Common Issues section, a reference to an 

unapproved Reliability Standard may be considered in an enforcement action, but is not a 

reason to delay approving and enforcing this Reliability Standard. The Commission 

expects that the data will be sent to the Regional Entities (instead of the regional 

reliability organizations) after they are approved. 

1533. For the reasons discussed in the NOPR and above, the Commission concludes that 

Reliability Standard PRC-015-0 is just, reasonable, not unduly discriminatory or 

preferential and in the public interest and approves it as mandatory and enforceable. 

p. Special Protection System Misoperations (PRC-016-0)

1534. PRC-016-0 requires transmission owners, generator owners and distribution 

providers to provide the regional reliability organization with documentation, analyses 

and corrective action plans for misoperation of special protection systems. 

1535. In the NOPR, the Commission proposed to approve Reliability Standard PRC016-0 as mandatory and enforceable. In addition, the Commission proposed to direct 

NERC to submit a modification to PRC-016-0 that includes a requirement that 

maintenance and testing of these special protection system programs be carried out within 

a maximum allowable interval that is appropriate for the type of relays used and the 

impact of these special system protection systems on the reliability of the Bulk-Power 

System. 

i. Comments

1536. While APPA agrees that PRC-016-0 is sufficient for approval as a mandatory 

Reliability Standard, APPA, ISO/RTO Council and ISO-NE state that PRC-016-0 cannot 

be enforced until pending Reliability Standard PRC-012-0 has become effective. 

1537. FirstEnergy suggests that NERC clarify and provide guidance to transmission 

operators on the types of misoperations that have Interconnection-wide impacts and the 

types of misoperations that need reporting. 

ii. Commission Determination

1538. PRC-016-0 states that transmission owners, generator owners and distribution 

providers that own a special protection system must analyze the system operations and 

maintain a record of misoperations in accordance with the review procedure specified in 

PRC-012-0. As we explained above in the context of PRC-015-0, applicable entities are 

expected to comply with PRC-015-0, and the procedures specified in PRC-012-0 will 

continue to be maintained by the regional reliability organizations pursuant to the ERO 

Rules of Procedure and the Commission’s reliability information provision. We disagree 
Docket No. RM06-16-000 - 399 - 

with APPA, ISO/RTO Council and ISO-NE and conclude that PRC-016-0 is enforceable 

as of the effective date of this rulemaking. As stated in the Common Issues section, a 

reference to an unapproved Reliability Standard may be considered in an enforcement 

action, but is not a reason to delay approving and enforcing this Reliability Standard. 

The Commission expects that the plans will be sent to the Regional Entities (instead of 

the regional reliability organizations) after they are approved. 

1539. The Commission concludes that Reliability Standard PRC-016-0 is just, 

reasonable, not unduly discriminatory or preferential, and in the public interest, and 

approves it as mandatory and enforceable. We observe that a maximum allowable 

interval for maintenance and testing of special protection systems is not relevant to PRC016-0, where the primary purpose is to analyze and report all misoperations of special 

protection systems. The Commission, therefore, will not adopt the proposal to require the 

ERO to modify PRC-016-0 to include a requirement for a maximum allowable interval 

for maintenance and testing. 

1540. The Commission concludes that Reliability Standard PRC-016-0 is just, 

reasonable, not unduly discriminatory or preferential and in the public interest, and 

approves it as mandatory and enforceable. 

q. Special Protection System Maintenance and Testing 

(PRC-017-0)

1541. PRC-017-0 requires transmission owners, generator owners and distribution 

providers to provide the regional reliability organization with documentation of special 

protection system maintenance, testing and implementation plans. 

1542. In the NOPR, the Commission proposed to approve PRC-017-0 as mandatory and 

enforceable. In addition, the Commission proposed to direct NERC to submit a 

modification to PRC-017-0 that: (1) includes a requirement that maintenance and testing 

of these special protection system programs must be carried out within a maximum 

allowable interval that is appropriate to the type of relaying used and (2) identifies the 

impact of these special protection system programs on the reliability of the Bulk-Power 

System. 

i. Comments 

1543. APPA agrees that PRC-017-0 is sufficient for approval as a mandatory and 

enforceable Reliability Standard. It also agrees that NERC and the industry should 

consider adoption of maximum allowable maintenance intervals. With respect to the 

Commission’s second directive, APPA points out that the documentation of the test 
Docket No. RM06-16-000 - 400 - 

results will identify the impact of the special protection systems on the Bulk Electric 

System. 

1544. FirstEnergy states that NERC should establish a maximum maintenance interval 

for protective system equipment and a national limitation, taking into account both relay 

type and functional versus calibration testing. Entergy does not object to NERC’s 

development of maximum allowable maintenance intervals for the purpose of evaluating 

protection system and control programs. 

ii. Commission Determination

1545. The commenters agree with the Commission’s proposed directive on a maximum 

allowable interval for maintenance and testing of protection system equipment and we 

conclude that such a modification is beneficial. However, we agree with APPA’s view 

on our second proposed directive assuming that the documentation is requested by either 

the regional reliability organization or NERC. Therefore, we will modify our direction to 

require that the documentation be routinely provided to the ERO or Regional Entity and 

not only when it is requested. 

1546. The Commission approves Reliability Standard PRC-017-0 as mandatory and 

enforceable. In addition, the Commission directs the ERO to develop a modification to 

PRC-017-0 through the Reliability Standards development process, that includes: (1) a 

requirement that maintenance and testing of a protection system must be carried out 

within a maximum allowable interval that is appropriate for the type of the protection 

system and (2) a requirement that documentation identified in Requirement R2 shall be 

routinely provided to the ERO or Regional Entity. 

r. Disturbance Monitoring Equipment Installation and Data 

Reporting (PRC-018-1)

1547. PRC-018-1 ensures that disturbance monitoring equipment is installed and 

disturbance data is reported in accordance with comprehensive requirements. PRC-018-1 

contains several different effective dates for specific requirements. 

1548. In the NOPR, the Commission proposed to approve PRC-018-1 as mandatory and 

enforceable. 

i. Comments

1549. While APPA agrees that PRC-018-1 is sufficient for approval as a mandatory 

Reliability Standard, it contends that enforcement is not possible until PRC-002-0, a fillin-the-blank standard, is effective. For the same reason, ISO/RTO Council and ISO-NE 

state that the Reliability Standard should not be approved or remanded at this time. 
Docket No. RM06-16-000 - 401 - 

ii. Commission Determination

1550. The portion of PRC-018-1 that NERC proposes will become effective on the 

effective date of this Final Rule states that transmission owners and generator owners that 

own a disturbance monitoring system must assure that disturbance data is reported in 

accordance with PRC-002-1 to facilitate analyses of events. Applicable entities are 

expected to comply with PRC-018-1, and the procedures specified in PRC-002-1 will be 

provided pursuant to the data gathering provisions of the ERO’s Rules of Procedure and 

the Commission’s ability to obtain information pursuant to section 215 of the FPA and 

Part 39 of the Commission’s regulations. Accordingly, we disagree with APPA, 

ISO/RTO Council and ISO-NE and conclude that the effective portions of PRC-018-1 

are enforceable as of the effective date of this rulemaking. As stated in the Common 

Issues section, a reference to an unapproved Reliability Standard may be considered in an 

enforcement action, but is not a reason to delay approving and enforcing this Reliability 

Standard. 

1551. Accordingly, for reasons stated in the NOPR and above, the Commission approves 

Reliability Standard PRC-018-1 as mandatory and enforceable.

s. Undervoltage Load Shedding Program Database (PRC020-1)

1552. 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. 

1553. In the NOPR, the Commission identified PRC-020-1 as a fill-in-the-blank 

standard. The NOPR stated that because the regional procedures on maintaining UVLS 

databases have not been submitted, the Commission would not propose to approve or 

remand PRC-020-0 until the ERO submits the additional information. 

i. Comments

1554. APPA disagrees that PRC-020-1 is a regional fill-in-the-blank Reliability Standard 

because it does not require regional procedures. However, APPA recognizes that PRC020-1 requires the regional reliability organization to establish a database. 

ii. Commission Determination

1555. APPA is correct that the reason for not approving or remanding this Reliability 

Standard is because it applies solely to the regional reliability organization, and not 

because it is a fill-in-the-blank standard. For this reason, the Commission will not 

approve or remand PRC-020-1. 
Docket No. RM06-16-000 - 402 - 

t. Undervoltage Load Shedding Program Data (PRC-021-1)

1556. 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 their 

systems and other related protection schemes to their regional reliability organization’s 

database. 

1557. In the NOPR, the Commission proposed to approve PRC-021-1 as mandatory and 

enforceable. 

i. Comments

1558. APPA agrees that PRC-021-1 should be approved as a mandatory and enforceable 

Reliability Standard. 

1559. The ISO-NE and ISO/RTO Council contend that the Commission should refrain 

from approving PRC-021-1 until it approves PRC-020-1 which the Commission has not 

approved or remanded. 

ii. Commission Determination

1560. For the reasons stated in the NOPR and above, the Commission approves PRC021-1 as mandatory and enforceable. The referenced information will be provided 

pursuant to the data gathering provisions of the ERO’s rules of procedure and the 

Commission’s ability to obtain information pursuant to section 215 of the FPA and Part 

39 of the Commission’s regulations. As stated in the Common Issues section, a reference 

to an unapproved Reliability Standard may be considered in an enforcement action, but is 

not a reason to delay approving and enforcing this Reliability Standard. 

u. Undervoltage Load Shedding Program Performance 

(PRC-022-1)

1561. PRC-022-1 requires transmission operators, LSEs, and distribution providers to 

provide analysis, documentation and misoperation data on UVLS operations to the 

regional reliability organization. 

1562. In the NOPR, the Commission proposed to approve PRC-022-1 as mandatory and 

enforceable. 

i. Comments

1563. APPA agrees that PRC-022-1 should be approved as a mandatory and enforceable 

Reliability Standard. 
Docket No. RM06-16-000 - 403 - 

1564. FirstEnergy comments that Requirement R1.3 requires “a simulation of the event, 

if deemed appropriate by the RRO” and believes that the applicable entities such as 

transmission operators may not be able to simulate large system events. FirstEnergy 

suggests that Requirement R1.3 be revised to state that “a simulation of the event, if 

deemed appropriate, and assisted by the [regional reliability organization].” 

ii. Commission Determination

1565. For the reasons discussed in the NOPR, the Commission concludes that Reliability 

Standard PRC-022-1 is just, reasonable, not unduly discriminatory or preferential, and in 

the public interest and approves it as mandatory and enforceable. 

1566. The Commission directs the ERO to consider FirstEnergy’s suggestion in the 

Reliability Standards development process. 

11. TOP: Transmission Operations 

1567. The eight 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. 

a. Reliability Responsibilities and Authorities (TOP-001-1)

1568. The reliability goal of TOP-001-1 is to ensure that system operators have the 

authority to take actions and direct others to take action to maintain Bulk-Power System 

facilities within operating limits. TOP-001-1 requires that: (a) 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 LSE to take emergency actions when directed to do so in order to keep the 

transmission system intact. 
Docket No. RM06-16-000 - 404 - 

1569. The Commission proposed in the NOPR to approve the Reliability Standard as 

mandatory and enforceable and to direct NERC to submit a modification to it that 

includes Measures and Levels of Non-Compliance. On November 15, 2006, NERC 

submitted revisions to the Reliability Standard to include Measures and Levels of NonCompliance.397

i. Comments

1570. APPA notes that TOP-001-1, as revised to include Measures and Levels of NonCompliance, fulfills the proposed directive in the NOPR. Accordingly, APPA agrees that 

the Commission should approve TOP-001-1 as mandatory and enforceable. 

1571. California PUC asserts that TOP-001 should not be adopted unless the 

Commission provides for proper deference to existing authorities. It states that the 

requirements contained in TOP-001 are duplicative of what the CAISO already requires 

under its participating generator agreements. 

1572. FirstEnergy contends that TOP-001-1 contains “reliability directives” to be 

followed by various entities, but it has no clear line of authority for specified directives. 

This could lead to a generator receiving conflicting directions. FirstEnergy maintains 

that TOP-001-1 should establish a clear line of authority for issuing and complying with 

directives, but the reliability coordinator’s instructions should govern in all instances. 

1573. In a similar vein, MEAG Power is concerned that the scope of “reliability 

directives” contained in the Measures filed on November 15, 2006 is unclear. For 

example, Measure M4 states that “[e]ach Balancing Authority, Generator Operator, 

Distribution Provider and Load Serving Entity shall have and provide upon request 

evidence that ... it complied with its Transmission Operator’s reliability directives.” 

While a directive by a transmission operator to a LSE to increase its planning reserve 

margin from 15 percent to 20 percent or reconductor a transmission line might be within 

the realm of possibilities, such “reliability directives” would be inappropriate. MEAG 

Power therefore recommends an alternative definition of “reliability directive” that it 

believes would specify an appropriate range of directives. 

 397 In its November 15, 2006, filing, NERC submitted TOP-001-1, which 

supercedes the Version 0 Reliability Standard. TOP-001-1 adds Measures and Levels of 

Non-Compliance to the Version 0 Reliability Standard. In this Final Rule, we review the 

November version, TOP-001-1. 
Docket No. RM06-16-000 - 405 - 

1574. MEAG Power also recommends a modification to TOP-001-1 clarifying that an 

entity may be found non-compliant only if it fails to comply with a reliability directive 

issued to it by its host reliability coordinator. MEAG Power is concerned that the 

requirements as currently written may apply to entities outside a reliability coordinator’s 

footprint. 

1575. FirstEnergy and California Cogeneration state that the definition of “emergency” 

is vague and should be clarified. FirstEnergy states TOP-001 does not specify who 

decides when there is an emergency. California Cogeneration states that under 

emergency conditions, it would be appropriate to require a QF to follow the directives of 

a reliability coordinator.398 But California Cogeneration argues that because of the broad 

definition of emergency, reliability coordinators could issue directives on a regular basis. 

California Cogeneration therefore proposes that the Reliability Standard clearly address 

which entities are exempt from such directives because they have no material impact on 

reliability. 

1576. FirstEnergy states that the term “safety” in Requirement R4 should be clarified 

with respect to whether it means safety to the system/equipment, public safety or both. 

1577. Requirement R6 of TOP-001-1 requires an applicable entity to “render all 

available emergency assistance to others as requested.” Regarding this provision, 

FirstEnergy maintains that NERC should clarify that all instructions should be subject to 

the reliability coordinator’s direction and control to avoid causing unforeseen harm to 

other systems. Any entity requesting assistance must implement its emergency 

procedures before or in unison with assistance from other entities. However, FirstEnergy 

asserts that it is not clear how a responding entity will determine whether the requesting 

entity has implemented its comparable emergency procedures before the responding 

entity honors the request. FirstEnergy, therefore, states that TOP-001-1 should require 

the requesting party to report on whether all of its emergency procedures were 

implemented as part of its request for emergency assistance. 

1578. Santa Clara states that, in some instances, notifying the reliability coordinator that 

a transmission operator is removing facilities from service may not be appropriate 

because the transmission owner traditionally notifies the balancing authority. Santa Clara 

therefore requests that Requirements R7.2 and R7.3 of the Reliability Standard be revised 

 398 California Cogeneration notes that the curtailment of QFs in an emergency is 

allowed by 18 CFR 292.307. 
Docket No. RM06-16-000 - 406 - 

to provide that the transmission operator may notify the reliability coordinator or 

balancing authority.399 

ii. Commission Determination

1579. The Commission approves TOP-001-1 as mandatory and enforceable. We address 

the concerns raised by commenters below. 

1580. While the Commission agrees with APPA that TOP-001-1 should be approved, it 

does not agree that the new Measures and Levels of Non-Compliance fully address the 

Commission’s concerns stated in the NOPR. The modified Reliability Standard does not 

contain Measures or Levels of Non-Compliance corresponding to Requirement 8. This 

Requirement deals with actions to restore real and reactive power balance. Given the 

importance of these matters to reliable operations, the Commission directs the ERO to 

provide Measures and Level of Non-Compliance for this Requirement. 

1581. We disagree with California PUC’s assertion that the Commission should not 

adopt TOP-001-1 unless it commits to a policy of “appropriate deference” to existing 

authorities. Approval of a continent-wide Reliability Standard should not be delayed 

because it may overlap with a local or regional program. Rather, stakeholders should 

raise related concerns in the ERO Reliability Standards development process. Moreover, 

section 215(i)(3) of the FPA provides that “nothing in [section 215] shall be construed to 

preempt any authority of any State to take action to ensure the safety, adequacy, and 

reliability of electric service within that State, as long as such action is not inconsistent 

with any reliability standard.” In any event, California PUC does not suggest how the 

Requirements in TOP-001-1 and the provisions of CAISO’s participating generator 

agreements will lead to conflicting outcomes. To the extent a potential conflict arises, we 

note that the CAISO’s participating generator agreements are subject to Commission 

jurisdiction, and § 39.6 of the Commission’s regulations provides procedures for 

resolving conflicts between a requirement in a Reliability Standard and a provision of an 

agreement accepted for filing at the Commission.400 

1582. We agree with FirstEnergy that TOP-001-1 should establish a clear line of 

authority. Requirement R3 of Reliability Standard IRO-001-0 clearly establishes the 

decision-making authority of the reliability coordinator to act and to direct actions to be 

 399 Santa Clara makes a similar argument reagarding Requirement R3 of TOP-008-

1. 

400 See 18 CFR 39.6 (Conflict of a Reliability Standard with a Commission Order). 
Docket No. RM06-16-000 - 407 - 

taken by operating entities to preserve the integrity and reliability of the Bulk-Power 

System. When an entity is faced with conflicting directives, it must follow the reliability 

coordinator’s directives because the reliability coordinator is the highest authority in 

matters affecting reliability of the Bulk-Power System. Therefore no changes are 

required to the Reliability Standard in this connection. 

1583. We agree with MEAG Power that a reliability directive to a LSE to increase its 

planning reserve to 15 percent or to reconductor its transmission line is outside the scope 

of a TOP reliability directive. Reliability directives in the TOP group of Reliability 

Standards deal with operational directives and not planning directives. 

1584. We disagree with MEAG Power that an entity may have to comply with a 

reliability directive issued to it by a reliability coordinator other than its host reliability 

coordinator. The operating hierarchy embodied in the Reliability Standard gives the 

reliability coordinator responsibility and authority to issue reliability directives to its own 

transmission operators, balancing authorities and generator operators. These entities 

must comply with these directives as stated in Requirement R3 in TOP-001-1.401 An 

entity is only responsible for following directives from its host reliability coordinator 

unless authority is delegated to another reliability coordinator by the host reliability 

coordinator. 

1585. We agree with FirstEnergy and California Cogeneration that the definition of 

“emergency” could be further clarified. We discuss this issue in this Final Rule in 

connection with Reliability Standard EOP-001-0 and conclude that emergency states 

need to be defined and that criteria for entering these states and authority for declaring 

them need to be specified. We therefore direct the ERO to modify the Reliability 

Standard accordingly. With respect to California Cogeneration’s argument regarding 

exemptions from the requirement to respond to emergencies, the reliability coordinator 

must be in a position to take all necessary actions in response to an emergency and is in 

the best position to determine which entities should respond to its directives. 

1586. In response to FirstEnergy’s request for clarification of the meaning of “safety” in 

the first sentence of Requirement R4, of TOP-001-1 and whether it refers to safety to the 

system/equipment, public safety or both, the Commission notes that each term in the 

 401 The Requirement states in part that “[e]ach Transmission Operator, Balancing 

Authority, and Generator Operator shall comply with reliability directives issued by the 

Reliability Coordinator. . . .” 
Docket No. RM06-16-000 - 408 - 

series set forth in this provision refers to a type of “requirement.”402 The provision 

clearly differentiates between the safety of persons and equipment requirements. Since 

equipment requirements are mentioned separately, safety must be read as referring to 

requirements related to safety of persons. 

1587. With regard to FirstEnergy’s proposal that the entity requesting emergency 

assistance be required to report that it has implemented all of its own emergency 

procedures as part of its request for emergency assistance, we believe that such reporting 

is not appropriate during an emergency situation. Requirement R6 of the Reliability 

Standard clearly specifies that entities must provide available emergency assistance 

provided the requesting entity has implemented its comparable emergency procedures. 

Given the nature of emergency situations where time is of the essence, compliance with 

this Requirement must be assessed after the fact as part of the compliance audit, and not 

during an emergency. 

1588. With respect to Santa Clara’s proposal that Requirements R7.2 and R7.3 be 

revised to provide that the transmission operator may notify the reliability coordinator or 

the balancing authority that it is removing facilities from service, the Commission directs 

the ERO to consider Santa Clara’s comments in the Reliability Standards development 

process. 

1589. Accordingly, the Commission approves Reliability Standard TOP-001-1. In 

addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the 

Commission directs the ERO to develop a modification to TOP-001-1 through the 

Reliability Standards development process that: (1) includes Measures and Levels of 

Non-Compliance for Requirement R8 and (2) considers adding other Measures and 

Levels of Non-Compliance in the Reliability Standard. 

b. Normal Operations Planning (TOP-002-2)

1590. Reliability Standard TOP-002-2 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 

Reliability Standard addresses the following matters: (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; 

 402 Requirement R4 states: “Each Distribution Provider ... shall comply with all 

reliability directives ... unless such actions would violate safety, equipment, regulatory or 

statutory requirements.” 
Docket No. RM06-16-000 - 409 - 

(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. 

1591. In the NOPR, the Commission proposed to approve the Reliability Standard as 

mandatory and enforceable. In addition, the Commission proposed to direct that NERC 

submit a modification 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 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.403

1592. The Commission also proposed to interpret Requirement R7 of the Reliability 

Standard as requiring that each balancing authority plan to meet capacity and energy 

reserve requirements, including deliverability/capability for any single contingency. 

Although the NERC glossary defines “contingency,”404 the Commission expressed 

concern in the NOPR that the phrase “single contingency” is open to interpretation, and 

“deliverability” is not defined. The Commission proposed in the NOPR to interpret 

contingency as discussed in connection with the TPL Reliability Standards 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. 

i. Comments

1593. APPA states that NERC has added Measures for many but not all of the 

Requirements of TOP-002-2 and needs to develop Measures for Requirements R2, R3, 

R4, R12 and R17. 

 403 In its November 15, 2006, filing, NERC submitted TOP-002-2, which 

supercedes the earlier Reliability Standard. TOP-002-2 adds Measures and Levels of 

Non-Compliance to the Reliability Standard, and includes a modified Requirement R14. 

In this Final Rule, we review the November version, TOP-002-2. 

404 NERC 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.” NERC Glossary at 3. 
Docket No. RM06-16-000 - 410 - 

1594. Entergy and MidAmerican support the Commission’s proposal to delete references 

to confidentiality agreements from the requirements and state that different approaches 

must be explored to preserve the confidentiality of data. MidAmerican adds that NERC 

should adopt an administrative approach to keep the confidential information from being 

disclosed before the confidentiality provisions are deleted from the requirements. LPPC 

asks the Commission to clarify that CEII remains confidential and states that without 

such clarification there is a danger that sensitive information related to the Bulk-Power 

System will become public. 

1595. FirstEnergy and Entergy express concerns regarding identifying all control actions 

in 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. 

They contend that system conditions can change significantly between day-ahead 

analysis and real-time operations, rendering potential control actions irrelevant. 

Therefore they state that operating entities should be held harmless for not having listed 

in advance control actions taken in the face of real-time contingencies resulting from 

unpredicted changing system conditions. APPA states that such requirements are not 

necessary given that system operators use state estimators and other tools to identify 

effective control actions that produce more accurate results than would be achieved 

through the proposed day-ahead analysis. APPA and Entergy assert that it should be left 

to NERC, as the technical expert charged with setting standards, to decide in the first 

instance whether such day-ahead analysis would be of sufficient benefit to justify 

requiring it. 

1596. MidAmerican is concerned that the Commission’s proposal to interpret the phrase 

“single contingency” as a contingency that includes all multi-element pieces of the 

system that go out of service together in response to a single event is too restrictive on 

system operations. However, it also states that historically it has performed the studies in 

accordance with the Commission’s proposal and will support that proposal in the interest 

of reliability. MidAmerican notes that where a multiple-element single contingency 

traverses neighboring systems, such contingencies must be coordinated with other 

systems. Further, it contends that the Commission’s directive to have operating plans to 

meet any scheduled change in system configuration and generation dispatch seems 

burdensome if not impossible and requests clarification of the Commission’s intent in this 

connection. 

1597. ISO-NE recommends that the reference to “transmission service provider” in 

Requirement R12 of TOP-002-2 should be replaced by “transmission operator” and/or 
Docket No. RM06-16-000 - 411 - 

“transmission owner.”405 It claims that such a change would be consistent with the 

definition of the term “transmission service provider,” which the NERC glossary defines 

as: “[t]he entity that administers the transmission tariff and provides Transmission 

Service to Transmission Customers under applicable transmission service agreements.” 

In performing this function, the transmission service provider provides a business service 

that entails executing contractual agreements with its customers to provide open access 

transmission service, whereas SOLs and IROLs are technical in nature and do not 

translate into transmission service provider functions. In contrast, transmission operators 

and transmission owners perform planning and operations functions and will need SOL 

and IROL data. 

1598. NRC states that it is not clear whether TOP-002-2 considers the N-1 and the N-1-1 

criteria consistent with TPL-002-0 and TPL-003-0, respectively. NRC is concerned 

about verifying that the Bulk-Power System will provide the necessary voltages to the 

auxiliary power system busses after a nuclear power plant trip. It suggests that 

knowledge and verification of significant generator characteristics are essential to this 

end, especially verification of real and reactive capabilities, automatic voltage regulator 

status and operating limits. NRC also proposes various revisions to TOP-002-2. 

ii. Commission Determination 

1599. The Commission approves Reliability Standard TOP-002-2 as mandatory and 

enforceable. In addition, we direct the ERO to develop modifications to the Reliability 

Standard through the Reliability Standards development process as discussed below. 

1600. We are adopting our proposal regarding deletion of references to confidentiality 

agreements from the Requirements. As we explained in the NOPR, the effectiveness of a 

Reliability Standard should not be predicated upon the existence of a confidentiality 

agreement.406 The ERO should address the confidentiality provision separately to ensure 

that confidentiality of data is not compromised and CEII information remains 

confidential. 

 405 Requirement R12 provides: “The Transmission Service Provider shall include 

known SOLs and IROLs within its area and neighboring areas in the determination of 

transfer capabilities, in accordance with filed tariffs, and or regional Total Transfer 

Capability and Available Transfer Capability calculation processes.” 

406 NOPR at P 976. 
Docket No. RM06-16-000 - 412 - 

1601. As noted above, a number of commenters express concerns with the 

Commission’s proposal to require a next-day analysis for all IROLs to identify and 

communicate control actions to system operators. Identification and communication of 

control actions that can be implemented within 30 minutes are required to ensure that 

system operators are aware of and have options available to respond to system conditions 

following the first contingency to restore the system to a secure state so that it can 

withstand the next contingency. In addition, the control actions identified in the next-day 

analysis may quite often be relevant, and informing the system operators of the control 

options earlier on would be helpful. While the operators may take other actions to 

preserve the system, they need to have at least one plan (control actions) that will 

preserve the system from cascading. We believe this addresses FirstEnergy’s concern 

regarding whether compliance requires the use of only the control actions identified in 

the day-ahead analysis. In response to APPA’s comment on the use of state estimators 

and other tools to identify effective control actions, we note that this capability will help 

operators in assessing system responses, but they will not identify the control actions 

system operators will need to take in real-time. Further, operators may not be aware of 

available control actions, or worse they may not have any control actions, other than firm 

load-shedding, available to adjust the system after a first contingency occurs. Therefore, 

we direct the ERO to modify Reliability Standard TOP-002-2 to require 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. 

1602. With respect to NRC’s comments, system operators must operate the system in 

front of them at all times to be capable of withstanding a critical contingency (N-1) 

without resulting in instability, uncontrolled separation or cascading failures. After this 

N-1 contingency the operators must adjust the system as soon as possible and in no 

longer than 30 minutes so that the system can then withstand a new N-1 contingency. 

Further discussion of how this applies in the planning arena is presented in connection 

with the TPL group of Reliability Standards. 

1603. The Commission agrees with NRC that the minimum voltages at nuclear plant 

auxiliary power system buses should be assessed in next-day analysis to ensure that 

adequate voltages can be maintained in accordance with the nuclear plant minimum 

voltage requirements. If this assessment projects that the minimum voltage requirements 

cannot be met, the transmission operators or balancing authorities must notify the nuclear 

power plan as soon as possible, but in no event later than the commencement of the next 

day’s real-time operations. If during real-time operations the transmission operator 

cannot maintain the minimum voltage, pre or post contingency, it must inform the 

nuclear plant operator accordingly so that the appropriate corrective actions can be 

carried out by both the nuclear plant operator and the transmission operator. The 
Docket No. RM06-16-000 - 413 - 

Commission directs the ERO to modify Reliability Standard TOP-002-2 to address these 

two issues. 

1604. The Commission proposed in the NOPR that simulations must be consistent with 

the number of elements that will be removed from service as a result of the failure of a 

single element.407 MidAmerican states that it operates consistent with this proposal, in 

that it respects a single contingency as one that includes all multiple pieces of the 

elements that go out of service together in response to a single event. Even though 

MidAmerican states that the Commission’s proposal is too restrictive on system 

operation, it supports the proposal in the interest of reliability. To do otherwise would 

not represent what actually happens in real-time operations to the detriment of BulkPower System reliability, which demonstrates the need to approach the issue as we 

propose. We discuss this issue further in connection with a the TPL group of Reliability 

Standards, where we direct the ERO to modify the TPL Reliability Standards to simulate 

what actually happens in the physical system, including multiple element failures. 

1605. We note with regard to MidAmerican’s comment on operating plans to meet any 

scheduled change in system configuration and generation dispatch that we have not 

directed any action in this connection and therefore cannot provide any further 

clarification on this point. With regard to MidAmerican’s comment on coordinated 

efforts with neighboring systems to deal with multiple element single contingencies, we 

note that such coordination is already required by IRO and TOP Reliability Standards. 

1606. Commenters did not take issue with the proposed interpretation of the term 

“deliverability” as “the ability to deliver the output from generation resources to firm 

load without any reliability criteria violations for plausible generation dispatches.”408 

The Commission adopts this proposed interpretation. In order to ensure the necessary 

clarity, the term as used in Requirement R7 of TOP-002-2 should be understood in this 

manner. 

1607. With respect to the modifications to Requirement R12 of the Reliability Standard 

recommended by ISO-NE and NRC’s comments on Measure M7 and a new Measure 

M11, the Commission directs the ERO to consider these matters in the Reliability 

Standards development process. In response to NRC’s suggestion regarding periodic 

review of generators’ reactive capability, we note that Reliability Standard MOD-025-1 

already requires periodic review of generators’ reactive capability. 

 407 NOPR at P 979. 

408 Id. at P 974. 
Docket No. RM06-16-000 - 414 - 

1608. As we explained in the NOPR, TOP-002-2 serves an important purpose in 

ensuring that resources and operational plans are in place to enable system operators to 

maintain the Bulk-Power System in a reliable state. Further, the requirements set forth in 

the Reliability Standard are sufficiently clear and objective to provide guidance for 

compliance. Accordingly, the Commission approves Reliability Standard TOP-002-2. In 

addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the 

Commission directs the ERO to develop a modification to TOP-002-2 through the 

Reliability Standards development process that: (1) 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; (2) 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; (3) requires nextday analysis of minimum voltages at nuclear power plants auxiliary power busses and (4) 

requires simulation contingencies to match what will actually happen in the field. 

c. Planned Outage Coordination (TOP-003-0)

1609. Reliability Standard TOP-003-0 requires transmission operators that operate 

facilities greater than 100 kV, generator operators that operate facilities greater than 50 

MW 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. 

1610. The Commission proposed in the NOPR to approve Reliability Standard TOP003-0 as mandatory and enforceable. The Commission also proposed to direct NERC to 

submit a modification to TOP-003-0 that: (1) includes a requirement to communicate 

scheduled outages well in advance to ensure reliability and accuracy of ATC calculation 

and (2) makes any facility below the 100 kV or 50 MW 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. 

1611. In addition, the Commission noted in the NOPR that outage information is 

important to both reliable operation and to the calculation of ATC. 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 affected transmission operators and reliability coordinators with 

sufficient lead time to coordinate outages. The Commission then requested industry 

input on what constitutes sufficient lead time for planned outages. 
Docket No. RM06-16-000 - 415 - 

i. Comments

1612. MRO, APPA and others raise concerns requiring the proposed requirement to 

communicate scheduled outages “well in advance.” APPA cautions that TOP-003-0 was 

generally designed to ensure that transmission operators receive accurate and timely 

information about transmission and generation outages affecting “next-day operations,” 

rather than the longer term outage planning information. MRO states that requiring outage 

information well in advance reduces the entity’s flexibility for other contingencies and 

changes. MRO also contends that the phrase “well in advance” is vague, not measurable, 

and may not be enforced fairly and consistently. FirstEnergy states that NERC should 

specify the meaning of “well in advance” through its Reliability Standards development 

process with industry input. MRO recommends that the time period for outage 

notification should be based on the size of the generating facility and voltage level of the 

transmission line so that a larger facility has a longer lead time for outage notification. 

1613. While MISO agrees with the need for early notification of planned outages, it is 

concerned that an arbitrary lead time will cause entities to postpone needed maintenance 

to accommodate the timeline, thereby reducing the reliability of the Bulk-Power System. 

1614. LPPC states that business reasons often drive a longer lead time for outage 

planning to allow market participants to better understand the congestion and market 

impacts of the planned outage. LPPC believes that the Commission should exercise 

caution and avoid adopting a business practice as part of the Reliability Standard. 

Reliability concerns often dictate that an outage should not be planned and set in stone 

too far in advance because the circumstances may change. According to LPPC, the 

Commission should refrain from prescribing a lead time that would cut into an operator’s 

flexibility, which is needed to respond to real-time situations. 

1615. In response to the Commission’s question regarding the lead time for planned 

outages, MidAmerican states that although it believes that a requirement for extending 

the lead time will result in higher costs and less flexibility, a two-week advance notice for 

planned outages of 345 kV facilities and one-week advance notice for 161 and 69 kV 

facilities is appropriate. TVA proposes one-week advance notice for all planned outages 

and recommends that TOP-003-0 should be modified to include breaker outages within 

the meaning of the facilities that are subject to advance notice for planned outages. 

1616. CAISO states that its current tariff provides for three days of lead time for 

providing outage information and that this is a standard practice throughout WECC. It 

maintains, however, that the three-day lead time is not sufficient for the needed review 

and coordination of outages. In fact, CAISO states that many ISOs and RTOs are 

moving toward a lead time of either 30 days or 45 days prior to the beginning of the 

outage month. CAISO contends that rather than basing the outage information on a 
Docket No. RM06-16-000 - 416 - 

certain kV level, the emphasis should be on facilities that may have a significant effect on 

congestion revenue rights resource adequacy. 

1617. Entergy and FirstEnergy support the proposed modification to include 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 the 

Bulk-Power System subject to Requirement R1 for planned outage coordination. They 

maintain that such a modification will provide the transmission operator much needed 

flexibility. APPA, on the other hand, opposes the proposal. APPA states that the 

Commission should allow the ERO in the first instance to consider whether to add this 

specific requirement to TOP-003-0. If the Commission is concerned that TOP-003-0 as it 

now stands might “not include all facilities that have a significant impact on the operation 

of the Bulk-Power System,” it should direct NERC to consider that issue on remand 

using its Reliability Standards development process. 

1618. Xcel notes that Requirement R4 of the Reliability Standard provides that each 

reliability coordinator should resolve any potential conflicts in scheduling of planned 

outages. Xcel argues that if a reliability coordinator requires an entity to move its 

planned outage to accommodate another entity’s unplanned outage, the entity that agrees 

to move its planned outage to another time should receive compensation. 

ii. Commission Determination

1619. The Commission approves TOP-003-0 as mandatory and enforceable. We address 

the concerns raised by commenters below. 

1620. In Order No. 890, the Commission directed that information concerning ATC 

calculations be consistent and transparent.409 The timing of facility outages is one 

important piece of information in ATC calculations. In Order No. 890, the Commission 

directed that specific data be exchanged among transmission providers, including 

transmission planned and contingency outages, for the purpose of ATC modeling.410 

Consistent with this determination in Order No. 890, the Commission directs the ERO to 

develop a modification to TOP-003-0 that requires the communication of scheduled 

outages to all affected entities well in advance to ensure reliability and accuracy of ATC 

 409 See Order No, 890 at P 68-69, 207-213. 

410 Id. at P 292. 
Docket No. RM06-16-000 - 417 - 

calculations.411 We believe this addresses LPPC’s concern regarding the interplay 

between reliability and business practices. 

1621. Several commenters raised concerns regarding the Commission’s proposal to 

require outage information well in advance. Specifically, they argue that the term “well 

in advance” is vague, that the requirement would reduce flexibility and that it would 

cause entities to postpone needed maintenance work, thereby reducing reliability. In 

response to the Commission’s request for comments on lead time for planned outages, 

entities provide information on current lead time practices indicating that lead times 

range from one week to 45 days. We direct the ERO to modify the Reliability Standard 

to incorporate an appropriate lead time for planned outages. The ERO should utilize the 

information filed by commenters in the Reliability Standards development process. In 

doing so the ERO should take into consideration the need for flexibility, as well the lead 

time required for coordination with other entities and outage assessments. Proper 

coordination will ensure that priority is given to needed maintenance work for critical 

facilities to ensure reliability. 

1622. With regard to TVA’s request to include breaker outages within the meaning of 

the facilities that are subject to advance notice for planned outages, we direct the ERO to 

consider this suggestion in the Reliability Standards development process. 

(a) Applicability 

1623. As noted above, the Commission proposed to direct the ERO to modify TOP-003-

0 to make 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. 

1624. Entergy and FirstEnergy support the proposed modification to include any facility 

below the threshold that in the opinion of the reliability coordinator, balancing authority 

or transmission operator will have a direct impact on the operation of the Bulk-Power 

 411 The Commission notes that PJM has developed an outage scheduling process in 

response to Commission directives to avoid the possibility of undue discrimination. 

http://www.pjm.com/committees/mrc/downloads/20060630-item-06-draft-manual-14bchanges.pdf The outage scheduling process was developed through a stakeholder process 

and has been utilized in the entire PJM footprint for a number of years. PJM’s outage 

scheduling program is one example of the type of program that should be implemented 

through the Reliability Standard. 
Docket No. RM06-16-000 - 418 - 

System. On the other hand, APPA opposes this proposal and contends that the 

Commission should allow the ERO, as the expert entity charged with developing 

Reliability Standards, to consider whether to add this specific requirement. The 

Commission disagrees because registered entities below the thresholds currently defined 

in Requirement R1 of the Reliability Standard may have an impact on reliability and 

therefore should be required to submit data on their planned outages. The Commission 

therefore directs the ERO to modify the Reliability Standard to require that 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 reliability of the 

Bulk-Power System be subject to Requirement R1 for planned outage coordination. 

(b) Other Issues 

1625. In response to Xcel’s proposal that entities that agree to reschedule their 

previously-approved planned outages to accommodate another entity’s unplanned outage 

be compensated, the Commission notes that whereas rescheduling of the outage is a 

reliability matter, compensation is not and therefore is outside the scope of this 

proceeding. 

(c) Summary of Commission Determination

1626. Planned outage coordination is a necessary element of reliable operations, and 

TOP-003-0 promotes that goal. Accordingly, the Commission approves the Reliability 

Standard as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the 

FPA and § 39.5(f) of our regulations, the Commission directs the ERO to develop a 

modification to TOP-003-0 through the Reliability Standards development process that: 

(1) includes a new requirement to communicate longer term outages well in advance to 

ensure reliability and accuracy of ATC calculation; (2) makes any facility below the 

voltage 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 and (3) incorporates 

an appropriate lead time for planned outages as discussed above. 

d. Transmission Operations (TOP-004-1)

1627. This Reliability Standard requires transmission operators to operate the 

transmission system within SOL and IROL.412 The N-1 operating criterion for the 

 412 In its November 15, 2006, filing, NERC submitted TOP-004-1, which has an 

effective date of October 1, 2007, at which time it will supercede the Version 0 

Reliability Standard. TOP-004-1 adds Measures and Levels of Non-Compliance to the 

(continued) 
Docket No. RM06-16-000 - 419 - 

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 goal of the Reliability Standard 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. 

1628. The Commission proposed in the NOPR to approve the Reliability Standard as 

mandatory and enforceable. In addition, the Commission proposed to direct that NERC 

submit a modification that: (1) includes Measures and Levels of Non-Compliance; (2) 

clarifies that the system should be restored as soon as possible, taking no more than 30 

minutes and (3) defines high risk conditions under which the system must be operated to 

respect multiple outages in Requirement R3. The Commission also proposed to direct the 

ERO to perform a survey of the prevailing operating practices and actual operating 

experiences surrounding drifting in and out of IROL limits. 

1629. Requirement R3 requires that each transmission operator shall, when practical, 

operate the system to respect multiple outages as specified by the regional reliability 

organization policy. The Commission noted in the NOPR that Requirement R3 does not 

define conditions under which multiple outages must be considered. The NOPR 

proposed to 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 

multiple outages approaches that of a single element outage.”413 

i. Comments

1630. PG&E and APPA oppose a modification to the Reliability Standard that changes 

the requirement allowing operators to return the system to a reliable operating state 

within 30 minutes to a requirement that they do so as soon as possible and in no longer 

than 30 minutes. PG&E is concerned that during emergencies operators would be subject 

to uncertainty in complying with such a requirement, which could lead to overly hasty 

responses with a corresponding detrimental effect on reliability. PG&E states that to 

avoid the confusion and ambiguity from a subjective standard, the Commission and 

NERC should only clarify that operators should seek to return the system to a reliable 

operating state as soon as possible, but maintain the current requirement of 30 minutes as 

stated in Requirement R4 of TOP-004-1. APPA states that if the Commission is 

 

Version 0 Reliability Standard. Because TOP-004-0 will be in effect until October 1, 

2007 and TOP-004-1 thereafter, we address both versions of the Reliability Standard. 

413 NOPR at P 997. 
Docket No. RM06-16-000 - 420 - 

concerned about the need to require a response time that is quicker than 30 minutes, it 

should direct the ERO to consider this issue as part of the Reliability Standards 

development process. 

1631. Entergy and MidAmerican support the Commission’s proposal to have NERC 

conduct a survey and report the operating practices and actual experiences surrounding 

drifting in and out of IROL violations. MISO, on the other hand, opposes the survey 

because there are already requirements for reporting IROL violations elsewhere in the 

Reliability Standards. APPA proposes that the Commission should ask the ERO to 

determine if such information would improve reliable operations. If it is determined that 

such information will improve reliability, NERC should include this type of information 

in compliance violation reporting procedures. 

1632. LPPC and Xcel recommend that the Commission not require NERC to define in 

Requirement R3 the specific high-risk conditions under which the system must be 

operated to respect multiple outages. Xcel argues that it is unnecessary and impractical 

to attempt to define in advance all of the possible scenarios that will result in a high-risk 

condition. Not all high-risk conditions can be defined at any one time because changes in 

the system will introduce new high-risk conditions. Even if a list of high-risk conditions 

is developed, then, by definition, all other conditions not listed are excluded from 

consideration under this Reliability Standard. LPPC states that the proposed modification 

to deal with high-risk conditions is an unnecessarily prescriptive approach and could be 

detrimental to reliability by excluding scenarios that should be listed under this 

Requirement. 

1633. California PUC states that the Commission should not interpret hurricanes and ice 

storms as high risk conditions for studying multiple outages because events such as 

hurricanes and ice storms actually reduce the stress on the Bulk-Power System. This is 

because such events cause outages at the local distribution system level. California PUC 

maintains that since events such as hurricanes and ice storms rarely cause cascading 

outages, the proper approach for dealing with such situations is to focus on system 

restoration planning rather than including them in the contingency analysis that the 

proposed modification will require as a result of including such natural events within the 

meaning of high risk conditions. 

1634. Santa Clara states that Requirement R2 of the Reliability Standard should be 

revised to include frequency monitoring in addition to the monitoring of voltage, real and 

reactive power flows. 
Docket No. RM06-16-000 - 421 - 

ii. Commission Determination

1635. The Commission approves TOP-004-0 as mandatory and enforceable until 

October 1, 2007, when TOP-004-1 will be mandatory and enforceable. We address the 

concerns raised by commenters below. 

1636. We adopt our proposal to require the ERO to clarify that the system should be 

restored as soon as possible, taking no more than 30 minutes. Requirement R4 of TOP004-1 (as well as the Version 0 standard) 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. However, as we stated in the NOPR, this language may be interpreted 

as a grace period to the detriment of reliability.414 The Commission, therefore, directs 

that the ERO develop a modification to Requirement R4 providing that the system should 

be restored to respect proven reliable power system limits as soon as possible and in no 

longer than 30 minutes. In response to PG&E’s point that the phrase “as soon as 

possible” would add confusion, we note that Measure M1 in TOP-004-1 would measure 

performance against the 30-minute period specified in Requirement R4. 

1637. Entergy and MidAmerican support our proposal to direct the ERO to conduct a 

survey and report the operating practices and actual experiences surrounding drifting in 

and out of IROL violations. We disagree with MISO that TOP-007-0 covers reporting of 

“drifting” in and out of IROL violations because that Reliability Standard only requires 

reporting of IROL violations exceeding 30 minutes. With regard to APPA’s suggestion 

that NERC should determine whether such information would improve reliable 

operations, we believe a survey is appropriate to determine actual practices, and simply 

modifying the compliance reporting procedures may not provide sufficient data to 

determine the reliability impacts of such practices and whether a modification to the 

Reliability Standard is appropriate. Accordingly, we direct the ERO to conduct a survey 

on the operating practices and actual experiences surrounding drifting in and out of IROL 

violations. Such a survey will provide factual support for whether additional 

modifications to the Reliability Standard are needed. The survey will also indicate 

whether additional vigilance on the part of compliance auditors is warranted in this area 

to ensure Bulk-Power System reliability. 

1638. As mentioned above, the Commission proposed to interpret “multiple outages” in 

the context of Requirement R3 to include multiple element outages resulting from highrisk conditions such as hurricanes, wild fires, ice storms or periods of high solar magnetic 

 414 See NOPR at P 995. 
Docket No. RM06-16-000 - 422 - 

disturbances during which the probability of multiple outages approaches that of a single 

element outage. This is not an exhaustive list but is meant to contain illustrative 

examples, and the Reliability Standards development process should develop a procedure 

to identify applicable high risk conditions. Under the high-risk conditions, the 

Commission understands that systems are normally operated in a more secure manner so 

that the Bulk-Power System can withstand multiple outages. These multiple outages 

exceed the normal N-1 criterion because the probability of multiple outages during highrisk conditions approaches that of a single outage during normal conditions. This does 

not preclude development of restoration plans as suggested by California PUC. Thus, we 

direct the ERO to develop a modification to the Reliability Standard that explicitly 

incorporates this interpretation with the details identified in the Reliability Standards 

development process. 

1639. We direct the ERO to consider Santa Clara’s suggestion regarding changes to 

Requirement R2 in the Reliability Standards development process. 

1640. Accordingly, the Commission approves Reliability Standard TOP-004-0. Further, 

we approve TOP-004-1 so that it will become mandatory and enforceable on the stated 

effective date of October 1, 2007. In addition, pursuant to section 215(d)(5) of the FPA 

and § 39.5(f) of our regulations, the Commission directs the ERO to develop a 

modification to the Reliability Standard through the Reliability Standards development 

process that: (1) modifies Requirement R4 to state that the system should be restored to 

respect proven limits as soon as possible, taking no more than 30 minutes and (2) defines 

high risk conditions under which the system must be operated to respect multiple outages 

in Requirement R3, consistent with the discussion above. 

1641. In addition, the Commission directs the ERO to perform a survey of the prevailing 

operating practices and actual operating experiences surrounding drifting in and out of 

IROL limits as discussed more fully in this Final Rule in connection with the IRO group 

of Reliability Standards. As an example of the type of data that would be appropriate in 

the survey, we would expect to have reliability coordinators report any violation of an 

IROL not exceeding 30 minutes, its causes, the date and time of the violation, and the 

duration for 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. The ERO 

should report the results to the Commission in an informational filing within 18 months 

from the effective date of this Final Rule. 

e. Operational Reliability Information (TOP-005-1)

1642. Reliability Standard TOP-005-1 seeks to ensure that reliability information is

shared among reliability coordinators, transmission operators and balancing authorities. 

It requires the transmission operator and the balancing authority to provide operating data 
Docket No. RM06-16-000 - 423 - 

to each other and to the reliability coordinator, and it provides a list of typical operating 

data that must be provided. TOP-005-1 also provides that each data recipient must 

execute a confidentiality agreement as a condition of receiving data from NERC’s 

Interregional Security Network.415

1643. The Commission proposed in the NOPR to approve Reliability Standard TOP005-1 as mandatory and enforceable. The Commission also proposed to direct NERC to 

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. 

i. Comments

1644. FirstEnergy states that TOP-005-1 should also apply to transmission providers 

because some of the information listed in Attachment 1 to the Reliability Standard is in 

their possession. Attachment 1 should be modified so that it allows each entity to know 

what data it is expected to provide. As currently written, Attachment 1 lists various 

entities that are supposed to provide data without specifying who will provide which 

information. FirstEnergy states that transmission operators, for example, may not have 

all the information listed in item 1.5 of Attachment 1. 

1645. APPA and Entergy agree that TOP-005-1 should be modified to include 

information about the operational status of special protection systems and power system 

stabilizers in Attachment 1. However, APPA contends that the Commission’s directive 

should be revised so that this change is developed through the Reliability Standards 

development process. 

1646. ISO-NE recommends that the reference to “purchasing-selling entity” in 

Requirement R4 should be replaced with “generator owner, transmission owner, and 

LSE.”416 It argues that since NERC’s glossary defines the term “purchasing-selling 

 415 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. 

416 Requirement R4 states: “Each Purchasing-Selling Entity shall provide 

information as requested by its Host Balancing Authorities and Transmission Operators 

to enable them to conduct operational reliability assessments and coordinate reliable 

operations.” 
Docket No. RM06-16-000 - 424 - 

entity” as “[t]he entity that purchases or sells, and takes title to, energy, capacity, and 

Interconnected Operation services,” many entities can fall within this category (e.g., 

commodity traders such as financial/power marketers) that may possess little or none of 

the operational or reliability data the host balancing authority and transmission operator 

need to conduct reliability assessments. 

1647. A number of commenters discussed the Commission’s proposal to delete 

references to confidentiality agreements in the Reliability Standard but to address the 

issue separately to ensure that necessary protections are in place related to confidential 

information. Those comments are summarized above in connection with the same 

proposal made by the Commission in the case of TOP-002-1. 

ii. Commission Determination

1648. For the reasons stated in the NOPR,417 we direct the ERO to develop a 

modification to TOP-005-1 through the Reliability Standards development process 

regarding the operational status of special protection systems and power system 

stabilizers in Attachment 1. Several commenters agree with this directive, and we 

believe that this information will provide a more comprehensive list in Attachment 1. 

1649. We are adopting our proposal regarding deletion of references to confidentiality 

agreements from the Requirements. Our discussion of this matter in connection with 

TOP-002-1 applies equally here. 

1650. The Commission directs the ERO to consider FirstEnergy’s recommended 

modifications to Attachment 1 to the Reliability Standard and ISO-NE’s recommended 

revision to Requirement R4 in the Reliability Standards development process. 

1651. Accordingly, the Commission approves Reliability Standard TOP-005-1. In 

addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the 

Commission directs the ERO to develop a modification to TOP-005-1 through the 

Reliability Standards development process 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. 

 417 NOPR at P 1005. 
Docket No. RM06-16-000 - 425 - 

f. Monitoring System Conditions (TOP-006-1)

1652. TOP-006-1 requires operating personnel to continuously monitor essential BulkPower System parameters such as line flows, circuit breaker status, generator resources, 

relays, weather forecasts and frequency to ensure that the facilities do not exceed their 

operating limits. 

1653. The Commission proposed in the NOPR to approve the Reliability Standard as 

mandatory and enforceable.418 The Commission also proposed to direct NERC to submit 

a modification that: (1) includes Measures and Levels of Non-Compliance; (2) includes a 

new Requirement related to the provision of a minimum set of analytical tools that will 

aid in situational awareness and (3) clarifies the meaning of “appropriate technical 

information” concerning protective relays. 

i. Comments

1654. Dominion supports including a new requirement for a minimum set of analytical 

tools. It argues that such a requirement will ensure that operators have a minimum set of 

tools with which to perform their duties. The Reliability Standard should also specify 

metrics that can be audited, such as minimum availability times, so that these tools are 

adequately maintained. However, Alcoa states that requiring a minimum set of tools will 

be unduly onerous, especially to smaller balancing authorities and transmission operators. 

Although situational awareness tools, such as state estimators, are critical for an ISO and 

RTO, smaller balancing authorities and transmission operators should provide necessary 

data to the reliability coordinator that monitors a wide region using such tools. 

1655. Alcoa claims that developing additional capability at the balancing authority and 

transmission operator levels when such capability already exists at the reliability 

coordinator level will be redundant. Requiring state estimation for a small balancing area 

that is under an ISO would provide little benefit for grid reliability since the scope of the 

balancing area’s visibility is limited. 

1656. APPA does not support the proposed requirement related to the provision of a 

minimum set of analytical tools and claims that inclusion of specific analytical tools is 

counterproductive because the tools become obsolete within two to five years due to 

 418 In its November 15, 2006 filing, NERC submitted TOP-006-1, which 

supercedes the Version 0 Reliability Standard. TOP-006-1 adds Measures and Levels of 

Non-Compliance to the Version 0 Reliability Standard. In this Final Rule, we review the 

November version, TOP-006-1. 
Docket No. RM06-16-000 - 426 - 

technical advances. APPA states that deciding whether to add a new requirement for a 

minimum set of analytical tools should be left to NERC in the first instance. Similarly, 

TAPS argues that NERC should consider in the first instance whether minimum 

analytical tools are necessary and for what subset of generator operators and transmission 

operators. 

1657. LPPC maintains that the Commission should require NERC to list the capabilities 

required rather than specific tools because tools will change over time. 

1658. APPA states that the ERO’s filing on November 15, 2006 includes new Measures 

M1 through M6, which only measure Requirements R1, R2, R4, R5 and R7. 

ii. Commission Determination

1659. The Commission approves TOP-006-1 as mandatory and enforceable. In addition, 

the Commission directs the ERO to develop modifications to TOP-006-1 through the 

Reliability Standards development process, as discussed below. 

1660. We adopt our proposal to require the ERO to develop a modification related to the 

provision of a minimum set of analytical tools. In response to LPPC and others, we note 

that our intent was not to identify specific sets of tools, but rather the minimum 

capabilities that are necessary to enable operators to deal with real-time situations and to 

ensure reliable operation of the Bulk-Power System. In response to APPA that the 

inclusion of specific analytical tools is counterproductive because the tools will become 

obsolete, we note that we are not seeking specific analytical tools, but rather minimum 

capabilities. 

1661. In regard to Alcoa’s concern that this new Requirement would be unduly onerous, 

especially for smaller balancing authorities and transmission operators, the Commission’s 

intent is not to subject smaller balancing authorities and transmission operators to the 

same requirements placed on larger balancing authorities and transmission operators. As 

part of the modification of this Reliability Standard to develop a new requirement for 

minimum capability for analytical tools, the ERO should take into account what would be 

required of smaller balancing authorities and transmission operators for the Reliable 

Operation of the Bulk-Power System, instead of applying the same requirements as are 

placed on other reliability entities such as reliability coordinators and larger balancing 

authorities and transmission operators. 

1662. We disagree with Alcoa that developing additional capability at the balancing 

authority and transmission operator levels when such capability already exists at the 

reliability coordinator level will be redundant. We are not seeking to duplicate the same 

capability for each reliability entity, but rather the new requirement should specify the 
Docket No. RM06-16-000 - 427 - 

minimum capability taking into account the role played by each entity. For example, a 

reliability coordinator may need to have access to state estimator and contingency 

analysis whereas a generator operator may not need these capabilities.419 

1663. No commenters addressed our proposal with respect to the meaning of 

“appropriate technical information” concerning protective relays in Requirement R3 of 

the Reliability Standard. To provide more clarity, criteria that define what “appropriate 

technical information” is necessary should be specified so that operators can make better 

informed decisions. An example of such information would be the allowable reclosing 

angle set in the existing relays and the maximum angle at specific points in the BulkPower System that would be acceptable to allow closing of lines during system 

restoration. 

1664. The ERO should consider APPA’s comment regarding the missing Measures in 

the ERO’s Reliability Standards development process. 

1665. Accordingly, the Commission approves Reliability Standard TOP-006-1. In 

addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of our regulations, the 

Commission directs the ERO to develop a modification to TOP-006-1 through the 

Reliability Standards development process that: (1) includes a new requirement related 

to the provision of minimum capabilities that are necessary to enable operators to deal 

with real-time situations and to ensure reliable operation of the Bulk-Power System and 

(2) clarifies the meaning of “appropriate technical information” concerning protective 

relays. 

g. Reporting SOL and IROL Violations (TOP-007-0)

1666. TOP-007-0 requires that violations of SOL and IROL be 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 in 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, the Reliability Standard requires that the reliability 

coordinator take action to mitigate an SOL or IROL violation if the transmission 

operator’s actions are not effective. 

 419 We note that TOP-006-0 applies to transmission operators, balancing 

authorities, generator operators and reliability coordinators. 
Docket No. RM06-16-000 - 428 - 

1667. The Commission proposed in the NOPR to approve TOP-007-0 as mandatory and 

enforceable. 

1668. In the NOPR, the Commission solicited comment on potentially overlapping 

matters addressed in Reliability Standards TOP-007-0 and TOP-008-0. 

i. Comments

1669. NERC recognizes that there are some redundancies and awkward relationships 

among the various Reliability Standards, which are the result of the translation from the 

previous operating policies where each policy was treated as a separate set of concepts. 

NERC states that its 2007–2009 Reliability Standards Work Plan addresses work to be 

done to eliminate redundancies and better organize the Requirements across Reliability 

Standards so as to provide a more logical presentation. 

1670. APPA states that the concerns expressed in the NOPR about overlapping matters 

between TOP-007-0 and TOP-008-0 should be referred to the NERC Reliability 

Standards development process to better comport with the statutory division of 

responsibility. FirstEnergy and SoCal Edison state that Requirements R2 through R4 are 

clearly not reporting activities and should be combined with the requirements of TOP008. 

1671. NRC states that some nuclear power plant voltage requirements would result in 

SOL, i.e., the nuclear power plant voltage limits would be an SOL as a result of the 

minimum and maximum voltages required at the nuclear power plant switchyard, which 

typically has a tighter operating band (a higher minimum and a lower maximum) than 

other nodes in the system. It therefore recommends adding a new requirement that states 

as follows: “Following discovery of a potential contingency that could result in an SOL 

being exceeded at a nuclear power plant (e.g., at post-trip voltage), the transmission 

owner shall notify the nuclear power plant operator as soon as possible but not longer 

than 30 minutes if the contingency has not been corrected.” NRC also suggests 

modifying the Measures and Compliance sections and Table 1 to account for the new 

requirement, and provides specific language to be included in those places. 

ii. Commission Determination

1672. The Commission approves TOP-007-0 as mandatory and enforceable. We agree 

with APPA, FirstEnergy and SoCal Edison that the Reliability Standards would benefit 

from the elimination of overlapping matters in TOP-007-0 and TOP-008-1. The ERO 

indicates that it plans to address this as part of its Work Plan and this suffices. 
Docket No. RM06-16-000 - 429 - 

1673. NRC has raised some significant issues regarding the consideration of nuclear 

power plants voltage requirements. Consistent with our general approach in this Final 

Rule, we direct the ERO to consider NRC’s comments in the Reliability Standards 

development process when addressing TOP-007-0 as part of its Work Plan. 

1674. Accordingly, the Commission approves Reliability Standard TOP-007-0 as 

mandatory and enforceable. 

h. Response to Transmission Limit Violations (TOP-008-1)

1675. TOP-008-1 requires a transmission owner to take immediate steps to mitigate SOL 

and IROL violations. 

1676. The Commission proposed in the NOPR to approve Reliability Standard TOP008-0 as mandatory and enforceable. The Commission also proposed to direct that 

NERC submit a modification to TOP-008-0 that: (1) includes Measures and Levels of 

Non-Compliance and (2) includes reliability coordinators in the applicability section.420

i. Comments

1677. APPA questions whether TOP-008-1 should be modified to apply to reliability 

coordinators. It claims that the Requirement R3 simply mentions that the reliability 

coordinator will receive information provided by the transmission operator and does not 

play any substantive role under TOP-008-1. MISO notes that the reliability coordinators’ 

responsibility related to IROL violations are outlined in connection with IRO Reliability 

Standards and the reasons for adding the reliability coordinator as applicable entity in 

multiple locations is unclear. 

1678. APPA states that NERC has not submitted a Measure for the Requirement R2 of 

the Reliability Standard. The new Measures M1 through M5 included in TOP-008-1 only 

measure Requirements R1, R3, and R4. In addition, the data retention and compliance 

levels reference Measures M1 through M5. Therefore, an entity subject to TOP-008-1 

could arguably comply with Requirements R1, R3 and R4 and be in compliance with the 

entire Reliability Standard. 

 420 In its November 15, 2006, filing, NERC submitted TOP-008-1, which 

supercedes the Version 0 Reliability Standard. TOP-008-1 adds Measures and Levels of 

Non-Compliance to the Version 0 Reliability Standard. In this Final Rule, we review the 

November version, TOP-008-1. 
Docket No. RM06-16-000 - 430 - 

ii. Commission Determination

1679. For the reasons stated in the NOPR,421 the Commission approves TOP-008-1 as 

mandatory and enforceable. We address the concerns raised by commenters below. 

1680. We agree with APPA that the reliability coordinator merely receives information 

provided by the transmission operator and does not play any substantive role under TOP008-1. We also agree with MISO that the reliability coordinators’ responsibility related 

to IROL violations are outlined in connection with the IRO Reliability Standards and 

therefore there is no need to modify the applicability section of TOP-008-1 to include the 

reliability coordinator. 

1681. The ERO should consider APPA’s comment regarding the missing Measures in 

the ERO’s Reliability Standards development process. 

1682. Accordingly, the Commission approves Reliability Standard TOP-008-1 as 

mandatory and enforceable. 

12. TPL: Transmission Planning 

1683. The Transmission Planning (TPL) group of Reliability Standards consists of six 

Reliability Standards that are applicable to transmission planners, planning authorities 

and regional reliability organizations. These Reliability Standards are intended to ensure 

that the transmission system is planned and designed to meet an appropriate and specific 

set of reliability criteria. Transmission planning is a process that involves a number of 

stages including developing a model of the Bulk-Power System, using this model to 

assess the performance of the system for a range of operating conditions and 

contingencies, determining those operating conditions and contingencies that have an 

undesirable reliability impact, identifying the nature of potential options, and the need to 

develop and evaluate a range of solutions and selecting the preferred solution, taking into 

account the time needed to place the solution 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 needs422

and (2) the information required to assess regional compliance with planning criteria and 

for self-assessment of regional reliability.423 

 421 See NOPR at P 1035-36. 

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

423 See TPL-005-0 and TPL-006-0. 
Docket No. RM06-16-000 - 431 - 

1684. The TPL group of Reliability Standards contains a table designated “Table 1” 

(Transmission System Standards – Normal and Emergency Conditions), which is a key 

part of this group of Reliability Standards. It lays out the system performance 

requirements for a range of contingencies grouped according to the number of elements 

forced out of service as a result of the contingency. For example: Category A applies to 

the normal system with no contingencies; Category B applies to contingencies resulting 

in the loss of a single element, defined as a generator, transmission circuit, transformer, 

single DC pole with or without a fault; Category C applies to a contingency resulting in 

loss of two or more elements, such as any two circuits on a multiple circuit tower line or 

both poles of a bi-polar DC line; while Category D applies to extreme contingencies 

resulting in loss of multiple elements, such as a substation or all lines on a right-of-way. 

The system performance expectations for Category C contingencies are lower than those 

for Category B contingencies, in that they allow unspecified amounts of planned or 

controlled loss of load. 

a. General Issues 

1685. Commenters raise a number of issues that apply generally to Reliability Standards 

TPL-001-0 through TPL-004-0. These issues are related to the transmission planning 

process, sensitivity studies and critical system conditions, element-based versus eventbased contingencies, spares strategy, and resource information for planning and sharing 

information with neighboring systems. We address these general issues here, and the 

conclusions reached will apply to our discussion of individual TPL Reliability Standards. 

i. Transmission Planning Process

1686. The Commission stated in the NOPR that the Reliability Standards are not 

intended to make the Bulk-Power System failure-proof.424 In addition, we did not 

propose to modify the TPL Reliability Standards to require that the system be able to 

withstand all multiple-contingency and extreme contingency events without loss of load. 

Nonetheless, we stated that we believe that the planning-related Reliability Standards 

could be improved to better account for probable contingencies when conducting 

planning studies. Much of our proposal was consistent with the potential improvements 

NERC recognized in its comments on the Staff Preliminary Assessment. In addition, we 

noted 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 

 424 NOPR at P 1042. 
Docket No. RM06-16-000 - 432 - 

Reliability Standards.425 Accordingly, we proposed 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. 

(a) Comments

1687. EEI and APPA strongly believe that the transmission planning processes 

performed under these Reliability Standards have served this nation extremely well. The 

Reliability Standards have evolved with changes in industry structure, computer and 

communications technology, electric generation and transmission technology and a broad 

range of state and federal regulatory demands. EEI and APPA state that it is unclear 

whether the Commission is proposing a significant expansion of this reliability planning 

process, which would amount to a fundamental shift in the nature of that process, or 

whether the Commission is proposing a more specific description of today’s 

comprehensive planning approach. EEI and APPA state that they can interpret the 

Commission’s proposal either as suggesting that planning should support a robust and 

flexible network that can “bend” to a broad range of critical system conditions, as 

practiced up to now, or that planning should be “finely tuned” so that reliability can be 

maintained under conditions where both resources and loads are highly controlled. They 

find the source for the latter interpretation in the Commission’s request that the industry 

move toward more explicit requirements that transmission planners consider the effects 

of load control or other forms of DSM, or conduct planning studies for far more 

combinations of resource alternatives. EEI and APPA state that the existing Reliability 

Standards fully meet the Commission’s criteria as set forth in Order No. 672, unless the 

Commission envisions a very different transmission system planning process or seeks to 

move away from current network design toward the development of a much “tighter” 

transmission system through substantially higher saturations of controllable resources and 

loads. 

1688. SDG&E notes that the NOPR’s characterization of the dual objectives of 

“appropriateness” and “specificity” speaks, on the one hand, to the need for Reliability 

Standards that are tailored to each transmission planner’s area of responsibility, and, on 

 425 Examples include practices cited in NERC’s “Examples of Excellence” found 

in its Readiness Audits (available at http://www.nerc.com) and 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. 
Docket No. RM06-16-000 - 433 - 

the other hand, clear, consistent and workable rules. SDG&E urges the Commission to 

be mindful of the need to assess and balance these considerations in future iterations of 

the transmission planning Reliability Standards. 

1689. Northern Indiana states that the presentation of TPL-001-0 through TPL-004-0 as 

individual Reliability Standards creates a great deal of confusion. In practice, most 

transmission planners take an integrated view of these Reliability Standards and treat 

them as if they were a single standard. Accordingly, Northern Indiana suggests that the 

Commission ask NERC to file a substitute proposal that would integrate the transmission 

planning standards and improve their clarity and quality. 

1690. SDG&E supports the Commission’s proposal to direct NERC to submit for 

approval regional transmission planning criteria that have been adopted and extensively 

used that are more stringent than those specified in the current TPL Reliability Standards. 

NCPA states that whenever a RTO/ISO adopts criteria that differ from ERO or regional 

standards, those criteria should be made public and transparent. 

(b) Commission Determination

1691. EEI and APPA raise an important question on the Commission’s intent regarding 

the transmission planning process and proposed modifications to the transmission 

planning standards. They ask whether the Commission is proposing a fundamental shift 

in the nature of the planning process that would result in a move away from the current 

network design towards a much “tighter” transmission system through substantially 

increased use of controllable resources and loads. The Commission is not proposing a 

fundamental shift in the nature of the planning process as it is practiced today. We 

clarify that all the proposed modifications to the TPL group of Reliability Standards are 

aimed at ensuring Reliable Operation of the Bulk-Power System. To achieve this goal, it 

is necessary, among other things, to ensure that the planning process and the Reliability 

Standards produce a Bulk-Power System that is robust enough to be able to withstand a 

range of probable contingencies while reliably serving customer demand and preventing 

the identified outages, and flexible enough to accommodate a broad range of system 

conditions over a planning horizon that takes into account lead times to place facilities in 

service. Further, the proposed modifications are intended to ensure that the planning 

requirements are specific enough to promote rigor and consistency in assessments and 

provide clear and measurable rules for mandatory and enforceable Reliability Standards. 

The Commission therefore agrees with SDG&E’s comments in this regard and on the 

need to balance “appropriateness” and “specificity.” 

1692. The Commission agrees with Northern Indiana that the Reliability Standards TPL001-0 through TPL-004-0 would be improved if they were integrated into a single 

Reliability Standard. Such an approach conforms more closely to common planning 
Docket No. RM06-16-000 - 434 - 

practices, and integrating these Reliability Standards therefore could enhance their 

practical effectiveness. The Commission notes that the Work Plan submitted by the ERO 

has earmarked this group of Reliability Standards for revision during the early stages of 

the plan. The Commission directs the ERO to consider integrating Reliability Standards 

TPL-001-0 through TPL-004-0 into a single Reliability Standard through the Reliability 

Standards development process. 

1693. The Commission agrees with SDG&E and NCPA that any criteria that are more 

stringent than the ERO planning criteria should be made public and transparent. It is 

essential that such criteria be accessible to and understood by the entities to which they 

apply. Accordingly, the Commission directs the ERO to submit to the Commission in an 

informational filing, in addition to regional criteria, all utility and RTO/ISO differences in 

transmission planning criteria that are more stringent than those specified by the TPL 

group of Reliability Standards. We believe that this information will provide us, as well 

as the ERO and industry with an indication of the actual transmission practices utilized in 

the industry today. This should be used by the ERO in the Reliability Standards 

development process. 

ii. Sensitivity studies and critical system conditions 

1694. The Commission stated in the NOPR that it is not realistic to expect the ERO to 

develop Reliability Standards that anticipate every conceivable critical operating 

condition applicable to unknown future configurations for regions with various 

configurations and operating characteristics.426 The practical solution implemented by 

many in the industry is to perform sensitivity studies that define and provide 

documentation of the reliability impact on the system. The Commission therefore stated 

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. Both staff and commenters on the 

Staff Preliminary Assessment noted that system conditions are as important as 

contingencies in evaluating the performance of present and future systems.

(a) Comments

1695. Most of the commenters agree with the Commission’s proposal on sensitivity 

studies to determine critical system conditions. These include FirstEnergy, TVA, 

MidAmerican, Entergy and SDG&E. However, a few commenters, including EEI, 

 426 NOPR at P 1047. 
Docket No. RM06-16-000 - 435 - 

APPA, MISO and Northern Indiana, take the view that such a requirement is unnecessary 

and overly prescriptive. 

1696. FirstEnergy states that it is appropriate for the Commission to require sensitivity 

analyses, because assessing multiple sensitivities against a set of system contingencies is 

prudent system planning. 

1697. TVA agrees that an appropriate range of critical operating conditions that will 

“stress” the Bulk-Power System needs to be identified for use in transmission planning. 

It states that sensitivity studies should be performed and historic data analyzed to 

determine the most probable range of operating conditions that will stress the Bulk-Power 

System. 

1698. MidAmerican believes that the proposal to require sensitivity studies to “bracket” 

the range of probable outcomes and determine critical system conditions is reasonable. It 

states that, while critical conditions may be determined in a similar manner for the 

different TPL Reliability Standards, different critical conditions are pertinent to each 

Reliability Standard. For example, thermal overloads occur under peak load conditions 

and dynamic instability occur under light load conditions. 

1699. Entergy does not object to an assessment of critical system conditions using the 

factors identified in the NOPR,427 but it contends that the Commission’s guidance is 

problematic to the extent that it may require constructing facilities to address potential 

constraints identified through these assessments. Entergy states that such construction 

may not create a desirable result and may instead threaten reliability. For example, 

assessing a system using alternative generation dispatch and transaction patterns could 

bias a transmission provider in favor of transmission plans that benefit a specific 

generator or set of generators. 

1700. SDG&E sees the Commission’s treatment of sensitivity studies and critical system 

conditions as requiring transmission planning entities to exercise judgment in 

determining the scope, content and number of their sensitivity studies so that they are 

appropriate given unique system characteristics and reasonably anticipated contingencies. 

SDG&E state that this guidance is welcome and should be reflected in future 

Requirements. 

1701. MISO agrees that planning entities should have a process to identify appropriate 

critical system conditions for planning purposes. However, it does not believe that the 

 427 Id. at P 1061. 
Docket No. RM06-16-000 - 436 - 

Reliability Standard needs to be prescriptive in terms of the specific sensitivities that 

should be evaluated. If an entity’s approach to selecting the critical planning conditions 

is appropriate, sensitivities to variations from these conditions are unnecessary. MISO 

and Northern Indiana state that requiring sensitivities in planning studies as a mandatory 

standard practice could result in unnecessary additional analysis that could overwhelm 

the planning process and detract from more appropriate focused analysis and evaluation 

of solutions. 

1702. EEI and APPA state that the Commission’s proposal on sensitivity studies would 

add an unnecessarily redundant process that ignores the totality of the studies contained 

in study libraries that inform planners’ decisions. The historical libraries of system 

studies provide a strong base for selecting critical transmission system conditions. EEI 

believes that the knowledge and experience of planners who have conducted these studies 

provides reliable guidance and that a new array of sensitivity analyses would offer no 

additional benefit over existing practices. 

1703. Regarding specific variables to be included in sensitivity studies, EEI and APPA 

note that load power factors, controllable loads and DSM at specific locations and 

outages of reactive devices have much more to do with distribution operations planning 

than long-term system planning. They state that while transmission system planners will 

study a broad range of combinations of substation loadings, system configurations and 

resource availabilities over the planning horizon, changes in the variables of the sort 

identified by the Commission have very little influence on the long-term study outcomes 

except for the loss of load that could occur under extreme circumstances. MISO believes 

that transmission reactive power devices should be treated like any other transmission 

facility and included in the required contingency analysis. The current Reliability 

Standards are not explicit in this regard, and MISO agrees that this would be an 

appropriate clarification. It believes that power factor sensitivity studies are best suited 

for operational planning studies rather than long-term planning since corrective actions 

have relatively short lead times. In regard to alternative dispatch scenarios, MISO states 

that if a variation from the expected dispatch leads to unacceptable performance, it 

becomes an economic planning question, rather than a planning standard issue, whether 

expansion should be undertaken or whether the dispatch becomes a congestion cost.

(b) Commission Determination

1704. In response to Entergy’s comments, the Commission reiterates the statement from 

the NOPR428 that the results of the sensitivity studies would be used to document the 

 428 Id. at P 1061. 
Docket No. RM06-16-000 - 437 - 

selection of critical system conditions and study years used in assessing system 

conditions. The Commission notes that it is not the purpose of sensitivity studies to 

identify remedial actions, but, as stated in the NOPR, if different scenarios that lead to 

criteria violations are probable they require mitigation plans.429 Entergy goes on to state 

that constructing facilities, the need for which is determined through sensitivity studies, 

may not create a desirable result, in that they may bias transmission plans towards a 

specific generator or set of generators and as a result may threaten reliability. The 

Commission disagrees that constructing well-planned facilities may threaten reliability. 

The planning process should anticipate any inter-regional impacts, and the net result 

should be higher local and inter-regional reliability. In any case, we are not requiring the 

construction of additional facilities. 

1705. MISO, EEI, APPA and others question the value of sensitivity studies and their 

role in mandatory Reliability Standards given the knowledge and experience of planners 

and the historical library of system studies. The Commission notes that while specificity 

was not required in the regime of voluntary standards, it is required in a regime of 

mandatory Reliability Standards to ensure consistency in system assessment and provide 

clear and measurable requirements. Further, as stated in the NOPR430 and concurred with 

by commenters to the Staff Preliminary Assessment, system conditions are as important 

as contingencies in evaluating the performance of present and future systems. Indeed, 

Table 1 lists the contingencies to be evaluated, but there is no corresponding requirement 

for selecting critical system conditions. 

1706. The Commission believes it is important to clarify the type of analysis required in 

determining critical system conditions, which is the intent of the directed modifications 

on sensitivity studies. The Commission proposed in the NOPR a range of variables to be 

included in sensitivity studies, specifically: firm transfers, demand levels, existing and 

planned facilities, reactive power resources, control devices, load power factors, 

generation retirements, generation dispatch, transaction patterns, controllable loads, DSM 

and transmission outages including outages of reactive power devices.431 The 

Commission also stated that it is not precluding other approaches to defining and 

documenting critical system conditions that have proven to be effective. The 

Commission also notes that in analyzing contingencies as part of Requirement R1.3.1 in 

Reliability Standards TPL-002-0 through TPL-004-0, not all contingencies need be 

 429 Id. at n.324. 

430 Id. at P 1046. 

431 Id. at P 1047. 
Docket No. RM06-16-000 - 438 - 

assessed for every system element but only those that would produce the more severe 

reliability impacts with documentation of selection rationale. The same applies to the 

range of variables specified for sensitivity studies. The Commission expects that the full 

range of variables will be considered, but only those deemed to be significant need to be 

assessed and documentation provided that explains the rationale for the selection of 

variables assessed. 

iii. Element-Based vs. Event-Based Contingencies 

1707. The Commission stated in the NOPR that planning Reliability Standards must 

influence system design and not the other way around.432 To achieve this objective, 

planning Reliability Standards should promote system designs that result in the minimum 

set of elements being removed from service for “unanticipated failures of system 

elements.”433 The NOPR goes on to say that the Commission believes that the 

simulations used in planning assessments should faithfully duplicate what will happen in 

the actual power system and not a generic listing of outages. The Bulk-Power System 

also 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 an 

unanticipated failure of any system element. If a specific portion of the system has been 

designed such that the response to a failure results in multiple lines, transformers, 

generators, circuit breakers, etc., being removed from service, the Commission proposed 

that this is what should be simulated.434

(a) Comments

1708. National Grid, MidAmerican and SDG&E support the principles set forth in the 

NOPR. National Grid states that event-based planning is a more robust form of 

contingency analysis than element-based planning because the former focuses on 

contingencies regardless of how many elements may be affected while the latter focuses 

 432 Id. at P 1049. 

433 Section 215(a) of the FPA defines “Reliable Operation” as “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). 

434 With respect to failure, the element includes a single transmission line, 

transformer, generator or single pole of a DC line. 
Docket No. RM06-16-000 - 439 - 

on losses of specific elements that may not have a direct relationship to the severity of the 

impact on or risks to reliability. As such it supports the Commission’s statement that 

“simulations should faithfully duplicate what will happen in the actual power system and 

not a generic listing of outages.”435 

1709. MidAmerican states that it supports the Commission’s proposal to interpret a 

“single contingency” to include all elements of the system, irrespective of their number, 

that go out of service in response to failure of a single element, as it has historically 

performed this analysis as a part of normal planning in the interest of reliability. 

MidAmerican is concerned, however, that this proposal may be too restrictive for system 

planning, particularly with regard to the double contingencies of Category C. It states 

that if a multi-element single contingency occurs first, as part of system adjustment, the 

reliability coordinator or transmission operator will switch back the unfaulted elements to 

service prior to the next contingency. Therefore this N-1-1 contingency at its worst will 

consist of a single element outage followed by a multi-element outage. Therefore 

MidAmerican states that the extent of a multiple-element single contingency is better 

determined through coordinated efforts of neighboring systems in conjunction with the 

planning authority and reliability coordinator. 

1710. SDG&E agrees that further modifications to the TPL Reliability Standards should 

be guided by the NOPR’s directive that simulations should faithfully duplicate what will 

happen in the actual power system and not a generic listing of outages. However, it states 

that the Commission should provide further guidance in defining an event so that 

planning studies can assess electrical system contingencies consistently and numerically. 

A simulation that faithfully duplicates reasonably expected scenarios will necessarily 

involve the transmission planner’s sound engineering judgment and knowledge of 

elements that would be expected to be removed from service during the contingency. 

SDG&E states that the updated TPL Reliability Standard should reflect and implement 

these concerns. 

1711. EEI believes the planning Reliability Standards and practices clearly reflect the 

language in FPA section 215 regarding “element based” planning. Planners study single 

contingency and multiple contingency events covering a broad range of system elements 

and not a list of generic outages. 

1712. TANC recommends that the Commission direct that transmission planning in the 

West be based on probability of an event occurring and the severity of the consequences, 

rather than on a deterministic approach that uses single and multiple contingency 

 435 NOPR at P 1049. 
Docket No. RM06-16-000 - 440 - 

categories as exemplified by Table 1. It states that WECC has assessed the probability of 

an event occurring for each category and assigned probabilities accordingly. TANC 

states that to be more cost effective and efficient, investments to remedy a problem 

should be based on a combination of the probability of the occurrence of the event and 

the severity of the associated consequences. 

1713. In response to the Commission’s request in the NOPR for comment on whether 

planning for cyber security events should be addressed in the planning Reliability 

Standards or in the Critical Infrastructure Protection (CIP) Reliability Standards,436

MidAmerican, EEI, APPA, ISO-NE and SoCal Edison state they believe that events 

requiring study under the CIP Reliability Standards should be included in that specialized 

forum rather than the TPL Reliability Standards. Such events are identified using 

approaches provided for in the CIP Reliability Standards. Therefore the best place to 

explore those events and determine their impacts using the full background of the 

information about the events is the CIP Reliability Standards, although some of these 

events will require implementation of elements from other Reliability Standards. 

1714. National Grid and International Transmission take the view that cyber security 

incidents are no different than other events that remove single or multiple elements from 

service at a single time and require analysis of system impacts. Planning assessment for 

cyber security incidents therefore is most appropriately addressed in the TPL Reliability 

Standards. International Transmission states that although Table 1 of the TPL Reliability 

Standards does not list the initiating event, cyber security events could be included in the 

list of contingencies as an initiating event. National Grid cautions that provisions 

detailing specific cyber security protections should be addressed in CIP Reliability 

Standards, and emergency response procedures for response to cyber security events 

should be addressed in EOP Reliability Standards. 

(b) Commission Determination

1715. Several commenters437 agree with the Commission’s statement in the NOPR438

that “simulations should faithfully duplicate what will happen in the actual power system 

and not a generic listing of outages.” It follows that in simulating the failure of a single 

element, as required in Category B of TPL-002-0, all of the elements that are removed 

 436 Id. at P 1050. 

437 National Grid, MidAmerican and SDG&E. 

438 NOPR at P 1049. 
Docket No. RM06-16-000 - 441 - 

from service to isolate the single faulted element should be modeled in the simulation 

rather than restricting the simulation to just the single faulted element, as Table 1 of TPL002-0 implies. As SDG&E notes, this will require the transmission planner’s sound 

engineering judgment and knowledge of elements that would be expected to be removed 

from service during the single contingency. The Commission agrees with MidAmerican 

that for Category C contingencies of TPL-003-0, the worst N-1-1 contingency would be a 

single element outage followed by a multiple element outage, provided that following the 

first N-1 contingency, capability exists to switch the unfaulted elements back into service 

promptly, i.e., within 30 minutes, as part of the adjustments that the Reliability Standard 

allows. 

1716. SDG&E agrees that simulations should faithfully duplicate what will happen in 

the actual power system and not a generic listing of outages, but it seeks Commission 

guidance on how an event should be defined. In the Commission’s view, a single 

contingency consists of a failure of a single element that faithfully duplicates what will 

happen in the actual system.439 Such an approach is necessary to ensure that planning 

will produce results that will enhance the reliability of that system. Thus, if the system is 

designed such that failure of a single element removes from service multiple elements in 

order to isolate the faulted element, then that is what should be simulated to assess system 

performance. Accordingly, the Commission directs the ERO to submit modifications to 

Category B of Table 1 consistent with this approach. Entities whose systems may have 

been planned and designed on the basis of a different approach to single contingencies 

should work with the ERO in developing plans to transition to this approach. 

1717. The Commission disagrees with EEI that the planning Reliability Standards and 

practices clearly reflect the language in FPA section 215 regarding “element based” 

planning. Section 215(a) of the FPA defines “Reliable Operation” as “operating the 

elements of the Bulk-Power System” within certain limits so that “instability, 

uncontrolled separation or cascading failures of that system will not occur as a result of 

sudden disturbances, including a cyber security incident, or unanticipated failure of 

system elements.” This definition specifies an ultimate goal and does not dictate any 

specific type of planning. The approach to a single contingency the Commission has set 

forth above ensures that transmission planners 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 limited 

number of outages listed in Table 1 of the TPL Reliability Standards. In short, the 

 439 A “single element” means a transmission line, a transformer, a generator or a 

single pole of a DC line. 
Docket No. RM06-16-000 - 442 - 

Commission’s approach speaks directly to the problem that the statute requires be 

addressed. 

1718. In response to TANC’s proposal that the Commission direct that probabilistic 

approaches to transmission planning be adopted in the West, the Commission notes that 

proposals of this type should be submitted to the ERO for approval as a regional 

difference. If such a proposal is developed for the Western Interconnection, to assist the 

ERO and the Commission in its assessment of such a proposal, we encourage WECC to 

also submit operating information that quantifies the level of actual performance that has 

been achieved with the present deterministic planning approach. Such performance 

metrics would assist us in determining whether a probabilistic approach would result in 

equivalent or higher levels of Reliable Operation than currently achieved. 

1719. In response to the comments received on how best to address planning for cyber 

security events, it is clear that the nature of risks as well as the contingencies and 

measures needed to overcome them are best addressed in the CIP Reliability Standards 

because this forum has the specialized knowledge to deal with cyber security matters. 

However, the system impacts of cyber security events are best addressed in the TPL 

group of Reliability Standards, particularly TPL-004-0, alongside other similar common 

mode failures. Emergency plans and restoration procedures to deal with cyber security 

events are best addressed by the EOP Reliability Standards because these Reliability 

Standards deal with emergency plans and restoration procedures. The Commission 

directs the ERO to consider appropriate revisions to the Reliability Standards through its 

Reliability Standards development process to address these matters. 

iv. Spare Equipment Strategy

1720. The Commission stated in the NOPR that while Reliability Standards TPL-002 

through TPL-004 require consideration of planned outages at those demand levels for 

which planned outages are performed, they do not address situations where critical 

equipment, such as a transformer or phase angle regulator, may be unavailable for a 

prolonged period. Including such a requirement would ensure the coordination of 

contingency plans, including the entity’s spare equipment strategy, to return facilities to 

service in a timely manner for reliability. The Commission therefore proposed that the 

Reliability Standards be modified to include a new requirement to assess the reliability 

impact of an entity’s existing spare equipment strategy. 

(a) Comments

1721. SDG&E states that it generally supports a new requirement that would include 

assessing the reliability impact of an entity’s spare equipment strategy, but several key 

features of this requirement need clear and thorough definition. For example, the 
Docket No. RM06-16-000 - 443 - 

requirement should provide an industry-developed finite list of “critical items,” and the 

meaning of “impact IROL” would need further clarification. SDG&E submits that, 

absent a careful delineation of the requirement and its terms, this proposed modification 

will not enhance system reliability 

1722. MidAmerican, LPPC, EEI, APPA and SoCal Edison state that they understand the 

Commission’s concern about spare equipment planning and acquisition strategy. 

However, MidAmerican and LPPC note that typically spare equipment strategy is of 

more concern in operating studies than planning studies. MidAmerican states that most 

equipment can be installed in a year or less even if it is not on hand. It maintains that it 

may be appropriate to add this requirement to the TPL Reliability Standards because 

scarcity of new equipment due to recent disasters has led to longer lead times. LPPC 

cautions the Commission that associating spare equipment strategy with the planning 

Reliability Standards could lead to Reliability Standards that overstep the limits of FPA 

section 215(i)(2) through proposing a Reliability Standard that would, indirectly, come 

close to authorizing the ERO to order the construction of transmission capacity. LPPC 

states that it is unclear how to separate: (1) requiring a utility to assess its spare 

equipment strategy; (2) requiring a utility to have spares on hand to meet anticipated 

reliability needs and (3) requiring a utility to use spare equipment to meet the reliability 

needs. 

1723. EEI, APPA and SoCal Edison question the need to address this issue in the context 

of a Reliability Standard. EEI states that, where delivery delay could occur for long lead 

time equipment such as transformers, the existing Reliability Standards provide for study 

of the full range of single and multiple-event contingencies with that piece of equipment 

modeled off-line. According to EEI, the Commission’s general concern regarding the 

current policies and practices related to equipment acquisition can be addressed in the 

NERC forum without revising the Reliability Standards. This forum also will account for 

the need to protect information on critical infrastructure facilities. 

(b) Commission Determination 

1724. Several commenters stated that they understand the Commission’s concern about 

requiring a reliability impact assessment of an entity’s spare equipment strategy, but they 

question the need to address this issue in the Reliability Standards in general and the 

transmission planning Reliability Standards in particular. The Commission disagrees 

with EEI that the existing Reliability Standards provide for situations that cover the 

delivery of long lead time equipment, such as transformers, by requiring a full range of 

single and multiple contingency studies with that equipment modeled off-line. TPL-002-

0 and TPL-003-0 currently state explicitly in Requirement R1.3.12 that the assessments 

shall include planned outages of bulk electric equipment at those demand levels for 

which planned (including maintenance) outages are performed. However, equipment 
Docket No. RM06-16-000 - 444 - 

such as transformers may not be available for service for a year or more and therefore 

their unavailability cannot be scheduled when system conditions permit. 

1725. The current Reliability Standards do not require assessment of the reliability 

impacts that result from not having this long lead time equipment available under those 

system conditions likely to be experienced during the course of the year when the system 

is heavily stressed. Clearly the consideration of planned outages is inextricably linked 

with spare equipment strategy. Thus, if an entity’s spare equipment strategy for the 

permanent loss of a transformer is to use a “hot spare” or to relocate a transformer from 

another location in a timely manner, the outage of the transformer need not be assessed 

under peak system conditions. However, if the spare equipment strategy entails 

acquisition of a replacement transformer that has a one-year or longer lead time, then the 

outage of the transformer must be assessed under the most stressed system conditions 

likely to be experienced. Accordingly, the Commission directs the ERO to modify the 

planning Reliability Standards to require the assessment of planned outages consistent 

with the entity’s spare equipment strategy. 

1726. LPPC questions whether the Commission’s proposal oversteps the limits of FPA 

section 215(i)(2) because assessing the impact on reliability of an entity’s decision 

concerning spare equipment could force an entity to construct transmission capability. 

FPA section 215(i)(2) prohibits the ERO and the Commission from ordering the 

construction of “additional” transmission capacity. A requirement to assess the reliability 

impacts of an entity’s spare equipment strategy is no different than a requirement to 

assess the reliability impacts of any number of contingencies. Even if an entity was 

forced to conclude that its spare strategy was inadequate, rectifying the problem would 

not require that the entity construct “additional” transmission capacity, only that it 

possess adequate spares, or take other appropriate action, to ensure the reliable operation 

of its system. In short, while FPA section 215(i)(2) precludes ordering expansion of 

transmission or generation capacity, section 215 clearly authorizes requiring entities to 

take appropriate steps to ensure that their existing capacity operates reliably. 

1727. With regard to SDG&E’s suggestion to clarify specific elements of this Reliability 

Standard, we direct the ERO to consider such suggestions in its Reliability Standards 

development process. 

v. Resource Information for Planning

1728. The Commission in the NOPR requested 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. Further, if transmission planners and planning authorities currently experience 
Docket No. RM06-16-000 - 445 - 

difficulty obtaining this information, the Commission asked how this potential 

information gap should be addressed.440

(a) Comments

1729. The Commission noted in the NOPR that transmission planning requires 

information on forecasted loads and probable generation plans to supply those loads.441 

While the MOD Reliability Standards require information on forecasted loads, energy, 

interruptible loads and direct control load management over the next ten years, there is no 

requirement to inform transmission planners and planning authorities of new or retiring 

generation resources. The Commission sought 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 and if not, how this potential gap should be addressed. 

1730. NERC stated that it and the regional reliability organizations have generally not 

had problems obtaining the data and information required for reliability assessments. 

NERC believes that given its authority and responsibility as the ERO, it will be 

successful in obtaining all the data and information it needs to conduct reliability 

assessments without the need to include these requirements in Reliability Standards. In 

the event that it and the regional reliability organizations are unsuccessful in obtaining 

such data and information, the ERO will turn to the Commission for assistance. 

1731. ISO-NE states that as the planning authority it obtains resource plans for additions, 

capacity changes, deactivations and retirements for a ten year planning horizon. 

Although these plans cannot be expected to occur exactly as projected, they serve as 

useful information in projecting needs for new resources or new or upgraded transmission 

facilities. As the administrator of wholesale electric markets, ISO-NE relies on the 

development of robust market rules accompanied by a regulated transmission planning 

process to achieve its goal of encouraging the availability of sufficient resources. ISONE states that planning for the introduction and retirement of specific resources ten years 

in advance not only is unnecessary, it is inconsistent with relying on markets to determine 

the most efficient allocation of resources to meet system needs. 

1732. FirstEnergy and SoCal Edison state that currently they are able to obtain 

information regarding new generation from publicly available information and from the 

 440 NOPR at P 1060. 

441 Id.
Docket No. RM06-16-000 - 446 - 

generator interconnection queue. Typically, a generation application that is in the 

interconnection agreement phase is considered for transmission planning studies. New 

generation has a longer lead time, and thus information on it may be available sooner 

than information about retirements, which have a much shorter lead time before they are 

announced. FirstEnergy states that despite the unpredictability of such information, 

assessments can be conducted using assumptions of new generation and retirements, and 

the results should recognize that the inputs were based on reasonably foreseeable 

conditions. 

1733. In contrast, CAISO, National Grid and Northern Indiana state that obtaining 

resource information has been a challenge given that the Reliability Standards impose no 

obligation on generation owners to provide information to planning authorities and 

transmission service providers about new and retiring generation. Northern Indiana states 

that this issue is among the greatest challenges for its transmission planners. Because 

transmission planning is focused on matching the source to the sink, having the sources 

unknown, in the case of future generation, creates a weakness in the entire transmission 

planning process. Northern Indiana contends that weakness will be difficult to eliminate 

because information about siting of future generation units is considered commercially 

sensitive information. This lack of information makes it difficult for transmission 

planners to reflect accurately the amount and location of new generation in their 

transmission studies. CAISO agrees that there is a gap in its ability to obtain this 

information particularly from adjacent balancing authorities. CAISO suggests that to 

bridge this gap, generator owners and operators should be required to provide data about 

new and retiring generation to their planning authorities and that the planning authorities 

be required to share this information with neighboring balancing authorities, subject to 

appropriate non-disclosure agreements. CAISO notes that there currently exists no 

centralized database for the collection and dissemination of this information within the 

Western Interconnection. 

1734. National Grid states that forward capacity markets and the generation 

interconnection queue provide some understanding about new generation but only for 

five to seven years, even though transmission planning horizons are considerably longer. 

National Grid and Northern Indiana contend that it may be reasonable to conclude that 

certain areas are prime locations for new resources, particularly inexpensive and 

renewable resources that are dependent on “non-transportable” fuel supplies. National 

Grid states that the Commission should embrace efforts of transmission planners to 

facilitate new generation entry when such initiatives are expected to increase customer 

access to inexpensive, renewable and diverse sources of supply. 

1735. Entergy believes that from a transmission provider’s point of view it would be 

desirable to have LSEs provide ten or even five-year resource forecasts. Entergy 

recognizes that such a requirement may not be practical when LSEs depend significantly 
Docket No. RM06-16-000 - 447 - 

on short-term purchases due to the abundance of independent power producers or in areas 

that have an locational marginal pricing -like market structure. MISO states that its 

experience suggests that LSEs do not identify new generation resources except in very 

general terms past the second or third year. In most cases LSEs show future capacity 

requirements served from generic base load and peaking power resources or from 

potential contract purchases with no information on location. This increases the 

difficulty of accurate long-range transmission planning studies. 

1736. National Grid states that it is also vitally important to acknowledge that generation 

retirements may pose a greater threat to reliability in some areas of the country than the 

slow down of new generation. Because required notice periods for retirements may be as 

little as ninety days in some areas, it is imperative that transmission planners use a robust 

statistical approach to identify vulnerable sources of generation and conduct such 

modeling as an integral part of the transmission planning process. 

1737. MISO states that planning assumptions around generation retirements are 

particularly difficult because such assumptions are driven by complex economic factors 

that may or may not prevail. While MISO has the tools to project what unit may be more 

likely to retire than others, it contends that the preferred approach is to have in place tariff 

provisions that require suppliers to announce retirement intentions six months in advance 

of the retirement. This permits reliability studies to be performed with certainty and 

corrective actions to be implemented that could include placing the unit on contract to 

continue operations until appropriate operating measures or system expansions can be 

made. 

1738. SoCal Edison states that business decisions by generator owners to retire or 

mothball units are outside of SoCal Edison’s control, and generally SoCal Edison does 

not receive this information in a timely manner for transmission planning studies. 

1739. National Grid urges the Commission to support longer planning horizons. It states 

that in many respects, the ten year planning horizon may be too short a time frame for 

assessing transmission needs, particularly with regard to long distance extra high voltage 

facilities that pose considerable siting and permitting challenges. Establishing planning 

horizons that are shorter than transmission construction lead times may create gaps where 

the identification of a reliability need to which transmission may be the best solution 

occurs too late to head off the identified reliability violation. National Grid states that 

PJM is establishing a fifteen year planning horizon that will accommodate large-scale 

projects that are needed for reliability and to support regional transactions. 

1740. MISO and International Transmission note that while it is important for planners 

to have quality information on available resources, the enabling legislation for the ERO 

specifically excludes authority regarding resource adequacy. MISO states it is not certain 
Docket No. RM06-16-000 - 448 - 

how far the Reliability Standards can go. International Transmission states that, in the 

absence of a standard on resource adequacy, transmission service providers must use 

their judgment on potential new generation or retirements to create base cases and plan 

the system accordingly. 

1741. Reliant states that, while section 215 of the FPA requires the ERO to develop 

Reliability Standards that provide an adequate level of Bulk-Power System reliability, the 

proposed Reliability Standards surprisingly lack any substantive consideration of 

planning reserve obligations to ensure capacity available to meet the needs of a reliable 

system. Reliant proposes that each regional reliability organization develop and enforce 

its own minimum planning reserve margin. Such a program would be critical to the 

development of new generation, demand response and distributed generation resources 

and allow each region to retain its own autonomy in developing its own resource 

adequacy standards. 

1742. Process Electricity Committee supports long-term planning as a vital part of any 

economic and thorough set of Reliability Standards. However, it is concerned that 

transmission service providers who are also market participants will have an incentive to 

exploit commercially sensitive data on generation plans to the disadvantage of other 

competing suppliers. Process Electricity Committee asks the Commission to clarify that 

transmission planners may not use the Reliability Standard to obtain and exploit such 

information, and it urges the Commission to take all appropriate measures to guard 

against such abuse. 

(b) Commission Determination

1743. Several commenters addressed separately the availability of information on new 

generation resources and generation retirements, given that these have very different lead 

times. NERC, ISO-NE and others appear to be able to acquire the resource information 

they need on new resources and retirements for reliability assessments. Others, such as 

National Grid and MISO, have had difficulty in obtaining this information in a timely 

manner, particularly as it relates to generation retirements.

1744. The Commission disagrees with ISO-NE’s statement that planning for the 

introduction of resources ten years in advance is not necessary. The existing Reliability 

Standard requires that the planning horizon must take into account the lead times for 

siting and permitting of new long-distance transmission lines and other solutions that can 

exceed ten years. In short, the need for long-term planning has already been widely 

recognized. The Commission agrees with National Grid that establishing planning 

horizons that are shorter than transmission lead times may create gaps where the 

identification of a reliability need to which transmission may be the best solution occurs 
Docket No. RM06-16-000 - 449 - 

too late to avert the identified reliability violation. Indeed, this point is supported by the 

fact that PJM is establishing a fifteen year planning horizon.442 

1745. In the absence of information about future generation resources required for 

transmission planning the Commission notes that entities conduct assessments using 

assumptions based on the knowledge that certain areas are prime locations for new 

resources, particularly those resources that use non-transportable fuels. National Grid 

states that generation retirements may pose a greater threat to reliability in some areas 

than the slowdown of new generation construction. As a result, it states that it is 

imperative that transmission planners use robust statistical approaches to identify 

vulnerable sources of generation and conduct such modeling as an integral part of the 

transmission planning process. The Commission understands this as a further 

endorsement of its proposal to require a full range of sensitivity studies discussed above. 

1746. MISO, International Transmission and Reliant raise important issues about the 

absence of a Reliability Standard on resource adequacy. Reliant points out the 

inconsistency between the statutory requirement to provide an adequate level of BulkPower System reliability and the lack of any substantive consideration of planning 

reserve obligations to ensure capacity is available to meet the needs of a reliable system. 

In the same vein, the Commission notes that Requirement R7 of TOP-002-0 requires each 

balancing authority to plan to meet capacity and energy reserve requirements in the 

operating time frame but that there is no explicit corresponding consideration required of 

generation reserves in the planning time frame. 

1747. Section 215(a)(3) of the FPA makes clear that enforceable Reliability Standards 

may not address requirements to enlarge facilities or construct new generation capacity. 

We have noted that when a state or appropriate jurisdictional entity has such a 

requirement, it should be included in transmission planning analysis. Resource adequacy 

levels are set to achieve a number of goals, one of which is system reliability. Our 

jurisdiction is to approve and enforce Reliability Standards that provide for an adequate 

level of reliability for the Bulk-Power System. The TPL group of Reliability Standards 

includes load growth, changes in the transmission topology, existing generation, 

generation retirements, and confirmed new generation as inputs to the analyses. When an 

entity does not meet a reliability criterion, including the inability of generation to be 

deliverable to load, mitigation plans are required. Although the Commission anticipates 

that some of those mitigation plans may include new generation, we do not require this. 

 442 See http://www.pjm.com/contributions/pjm-manuals/manuals.html
Docket No. RM06-16-000 - 450 - 

1748. Some entities have proposed possible solutions to address the gap of inadequate 

and unreliable resource information for long-term planning as required by the TPL group 

of Reliability Standards. CAISO suggests that generator owners and operators be 

required to provide data on new generation and retirements to their planning authorities. 

Entergy proposes requiring LSEs to provide this information, but recognizes that this 

approach has its limitations. MISO contends the preferred approach to retirements is to 

have in place tariff provisions that require suppliers to announce retirement intentions six 

months in advance of retirements. Process Electricity Committee is concerned about the 

implications of sharing non-public transmission or customer information which could 

then be exploited to the disadvantage of competing suppliers. The Commission’s 

Standards of Conduct addresses the sharing of such information and generally prohibits 

the sharing of commercially sensitive information between the transmission organization 

and affiliated merchant functions.443 In response to Process Electricity Committee, the 

Commission will continue to enforce the information sharing prohibition in the Standards 

of Conduct. 

1749. The responses to the Commission’s inquiry on these matters are helpful. The 

comments further point out the importance of conducting a wider range of sensitivity 

studies on generation scenarios. However, the Commission is not directing at this time 

any modifications to address the Commission’s concerns. 

vi. Sharing of Information with Neighboring Systems

1750. In the NOPR, the Commission stated that, because neighboring systems may be 

adversely impacted, such systems should be involved in determining and reviewing 

system conditions and contingencies to be assessed in connection with Requirement R1.3 

of TPL-001-0 to TPL-004-0.444 

(a) Comments

1751. EEI, APPA, FirstEnergy, ERCOT and SDG&E support or acknowledge the value 

of sharing of various kinds of planning information with neighboring systems. 

FirstEnergy states that the proposed requirement that system conditions and 

contingencies assessed be shared and reviewed by neighboring systems will improve 

communications with interconnected companies. This process was established among 

former ECAR companies through the “ECAR Peer Review Process,” and FirstEnergy 

 443See Order No. 2004. 

444 NOPR at P 1063. 
Docket No. RM06-16-000 - 451 - 

recommends that regional reliability organizations be encouraged to establish a similar 

process going forward. EEI and APPA state that sharing of various kinds of planning 

information, including expected generation additions and retirements, planned outages, 

demand forecasts and estimates of firm transfers will go a long way to improving the 

quality and consistency of planning study efforts. However, it is not clear to EEI whether 

a formal Reliability Standard would be the most effective approach. An alternative could 

be to request that NERC oversee an informal process to explore alternatives and report 

back to the Commission by a specific date. Although ERCOT states that this proposal is 

a sensible recommendation, it also states that it would not be appropriate for ERCOT 

since the transmission service provided there is not subject to interruption by the ISO, 

and outbound flows are also not interrupted if there is a shortage of capacity. 

1752. SDG&E notes that under the auspices of the CAISO it regularly convenes 

stakeholder meetings with the general public, neighboring utilities, generator owners, 

regulators and the CAISO. In these meetings, SDG&E reviews the grid assessment 

process and receives comments from participants about all aspects of its process. As a 

member of WECC, SDG&E states that it also holds meetings to discuss inter-area 

projects that SDG&E has proposed to construct. This review group consists of 

neighboring utilities, generator owners and other stakeholders who are members of 

WECC. Similarly, SDG&E maintains that it participates in other California-based utility 

review groups. SDG&E finds that these existing processes provide ample opportunities 

for regular sharing of relevant information with neighboring transmission planning 

entities. It thus recommends that the Reliability Standards development process take into 

account existing forums for apprising neighboring utilities of current and anticipated 

transmission planning issues and projects. If the Commission believes additional 

communications are needed, SDG&E strongly recommends that the Commission, 

through NERC or the applicable Regional Entity, specify in greater detail the nature and 

periodicity of the information to be shared pursuant to the TPL Reliability Standards. 

1753. SoCal Edison states that TPL-001-0 is for systems operating under normal 

conditions, and as such there should not be a need for any review by neighboring 

systems. 

(b) Commission Determination

1754. Most commenters agree with the Commission’s proposal that neighboring 

systems be involved in a peer review of system assessments in connection with 

Requirement R1.3 of TPL-001-0 through TPL-004-0. Given that neighboring systems 

assessments by one entity may identify possible interdependant or adverse impacts on its 

neighboring systems, this peer review will provide an early opportunity to provide input 

and coordinate plans. The Commission therefore disagrees with SoCal Edison’s view 

that there is no need for any review by neighboring systems for TPL-001-0. For 
Docket No. RM06-16-000 - 452 - 

example, the planning authorities needs to be consistent in the line flow values that they 

use. 

1755. While supporting the concept of a peer review, EEI questions whether making this 

a Requirement in a Reliability Standard is the most effective approach or whether NERC 

should explore alternatives and report to the Commission by a specific date. The 

Commission sees no reason why peer reviews should not be part of a Reliability Standard 

since TPL-001-0 through TPL-004-0 already include in Requirement R1.3 a review of 

assessments by the associated regional reliability organization. The Commission 

understands that some regions include peer review as part of their procedures. 

Accordingly, to ensure that neighboring systems are not adversely affected and to provide 

an early opportunity for input and coordination of plans, the Commission directs the ERO 

to include these modifications to the Reliability Standard through its Reliability 

Standards development process to provide for the appropriate sharing of information with 

neighboring systems. 

1756. The Commission has taken action on its OATT reform initiative in Order No. 890. 

In that order, the Commission encourages the formation of regional planning processes 

and economic planning studies.445 Sharing of information and peer review are the first 

steps in a regional planning process. The Commission provides guidance and direction 

on these subjects in our discussion of Reliability Standard TPL-005-0. 

b. System Performance Under Normal (No Contingency) 

Conditions (TPL-001-0)

1757. Reliability Standard TPL-001-0 deals with planning related 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.446 The Reliability Standard seeks 

to ensure that the Bulk-Power System is planned to meet the system performance 

requirements under these normal conditions by requiring the transmission planner and the 

planning authority to evaluate their transmission system annually and document the 

ability of that system to meet the performance requirements established in the Reliability 

 445 Order No. 890 at P 526, 542. 

446 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 - 453 - 

Standard under conditions where no system contingencies are present.447 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. 

1758. 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 set forth 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. 

1759. The Commission proposed in the NOPR 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, we proposed to direct NERC to 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) of 

Table 1 to not apply emergency ratings to compare stresses on the system under normal 

conditions as recommended by the Transmission Issues Subcommittee of the NERC 

Planning Committee448 and require that normal facility ratings be in accordance with 

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

Reliability Standard. 

448 See NERC Transmission Issues Subcommittee Report: Evaluation of Criteria, 

Methods and Practices Used in System Design, Planning and Analysis in Response to 

NERC Blackout Recommendation 13c. Appendix B, November 28, 2005. 
Docket No. RM06-16-000 - 454 - 

Reliability Standard FAC-008-1 and that normal voltages be in accordance with 

Reliability Standard VAR-001-1.449

i. Comments

1760. APPA agrees with the Commission that TPL-001-0 is sufficient for approval as a 

mandatory and enforceable standard. 

1761. MidAmerican and others generally support the Commission’s proposal to improve 

TPL-001-0 but caution that: (1) planned outages should only be considered at load levels 

and conditions under which they commonly occur and (2) emergency ratings should 

recognize the varying time frames of overloads that result from various contingency 

events. Further, MidAmerican states that, while it is appropriate that planning margins 

for normal voltages be calculated in accordance with VAR-001-1 as proposed by the 

Commission, it would be better if the proposed modification provided that voltage 

criteria do not conflict with VAR-001-1. Northern Indiana agrees with the Commission’s 

position regarding consideration of planned outages and states that it considers them 

currently in its transmission planning studies. International Transmission states that both 

planned outages of critical equipment and the extended forced outages of similar 

equipment should be considered. FirstEnergy states that planned outages should be 

accounted for at load levels and conditions under which they commonly apply. 

1762. Other commenters disagree that planned outages of critical equipment should be 

included in TPL-001-0.450 They contend that the Reliability Standard has a very simple 

aim, namely, to examine whether a system can perform under normal system intact 

conditions, i.e., when all elements are in service and operating as expected. The outages 

contemplated are appropriate for TPL-002-0 through TPL-004-0 where the planned 

outage could be a line outage caused by a maintenance project that extends into a period 

where the system is heavily loaded. SDG&E states that for near-term planned outages, 

the transmission planning entity should retain an appropriate amount of latitude to plan 

the outage’s timing and details and to modify them as necessary. SDG&E comments 

that, for outages planned with a more distant horizon (one year or longer), this 

information can be accounted for in sensitivity analyses. SoCal Edison states that no 

information will be available about planned outages of critical equipment to be used for 

short-term (five years) or long-term (10 years) simulations. It may be possible to 

consider planned outages of critical equipment if there is a major project construction 

 449 NOPR at P 1065-67. 

450 See, e.g., EEI, APPA, SDG&E, Entergy, SoCal Edison and TVA. 
Docket No. RM06-16-000 - 455 - 

activity. If generators and transmission lines are out for scheduled maintenance during 

off-peak load conditions, then these outages should be considered. 

1763. EEI supports the Commission’s recommendation to modify footnote (a) in Table 

1. International Transmission states that the footnotes in Table 1 are not footnotes but 

rather requirements for transmission system performance. These should be made 

requirements of the Reliability Standards so that they are more obvious and easier to 

monitor. APPA, LPPC and TANC recommend that changes to footnotes of Table 1 be 

subject to the Reliability Standards development process. They state that the footnotes 

have been extensively reviewed by technical experts at NERC for several years and 

currently represent a general consensus among these industry technical experts. Changes 

to the footnotes impact Table 1 and have a direct impact on the determination of the 

severity of consequences that were approved along with the original Reliability Standard. 

Therefore, the Commission should give due weight to the ERO and allow the Reliability 

Standards development process to resolve any existing ambiguities in the Table 1 

footnotes. 

ii. Commission Determination

1764. The Commission approves TPL-001-0 as a mandatory and enforceable Reliability 

Standard. In addition, we direct the ERO to develop modifications to TPL-001-0 through 

the Reliability Standards development process, as discussed below. 

1765. In assessing system conditions, Requirement R1.3.1 of TPL-001-0 requires entities 

to cover “critical system conditions and study years,” as deemed appropriate by the entity 

performing the study. As stated in the NOPR, system conditions are as important as 

contingencies in evaluating the performance of present and future systems,451 and yet 

TPL-001-0 does not specify the rationale for determining critical system conditions and 

study years. Consistent with our discussion of the issue above regarding sensitivity 

studies and critical system conditions, the Commission concludes that proposed 

modification (1), which requires that critical system conditions be determined by 

conducting sensitivity studies, is justified. Accordingly, we direct the ERO to modify the 

Reliability Standard to require that critical system conditions and study years be 

determined by conducting sensitivity studies with due consideration of the range of 

factors outlined above. 

1766. Requirement R1.3 of TPL-001-0 states that the planning authority and 

transmission planner must provide studies and simulations to support its planning 

 451 NOPR at P 1046. 
Docket No. RM06-16-000 - 456 - 

assessments, and that the specific elements selected for the study shall be acceptable to 

the associated regional reliability organization. Given that neighboring systems may be 

adversely affected, our goal is to ensure that they are involved in the determination and 

review of system assessments to permit an early opportunity to provide input and 

coordinate plans. We discussed above the issue of information sharing as it applies to the 

TPL group of Reliability Standards generally and, consistent with our conclusions there, 

we direct the ERO to modify TPL-001-0 to require a peer review of planning assessments 

with neighboring entities. 

1767. The Commission received no comments on its proposal that Requirement R1.3 be 

modified to substitute the reference to the regional reliability organization with a 

reference to the Regional Entity. The Commission has explained the need for this 

modification above, and therefore it directs the ERO to modify Requirement R1.3 of 

TPL-001-0 to substitute the reference to the regional reliability organization with a 

reference to the Regional Entity. 

1768. While some commenters support the consideration of planned outages at load 

levels for conditions under which they are performed, others disagree on the grounds that 

the goal of TPL-001-0 is to ensure that the Bulk-Power System can perform reliably 

when all elements are in service and operating as expected. The Commission notes that 

Reliability Standards TPL-002-0 through TPL-004-0 include consideration of planned 

outages, as initial system conditions, at load levels for conditions under which they are 

performed. Because these Reliability Standards, and not TPL-001-0, will govern the 

adequacy of the Bulk-Power System under planned outage conditions, the Commission 

will not adopt the NOPR proposal to require consideration of planned outages at load 

levels for conditions under which they are performed for Reliability Standard TPL-001-0. 

However, consistent with our discussion above on spare equipment strategy, the 

Commission directs a modification to this Reliability Standard to require assessments of 

outages of critical long lead time equipment, consistent with the entity’s spare equipment 

strategy. Thus, for example, if an entity’s spare equipment strategy for the permanent 

loss of a transformer is to use a “hot spare” or to relocate a transformer from another 

location in a timely manner, the outage of the transformer need not be assessed under 

peak system conditions. However, if the spare equipment strategy entails acquisition of a 

replacement transformer that has a one-year or longer lead time, then the outage of the 

transformer must be assessed under peak loading conditions likely to be experienced. 

This approach will ensure that system conditions are adequately assessed. 

1769. While commenters generally agree with the Commission’s proposal to modify 

footnote (a) of Table 1, they caution that any changes to the footnotes affect Table 1 and 

should be reviewed through NERC’s Reliability Standards development process. 

International Transmission states that the footnotes in Table 1 are not footnotes but rather 

requirements for transmission system performance and therefore should be made 
Docket No. RM06-16-000 - 457 - 

Requirements in the Reliability Standard. The Commission agrees with International 

Transmission because this will promote clarity in and consistent application of the 

Reliability Standard. The Commission therefore directs the ERO to modify the 

Reliability Standard to address the concerns regarding footnote (a) of Table 1, including 

the applicability of emergency ratings and consistency of normal ratings and voltages 

with values obtained from other Reliability Standards. As with any modification to a 

Reliability Standard, modifications to TPL-001-0 should be developed through the 

ERO’s Reliability Standards development process. 

1770. Accordingly, the Commission approves Reliability Standard TPL-001-0 as 

mandatory and enforceable. In addition, the Commission directs the ERO to develop a 

modification to TPL-001-0 through the Reliability Standards development process that: 

(1) requires that critical system conditions and study years be determined by conducting 

sensitivity studies with due consideration of the range of factors outlined above; (2) 

requires a peer review of planning assessments with neighboring entities; (3) modifies 

Requirement R1.3 to substitute the reference to regional reliability organization with 

Regional Entity; (4) requires assessments of outages of critical long lead time equipment, 

consistent with the entity’s spare equipment strategy and (5) address the concerns 

regarding footnote (a) of Table 1, including the applicability of emergency ratings and 

consistency of normal ratings and voltages with values obtained from other Reliability 

Standards and the concerns raised by International Transmission in regard to the 

footnotes in Table 1. 

c. System Performance Following Loss of a Single Element 

(TPL–002–0)

1771. Reliability Standard TPL-002-0 addresses system planning related 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. The Reliability Standard seeks to ensure that the future BulkPower System is planned to meet the system performance requirements, with the loss of 

one element, by requiring that the transmission planner and planning authority annually 

evaluate and document the ability of the transmission system to meet the performance 

requirements where an event results in the loss of a single element.452 Meeting these 

requirements means two things. First, it means that 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 

 452 The performance requirements are set forth in Category B of Table 1 of the 

Reliability Standard. 
Docket No. RM06-16-000 - 458 - 

demands. Second, it means that 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.453 The Reliability Standard applies both to nearterm and longer-term planning horizons. 

1772. TPL-002-0 specifies 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 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 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. 

1773. The Commission proposed in the NOPR to approve Reliability Standard TPL-002-

0 as mandatory and enforceable. In addition, pursuant to section 215(d)(5) of the FPA 

and § 39.5(f) of our regulations, we proposed to direct NERC to submit a modification to 

TPL-002-0 that: (1) requires that critical system conditions be determined in the same 

manner as proposed for TPL-001-0; (2) requires the inclusion of the reliability impact of 

the entity’s 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) to Table 1 to allow no 

firm load or firm transactions to be interrupted except for consequential load loss. 

i. Comments

1774. APPA agrees that TPL-002-0 is sufficient for approval as a mandatory and 

enforceable reliability standard. 

 453 Footnote b to Table 1 allows for the interruption of firm load for consequential 

load loss. 
Docket No. RM06-16-000 - 459 - 

1775. In response to the Commission’s proposal454 that NERC modify TPL-002-0, in 

part, because it does not address situations in which critical equipment may be 

unavailable for a prolonged period, Northern Indiana states that systems depicted in 

planning studies cannot possibly contain complete planned and forced outage schedules 

for the next ten years. For this reason TPL-003-0 deals with double contingencies, i.e., 

contingencies that allow operator intervention after the first outage, and then capture 

system response to an additional outage. Operator intervention includes coordination of 

contingency plans and may impact strategies for spare equipment, particularly for critical 

equipment. 

1776. EEI and MidAmerican support requiring all generators to ride through the same 

contingencies as required for wind generators. Constellation notes that while it supports 

the Commission’s proposed modifications to TPL-002-0, an explicit requirement that all 

generators stay online during the same set of Category B and C events, as is required for 

wind generators, is too broad. Constellation requests that the Commission modify this 

requirement to recognize that NRC has specific requirements for how nuclear generation 

must respond to disturbances on the Bulk-Power System, and that those NRC rules 

should apply. Moreover, Constellation generally recommends that the Reliability 

Standards applied to nuclear generation should be consistent with NRC requirements and 

that NRC rules should control in the event of conflict. 

1777. NRC notes that there appears to be significant variation in the interpretation of this 

Reliability Standard. It states that some of its licensees interpret the TPL-002-0 

Reliability Standard to state that if a licensee is operating in an N-1 condition another 

single contingency does not need to be considered. NRC states that its interpretation has 

been that the N-1 condition is always analyzed from the conditions being experienced. 

They state that this Reliability Standard should be clarified and recommend specific 

revisions to Requirements R1.6, R2.1, R2.2 and Levels of Non-Compliance. 

1778. Northern Indiana expresses concern about the statement in P 1062 of the NOPR 

that “load models used in system studies have a significant impact on system 

performance. . . .” Northern Indiana believes the opposite is true, i.e., system 

performance has a significant impact on load models. The goal of the models is to 

attempt to capture system performance. 

1779. MidAmerican supports the proposed clarifications to operating steps and to 

footnote (b). International Transmission states that more clarification should be provided 

for the thresholds of normal and emergency ratings. There are potential inconsistencies 

 454 NOPR at P 1081. 
Docket No. RM06-16-000 - 460 - 

with respect to whether or not an entity can plan to operate above normal ratings, but 

below emergency ratings, and for how long. 

1780. Northern Indiana also takes issue with the NOPR proposal that no load or 

transactions be interrupted except for consequential load loss. Attempting to reduce the 

probability of load loss to zero would greatly increase capital spending, and therefore 

increase rates to customers, and all in the name of achieving an unattainable goal. PG&E 

disputes that the Reliability Standard should provide limits on the magnitude and duration 

of consequential load loss. Determining the magnitude and consequences of load loss is 

a factor in the economic evaluation during the development of transmission expansion 

plans. This economic evaluation is not an appropriate subject for this Reliability 

Standard. Northern Indiana urges the Commission to acknowledge that planning studies 

by nature must balance infrastructure improvement and expansion against site-specific 

and regional load projections, using available resources. It questions whether the NOPR 

reflects a proper balance between the many costs involved and the benefits, if any, that 

would be realized. 

1781. Entergy opposes the Commission’s proposed guidance concerning footnote (b) to 

Table 1 for two reasons. First, Entergy believes the Commission should give due weight 

to the technical expertise of NERC and permit NERC to address these matters through 

Reliability Standards development process. Second, the Commission’s guidance 

suggests that it views all transmission outages as having the same level of importance to 

and impact on the interconnected transmission grid. Entergy states that the Commission 

should recognize that the effect of transmission outages can be local in nature and have 

no impact on the reliability of the Bulk Power System. Removing the transmission 

operator’s ability to shed load or enact other system adjustments as appropriate for a 

single contingency would result in significant facility upgrade costs simply to avoid the 

consequence of a local outage. Entergy requests that the Commission clarify that its 

guidance does not constrain the transmission operator’s ability to determine the best 

course of action to take to address any reliability constraint that may result from these 

local outages. 

1782. PG&E disagrees with the Commission’s proposal to delete from footnote (b) of 

this Reliability Standard the phrase “to prepare for the next contingency, system 

adjustments are permitted, including curtailments of contracted Firm (non-recallable 

reserved) electric power transfers.”455 PG&E states that this phrase permits critical 

system adjustments to reduce the potential for and impact of future contingencies. It 

would allow re-scheduling power (but not load shedding) as part of manual system 

 455 Id. at P 1084. 
Docket No. RM06-16-000 - 461 - 

adjustment after the first Category B contingency (first N-1) to bring the system back to a 

safe operating point before the next Category B contingency (second N-1). This phrase is 

consistent with the manual system adjustment allowed in Category C.3.456 PG&E states 

that, contrary to the Commission’s interpretation, footnote (c) does not capture this 

phrase. The difference between footnote (b) as part of Category B and Category C.3 is 

that footnote (b) applies before the second N-1, whereas Category C.3 applies after the 

second N-1. Without this phrase in footnote (b), no manual system adjustment would be 

allowed after a Category B contingency, which would be inconsistent with Category C.3. 

1783. APPA and LPPC recommend that changes to the footnotes of Table 1 be subject to 

the NERC Reliability Standards development process. They state that the footnotes have 

been extensively reviewed by technical experts at NERC for several years and currently 

represent a general consensus among these industry technical experts. Changes to the 

footnotes affect Table 1 and have a direct impact on the determination of the severity of 

consequences that were approved along with the original standard. APPA also states that 

consideration of reliability impacts of spare equipment strategies and obligations of all 

generators to have the same voltage ride through capabilities are important changes that 

should not be made by Commission fiat. 

ii. Commission Determination

1784. The Commission approves TPL-002-0 as a mandatory and enforceable Reliability 

Standard. In addition, we direct the ERO to develop modifications to TPL-002-0 through 

the Reliability Standards development process, as discussed below. 

1785. The Commission notes that, like Requirement R1.3.1 of TPL-001-0, R1.3.2 of 

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 

it does not specify the rationale for determining critical system conditions and study 

years. The Commission directs the ERO to modify TPL-002-0 to require that critical 

system conditions and study years be determined in the same manner as it directed with 

regard to TPL-001-0. The Commission’s explanation of the need for that change applies 

equally here. 

1786. With regard to Northern Indiana’s concerns, we disagree that the proposal to 

address situations in which critical equipment may be unavailable for a prolonged period 

 456 From TPL Standards Table 1, Category C.3 is Category B (B1, B2, B3 or B4) 

contingency, manual system adjustments, followed by another Category B (B1, B2, B3 or 

B4) contingency. 
Docket No. RM06-16-000 - 462 - 

requires planned and forced outage schedules for the next ten years. Reliability Standard 

TPL-002-0 requires consideration of planned outages at those demand levels for which 

planned outages are performed but does not address situations in which critical long lead 

time equipment, such as a transformer or phase angle regulator, may be unavailable for a 

prolonged period that could extend into periods where planned outages of such 

equipment would not normally be performed. Assessments of these situations do not 

require outage schedules for the next ten years but rather identification of which facilities 

are deemed to be critical that have long lead times for repair or replacement. Given that 

planned outage considerations of such long lead time equipment are inexorably linked to 

spare equipment strategy, consistent with our discussion of the issue above in connection 

with spare equipment strategy, the Commission directs the ERO to modify the Reliability 

Standard to require assessments of planned outages of long lead time critical equipment 

consistent with the entity’s spare equipment strategy. 

1787. In the NOPR, the Commission identified an implicit assumption in the TPL 

Reliability Standards that all generators are required to ride through the same types of 

voltage disturbances and remain in service after the fault is cleared. This implicit 

assumption should be made explicit. Commenters agree with the proposed requirement 

for all generators to ride through the same set of Category B and C events as required for 

wind generators. The Commission understands that NRC has both degraded voltage and 

loss of voltage requirements. The degraded voltage requirement allows the voltage at the 

auxiliary power system busses to go below the minimum value for a time frame that is 

usually much longer than normal fault clearing time.457 If a specific nuclear power plant 

has an NRC requirement that would force it to trip off-line if its auxiliary power system 

voltage was depressed below some minimum voltage, the simulation should include the 

tripping of the plant in addition to the faulted facilities. In this regard, the Commission 

agrees that NRC requirements should be used when implementing the Reliability 

Standards. Using NRC requirements as input will assure that there is consistency 

between the Reliability Standards and the NRC requirement that the system is accurately 

modeled. Accordingly, the Commission directs the ERO to modify the Reliability 

Standard to explicitly require either that all generators are capable of riding through the 

same set of Category B and C contingencies, as required by wind generators in Order No. 

661, or that those generators that cannot ride through be simulated as tripping. If a 

generator trips due to low voltage from a single contingency, the initial trip of the faulted 

element and the resulting trip of the generator would be governed by Category B 

contingencies and performance criteria. 

 457 10 CFR 50, Appendix a, GDC17. 
Docket No. RM06-16-000 - 463 - 

1788. The Commission agrees with NRC that for operations purposes the N-1 condition 

is always analyzed from the conditions being experienced. In other words, allowing for 

the 30 minute system adjustment period, the system must be capable of withstanding an 

N-1 contingency, with load shedding available to system operators as a measure of last 

resort to prevent cascading failures. However, for planning purposes, a different analysis 

applies. The N-1 condition is a Category B event under TPL-002-0, and, following the 

N-1 contingency, the system must be stable and thermal loading and voltages be within 

applicable limits. Some adjustment of generation or other controls is permitted to return 

loadings to within continuous ratings, provided the loadings before adjustments are 

within the emergency or short-term ratings. Under TPL-002-0 the system is not required 

to be able to withstand another N-1 contingency. That N-1 requirement is a Category C 

contingency which is addressed by TPL-003-0. The Commission has addressed NRC’s 

comment concerning N-1 contingencies in real-time operation in TOP-002. In regard to 

the specific revisions proposed by NRC, the Commission directs the ERO to consider 

these as part of the Reliability Standards development process. 

1789. In regard to Northern Indiana’s comment concerning the load modeling statement 

made in the NOPR, it should be clear that the context of the discussion is system 

performance during simulations. Load models used in simulations clearly should, to the 

extent feasible, represent the actual performance of the aggregate mix of industrial, 

commercial and residential loads. If the load model representations used in simulations 

do not mirror the actual performance of loads, especially during dynamic simulations, but 

also when carrying out voltage stability studies, the simulation results will not be 

accurate. Because load representation in simulations has a significant impact on 

simulation results and often load models are not well known, it is common practice for 

planners to perform sensitivity studies with a range of load models. Accordingly, as 

proposed in the NOPR, the Commission directs the ERO to modify the Reliability 

Standard to require documentation of load models used in system studies and the 

supporting rationale for their use. 

1790. In the NOPR, the Commission set forth its rationale for proposing that the ERO 

clarify the phrase “permit operating steps necessary to maintain system control” in 

footnote (a) to Table 1.458 Specifically, the Commission stated that the operating steps 

required to relieve emergency loadings and return the system to a normal state should not 

include firm load shedding. MidAmerican agrees with the Commission. International 

Transmission states clarification is required on the thresholds for normal and emergency 

ratings and, in particular, on whether an entity can plan to operate above normal ratings 

but below emergency ratings and for how long. The Commission agrees that this issue 

 458 NOPR at P 1083. 
Docket No. RM06-16-000 - 464 - 

requires clarification and therefore directs the ERO to modify the standard to clarify the 

phrase of footnote (a) that states “permit operating steps necessary to maintain system 

control” to clarify the use of emergency ratings. 

1791. The Commission stated in the NOPR that footnote (b) raises three issues that need 

to be addressed.459 Two relate to the use of planned or controlled load interruption under 

certain circumstances, and the third relates to the use of system adjustments including 

curtailment of firm transfers to prepare for the next contingency. Northern Indiana and 

Entergy disagree with the Commission’s proposal 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). The commenters argue that the impact of transmission outages 

can be local in nature and have no impact on the reliability of the Bulk-Power System and 

that removing the option to shed load in a local area for a single contingency would result 

in significant facility upgrade costs and therefore increased rates to customers simply to 

avoid a local outage. Entergy seeks clarification that the Commission does not intend to 

constrain the transmission operator’s ability to determine the best course of action to 

address local reliability constraints. 

1792. The NOPR proposed a modification that would clarify footnote (b) as disallowing 

loss of such firm load or the curtailment of firm transactions after a first contingency of 

the bulk electric system. In its comments to the Staff Preliminary Assessment, NERC 

agreed with this interpretation, representing that a practice that permits the planned 

interruption of “firm transmission service” is a misapplication of the Reliability 

Standard.460 Some commenters now argue otherwise, and in some cases cite examples 

where, based on a balance of economic and reliability considerations, it may be 

preferable to plan the bulk electric system in such a manner that contemplates the 

interruption of some firm load customers in the event of a N-1 contingency. We view 

these arguments as based largely on the matter of economics, not reliability, with the 

underlying premise that it is not economically feasible to invest in the bulk electric 

system to the point that it can continue service to all firm load customers under some 

specific N-1 scenarios. Therefore, they argue, the ambiguities of footnote (b) should be 

 459 Id. at P 1084. 

460 “NERC standards, including footnote (b), are not intended to endorse or 

approve planning the interconnection using radial configurations as a preferred method 

for reliably serving load, nor do NERC standards consider load shedding acceptable for a 

single contingency.” NERC comments to the Staff Preliminary Assessment at 57-58. 
Docket No. RM06-16-000 - 465 - 

interpreted to allow that an entity plan for some amount of load loss to avoid costly 

infrastructure investments. 

1793. The Commission considers this matter to be a fundamental issue of transmission 

service. Indeed, the ERO's definition of "firm transmission service" specifically states 

that it is the "highest quality (priority) service offered to customers under a filed rate 

schedule that anticipates no planned interruption." 

1794. Based on the record before us, we believe that the transmission planning 

Reliability Standard should not allow an entity to plan for the loss of non-consequential 

load in the event of a single contingency.461 The Commission directs the ERO to clarify 

the Reliability Standard. Regarding the comments of Entergy and Northern Indiana that 

the Reliability Standard should allow entities to plan for the loss of firm service for a 

single contingency, the Commission finds that their comments may be considered 

through the Reliability Standards development process. However, we strongly 

discourage an approach that reflects the lowest common denominator.462 The 

Commission also clarifies that an entity may seek a regional difference to the Reliability 

Standard from the ERO for case-specific circumstances. 

1795. PG&E disputes that the Reliability Standard should provide limits on the 

magnitude and duration of consequential load loss, as this is an economic evaluation and 

is not an appropriate goal for this Reliability Standard. The Commission disagrees. 

Indeed in its comments to the Staff Preliminary Assessment, the ERO raised the issue of 

what is an acceptable magnitude and duration of consequential load loss.463 The 

Commission notes that most utilities have guidelines for the magnitude and duration of 

load loss that is acceptable on radial facilities before the facilities are looped to provide a 

second source of supply to accommodate load growth. NERC also stated that it 

recognizes that looped configurations are key to the reliable operation of the 

Interconnection and to meet reasonable expectations for reliable service to loads.464 The 

 461 Consequential load is the load that is directly served by the elements that are 

removed from service as a result of the contingency. 

462 See Order No. 672 at P 329. 

463 NERC Comments to Staff Preliminary Assessment at 56 – 57. 

464 “NERC recognizes that looped configurations are key to the reliable operation 

of the interconnection, and to meet reasonable expectations for reliable service to loads.” 

Id. at 57. 
Docket No. RM06-16-000 - 466 - 

Commission, therefore, suggests that the ERO consider developing a ceiling on the 

amount and duration of consequential load loss that will be acceptable. If the ERO 

determines that such a ceiling is appropriate, it should be developed through the ERO’s 

Reliability Standards development process. Further, we note that the DOE thresholds for 

reporting disturbances on Form EIA-417 would be one example of an appropriate starting 

point for developing such a ceiling. These thresholds for load loss are 300 MW for 15 

minutes or 50,000 customers for one hour, whichever is greater. 

1796. The third issue with footnote (b) relates to the Commission’s proposal in the 

NOPR to delete the footnote’s second sentence, which states “[t]o prepare for the next 

contingency, system adjustments are permitted, including curtailments of contracted Firm 

(non-recallable reserved) electric power transfers.”465 PG&E disagrees with the 

Commission’s proposal because it allows re-scheduling power (but not load shedding) as 

part of manual adjustment after the first Category B contingency to bring the system back 

to a safe operating point. The Commission agrees that footnote (b) should permit manual 

adjustments including generation redispatch and transmission reconfiguration, but not 

load shedding, to return the system to a normal operating state within the time period 

permitted by the emergency or short term ratings. The Commission understands that this 

is the normal practice used by most transmission planners. However, the system 

adjustments permitted in the statement above includes curtailments of contracted firm, 

non-recallable reserved and electric power transfers and this is not acceptable for 

Category B single contingencies. Therefore, the ERO should modify the sentence to 

indicate that manual system adjustments, except for shedding firm load or curtailment of 

firm transfers, are permitted after the first contingency to bring the system back to a 

normal operating state. The Commission disagrees with PG&E’s statement that the 

difference between footnote (b) as part of Category B and Category C.3 is that footnote 

(b) applies before the second N-1 contingency, whereas Category C.3 applies after the 

second N-1 contingency. Rather, manual adjustments referred to in both cases apply 

after the first N-1 contingency. The Commission, therefore, directs the ERO to modify 

the second sentence of footnote (b) to clarify that manual system adjustments other than 

shedding of firm load or curtailment of firm transfers are permitted to return the system 

to a normal operating state after the first contingency, provided these adjustment can be 

accomplished within the time period allowed by the short term or emergency ratings. 

1797. Accordingly, the Commission approves Reliability Standard TPL-002-0 as 

mandatory and enforceable. In addition, the Commission directs the ERO to develop a 

modification to TPL-002-0 through the Reliability Standards development process that: 

(1) requires that critical system conditions be determined in the same manner as we 

 465 NOPR at P 1083. 
Docket No. RM06-16-000 - 467 - 

propose to require for TPL-001-0; (2) requires assessments of planned outages of long 

lead time critical equipment consistent with the entity’s spare equipment strategy; (3) 

requires all generators to ride through the same set of Category B and C contingencies as 

required by wind generators in Order No. 661, or to simulate those generators that cannot 

ride through as tripping; (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” in footnote (a) and the use of emergency 

ratings and (6) clarifies footnote (b) in regard to load loss following a single contingency, 

specifying the amount and duration of consequential load loss and system adjustments 

permitted after the first contingency to return the system to a normal operating state, as 

discussed above. 

d. System Performance Following Loss of Two or More 

Elements (TPL-003-0)

1798. Reliability Standard TPL-003-0 seeks to ensure 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. 

1799. 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. 

1800. The Commission proposed in the NOPR 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, we proposed to direct NERC to 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) makes certain 
Docket No. RM06-16-000 - 468 - 

clarifications to footnote (c) to Table 1; (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 Standard. 

1801. The Commission also sought comments on one potential addition to TPL-003-0. 

It noted that Category C3 of this Reliability Standard involves a situation in which two 

single contingencies occur, with manual system adjustments permitted after the first 

contingency to prepare for the next one (generally referred to as N-1-1). However, the 

Commission also noted that 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. For that reason some entities plan and operate their 

systems so that they are able to withstand the simultaneous occurrence of the two 

contingencies (normally referred to as N-2) for major load pockets. The Commission 

sought comments on the value and appropriateness of including such a requirement in 

TPL-003-0. 

i. Comments

1802. LPPC recommends that changes to footnotes of Table 1 be subject to the NERC 

Reliability Standards development process. It states that the footnotes have been 

extensively reviewed by technical experts at NERC for several years and currently 

represent a general consensus among these industry technical experts which should be 

given due weight by the Commission. Changes to the footnotes impact Table 1 and have 

a direct impact on the determination of the severity of consequences that were approved 

along with the original Reliability Standard. 

1803. FirstEnergy supports the proposed requirement to document proxies of subsequent 

line trips due to thermal overload and low voltage generation trips to evaluate potential 

cascading conditions. FirstEnergy states it currently is required to account for these items 

in its planning process. 

1804. EEI questions the value of providing proxies when planners conduct thousands of 

studies based on combinations of contingencies under a broad range of circumstances and 

conditions, especially in longer-term planning horizons where the uncertainty around the 

value of any one variable is already very high. SoCal Edison states that one can 

determine the cascading outages in load flow studies. In transient stability studies, if the 

outage is severe, then the thermal overload relays and undervoltage relays, if modeled, 

will trip the load. If the load tripped was not planned to be tripped for this outage, then 

the planning authority should take the necessary steps to avoid this situation, as cascading 

is not allowed. 
Docket No. RM06-16-000 - 469 - 

1805. LPPC and Northern Indiana oppose the proposal to require proxies necessary to 

simulate cascading outages be defined and documented. Northern Indiana states that 

there is no consensus on what these proxies should be. LPPC states that utility planners 

have traditionally used their engineering judgment to simulate a conservative estimate of 

the level of thermal overload or low voltage that will cause the likelihood of subsequent 

line or generator trips and cascading events. LPPC states that this approach has been 

successful, and NERC should not be asked to second-guess the decisions of operators in 

this area. That could result in the adoption of less conservative, least common 

denominator, design assumptions across all regions and reduce modeling flexibility and 

use of engineering judgment. Proxies are typically tailored to specific systems because 

the development of proxies is highly dependent on regional differences and localized 

knowledge. If the Commission determines that independent review of utility outage 

simulation proxies is necessary, Regional Entities should conduct that review, because 

they better understand the regional and localized factors that influence the proxies. 

1806. EEI requests that the Commission clarify the meaning of the term “controlled load 

interruption” and the meaning of its statement that “to avoid undue negative impact on 

competition, third party studies could be permitted to implement the same or less 

controlled load interruption as used by the transmission owner.”466

1807. NRC states that this Reliability Standard should be clarified in regard to the N-1-1 

condition. In addition, it recommends specific changes to Requirements R1.6, R.1.2 and 

R2.2. 

1808. A number of commenters respond to the Commission’s request for comments on 

the value and appropriateness of including the ability of the system to withstand two 

simultaneous contingencies for major load pockets. NERC states that this issue has been 

recognized as needing clarification, and it welcomes comments in the development of 

these revisions in accordance with its Reliability Standards development process. NERC 

states that it is developing a proposal for a transmission availability data system that will 

provide a quantitative (probabilistic) basis for judging the likelihood of various multielement contingencies which will be helpful in determining the value of this proposal. 

1809. APPA, LPPC and National Grid state that imposing N-2 planning may be difficult 

to administer since there is no consensus on what constitutes a “major load pocket.” 

LPPC states that the definition of major load pockets has been, and is still being debated. 

As there is no nation-wide consensus on the term’s definition, no list of major load 

pockets exists. Because load pockets and their boundaries change with the dynamically 

 466 Id. at P 1097. 
Docket No. RM06-16-000 - 470 - 

changing system and load patterns, it is difficult to establish or administer a rule that 

encompasses the particular sub-region to which such an N-2 requirement would apply. 

1810. APPA and EEI believe such provisions would significantly expand planning 

requirements for extremely unlikely events that in most cases are not cost effective to 

build into system planning decisions. They explain that the Reliability Standard currently 

includes the more likely situation, i.e., where two events occur in a time frame that allows 

some time to adjust in response to the first event. APPA and EEI state that various 

planning entities may, of course, study much more extreme events, including the 

hypothetical the Commission poses, especially if formal state or regional planning 

requires such studies, and actual preparation for extreme events is viewed as costeffective in a particular area. However, this level of planning sensitivity is simply 

unnecessary for many regions of the country. They ask that if the Commission 

envisions changes to provide for N-2 service to load pockets, a dialogue must first be 

initiated within the industry and with state public utility commissions to identify such 

load pockets, target the required transmission investments (which could be very 

substantial) and develop plans for allocating the costs of such investments. 

1811. FirstEnergy comments that, although simultaneous C.3 independent contingencies 

may pose potentially high risk, they are most likely extremely low in probability. 

FirstEnergy states that it nevertheless routinely evaluates these contingencies across its 

system for facilities 200 kV and higher and suggests that if this analysis is made a 

requirement, it should be limited to an extra high voltage subset of the Bulk-Power 

System. 

1812. MISO believes that evaluation of multiple contingency events should only reside 

in the planning arena and not in the operations environment. It states that the current 

Reliability Standard provides a reasonable and time tested methodology. 

1813. National Grid opposes applying this N-2 criterion across the board. It states that 

N-2 planning is usually relied upon when a particular area does not have the resources or 

flexibility to adopt the N-1-1 approach. The Bulk-Power System is designed differently 

in every region, and there is no need to impose N-2 planning where regions are 

satisfactorily implementing the N-1-1 methodology. 

1814. SDG&E states that the N-2 consideration for major load pockets is neither of 

value nor appropriate for transmission planning entities at large. The probability of such 

a contingency for a major load pocket is very low, and the costs for addressing such a 

remote contingency would be significant. SoCal Edison states the potential number of 

multi-contingency events that could be studied under TPL-003-0 is staggering. Planners 

should be given flexibility to select generation and transmission elements that reflect a 

broad range of potential combinations without having to commit resources to conduct 
Docket No. RM06-16-000 - 471 - 

potentially hundreds or thousands of contingency studies. Northern Indiana contends that 

this requirement is in effect a third back-up capability, that it would be prohibitive in 

terms of time and cost, and that it would take many years to put the infrastructure it 

would require into place. 

1815. PG&E believes there is no need for a general requirement to withstand the 

simultaneous occurrence of any two contingencies for major load pockets. It states that 

IRO-005 provides for contingencies that are credible when operating below IROL in 

current day operations. The TPL group of Reliability Standards already require 

provisions for specific circumstances based on evaluations that take into account the 

probability of an outage occurring and the associated consequences when transmission 

plans are developed. PG&E states that TPL-003-0, Category C.5 contingency already 

addresses the more probable simultaneous outages (due to common-mode failure) that 

could occur. PG&E maintains that simultaneous occurrence of other contingencies is not 

credible. The principles incorporated in the Reliability Standards require that evaluations 

of credibility be balanced against potential impact, and investing resources to prevent 

improbable events diverts attention and focus from more critical Reliability Standards 

and more probable conditions. 

ii. Commission Determination 

1816. The Commission approves proposed Reliability Standard TPL-003-0 as a 

mandatory and enforceable Reliability Standard. In addition, we direct the ERO to 

develop modifications to TPL-003-0 through the Reliability Standards development 

process, as discussed below. 

1817. The Commission notes that, like Requirement R1.3.1 of TPL-001-0, Requirement 

R1.3.2 of TPL-003-0 requires an entity assessing system performance to cover “critical 

system conditions and study years” as deemed appropriate by the entity performing the 

study, but that the Requirement does not specify the rationale for determining critical 

system conditions and study years. The Commission directs the ERO to modify TPL003-0 to require that critical system conditions and study years be determined in the same 

manner as we directed with regard to TPL-001-0, for the reasons as set forth in our 

discussion of TPL-001-0.

1818. The intent underlying the statement that “to avoid undue undue negative impact on 

competition, third party studies should be permitted to implement the same or less 

controlled load interruption as used by the transmission owner” is to ensure that third 

parties have access to the same options that the transmission owner uses to alleviate 

reliability constraints including those related to controlled load shedding. For example, if 

a transmission owner designs its system to result in a controlled load shedding of 300 

MW for Category C contingencies, designs proposed for third parties requesting 
Docket No. RM06-16-000 - 472 - 

interconnections to that system must also be permitted, but not required, to have 300 MW 

of controlled load shedding for the same Category C contingencies. The Commission 

directs the ERO to modify footnote (c) of Table 1 to the Reliability Standard to clarify the 

term “controlled load interruption.” In response to LPPC’s comments on modification 

procedures, the Commission agrees that changes to the footnotes of Table 1 should be 

addressed through the ERO’s Reliability Standards development process. 

1819. The Commission stated in the NOPR that the concern involved relates to the use 

of thermal overloads or low voltage proxies to judge the likelihood of subsequent line or 

generator trips leading to a cascading outage.467 The Commission agrees with SoCal 

Edison that, if an entity models overload relays, undervoltage relays, all remedial action 

schemes including those of neighboring systems and has a good load representation, then 

proxies are not required. However, due to modeling and simulation limitations this is 

often not the case and planners invariably use proxies.468 Recognizing this and the range 

of proxies currently in use, the Transmission Issues Subcommittee of the NERC Planning 

Committee recommended that proxies used in simulations be defined until such time as 

improved analytical tools and models are available to simulate cascading events. 

1820. The Commission disagrees with LPPC that defining and documenting proxies will 

result in the adoption of less conservative, least common denominator design 

assumptions across all regions and reduce modeling flexibility and engineering judgment. 

To the contrary, the Commission believes that such sharing of information will improve 

knowledge and understanding and promote a more rigorous approach to analyzing 

cascading outages. The Commission agrees with LPPC that it may be preferable for the 

Regional Entities to conduct the review of proxies, because they better understand the 

regional and localized factors that influence the proxies. However, we expect the ERO to 

coordinate between regions to assure that best practices are shared among the Regional 

Entities. Accordingly, the Commission directs the ERO to modify the Reliability 

Standard to require definition and documentation of proxies necessary to simulate 

cascading outages. 

1821. No comments were received on the Commission’s proposal that the purpose 

statement of TPL-003-0 be tailored to reflect the specific goal of the Reliability Standard. 

The Commission directs that this modification be made. Reliability Standards should be 

 467 Id. at P 1098. 

468 See WECC Disturbance Performance Table W-1 and Figure W-1 of Allowable 

Effects on other Systems, NERC/WECC Planning Standards April 10, 2003. 
Docket No. RM06-16-000 - 473 - 

clear and unambiguous, and a clear statement of a Reliability Standard’s purpose and 

goal is one of the features necessary to achieve this end. 

1822. The NRC’s comments on TPL-003-0 parallel its comments on TPL-002-0. The 

Commission discussed those comments above, and its conclusions there apply equally 

here. The Commission, for the same reasons set forth in our discussion of TPL-002-0, 

directs the ERO to address NRC concerns through its Reliability Standards development 

process. 

1823. The Commission received numerous comments on its request for comments on the 

appropriateness and value of including the ability of the system to withstand two 

simultaneous Category B contingencies for major load pockets. The Commission stated 

that it was aware that several entities currently apply this approach and notes that one 

entity was actually commended by NERC for doing so as part of its readiness review. 

FirstEnergy states that it routinely evaluates these contingencies across its system for 200 

kV and higher. NERC states that this issue has been recognized as requiring clarification, 

and it welcomes comments on these revisions in accordance with the Reliability 

Standards development process. 

1824. Many commenters state that, without a consensus on what constitutes a major load 

pocket, little progress can be made in this regard. LPPC states that the definition of 

major load pockets has been and is still being debated. National Grid states that N-2 

planning is usually relied upon when a particular area does not have the resources and 

flexibility to adopt the N-1-1 approach. The Commission agrees with National Grid but 

notes that this is more applicable to the operating domain, something that MISO opposes. 

PG&E states that this approach is not necessary because Category C5 already addresses 

more probable simultaneous outages due to common mode failure. The Commission 

disagrees since Category C5 only deals with a loss of any two circuits on a multi-circuit 

tower line and not a simultaneous loss of a line and a generator which was envisaged by 

the request for comments. Many commenters indicated that this was a very low 

probability event and the costs for addressing such an event would be significant. As a 

result, EEI states that a dialogue must first be initiated within the industry and with state 

public utility commissions to identify such load pockets, to target the required potentially 

significant transmission investments and to develop plans for allocating the costs of such 

investments. In light of these comments, the Commission does not intend to recommend 

action on this issue at this time and, instead, directs the ERO to consider the comments in 

possible future revisions to the Reliability Standard. 

1825. Accordingly, the Commission approves Reliability Standard TPL-003-0 as 

mandatory and enforceable. In addition, the Commission directs the ERO to develop a 

modification to TPL-003-0 through the Reliability Standards development process that: 

(1) requires that critical system conditions be determined in the same manner as we 
Docket No. RM06-16-000 - 474 - 

propose to require for TPL-001-0; (2) modifies footnote (c) to Table 1 to clarify the term 

“controlled load interruption;” (3) requires 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 Standard. 

e. System Performance Following Extreme Events (TPL004-0)

1826. The goal of Reliability Standard TPL-004-0 is to ensure that the future BulkPower System is evaluated to assess the risks and consequences of an extreme event 

involving the loss of multiple elements. It seeks to do this by requiring 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. 

1827. 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. 

1828. The Commission proposed in the NOPR 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, we proposed to direct NERC to 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. 

i. Comments

1829. MidAmerican supports the Commission’s proposed modifications to the 

Reliability Standard as reasonable and agrees with the Commission that the Reliability 

Standard should not require improvements for low probability events that cannot be 
Docket No. RM06-16-000 - 475 - 

justified.469 MidAmerican supports developing options for any events listed in TPL-004-

0 that result in cascading outages and suggests use of probabilistic estimates to determine 

which, if any, of the TPL-004 extreme events options should be estimated to reduce their 

probability or impacts. 

1830. FirstEnergy, EEI, APPA, TVA and Northern Indiana all oppose the expansion of 

the list of extreme contingencies to include natural disasters such as hurricanes and ice 

storms. They state that the potential contingencies resulting from this expansion are 

endless and therefore impractical to consider through engineering studies. As a result, 

additional requirements in this Reliability Standard are unnecessary. EEI and APPA state 

that to the extent that such events will happen, entities historically have put heavy 

emphasis on emergency planning and procedures, which are addressed by the EOP group 

of Reliability Standards. 

ii. Commission Determination

1831. The Commission approves proposed Reliability Standard TPL-004-0 as mandatory 

and enforceable. In addition, we direct the ERO to develop modifications to TPL-004-0 

through the Reliability Standards development process, as discussed below. 

1832. The Commission notes that, like Requirement R1.3.1 of TPL-001-0, Requirement 

R1.3.2 of TPL-004-0 requires an entity assessing system performance to cover “critical 

system conditions and study years” as deemed appropriate by the entity performing the 

study, but it does not specify the rationale for determining critical system conditions and 

study years. The Commission directs the ERO to modify TPL-004-0 to require that 

critical system conditions and study years be determined in the same manner as we 

directed with regard to TPL-001-0 and for the reasons stated there. 

1833. MidAmerican states that it supports the proposal to modify TPL-004-0 to require 

identification of options for reducing the probability or impacts of extreme events that 

cause cascading. Accordingly, for the reasons cited in the NOPR, the Commission 

directs the ERO to modify the Reliability Standard to make this modification to the 

Reliability Standard. 

1834. All commenters that responded on the issue opposed the Commission’s proposal 

to modify TPL-004-0 to require that, in determining the range of the extreme events to be 

assessed, the contingency list of Category D be expanded to include recent events such as 

hurricanes and ice storms. The Commission is not persuaded by the commenters’ 

 469 See NOPR at P 1112. 
Docket No. RM06-16-000 - 476 - 

contention that expansion of the extreme events list will lead to an endless list of 

possibilities. The two that the Commission used are examples from the general news 

media. While the NOPR referred to two recent events, other examples include: (1) loss 

of a large gas pipeline into a region or multiple regions that have significant gas-fired 

generation; (2) a successful cyber attack; (3) regulation that restricts or eliminates the use 

of a river or lake or other body of water as the cooling source for generation; (4) 

shutdown of a nuclear power plant and other facilities a day or more prior to a hurricane, 

tornado or wildfire, or other event and (5) the loss of older transmission lines, which may 

not be constructed to meet an entity’s present radial ice loading requirements, while the 

newer or stronger transmission lines remain in service. The above examples are not an 

exhaustive list, however, the Commission would not expect the range of scenarios to be 

much more extensive than this, either. Thus, we are not expecting an endless list of 

scenarios and infinite number of combinations in directing this modification. Each event 

is identifiable for each entity based on its topology, facilities and generation mix. 

Accordingly, the Commission directs the ERO to expand the list of events with examples 

of such events identified above. 

1835. The Commission received no comments on its proposal to modify the purpose 

statement of TPL-004-0 to reflect the specific goal of the Reliability Standard. The 

Commission directs that this modification be made. 

1836. Accordingly, the Commission approves Reliability Standard TPL-004-0 as 

mandatory and enforceable. In addition, the Commission directs the ERO to develop a 

modification to TPL-004-0 through the Reliability Standards development process 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)

1837. Reliability Standard TPL-005-0 seeks to ensure that each regional reliability 

organization conducts reliability assessments of its existing and planned regional bulk 

electric system annually by requiring it 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. 

1838. The Commission proposed in the NOPR not to approve or remand TPL-005-0, as 

it applies only to regional reliability organizations. 
Docket No. RM06-16-000 - 477 - 

i. Comments

1839. EEI comments that TPL-005-0 should be revised to remove the regional reliability 

organizations. 

ii. Commission Determination

1840. Consistent with our discussion in the Common Issues section above, we will not 

approve or remand TPL-005-0 until we receive additional information from the ERO. 

1841. In Order No. 890, the Commission stated that there will be a series of technical 

conferences and regional meetings to obtain industry input to achieving the goal of 

regional planning.470 The Commission encourages the ERO to monitor those proceedings 

and use the results as input to the Reliability Standards development process in revising 

Reliability Standard TPL-005-0 to address regional planning and related processes. 

g. Assessment Data from Regional Reliability Organizations 

(TPL-006-0)

1842. Reliability Standard TPL-006-0 seeks to ensure 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. 

1843. The Commission proposed in the NOPR not to approve or remand TPL-006-0, as 

it applies only to regional reliability organizations. 

i. Comments

1844. EEI agrees that TPL-006-0 should be revised to remove the regional reliability 

organizations. 

ii. Commission Determination

1845. Consistent with our discussion in the Common Issues section above, the 

Commission will not approve or remand TPL-006-0. 

 470 Order No. 890 at P 443. 
Docket No. RM06-16-000 - 478 - 

13. VAR: Voltage and Reactive Control

1846. 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 

Requirements. These two new proposed Reliability Standards have been submitted by 

NERC as part of the August 28, 2006 Supplemental Filing for Commission review. 

NERC requested an effective date of February 2, 2007 for VAR-001-1, and August 2, 

2007 for VAR-002-1. 

a. VAR-001-1 Voltage and Reactive Control

1847. Reliability Standard VAR-001-1 requires transmission operators to implement 

formal policies for monitoring and controlling voltage levels, acquire sufficient reactive 

resources, specify criteria for generator voltage schedules, know the status of all 

transmission reactive power resources, operate or direct the operation of devices that 

regulate voltage and correct IROL or SOL violations resulting from reactive resource 

deficiencies. VAR-001-1 also requires purchasing-selling entities to arrange for reactive 

resources to satisfy their reactive requirements. 

1848. In the NOPR, the Commission proposed to approve VAR-001-1 as mandatory and 

enforceable. In addition, the Commission proposed to direct NERC to submit a 

modification to VAR-001-1 that: (1) expands the applicability to include reliability 

coordinators and LSEs; (2) includes detailed and definitive requirements on “established 

limits” and “sufficient reactive resources,” and identifies acceptable margins above the 

voltage instability points; (3) includes Requirements to perform voltage stability 

assessments periodically during real-time operations and (4) includes controllable load 

among the reactive resources to satisfy reactive requirements. The Commission also 

requested comments concerning NERC’s assertion that all LSEs are also purchasingselling entities, and on the acceptable ranges of net power factor range at the interface at 

which the LSEs receive service from the Bulk-Power System during normal and extreme 

load conditions. 

1849. Most comments address the specific modifications and concerns raised by the 

Commission in the NOPR. Below, we address each topic separately, followed by an 

over-all conclusion and summary. 
Docket No. RM06-16-000 - 479 - 

i. Applicability to Load-Serving Entities and

Reliability Coordinators

(a) Comments

1850. EEI agrees with the Commission that the applicability of VAR-001-1 should be 

expanded to include reliability coordinators and LSEs. 

1851. MISO contends that the view and role of generator operators, transmission 

operators and reliability coordinators are different, and reliability coordinators’ 

monitoring and response requirements are addressed elsewhere in the Reliability 

Standards. 

1852. In response to the Commission’s request in the NOPR for comments concerning 

whether all LSEs are also purchasing-selling entities, SoCal Edison believes they are 

distinguishable. It states that a purchasing-selling entity, according to the functional 

model, makes financial deals across balancing authorities (from source to sink). Within 

the area of a large balancing authority, such as the CAISO, an LSE can serve load from a 

resource within the balancing authority, so that there is no requirement to tag this 

transaction, and technically there is no purchasing-selling entity involved. 

1853. APPA is concerned that requiring VAR-001-1 to be applicable to LSEs would 

require LSEs to conduct various studies and perform reliability functions that have been 

assigned to other functional entities. The role of LSEs in voltage stability assessments 

should be limited to coordination and the provision of data. TAPS also questions the 

need to expand applicability of these Reliability Standards to LSEs. TAPS maintains that 

purchasing and selling utilities are already subject to the Reliability Standards, and are 

required to satisfy any reactive requirements through purchasing Ancillary Service No. 2 

under the OATT (or self-supply). TAPS believes that the addition of LSEs as an 

additional applicable entity serves no reliability purpose. 

(b) Commission Determination

1854. In a complex power grid such as the one that exists in North America, reliable 

operations can only be ensured by coordinated efforts from all operating entities in longterm planning, operational planning and real-time operations. To that end, the Staff 

Preliminary Assessment recommended and the NOPR proposed that the applicability of 

VAR-001-1 extend to reliability coordinators and LSEs. 

1855. Since a reliability coordinator is the highest level of authority overseeing the 

reliability of the Bulk-Power System, the Commission believes that it is important to 

include the reliability coordinator as an applicable entity to assure that adequate voltage 
Docket No. RM06-16-000 - 480 - 

and reactive resources are being maintained. As MISO points out, other Reliability 

Standards address responsibilities of reliability coordinators, but we agree with EEI that it 

is important to include reliability coordinators in VAR-001-1 as well. Reliability 

coordinators have responsibilities in the IRO and TOP Reliability Standards, but not the 

specific responsibilities for voltage levels and reactive resources addressed by VAR-001-

1, which have a great impact on system reliability. For example, voltage levels and 

reactive resources are important factors to ensure that IROLs are valid and operating 

voltages are within limits, and that reliability coordinators should have responsibilities in 

VAR-001-1 to monitor that sufficient reactive resources are available for reliable system 

operations. Accordingly, the ERO should modify VAR-001-1 to include reliability 

coordinators as applicable entities and include a new requirement(s) that identifies the 

reliability coordinator’s monitoring responsibilities. 

1856. The Commission agrees with SoCal Edison that not all LSEs are purchasingselling entities, because not all LSEs purchase or sell power from outside of their 

balancing authority area. This understanding is consistent with the NERC functional 

model and NERC glossary. Both LSEs and purchasing-selling entities should have some 

requirements to provide reactive power to appropriately compensate for the demand they 

are meeting for their customers. Neither a purchasing-selling entity nor a LSE should 

depend on the transmission operator to supply reactive power for their loads during 

normal or emergency conditions. 

1857. VAR-001-1 recognizes that energy purchases of purchasing-selling entities can 

increase reactive power consumption on the Bulk-Power System and the purchasingselling entities must supply what they consume. The Commission agrees with APPA that 

LSEs would provide data for voltage stability assessments. However, the Commission 

also believes that LSEs have an active role in voltage and reactive control, since LSEs are 

responsible for maintaining an agreed-to power factor at the interface with the BulkPower System. 

1858. While the Commission recognizes the point made by TAPS, that purchasingselling entities are required to satisfy any reactive requirements through purchasing 

Ancillary Service #2 under the OATT or self-supply, the Commission disagrees that 

adding LSEs to this Reliability Standard serves no reliability purpose. As discussed in 

the NOPR and the Staff Preliminary Assessment, LSEs are responsible for significantly 

more load than purchasing-selling entities.471 The reactive power requirements can have 

significant impact on the reliability of the system and LSEs should be accountable for 

that impact in the same ways that purchasing-selling entities are accountable, by 

 471 NOPR at P 1134. 
Docket No. RM06-16-000 - 481 - 

providing reactive resources, and also by providing information to transmission operators 

to allow transmission operators to accurately study the reactive power needs for both the 

LSEs’ and purchasing-selling entities’ load characteristics.472 The Commission 

recognizes that all transmission customers of public utilities are required to purchase 

Ancillary Service No. 2 under the OATT or self-supply, but the OATT does not require 

them to provide information to transmission operators needed to accurately study reactive 

power needs. The Commission directs the ERO to address the reactive power 

requirements for LSEs on a comparable basis with purchasing-selling entities. 

ii. Acceptable ranges of net power factor range

(a) Comments

1859. SoCal Edison states that its Bulk-Power System facilities are designed and 

operated to provide a unity power factor during normal load conditions, and that during 

extreme load conditions, this power factor could be in the range of 0.95 to 1.0. 

1860. APPA contends that it may be difficult to reach an agreement on acceptable ranges 

of net power factors at the interfaces where LSEs receive service from the Bulk-Power 

System because the acceptable range of power factors at any particular point on the 

electrical system varies based on many location-specific factors. APPA further states that 

system power factors will be affected by the transmission infrastructure used to supply 

the load. As an example, APPA states that an overhead circuit may operate at a higher 

power factor than an underground cable due to a substantial amount of reactive line 

charging, and that a transmission circuit carrying low levels of real power will tend to 

provide more reactive power, which will affect the need to switch off capacitor banks at 

the delivery point to manage delivery power factors. 

(b) Commission Determination

1861. In the NOPR, the Commission asked for comments on acceptable ranges of net 

power factor at the interface at which the LSEs receive service from the Bulk-Power 

System during normal and extreme load conditions. The Commission asked for these 

comments in response to concerns that during high loads, if the power factor at the 

interface between many LSEs and the Bulk-Power System is so low as to result in low 

voltages at key busses on the Bulk-Power System, then there is risk for voltage collapse. 

 472 Purchasing selling entities provide information concerning their load through 

the INT series of Reliability Standards. Load serving entities would need to provide 

similar information through this Reliability Standard. 
Docket No. RM06-16-000 - 482 - 

The Commission believes that Reliability Standard VAR-001-1 is an appropriate place 

for the ERO to take steps to address these concerns by setting out requirements for 

transmission owners and LSEs to maintain an appropriate power factor range at their 

interface. We direct the ERO to develop appropriate modifications to this Reliability 

Standard to address the power factor range at the interface between LSEs and the BulkPower System. 

1862. We direct the ERO to include APPA’s concern in the Reliability Standards 

development process. We note that transmission operators currently have access to data 

through their energy management systems to determine a range of power factors at which 

load operates during various conditions, and we suggest that the ERO use this type of 

data as a starting point for developing this modification. 

1863. The Commission expects that the appropriate power factor range developed for the 

interface between the bulk electric system and the LSE from VAR-001-1 would be used 

as an input to the transmission and operations planning Reliability Standards. The range 

of power factors developed in this Reliability Standard provides the input to the range of 

power factors identified in the modifications to the TPL Reliability Standards. In the 

NOPR, the Commission suggested that sensitivity studies for the TPL Reliability 

Standards should consider the range of load power factors.473 

iii. Requirements on “established limits” and 

“sufficient reactive resources”

(a) Comments

1864. Dynegy supports the Commission’s proposal to include more definitive 

requirements on “established limits” and “sufficient reactive resources.” It recommends 

that VAR-001-1 be further modified to require the transmission operator to have more 

detailed and definitive requirements when setting the voltage schedule and associated 

tolerance band that is to be maintained by the generator operator. Dynegy states that the 

transmission operator should not be allowed to arbitrarily set these values, but rather 

should be required to have a technical basis for setting the required voltage schedule and 

tolerance band that takes into account system needs and any limitations of the specific 

generator. Dynegy believes that such a requirement would eliminate the potential for 

undue discrimination, as well as the possibility of imposing overly conservative and 

burdensome voltage schedules and tolerance bands on generator operators that could be 

 473 NOPR at P 1047. 
Docket No. RM06-16-000 - 483 - 

detrimental to grid reliability, or conversely, the imposition of too low a voltage schedule 

and too wide a tolerance band that could also be detrimental to grid reliability. 

1865. While MISO supports the concept of including more detailed requirements, it 

believes that there needs to be a definitive reason for establishing voltage schedules and 

tolerances, and that any situations monitored in this Reliability Standard need to be 

limited to core reliability requirements. 

1866. EEI seeks clarification about whether the Commission is suggesting that reactive 

requirements should aim for significantly greater precision, especially in terms of 

planning for various emergency conditions. If so, EEI cautions the Commission against 

“‘putting too many eggs’ in the reactive power ‘basket.’”474 To the extent compliance 

takes place pursuant to all other modeling and planning assessments under the other 

Reliability Standards, EEI strongly believes that the Commission should have some high 

level of confidence that the system’s reactive power needs can be met satisfactorily 

across a broad range of contingencies that planners might reasonably anticipate. 

Moreover, EEI believes that requirements to successfully predict reactive power 

requirements in conditions of near-system collapse would require significantly more 

creative guesswork than solid analysis and contingency planning. For example, EEI 

notes that the combinations and permutations of how a voltage collapse could occur on a 

system as large as the eastern Interconnection are numerous. 

1867. EEI suggests that, alternatively, the Commission should consider that reactive 

power evaluations should be conducted within a process that is documented in detail and 

includes a range of contingencies that might be reasonably anticipated, because this 

would avoid the ‘one size fits all’ problem, where a prescriptive analytical methodology 

does not fit with a particular system configuration. EEI believes that this flexible 

approach would provide a more effective planning tool for the industry, while satisfying 

the Commission’s concerns over potentially inadequate reactive reserves. MRO notes 

that the need for, and method of providing for, reactive resources varies greatly, and if 

this Reliability Standard is expanded it must be done carefully. MRO believes that all 

entities should not be required to follow the same methodology to accomplish the goal of 

a reliable system. 

(b) Commission Determination

1868. In the NOPR, the Commission expressed concern that the technical requirements 

containing terms such as “established limits” or “sufficient reactive resources” are not 

 474 EEI at 99. 
Docket No. RM06-16-000 - 484 - 

definitive enough to address voltage instability and ensure reliable operations.475 To 

address this concern, the NOPR proposed directing the ERO to modify VAR-001-1 to 

include more detailed and definitive requirements on “established limits” and “sufficient 

reactive resources” and identify acceptable margins (i.e. voltage and/or reactive power 

margins) above voltage instability points to prevent voltage instability and to ensure 

reliable operations. We will keep this direction, and direct the ERO to include this 

modification in this Reliability Standard. 

1869. We recognize that our proposed modification does not identify what definitive 

requirements the Reliability Standard should use for “established limits” and “sufficient 

reactive resources.” Rather, the ERO should develop appropriate requirements that 

address the Commission’s concerns through the ERO Reliability Standards development 

process. The Commission believes that the concerns of Dynegy, EEI and MISO are best 

addressed by the ERO in the Reliability Standards development process. 

1870. In response to EEI’s concerns about a prescriptive analytical methodology, we 

clarify that the Commission is not asking that the Reliability Standard dictate what 

methodology must be used to determine reactive power needs. Rather, the Commission 

believes that the Reliability Standard would benefit from having more defined 

requirements that clearly define what voltage limits are used and how much reactive 

resources are needed to ensure voltage instability will not occur under normal and 

emergency conditions. For example, in the NOPR, the Commission suggested that 

NERC consider WECC’s Reliability Criteria, which contain specific and definitive 

technical requirements on voltage and margin application. While we are not directing 

that the WECC reliability criteria be adopted, we believe they represent a good example 

of clearly-defined requirements for voltage and reactive margins. 

1871. In sum, the Commission believes that minimum requirements for voltage levels 

and reactive resources should be clearly defined by placing more detailed requirements 

on the terms “established limits” and “sufficient reactive resources” in the Reliability 

Standard as discussed in the NOPR and the Staff Preliminary Assessment. As mentioned 

above, EEI’s concerns should be considered in the ERO’s Reliability Standards 

development process. 

 475 See NOPR at P 1140. 
Docket No. RM06-16-000 - 485 - 

iv. Periodic voltage stability analysis in real-time

operations

(a) Comments 

1872. SDG&E supports the NOPR recommendation that a more effective requirement 

could be based on WECC’s reliability criteria, which contain specific and definitive 

technical requirements on voltage and margin application. MidAmerican and PacifiCorp 

recommend that the “WECC Methods to address voltage stability and settling margins” 

should be consulted when designing corresponding NERC requirements. 

1873. Xcel Energy recommends that this proposed modification instead address 

requirements to measure reactive power margin for a variety of topology conditions. 

MidAmerican recommends that the Commission’s proposal be modified to require realtime checks for voltage stability assessments only in areas susceptible to voltage 

instability. Alternatively, MidAmerican suggests that the Commission “should exempt 

from these requirements areas that can demonstrate they are not susceptible to voltage 

instability.” 

1874. APPA, SDG&E and EEI all state that they are not aware of commerciallyavailable tools to provide real-time transient stability assessments as part of an integrated 

energy management system for operators. APPA notes that premature reliance on 

various tools that are now under development but not yet operational may jeopardize 

reliability by providing operators with a false sense of security and recommends leaving 

the decision to use such tools to NERC. EEI points out that any tools to conduct the 

analyses recommended by the Commission will require adjustments and modifications to 

improve their capabilities. Therefore, EEI recommends that the Commission consider its 

proposals regarding these standards as long-term industry objectives and of a lower 

priority than other Reliability Standards. In addition, it is unclear to EEI whether the 

proposed voltage stability assessments apply to steady-state or dynamic analyses, or 

whether these assessments are of a general nature. Since these analyses are technically 

complex and involve a broad range of assumptions regarding system configurations, EEI 

suggests that the Commission provide further guidance. 

(b) Commission Determination 

1875. In response to the concerns of APPA, SDG&E and EEI on the availability of tools, 

the Commission recognizes that transient voltage stability analysis is often conducted as 

an offline study, and that steady-state voltage stability analysis can be done online. The 

Commission clarifies that it does not wish to require anyone to use tools that are not 

validated for real-time operations. Taking these comments into consideration, the 

Commission clarifies its proposed modification from the NOPR. For the Final Rule, we 
Docket No. RM06-16-000 - 486 - 

direct the ERO, through its Reliability Standards development process, to modify 

Reliability Standard VAR-001-1 to include Requirements to perform voltage stability 

analysis periodically, using online techniques where commercially-available, and offline 

simulation tools where online tools are not available, to assist real-time operations. The 

ERO should consider the available technologies and software as it develops this 

modification to VAR-001-1 and identify a process to assure that the Reliability Standard 

is not limiting the application of validated software or other tools. 

1876. With respect to MidAmerican’s suggestion of exempting areas that are not 

susceptible to voltage instability from the requirement to perform voltage stability 

analysis, the Commission notes that such exemption is not appropriate. We draw an 

analogy between transient stability limits and voltage stability limits. The requirement to 

perform voltage stability analysis is similar to existing operating practices for IROLs that 

are dictated by transient stability. Transient stability IROLs are determined using the 

results of off-line simulation studies, and no areas are exempt. In real-time operations, 

these IROLs are monitored to ensure that they are not violated. Similarly, voltage 

stability is conducted in the same manner, determining limits with off-line tools and 

monitoring limits in real-time operations. Areas that are susceptible to voltage instability 

are expected to run studies frequently, and areas that have not been susceptible to voltage 

instability are expected to periodically update their study results to ensure that these 

limits are not encountered during real-time operations. 

v. Controllable Load 

(a) Comments

1877. SMA supports adoption of the proposal to include controllable load as a reactive 

resource. SMA notes that its members’ facilities often include significant capacitor 

banks, and further, reducing load can reduce local reactive requirements. 

1878. SoCal Edison suggests caution regarding the Commission’s proposal to include 

controllable load as a reactive resource. It agrees that, when load is reduced, voltage will 

increase and for that reason controllable load can lessen the need for reactive power. 

However, SoCal Edison believes that controllable load is typically an energy product and 

there are other impacts not considered by the Commission’s proposal to include 

controllable load as a reactive resource. For example, activating controllable load for 

system voltage control lessens system demand, requiring generation to be backed down. 

It is not clear to SoCal Edison whether any consideration has been given to the potential 

reliability or commercial impacts of the Commission’s proposal. 
Docket No. RM06-16-000 - 487 - 

(b) Commission Determination

1879. The Commission noted in the NOPR that in many cases, load response and 

demand-side investment can reduce the need for reactive power capability in the 

system.476 Based on this assertion, the Commission proposed to direct the ERO to 

include controllable load among the reactive resources to satisfy reactive requirements 

for incorporation into Reliability Standard VAR-001-1. While we affirm this 

requirement, we expect the ERO to consider the comments of SoCal Edison with regard 

to reliability and SMA in its process for developing the technical capability requirements 

for using controllable load as a reactive resource in the applicable Reliability Standards.

vi. Summary of Commission Determination

1880. Accordingly, the Commission approves 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 directs the ERO to develop a modification to 

VAR-001-1 through the Reliability Standards development process that: (1) expands the 

applicability to include reliability coordinators and LSEs; (2) includes detailed and 

definitive requirements on “established limits” and “sufficient reactive resources” as 

discussed above, and identifies acceptable margins above the voltage instability points; 

(3) includes Requirements to perform voltage stability analysis periodically, using online 

techniques where commercially available and offline techniques where online techniques 

are not available, to assist real-time operations, for areas susceptible to voltage instability; 

(4) includes controllable load among the reactive resources to satisfy reactive 

requirements and (5) addresses the power factor range at the interface between LSEs and 

the transmission grid. 

b. VAR-002-1

1881. Reliability Standard VAR-002-1 requires generator operators to operate in 

automatic voltage control mode, to maintain generator voltage or reactive power output 

as directed by the transmission operator, and to notify the transmission operator of a 

change in status or capability of any generator reactive power resource. The Reliability 

Standard requires generator owners to provide transmission operators with settings and 

data for generator step-up transformers. In the NOPR, the Commission stated its belief 

that Reliability Standard VAR-002-1 is just, reasonable, not unduly discriminatory or 

 476 See FERC Staff Reportl, Principles of Efficient and Reliable Reactive Power 

Supply and Consumption (2005), available at http://www.ferc.gov/legal/staff-reports.asp. 
Docket No. RM06-16-000 - 488 - 

preferential and in the public interest; and proposed to approve it as mandatory and 

enforceable. 

i. Comments

1882. APPA and SDG&E agree that VAR-002-1 is sufficient for approval as a 

mandatory and enforceable Reliability Standard. 

1883. Dynegy believes that VAR-002-1 should be modified to require more detailed and 

definitive requirements when defining the time frame associated with an “incident” of 

non compliance (i.e., each 4-second scan, 10-minute integrated value, hourly integrated 

value). Dynegy states that, as written, this Reliability Standard does not define the time 

frame associated with an “incident” of non-compliance, but apparently leaves this 

decision to the transmission operator. Dynegy believes that either more detail should be 

added to the Reliability Standard to cure this omission, or the Reliability Standard should 

require the transmission operator to have a technical basis for setting the time frame that 

takes into account system needs and any limitations of the generator. Dynegy believes 

that this approach will eliminate the potential for undue discrimination and the imposition 

of overly conservative or excessively wide time frame requirements, both of which could 

be detrimental to grid reliability. 

ii. Commission Determination

1884. In the NOPR, the Commission commended NERC and industry for its efforts in 

expanding on the Requirements of VAR-002-1 from the predecessor standard, and noted 

that the submitted Reliability Standard includes Measures and Levels of Non-Compliance 

to ensure appropriate generation operation to maintain network voltage schedules. 

Accordingly, the Commission approves Reliability Standard VAR-002-1 as mandatory 

and enforceable. 

1885. Dynegy has suggested an improvement to Reliability Standard VAR-002-1, and 

NERC should consider this in its Reliability Standards development process. 

14. Glossary of Terms Used in Reliability Standards

1886. NERC’s glossary is updated whenever a new or revised Reliability Standard is 

approved that includes a new defined term. 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. 

1887. In the NOPR, the Commission proposed to approve the glossary. In addition, the 

Commission proposed to direct NERC to submit a modification to the glossary that: 

(1) includes the statutory definitions of Bulk-Power System, Reliable Operation, and 
Docket No. RM06-16-000 - 489 - 

Reliability Standard, as set forth in section 215(a) of the FPA; (2) modifies the definitions 

of “transmission operator” and “generator operator” to include aspects unique to ISOs, 

RTOs and pooled resource organizations; (3) modifies the definition of “bulk electric 

system” consistent with discussion in the NOPR Common Issues section477 and (4) 

modifies the definition of terms concerning reserves (such as operating reserves) to 

include DSM, including controllable load. 

a. Comments

1888. NERC supports the Commission’s proposal to approve the glossary. APPA 

supports the Commission’s proposal to have NERC incorporate the statutory definitions 

of the terms Bulk-Power System, Reliable Operation and Reliability Standard into the 

NERC glossary, as an aide to the development of future NERC Reliability Standards. 

1889. APPA suggests that the Commission permit NERC and industry to consider 

whether any modifications to the terms “transmission operator” and “generation 

operator” are needed, rather than directing NERC to modify these terms. APPA’s initial 

reaction is that the existing terms are adequate and accommodate most elements of ISO, 

RTO and pooled resource organization operations. APPA believes that a broader and 

continuing inquiry is required to address such situations. APPA anticipates that many 

such concerns will arise as NERC and the Regional Entities implement the initial 

compliance program in June 2007, and states that any additional changes to the glossary 

should be driven by that experience. 

1890. APPA’s concerns regarding the Commission proposal to modify the definition of 

terms concerning reserves to include DSM (including controllable load) are discussed 

above in reference to the BAL Reliability Standards. 

1891. NERC supports the Commission’s proposal to direct NERC to complete the 

necessary improvements to the proposed Reliability Standards through the established 

NERC Reliability Standards development process. 

1892. Santa Clara submits that, to eliminate any ambiguity about when these definitions 

of these commonly-used terms apply, a footnote should be added to the glossary that 

states that the definitions contained in the glossary are not intended to supersede any 

definitions in a tariff or contract approved or accepted by the Commission. 

 477 NOPR at P 42-43. 
Docket No. RM06-16-000 - 490 - 

b. Commission Conclusion

1893. The Commission approves the glossary. The terms defined in the glossary have an 

important role in establishing consistent understanding of the Reliability Standards 

Requirements and implementation. The approval of the glossary will provide continuity 

in application of the glossary definitions industry-wide, and will eliminate multiple 

interpretations of the same term or function, which may otherwise create 

miscommunication and jeopardize Bulk-Power System reliability. The glossary should 

be updated through the Reliability Standards development process whenever a new or 

revised Reliability Standard that includes a new defined term is approved, or as needed to 

clarify compliance activities. For example, the ERO will need to update the glossary to 

reflect modifications required by the Commission in this Final Rule.478 

1894. The Commission directs the ERO to modify the glossary through the Reliability 

Standards development process to include the statutory definitions of the terms BulkPower System, Reliable Operation and Reliability Standard. However, this determination 

does not negate our discussion in the Applicability section of the Final Rule. While the 

glossary should be revised to include the stautory definition of Bulk-Power System, the 

Reliability Standards refer to the bulk electric system, which is also defined in the 

glossary. 

1895. The Commission directs the ERO to submit a modification to the glossary that 

enhances the definitions of “transmission operator” and “generator operator” to reflect 

concerns of the commenters and the direction provided by the Commission in other 

sections of this Final Rule. The Commission is concerned that there not be any gaps or 

unecessary overlaps of responsibilities concerning any of the Requirements in the 

Reliability Standards that are applicable to transmission operators and generator 

operators. 

1896. Further, we adopt the NOPR proposal to require the ERO to submit a modification 

to the glossary that updates the definition of “operating reserves,” as required in our 

discussion of BAL-002-0 and BAL-005-0. 

1897. Regarding Santa Clara’s concern about terms in the glossary differing from 

definitions in tariffs, we clarify that the glossary governs Reliability Standards, while 

tariff definitions govern tariff issues. We recognize that many items have different tariff 

definitions from those in the NERC glossary. However, we expect most of these terms to 

be consistent. If the glossary definition creates a conflict between the Reliability 

 478 See, e.g., MOD-001-0, TOP-002-1 and the INT Reliability Standards. 
Docket No. RM06-16-000 - 491 - 

Standards and a Transmission Organization’s function, rule, order, tariff, rate schedule, or 

agreement accepted, approved, or ordered by the Commission, then the Transmission 

Organization shall expeditiously notify the Commission, the Electric Reliability 

Organization and the relevant Regional Entity of the possible conflict pursuant to § 39.6 

of the Commission’s regulations.479

1898. In conclusion, the Commission approves the glossary. Further, pursuant to section 

215(d)(5) of the FPA and § 39.5(f) of our regulations, the Commission directs ERO to 

modify the glossary through the Reliability Standards development process to: 

(1) include the statutory definitions of the terms Bulk-Power System, Reliable Operation 

and Reliability Standard; (2) modify the definition of “transmission operator” and 

“generator operator” to include aspects unique to ISO, RTO and pooled resource 

organizations and (3) modify the definition of “operating reserves” as discussed in BAL002-0 and BAL-005-0. 

III. Information Collection Statement

1899. The Office of Management and Budget (OMB) regulations require that OMB 

approve certain reporting and recordkeeping (collections of information) imposed by an 

agency.480 The information collection requirements in this Final Rule are identified under 

the Commission data collection, FERC-725A "Bulk Power System Mandatory Reliability 

Standards." Under section 3507(d) of the Paperwork Reduction Act of 1995,481 the 

proposed reporting requirements in the subject rulemaking will be submitted to OMB for 

review. Interested persons may obtain information on the reporting requirements by 

contacting the Federal Energy Regulatory Commission, 888 First Street, NE, 

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

202-502-8415) or from the Office of Management and Budget (Attention: Desk Officer 

for the Federal Energy Regulatory Commission, fax: 202-395-7285, e-mail: 

oira_submission@omb.eop.gov). 

1900. The “public protection” provisions of the Paperwork Reduction Act of 1995 

requires each agency to display a currently valid control number and inform respondents 

that a response is not required unless the information collection displays a valid OMB 

control number on each information collection or provides a justification as to why the 

 479 18 CFR 39.6 (2006). 

480 5 CFR 1320.11. 

481 44 U.S.C. 3507(d) (2000). 
Docket No. RM06-16-000 - 492 - 

information collection number cannot be displayed. In the case of information 

collections published in regulations, the control number is to be published in the Federal 

Register. 

1901. Public Reporting Burden: In the NOPR, the Commission based its initial 

estimates on the premise that the proposed Reliability Standards have already been in 

effect for a substantial period of time on a voluntary basis and consequently entities 

would have already put them into practice. Seventy of the 125 commenters express 

concern with the burden to be imposed by the NOPR’s requirements. The majority of 

these comments address the potential impact the requirements would have on small 

entities but did not provide specific estimates on this impact. Because these comments 

are also the subject of the analysis performed under the Regulatory Flexibility Act, the 

Commission has provided a response under that section of this rulemaking. Commenters 

also raise concerns about the impact of specific Reliability Standards, and the 

Commission has addressed those concerns in the discussion of each Reliability Standard. 

Five commenters, Reliant, TAPS, Wisconsin Electric, Portland General and WECC 

questioned the Commission’s initial burden estimates as contained in the NOPR. 

1902. By Reliant’s estimate, it would take at least four employees to prepare and submit 

compliance filings and to monitor compliance on an on-going basis. TAPS, while not 

providing a specific estimate on the burden, believes that the NOPR’s proposed 

application of mandatory Reliability Standards is overly-broad and would encompass 

several thousand municipal systems. Wisconsin Electric states that the NOPR 

significantly understated the impact that would be imposed by mandatory Reliability 

Standards. Wisconsin Electric believes that a “typical control area utility with its 

multiple functional entity responsibilities” will need far more than the 100 hours 

estimated by the Commission to manage a quality compliance program as discussed in 

the ERO’s Sanction Guidelines.482 

1903. Portland General believes that meeting the Requirements of mandatory Reliability 

Standards will place an additional burden for documentation, over and above compliance 

with the substance of the Requirements. It claims that the NOPR failed to take this 

additional burden into account in its cost estimate for compliance. WECC disagrees with 

the Commission’s estimate that compliance cost would be $40 million annually on an 

aggregate basis. It also disagrees with the Commission’s assumption that there would be 

no increased reporting burden or additional information requirements because the 

Reliability Standards impose new documentation requirements that will create additional 

costs. 

 482 Wisconsin Electric at 9. 
Docket No. RM06-16-000 - 493 - 

1904. In response to the comments and upon further review we have revised our initial 

estimates as reflected in the table below. While the ERO has submitted several new 

Reliability Standards and included additional Measures for documenting compliance with 

20 existing Reliability Standards, we continue to believe that the reporting requirements 

embedded in the Reliability Standards that are approved in the Final Rule have been 

implemented on a voluntary basis for many years in most instances.483 This would not 

apply, however, to entities that are new to reliability oversight. We encourage entities 

that are responsible for compliance with mandatory Reliability Standards to develop a 

quality compliance program as discussed in the ERO’s Sanction Guidelines. However, 

we believe that the costs of such a program are distinct from the reporting burdens that 

are estimated below. 

1905. Further, our estimates below reflect a revision in the number of respondents, based 

on our determinations regarding “applicability,” as discussed in section II.C above. 

1906. Total Annual Hours for Collection: 

Data 

Collection 

No. of 

Respondents 

No. of 

Responses 

Hours Per 

Response 

Total Annual 

Hours 

FERC-725A 

Investor 

Owned 

Utilities 

170 1 2,080 353,600 

Municipals 

and 

Cooperatives - 

Large 

80 1 1,420 113,600 

Municipals 

and 

Cooperatives -

Small 

670 1 710 475,700 

Generator 

Operators 

360 1 500 180,000 

 483 NOPR at P 1157. 
Docket No. RM06-16-000 - 494 - 

Power 

Marketers 

159 1 100 15,900 

Investor Owned Utilities 35,360 

Munis/Coops (Large) 11,360 

Munis/Coops (Small) 47,570 

Generator Owner/Ops. 18,000 

Power Marketers 1,590 

Recordkeeping 

Totals 1,252,680 

(FTE=Full Time Equivalent or 2,080 hours) 

Total Hours = 1,138,800 (reporting) + 113,880 (recordkeeping) = 1,252,680 hours. This 

estimated reporting burden will be significantly reduced once joint action agencies are 

established, which would will reduce the number of small entities that will be responsible 

for compliance with Reliability Standards. 

1907. Information Collection Costs: The Commission sought comments about the 

costs needed to comply with these requirements. As noted above, a number of 

commenters state that the NOPR underestimated the burden of the rulemaking in terms of 

hours required to comply. However, no comments were received regarding the 

Commission’s estimate of the projected cost of $200/hour to comply with these 

requirements. In further consideration, the Commission believes that the $200/hour 

projection is too high, and the calculations below reflect an adjusted hourly figure. 

Cost to Comply: 

Reporting = 1,138,800 @ $114/hour = $129,823,200 

1,138,800 hours @ 114 per hour (average cost of attorney ($200 per hour), consultant 

($150), technical ($80) and administrative support ($25)). 

Recordkeeping = 113,880 @ $17/hour = $1,935,960 

113,880 hours @ $17 per hour (file/record clerk @ $17 an hour) 

Total Costs: Reporting ($129,823,200) + Recordkeeping ($1,935,960) = $131,759,160. 
Docket No. RM06-16-000 - 495 - 

Sources: “NERC Compliance Update: What it might cost to comply”, Herb 

Schrayshuen, NARUC-Electric Reliability Staff Subcommittee, November 12, 2006. 

Janco Associates, Inc., 2005 Information Technology Compensation Study, January 

2005. 

Bureau of Labor Statistics, Department of Labor, Occupational Outlook Handbook, 

http://www.bls.gov/oco/ocos268.htm. 

Titles: FERC-725A "Mandatory Reliability Standards for the Bulk-Power System” 

Action: Proposed Collection of Information 

OMB Control Nos: To be determined. 

Respondents: Business or other for profit, not for profit institutions, state, local or tribal 

government and Federal Government. 

Frequency of Responses: On occasion. 

Necessity of Information: The Final Rule approves 83 Reliability Standards. 

Compliance with such Reliability Standards will be mandatory and enforceable for the 

applicable categories of entities identified in each Reliability Standard. These Reliability 

Standards are approved by the Commission pursuant to its authority under section 215 of 

the FPA, which authorizes the Commission to approve a Reliability Standard proposed 

by the ERO if the Commission determines that it is just and reasonable, not unduly 

discriminatory or preferential and in the public interest. The Reliability Standards 

approved in this Final Rule are necessary for the reliable operation of the nation’s 

interconnected Bulk-Power System. 

For information on the requirements, submitting comments on the collection of 

information and the associated burden estimates including suggestions for reducing this 

burden, please send your comments to the Federal Energy Regulatory Commission, 888 

First Street, NE, Washington, D.C. 20426 (Attention: Michael Miller, Office of the 

Executive Director, 202-502-8415) or send comments to the Office of Management and 

Budget (Attention: Desk Officer for the Federal Energy Regulatory Commission, fax: 

202-395-7285, e-mail oira_submission@omb.eop.gov). 
Docket No. RM06-16-000 - 496 - 

IV. Environmental Analysis

1908. The Commission is required to prepare an Environmental Assessment or an 

Environmental Impact Statement for any action that may have a significant adverse effect 

on the human environment.484 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.485

V. Regulatory Flexibility Act 

1909. The Regulatory Flexibility Act of 1980 (RFA)486 generally requires a description 

and analysis of Final Rules that will have significant economic impact on a substantial 

number of small entities. The RFA does not mandate any particular outcome in a 

rulemaking. It only requires consideration of alternatives that are less burdensome to 

small entities and an agency explanation of why alternatives were rejected. 

1910. In drafting a rule an agency is required to: (1) assess the effect that its regulation 

will have on small entities; (2) analyze effective alternatives that may minimize a 

regulation’s impact and (3) make the analyses available for public comment.487 In its 

NOPR, the agency must either include an initial regulatory flexibility analysis (initial 

RFA)488 or certify that the proposed rule will not have a “significant impact on a 

substantial number of small entities.”489

1911. If in preparing the NOPR an agency determines that the proposal could have a 

significant impact on a substantial number of small entities, the agency shall ensure that 

small entities will have an opportunity to participate in the rulemaking procedure.490

 484 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). 

485 18 CFR 380.4(a)(5). 

486 5 USC 601 – 612 (2006). 

487 5 USC 601 – 604. 

488 5 USC 603(a). 

489 5 USC 605(b). 

490 5 USC 609(a). 
Docket No. RM06-16-000 - 497 - 

1912. In its Final Rule, the agency must also either prepare a Final Regulatory Flexibility 

Analysis (Final RFA) or make the requisite certification. Based on the comments the 

agency receives on the NOPR, it can alter its original position as expressed in the NOPR 

but it is not required to make any substantive changes to the proposed regulation. 

1913. The statute provides for judicial review of an agency’s final certification or Final 

RFA.491 An agency must file a Final RFA demonstrating a “reasonable, good-faith 

effort” to carry out the RFA mandate.492 However, the RFA is a procedural, not a 

substantive, mandate. An agency is only required to demonstrate a reasonable, good faith 

effort to review the impact the proposed rule would place on small entities, any 

alternatives that would address the agency’s and small entities’ concerns and their 

impact, provide small entities the opportunity to comment on the proposals, and review 

and address comments. An agency is not required to adopt the least burdensome rule. 

Further, the RFA does not require an agency to assess the impact of a rule on all small 

entities that may be affected by the rule, only on those entities that the agency directly 

regulates and that will be directly impacted by the rule.493

A. Notice of Proposed Rulemaking 

1914. In the NOPR, the Commission stated that the proposed Reliability Standards 

“may cause some small entities to experience significant economic impact.”494 In 

response to the ERO’s proposal to develop limits on the applicability of specific 

Reliability Standards, the Commission stated that, while it could not rule on the merits 

until a specific proposal is submitted, the Commission stated that it believed that 

reasonable limits based on size may be an acceptable alternative to “lessen the economic 

impact on the proposed rule on small entities.”495 The Commission emphasized that any 

such limits must not weaken Bulk-Power System reliability. 

1915. Further, under the Applicability Issues section of the NOPR, we devoted an entire 

subsection to the issues facing small entities.496 The Commission stated that there may 

 491 5 USC 611. 

492 United Cellular Corp. v. FCC, 254 F.3d 78, 88 (D.C. Cir. 2001); Alenco 

Commuications, Inc. v. FCC, 201 F.3d 608, 625 (5th Cir. 2000). 

493 Mid-Tex Electric Coop., Inc. v. FERC, 773 F.2d 327 (D.C. Cir 1985). 

494 NOPR at P 1175. 

495 Id. at 1176. 

496 Id. at 49-53 (Section B.3 “Applicability to Small Entities”). 
Docket No. RM06-16-000 - 498 - 

be instances in which small entity compliance with a particular Reliability Standard may 

be critical to reliability. It explained that, in such circumstances, it may be appropriate to 

differentiate among subsets of users, owners and operators. As an example, the NOPR 

provided that “the requirement to have adequate communications capabilities to address 

real-time emergency conditions . . . 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.”497 Additionally, in the NOPR, the 

Commission supported the ERO’s proposal to permit the registration of “joint action 

agencies,” a concept designed to ease the burden of small entities by allowing one 

organization to perform reliability-related activities for multiple entities. The 

Commission proposed to direct the ERO to develop procedures that would permit a joint 

action agency or similar organization to accept compliance responsibility on behalf of its 

members. 

1916. Thus, in the NOPR, the Commission discussed the potential disparate impact on 

small entities, considered the implications and potential alternatives and solicited 

comments on the limiting the application of the Reliability Standards to small entities. 

Further, the Information Collection Statement discussed the difficulty estimating the 

number of small entities that would be affected by the Reliability Standards. As such, the 

Commission was aware of the potential impacts on small entities and was actively 

considering alternatives that would lessen the impact on them while still ensuring 

reliability of the Bulk-Power System. 

1. Comments

1917. APPA and NRECA, in their joint comments, provide data about their membership. 

APPA states that, based on 2005 data, 1,971 public utilities or 98 percent of the public 

utilities in the United States had less than 4 million MW hours in sales which would 

qualify them as small entities. Of these, 90 percent - or 1,775 - are distribution-only 

utilities, 48 are wholesale–only, and 148 make both wholesale and retail sales.498 

NRECA states that its membership includes 930 rural cooperatives most of which are 

distribution utilities and almost all of which would qualify as small entities. 

Additionally, according to NRECA, 40 of its 65 generation and transmission cooperatives 

also qualify as small entities.499

 497 Id. at 51. 

498 APPA/NRECA comments at 2. 

499 Id.
Docket No. RM06-16-000 - 499 - 

1918. APPA/NRECA contends that the Commission did not include a complete initial 

RFA analysis as required and, without a full initial RFA, the Commission cannot lay a 

proper foundation for eliciting public comments on the impacts of the rule on small 

entities. Specifically, APPA/NRECA contends that the NOPR failed to include proposals 

that would minimize the impact on small entities. They assert that, instead, the 

Commission’s proposed definition of bulk electric system in the NOPR exceeds NERC’s 

definition and thereby sweeps in many small facilities that are unnecessary to the 

Reliable Operation of the Bulk-Power System. APPA/NRECA argue that, if the 

Commission adopts this definition, many small transmission owners and operators of 

lower voltage transmission systems will be unnecessarily required to bear the increased 

training costs to comply with Reliability Standards, yet the NOPR never considered these 

additional burdens. APPA/NRECA also asserts that, under this definition, many small 

distribution providers would also be required to comply with the communication-related 

(COM) Reliability Standards at additional costs that were never discussed. They request 

that the Commission address these shortcomings. 

1919. APPA/NRECA also claims that the Commission substantially underestimated the 

number of small entities that would be impacted by the application of the Reliability 

Standards as proposed in the NOPR. APPA/NRECA asserts that 98 percent of public 

utilities and 99 percent of public cooperatives, along with numerous small industrial 

facilities, small qualifying facilities and small generators would qualify under the small 

entity definition and would be impacted by the rule. According to APPA/NRECA, most 

of these small entities would not have a material impact on the reliability of the BulkPower System but, under the NOPR’s definition of Bulk-Power System, would be 

required to comply with the Reliability Standards. 

1920. APPA/NRECA suggests that the Commission can significantly reduce the impact 

on small entities by “focusing on materiality.” They contend that an overly-expansive 

reliability regime would violate the FPA by imposing unnecessary regulatory burdens on 

small entities and divert the ERO’s and the Commission’s resources away from those 

entities that are crucial to Bulk-Power System reliability. APPA/NRECA asserts that the 

Commission can ensure reliability without unnecessarily burdening small entities by 

considering two alternatives. First, they urge the Commission to adopt NERC’s current 

definition of bulk electric system. Second, they ask the Commission to reconsider the 

standard-by-standard approach to defining owners, users and operators of the Bulk-Power 

System and, instead, accept the NERC compliance registry to identify the entities that 

will be responsible for compliance with Reliability Standards. APPA/NRECA, TAPS, 
Docket No. RM06-16-000 - 500 - 

and numerous other commenters discuss these proposals in their comments, which the 

Commission addresses in the Applicability Issues section of the Final Rule.500

1921. TAPS asserts that the Commission should apply the ERO’s registration thresholds 

and, “absent such limits, the Commission cannot satisfy its obligations under the 

[RFA].”501 Georgia Cities asserts that the Commission should adopt reasonable limits on 

the application of the Reliability Standards to small entities, as it promised in its RFA 

statement. 

2. Commission response

1922. The Commission believes that the NOPR provided a meaningful discussion of the 

impact that the Reliability Standards could have on small entities and discussed several 

potential alternatives. In fact, the NOPR contained an entire section on the applicability 

of the proposed standards on small entities.502 In that section, the Commission discussed 

various alternatives to lessen the acknowledged potential impact on small entities. The 

Commission indicated its receptiveness to the ERO’s proposal to develop threshold limits 

regarding the applicability of specific Reliability Standards. The Commission also 

suggested that, where it is necessary for reliability that a Reliability Standard apply to 

small entities, implementation of the requirements of such Reliability Standards may vary 

based on size or role. In the NOPR, the Commission set forth another alternative to 

address the potential burden on small entities when it proposed to direct the ERO to 

develop procedures permitting a joint action agency or similar organization to accept 

compliance responsibility on behalf of its members. 

1923. As previously stated, the purpose of the RFA is to ensure that agencies consider 

the impact a proposed rule would have on small entities and any potential alternatives 

that would minimize that impact. The initial RFA analysis is designed to elicit informed 

comments on the impacts to small entities and alternatives. The Commission believes the 

NOPR achieved this goal. After the NOPR was issued, the Commission received over 

125 comments and a majority of those addressed small entity issues. Further, almost all 

of the commenters addressed the NOPR’s proposed interpretation of the definition of the 

 500 See Applicability Issues: Bulk-Power System v. Bulk Electric System and 

Applicability to Small Entities, supra sections II.C.1-2. 

501 TAPS at 13. 

502 NOPR at P 49-53. 
Docket No. RM06-16-000 - 501 - 

bulk electric system, which as APPA/NRECA states would have had the greatest impact 

on small entities. 

1924. In addition to the comments received addressing these issues, Commission staff 

has met with representatives of small entities, including APPA and NRECA, and listened 

to their concerns on the potential impacts of the Final Rule and discussed possible 

alternatives. 

1925. Since receiving APPA/NRECA’s comments on the RFA, the Commission has 

compiled and reviewed available data on small entities and the impact of the Final Rule 

on such entities. Therefore, the Commission believes that any inadequacy that may have 

existed in the NOPR’s initial RFA analysis has now been corrected. This Final RFA and 

the alternative proposals adopted herein demonstrate the Commission’s consideration of 

the potential burdens that the rulemaking could place on small entities. 

1926. As discussed in the Applicability section above, the Commission adopts in the 

Final Rule the current definition of bulk electric system. Any possible change to the 

definition would occur in a future Commission proceeding. Further, the Commission has 

endorsed the ERO’s compliance registry process to identify the entities that must comply 

with mandatory Reliability Standards.503 By adopting these alternative proposals, the 

Commission has been responsive to small entity concerns and greatly reduced the number 

of small entities that will be affected by the Final Rule. 

B. Final RFA 

1. Description of the reasons why action by the agency is being 

considered 

1927. On April 4, 2006, as later modified and supplemented, NERC – the ERO – 

submitted 107 Reliability Standards for Commission approval pursuant to section 215(d) 

of the FPA. The ERO’s submission includes the “Version 0” standards with which the 

electric industry has complied on a voluntary basis as well as several new Reliability 

Standards approved by NERC since its certification as the ERO. 

1928. As set forth in section 215(a) of the FPA, the term “Reliability Standard” means a 

requirement, approved by the Commission to provide for the Reliable Operation of the 

Bulk-Power System. The term “Reliable Operation” means “operating the elements of 

 503 As noted previously, APPA, NRECA and TAPs submitted supplemental 

comments supporting the ERO’s compliance registry process. 
Docket No. RM06-16-000 - 502 - 

the bulk-power system within equipment and electric system, thermal, voltage, and 

stability limits so that instability, uncontrolled, or cascaded failures of such system will 

not occur as a result of a sudden disturbance . . . or unanticipated failure of system 

elements.”504 Thus, the purpose of each Reliability Standard approved by the 

Commission in this Final Rule is to provide for the Reliable Operation of the Bulk-Power 

System and thereby minimize the risk of instability, uncontrolled or cascading failure on 

the Bulk-Power System. 

1929. The Commission is approving 83 of the proposed Reliability Standards. Upon the 

effective date of the Final Rule, compliance with these Reliability Standards will be 

mandatory and enforceable for applicable users, owners and operators of the Bulk-Power 

System. The Commission believes that these Reliability Standards form a solid 

foundation on which to develop and maintain the reliability of the North American BulkPower System. 

2. Objectives of and the legal basis for the Final Rule

1930. This Final Rule requires applicable users, owners and operators of the Bulk-Power 

System to comply with mandatory and enforceable Reliability Standards. As discussed 

above, these Reliability Standards are necessary to ensure the reliable operation of the 

North American Bulk-Power System. 

1931. EPAct 2005 added a new section 215 to the FPA, which provides for a system of 

mandatory and enforceable Reliability Standards. Section 215(d)(1) of the FPA provides 

that the ERO must file each Reliability Standard or modification to a Reliability Standard 

that it proposes to be made effective, i.e., mandatory and enforceable, with the 

Commission. As mentioned above, on April 4, 2006, and as later modified and 

supplemented, the ERO submitted 107 Reliability Standards for Commission approval 

pursuant to section 215(d) of the FPA. 

1932. Section 215(d)(2) of the FPA provides that the Commission may approve, by rule 

or order, a proposed Reliability Standard or modification to a proposed Reliability 

Standard if it meets the statutory standard for approval, giving due weight to the technical 

expertise of the ERO. Alternatively, the Commission may remand a Reliability Standard 

pursuant to section 215(d)(4) of the FPA. Further, the Commission may order the ERO 

to submit to the Commission a proposed Reliability Standard or a modification to a 

Reliability Standard that addresses a specific matter if the Commission considers such a 

new or modified Reliability Standard appropriate to “carry out” section 215 of the 

 504 16 U.S.C. 824o(a)(4) (2006). 
Docket No. RM06-16-000 - 503 - 

FPA.505 The Commission’s action in this Final Rule is based on its authority pursuant to 

section 215 of the FPA. 

3. Significant issues raised by comments, agency assessment of the 

comments and a statement of any changes made in the proposed 

rule as a result of the comments

1933. Numerous small entity commenters oppose the NOPR interpretation of bulk 

electric system and urge the Commission to adopt the ERO’s current definition of that 

term. Further, small entity commenters oppose the NOPR’s proposal to address 

applicability on a standard-by-standard basis and, instead, ask that the Commission rely 

on the ERO’s compliance registry process as the means to identify entities responsible for 

complying with mandatory and enforceable Reliability Standards. Commenters assert 

that the Commission’s proposed changes would greatly increase the number of small 

entities that would be significantly impacted by the Final Rule. 

1934. As discussed above, the Commission is not adopting its proposed interpretation of 

bulk electric system contained in the NOPR. Rather, the Commission adopts the NERC 

definition of bulk electric system. Further, the Commission is relying on NERC’s 

registration process to provide as much certainty as possible regarding the applicability 

and responsibility of specific entities in the start-up phase of the mandatory Reliability 

Standards regime. Any change in these approaches would be addressed in a separate 

Commission proceeding. 

1935. A complete summary of these comments and the Commission’s response has been 

previously addressed in the Applicability section. 

4. Description and estimate of the number of small entities to 

which the Final Rule will apply 

1936. According to the SBA, a small electric utility is defined as one that has a total 

electric output of less than four million MWh in the preceeding year. 

1937. According to the DOE’s Energy Information Administration (EIA), there were 

3,284 electric utility companies in the United States in 2005,506 and 3,029 of these electric 

utilities qualify as small entities under the SBA definition. Of these 3,284 electric utility 

 505 See 16 U.S.C. 824o(d)(5) (2006). 

506 See Energy Information Administration Database, Form EIA-861, Dept. of 

Energy (2005), available at http://www.eia.doe.gov/cneaf/electricity/page/eia861.html. 
Docket No. RM06-16-000 - 504 - 

companies, the EIA subdivides them as follows: (1) 883 cooperatives of which 852 are 

small entity cooperatives; (2) 1,862 municipal utilities, of which 1842 are small entity 

municipal utilities; (3) 127 political subdivisions, of which 114 are small entity political 

subdivisions; (4) 159 power marketers, of which 97 individually could be considered 

small entity power marketers;507 (5) 219 privately owned utilities, of which 104 could be 

considered small entity private utilities; (6) 25 state organizations, of which 16 are small 

entity state organizations and (7) nine federal organizations of which four are small entity 

federal organizations. 

1938. As discussed above, the Commission is relying on the ERO’s compliance registry 

process to identify which entities must comply with mandatory and enforceable 

Reliability Standards. The ERO’s Compliance Registry Criteria describe how NERC will 

identify organizations that may be candidates for registration and assign them to the 

compliance registry.508 According to this document, the ERO will register transmission 

owners and operators with an integrated element associated with the Bulk-Power System 

of 100 kV and above, or lower voltage as defined by a Regional Entity. The ERO plans 

to register only those distribution providers or LSEs that have a peak load of 25 MW or 

greater and are directly connected to the bulk electric system or are designated as a 

responsible entity as part of a required underfrequency load shedding program or a 

required undervoltage load shedding program. For generators, the ERO plans to register 

individual units of 20 MVA or greater that are directly connected to the bulk electric 

system, generating plants with an aggregate rating of 75 MVA or greater, any blackstart 

unit material to a restoration plan, or any generator “regardless of size, that is material to 

the reliability of the Bulk-Power System.” Further, the ERO will not register an entity 

that meets the above criteria if it has transferred responsibility for compliance with 

mandatory Reliability Standards to a joint action agency or other organization. 

1939. As mentioned above, the SBA defines a small electric utility as one that has a total 

electric output of less than four million MWh in the proceeding year. Thus, the set of 

small entities that must comply with mandatory Reliability Standards would be those that 

exceed the ERO registry criteria but still meet the SBA definition. The Commission has 

reviewed data compiled by EIA in Form EIA-861, NERC’s pre-registry data, and 

information submitted by commenters, and determined an estimate of the number of 

small entities to which the Final Rule will apply. 

 507 Most of these small entity power marketers and private utilities are affiliated 

with others and, therefore, do not qualify as small entities under the SBA definition. 

508 See NERC Statement of Compliance Registry Criteria (Revision 3) at 6-8. 
Docket No. RM06-16-000 - 505 - 

1940. The Commission estimates that the Reliability Standards approved in the Final 

Rule will apply to approximately 682 small entities (excluding entities in Alaska and 

Hawaii) as follows: 

670 small municipal utilities and cooperatives and 12 small investor-owned 

utilities. 

1941. As discussed above, the ERO’s Compliance Registry Criteria allows for a joint 

action agency, G&T cooperative or similar organization to accept compliance 

responsibility on behalf of its members. Once such organizations register with the ERO, 

the number of small entities registered with the ERO will diminish and, thus, 

significantly reduce the impact of the Final Rule on small entities. 

1942. To be included in the compliance registry, the ERO will have made a 

determination that a specific small entity has a material impact on the Bulk-Power 

System. Consequently, the compliance of such small entities is justifiable as necessary 

for Bulk-Power System reliability. 

5. Description of the projected reporting, record keeping and other 

compliance requirements for small entities

1943. A complete summary of comments and the Commission’s response has been 

previously addressed in the Information Collection Statement section. 

6. Duplication of other Federal Rules

1944. There are no relevant Federal rules which may duplicate, overlap or conflict with 

the Final Rule. 

7. Description of any significant alternatives to the Final Rule 

1945. In the Final Rule, the Commission adopts several significant alternatives that will 

minimize the burden on small entities. The Commission approves the current ERO 

definition of bulk electric system, which will reduce significantly the number of small 

entities responsible for complying with the Final Rule. The Commission also approves 

the ERO compliance registry process to identify the entities responsible for compliance 

with mandatory and enforceable Reliability Standards. Further, the Commission directs 

the ERO to submit a procedure to permit a joint action agency or similar organization to 

accept compliance responsibility on behalf of its members. A complete summary of 

comments and the Commission’s response has been previously addressed in the 

Applicability Section. 
Docket No. RM06-16-000 - 506 - 

VI. Document Availability

1946. 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. 

1947. From FERC's Home Page on the Internet, this information is available on 

eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft 

Word format for viewing, printin, 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. 

1948. User assistance is available for eLibrary and FERC's website during normal 

business hours from our Help line at (202) 502-8222 or the Public Reference Room at 

(202) 502-8371 Press 0, TTY (202) 502-8659. E-Mail the Public Reference Room at 

public.referenceroom@ferc.gov. 

VII. Effective Date and Congressional Notification

1949. These regulations are effective [insert date 60 days from the date the rule is 

published in the Federal Register]. The Commission has determined, with the 

concurrence of the Administrator of the Office of Information and Regulatory Affairs of 

OMB, that this rule is a “major rule” as defined in section 351 of the Small Business 

Regulatory Enforcement Fairness Act of 1996. 

List of subjects in 18 CFR Part Part 40

Electric power; reporting and recordkeeping requirements 

By the Commission. 

( S E A L ) 

 Philis J. Posey, 

 Acting Secretary. 

 
Docket No. RM06-16-000 - 507 - 

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 Electric 

Reliability Organization. 

(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 post on its website the currently 

effective Reliability Standards as approved and enforceable by the Commission. The 

effective date of the Reliability Standards must be included in the posting. 
Docket No. RM06-16-000 508 

NOTE: The following appendices will not be published in the Code of Federal 

Regulations.

Appendix A

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-001-1 Sabotage Reporting Approve; direct modification 

COM-001-1 Telecommunications Approve; direct modification 

COM-002-2 Communications and Coordination Approve; direct modification

EOP-001-0 Emergency Operations Planning Approve; direct modification

EOP-002-2 Capacity and Energy Emergencies Approve; direct modification 

EOP-003-1 Load Shedding Plans Approve; direct modification 

EOP-004-1 Disturbance Reporting Approve; direct modification

EOP-005-1 System Restoration Plans Approve; direct modification

EOP-006-1 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 
Docket No. RM06-16-000 509 

Reliability 

Standard Title Proposed Disposition 

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

INT-001-2 Interchange Transaction Tagging Approve; direct modification

INT-002-0 Interchange Transaction Tag Communication and Assessment Withdrawn

INT-003-2 Interchange Transaction Implementation Approve

INT-004-1 Interchange Transaction Modifications Approve

INT-005-1 Interchange Authority Distributes Arranged Interchange Approve 

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-001-1 Reliability Coordination – Responsibilities and Authorities Approve; direct modification 

IRO-002-1 Reliability Coordination – Facilities Approve; direct modification 

IRO-003-2 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; direct modification 

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; direct modification

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; direct modification

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; direct modification
Docket No. RM06-16-000 510 

Reliability 

Standard Title Proposed Disposition 

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; direct modification

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

Models 

Pending; direct modification

MOD-015-0 Development of Interconnection-Specific Dynamics System 

Models 

Pending; direct modification

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; direct modification

PER-001-0 Operating Personnel Responsibility and Authority Approve

PER-002-0 Operating Personnel Training Approve; direct modification 

PER-003-0 Operating Personnel Credentials Approve; direct modification 

PER-004-1 Reliability Coordination – Staffing Approve; direct modification

PRC-001-1 System Protection Coordination Approve; direct modification

PRC-002-1 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
Docket No. RM06-16-000 511 

Reliability 

Standard Title Proposed Disposition 

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

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 Undervoltage Load Shedding Program Database Pending

PRC-021-1 Undervoltage Load Shedding Program Data Approve 

PRC-022-1 Undervoltage Load Shedding Program Performance Approve 

TOP-001-1 Reliability Responsibilities and Authorities Approve; direct modification 

TOP-002-2 Normal Operations Planning Approve; direct modification 

TOP-003-0 Planned Outage Coordination Approve; direct modification 

TOP-004-1 Transmission Operations Approve; direct modification 

TOP-005-1 Operational Reliability Information Approve; direct modification 

TOP-006-1 Monitoring System Conditions Approve; direct modification

TOP-007-0 Reporting SOL and IROL Violations Approve

TOP-008-1 Response to Transmission Limit Violations Approve; 

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; direct modification

Regional 

Difference BAL-006: MISO RTO inadvertent Interchange Accounting Approve 

Regional 

Difference BAL-006: MISO/SPP Financial Inadvertent Settlement Approve 

Regional 

Difference 

INT-001/4: WECC Tagging Dynamic Schedules and Inadvertent 

Payback 

Pending 
Docket No. RM06-16-000 512 

Reliability 

Standard Title Proposed Disposition 

Regional 

Difference INT-001/3:MISO Energy Flow Information Approve 

Regional 

Difference INT-003: MISO/SPP Scheduling Agent Approve 

Regional 

Difference INT-003: MISO Enhanced Scheduling Agent Approve 

Regional 

Difference 

IRO-006: PJM/MISO/SPP Enhanced Congestion Management Pending 
Docket No. RM06-16-000 513 

Appendix B: Commenters on Notice of Proposed Rulemaking

ABBREVIATION ENTITY 

Alberta ESO Alberta Electric System Operator 

ALCOA Alcoa, Inc. and Alcoa Power Generating 

Company 

Allegheny Allegheny Power and Allegheny Energy 

Supply Company, LLC 

AMP Ohio American Municipal Power – Ohio, Inc. 

APPA American Public Power Association 

APPA/NRECA APPA/NRECA 

ATC American Transmission Company, LLC 

Avista/Puget Avista Corporation and Puget Sound Energy, 

Inc. 

BPA Bonneville Power Administration 

CAISO California Independent System Operator 

Corporation 

California Cogernation Cogeneration Association of California and the 

Energy Producers and Users Coalition 

California PUC Public Utilities Commission of the State of 

California 

CEA Canadian Electricity Association 

Cleveland Public Power City of Cleveland, Division of Cleveland 

Public Power 

Comverge Comverge, Inc. 

Connecticut Attorney General* Richard Blumenthal, Attorney General for the 

State of Connecticut 

Connecticut DPUC* Connecticut Department of Public Utility 

Control

Constellation Constellation Energy Group 

Dominion Dominion Resources Services, Inc. 

Duke Duke Energy Corporation 

Dynegy Dynegy, Inc. 

EEI Edison Electric Institute 

ELCON Electricity Consumers Resource Council 

Entergy Entergy Services, Inc. 

EPSA Electric Power Supply Association 

ERCOT Electric Reliability Council of Texas, Inc. 

Fertilizer Institute Fertilizer Institute 

FirstEnergy FirstEnergy Service Company 
Docket No. RM06-16-000 514 

City of Acworth 

City of Adel 

City of Blakely 

City of Cairo 

City of Calhoun 

City of Camilla 

City of College Park 

City of Commerce 

City of Doerun 

City of Douglas 

City of East Point 

City of Ellaville 

City of Fairburn 

City of Forsyth 

City of Fort Valley 

City of Grantville 

City of Hogansville 

City of Lafayette 

City of Lagrange 

City of Lawrenceville 

City of Mansfield 

City of Monticello 

City of Moultrie 

City of Norcross 

City of Oxford 

City of Palmetto 

City of Quitman 

City of Sanderville 

City of Sylvester 

City of Thomaston 

City of Thomasville 

City of Washington 

City of West Point 

Crisp County Power Commission 

City of Whigham 

Fitzgerald Water, Light and Bond Commission 

Georgia Cities 

Marietta Power and Water 

Georgia Operators Georgia System Operators Corp. 

International Transmission International Transmission Company 

ISO/RTO Council ISO/RTO Council 
Docket No. RM06-16-000 515 

ISO-NE ISO New England, Inc. 

KCP&L Kansas City Power and Light Company 

LPPC Large Public Power Council 

Manitoba Manitoba Hydro 

Marshall Municipal Utility Group 

Massachusetts DTE Massachusetts Department of 

Telecommunications and Energy 

MEAG Power MEAG Power 

MidAmerican MidAmerican Electric Operating Companies 

Mid-Continent Mid- Continent Systems Group 

MISO-PJM Midwest Independent Transmission System 

Operator, Inc. and PJM Interconnection, L.L.C. 

MRO Midwest Reliability Organization 

NARUC National Association of Regulatory Utility 

Commissioners 

National Grid National Grid USA 

NCPA Northern California Power Agency 

NERC North American Electric Reliability Corp. 

New England Conference of Public 

Utilities Commissioners* 

New England Conference of Public Utilities 

Commissioners, Inc. 

New York Commission New York State Public Service Commission 

New York Public Power New York Association of Public Power 

New York TOs New York Transmission Owners 

Nevada Companies Nevada Power Company and Sierra Pacific 

Power Company 

Northeast Utilities Northeast Utilities Service Company 

Northern Indiana Northern Indiana Public Service Company 

Northwest Requirements Utilities Northwest Requirements Utilities 

NPCC Northeast Power Coordinating Council: CrossBorder Regional Entity, Inc. 

NRC United States Nuclear Regulatory Commission 

NRECA National Rural Electric Cooperative 

Association 

NYSRC New York State Reliability Council, LLC 

NY Major Consumers Multiple Intervenors, an unincorporated 

association of approximately 55 large 

industrial, commercial and institutional end-use 

energy consumers with facilities in New York 

Ontario IESO Ontario Independent Electricity System 

Operator 
Docket No. RM06-16-000 516 

Otter Tail Otter Tail Power Company 

PG&E Pacific Gas and Electric Company 

Portland General Portland General Electric Company 

Process Electricity Committee Process Gas Consumers Group Electricity 

Committee 

Progress Energy Progress Energy, Inc. 

ReliabilityFirst ReliabilityFirst Corporation 

Reliant Reliant Energy, Inc. 

Santa Clara City of Santa Clara, California 

SDG&E San Diego Gas and Electric Company 

SERC SERC Reliability Corporation 

Six Cities Cities of Anaheim, Azusa, Banning, Colton, 

Pasadena, and Riverside, California 

SMA Steel Manufacturers Association 

Small Entities Forum ReliabilityFirst Corporation Small Entities 

Forum 

SoCal Edison Southern California Edison Company 

South Carolina E&G South Carolina Electric and Gas Company 

Southern Southern Company Services, Inc. 

Southwest TDUs Southwest Transmission Dependent Utility 

Group 

STI Capital STI Capital Company 

Tacoma Tacoma Power 

TANC Transmission Agency of Northern California 

TAPS Transmission Access Policy Study Group 

TVA Tennessee Valley Authority 

Utah Municipal Power Utah Associated Municipal Power Systems 

Valley Group The Valley Group, Inc. 

WECC Western Electricity Coordinating Council 

WIRAB advice Western Interconnection Regional Advisory 

Body 

Wisconsin Electric Wisconsin Electric Power Company 

Xcel Xcel Energy Services 

*Comments filed out-of-time
Docket No. RM06-16-000 - 517 - 

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 

DSM Demand-Side Management 

ERO Electric Reliability Organization 

GWh Gigawatt hour 

IEEE Institute of Electrical and Electronics Engineers 

IROL Interconnection Reliability Operating Limits 

LSE Load-serving Entity 

MVAR Mega Volt Ampere Reactive 

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 Underfrequency Load Shedding 

UVLS Undervoltage Load Shedding