16416 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

DEPARTMENT OF ENERGY 

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 

Web site for public inspection. 

EFFECTIVE DATE: This rule will become 

effective June 4, 2007. 

FOR FURTHER INFORMATION CONTACT: 

Jonathan First (Legal Information), 

Office of the General Counsel, Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 20426, 

(202) 502–8529. 

Paul Silverman (Legal Information), 

Office of the General Counsel, Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 20426, 

(202) 502–8683. 

Robert Snow (Technical Information), 

Office of Energy Markets and Reliability, 

Division of Reliability, Federal Energy 

Regulatory Commission, 888 First 

Street, NE., Washington, DC 20426, 

(202) 502–6716. 

Kumar Agarwal (Technical 

Information), Office of Energy Markets 

and Reliability, Division of Policy 

Analysis and Rulemaking, Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 20426, 

(202) 502–8923. 

SUPPLEMENTARY INFORMATION: Before 

Commissioners: Joseph T. Kelliher, 

Chairman; Suedeen G. Kelly; Marc 

Spitzer; Philip D. Moeller; and Jon 

Wellinghoff. 

TABLE OF CONTENTS

Paragraph 

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 

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 .................................................................................................................................. 446 


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Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 16417 

1U.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. 

2Energy 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. 

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

4Rules 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). 

5North 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). 

6Section 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). 

7Order No. 672 at P 262, 321–37. 

TABLE OF CONTENTS—Continued 

Paragraph 

3. COM: Communications ......................................................................................................................................................... 473 

4. EOP: Emergency Preparedness and Operations ................................................................................................................... 542 

5. FAC: Facilities Design, Connections, Maintenance, and Transfer Capabilities ................................................................. 678 

6. INT: Interchange Scheduling and Coordination .................................................................................................................. 796 

7. IRO: Interconnection Reliability Operations and Coordination .......................................................................................... 889 

8. MOD: Modeling, Data, and Analysis .................................................................................................................................... 1007 

9. PER: Personnel Performance, Training and Qualifications ................................................................................................. 1325 

10. PRC: Protection and Control ............................................................................................................................................... 1419 

11. TOP: Transmission Operations ........................................................................................................................................... 1568 

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 

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 Web site 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 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 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 


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16418 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

8 Id. at P 329. 

9 Id. at P 332. 

10 Id. at P 337. 

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

12 18 CFR 39.5(a). 

13 18 CFR 39.5(e). 

14The 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 Web site, http:// 

www.nerc.com/filez/nerc_filings_ferc.html. 

15Eight 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. 

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

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 Interconnectionwide basis with respect to a proposed 

Reliability Standard or a proposed 

modification to a Reliability Standard to 

be applicable within that 

Interconnection. However, the 

Commission 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 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 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 


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Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 16419 

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). 

17The 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. 

18See NERC comments, Attachment B. 19NOPR at P 14. 

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 BulkPower 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). 

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). 

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, 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, 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 Bulk-Power 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 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 


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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). 

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). 

32Under 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). 

34Section 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). 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. 

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 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 Interconnectionwide basis for a Reliability Standard or 

modification to a Reliability Standard to 

be applicable on an Interconnectionwide 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 

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 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 


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36FPT letter to Chairman Kelliher (submitted on 

July 10, 2006) (placed in the record of this 

proceeding). 37NOPR at P 37. 

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 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. 

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 BulkPower System comply with 

Commission-approved Reliability 

Standards developed by the ERO, and 

would provide that the Commissionapproved Reliability Standards can be 

obtained from the Commission’s Public 

Reference Room at 888 First Street, NE., 

Room 2A, Washington, DC 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. 

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 Web 

site. Therefore, we will require that all 

Commission-approved Reliability 

Standards be available on the ERO’s 

Web site, 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, NE., Room 2A, 

Washington, DC, 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 


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38See 16 U.S.C. 824o(d)(2). 

39NOPR at P 39–41. 40See 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). 41See Order No. 672 at P 308; Order No 672–A 

at P 26. 42NERC Glossary at 2. All citations to the 

Glossary in this Final Rule refer to the November 

1, 2006 version filed on November 15, 2006. 

43NOPR 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. 

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 Web site. 

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 Commissionapproved Reliability Standards that are 

available in the Commission’s Public 

Reference Room and on the Internet at 

the ERO’s Web site. 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

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 Web 

site 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 

Web site 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 Web site 

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 

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 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-bycase 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 


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44NRECA, citing Morissette v. United States, 342 

U.S. 246, 263 (1952). 45See, e.g., NERC, TAPS and NRECA. 

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 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 BulkPower 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 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 BulkPower 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 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 


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46See Rules of Procedure, § 500. 

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 Bulk-Power 

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. 

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 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 BulkPower 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 


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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.’’

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

Entities, infra. 

49Citing Morissette v. United States, 342 U.S. 

246, 263 (1952). 

50NOPR 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. 

51See id. at P 64–65 & n.53–54. 52 Id. P 49–53. 

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 

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 caseby-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 system 47 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 BulkPower 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 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 BulkPower 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 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, 


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53See ERO Rehearing Order at P 108. 

54NERC 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. 

55See NOPR at P 1175–76. 

56 18 CFR 292.601(c). 

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. 

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 BulkPower 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. 

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 BulkPower 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 Bulk-Power 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 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 


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57California Cogenration at 6–7, citing California 

Independent System Operator Corp., 96 FERC 

¶ 63,015, at P 7, 24–25 (2001). 

58ERO Certification Order at P 689. 

59The 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. 

60See Supplemental Comments of TAPS 

(February 13, 2007), APPA (February 14, 2007), and 

NRECA (February 15, 2007). 

61See NERC Rules of Procedure, § 500. 

62NOPR at P 49. 

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 facilityby-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 BulkPower 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 

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. 

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 


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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. 

65See ERO Certification Order at P679. 

66See NERC comments at 53–55; NERC 

supplemental filing, Statement of Compliance 

Registry Criteria (Revision 3) at 9. 

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 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 (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. 

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 


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Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 16429 

67Section 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. 

68See NERC Supplemental Filing, Statement of 

Compliance Registry Criteria (Revision 3), at 8–9. 

69NOPR at P 43. 

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, 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. 

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 standardby-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. 

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 


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70NOPR at P 46–48. 

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. 

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 BulkPower 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 

Commission-approved 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 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 

should be modified to exclude entities 

providing service only to loads on-site 

or pursuant to private contract. 


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Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 16431 

71We note that NERC has available on its Web 

site, http://www/nerc.com, the current version of 

the Functional Model. We expect NERC to continue 

to do so in the future. 

72NOPR 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. 

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 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 Commissionapproved 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. 

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 


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16432 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

74See, 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. 

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 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 selfevident, 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. 

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 

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 


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75NOPR at P 54. 

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. 

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. 

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 


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76Order No. 672 at P 654. 

77EOP–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. 

78NOPR at P 57 (footnotes omitted). 

79See ERO Certification Order at P 281. 

80Order No. 672 at P 262, 321–37. 

81NOPR 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. 

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. 

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

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 long-term 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 non-statutory 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 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, Order No. 

672 identified factors that the 

Commission will consider when 

determining whether a proposed 


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83Order 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.’’) 

85NOPR at P 78–82. 

86See, e.g., NERC, Entergy, EEI, APPA, National 

Grid, NRECA, TAPS, ISO–NE and Duke. 

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 ANSIcertified 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. 

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 


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87See, e.g., NERC, EEI, ELCON, CEA, NYSRC, 

TVA, LPPC, NPCC, Ontario IESO, Constellation, 

Progress and Dynegy. 

development 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 pre-determine 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 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 yetto-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 

improvements to the Reliability 

Standards. NERC states that if the 

Commission acts on the views 

expressed on a specific Reliability 

Standard 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 


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88See NOPR at P 79–80. 

89 16 U.S.C. 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.’’). 

90Moreover, 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 U.S.C. 824o(d)(5). 

92See discussion below regarding the Trial 

Period, section II.D.4. 

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. 

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 

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 threeyear 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. 

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 Bulk-Power 

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 


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93See 18 CFR 39.5(g). 

94NOPR at P 85–87. 

95 Id. at Appendix D (High Priority List). 

96Some projects relate to new Reliability 

Standards that are not before the Commission in the 

instant rulemaking. 97NOPR at P 86. 

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 

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. 

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 NonCompliance 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 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 NonVerDate Aug<31>2005 18:02 Apr 03, 2007 Jkt 211001 PO 00000 Frm 00024 Fmt 4701 Sfmt 4700 E:\FR\FM\04APR2.SGM 04APR2

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98Preventing 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. 

100See, e.g., EEI, APPA, TAPS, EPSA, CAISO, 

Bonneville, California PUC, Cleveland, Otter Tail, 

Northwest Requirements Utilities, TVA and SMA. 

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 NonCompliance 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. 

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

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 BulkPower System is substantially altered to 


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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 

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 wellunderstood 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. 

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 

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 


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101NOPR at P 92. 

102 Id. at P 93. 

103ERO Certification Order at P 451. 

104See Order No. 672 at P 400. 

105ERO Certification Order at P 286. 

106Compliance Filing of the North American 

Electric Reliability Council and the North American 

Electric Reliability Corporation Addressing NonGovernance Issues, Appendix 3C, Docket No. 

RR06–1–000 (October 18, 2006). 

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 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 BulkPower 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 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. 672 104 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. 

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. 


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16442 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

107 January 2007 Compliance Order at P 44. 

108 Id. 

109Order No. 672 at P 296. 

110NOPR at P 99–100. 

111Blackout Report at 147 

112EEI 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). 

114Order No. 890 at P 1671–77. 

115U.S.-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 at Fully Implement 

Recommendation 8: No further action under this 

recommendation is needed’’). 

116 Id. (‘‘In the United States, some state 

regualtors have informally expressed the view that 

there is appropriate protection against liability suits 

for parties who shed load according to approved 

guidelines.’’) 

117Order 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, 

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 NERCproposed 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 continentwide Reliability Standards. 

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 BulkPower 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

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 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 


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Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 16443 

225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. New 

York v. FERC, 535 U.S. 1 (2002). 

118Although 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 noncompliance with a Reliability Standard. The Levels 

of Non-Compliance range from Level 1 to Level 4, 

with Level 4 being the most severe. 

120NOPR at P 105–07. 

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 NonCompliance 

238. The NOPR noted that, according 

to the Staff Preliminary Assessment, a 

number of proposed Reliability 

Standards do not contain Measures 118

or Levels of Non-Compliance,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 Non-Compliance 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 NonCompliance 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 NonCompliance.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 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 NonCompliance. 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. 

243. NYSRC states that, in NERC’s 

rush to file with the Commission the 20 

revised Reliability Standards with new 

Measures and Levels of NonCompliance, 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. 


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16444 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

121FirstEnergy at 10–11, citing NOPR at P 16; see 

also Order No. 672 at P 262, 321–37. 

122NOPR at P 105 (footnote omitted). 

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. 

247. With regard to the concerns of 

MISO and Constellation, we agree as a 

general principle that Levels of NonCompliance 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 NonCompliance 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 Non-Compliance, 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 NonCompliance 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 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 NonCompliance. 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 NonCompliance 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 Non-Compliance 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: 

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 Non-Compliance, 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 


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Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 16445 

123APPA 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 NonCompliance 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. 

124Enforcement of Statutes, Orders, Rules, and 

Regulations, 113 FERC ¶ 61,068 (2005) (Policy 

Statement on Enforcement). 

125 January 2007 Compliance Order at P 93. 

126NOPR at P 107. 

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 NonCompliance. Where a Reliability 

Standard can be improved by providing 

missing Measures or Levels of NonCompliance 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 NonCompliance does not make an otherwise 

clear Requirement 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. 

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-by-standard 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 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. 


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127NOPR at P 110–12. 

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 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. 

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 BulkPower 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 


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Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 16447 

128Many sections of the FPA, including section 

215, use such terms as just and reasonable or 

unduly discriminatory or preferential or even the 

public interest. 129 January 2007 Compliance Order at P 16. 

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. 

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 

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-bystandard 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, BulkPower 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 NonCompliance 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 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 


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130NOPR at P 115. 

131 January 2007 Compliance Order at P 18. 

132NOPR at P 116. 

133 Id. at P 121, citing Order No. 672 at P 292; 

ERO Certification Order at P 274. 134NOPR at P 123. 

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-bystandard 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 

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-by-standard 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 continentwide 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 fillin-the-blank standards, require the 

regional reliability organizations to 

develop criteria for use 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-inthe-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-theblank standards) as pending at the 

Commission until further information is 

provided, and to require that BulkPower 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 

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 


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Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 16449 

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

0, PRC–016–0, PRC–018–1 and PRC–021–0. 136NOPR at P 123. 137 Id. at P 121 (footnote omitted). 

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-theblank Reliability Standards.135 ISO–NE 

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 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 fillin-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-theblank 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 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 


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138Policy Statement on Matters Related to Bulk 

Power System Reliability, 107 FERC ¶ 61,052 at P 

23–26 (2004) (Reliability Policy Statement). 139NOPR at P 136. 

140At 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. 

141 Id. at P 143. 

142Order No. 672 at P 290. 

143 Id. at P 291. 

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 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 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 area 140

asynchronously connected to the 

Eastern Interconnection, cannot create 

inadvertent flows or time errors in other 

control areas and (2) CPS2 may not be 

feasible under ERCOT’s competitive 

balancing energy market. In support of 

this argument, ERCOT cites to a study 

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 


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144 Id. 

145A ‘‘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. 

146NOPR at P 151. 

147The NOPR explained that this could be 

accomplished by modifying Requirement R2 or 

developing a new Reliability Standard. 

148This 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. 149NERC Glossary at 15. 

150See 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. 

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. 

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 groups 145

and regional reliability organizations. 

317. In the NOPR, the Commission 

proposed to approve Reliability 

Standard BAL–002–0 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. 

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 NonCompliance 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 re-apportioned 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 

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 demandside 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 


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151See NERC, ISO–NE, APPA and SDG&E. 

152MISO–PJM comments jointly with respect to 

IRO–006–3 only. 

153NOPR at P 157. 

154Order 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.’’) 

156See http://www.electricitycommission.govt.nz/ 

pdfs/rulesandregs/rules/rulespdf/Part-C-sched-C5- 

1Dec06.pdf. 

157ERCOT 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. 

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 the 

Commission eliminate any such 

uncertainty and amend the proposed 

Reliability Standards as further 

described in its comments. 

326. Some commenters 151 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. 

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 Bulk-Power 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 objectivebased 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 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 


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158See APPA, International Transmission, MISO–

PJM, LPPC and California PUC. 

159NOPR at P 156. 

160Although Frequency Response and Bias are 

161NOPR at P 153. 

162See NERC, APPA, Xcel, MRO, ISO–NE, EEI 

and Nevada Companies. 

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. 

338. Other commenters 158 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,’’ ‘‘nonspinning,’’ ‘‘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 

continent-wide 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 

interconnected or isolated operation.160

341. 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. 

342. 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. 

343. 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. 

344. 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 BulkPower System. 

345. Accordingly, the Commission 

requires the ERO to develop a continentwide 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 continentwide 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. 

v. Disturbance Control Standard and the 

Associated Reserve Requirement 

(a) Comments 

346. 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

347. Most commenters 162 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 


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163See NOPR at n.116. 164 Id. at n.134. 

165NERC Comments on the Staff Preliminary 

Assessment at 41. 

166NOPR at P 153. 

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. 

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. 

348. NRC notes the NERC and 

Commission observations regarding the 

declining trend in frequency response 

and states that this Reliability Standard 

provides the opportunity to establish a 

frequency response performance 

standard. NRC staff suggests that a 

Measure be added to establish a 

frequency response. 

349. 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. 

350. 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. 

351. 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 

352. 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. 

353. 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

354. 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. 

355. 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. 

356. 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 

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 

357. The Commission approves 

Reliability Standard BAL–002–0 as 


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168This could be accomplished by modifying 

Requirement R2 or developing a new Reliability 

Standard. 

169Frequency 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. 

170The 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. 

171NOPR at P 177. 

172 Id. at P 175. 173See id. at P 129. 

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) 

358. The purpose of BAL–003–0 is to 

ensure that a balancing authority’s 

frequency bias setting 169 is accurately 

calculated to match its actual frequency 

response.170 In the NOPR, 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 BAL–003–0 

that: (1) Includes Levels of NonCompliance and (2) modifies Measure 

M1 to include yearly surveys of 

frequency response.171

359. 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 

360. Several commenters address the 

Commission’s proposal to direct the 

ERO to modify Measurement M1 to 

include yearly surveys. 

361. 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. 

362. 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. 

363. 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). 

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 overcompensated 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. 

364. 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. 

365. 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 natural response and (3) 

possible opportunities for creating 

markets for load and generator response 

to frequency changes. 

366. 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 counterproductive by making procedural errors 

more likely, which could harm 

reliability. Northern Indiana suggests 

that the approach suggested in the 

NOPR would require frequency 


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174Order No. 672 at P 324. 175As 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. 

176See 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_Assessment_12-18-06.doc. 

177See 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.pdf. 

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. 

367. 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 steady-state 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. 

368. 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 

369. 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. 

370. 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 Web site 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 BulkPower 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

371. 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. 

372. 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 overcompensated across the 

Interconnections, while EEI states that 

the one percent default value was 

deliberately set to over-bias the system 

to 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 event 176 that resulted in larger 

than anticipated amounts of firm load 

shedding by underfrequency relays 

operation due to less than desirable 

amounts of frequency response. 

373. 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. 

374. As the Commission noted in the 

NOPR and in our response to 

FirstEnergy, Requirement R2 of this 


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178Cohn, Nathan, Control of Generation and 

Power Flow on Interconnected Systems, (John Wiley 

and Sons 1966). 179The 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. 

180NOPR at P 184. 

181See http://www.wecc.biz/documents/library/ 

procedures/Time_Error_ Procedure_10-04-02.pdf. 

182See http://www.nerc.com/~filez/inadv.html 

(regarding inadvertent interchange data) and http:// 

www.nerc.com/~filez/timerror.html (regarding time 

error correction). 

183See Xcel, Northern Indiana, ISO–NE, LPPC 

and MISO–PJM. 

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. 

375. 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. 

376. 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) 

377. 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 

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 NonCompliance and additional Measures.180

378. Further, the Commission noted 

that WECC has implemented an 

automatic time error correction 

procedure 181 that, according to data on 

the NERC Web site, 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 

379. 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. 

380. While APPA and EEI favor 

adopting the WECC approach to time 

error correction, NERC and the majority 

of other commenters 183 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 WECCtype 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 treated as a 

non-essential guide. ISO–NE agrees that 

time error correction is not a reliability 

issue. 

381. 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. 

382. 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 

383. 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 


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184See W.R. Prince, et al., Cost Aspects of AGC, 

Inadvertent Energy and Time Error, IEEE 

Transactions on Power Systems, February 1990, at 

111. 

185NOPR at P 179, 183. 186NOPR at P 197. 

187See APPA, EEI, International Transmission, 

MISO–PJM, MidAmerican and LPPC. 

research that would provide a technical 

basis for the present approach or for any 

alternative approach. 

384. 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 

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. 

385. 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 

Web site 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. 

386. 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. 

387. The Commission agrees with 

MISO regarding the number of time 

error corrections using WECC’s 

procedure. However, the magnitude of 

the frequency change 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) 

388. 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. 

389. In the NOPR, the Commission 

proposed to approve Reliability 

Standard BAL–005–0 as mandatory and 

enforceable. In addition, pursuant to 

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

§ 39.5(f) of our regulations, the 

Commission 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 Non-Compliance and 

Measures, including a Measure that 

provides for a verification process over 

the minimum required automatic 

generation control or regulating reserves 

a balancing authority maintains.186

390. 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 

391. 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 

indicator. South Carolina E&G believes 

the Commission’s proposal provides a 

good interim solution. 

392. 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. 

393. NERC and other commenters 187

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. 

394. 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. 

395. 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. 


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188EEI, TVA, International Transmission, 

Multiple Interveners, MISO–PJM, South Carolina 

E&G and Wisconsin Electric. 

189Since the Commission used the term 

‘‘contingency reserves’’ inappropriately in this 

section, we assume that Constellation intended this 

to be regulating reserves. 

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. 

396. 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. 

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 

397. 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. 

398. 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. 

399. 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. 

400. 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 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 

401. 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. 

402. 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. 

403. 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. 

404. 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 

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 

405. 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 


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16460 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

190NOPR at P 194. 

191See California Cogeneration at 6, citing 

California Independent System Operator Corp., 

Opinion No. 464, 104 FERC ¶ 61,196 (2003). 

192NOPR at n.134. 

193See R. L. Vice, Frequency Issues 2005, 

available at: http://www.wecc.biz/documents/ 

library/RITF/Frequency_Issues_2005_rev_0.pdf. 

control load management as regulating 

reserves, subject to the clarifications 

provided in this section. 

406. 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. 

407. 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. 

iii. Whether Balancing Authorities Are 

Experiencing or Predicting Difficulty in 

Obtaining Sufficient Automatic 

Generation Control 

(a) Comments 

408. 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 

409. In response to Constellation’s 

concerns, the Commission notes that, if 

regulation is being provided over nonfirm 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 

410. 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. 

411. 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. 

412. 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. 

413. 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

414. 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 

415. 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 documents 

that identify that some balancing 

authorities are restricting automatic 

generation control actions during 

schedule changes.193

416. 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. 

417. 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 


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194See Applicability Issues: Bulk-Power Ststem v. 

Bulk Electric System and Applicability to Small 

Entities, supra sections II.C.1–2. 

195See Common Issues Pertaining to Reliability 

Standards: Measures and Levels of NonCompliance, supra section II.E.2. 196NOPR at P 212. 

197 Xcel, MRO, MidAmerican and MISO–PJM. 

198MidAmerican explains that large interchange 

imbalances are a result of telemetry failures, AGC 

misoperation or scheduling errors and further states 

that BAL–001 addresses AGC performance and the 

INT standards handle compliance with scheduling 

requirements. 

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. 

418. 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. 

419. 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 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

420. 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 

421. 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 non-firm 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) 

422. BAL–006–1 requires that each 

balancing authority calculate and record 

inadvertent interchange on an hourly 

basis. 

423. In the NOPR, the Commission 

proposed to approve Reliability 

Standard BAL–006–1 as mandatory and 

enforceable. In addition, pursuant to 

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

§ 39.5(f) of our regulations, the 

Commission proposed to direct that 

NERC submit a modification to BAL–

006–1 that adds Measures and 

additional Levels of Non-Compliance 

including Measures concerning the 

accumulation of large inadvertent 

imbalances.196

424. 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 

Non-Compliance Including Measures 

Concerning the Accumulation of Large 

Inadvertent Imbalances 

(a) Comments 

425. Certain commenters 197 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 NonCompliance for large accumulations, it 

must insure that no ‘‘double penalties’’

are imposed. 

426. 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 control 

performance standard. EEI strongly 

recommends that the Commission 

clarify whether it intends for the 

industry to reconsider this fundamental 

reliability principle. 

427. 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 


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16462 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

199OATT Reform NOPR at P 208. 

200NOPR at P 206. 

201See BAL–006–1 (Inadvertent Interchange, 

Purpose Statement). 202See Order No. 890 at P 702–03. 203NOPR at P 216. 

scheduling requirement for small 

bilateral paybacks (such as WECC has 

implemented). 

428. 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 

docket 199 while approving Reliability 

Standards that perpetuate the 

preferential treatment of balancing 

authority inadvertent interchange.200

(b) Commission Determination 

429. 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 NonCompliance. 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. 

430. The Commission disagrees with 

MidAmerican that having Measures in 

this Reliability Standard will result in 

double penalties. The Commission 

believes that this 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

431. 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. 

432. 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. 

433. 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

434. 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 

435. 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 and demand and 

suggests that options to address these 

large inadvertent imbalances should be 

addressed through the Reliability 

Standards development process. 

436. 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. 

437. 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 

438. 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. 

439. 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 

440. 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. 

h. Regional Differences to BAL–006–1: 

Inadvertent Interchange Accounting and 

Financial Inadvertent Settlement 

441. 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, 


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204BAL–006–1, filed on August 28, 2006, would 

extend the regional difference to SPP. 

205Order No. 672 at P 291. 

206The 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 Non-Compliance. 

207On 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. 

and NERC approved, the same regional 

difference for.204

442. 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. 

443. 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 

444. 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. 

ii. Commission Determination 

445. 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 market 205 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 

446. 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

447. 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 

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. 

448. 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 

449. 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. 

450. 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. 

451. 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 BulkPower System. California Cogeneration 

suggests that CIP–001–1 be revised to: 

(1) Exclude generator output used onsite and (2) provide a mechanism for 

determining that a facility has no 

material impact and thus is exempt from 

compliance. 

452. 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 


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208See, e.g., APPA, FirstEnergy, SoCal Edison, 

Six Cities and TAPS. 

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. 

453. 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 ‘‘entity-specific ‘fill-inthe-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. 

454. 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. 

455. 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 

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. 

456. 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. 

457. 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. 

458. 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 

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 

459. 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. 

460. 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 


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209See 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. * * *’’ 211NOPR at P 228. 212 Id. at P 231. 

(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. 

461. 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 CIP–001–1 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. 

ii. Definition of Sabotage 

462. 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. 

463. 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 

464. 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-in-the-blank standard, contends that 

it lacks sufficient detail upon which the 

ERO can base compliance and 

enforcement efforts. 

465. 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 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 

466. 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. 

467. 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 

468. CIP–001–1, Requirement R4, 

requires that each applicable entity 

establish communications contacts, as 

applicable, with the local FBI or Royal 

Canadian Mounted 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

469. 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’’


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213 Id. at n.142. 

214See 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. 

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. 

470. 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. 

471. 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 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 

472. 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 

473. 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. 

474. 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) 

475. COM–001–0 215 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. 

476. 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. 

477. 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. 


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216COM–001–1 Requirement R1.4 states: ‘‘Where 

applicable, these [telecommunications] facilities 

shall be redundant and diversely routed.’’

478. 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 

479. 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 

480. 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. 

481. 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 Bulk-Power System. 

482. 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. 

483. 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. 

484. TAPS states that Requirement 

R1.4 has an ambiguous requirement 216

that, if applied to distribution providers 

and generator operators, would impose 

redundancy requirements well beyond 

what is reasonably necessary for BulkPower 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 ‘‘overstepping 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. 

485. 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. 

486. 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. 

487. 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 

488. 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 


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16468 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

217See Applicability Issues: Applicability to 

Small Entities, supra section II.C.2. 

218See, e.g., EEI, International Transmission, 

ISO–NE, Process Electricity Committee and SoCal 

Edison. 

requirements will be developed under 

the Reliability Standards development 

process. 

489. 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. 

490. 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 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. 

491. 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. 

492. 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. 

493. 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 BulkPower 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 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. 

494. 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 BulkPower System. 

ii. Requirements for 

Telecommunications Facilities 

495. 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 

496. 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. 

497. Many commenters recommend 

that telecommunications facilities 

requirements should be specified in 

broad terms. EEI, APPA, Alcoa, 

International Transmission, 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 


ycherry on PROD1PC64 with RULES2
Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 16469 

219Attachment 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. 

cautions that we should not prejudice 

the modification of this Reliability 

Standard by indicating the specific 

requirements or the performance 

criteria. 

498. 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. 

499. 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. 

500. 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. 

501. 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 display alarms 

only for data facilities. Requirement R2 

could be misinterpreted to require 

alarms on voice facilities as well, which 

would be impractical. 

502. 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 

503. 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. 

504. 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 costeffective solutions for compliance with 

the Reliability 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. 

505. 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 NonCompliance 

506. 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 Non-Compliance to the 

Version 0 Reliability Standard. 

(a) Comments 

507. 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 

508. 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 


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16470 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

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. 

221See Common Issues Pertaining to Reliability 

Standards: Measures and Levels of NonCompliance, supra section II.E.2. 

regional reliability organization should 

not be the compliance monitor for 

NERCNet, we leave it to the ERO to 

determine whether it is the appropriate 

compliance monitor or if compliance 

should be monitored by the Regional 

Entities for NERCNet User 

Organizations. 

iv. Summary of Commission 

Determination 

509. While the Commission has 

identified a number of concerns with 

regard to COM–001–1, 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) 

510. COM–002–2 220 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. 

511. The Commission proposed in the 

NOPR to approve Reliability Standard 

COM–002–1 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 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 

512. 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 

513. 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 COM–002–2 

to apply to distribution providers 

through its Reliability Standards 

development process. 

514. 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. 

ii. Measures and Levels of NonCompliance 

(a) Comments 

515. 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 Non-Compliance 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 

516. 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 

517. 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 


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Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 16471 

222See, e.g., APPA, EEI, California PUC, ISO–NE 

and SDG&E. 223Alcoa 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. 224The 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.’’ 225The 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 widearea 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. 

226TOP–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 * * *.’’

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 

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. 518. 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. 519. 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

(b) Commission Determination 

520. 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. 

521. 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 BulkPower System. Therefore, we adopt the 

proposed directive as stated in the 

NOPR. 

522. 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 

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. 

523. 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. 

524. 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 TOP–001–1 Requirement 

R3 in cases of personnel safety, 

potential equipment failure or 

environmental needs. 

525. We disagree with commenters 

that the Commission’s proposed 


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227Blackout Report at 107. 

228 Id. at 141. 

229NOPR at P 255. 

230EOP–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.’’

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 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 COM–002–2 is duplicative 

of IRO–005–1. 

526. 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 

527. 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 

528. 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

529. EEI supports the Commission in 

its concerns regarding Blackout 

Recommendation No. 26 on emergency 

communications. However, EEI states 

that 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. 

530. 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. 

531. 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 

532. 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. 

533. 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 continentwide basis. This will eliminate possible 

ambiguities in communications 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. 

534. 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. 

535. 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. 

536. 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 

537. 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. 

538. FirstEnergy asks that the 

Reliability Standard specify what is 


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231This Requirement could, for example, be 

included in COM–002–2 or in an operating 

Reliability Standard. 232NOPR at P 272. 

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. 

539. 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 real-time 

emergency conditions will constitute 

adequate compliance. 

(b) Commission Determination 

540. 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 

541. 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 authority 231 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 

542. 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) 

543. NERC’s proposed Reliability 

Standard EOP–001–0 requires each 

transmission operator and balancing 

authority to develop, maintain and 

implement a set of plans to mitigate 

operating emergencies. These plans 

must be coordinated with other 

transmission operators and balancing 

authorities and the reliability 

coordinator. 

544. In the NOPR, the Commission 

proposed to approve Reliability 

Standard EOP–001–0 as mandatory and 

enforceable. In addition, pursuant to 

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

§ 39.5(f) of our regulations, 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. 

545. 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 

546. 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. 

547. 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. 

(b) Commission Determination 

548. 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 


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233 Id. at P 273. 

234 Id. 

235 Id. at P 995. 

236 Id. 

operating emergencies for their specific 

areas of responsibility, unlike reliability 

coordinators, they do not have widearea views. 

549. 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 

550. 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 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 loads 

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. 

551. 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. 

552. 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 

553. 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 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. 

554. 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. 

555. 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. 

556. 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. 

557. 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 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 

558. 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 


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237 Id. at P 275. 

238 Id. at P 276. 239 Id. 

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. 

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. 

559. 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 

560. 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

561. 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 

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. 

562. 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. 

563. Further, we agree with ISO–NE 

that the proposed modification should 

be field-tested 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 

564. 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 plan elements, and 

not the ‘‘for consideration’’ elements of 

Attachment 1, should be the basis for 

compliance. 

(b) Commission Determination 

565. 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. 

566. 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 

567. 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. 

b. Capacity and Energy Emergencies 

(EOP–002–2) 

568. 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 


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241NOPR at P 284. 

242Requirement 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.’’

243 ISO–NE also notes that in the first line of 

Requirement R7 the reference to ‘‘R7’’ should be to 

‘‘R6.’’

all necessary generation on line, 

communicate about the energy and 

capacity emergency with the reliability 

coordinator and coordinate with other 

balancing authorities. EOP–002–2 

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. 

569. 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. 

570. 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 

571. 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. 

(b) Commission Determination 

572. 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 

573. 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 

574. 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 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 

575. 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. 

576. International Transmission states 

that TLR can be an effective and 

appropriate means to mitigate IROL 

violations or for use in emergency 

situations and therefore EOP–002–2 

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. 

577. 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 NERC to 

allow the responsible entities flexibility 

in the means by which they achieve 

compliance with the Reliability 

Standard.243

(b) Commission Determination 

578. A number of commenters agree 

that the TLR procedure is an 

inappropriate and ineffective tool for 

mitigating actual IROL violations or for 


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244See, e.g., APPA, EEI, Entergy and 

MidAmerican. 

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. 

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. 579. As to APPA’s comment that we 

are intruding on NERC’s role as a 

standard-setting 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 

580. 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 discretion not to 

implement every action specified in its 

capacity and energy emergency plans 

when other appropriate actions are 

possible. 581. 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. 582. 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 

583. 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 

584. 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) 

585. 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 Interconnection.245 It includes 

requirements to establish plans for 

automatic load shedding for 

underfrequency or undervoltage, 

manual load shedding to respond to 

real-time emergencies and 

communication with other balancing 

authorities and transmission operators. 

586. 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 NonCompliance. 

587. 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 

588. 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 Bulk-Power 

System without causing adverse impacts 

associated with unnecessary shedding 

of firm load. 


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246 NOPR at P 294. 

247See Xcel, ISO–NE, TVA, International 

Transmission and MISO. 

589. 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. 

590. 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. 

591. 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 

592. 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. 

593. 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. 

594. 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. 

595. 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. 

596. 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. 

ii. Periodic drills of simulated load 

shedding 

(a) Comments 

597. 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 EOP–003–1. 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 

598. 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 

599. 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, 


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248See Common Issues Pertaining to Reliability 

Standards: Blackout Report Recommendation on 

Liability Limitations, supra section II.E.1. 

249U.S.-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 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. 

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. 

600. 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 

601. 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. 

602. 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. 

603. 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. 

iv. Summary of Commission 

Determination 

604. 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) 

605. 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. 

606. 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 

607. 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 explicitly 

stating the requirement to provide data 

to NERC brings clarity to the 

expectations of NERC and the 

Commission. 

608. 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. 

609. 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. 

610. 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. 


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251NOPR at P 304. 

611. APPA states that NERC’s 

November 15, 2006 revision partially 

fulfills the proposed modification to 

include Measures and Levels of NonCompliance. APPA notes that EOP–004–

1 did not provide Measures for R2, R3.2, 

R3.4, R4 and R5. 

ii. Commission Determination 

612. 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 BulkPower System to provide disturbance 

data, voice recordings and other 

information collected during the 

disturbance to assist NERC in the 

investigation of the blackout or 

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. 

613. 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. 

614. 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. 

615. 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. 

616. 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. 

617. 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. 

618. 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. 

619. 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) 

620. 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. 

621. In the NOPR, the Commission 

proposed to approve Reliability 

Standard EOP–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 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 

622. 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 but the 

Measures and Levels of NonCompliance elements refer only to 

transmission operators. 

623. 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. 

624. 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 EOP–005–1 would 

be redundant. MISO also believes that 

the proposed modification is 

unnecessary. It states that there are 

already requirements for simulationbased training on emergencies and 

restoration and it is unclear what is 

meant by conducting training to prepare 

operators for unforeseen events. 


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252See APPA, ISO–NE, FirstEnergy and MRO. 

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. 

625. 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 companyspecific basis. 

626. 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. 

627. 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, 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 

628. 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. 

629. 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. 

630. 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 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. 

631. 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 EOP–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 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) 

632. 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. 

633. 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 NonCompliance. 

i. Comments 

634. APPA states that Reliability 

Standard EOP–006–1, which NERC filed 

on November 15, 2006, includes the 

required Measures and Levels of NonCompliance and 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. 


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254See FirstEnergy at 35. 

255See NOPR at P 328. 

635. 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. 

636. 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 

637. 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. 

638. 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. 

639. 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) 

640. 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. 

641. The NOPR did not propose to 

approve or remand EOP–007–0, because 

it applies only to regional reliability 

organizations. 

i. Comments 

642. 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. 

643. 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. 

644. 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 

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 

645. 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. 

646. 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

647. With regard to TANC’s request 

for regional flexibility in determining 

the appropriate mix of facilities needed 

to achieve the reliability objectives, it is 


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256The 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. 

257NOPR at P 329. 

258See Id. at P 336. 

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. 

648. 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. 

649. 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) 

650. 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. 

651. 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 

652. In the NOPR, the Commission 

proposed to approve Reliability 

Standard EOP–008–0 as mandatory and 

enforceable. In addition, pursuant to 

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

§ 39.5(f) of our regulations, 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 

653. 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. 

654. 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 

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. 

655. 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. 

656. In response to the request for 

comments on backup capabilities, NERC 

states that these are best addressed 

through the Reliability Standards 

development process. 

657. SoCal Edison suggests that a riskbased 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. 

658. 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. 

659. 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. 

(b) Commission Determination 

660. 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.’’

661. 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 


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should correspond to the time it would 

take to replace the primary control 

center. 

662. 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. 

663. 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. 

664. 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, 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 

665. 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 

666. 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. 

667. 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. 

668. 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 control 

center would not have a substantial 

impact on the reliability of the BulkPower 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. 

669. 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 centrallylocated 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. 

670. Nevada Companies also 

questions whether the significant cost of 

full replication could ever be costeffective, 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 

671. 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. 

672. 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 

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. 


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iii. Summary of Commission 

Determination 

673. 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) 

674. Proposed Reliability Standard 

EOP–009–0 deals with documentation 

of blackstart generating unit test results. 

In the NOPR, the Commission proposed 

to approve EOP–009–0 as mandatory 

and enforceable without modifications. 

i. Comments 

675. 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. 

ii. Commission Determination 

676. 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. 

677. 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 

678. 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 rightsof-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, 

FAC–011–0 and FAC–014–0. These 

Reliability Standards are being 

addressed in a separate docket. 

a. Facility Connection Requirements 

(FAC–001–0) 

679. 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 

680. APPA agrees with the 

Commission’s proposal to approve 

FAC–001–0 as mandatory and 

enforceable. 

ii. Commission Determination 

681. 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. 

b. Coordination of Plans for New 

Generation, Transmission, and End-User 

Facilities (FAC–002–0) 

682. 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. 

683. In the NOPR, the Commission 

proposed to approve Reliability 

Standard FAC–002–0 as mandatory and 

enforceable. In addition, pursuant to 

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

§ 39.5(f) of our regulations, the 

Commission 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 

684. 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. 

685. 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. 

686. 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 the tasks outlined 

in this Reliability Standard and that 

these two entities provide only certain 


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16486 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

259FAC–002–0. 

260Standards 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). 261NOPR at P 352. 

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. 

687. 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 enduser facilities includes modeling of 

normal system and contingency 

conditions. 

(b) Commission Determination 

688. 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. 

689. 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 

Reliability Standards, then it should 

follow those procedures, it should not 

be concerned about violating the 

Reliability Standard. 

ii. Standards of Conduct 

(a) Comments 

690. Xcel and MidAmerican believe 

that the assessment required under this 

Reliability Standard may conflict with 

the Commission’s Standards of 

Conduct 260 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 

691. 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 

692. 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 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 enduser 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 

693. 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 TPL–

003–0. 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. 

694. 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. 


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262FAC–003–1 (Requirement R1.2.2). 

263An IROL-related facility is a facility whose 

outage would result in an Interconnection 

Reliability Operating Limit (IROL) violation. 

Further, the Commission also directs the 

ERO to consider the above commenters’

concerns through the Reliability 

Standards development process. 

c. Transmission Vegetation Management 

Program (FAC–003–1) 

695. 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. 

696. 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

697. In the NOPR, the Commission 

proposed to approve Reliability 

Standard FAC–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 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 

698. 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 by the ERO, as 

supported by reliability studies using 

consistent reliability contingency 

criteria. 

699. LPPC supports using an impactbased 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 BulkPower System. 

700. 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. 

701. 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 

facilities 263 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. 

702. 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. 

703. 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 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 lower-voltage facilities that 

previously were not subject to this 

Reliability Standard. 

704. EEI maintains that not changing 

this Reliability Standard would best 

maintain reliability, since removing the 

existing 200 kV threshold requirement 

could inadvertently expose the BulkPower 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.’’

705. 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. 

706. 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 BulkPower System. NERC notes that the 

current applicability of the Reliability 


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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 

707. 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 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 lower-voltage 

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. 

708. 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. 

709. 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. 

710. 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 lowervoltage 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. 

711. 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. 

712. 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 

713. 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 

714. 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. 

715. 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 

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. 

716. 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 


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264Utility Vegetation Management and Bulk 

Electric Reliability Report at 10–11, available at 

http://www.ferc.gov/industries/electric/indus-act/ 

reliability/2004.asp (Vegetation Management 

Report). 

265See, e.g., EEI, Energy, International 

Transmission, Progress Energy, SERC, LPPC and 

MISO. 

266The 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. 

267Forest Service, Bureau of Land Management, 

Fish & Wildlife Service, National Park Service, and 

U.S. Environmental Protection Agency. 

could result in a transmission owner 

complying with the Reliability Standard 

while not adequately protecting the 

reliability of that region’s transmission 

system. 

717. 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. 

718. 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. 

719. 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. 

(b) Commission Determination 

720. 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. 

721. 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

722. 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 

723. 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. 

(a) Comments 

724. APPA believes that a case-bycase 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.’’

725. 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. 

726. Progress Energy and SERC note 

that EEI and certain federal agencies 267

have jointly addressed the issue of 

consistency in vegetation management 

work on federal lands, and developed a 

memorandum of understanding 

(Vegetation MOU) which sets the 

framework for managing vegetation on 

transmission line rights-of-way under 


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268The Vegetation MOU is available at http:// 

www.eei.org/industry_issues/environment/land/ 

vegetation_management/EEI_MOU_FINAL_5-25- 

06.pdf. 

269Controlled environments and operating 

conditions include clear days without precipitation, 

high winds or lightning. 270 Institute of Electrical and Electronics 

Engineers, Inc. (IEEE) Standard 516–2003, IEEE 

Guide for Maintenance Methods at 20. 271ANSI Z133, American National Standards 

Institute Standard for Tree Care Operations—

Pruning, Trimming, Repairing, Maintaining and 

Removing Trees, and Cutting Brush—Safety 

Requirements. 

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. 

727. 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-to-line contact 

occurring within national/state forestry 

boundaries or on private property. 

728. 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. 

729. 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-of-way 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 rightof-way. 

(b) Commission Determination 

730. As proposed in the NOPR, the 

Commission approves Reliability 

Standard FAC–003–1 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 

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. 

731. 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 rightof-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. 

732. 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 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

733. 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 caseby-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. 

734. 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 


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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. 

735. FirstEnergy suggests that rightsof-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 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 

736. 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 caseby-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) 

737. 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. 

738. In the NOPR, the Commission 

proposed to approve Reliability 

Standard FAC–008–1 as mandatory and 

enforceable. In addition, pursuant to 

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

§ 39.5(f) of our regulations, the 

Commission 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 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 

739. 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 

740. 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 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 

741. 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 


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272NOPR at P 404. 

line ratings, although the changes are 

not expected to be substantial. 

742. 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. 

(b) Commission Determination 

743. 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 

744. 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. 

745. 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 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. 

746. 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. 

747. 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. 

748. 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 Bulk-Power 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 


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273An element is made up of one or more 

components. 274 16 U.S.C. 824o(a)(4). 

proceeding and could jeopardize, rather 

than further, reliable transmission 

system operations. 

749. 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. 

750. 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. 

751. 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. 

752. 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. 

753. 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. 

754. 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. 

755. 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 

756. 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. 

757. 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 

Element 273 (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. 

758. 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 component of each facility to be 

identified in order to understand what 

components are 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. 

759. 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 BulkPower 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. 

760. In response to Dominion’s 

comments, if the PJM Regional 

Transmission Expansion Planning 

process meets the criteria, there is no 


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16494 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

275Blackout Report at 162. 

need to exclude facilities covered by 

that process from this requirement. 

761. 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. 

762. 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. 

763. 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 

764. 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 MOD–025–

1. 

765. 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 

766. 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. 

v. Compliance With Blackout Report 

Recommendation No. 27 

(a) Comments 

767. 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. 

768. 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 

769. 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. 

vi. General Comments 

770. APPA notes that FAC–008–1 

should be revised to replace Levels of 

Non-Compliance with Violation 

Security Levels, and to include 

Violation Risk Factors on all FAC–008–

1 requirements. 

(a) Commission Determination 

771. 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 

772. 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. 


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Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 16495 

e. Establish and Communicate Facility 

Ratings (FAC–009–1) 

773. 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 

774. APPA supports approval of FAC–

009–1 as a mandatory and enforceable 

Reliability Standard. 

ii. Commission Determination 

775. FAC–009–1 serves an important 

reliability purpose of ensuring that 

facility ratings are determined based on 

an established methodology. Further, 

the proposed Requirements set forth in 

FAC–009–1 are sufficiently clear and 

objective to provide guidance for 

compliance. Accordingly, the 

Commission approves Reliability 

Standard FAC–009–1 as mandatory and 

enforceable. 

f. Transfer Capability Methodology 

(FAC–012–1) 

776. Proposed Reliability Standard 

FAC–012–1 requires each reliability 

coordinator and planning authority to 

document the methodology used to 

develop its inter-regional and intraregional transfer capabilities. This 

methodology must describe how it 

addresses transmission topology, system 

demand, generation dispatch and use of 

projected and existing commitment of 

transmission. 

777. 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. 

778. 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 

779. 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 

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 

780. 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 

781. 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. 

782. 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 Web site. 

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. 

(b) Commission Determination 

783. 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 


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16496 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

276See supra P 780. 

277Order No. 890 at P 196. 

criteria used for other users of the BulkPower 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. 

784. 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 (FAC–013–1) 

785. 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. 

786. In the NOPR, the Commission 

proposed to approve Reliability 

Standard FAC–013–1 as mandatory and 

enforceable. In addition, pursuant to 

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

§ 39.5(f) of our regulations, the 

Commission 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 

787. 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 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. 

788. 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. 

789. 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. 

790. 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 

791. 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. 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. 

792. 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

793. 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. 

794. 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

795. 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 FAC–013–1 through 

the Reliability Standards development 

process that makes it applicable to 

reliability coordinators. 


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Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 16497 

278The NERC glossary defines ‘‘interchange’’ as 

‘‘Energy transfers that cross Balancing Authority 

boundaries.’’ NERC Glossary at 9. 

279The 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. 

280Currently, the reliability analysis service used 

by NERC is the Interchange Distribution Calculator. 

281This Requirement was included in INT–001–

0 as Requirement R1.2. 

6. INT: Interchange Scheduling and 

Coordination 

796. 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 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 

797. 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 Bulk-Power System required to 

comply with mandatory Reliability 

Standards. 

i. Comments 

798. 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. 

799. 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. 

800. 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. 

801. 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 

802. 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. 

803. 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) 

804. 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 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. 

805. 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

806. 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 eTagging requirements as part of its 


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282The 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. 

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. 

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. 

807. 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 NonCompliance 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 

808. 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 Non-Compliance 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 authority area, it 

does not understand the Commission’s 

reliability concerns in this connection. 

809. 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 Bulk-Power System reliability, 

but also a reduction of undue 

discrimination in transmission services. 

810. 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.’’

811. 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. 

812. 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. 

813. 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 

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. 

814. 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 

815. 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. 

816. 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. 

817. 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. 

818. 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. 

819. 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-topoint transactions within the PJM 

market are consistent with the proposed 

INT Reliability Standards. 

820. 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 


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284The Requirement was included in INT–001–0 

as Requirement R1.2. 

285To date, the Commission has not received the 

requested information. 286Order No. 672 at P 290. 

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. 

821. 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. 

822. 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-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 

823. 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 

824. APPA agrees with the 

Commission’s proposed course of action 

addressing this regional difference. 

825. 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 

826. 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 

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 

827. 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 

828. APPA agrees with Commission’s 

proposed course of action in approving 

this regional difference. 

ii. Commission Determination 

829. 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 Commissionapproved, 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 statutory 

standard for approval of a Reliability 

Standard, and therefore approves it as 

mandatory and enforceable. 

e. Interchange Transaction 

Implementation (INT–003–2) 

830. 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. 


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287NERC proposed three regional differences for 

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

proposed regional difference was addressed in 

Reliability Standard INT–001–1. The remaining two 

are discussed here. 

831. The Commission proposed in the 

NOPR to approve Reliability Standard 

INT–003–1 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. 

832. 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 

833. APPA states that INT–003–2 

fulfills the Commission’s proposed 

directive to include Measures and 

Levels of Non-Compliance. 

ii. Commission Determination 

834. 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. 

f. Regional Differences to INT–003–2: 

MISO/SPP Scheduling Agent and MISO 

Enhanced Scheduling Agent 

835. 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, 

which creates a variance from INT–003–

1 for MISO that permits an enhanced 

single point of contact scheduling agent. 

836. 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 multicontrol 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 

837. APPA agrees with the 

Commission’s proposed approval of 

these regional differences. 

838. 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. 

ii. Commission Determination 

839. 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. 

840. 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 (INT–004–1) 

841. 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. 

842. 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 

843. 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 

844. 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 

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 

Non-Compliance to the Reliability 

Standard. 

h. Interchange Authority Distributes 

Arranged Interchange (INT–005–1) 

845. 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. 

846. 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 BulkPower System that is required to comply 

with mandatory Reliability Standards. 


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i. Comments 

847. 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 

848. 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. 

849. 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. 

i. Response to Interchange Authority 

(INT–006–1) 

850. 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. 

851. 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 widearea 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 

852. 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. 

853. 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. 

854. 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 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. 

855. 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 INT–

005 through INT–009. 

856. 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. 

857. 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. 

858. 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. 

859. 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 

Commission-proposed 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. 

ii. Commission Determination 

860. 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. 

861. 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 


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288NOPR at P 219. 

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. 

862. 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. 

863. 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 implementation.288

While we did not require a specific 

notification time prior to actual 

transactions, this proactive approach 

should promote system reliability. 

864. 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. 

865. 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 widearea 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. 

866. 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. 

867. 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 widearea 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. 

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) 

868. 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 

869. 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 

870. 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 (INT–008–1) 

871. 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 

872. APPA agrees with the 

Commission that INT–008–1 is 

sufficient for approval as a mandatory 

and enforceable Reliability Standard, 


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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 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 

873. 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) 

874. 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 

875. 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 

876. 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. 

m. Interchange Exemptions (INT–010–1) 

877. 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. 

878. 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 reliabilityrelated 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. 

879. The Commission proposed to 

approve INT–010–1, interpreted as set 

forth above, as mandatory and 

enforceable. 

i. Comments 

880. 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. 

881. 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 NonCompliance, should be edited to state 

that ‘‘[t]here shall be a level four noncompliance * * *.‘‘ instead of ‘‘[t]here 

shall be a level three non-compliance 

* * *.’’

882. 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 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. 

883. 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. 

884. 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, 


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289According 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 * * *.’’

290 IRO–001–1 supercedes the Version 0 

Reliability Standard. In this Final Rule, we review 

the November version, IRO–001–1. 

consistent with Commission 

expectations. 

ii. Commission Determination 

885. For the reasons and 

interpretation noted in the NOPR, the 

Commission approves INT–010–1 as 

mandatory and enforceable. 

886. 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- 

minute 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. 

887. 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. 

888. 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 

889. 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 widearea 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. 

a. Reliability Coordination—

Responsibilities and Authorities (IRO–

001–1) 

890. 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. 

891. In November 2006, NERC 

submitted IRO–001–1, which includes 

Measures and Levels of NonCompliance.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 purchasingselling 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 purchasingselling entities ‘‘shall comply with 

Reliability Coordinator directives unless 

such actions would violate safety, 

equipment, or regulatory or statutory 

requirements.’’

892. 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 

893. 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. 

894. 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. 

895. Requirement R3 provides that a 

reliability coordinator ‘‘shall have clear 

decision-making 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.’’

896. 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. 


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291Requirement 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. 

292See 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. 294See Order No. 672 at P 329. 

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 

897. 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 R1 291 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 the NERC 

Rules of Procedures and eliminate the 

regional reliability organization as an 

applicable entity.292

898. 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. 

899. 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) 

900. 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

901. 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. 

i. Comments 

902. 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 IRO–002–1 is 

appropriate since it will ensure that 

operators have a minimum set of tools 

with which to perform their duties. 

903. 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. 

904. 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 

905. 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 NonCompliance, it does not provide any 

specific suggestions for changes to 

NERC’s proposal. 

906. 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. 

907. 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 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

908. 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 


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295NOPR at P 511. 

296 In its November 15, 2006, filing, NERC 

submitted IRO–003–2, which supersedes 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. 297See NOPR at P 519. 

298California 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-themeter information, whether on generation or load.’’

299See NOPR at P 529. 

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. 

909. 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) 

910. The purpose of IRO–003–2 is for 

a reliability coordinator to have a widearea view of its own and adjacent areas 

to maintain situational awareness. 

Wide-area view also facilitates a 

reliability coordinator’s ability to 

calculate SOL and IROL as well as 

determine potential violations in its 

own area.296

911. 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 

912. 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.’’

913. 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 

914. 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. 

915. 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 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) 

916. 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. 

917. 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 

918. 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 NonCompliance, and the ERO and Regional 

Entities should not assess penalties 

until additional Measures and Levels of 

Non-Compliance are developed. 

919. 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. 

920. 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 dayahead schedules. 

921. FirstEnergy contends that IRO–

004–1 should require a day-ahead 

planning process and reflect activities 

inherent within a market operation. 

922. Northern Indiana contends that 

the Commission’s proposed directive is 

unclear. It asks whether the Commission 

is requiring the reliability coordinator to 

secure the 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. 

923. 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. 

924. 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 

925. For the reasons stated in the 

NOPR,299 the Commission approves 

proposed Reliability Standard IRO–004–

1 as mandatory and enforceable. In 


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Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 16507 

300 IRO–004–1 Purpose Statement states in part 

‘‘Plans must be developed to alleviate SOL and 

IROL violations.’’

301NOPR 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.’’) 

addition, the Commission directs the 

ERO to develop modifications to the 

Reliability Standard, as discussed 

below. 

926. 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. 

927. 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 

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. 

928. 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 reaffirmation prior to their removal from 

service or a short recall time subject to 

certain system conditions developing in 

real-time operations. 

929. We disagree with FirstEnergy 

that IRO–004–1 should include the dayahead 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. 

930. 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. 

931. 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 IROL-related 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. 

932. 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 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. 

933. 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. 

934. 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. 

935. 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. 

936. 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 (IRO–005–1) 

937. IRO–005–1 ensures energy 

balance and transmission reliability for 

the current day by identifying tasks that 

reliability coordinators must perform 

throughout the day. 

938. 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 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


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16508 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

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.’’

303NOPR 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. 

304The 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. 

i. Comments 

939. 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. 

940. MidAmerican supports the 

Commission’s proposed survey and 

notes that based on its experience, IROL 

violations have been faithfully reported 

across NERC. 

941. 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. 

942. 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. 

943. 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 IROL 

violations, but which have a low 

probability of occurrence and can be 

mitigated through other proven 

procedures. 

944. 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

945. 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 re-examine it. 

ii. Commission Determination 

946. 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. 

947. 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 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. 

948. 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. 

949. 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. 

950. 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. 

951. 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. 

952. Accordingly, the Commission 

approves Reliability Standard IRO–005–

1 as mandatory and enforceable. 


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Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 16509 

305The 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. 

306Blackout 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.’’

307The 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.’’

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 NonCompliance 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) 

953. 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. 

954. 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 NonCompliance 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 

955. 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 NonCompliance 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. 

956. 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. 

957. 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. 

958. 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. 

959. Entergy and MidAmerican 

believe that TLR procedures can be an 

effective mechanism to avoid potential 

SOL and IROL violations or potential 

emergency situations. 

960. In contrast, Progress Energy 

disagrees with the Commission’s 

reasoning on the ineffectiveness of using 

TLR procedures to alleviate actual IROL 

violations. 

ii. Commission Determination 

961. 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. 

962. 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. 

963. 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. 

964. We do not understand Progress 

Energy’s disagreement because no 

reason is provided. 

965. 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 

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 


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16510 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

308See NOPR at P 564–65. 

309NOPR at P 568. 

consistency with the standard form of 

the Reliability Standards including 

Requirements, Measures and Levels of 

Non-Compliance.308

g. Regional Difference to IRO–006–3: 

PJM/MISO/SPP Enhanced Congestion 

Management (Curtailment/Reload/ 

Reallocation) 

i. Background 

966. 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. 

967. 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. 

968. 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 nonmarket entities because the waiver 

subjects the RTOs to curtailment (and 

the corresponding redispatch costs) in 

circumstances where the non-market 

entities would not be subject to 

curtailment. 

969. In the NOPR, the Commission 

did not propose to approve or remand 

this regional difference. 

ii. Comments 

(a) Application of the Regional 

Difference 

970. 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 nondiscriminatory 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-toload impacts of non-market entities in 

the application of the TLR standard. 

971. 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 

972. Several entities argue that the 

Commission should not overturn the 

existing IRO–006–3 regional difference. 

MidAmerican states that MISO and PJM 

should continue to pursue a negotiated 

solution to the issues outlined in MISO–

PJM’s filings. Mid-Continent 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. 

973. Mid-Continent asks the 

Commission to not implement MISO 

and PJM’s proposal to modify NERC’s 

procedures and 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 giveand-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 

MISO–PJM 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. MidContinent 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. 

974. 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 

975. 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 


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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. 

976. 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 

‘‘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. 

977. 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. 

978. MISO–PJM also states that 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 Seams 

Operating Agreement. MISO and PJM do 

not believe they can address the equity 

issue by continuing discussions with 

the NERC Operating Subcommittee. 

979. 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 counterflow 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. 

980. 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.’’ MISO–

PJM 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 MidContinent 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. 

981. 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. 

(d) Reporting of Generator to Load 

Impacts by Non Market Areas 

982. 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-toload 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 non-market 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. 

983. MISO–PJM states that the 

reporting of generator-to-load impacts 

by the non-market entities is the one 

area that is not currently under 


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310See 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). 

311Commonwealth 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. 

312See Midwest Independent Transmission 

System Operator, Inc., 108 FERC ¶ 61,163 (2004). 

313To resolve this issue, the Commission 

encouraged market participants to use the PJMMidwest 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. 

314See Midwest Independent Transmission 

System Operator, Inc., 110 FERC ¶ 61,290 (2005). 

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 generator-toload 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. 

984. 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. 

985. 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 treat 

MISO–PJM market flows differently 

because they are greater than the system 

flows that resulted from control areabased 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 

986. 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 contends 

that 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. 

987. 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 

988. 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 nonmarket 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 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-nonmarket seams 313 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

989. The Commission recognizes 

MISO–PJM’s concerns that: (1) The 

congestion management 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 nonmarket control areas are consolidated, 

this can have an effect on the loop flows 

experienced by 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. 


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315See 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). 

316 IRO–016–1 Level of Non-Compliance 2.1 

states: ‘‘For potential, actual or expected events 

which required Reliability Coordinator-toReliability Coordinator coordination, the Reliability 

Coordinator did coordinate, but did not have 

evidence that it coordinated with other Reliability 

Coordinators.’’

317MOD–001–0 through MOD–009–0. 

318MOD–010–0 through MOD–015–0. 

990. 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. 

991. The Commission instructs the 

RTOs to continue working with the nonmarket 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. 

992. The Commission will not adopt 

MISO–PJM’s proposal to require nonmarket entities to report their generatorto-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-bycase basis or, as appropriate, in the 

proceeding on RTO Border Utility 

Issues.315

993. 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) 

994. 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. 

995. In the NOPR, the Commission 

proposed to approve IRO–014–1 as 

mandatory and enforceable. 

i. Comments 

996. APPA agrees with the 

Commission’s proposed approval of 

IRO–014–1 as mandatory and 

enforceable. 

ii. Commission Determination 

997. 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) 

998. 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. 

999. In the NOPR, the Commission 

proposed to approve IRO–015–1 as 

mandatory and enforceable. 

i. Comments 

1000. APPA agrees with the 

Commission’s proposed approval of 

IRO–015–1 as mandatory and 

enforceable. 

ii. Commission Determination 

1001. 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) 

1002. 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. 

1003. In the NOPR, the Commission 

proposed to approve IRO–016–1 as 

mandatory and enforceable. 

i. Comments 

1004. 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 Non-Compliance 

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 

1005. For the reasons stated in the 

NOPR, the Commission approves IRO–

016–1 as mandatory and enforceable. 

1006. We construe Level of NonCompliance 2.1 as requiring evidence of 

coordination, but allowing flexibility on 

the type of evidence. 

8. MOD: Modeling, Data, and Analysis 

1007. The Modeling, Data and 

Analysis group of Reliability Standards 

is intended to standardize 

methodologies and system data needed 

for traditional transmission system 

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 


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319MOD–016–0 through MOD–021–0. 

320MOD–024–1 through MOD–025–1. 

321Approved: 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. 

322See Common Issues Pertaining to Reliability 

Standards: Fill-in-the-Blank Standards, supra 

section II.E.5. 

323OATT Reform Final Rule, Order No. 890, 

issued February 15, 2007. 324FPA section 215(d)(5). 

covers actual and forecast demand 

data.319 The fourth category covers 

verification of generator real and 

reactive power capability.320

1008. 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 

1009. 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-inthe-blank Reliability Standards until 

those 13 are approved unconditionally. 

ISO/RTO Council and ISO–NE believe 

that the following Reliability Standards 

are dependent upon the 13 fill-in-theblank 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. 

1010. 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-theblank 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 

1011. 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. 

1012. 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-in-the-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. 

1013. In response to EPSA’s concern 

that opportunities for discrimination 

and concerns about reliability remain 

while we await additional information, 

we emphasize that the 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 

1014. 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. 

1015. 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, industry-wide 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

1016. 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 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 


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325The 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: fttp://www.nerc.com/pub/sys/all_updl/ 

mc/ltatf/LTATF_Final_Report_Revised.pdf. 

326The 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. 

327Technical Conference regarding Preventing 

Undue Discrimination and Preference in 

Transmission Service under RM05–25 et al. 

(October 12, 2006). 

328That 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. 

task, within 90 days of publication of 

Order No. 890 in the Federal Register. 

1017. 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–001–1, proposing ATC/ 

TTC/AFC (Available Flowgate 

Capability) revisions, on its Web site on 

February 15, 2007.328

(a) Comments 

1018. 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. 

1019. 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. 

1020. 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. 

(b) Commission Determination 

1021. 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. 

1022. 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 Commission-initiated 

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. 

1023. 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) 

1024. 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 its TTC and ATC 

methodologies on a Web site accessible 

by NERC, the regional reliability 

organization, and transmission users. 

1025. In the NOPR, the Commission 

identified MOD–001–0 as a fill-in-theVerDate Aug<31>2005 18:02 Apr 03, 2007 Jkt 211001 PO 00000 Frm 00101 Fmt 4701 Sfmt 4700 E:\FR\FM\04APR2.SGM 04APR2

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329NOPR 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, MOD–024–0 and MOD–025–0. 

331October 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. 

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. 

1026. 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 BulkPower 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 

1027. APPA agrees with the 

Commission that MOD–001–0 in its 

current form is a fill-in-the-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. 

ii. Commission Determination 

1028. 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 

1029. 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 

1030. 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. 

1031. The Commission understands 

that the ERO currently is developing 

three ATC calculation methodologies 

(contract or rating path ATC, network 

ATC, and network 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. 

1032. 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. 

1033. 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 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 


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332TRM also includes such things as loop flow 

and parallel path flow. 

333The 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. 334NOPR at P 169. 

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-topoint reservations; (4) rollover rights 

associated with long-term 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 shortterm ATC calculation, all reserved but 

unused transfer capability (nonscheduled) must be released as non-firm 

ATC. 

1034. 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. 

1035. 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 industrywide 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 MOD–001–0 Reliability 

Standards apply, i.e., users, owners and 

operators of the Bulk-Power System. 

iv. Require Disclosure of Algorithms 

and Processes Used in ATC Calculation 

(a) Comments 

1036. 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 

1037. 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. 

v. Identify a Detailed List of Information 

To Be Exchanged Among Transmission 

Providers for the Purposes of ATC 

Modeling 

(a) Comments 

1038. 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 

1039. 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 

1040. 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; (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 


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335FAC–010, FAC–011, and FAC–014 are 

addressed in Docket No. RM07–03 because they 

were submitted later than the original 107 

transmission provider operates and 

plans its system to serve native load, 

and the manner in which it calculates 

ATC for service to third parties. 

1041. 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 (peakand 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. 

1042. 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. 

1043. 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. 

1044. 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, 

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. 

1045. In conclusion, we direct the 

ERO to modify MOD–001–0 to require 

that: (1) Assumptions used for shortterm ATC calculations be consistent 

with those used for operation planning 

to the maximum extent practicable; (2) 

assumptions used for long-term 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 

1046. 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 

1047. 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. 

1048. 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 non-firm ATC for various 

time frames such as: (1) The scheduling 

horizon (same day and real-time), (2) 

operating horizon (day ahead and preschedule) 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. 

viii. Address Only ATC While TTC 

Should Be Addressed Under 

FAC–012–1 

(a) Comments 

1049. 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. 

1050. 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 BulkElectric 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 

1051. 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


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Reliability Standards and we did not have sufficient 

time to allow appropriate review and comment. 

336For example, WECC has a documented open 

process for establishing TTC for the Western 

Interconnection. 

337Transfer 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. 

338Total 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. 339NOPR at P 610. 

1052. The Commission directs the 

ERO, through the Reliability Standards 

development process, to modify FAC–

012–1 and any other appropriate 

Reliability Standards to assure 

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. 

1053. 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, 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 

1054. 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 BulkPower 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). 

1055. 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. 

(b) Commission Determination 

1056. 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 Commissionapproved 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. 

1057. 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 

1058. 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, 


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340The 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. 

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. 

d. Review of Transmission Service 

Provider Total Transfer Capability and 

Available Transfer Capability 

Calculations and Results (MOD–002–0) 

1059. 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. 

1060. In the NOPR, the Commission 

identified MOD–002–0 as a fill-in-theblank 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 MOD–002–0 until 

the ERO submits additional information. 

i. Comments 

1061. 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 

1062. 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. 

e. Regional Procedure for Input on Total 

Transfer Capability and Available 

Transfer Capability Methodologies and 

Values (MOD–003–0) 

1063. 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 

Web site. 

1064. In the NOPR, the Commission 

identified MOD–003–0 as a fill-in-theblank 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 

1065. 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 

1066. 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. 

1067. 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) 

1068. MOD–004–0 requires each 

regional reliability organization to: (1) 

Develop and document a regional 

CBM 340 methodology in conjunction 

with its members and (2) post the most 

recent version of its CBM methodology 

on a Web site accessible by NERC, 

regional reliability organizations and 

transmission users. 

1069. In the NOPR, the Commission 

identified MOD–004–0 as a fill-in-theblank 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 


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341APPA 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. 

342NERC, 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). 

343 Documented by NERC’s April 14, 2005 LongTerm AFC/ATC Task Force Final Report. 344TAPS refers the Commission to its August 7, 

2006 comments in Docket No. RM05–25–000 at 21–

24. 

approve or remand MOD–004–0 until 

the ERO submits the additional 

information. 

1070. 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. 

i. Comments 

1071. 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

1072. 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. 

1073. 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. 

1074. 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 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. 

1075. EEI agrees with the 

Commission’s concern about doublecounting 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 double-counting would 

be inappropriate, although 

MidAmerican states that it is not aware 

of any cases of double-counting of 

margins. 

1076. TAPS notes the significant 

potential for abuse 343 that could result 

from the current flexibility afforded 

transmission providers in the 

calculation of CBM and TRM, and 

proposes innovative approaches 344 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 

1077. 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 ‘‘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. 

1078. 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 


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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. 

1079. 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 MOD–004–0 that addresses 

the methods for CBM determination and 

allocation on paths that will reduce 

reliability and discrimination concerns. 

1080. 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 

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. 

1081. 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 Non-Compliance. We direct 

the ERO to modify the Reliability 

Standard accordingly. 

1082. 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. 

1083. 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 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. 

1084. 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) 

1085. 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. 

1086. In the NOPR, the Commission 

identified MOD–005–0 as a fill-in-theblank 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 

1087. 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 

1088. 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, 


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345NOPR at P 642. 

346 Id. at P 642, 648. 

347 Id. at P 647–48. 

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–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. 

1089. As to APPA’s comment on 

incorporating MOD–004 and MOD–005 

into MOD–006, 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) 

1090. 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 Web 

site accessible by the regional reliability 

organization, NERC and transmission 

users. 

1091. In the NOPR, the Commission 

proposed to approve Reliability 

Standard MOD–006–0 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. 

1092. 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 

1093. APPA supports the 

Commission’s proposal to approve 

MOD–006–0. Moreover, APPA agrees 

with the Commission’s proposed 

directives 345 that the standard should 

address the use of CBM and TRM for the 

same purpose. However, APPA believes 

that 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. 

1094. 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. 

1095. 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 reasonably-forecasted 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. 

1096. 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 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. 

1097. 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 MOD–007–0 to include such LSEs in 

the NOPR 347 seems bizarre. 

ii. Commission Determination 

1098. 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. 

1099. 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 


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348See NERC Glossary at 2. 

349TOP–002–2. 

350TPL–002–0. 

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 doublecounting. Such double-counting 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. 

1100. 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 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. 

1101. 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. 

1102. We also reiterate the direction 

in Order No. 890 that CBM should have 

a zero value in the calculation of nonfirm 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. 

1103. 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 believe that if 

there are enough resources to meet 

generation reliability criteria within the 

balancing authority, there is no need to 

request CBM. 

1104. 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. 

1105. 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. 

1106. 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) 

1107. MOD–007–0 requires 

transmission service providers that use 

CBM to report and post its use. 

1108. In the NOPR, the Commission 

proposed to approve Reliability 

Standard MOD–007–0 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. 

i. Comments 

1109. 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 

1110. 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 


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to modify the standard as discussed 

below. 

1111. 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. 

1112. 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. 

j. Documentation and Content of Each 

Regional Transmission Reliability 

Margin Methodology (MOD–008–0) 

1113. 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 Web site the most recent 

version of its TRM methodology. 

1114. In the NOPR, the Commission 

identified MOD–008–0 as a fill-in-theblank 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. 

1115. 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 

1116. 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. 

1117. 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. 

1118. In response to the Commission’s 

request for comments on the current 

calculation of TRM, and recommended 

approaches for the future, International 

Transmission 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. 

1119. MidAmerican responds with a 

discussion of its current approach to 

TRM calculation, which has been 

performed in accordance with MAPPapproved 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. 

1120. 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. 

1121. 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. 

ii. Commission Determination 

1122. 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. 

1123. 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 


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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. 

1124. 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. 

1125. 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. 

1126. 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. 

1127. 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. Procedure for Verifying Transmission 

Reliability Margin Values (MOD–009–0) 

1128. 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. 

1129. In the NOPR, the Commission 

identified MOD–009–0 as a fill-in-theblank 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 

1130. 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. 

ii. Commission Determination 

1131. 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) 

1132. 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. 

1133. In the NOPR, the Commission 

proposed to approve Reliability 

Standard MOD–010–0 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 

1134. 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. 

1135. ISO/RTO Council and ISO–NE 

do not support adoption of this standard 

because its requirements refer several 


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351MidAmerican further cautions that other 

contingencies exist that must be studied under stilldifferent 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. 352NOPR at P 663. 

times to the data requirements and 

reporting procedures specified in MOD–

011–0, which has been identified by the 

Commission as a fill-in the-blank 

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 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. 

1136. Constellation strongly supports 

the Commission’s proposals with 

respect to MOD–010–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. 

1137. 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. 

1138. 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. 

1139. 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, N–2, as well as 

multiple contingencies. 

1140. 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 

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. 

1141. 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-themeter operations, the provision of 

which should be seriously limited, and 

data on future interchange schedules, 

the confidentiality of which should be 

maintained. 

1142. 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. 

1143. 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. 

1144. 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. 

1145. 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 


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16528 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

concerns and to develop a consensus 

standard using its Reliability Standard 

development process. 

1146. 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. 

ii. Commission Determination 

1147. The Commission approves 

MOD–010–0. In addition, the 

Commission requires the ERO to modify 

MOD–010–0 as described below. 

1148. 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 steady-state 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. 

1149. 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. 

1150. 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 (N–1, 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. 

1151. 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 

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. 

1152. 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. 

1153. Consistent with California 

Cogeneration, Northern Indiana and 

MidAmerican’s concerns, we determine 

that those data that a company 

considers confidential, commerciallysensitive 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. 

1154. 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. 

1155. 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. 

1156. 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. 

1157. 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. 


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m. Maintenance and Distribution of 

Steady-State Data Requirements and 

Reporting Procedures (MOD–011–0) 

1158. 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. 

1159. In the NOPR, the Commission 

identified MOD–011–0 as a fill-in-theblank 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 

1160. APPA agrees with the 

Commission that this standard is a fillin-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. 

1161. TANC supports replacing the 

term regional reliability organization 

with an entity from the NERC 

Functional Model. 

ii. Commission Determination 

1162. 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. 

1163. 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. 

1164. 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. 

1165. 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 MOD–

011–0 satisfies the statutory requirement 

that a proposed Reliability Standard be 

‘‘just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest.’’ 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) 

1166. 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. 

1167. In the NOPR, the Commission 

proposed to approve Reliability 

Standard MOD–012–0 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 

1168. 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. 

1169. 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 fillin-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. 

1170. 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. 

1171. 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. 

However, MidAmerican warns that a 

list of faults and disturbances could be 


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16530 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

353MidAmerican 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. 

used in a ‘‘cook-book’’ manner to reach 

the wrong conclusions.353

1172. 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. 

1173. 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. 

1174. 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. 

1175. 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 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. 

1176. 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 

1177. The Commission approves 

MOD–012–0 as mandatory and 

enforceable. The Commission directs 

the ERO to modify MOD–012–0 as 

discussed below. 

1178. 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. 

1179. 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. 

1180. In response to MidAmerican’s 

concern that fault and disturbance 

information could be used as a ‘‘cookbook,’’ our expectation is that utility 

planners who use this data have 

sufficient experience to use it and 

interpret the results correctly. We 

expect that most utility planners are 

already familiar with their neighbors’

system topologies, and will be capable 

of identifying facilities on fault and 

disturbance lists. 

1181. 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. 

1182. Consistent with California 

Cogeneration, Northern Indiana and 

MidAmerican’s concerns, we determine 

that the data that a company considers 

confidential, market-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 

standard as necessary through its 

Reliability Standards development 

process. 

1183. 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. 

1184. 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 


ycherry on PROD1PC64 with RULES2
Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 16531 

354Requirement R1.1.1 allows for the use of 

estimated or typical manufacturer’s data on pre1990 units to model dynamic behavior when unitspecific data is unavailable. 

355EEI, LPPC, MidAmerican, Small Entities 

Forum and TVA. 

MOD–012–0 to require the transmission 

planner to provide fault and disturbance 

lists. 

1185. 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. 

1186. 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 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) 

1187. 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. 

1188. In the NOPR, the Commission 

identified MOD–013–1 as a fill-in-theblank 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. 

1189. 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 unrealistic simulations and 

inappropriate actions by responsible 

entities which may jeopardize the 

reliability of the Bulk-Power System. 

i. Comments 

1190. APPA agrees with the 

Commission that MOD–013–1 is a fillin-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. 

1191. 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. 

1192. 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 unitspecific 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. 

1193. 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 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. 

1194. 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-bycase 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 upto-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). 

1195. TANC agrees with the 

Commission that the standard 

requirement is arbitrary in imposing the 


ycherry on PROD1PC64 with RULES2
16532 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

356FERC Form 715 is available at http:// 

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

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 generally-accepted use of 

estimated or typical manufacturer data 

where unit-specific data is impractical 

to obtain. TVA agrees that the 1990 cutoff date is unnecessary. 

1196. 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 unitspecific information should be available 

for most units placed in service since 

1990. 

ii. Commission Determination 

1197. 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. 

1198. 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 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. 

1199. 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. 

1200. 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. 

1201. 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 MOD–

013–1 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) 

1202. MOD–014–0 requires the 

regional reliability organizations within 

each Interconnection to coordinate and 

jointly develop and maintain a library of 

solved Interconnection-specific steadystate models. These models are to 

include near- and long-term planning 

horizons representing system conditions 

for various demand levels. The models 

are to be updated annually. 

1203. In the NOPR, the Commission 

identified MOD–014–0 as a fill-in-theblank 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. 

1204. 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 MOD–

014–0. 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 

1205. APPA agrees with the 

Commission that MOD–014–0, a fill-inthe-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. 

1206. NRC suggests that a periodic 

verification against field data needs to 

be included in this Reliability Standard. 

1207. 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 

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. 


ycherry on PROD1PC64 with RULES2
Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 16533 

357Recommendation Number 24 of the Blackout 

Report at 160. 

1208. 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. 

1209. 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 

1210. 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. 

1211. 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 Report 357 and developing 

models for the Eastern Interconnection. 

1212. 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. 

1213. 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. 

1214. 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. 

1215. 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) 

1216. 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. These models 

represent near-term years and the years 

chosen from the longer-term planning 

horizon. 

1217. In the NOPR, the Commission 

identified MOD–015–0 as a fill-in-theblank 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 

1218. 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. 

1219. 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. 


ycherry on PROD1PC64 with RULES2
16534 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

358TPL–005–0, TPL–006–0, MOD–011–0, MOD–

013–0, MOD–014–0 and MOD–015–0. 

ii. Commission Determination 

1220. 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. 

1221. 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. 

1222. 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. 

1223. 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 MOD–015–0 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) 

1224. 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 load data, and controllable 

DSM data to be reported for system 

modeling and reliability analysis. 

1225. In the NOPR, the Commission 

proposed to approve Reliability 

Standard MOD–016–1 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 

1226. APPA agrees that MOD–016–1 

is sufficient for approval as a mandatory 

and enforceable reliability standard. 

1227. 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. 

1228. 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 standardssetting entity, should make the decision. 

1229. 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. 

1230. 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 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 

1231. 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. 

1232. 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. 

1233. Supported by many 

commenters, the Commission directs 


ycherry on PROD1PC64 with RULES2
Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 16535 

359Alcoa 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. 

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. 

1234. 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. 

1235. 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) 

1236. 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. 

1237. In the NOPR, the Commission 

proposed to approve Reliability 

Standard MOD–017–0 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 

1238. APPA agrees that the 

Commission should approve MOD–017–

0 as mandatory and enforceable. 

1239. 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. 

1240. 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. 

1241. 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

1242. 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. 

1243. 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. 

1244. 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, and the extent to which an 

explicit NERC process requirement 

could distract or confuse industry 

participants. 

1245. 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 


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16536 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

360Order No. 672 at P 329. 

361See Brattle Group Report on PJM Load 

Forecast Model, available at http://www.pjm.com/ 

planning/res-adequacy/load-forecast.html. 

362Form 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. 

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. 

1246. 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 

1247. 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. 

1248. 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. 

1249. 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. 

1250. 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. 

1251. 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. 

1252. 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. 

1253. 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. 

1254. 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. 

1255. 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. 

1256. 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. 

1257. 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. 

1258. 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; (2) reporting of accuracy, 


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363While 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. 

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) 

1259. 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. 

1260. In the NOPR, the Commission 

proposed to approve MOD–018–0 as 

mandatory and enforceable. 

i. Comments 

1261. APPA agrees that MOD–018–0 

is sufficient for approval as a mandatory 

and enforceable reliability standard. 

1262. 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. 

1263. 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 

1264. The Commission approves 

MOD–018–0 as mandatory and 

enforceable. 

1265. 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 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. 

1266. 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) 

1267. 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. 

1268. In the NOPR, the Commission 

proposed to approve Reliability 

Standard MOD–019–0 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 load 363 forecasts. 

i. Comments 

1269. 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. 

1270. 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 MOD–019–0 cannot 

be effectively implemented. 

1271. 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. 

1272. 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. 

1273. 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. 

1274. 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 percentagebased 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 


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16538 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

percentage deviations as compliance 

measures can produce discriminatory 

results, and has applied MW minimums 

to minimize the discrimination that 

would otherwise result. 

ii. Commission Determination 

1275. 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. 

1276. 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. 

1277. 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. 

1278. 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. 

1279. 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. 

1280. 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) 

1281. 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. 

1282. In the NOPR, the Commission 

proposed to approve Reliability 

Standard MOD–020–0 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 

1283. 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. 

1284. 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. 

1285. 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 regionspecific 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. 

1286. TAPS is concerned that the 

Commission’s recommendation in the 

NOPR may be interpreted to make 

forecast accuracy a component of 

Reliability Standards compliance. 


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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 

1287. 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. 

1288. 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 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. 

1289. 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. 

1290. 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) 

1291. 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. 

1292. In the NOPR, the Commission 

proposed to approve Reliability 

Standard MOD–021–0 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 

1293. APPA supports the 

Commission’s approval of MOD–021–0 

as mandatory and enforceable. 

1294. 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 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. 

1295. 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. 

1296. 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 

1297. 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. 

1298. 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. 

1299. 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 


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364Northern 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, 

temperature-driven 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 control to reach maximum net 

demonstrated capacity for the test. By taking units 

off automatic generator control, the generating 

owners’ regulating capabilities are lost. 

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. 

1300. 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. 

1301. The Commission directs the 

ERO to modify the title and purpose 

statement to remove the word 

‘‘controllable.’’ We note that no 

commenter disagrees. 

1302. 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) 

1303. 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. 

1304. In the NOPR, the Commission 

identified MOD–024–1 as a fill-in-theblank standard that requires the regional 

reliability organization to establish and 

maintain procedures to address 

verification of generator gross and net 

real power capability. The 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 

1305. 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. 

1306. 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. 

1307. 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 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. 

1308. 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 

1309. 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. 

1310. 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 


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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. 

1311. 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. 

1312. 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. 

1313. 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) 

1314. 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. 

1315. In the NOPR, the Commission 

identified MOD–025–1 as a fill-in-theblank 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 

1316. 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. 

1317. 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. 

1318. 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. 

1319. 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 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. 

1320. 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 

1321. 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, 


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365See Applicability Issues: Use of the NERC 

Functional Model, supra section II.C.4. 

we direct the ERO to develop a Work 

Plan as defined in the Common Issues 

section. 

1322. 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. 

1323. 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. 

1324. 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 

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 

1325. 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 (PER–001–0) 

1326. 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. 

1327. In the NOPR, the Commission 

proposed to approve PER–001–0 as 

mandatory and enforceable. 

i. Comments 

1328. APPA agrees that PER–001–0 is 

sufficient for approval as a mandatory 

and enforceable Reliability Standard. 

1329. 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 Bulk-Power 

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. 

ii. Commission Determination 

1330. 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

1331. 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) 

1332. 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. 

1333. 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. 

i. General Issues 

(a) Comments 

1334. 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 


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366NOPR at P 236–37. 

367 Id. at P 237, 779. 

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. 

1335. 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 

1336. 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 

1337. In the NOPR, the Commission 

noted that decisionmaking 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 

Standards, the NOPR indicated that the 

proposal would apply in the training 

and certification context, as well.367

(a) Comments 

1338. 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. 

1339. 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. 

1340. Northern Indiana states that it is 

not uncommon in the industry for 

employees who perform switching 

operations to be supervised by NERCcertified operators and that such 

employees are subject to round-theclock 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 BulkPower System reliability. SoCal Edison 

disagrees that the operators of these 

switching centers, simply because the 

switching center has SCADA capability, 

must be NERC-certified. 

1341. 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 real-time operations personnel 

should receive. 

1342. 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 

1343. 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. 

1344. 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 


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16544 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

368The Commission expects the entity registered 

as the transmission operator to ensure that these 

personnel are competent for the tasks that they 

perform. 

369See NOPR at P 773, 775. 

370 Id. at P 772. 

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. 

1345. 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 centrallylocated 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 centrallylocated 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

1346. 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. 

1347. 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. 

1348. The Commission disagrees with 

those commenters who contend that, 

because operators at local control 

centers take direction from NERCcertified 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 BulkPower System including protecting 

assets, protecting personnel safety, 

adhering to regulatory requirements and 

establishing stable islands during 

system restoration. 

1349. 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 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 

1350. 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 

1351. 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. 

1352. 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. 

1353. 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 BulkPower 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. 

1354. 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 


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371NOPR at P 771. 

372The Commission expects the entity registered 

as the generator operator to ensure that plant 

operators are competent for the tasks that they 

perform. 

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. 

1355. 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 NERCcertified. Dynegy and MISO support a 

more limited extension of these 

Reliability Standards to 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. 

1356. 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. 

1357. 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. 

1358. 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. 

1359. 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 

1360. 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 

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 BulkPower System. Thus, we direct the ERO 

to develop a modification to make PER–

002–0 applicable to generator operators. 

1361. 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 centrally-located 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

1362. 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. 

1363. 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 

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 


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373NOPR at P 780. 

developed in a Reliability Standard with 

continent-wide applicability. 

1364. 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. 

1365. 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. 

1366. 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. 

iv. Applicability to Operations Planning 

and Operations Support Staff 

1367. 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 

1368. 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. 

1369. 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. 

1370. 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 Bulk-Power 

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. 

1371. 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 

NERC-certified 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. 

1372. 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 

1373. 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 Bulk-Power 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. 

1374. 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 


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374 Id. at P 776. 375 Id. at P 775. 376 Id. at P 778. 

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. 

1375. 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 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. 

1376. 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 

1377. 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 

1378. 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. 

1379. 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 overlyprescriptive and deviates from a 

fundamental training concept that 

training should be tailored to the 

organization and to the individual. 

(b) Commission Conclusion 

1380. 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 

1381. 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 

1382. 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 

1383. 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 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 

1384. 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 

1385. While most commenters 

recognize the benefits of simulator 

training, they differ on whether 

simulator training should be mandatory. 

1386. 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 


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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. 

1387. 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 firsthand 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 full-scale 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. 

1388. 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. 

1389. 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 table-top 

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. 

1390. 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 

1391. 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 fullscale simulators and take these concerns 

into consideration. The Commission 

finds that significant reliability benefits 

may be derived from requiring simulator 

training for reliability coordinators, 

transmission operators and balancing 

authorities that have operational control 

over a significant portion of load and 

generation. 

1392. This does not mean that these 

entities must develop and maintain fullscale 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 

1393. 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. 

1394. 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. 

1395. 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. 


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Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 16549 

c. Operating Personnel Credentials 

(PER–003–0) 

1396. 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. 

1397. 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 

1398. 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. 

1399. 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 NERC-approved annual 

certification tests. MidAmerican 

believes that applicable tests should be 

tailored to specific job duties to ensure 

effectiveness and Reliability Standard 

compliance. 

1400. 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 PJM-certified 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. 

1401. 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. 

1402. 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 BulkPower System reliability. It also states 

that it is not clear whether ‘‘generator 

operator’’ means plant operator or the 

transmission operator responsible for 

generation. 

1403. Northern Indiana and SoCal 

Edison oppose a certification 

requirement for all real-time operating 

positions in a transmission control 

center that performs switching 

operations via SCADA for the BulkPower 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. 

1404. 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. 

1405. 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. 

1406. 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 


ycherry on PROD1PC64 with RULES2
16550 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

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. 

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. 

1407. 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. 

ii. Commission Determination 

1408. 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 NERC-certified 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 long-tenured 

operators. Personnel that are subject to 

such grandfathering still must comply 

with applicable training requirements 

pursuant to PER–002–0. 

1409. 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. 

1410. 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) 

1411. 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 

certified individuals.377 Further, 

reliability coordinator operating 

personnel must have a comprehensive 

understanding of the area of the BulkPower System for which they are 

responsible. 

1412. 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 

Measures and Levels of NonCompliance that address staffing 

requirements and the requirement for 

five days of emergency training. 

i. Comments 

1413. 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 Non-Compliance. It states 

that NERC should be directed to include 

Measures and Levels of NonCompliance related to all Requirements. 

1414. 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. 

1415. 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 

1416. No comments were received on 

the proposed modifications to include 

formal training requirements for 

reliability coordinators similar to those 

addressed under the 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. 

1417. 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. 

1418. We find that the Reliability 

Standard adequately addresses 

reliability coordinator staffing. 

Accordingly, the Commission approves 

Reliability Standard PER–004–1. In 


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Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 16551 

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. 

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 

1419. 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. 

a. System Protection Coordination 

(PRC–001–1) 

1420. PRC–001–1 378 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. 

1421. 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 BulkPower 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 

1422. While Constellation supports 

the Commission’s proposed directives 

because they represent additional steps 

to achieving reliability of the BulkPower 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. 

1423. With regard to the NOPR’s 

direction to the ERO to include 

Measures and Levels of NonCompliance, 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-existent 

Requirement R8.1. Similarly, rather than 

referencing Requirement R5.2, new 

Measure M2 incorrectly refers to nonexistent Requirement R8.2. 

1424. 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. 

1425. 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. 

1426. 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. 

1427. 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. 

1428. 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 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. 

1429. 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 


ycherry on PROD1PC64 with RULES2
16552 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

379PRC–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.’’

380 If delayed clearing results in reliability criteria 

violations, one solution can be the use of redundant 

relay systems. TPL–002–0 Table 1, footnote e. 

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.’’

1430. 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. 

1431. 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. 

1432. 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. 

1433. MidAmerican states that the 

term ‘‘immediately’’ in the 

Commission’s second directive is 

ambiguous and unenforceable. It 

suggests a 30-minute time limit. 

ii. Commission Determination 

1434. 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. 

1435. 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? 

1436. Protection systems on BulkPower 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. 

1437. 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 

Bulk-Power System, such requirements 

are included as one potential solution in 

the TPL Reliability Standards.380

1438. 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. 

1439. 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? 

1440. 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 reconfiguration, 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. 

1441. 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 BulkPower System. 

1442. Dynegy, Wisconsin Electric and 

Northern Indiana are concerned that the 

time required to troubleshoot, repair or 

replace failed relays and equipment 

would be 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 


ycherry on PROD1PC64 with RULES2
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381Order No. 672 at P 292. 

‘‘corrective action’’ consistent with this 

discussion when it modifies PRC–001–

1 in the Reliability Standards 

development process. 

1443. 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’’? 

1444. 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. 

1445. 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. 

1446. 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. 

1447. We agree with APPA that the 

added Measures and Levels of NonCompliance incorrectly reference nonexistent requirements. We direct the 

ERO to revise the references 

accordingly. 

1448. 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. 

1449. 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 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. 

1450. 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 BulkPower 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) 

1451. 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. 

1452. In the NOPR, the Commission 

identified PRC–002–1 as a fill-in-theblank 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. 

i. Comments 

1453. 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. 

1454. 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. 

1455. Otter Tail suggests that PRC–

002–1 should be developed on an 

Interconnection-wide basis to ensure 

consistency and promote reliability of 

the Bulk-Power System. 

ii. Commission Determination 

1456. For the reasons stated in the 

NOPR, the Commission will not 

approve or remand PRC–002–1. 

1457. 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 (PRC–

003–1) 

1458. 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 

develop a procedure to monitor and 

review misoperations of protection 


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382 Id. at P 292. 383NOPR at P 56–57. 

384The 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. 

systems and to develop and document 

corrective actions. 

1459. In the NOPR, the Commission 

identified PRC–003–1 as a fill-in-theblank 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 

1460. 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 

1461. For the reasons stated in the 

NOPR, the Commission will not 

approve or remand PRC–003–1. 

1462. 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) 

1463. 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. 

1464. In the NOPR, the Commission 

proposed to approve PRC–004–1 as 

mandatory and enforceable. 

i. Comments 

1465. APPA agrees that PRC–004–1 is 

sufficient for approval as a mandatory 

and enforceable Reliability Standard. 

1466. 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. 

1467. 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 

1468. The Commission approves 

Reliability Standard PRC–004–1 as 

mandatory and enforceable. 

1469. We are not persuaded by ISO–

NE and ISO/RTO Council’s assertion 

that PRC–004–1 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, 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. 

1470. 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) 

1471. 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. 

1472. 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 

1473. 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. 

1474. 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 

1475. For the reasons stated in the 

NOPR, the Commission approves 

Reliability Standard PRC–005–1 as 

mandatory and enforceable. 

1476. In addition, for the reasons 

discussed in the NOPR, the Commission 

directs the ERO to develop a 

modification to PRC–005–1 through the 


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385Underfrequency load shedding. 

386Undervoltage load shedding. 

387NOPR at P 367. 388NOPR at P 56–57. 

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) 

1477. PRC–006–0 ensures the 

development of a regional UFLS 385

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. 

1478. In the NOPR, the Commission 

identified PRC–006–0 as a fill-in-theblank 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 

UVLS 386 programs as part of its work on 

fill-in-the-blank Reliability 

Standards.387

i. Comments 

1479. 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 

1480. For the reasons stated in the 

NOPR, the Commission will not 

approve or remand PRC–006–0. 

1481. The Commission understands 

that UFLS, when properly coordinated 

with the dynamic response of the BulkPower 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) 

1482. 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. 

1483. In the NOPR, the Commission 

proposed to approve PRC–007–0 as 

mandatory and enforceable. 

i. Comments 

1484. 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. 

ii. Commission Determination 

1485. For the reasons stated in the 

NOPR, the Commission approves 

Reliability Standard PRC–007–0 as 

mandatory and enforceable. 

1486. 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) 

1487. 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. 

1488. In the NOPR, the Commission 

proposed to approve Reliability 

Standard PRC–008–0 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 Bulk-Power 

System. 

i. Comments 

1489. 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 

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.’’

1490. 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 fill-inthe-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. 


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389See PRC–008–0, Requirement R1. 

390NOPR at P 56–57. 

391NOPR at P 877–80. 

392NOPR at P 56–57. 

ii. Commission Determination 

1491. 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. 

1492. 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 PRC–008–0 as 

mandatory and enforceable because it 

requires entities to have equipment 

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. 

1493. 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 BulkPower System. 

i. UFLS Performance Following an 

Underfrequency Event (PRC–009–0) 

1494. 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. 

1495. In the NOPR, the Commission 

proposed to approve Reliability 

Standard PRC–009–0 as mandatory and 

enforceable. 

i. Comments 

1496. 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. 

1497. 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 fill-inthe-blank standard. 

ii. Commission Determination 

1498. For the reasons stated in the 

NOPR, the Commission approves 

Reliability Standard PRC–009–0 as 

mandatory and enforceable.391

1499. 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) 

1500. 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 in system conditions. The 

assessment must be conducted with the 

associated transmission planner and 

planning authority. 

1501. In the NOPR, the Commission 

proposed to approve Reliability 

Standard PRC–010–0 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. 

1502. 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 

1503. APPA agrees that PRC–010–0 

should be approved. While APPA agrees 

and 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 


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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. 

394NOPR P 883. 

395 Id. P 891–92. 

396A 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. 

the use of a coordinated protection 

system for the Bulk-Power System in 

each Interconnection. 

1504. 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. 

1505. FirstEnergy indicates that UVLS 

is primarily designed to address 

localized problems, and therefore 

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. 

ii. Commission Determination 

1506. 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. 

1507. 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

1508. 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. 

1509. 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. 

1510. 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 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) 

1511. 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. 

1512. 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 

1513. 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. 

1514. 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 

1515. 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. 

1516. 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. 

1517. 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 BulkPower System. 

l. Special Protection System Review 

Procedure (PRC–012–0) 

1518. PRC–012–0 requires regional 

reliability organizations to ensure that 

all special protection systems 396 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-theblank standard. The NOPR stated that 


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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 

1520. 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 

1521. For the reasons stated in the 

NOPR, the Commission will not 

approve or remand PRC–012–0. The 

Commission urges the ERO should 

consider APPA’s suggestions in the 

Reliability Standards development 

process. 

m. Special Protection System Database 

(PRC–013–0) 

1522. 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. 

1523. In the NOPR, the Commission 

identified PRC–013–0 as a fill-in-theblank 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 

1524. 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 

1525. 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) 

1526. 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. 

1527. In the NOPR, the Commission 

identified PRC–014–0 as a fill-in-theblank 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 

1528. 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 

Interconnection-wide basis through the 

use of ‘‘base procedures’’ for each 

Interconnection. 

ii. Commission Determination 

1529. 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) 

1530. 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. 

1531. In the NOPR, the Commission 

proposed to approve PRC–015–0 as 

mandatory and enforceable. 

i. Comments 

1532. 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 PRC–

15–0 until it approves PRC–012–0 and 

PRC–013–0, identified by the 

Commission as fill-in-the-blank 

standards. 

ii. Commission Determination 

1533. We disagree with APPA, ISO/ 

RTO Council and ISO–NE and conclude 

that PRC–015–0 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 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. 

1534. 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) 

1535. 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. 

1536. In the NOPR, the Commission 

proposed to approve Reliability 

Standard PRC–016–0 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. 


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i. Comments 

1537. 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. 

1538. 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 

1539. 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 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. 

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. We observe that a 

maximum allowable interval for 

maintenance and testing of special 

protection systems is not relevant to 

PRC–016–0, 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. 

1541. 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) 

1542. 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. 

1543. 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 

1544. 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 results will 

identify the impact of the special 

protection systems on the Bulk Electric 

System. 

1545. 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 

1546. 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. 

1547. 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) 

1548. 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. 

1549. In the NOPR, the Commission 

proposed to approve PRC–018–1 as 

mandatory and enforceable. 

i. Comments 

1550. 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 fill-in-theblank 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. 

ii. Commission Determination 

1551. 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 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 


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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. 

considered in an enforcement action, 

but is not a reason to delay approving 

and enforcing this Reliability Standard. 

1552. 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 (PRC–020–1) 

1553. 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. 

1554. In the NOPR, the Commission 

identified PRC–020–1 as a fill-in-theblank 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 

1555. 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 PRC–020–1 

requires the regional reliability 

organization to establish a database. 

ii. Commission Determination 

1556. 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 fillin-the-blank standard. For this reason, 

the Commission will not approve or 

remand PRC–020–1. 

t. Undervoltage Load Shedding Program 

Data (PRC–021–1) 

1557. 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. 

1558. In the NOPR, the Commission 

proposed to approve PRC–021–1 as 

mandatory and enforceable. 

i. Comments 

1559. APPA agrees that PRC–021–1 

should be approved as a mandatory and 

enforceable Reliability Standard. 

1560. 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 

1561. For the reasons stated in the 

NOPR and above, the Commission 

approves PRC–021–1 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) 

1562. 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. 

1563. In the NOPR, the Commission 

proposed to approve PRC–022–1 as 

mandatory and enforceable. 

i. Comments 

1564. APPA agrees that PRC–022–1 

should be approved as a mandatory and 

enforceable Reliability Standard. 

1565. 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 

1566. 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. 

1567. The Commission directs the 

ERO to consider FirstEnergy’s 

suggestion in the Reliability Standards 

development process. 

11. TOP: Transmission Operations 

1568. 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) 

1569. 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. 

1570. 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 NonCompliance. On November 15, 2006, 

NERC submitted revisions to the 

Reliability Standard to include 

Measures and Levels of NonCompliance.397

i. Comments 

1571. APPA notes that TOP–001–1, as 

revised to include Measures and Levels 

of Non-Compliance, fulfills the 

proposed directive in the NOPR. 

Accordingly, APPA agrees that the 

Commission should approve TOP–001–

1 as mandatory and enforceable. 


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398California Cogeneration notes that the 

curtailment of QFs in an emergency is allowed by 

18 CFR 292.307. 

399Santa Clara makes a similar argument 

reagarding Requirement R3 of TOP–008–1. 

400See 18 CFR 39.6 (Conflict of a Reliability 

Standard with a Commission Order). 

1572. 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. 

1573. 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. 

1574. 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. 

1575. MEAG Power also recommends 

a modification to TOP–001–1 clarifying 

that an entity may be found noncompliant 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. 

1576. 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. 

1577. 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. 

1578. 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. 

1579. 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 to 

provide that the transmission operator 

may notify the reliability coordinator or 

balancing authority.399

ii. Commission Determination 

1580. The Commission approves 

TOP–001–1 as mandatory and 

enforceable. We address the concerns 

raised by commenters below. 

1581. While the Commission agrees 

with APPA that TOP–001–1 should be 

approved, it does not agree that the new 

Measures and Levels of NonCompliance 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. 

1582. 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

1583. 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 taken by 

operating entities to preserve the 

integrity and reliability of the BulkPower 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 BulkPower System. Therefore no changes are 

required to the Reliability Standard in 

this connection. 

1584. We agree with MEAG Power 

that a reliability directive to an LSE to 

increase its planning reserve to 15 

percent or to reconductor its 

transmission line is outside the scope of 


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16562 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

401The Requirement states in part that ‘‘[e]ach 

Transmission Operator, Balancing Authority, and 

Generator Operator shall comply with reliability 

directives issued by the Reliability 

Coordinator* * *.’’

402Requirement R4 states: ‘‘Each Distribution 

Provider * * * shall comply with all reliability 

directives * * * unless such actions would violate 

safety, equipment, regulatory or statutory 

requirements.’’

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. 

404NERC 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. 

a TOP reliability directive. Reliability 

directives in the TOP group of 

Reliability Standards deal with 

operational directives and not planning 

directives. 

1585. 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. 

1586. 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. 

1587. 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 

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. 

1588. 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. 

1589. 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. 

1590. 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 NonCompliance 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) 

1591. 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; (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. 

1592. 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

1593. 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 

1594. 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. 

1595. 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 


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405Requirement 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.’’

406NOPR at P 976. 

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. 

1596. 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 realtime 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 dayahead 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. 

1597. MidAmerican is concerned that 

the Commission’s proposal to interpret 

the phrase ‘‘single contingency’’ as a 

contingency that includes all multielement 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. 

1598. 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 

‘‘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. 

1599. 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 

1600. 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. 

1601. 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. 

1602. 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 nextday 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. 

1603. 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. 


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407NOPR at P 979. 408 Id. at P 974. 

1604. 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 plant 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 Commission 

directs the ERO to modify Reliability 

Standard TOP–002–2 to address these 

two issues. 

1605. 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 realtime operations to the detriment of 

Bulk-Power System reliability, which 

demonstrates the need to approach the 

issue as we propose. We discuss this 

issue further in connection with 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. 

1606. 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. 

1607. 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. 

1608. 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. 

1609. 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 BulkPower 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 

next-day 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) 

1610. 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. 

1611. The Commission proposed in 

the NOPR to approve Reliability 

Standard TOP–003–0 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. 

1612. 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. 

i. Comments 

1613. 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 


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409See Order No. 890 at P 68–69, 207–213. 

410 Id. at P 292. 

411The 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-14b-changes.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. 

that a larger facility has a longer lead 

time for outage notification. 

1614. 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. 

1615. 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. 

1616. 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. 

1617. 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 certain kV level, the 

emphasis should be on facilities that 

may have a significant effect on 

congestion revenue rights resource 

adequacy. 

1618. 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 BulkPower 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. 

1619. 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 

1620. The Commission approves 

TOP–003–0 as mandatory and 

enforceable. We address the concerns 

raised by commenters below. 

1621. 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 

calculations.411 We believe this 

addresses LPPC’s concern regarding the 

interplay between reliability and 

business practices. 

1622. 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. 

1623. 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 

1624. 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. 

1625. 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 BulkPower 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 


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16566 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

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 

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. 413NOPR at P 997. 

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 

1626. 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 

1627. 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) 

1628. This Reliability Standard 

requires transmission operators to 

operate the transmission system within 

SOL and IROL.412 The N–1 operating 

criterion for the transmission system is 

also established in this Reliability 

Standard. It provides that operating 

configurations for which limits have not 

yet been determined should be treated 

as emergencies. The goal of the 

Reliability Standard is to maintain BulkPower System facilities within limits, 

thereby protecting transmission, 

generation, distribution and customer 

equipment and preventing cascading 

failures of the interconnected grid. 

1629. 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. 

1630. 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 

1631. 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 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. 

1632. 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. 

1633. 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. 

1634. 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. 

1635. Santa Clara states that 

Requirement R2 of the Reliability 

Standard should be revised to include 


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Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 16567 

414See NOPR at P 995. 

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. 

frequency monitoring in addition to the 

monitoring of voltage, real and reactive 

power flows. 

ii. Commission Determination 

1636. 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. 

1637. 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 TOP–004–

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. 

1638. 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. 

1639. As mentioned above, the 

Commission proposed to interpret 

‘‘multiple outages’’ in the context of 

Requirement R3 to include multiple 

element outages resulting from high-risk 

conditions such as hurricanes, wild 

fires, ice storms or periods of high solar 

magnetic 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 high-risk 

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. 

1640. We direct the ERO to consider 

Santa Clara’s suggestion regarding 

changes to Requirement R2 in the 

Reliability Standards development 

process. 

1641. 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. 

1642. 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) 

1643. 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 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

1644. The Commission proposed in 

the NOPR to approve Reliability 

Standard TOP–005–1 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 

1645. 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 


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16568 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

416Requirement R4 states: ‘‘Each PurchasingSelling 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.’’

417NOPR at P 1005. 

418 In its November 15, 2006 filing, NERC 

submitted TOP–006–1, which supersedes 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. 

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. 

1646. 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. 

1647. 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 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. 

1648. 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 

1649. 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. 

1650. 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. 

1651. 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. 

1652. 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. 

f. Monitoring System Conditions (TOP–

006–1) 

1653. TOP–006–1 requires operating 

personnel to continuously monitor 

essential Bulk-Power System parameters 

such as line flows, circuit breaker status, 

generator resources, relays, weather 

forecasts and frequency to ensure that 

the facilities do not exceed their 

operating limits. 

1654. 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 

1655. 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. 

1656. 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. 

1657. 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 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. 

1658. LPPC maintains that the 

Commission should require NERC to list 

the capabilities required rather than 

specific tools because tools will change 

over time. 

1659. 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 

1660. 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. 

1661. 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 realtime 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 


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Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 16569 

419We note that TOP–006–0 applies to 

transmission operators, balancing authorities, 

generator operators and reliability coordinators. 

will become obsolete, we note that we 

are not seeking specific analytical tools, 

but rather minimum capabilities. 

1662. 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 BulkPower 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. 

1663. 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 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

1664. 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 Bulk-Power 

System that would be acceptable to 

allow closing of lines during system 

restoration. 

1665. The ERO should consider 

APPA’s comment regarding the missing 

Measures in the ERO’s Reliability 

Standards development process. 

1666. 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) 

1667. 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. 

1668. The Commission proposed in 

the NOPR to approve TOP–007–0 as 

mandatory and enforceable. 

1669. In the NOPR, the Commission 

solicited comment on potentially 

overlapping matters addressed in 

Reliability Standards TOP–007–0 and 

TOP–008–0. 

i. Comments 

1670. 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. 

1671. 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 TOP–008. 

1672. 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 

1673. 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. 

1674. 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. 

1675. Accordingly, the Commission 

approves Reliability Standard TOP–

007–0 as mandatory and enforceable. 

h. Response to Transmission Limit 

Violations (TOP–008–1) 

1676. TOP–008–1 requires a 

transmission owner to take immediate 

steps to mitigate SOL and IROL 

violations. 

1677. The Commission proposed in 

the NOPR to approve Reliability 

Standard TOP–008–0 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 NonCompliance and (2) includes reliability 


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16570 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

420 In its November 15, 2006, filing, NERC 

submitted TOP–008–1, which supersedes 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. 

421See NOPR at P 1035–36. 

422See TPL–001–0, TPL–002–0, TPL–003–0 and 

TPL–004–0. 

423See TPL–005–0 and TPL–006–0. 

424NOPR at P 1042. 

425Examples 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. 

coordinators in the applicability 

section.420

i. Comments 

1678. 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. 

1679. 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. 

ii. Commission Determination 

1680. 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. 

1681. We agree with APPA that the 

reliability coordinator merely receives 

information provided by the 

transmission operator and does not play 

any substantive role under TOP–008–1. 

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. 

1682. The ERO should consider 

APPA’s comment regarding the missing 

Measures in the ERO’s Reliability 

Standards development process. 

1683. Accordingly, the Commission 

approves Reliability Standard TOP–

008–1 as mandatory and enforceable. 

12. TPL: Transmission Planning 

1684. 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 needs 422 and (2) the information 

required to assess regional compliance 

with planning criteria and for selfassessment of regional reliability.423

1685. 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 

1686. 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 

1687. 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 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 

1688. 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 


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426NOPR at P 1047. 

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. 

1689. 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 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. 

1690. 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. 

1691. 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 

1692. 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 BulkPower System. To achieve this goal, it 

is necessary, among other things, to 

ensure that the planning process and the 

Reliability Standards produce a BulkPower 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.’’

1693. The Commission agrees with 

Northern Indiana that the Reliability 

Standards TPL–001–0 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 

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. 

1694. 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 

1695. 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 

1696. Most of the commenters agree 

with the Commission’s proposal on 

sensitivity studies to determine critical 


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427 Id. at P 1061. 

428 Id. at P 1061. 

429 Id. at n 324. 

430 Id. at P 1046. 

system conditions. These include 

FirstEnergy, TVA, MidAmerican, 

Entergy and SDG&E. However, a few 

commenters, including EEI, APPA, 

MISO and Northern Indiana, take the 

view that such a requirement is 

unnecessary and overly prescriptive. 

1697. 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. 

1698. 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 BulkPower System. 

1699. 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. 

1700. 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. 

1701. 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. 

1702. 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 

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. 

1703. 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. 

1704. 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 

1705. 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 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. 

1706. 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. 

1707. The Commission believes it is 

important to clarify the type of analysis 


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431 Id. at P 1047. 432 Id. at P 1049. 433Section 215(a) of the FPA defines ‘‘Reliable 

Operation’’ as ‘‘operating the elements of the BulkPower 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). 

434With respect to failure, the element includes 

a single transmission line, transformer, generator or 

single pole of a DC line. 

435NOPR at P 1049. 436 Id. at P 1050. 

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 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 

1708. 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 

1709. 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 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

1710. 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. 

1711. 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. 

1712. 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. 

1713. 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 

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. 

1714. 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 


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437National Grid, MidAmerican and SDG&E. 

438NOPR at P 1049. 

439A ‘‘single element’’ means a transmission line, 

a transformer, a generator or a single pole of a DC 

line. 

implementation of elements from other 

Reliability Standards. 

1715. 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 

1716. Several commenters 437 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 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 

TPL–002–0 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. 

1717. 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. 

1718. 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 

Commission’s approach speaks directly 

to the problem that the statute requires 

be addressed. 

1719. 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. 

1720. 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 

1721. 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 

1722. 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 

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 


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440NOPR at P 1060. 

441 Id. 

terms, this proposed modification will 

not enhance system reliability. 

1723. 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. 

1724. 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 

1725. 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 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. 

1726. 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. 

1727. 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. 

1728. 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 

1729. 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 difficulty obtaining 

this information, the Commission asked 

how this potential information gap 

should be addressed.440

(a) Comments 

1730. 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. 

1731. 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, 


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the ERO will turn to the Commission for 

assistance. 

1732. 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. ISO–

NE 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. 

1733. FirstEnergy and SoCal Edison 

state that currently they are able to 

obtain information regarding new 

generation from publicly available 

information and from the 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. 

1734. 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. 

1735. 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 ‘‘nontransportable’’ 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. 

1736. 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 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 longrange transmission planning studies. 

1737. 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. 

1738. 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. 

1739. 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. 

1740. 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. 

1741. 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 how far the 

Reliability Standards can go. 

International Transmission states that, 

in the absence of a standard on resource 


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442See http://www.pjm.com/contributions/pjmmanuals/manuals.html. 443See Order No. 2004. 

adequacy, transmission service 

providers must use their judgment on 

potential new generation or retirements 

to create base cases and plan the system 

accordingly. 

1742. 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. 

1743. 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 

1744. 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. 

1745. 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 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

1746. 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. 

1747. 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 Bulk-Power 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. 

1748. 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 BulkPower 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. 

1749. 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. 

1750. 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. 


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444NOPR at P 1063. 

445Order No. 890 at P 526, 542. 

446The 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. 

447The performance requirements are set forth in 

Category A of Table I of the Reliability Standard. 

vi. Sharing of Information With 

Neighboring Systems 

1751. 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 

1752. 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 

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. 

1753. 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. 

1754. 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 

1755. 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 

interdependent 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 example, the planning 

authorities needs to be consistent in the 

line flow values that they use. 

1756. 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. 

1757. 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) 

1758. 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 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 longerterm planning horizons. 

1759. The Requirements of TPL–001–

0 specify that the planning authority 

and transmission planner must 


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448See 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. 

449NOPR at P 1065–67. 

450See, e.g., EEI, APPA, SDG&E, Entergy, SoCal 

Edison and TVA. 451NOPR at P 1046. 

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. 

1760. 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 Committee 448 and 

require that normal facility ratings be in 

accordance with Reliability Standard 

FAC–008–1 and that normal voltages be 

in accordance with Reliability Standard 

VAR–001–1.449

i. Comments 

1761. APPA agrees with the 

Commission that TPL–001–0 is 

sufficient for approval as a mandatory 

and enforceable standard. 

1762. 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 timeframes 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. 

1763. 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 activity. If generators and 

transmission lines are out for scheduled 

maintenance during off-peak load 

conditions, then these outages should be 

considered. 

1764. 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 

1765. 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. 

1766. 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. 

1767. Requirement R1.3 of TPL–001–

0 states that the planning authority and 

transmission planner must provide 

studies and simulations to support its 

planning 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 


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452The performance requirements are set forth in 

Category B of Table 1 of the Reliability Standard. 

453Footnote b to Table 1 allows for the 

interruption of firm load for consequential load 

loss. 

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. 

1768. 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. 

1769. 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 BulkPower 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 oneyear 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. 

1770. 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 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. 

1771. 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) 

1772. 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 

Bulk-Power 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 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 

near-term and longer-term planning 

horizons. 

1773. 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. 

1774. The Commission proposed in 

the NOPR to approve Reliability 

Standard TPL–002–0 as mandatory and 


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454NOPR at P 1081. 

455 Id. at P 1084. 

456From 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. 

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 

1775. APPA agrees that TPL–002–0 is 

sufficient for approval as a mandatory 

and enforceable reliability standard. 

1776. In response to the Commission’s 

proposal 454 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. 

1777. 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. 

1778. 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. 

1779. 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. 

1780. 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 with respect to whether 

or not an entity can plan to operate 

above normal ratings, but below 

emergency ratings, and for how long. 

1781. 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. 

1782. 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. 

1783. 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 rescheduling power (but not load 

shedding) as part of manual system 

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 


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457 10 CFR 50, Appendix a, GDC17. 458NOPR at P 1083. 

allowed after a Category B contingency, 

which would be inconsistent with 

Category C.3. 

1784. 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 

1785. 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. 

1786. 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. 

1787. 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 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. 

1788. 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. 

1789. 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. 

1790. 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. 

1791. 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 


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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. 

461Consequential load is the load that is directly 

served by the elements that are removed from 

service as a result of the contingency. 

462See Order No. 672 at P 329. 

463NERC 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. 

465NOPR at P 1083. 

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 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. 

1792. 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. 

1793. 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 

interpreted to allow that an entity plan 

for some amount of load loss to avoid 

costly infrastructure investments. 

1794. 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.’’

1795. 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. 

1796. 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 

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. 

1797. 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 (nonrecallable 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 


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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. 

1798. 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 

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) 

1799. Reliability Standard TPL–003–0 

seeks to ensure that the future BulkPower 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. 

1800. 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. 

1801. 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 

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. 

1802. 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 

1803. 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. 

1804. 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. 

1805. 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. 

1806. 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 


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466 Id. at P 1097. 

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. 

1807. 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

1808. 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. 

1809. 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 multi-element 

contingencies which will be helpful in 

determining the value of this proposal. 

1810. 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 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. 

1811. 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 cost-effective 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. 

1812. 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 BulkPower System. 

1813. 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. 

1814. 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 BulkPower 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. 

1815. 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 

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. 

1816. 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 

1817. 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. 

1818. 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 TPL–003–0 to require that 


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467 Id. at P 1098. 

468See WECC Disturbance Performance Table W–

1 and Figure W–1 of Allowable Effects on other 

Systems, NERC/WECC Planning Standards April 

10, 2003. 

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. 

1819. The intent underlying the 

statement that ‘‘to avoid 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 

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. 

1820. 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. 

1821. 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. 

1822. 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 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. 

1823. 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. 

1824. 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. 

1825. 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. 

1826. 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 

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 (TPL–004–0) 

1827. The goal of Reliability Standard 

TPL–004–0 is to ensure that the future 

Bulk-Power System is evaluated to 

assess the risks and consequences of an 

extreme event involving the loss of 

multiple elements. It 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 


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469See NOPR at P 1112. 

resulting in loss of two or more 

elements or cascading) for the near-term 

(five-year) planning horizon. 

1828. 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. 

1829. 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 

1830. 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 

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. 

1831. 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 

1832. 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. 

1833. 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. 

1834. 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. 

1835. 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’ 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. 

1836. 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. 

1837. 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 SelfAssessment Reliability Reports (TPL–

005–0) 

1838. 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. 

1839. The Commission proposed in 

the NOPR not to approve or remand 


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470Order No. 890 at P 443. 

TPL–005–0, as it applies only to 

regional reliability organizations. 

i. Comments 

1840. EEI comments that TPL–005–0 

should be revised to remove the regional 

reliability organizations. 

ii. Commission Determination 

1841. 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. 

1842. 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) 

1843. 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. 

1844. The Commission proposed in 

the NOPR not to approve or remand 

TPL–006–0, as it applies only to 

regional reliability organizations. 

i. Comments 

1845. EEI agrees that TPL–006–0 

should be revised to remove the regional 

reliability organizations. 

ii. Commission Determination 

1846. Consistent with our discussion 

in the Common Issues section above, the 

Commission will not approve or remand 

TPL–006–0. 

13. VAR: Voltage and Reactive Control 

1847. The Version 0 Voltage and 

Reactive Control (VAR) Reliability 

Standard VAR–001–0 is intended to 

maintain Bulk-Power System facilities 

within voltage and reactive power 

limits, thereby protecting transmission, 

generation, distribution, and customer 

equipment and the reliable operation of 

the Interconnection. The Voltage and 

Reactive Control group of Reliability 

Standards is intended to replace the 

existing VAR–001–0 and consists of two 

proposed Reliability Standards, VAR–

001–1 and VAR–002–1, with new 

Requirements. These two new proposed 

Reliability Standards have been 

submitted by NERC as part of the 

August 28, 2006 Supplemental Filing 

for Commission review. 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 

1848. 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. 

1849. 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 

purchasing-selling 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. 

1850. Most comments address the 

specific modifications and concerns 

raised by the Commission in the NOPR. 

Below, we address each topic 

separately, followed by an overall 

conclusion and summary. 

i. Applicability to Load-Serving Entities 

and Reliability Coordinators 

(a) Comments 

1851. EEI agrees with the Commission 

that the applicability of VAR–001–1 

should be expanded to include 

reliability coordinators and LSEs. 

1852. 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. 

1853. 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. 

1854. 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 

1855. 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 long-term 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. 

1856. Since a reliability coordinator is 

the highest level of authority overseeing 

the reliability of the Bulk-Power System, 

the Commission believes that it is 


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471NOPR at P 1134. 

472Purchasing 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. 473NOPR at P 1047. 

important to include the reliability 

coordinator as an applicable entity to 

assure that adequate voltage 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. 

1857. The Commission agrees with 

SoCal Edison that not all LSEs are 

purchasing-selling 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 purchasingselling 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. 

1858. VAR–001–1 recognizes that 

energy purchases of purchasing-selling 

entities can increase reactive power 

consumption on the Bulk-Power System 

and the purchasing-selling 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 

Bulk-Power System. 

1859. While the Commission 

recognizes the point made by TAPS, 

that purchasing-selling 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 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 purchasingselling entities. 

ii. Acceptable Ranges of Net Power 

Factor Range 

(a) Comments 

1860. 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. 

1861. 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 

1862. 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. 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 Bulk-Power System. 

1863. 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. 

1864. 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 

1865. Dynegy supports the 

Commission’s proposal to include more 

definitive requirements on ‘‘established 


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474EEI at 99. 475See NOPR at P 1140. 

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 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. 

1866. 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. 

1867. 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 nearsystem 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. 

1868. 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 

1869. In the NOPR, the Commission 

expressed concern that the technical 

requirements containing terms such as 

‘‘established limits’’ or ‘‘sufficient 

reactive resources’’ are not 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. 

1870. 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. 

1871. 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 clearlydefined requirements for voltage and 

reactive margins. 

1872. 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. 

iv. Periodic Voltage Stability Analysis in 

Real-Time Operations 

(a) Comments 

1873. 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. 

1874. 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.’’

1875. 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 


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476See FERC Staff Report, Principles of Efficient 

and Reliable Reactive Power Supply and 

Consumption (2005), available at http:// 

www.ferc.gov/legal/staff-reports.asp. 

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 steadystate 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 

1876. 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 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. 

1877. 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 

1878. 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. 

1879. 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. 

(b) Commission Determination 

1880. 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 

1881. 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 

1882. 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 preferential and in the public 

interest; and proposed to approve it as 

mandatory and enforceable. 

i. Comments 

1883. APPA and SDG&E agree that 

VAR–002–1 is sufficient for approval as 

a mandatory and enforceable Reliability 

Standard. 

1884. 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 


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16592 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

477NOPR at P 42–43. 

478See, e.g., MOD–001–0, TOP–002–1 and the 

INT Reliability Standards. 

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 

1885. 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 NonCompliance to ensure appropriate 

generation operation to maintain 

network voltage schedules. Accordingly, 

the Commission approves Reliability 

Standard VAR–002–1 as mandatory and 

enforceable. 

1886. 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 

1887. 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. 

1888. 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 

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 section 477

and (4) modifies the definition of terms 

concerning reserves (such as operating 

reserves) to include DSM, including 

controllable load. 

a. Comments 

1889. 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. 

1890. 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. 

1891. 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. 

1892. 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. 

1893. Santa Clara submits that, to 

eliminate any ambiguity about when 

these definitions of these commonlyused 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. 

b. Commission Conclusion 

1894. 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

1895. The Commission directs the 

ERO to modify the glossary through the 

Reliability Standards development 

process to include the statutory 

definitions of the terms Bulk-Power 

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. 

1896. 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. 

1897. 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. 

1898. 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 Standards and a 

Transmission Organization’s function, 


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479 18 CFR 39.6 (2006). 

480 5 CFR 1320.11. 

481 44 U.S.C. 3507(d) (2000). 

482Wisconsin Electric at 9. 

483NOPR at P 1157. 

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

1899. 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 BAL–002–0 

and BAL–005–0. 

III. Information Collection Statement 

1900. 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, DC 20426 

(Attention: Michael Miller, Office of the 

Executive Director, 202–502–8415) or 

from the Office of Management and 

Budget (Attention: Desk Officer for the 

Federal Energy Regulatory Commission, 

fax: 202–395–7285, e-mail: 

oira_submission@omb.eop.gov). 

1901. 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 

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. 

1902. 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. 

1903. 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

1904. 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. 

1905. 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. 

1906. 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. 

1907. Total Annual Hours for 

Collection: 

Data collection Number of 

respondents 

Number 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 


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16594 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

484Regulations 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 U.S.C. 601–612 (2006). 

487 5 U.S.C. 601–604. 

488 5 U.S.C. 603(a). 

489 5 U.S.C. 605(b). 

490 5 U.S.C. 609(a). 

491 5 U.S.C. 611. 

Data collection Number of 

respondents 

Number of 

responses 

Hours per 

response 

Total annual 

hours 

Power Marketers ...................................................................................... 159 1 100 15,900 

Recordkeeping .......................................................................................... Investor Owned Utilities ........................ 35,360 

Munis/Coops (Large) ........................ 11,360 

Munis/Coops (Small) ........................ 47,570 

Generator Owner/Ops. ........................ 18,000 

Power Marketers ........................ 1,590 

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 

will reduce the number of small entities 

that will be responsible for compliance 

with Reliability Standards. 

1908. 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. 

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 BulkPower 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, DC 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). 

IV. Environmental Analysis 

1909. 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 taken 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 

1910. 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. 

1911. 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

1912. 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

1913. 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. 

1914. The statute provides for judicial 

review of an agency’s final certification 

or Final RFA.491 An agency must file a 


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492United 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). 

494NOPR at P 1175. 

495 Id. at 1176. 

496 Id. at 49–53 (Section B.3 ‘‘Applicability to 

Small Entities’’). 

497 Id. at 51. 

498APPA/NRECA comments at 2. 

499 Id. 

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 

1915. 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. 

1916. 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 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 reliabilityrelated 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. 

1917. 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 

1918. 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

1919. 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. 

1920. 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 Bulk-Power System but, under the 

NOPR’s definition of Bulk-Power 

System, would be required to comply 

with the Reliability Standards. 

1921. 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, and numerous 


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500See Applicability Issues: Bulk-Power System 

v. Bulk Electric System and Applicability to Small 

Entities, supra sections II.C.1–2. 

501TAPS at 13. 

502NOPR at P 49–53. 

503As noted previously, APPA, NRECA and TAPs 

submitted supplemental comments supporting the 

ERO’s compliance registry process. 504 16 U.S.C. 824o(a)(4) (2006). 

other commenters discuss these 

proposals in their comments, which the 

Commission addresses in the 

Applicability Issues section of the Final 

Rule.500

1922. 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 

1923. 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. 

1924. 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 bulk electric 

system, which as APPA/NRECA states 

would have had the greatest impact on 

small entities. 

1925. 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. 

1926. 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. 

1927. 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 

1928. 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. 

1929. 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 BulkPower System. 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, 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. 

1930. 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 Bulk-Power System. 

2. Objectives of and the Legal Basis for 

the Final Rule 

1931. 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 BulkPower System. 

1932. 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. 

1933. 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 


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505See 16 U.S.C. 824o(d)(5) (2006). 

506See Energy Information Administration 

Database, Form EIA–861, Dept. of Energy (2005), 

available at http://www.eia.doe.gov/cneaf/ 

electricity/page/eia861.html. 

507Most 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. 

508See NERC Statement of Compliance Registry 

Criteria (Revision 3) at 6–8. 

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 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 

1934. 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. 

1935. 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. 

1936. 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 

1937. 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. 

1938. 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 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. 

1939. 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. 

1940. 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. 

1941. 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. 

1942. 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. 

1943. 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, Recordkeeping and Other 

Compliance Requirements for Small 

Entities 

1944. 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 

1945. 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 

1946. 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 


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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. 

VI. Document Availability 

1947. In addition to publishing the 

full text of this document in the Federal 

Register, the Commission provides all 

interested persons an opportunity to 

view and/or print the contents of this 

document via the Internet through 

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

and in FERC’s Public Reference Room 

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

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

Street, N.E., Room 2A, Washington DC 

20426. 

1948. From FERC’s Home Page on the 

Internet, this information is available on 

eLibrary. The full text of this document 

is available on eLibrary in PDF and 

Microsoft Word format for viewing, 

printing, and/or downloading. To access 

this document in eLibrary, type the 

docket number excluding the last three 

digits of this document in the docket 

number field. 

1949. User assistance is available for 

eLibrary and FERC’s Web site 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 

1950. These regulations are effective 

June 4, 2007. 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 40 

Electric power; reporting and 

recordkeeping requirements. 

By the Commission. 

Philis J. Posey, 

Acting Secretary. 

■ In consideration of the foregoing, the 

Commission amends Chapter I, Title 18, 

Code of Federal Regulations, by adding 

Part 40 to read as follows: 

PART 40—MANDATORY RELIABILITY 

STANDARDS FOR THE BULK-POWER 

SYSTEM 

Sec. 

40.1 Applicability. 

40.2 Mandatory Reliability Standards. 

40.3 Availability of Reliability Standards. 

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

§ 40.1 Applicability. 

(a) This part applies to all users, 

owners and operators of the Bulk-Power 

System within the United States (other 

than Alaska or Hawaii), including, but 

not limited to, entities described in 

section 201(f) of the Federal Power Act. 

(b) Each Reliability Standard made 

effective by § 40.2 must identify the 

subset of users, owners and operators of 

the Bulk-Power System to which a 

particular Reliability Standard applies. 

§ 40.2 Mandatory Reliability Standards. 

(a) Each applicable user, owner or 

operator of the Bulk-Power System must 

comply with Commission-approved 

Reliability Standards developed by the 

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 Web site 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. 

Note: The following appendices will not be 

published in the Code of Federal 

Regulations. 

APPENDIX A.—DISPOSITION OF RELIABILITY 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. 


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

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. 

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. 

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. 


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

Reliability standard Title Proposed disposition 

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. 

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. 

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. 

Georgia Cities .................................................................... City of Acworth. 

City of Adel. 

City of Blakely. 

City of Cairo. 

City of Calhoun. 

City of Camilla. 

City of College Park. 


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Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 16601 

APPENDIX B.—COMMENTERS ON NOTICE OF PROPOSED RULEMAKING—Continued 

Abbreviation Entity 

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. 

Marietta Power and Water. 

Georgia Operators ............................................................. Georgia System Operators Corp. 

International Transmission ................................................. International Transmission Company. 

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

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: Cross-Border 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. 

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. 


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16602 Federal Register / Vol. 72, No. 64 / Wednesday, April 4, 2007 / Rules and Regulations 

APPENDIX B.—COMMENTERS ON NOTICE OF PROPOSED RULEMAKING—Continued 

Abbreviation Entity 

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. 

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. 

[FR Doc. E7–5284 Filed 4–3–07; 8:45 am] 

BILLING CODE 6717–01–P 


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