121 FERC ¶ 61,296 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

18 CFR Part 40 

(Docket No. RM07-3-000; Order No. 705) 

Facilities Design, Connections and Maintenance Reliability Standards 

(Issued December 27, 2007) 

AGENCY: Federal Energy Regulatory Commission. 

ACTION: Final Rule. 

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

approves three Reliability Standards concerning Facilities Design, Connections and 

Maintenance that were developed by the North American Electric Reliability Corporation 

(NERC), the Commission-certified Electric Reliability Organization (ERO) responsible 

for developing and enforcing mandatory Reliability Standards. Further, pursuant to 

section 215(d)(5), we direct the ERO to develop a modification to one of the three 

Reliability Standards that are being approved as mandatory and enforceable. The three 

FAC Reliability Standards, designated FAC-010-1, FAC-011-1 and FAC-014-1, require 

planning authorities and reliability coordinators to establish methodologies to determine 

system operating limits for the Bulk-Power System in the planning and operation 

horizons. The Commission also approves a regional difference for the Western 

Interconnection administered by the Western Electricity Coordinating Council which is 

incorporated into FAC-010-1 and FAC-011-1. In addition, the Commission accepts three 
Docket No. RM07-3-000 - 2 - 

new terms for the NERC Glossary of Terms Used in Reliability Standards, remands 

another proposed term, and directs the ERO to submit modifications to its proposed 

Violation Risk Factors consistent with our prior orders. 

EFFECTIVE DATE: The approval granted in this order becomes effective due [insert 30 

days from the date that notice of this order is published in the FEDERAL 

REGISTER]. 

FOR FURTHER INFORMATION CONTACT: 

Christy Walsh (Legal Information) 

Office of the General Counsel 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, D.C. 20426 

(202) 502-6523 

Robert Snow (Technical Information) 

Office of Electric Reliability 

Division of Reliability Standards 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, D.C. 20426 

(202) 502-6716 

SUPPLEMENTARY INFORMATION: 
UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Before Commissioners: Joseph T. Kelliher, Chairman; 

 Suedeen G. Kelly, Marc Spitzer, 

 Philip D. Moeller, and Jon Wellinghoff. 

Facilities Design, Connections and Maintenance 

Reliability Standard 

Docket No. RM07-3-000 

ORDER NO. 705 

FINAL RULE 

(Issued December 27, 2007) 

 Paragraph Numbers

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

II. Background................................................................................................................... 2.

A. EPAct 2005 and Mandatory Reliability Standards .................................................. 2.

B. NERC’s Proposed FAC Reliability Standards ......................................................... 4.

C. Notice of Proposed Rulemaking............................................................................. 10.

III. Discussion.................................................................................................................. 13.

A. General Matters...................................................................................................... 15.

B. Specific Issues ........................................................................................................ 18.

1. Consistency with Order No. 890 ........................................................................ 18.

2. Loss of Consequential Load .............................................................................. 50.

3. Loss of Shunt Device.......................................................................................... 54.

4. Load Forecast Error under FAC-011-1 .............................................................. 59.

5. Other Issues ........................................................................................................ 72.

6. Effective Date ..................................................................................................... 80.

C. Western Interconnection Regional Difference....................................................... 85.

D. New Glossary Terms.............................................................................................. 97.

1. Cascading Outages.............................................................................................. 98.

2. IROL ................................................................................................................. 118.

3. IROL Tv............................................................................................................ 125.
Docket No. RM07-3-000 - 2 - 

E. Violation Risk Factors .......................................................................................... 129.

1. General Issues................................................................................................... 132.

2. Requirements R2 and R2.1 - R2.2.3 for FAC-010-1 and FAC-011-1 ............. 147.

3. FAC-014-1, Requirement R5 ........................................................................... 167.

4. FAC-010-1, Requirement 3.6 .......................................................................... 178.

5. FAC-011-1, Requirement 3.4 .......................................................................... 179.

IV. Information Collection Statement ........................................................................... 180.

V. Environmental Analysis ........................................................................................... 185.

VI. Regulatory Flexibility Act Certification ................................................................. 186.

VII. Document Availability........................................................................................... 189.

VIII. Effective Date and Congressional Notification.................................................... 192.

I. Introduction

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

approves three Reliability Standards concerning Facilities Design, Connections and 

Maintenance (FAC) that were developed by the North American Electric Reliability 

Corporation (NERC), the Commission-certified Electric Reliability Organization (ERO) 

responsible for developing and enforcing mandatory Reliability Standards. Further, 

pursuant to section 215(d)(5), we direct the ERO to develop a modification to one of the 

three Reliability Standards that are being approved as mandatory and enforceable. The 

three FAC Reliability Standards, designated FAC-010-1, FAC-011-1 and FAC-014-1, 

require planning authorities and reliability coordinators to establish methodologies to 

determine system operating limits (SOLs) for the Bulk-Power System in the planning and 

operation horizons. The Commission also approves a regional difference for the Western 

Interconnection administered by the Western Electricity Coordinating Council (WECC) 

which is incorporated into FAC-010-1 and FAC-011-1. In addition, the Commission 
Docket No. RM07-3-000 - 3 - 

accepts three new terms for the NERC Glossary of Terms Used in Reliability Standards, 

remands another proposed term, and directs the ERO to submit modifications to its 

proposed Violation Risk Factors consistent with our prior orders. 

II. Background

A. EPAct 2005 and Mandatory Reliability Standards

2. 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.1

 EPAct 2005 

adds a new section 215 to the FPA, which requires a Commission-certified ERO to 

develop mandatory and enforceable Reliability Standards that 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.2

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

section 215 of the FPA.3

 Pursuant to Order No. 672, the Commission certified one 

 1

 Energy Policy Act of 2005, Pub. L. No 109-58, Title XII, Subtitle A, section 

1211(a), 119 Stat. 594, 941 (2005), 16 U.S.C. 824o (2000 & Supp. V 2005). 

2

 FPA section 215(e), 16 U.S.C. 824o(e) (2000 & Supp. V 2005). 

3

 Rules Concerning Certification of the Electric Reliability Organization; and

Procedures for the Establishment, Approval and Enforcement of Electric Reliability 

Standards, Order No. 672, 71 FR 8662 (Feb. 17, 2006), FERC Stats. & Regs. ¶ 31,204 

(2006), order on reh’g, Order No. 672-A, 71 FR 19814 (Apr. 18, 2006), FERC Stats. & 

Regs. ¶ 31,212 (2006). 
Docket No. RM07-3-000 - 4 - 

organization, NERC, as the ERO.4

 The ERO is required to develop Reliability Standards, 

which are subject to Commission review and approval. Approved Reliability Standards 

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

Reliability Standard. 

B. NERC’s Proposed FAC Reliability Standards

4. On November 15, 2006, NERC filed 20 revised Reliability Standards and three 

new Reliability Standards for Commission approval. The Commission addressed the 20

revised Reliability Standards in Order No. 6935

 and established this rulemaking 

proceeding to review the three new Reliability Standards. 

5. NERC states that the three new Reliability Standards ensure that SOLs and 

interconnection reliability operating limits (IROLs)6

 are developed using consistent 

methods and that those methods contain certain essential elements. NERC designated the 

new Reliability Standards as follows: 

 4

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

Certification Order), order on reh’g & compliance, 117 FERC ¶ 61,126 (2006) (ERO 

Rehearing Order). 

5

 On March 16, 2007, the Commission approved 83 of the 107 Reliability 

Standards initially filed by NERC. See Mandatory Reliability Standards for the BulkPower System, Order No. 693, 72 FR 16416 (Apr. 4, 2007), FERC Stats. and Regs. 

¶ 31,242, order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053 (2007). 

6

 As discussed later, NERC has proposed the following definition of IROL, “a 

System Operating Limit that, if violated, could lead to instability, uncontrolled 

separation, or Cascading Outages that adversely impact the reliability of the Bulk Electric 

System.” 
Docket No. RM07-3-000 - 5 - 

FAC-010-1 (System Operating Limits Methodology for the 

Planning Horizon); 

FAC-011-1 (System Operating Limits Methodology for the 

Operations Horizon); and 

FAC-014-1 (Establish and Communicate System Operating 

Limits). 

6. NERC explains that FAC-010-1 requires each planning authority to document its 

methodology for determining SOLs and share its methodology with reliability entities. 

FAC-010-1 provides that the planning authority shall have a documented SOL 

methodology within its planning area that is applicable to the planning time horizon, does 

not exceed facility ratings, and includes a description of how to identify the subset of 

SOLs that qualify as IROLs. Requirement R2 of the Reliability Standard and its subparts 

identify specific considerations that must be included in the methodology. 

7. Reliability Standard FAC-011-1 requires each reliability coordinator to develop a 

SOL methodology for the operations time frame. This methodology must determine 

whether certain stability limits that are derived from multiple contingency analysis and 

provided by the planning authority are applicable in the operating horizon. Requirement 

R2 of FAC-011-1 identifies specific considerations that must be included in the 

methodology in both a pre-contingency state and following one or multiple 

contingencies. The provisions of Requirement R2 of FAC-011-1 are the same as those in 

Requirement R2 of FAC-010-1, except for Requirement R2.3.2 of FAC-011-1, discussed 

below, which addresses load shedding when studies underestimate real time conditions. 
Docket No. RM07-3-000 - 6 - 

8. Both FAC-010-1 and FAC-011-1 include an Interconnection-wide regional 

difference for the Western Interconnection administered by WECC. These regional 

differences incorporate a more detailed methodology to determine SOLs based on 

specified multiple contingencies. They also provide that the “Western Interconnection 

may make changes” to the contingencies required to be studied and/or the required 

responses to contingencies for specific facilities. 

9. Reliability Standard FAC-014-1 requires each reliability coordinator, planning 

authority, transmission planner and transmission operator to develop and communicate 

SOL limits in accordance with the methodologies developed pursuant to FAC-010-1 and 

FAC-011-1. FAC-014-1 requires the reliability coordinator to ensure that SOLs are 

established for its “reliability coordinator area” and that the SOLs are consistent with its 

SOL methodology. It provides that each transmission operator, planning authority and 

transmission planner must establish SOLs as directed by its reliability coordinator that are 

consistent with the reliability coordinator’s methodology. Further, FAC-014-1 requires 

the reliability coordinator, planning authority and transmission planner to provide its 

SOLs to those entities that have a reliability-related need.7

 

 7

 The Notice of Proposed Rulemaking (NOPR) provides additional background on 

the content of each FAC Reliability Standard. Facilities, Design, Connections and 

Maintenance Mandatory Reliability Standards, Notice of Proposed Rulemaking, 72 FR 

160 (Aug. 20, 2007), FERC Stats. And Regs. ¶ 32,622, at P 9-36 (Aug. 13, 2007). 
Docket No. RM07-3-000 - 7 - 

C. Notice of Proposed Rulemaking

10. On August 13, 2007, the Commission issued a NOPR proposing to approve 

Reliability Standards FAC-010-1, FAC-011-1 and FAC-014-1 as mandatory and 

enforceable Reliability Standards. The Commission also proposed to approve regional 

differences to FAC-010-1 and FAC-011-1 applicable to the Western Interconnection. In 

addition, the Commission sought ERO clarification and public comment on whether the 

FAC Reliability Standards are consistent with the Commission’s transmission reform 

efforts in Order No. 8908

 and with the transmission planning (TPL) Reliability Standards. 

The NOPR also sought ERO clarification and public comment on the scope of operating 

contingencies and appropriate responses under the Reliability Standard requirements, on 

the Commission’s proposal to approve the WECC regional difference, and on the WECC 

contingency designation and revision process should be incorporated into the Reliability 

Standard. Further, the Commission proposed certain clarifications to NERC’s glossary 

revisions. 

11. After submitting these FAC Reliability Standards, NERC filed proposed Violation 

Risk Factors that correspond to each Requirement of the proposed Reliability Standards.9

 

 8

 Preventing Undue Discrimination and Preference in Transmission Service, Order 

No. 890, 72 FR 12266 (Mar. 15, 2007), FERC Stats. & Regs. ¶ 31,241 (2007). 

9

 See NERC, Request for Approval of Violation Risk Factors for Version 1 

Reliability Standards, Docket No. RR07-10-000, Exh. A (March 23, 2007); and NERC, 

Request for Approval of Supplemental Violation Risk Factors for Version 1 Reliability 

Standards, Docket No. RR07-12-000, Exh. A (May 4, 2007). In its orders addressing the 

 (continued...) 
Docket No. RM07-3-000 - 8 - 

According to NERC, Violation Risk Factors measure the relative risk to the Bulk-Power 

System associated with the violation of Requirements within the Reliability Standards. 

Procedural Matters

12. The Commission required that comments be filed within 30 days after publication 

in the Federal Register, or September 19, 2007. Approximately 21 entities filed 

comments, including several late-filed comments. The Commission accepts these late 

filed comments. Appendix B provides a list of the commenters. 

III. Discussion

13. This order approves the FAC Reliability Standards, as discussed below.10 In 

approving the FAC Reliability Standards, the Commission concludes that they are just, 

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

three Reliability Standards serve an important reliability purpose in ensuring that SOLs 

used in the reliable planning and operation of the Bulk-Power System are determined 

based on an established methodology. Moreover, they clearly identify the entities to 

which they apply and contain clear and enforceable requirements. The Commission also 

 

violation risk factors, the Commission addressed only those Violation Risk Factors 

pertaining to the 83 Reliability Standards approved in Order No. 693. North American 

Electric Reliability Corp., 119 FERC ¶ 61,145, at P 14 (2007) (Violation Risk Factor 

Order) and North American Electric Reliability Corp., 119 FERC ¶ 61,321, at P 4 (2007) 

(Supplemental VRF Order). 

10 The three Reliability Standards will not be published in revised Commission 

regulations, but instead are available in Appendix C through the Commission’s eLibrary 

document retrieval system in Docket No. RM07-3-000 and will be posted on NERC’s 

website, https://standards.nerc.net/. 
Docket No. RM07-3-000 - 9 - 

accepts the WECC regional differences contained in FAC-010-1 and FAC-011-1. The 

Commission will discuss particular issues below as appropriate.11

14. The Commission also directs NERC to modify FAC-011-1, Requirement 2.3. In 

addition, we accept NERC’s proposals to add or revise the following terms in the NERC 

glossary: “Delayed Fault Clearing,” “Interconnection Reliability Operating Limit 

(IROL),” and “Interconnection Reliability Operating Limit Tv (IROL Tv).”12 However, 

for the reasons explained below, we remand NERC’s definition of “Cascading Outages” 

subject to NERC refiling. Finally, with respect to the Violation Risk Factors, we accept 

certain Violation Risk Factors but direct NERC to revise the Violation Risk Factors that 

are inconsistent with the Commission’s Violation Risk Factor guidelines, as discussed 

below. 

A. General Matters

15. Several commenters sought clarification of the Commission’s procedural 

approach, arguing that changes to Reliability Standards and glossary terms should be 

 11 In addition to the issues discussed, the NOPR requested that NERC clarify its 

proposals to replace the term “regional reliability organization” with the term Regional 

Entity and to incorporate references to the “planning coordinator” function into the 

Reliability Standards. We are satisfied with the explanations provided by NERC. 

12 In Order No. 693 at P 1893-98, the Commission approved the NERC glossary, 

directing specific modifications to the document. 
Docket No. RM07-3-000 - 10 - 

made through the NERC Reliability Standards development process.13 Some 

commenters question the Commission’s authority to require NERC to make specific 

revisions to the Reliability Standards and glossary terms.14 

Commission Determination

16. In response to commenters’ concerns about the Commission’s procedural 

approach, section 215(d) of the FPA provides that the Commission shall give due weight 

to the technical expertise of the ERO with respect to the content of a proposed Reliability 

Standard or modification to a Reliability Standard; and the Commission fully intends to 

faithfully implement this provision. Further, the Commission affirms the approach set 

forth in Order No. 693 that: 

[A] direction for modification should not be so overly 

prescriptive as to preclude 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.[15] 

17. Thus, in directing modification to FAC-011-1, while we provide specific details 

regarding the Commission’s expectations, we intend by doing so to provide useful 

 13 See Progress Energy Comments at 2 (citing Order No. 672 at P 40, 249 and 

344); see also EEI and APPA, and NRECA Comments. 

14 See, e.g., NRECA Comments. 

15 Order No. 693 at P 185. 
Docket No. RM07-3-000 - 11 - 

guidance to assist in the Reliability Standards development process, not to impede it.16 

As stated in Order No. 693, 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.17 

Consistent with Order No. 693, while the Commission offers a specific approach to 

address our concern with FAC-011-1, 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.18

B. Specific Issues

1. Consistency with Order No. 890

18. The NOPR stated the Commission’s concern that the FAC Reliability Standards 

called for the development of distinct methodologies to calculate system transfer limits 

and that these methodologies might differ from those used in the planning and operations 

horizons to develop available transfer capability (ATC) and total transfer capability 

(TTC) transfer limits. The NOPR explained that Order No. 890 amended the pro forma

open access transmission tariff (OATT) to provide greater specificity to reduce 

opportunities for undue discrimination and increase transparency in the rules applicable 

 16 Order No. 693 at P 186. 

17 FPA section 215(d)(5), 16 U.S.C. 824o(d)(5) (2000 & Supp. V 2005). 

18 Order No. 693 at P 186. 
Docket No. RM07-3-000 - 12 - 

to planning and use of the transmission system.19 Specifically, Order No. 890 requires 

the consistent use of assumptions underlying operational planning for short-term ATC 

calculations and expansion planning for long-term ATC calculations.20 

19. The NOPR noted that FAC-010-1 requires each planning authority to document its 

methods for determining system operating limits or SOLs for the planning horizon. 

However, the SOLs may affect ATC by determining transmission path or system 

interface limits. Furthermore, the NOPR noted that use of multiple contingency analyses 

would generally result in lower SOLs. The Commission expressed concern about 

potentially disparate results for calculating transfer limits under two methodologies, the 

first being the proposed Reliability Standard FAC-010-1 methodology for calculation of 

SOLs for the planning horizon and another being the methodology for calculating longterm ATC pursuant to NERC’s Modeling, Data, and Analysis (MOD) Reliability 

Standards. Therefore, the NOPR requested comment whether having separate 

methodologies was consistent with the Order No. 890 requirement to use consistent 

assumptions. 

20. The Commission had previously found that calculations of TTC transfer limits 

calculated under other FAC Reliability Standards, specifically FAC-012-1, were 

essentially the same as transfer limits calculated for modeling purposes under the MOD 

 19 NOPR at P 18-19 (citing Order No. 890 at P 290-95). 

20 Order No. 890 at P 290-95. 
Docket No. RM07-3-000 - 13 - 

Reliability Standard, MOD-001-1, and therefore required the calculations to be addressed 

under a single Reliability Standard. The NOPR set out two specific concerns, the first 

being whether there is a potential for undue discrimination as a result of the use of single 

and multiple contingencies in different contexts. The second concern was whether the 

use of different approaches to transfer limit calculations under FAC-010-1, under review 

in this proceeding on the one hand, and FAC-012-1, which was previously approved in 

Order No. 693, was consistent with the Commission’s prior determination that NERC 

should not establish multiple Reliability Standards for the same purpose. 

21. The NOPR raised similar issues for Reliability Standard FAC-011-1. Specifically, 

the Commission was concerned with the potential exercise of undue discrimination given 

the possibility for differing results with the use of single and multiple contingency 

analyses for SOLs in the operating horizon under FAC-011-1 and short-term ATC 

calculations, and second whether consistency was better reflected through coordinated 

and consistent criteria for the calculation of operating horizon SOLs and short-term ATC. 

We will address these issues in the context of FAC-010-1 and FAC-011 together, given 

the common issue to both Reliability Standards. Most commenters address the concerns 

together as well. 

Comments on Undue Discrimination

22. NERC, as well as the majority of industry representatives, takes the position that 

there is no potential for undue discrimination with the addition of the FAC SOL 
Docket No. RM07-3-000 - 14 - 

methodologies,21 in particular if consistency is provided for among the FAC, planning 

and operations methodologies.22 The NERC comments state that its draft ATC 

Reliability Standard requirements provide for consistency with the FAC-010-1 and FAC011-1 assumptions and conditions. The NERC comments describe this coordination: 

Draft reliability standard MOD-028-1 — Area Interchange 

Methodology requires the transmission operator to document 

that its model uses the same facility ratings as provided by the 

transmission owner. It also requires that the assumptions and 

contingencies used in determining TTC be consistent with 

those used for the same time horizon in operations and 

planning studies. 

Draft MOD-029-1 — Rated System Path Methodology 

requires the transmission operator to document that its model 

uses the same facility ratings as provided by the transmission 

owner. It also requires that the assumptions and 

contingencies used in determining TTC be consistent with 

those used for the same time horizon in operations and 

planning studies. 

Draft MOD-030-1 — Flowgate Methodology requires the 

transmission operator to document that its model uses the 

same facility ratings as provided by the transmission owner. 

It also requires that the assumptions and contingencies used in 

determining flowgates to match the contingencies and 

assumptions used in operations studies and planning studies 

for the applicable time periods. The links between the FAC 

standards and the MOD standards outlined above support the 

Commission’s directives in Order 890 regarding the 

 21 See, e.g., NERC and EEI and APPA Comments. 

22 See, e.g., MidAmerican, NYSRC and NYISO, PG&E, Progress Energy, 

Southern and WECC Comments. EPSA argues that ATC assumptions cannot be more 

stringent than planning assumptions to ensure that capacity is adequate. 
Docket No. RM07-3-000 - 15 - 

transparency requirements and mitigate potential for the 

exercise of undue discrimination.[23] 

23. According to NERC, this ensures that the contingencies and assumptions used in 

the planning horizon under FAC-010-1 and the contingencies and assumptions used in 

the operating horizon under FAC-011-1 are consistent with the contingencies and 

assumptions used in calculating TTC and ATC for various time horizons. 

24. Supplier and customer groups argue that there is a potential for undue 

discrimination if system operation and planning are not executed in a manner that is 

consistent with short- and long-term TTC assumptions.24 Some commenters assert that 

there is no potential for discrimination in independently operated independent system 

operator (ISO) and regional transmission organization (RTO) systems.25 The 

commenters largely agree that the potential for undue discrimination is mitigated insofar 

as the Order No. 890 transparency requirements promote open and consistent ATC 

calculations, because transparency allows any party to review and challenge the SOL 

criteria and methodology.26 

 23 NERC Comments at 18-20. 

24 See EPSA and NRECA Comments. 

25 See NYISO and Ontario IESO, ISO/RTO Council, and NYSRC and NYISO 

Comments. 

26 See, e.g., Duke and EPSA Comments; but see NRECA Comments (arguing that 

differences between operating and planning assumptions make new users vulnerable to 

confusion). 
Docket No. RM07-3-000 - 16 - 

25. NERC and others emphasize the consistency and coordination already required 

between the contingencies and assumptions used to determine SOLs for the planning 

horizon under the SOL methodology specified in FAC-010-1, on the one hand, and the 

contingencies and assumptions to develop TTCs which determine ATC. NERC states 

that FAC-010-1 requires planning authorities to have an explicit methodology to develop 

SOLs and must make this methodology available to all parties having a reliability-related 

need for the methodology or the limits so determined. This openness mitigates or 

prevents the exercise of undue discrimination.27

26. Furthermore, NERC states that the FAC Reliability Standards are coordinated with 

the development of pending MOD Reliability Standards, and this coordination supports 

transparency and mitigates the potential for the exercise of undue discrimination, 

consistent with Order No. 890. NERC notes that Order No. 693 did not approve 

Reliability Standard MOD-001-0 but directed specific improvements. Consequently, 

NERC is revising that Reliability Standard and preparing the three draft Reliability 

Standards described above. These draft Reliability Standards will set forth three 

currently used TTC and ATC calculation methodologies.28 Although each of these three 

 27 BPA, PG&E and WECC agree that disclosure mitigates the potential for undue 

discrimination. Ameren argues that the list provided for in FAC-014-1, Requirement R6 

should be supplied to the relevant transmission provider and transmission operator, in 

addition to the Planning Authority. 

28 See NERC Comments at 9-10 for a description of the methodologies. 
Docket No. RM07-3-000 - 17 - 

methodologies provides a different approach to the calculation of TTC, all require 

consistency between the contingencies and assumptions used in the determination of TTC 

and the contingencies and assumptions used in operating and planning studies for 

concurrent time periods. 

27. EEI and APPA are concerned that the Commission may be duplicating efforts 

underway pursuant to Order Nos. 890 and 693, which addressed competitive and 

reliability policy issues associated with the development and posting of ATC and TTC. 

EEI and APPA note that public utility transmission providers have recently posted for 

public review and comment the proposed Attachment Ks to their OATTs, proposing 

transmission planning and expansion methodologies, while a NERC Reliability Standards 

drafting team is developing a Reliability Standard covering the calculation of all elements 

of transfer capability, including ATC and TTC. According to EEI and APPA, the work 

of the NERC ATC Reliability Standard drafting team builds on the Reliability Standard 

proposed for Commission approval in this proceeding. EEI and APPA recommend that 

the Commission allow the industry to complete the intensive work required for 

implementation of Order Nos. 890 and 693 without the uncertainty that the Commission 

may seek to modify the scope and direction already established through material changes 

to the Reliability Standards proposed for approval in this proceeding. 

28. The ISO/RTO Council comments that there may be the potential for undue 

discrimination, but not in grids operated by ISOs due to the lack of economic incentives. 

Furthermore, because ISOs and RTOs operate centralized dispatch markets, they do not 
Docket No. RM07-3-000 - 18 - 

rely on physical path reservations within their boundaries. Therefore, these commenters 

conclude that ATC calculation is not critical.29 

29. Other commenters claim that coordination should not be so stringent to interfere 

with the different uses for the different transfer limit methodologies. MidAmerican 

maintains that the concurrent use of single and multiple contingencies is appropriate so 

long as appropriate coordination is made for long and short term analyses and ATC and 

operations planning. MidAmerican asserts that SOLs and TTC should remain distinct to 

allow the optimum reservation and use of the transmission system, while permitting 

appropriate responses to outages in the operations horizon. MidAmerican states that 

SOLs must change to incorporate current system operating information, addressing the 

“next contingency” to remain in a secure state, and that requiring SOLs to equal TTCs 

may result in less transmission capacity available for sale or increased reliance on 

transmission loading relief. The resulting lack of capacity may prevent transmission 

providers from meeting existing transmission contract obligations. 

30. Santa Clara states that there is a need for consistency in the SOL methodology 

used by the reliability coordinator and the planning authority. Also, Santa Clara claims 

that conflicts could result for engineering design and/or operational criteria if a planning 

authority’s SOL methodology calls for single contingency analysis, but a reliability 

 29 NYSRC, NYISO and Ontario IESO take similar positions. The Commission 

notes that the cited analyses would not apply for transactions that cross ISO and RTO 

boundaries. 
Docket No. RM07-3-000 - 19 - 

coordinator or planning authority calculates long-term ATC using multiple contingencies. 

Therefore, Santa Clara concludes that FAC-010-1 and FAC-011-1 should be consistent in 

the SOL methodologies used by planning authorities and reliability coordinators. 

31. Commenters disagree as to the impact of performing SOL determinations based on 

single contingencies while ATC is calculated using multiple contingencies. Several 

commenters argue that when SOLs are determined using single contingencies and ATC is 

calculated using multiple contingencies, the lack of consistency could permit 

discrimination in ATC calculation for transmission service.30 EPSA argues that this 

potential must be addressed to fulfill the Order No. 890 requirement that transmission 

providers use short and long-term ATC data and modeling assumptions that are 

consistent with operations and system expansion assumptions. Also, EPSA states that 

under Order No. 890 the Commission must ensure that planning and service capacity 

calculations are consistent and non-discriminatory. EPSA argues that FAC Reliability 

Standards that affect transmission planning cannot be divorced from the calculation of 

ATC and that use of different assumptions for planning and ATC could lead to 

inadequate capacity. 

32. Ameren states that Reliability Standards should not impose inconsistent 

obligations on system users, but notes some calculations that appear similar may be 

 30 See, e.g., EPSA and NYISO and NYSRC Comments. NRECA agrees that there 

is a potential for undue discrimination when there are differences in the treatment of 

single and multiple contingencies in the near and long-term. 
Docket No. RM07-3-000 - 20 - 

different due to different applications. For instance, SOL system limit calculations may 

differ from planning calculations due to their application to different time frames. 

Ameren argues that FAC-010 should be consistent with the transmission planning 

Reliability Standard TPL-002-0 for the long-term planning horizon, but acknowledges 

that FAC-010 may not be consistent with TPL-002-0 for the near-term planning horizon, 

to accommodate overload or low voltage mitigation efforts. Ameren requests that, to 

prevent the imposition of conflicting obligations, the Commission not accept the 

Reliability Standards and direct NERC to monitor the interrelated Reliability Standards 

for consistency. 

33. NRECA maintains that different methodologies may discriminate in particular 

against new entrants who are unfamiliar with the differences. NRECA states that there 

are some circumstances in which a transmission provider may be able to benefit because 

it will have preferential access to transmission expansion information, especially where 

the planning authority and reliability coordinator reside in the same corporate family. 

34. Several commenters request that the Commission delay approval and direct the 

ERO to evaluate the issues.31 Progress Energy asserts that, to ensure consistency, the 

planning authority and reliability coordinator should use the same number of 

contingencies and the same categories of facility ratings to determine these values for its 

transmission system. EPSA argues that ATC assumptions cannot be more stringent than 

 31 See, e.g., NYSRC and NYISO, and NRECA Comments. 
Docket No. RM07-3-000 - 21 - 

planning assumptions and that SOL contingencies must “be in balance” with ATC 

contingencies. 

Comments on Consistency for SOLs, Transfer Capability and TTC 

35. The second concern set out in the NOPR concerned whether the existence of 

different approaches to transfer limit calculations under FAC-010-1 and FAC-011, on the 

one hand, and FAC-012-1, on the other, was consistent with the Commission’s prior 

determination that calculations of TTC transfer limits calculated under the FAC 

Reliability Standards were essentially the same as transfer limits calculated for Modeling 

purposes under the MOD Reliability Standard, MOD-001-1. Foreseeing a similar 

connection between facility transfer limit calculations under FAC-010-1 and ATC 

transfer limit calculations, the NOPR requested comment whether the FAC Reliability 

Standards should reflect any such consistency. 

36. NERC states that the TPL Reliability Standards set the foundation for the types of 

contingencies to be considered for the Requirements in the FAC Reliability Standards. 

The FAC Reliability Standards are intended to be consistent with the set of contingencies 

identified in the TPL Reliability Standards. The FAC Reliability Standards define 

facility ratings and system operating limits that are used as the basis for limits that are 

used in the determination of the ATC values within MOD Reliability Standards. As the 

TPL series of Reliability Standards are modified, conforming changes to the FAC and/or 

MOD series of Reliability Standards are expected to be necessary to ensure consistency 

in the list of contingencies. 
Docket No. RM07-3-000 - 22 - 

37. In response to the Commission’s statement that SOLs will change as additional 

contingencies are considered, EEI and APPA provide a description of how IROLs and 

SOLs are determined. When IROL and SOL values are determined, they are based on a 

worst-contingency criterion as defined by applicable planning or operating criteria for a 

given set of Bulk-Power System conditions. Therefore, according to EEI and APPA, 

unless the underlying set of system conditions change, it would be extremely unusual for 

IROL and SOL values to change.32 

38. EEI and APPA state that SOLs are calculated and used to represent thermal, 

voltage, and stability limits for planning and operation of the Bulk-Power System with 

distinct calculation methods for SOLs under the three types of limits. For instance, a 

thermal-limit SOL is determined through a contingency analysis that models a facility as 

out of service while ensuring that the resulting flow is below the thermal ratings for each 

remaining facility. A voltage or stability limit SOL is determined by monitoring the 

flows on a facility or group of facilities to ensure voltage or stability criteria are not 

exceeded. These types of SOLs are commonly defined by planning authorities in their 

periodic studies, based on the pertinent Reliability Standards and other planning or 

operations criteria. 

 32 Cf. MidAmerican Comments at 7 (stating that SOLs change to account for 

actual or planned outages); and Southern Comments at 4-5 (noting that historically, 

power flow analyses were used to develop SOLs in the absence of real time data, but that 

it is now possible to perform real-time contingency analysis and identify SOLs based on 

actual system conditions and facility loads). 
Docket No. RM07-3-000 - 23 - 

39. Other commenters generally agree that SOLs and TTCs are not the same.33 

Several commenters describe SOLs as one of many inputs used to develop TTC and, 

consequently, ATC.34 Commenters distinguish SOLs and TTC/ATC, noting that TTC 

and ATC are defined by path (i.e., between a receipt point and delivery point) whereas an 

SOL applies to the discrete facilities that comprise the interconnected generation and 

transmission system (such as conductors, breakers and transformers). Also, SOLs vary 

based on season because of changes in ambient temperature, anticipated weather, and 

other variations in operational conditions.35 In contrast, TTC and ATC are recalculated 

dependent on other circumstances including system usage and contractual reservations. 

These and other differences prompt the commenters to state that the processes for 

determining SOLs and TTC/ATC are necessarily different. 

40. Several commenters note that SOL, ATC and TTC perform different functions.36 

These commenters concur that while assumptions should generally be consistent, 

 33 See, e.g., NERC, Progress Energy, WECC, Southern, Duke, PG&E and SoCal 

Edison Comments. 

34 See, e.g., NERC, Progress Energy, Duke, PG&E and SoCal Edison Comments. 

35 See, e.g., NERC and Progress Energy Comments; see also WECC Comments. 

Although comments vary as to whether SOLs are permanently set or may be updated 

based on new information, this apparent disagreement appears to stem from use of 

different terms. Thus, while individual facility ratings are unlikely to change, the 

particular facility that is establishing the system limits in the N-1 contingency analysis 

will vary as conditions change and adjustments are made. 

36 See ISO/RTO Council and Southern Comments. 
Docket No. RM07-3-000 - 24 - 

complete consistency is neither achievable nor desirable. Duke states that while both 

SOLs and TTC may be based on fixed dispatch and interchange, FAC-010-1, or varying 

dispatch and interchange, FAC-011-1, they should still be evaluated against the same N-1 

contingencies in a coordinated and consistent manner. 

41. Most commenters argue in favor of coordination of SOL and TTC assumptions 

and conditions but disagree on the degree to which such consistency requires additional 

explicit guidance in the Reliability Standards. NERC maintains that the proposed FAC 

Reliability Standards and the MOD Reliability Standards under development already 

require consistency between one another with respect to assumptions and contingencies 

and additional coordination is not needed to support the Commission’s directives in 

Order No. 890. SoCal Edison concurs that actual coordination is not necessary, but 

suggests that the ATC-related Reliability Standards reference the FAC Reliability 

Standards to provide clarity. 

42. Southern requests, in response to FAC-011-1, that the Commission clarify that a 

policy of consistency between short-term ATC calculations and operations planning, on 

the one hand, and long-term ATC calculations and system expansion planning on the 

other does not support a finding that data and modeling assumptions for short-term 

assessments should be consistent with assumptions for long-term assessments. While 

assumptions are generally consistent, complete consistency is neither achievable nor 

desirable. 
Docket No. RM07-3-000 - 25 - 

43. EPSA states that the Commission must ensure that planning and service capacity 

are calculated on a consistent, non-discriminatory basis, and argues that planning based 

on single contingencies combined with multiple contingency ATC calculations could lead 

to an inefficient transmission system, where service reservations cannot be met in real 

time. 

44. NYSRC and NYISO argue that multiple contingency analyses in the operating 

horizon under FAC-011-1, such as that employed by WECC, should be applied in all of 

North America. NYSRC and NYISO note that their Regional Entity, Northeast Power 

Coordinating Council (NPCC), has included a multiple element requirement in its 

operating criteria for 40 years without problems. They conclude that multiple element 

contingencies are not uncommon and the system’s ability to survive such incidents 

should be supported by appropriate operating Reliability Standards, not left to chance. 

45. NYSRC and NYISO states that the FAC-011-1 drafting team maintains that lower 

operating limits due to multiple element requirements would restrict competition. 

However, NYSRC and NYISO argue that this suggests that the mere possibility that a 

Reliability Standard may restrict competitive transactions is not a sufficient reason for not 

adopting the Reliability Standard, even if it would be effective in maintaining system 

reliability. They contend that permitting competitive concerns to outweigh reliability 

would be inconsistent with the Commission’s responsibility to ensure reliability. 
Docket No. RM07-3-000 - 26 - 

Commission Determination

46. The Commission will not direct NERC to revise the FAC Reliability Standards to 

address Order No. 890 consistency issues. Given that the SOLs developed pursuant to 

the FAC Reliability Standards will be inputs to the calculation of TTC and ATC under 

the MOD Reliability Standards currently under development, the Commission agrees 

with commenters that SOLs are not the same as TTC used for ATC calculation. 

However, we note that SOLs are a significant component in TTC calculation. 

47. Further, the Commission is persuaded by NERC’s comments that it will 

coordinate the assumptions and conditions considered in system planning under the TPL 

Reliability Standards, SOL determination under the FAC Reliability Standards and TTC 

calculation under the MOD Reliability Standards. 

48. At this time, the Commission disagrees with the commenters that argue that there 

is a potential for undue discrimination in the FAC Reliability Standards. The 

Commission raised the question regarding the application of the SOL methodology in the 

FAC Reliability Standards compared with the calculation of ATC. However, NERC has 

not at this time filed the Reliability Standards concerning TTC and ATC calculation. The 

Commission notes that it has previously provided directives concerning the need for 

coordination and consistency among short- and long-term ATC calculations, operations 

planning and system expansion determinations. The Commission agrees with 

commenters that the directives concerning consistency in Order Nos. 693 and 890 should 

alleviate concerns about the potential for undue discrimination. These directives are 
Docket No. RM07-3-000 - 27 - 

currently being addressed by NERC in Reliability Standards under development. We 

will not change those directives in this proceeding. When NERC files revised MOD 

Reliability Standards for calculating ATC or TTC, the Commission will review the 

resulting Reliability Standards for compliance with our directives in Order Nos. 890 and 

693 concerning consistency for SOLs, transfer capability and TTC.37 

49. Because the TPL series of Reliability Standards sets the foundation for the types 

of contingencies to be considered to meet requirements in the FAC Reliability Standards, 

and the FAC Reliability Standards are intended to be consistent with the set of 

contingencies identified in the TPL Reliability Standards, the Commission would be 

concerned if the TPL Reliability Standards use one set of contingencies to plan the 

system, while the FAC Reliability Standards generate another set to calculate SOLs in the 

planning horizon. As NERC acknowledges, as the TPL series of Reliability Standards is 

modified, conforming changes to the corresponding lists of contingencies in the FAC or 

MOD series of Reliability Standards are expected to be necessary to ensure consistency 

in the list of contingencies. Similarly, the Commission believes that as FAC or MOD 

Reliability Standards are updated, the TPL series of Reliability Standards must be 

updated to remain consistent. Therefore, we direct that any revised TPL Reliability 

Standards must reflect consistency in the lists of contingencies between the two 

 37 Our determination here not to revise prior directives also addresses Southern’s 

request, in response to FAC-011-1, that the Commission clarify its policy of consistency 

between operations planning and system expansion planning relative to TTC calculations. 
Docket No. RM07-3-000 - 28 - 

Reliability Standards.38 Should NERC file such revised TPL Reliability Standards, the 

Commission will review the resulting Reliability Standards for compliance with our 

directives in Order Nos. 890 and 693 concerning consistency for SOLs, transfer 

capability and TTC. 

2. Loss of Consequential Load 

50. The NOPR requested that NERC, as the ERO, clarify the discussion of network 

customer interruption in FAC-010-1, Requirement R2.3. Requirement R2.3 provides that 

the system’s response to a single contingency may include, inter alia, “planned or 

controlled interruption of electric supply to radial customers or some local network 

customers connected to or supplied by the Faulted Facility or by the affected area.”39 

The NOPR asked whether this provision is limited to the loss of load that is a direct result 

of the contingency, i.e., consequential load, or whether this provision allows firm load 

shedding and firm transmission curtailment following a single contingency.40 

 38 Similar consistency issues may arise with the transmission operating and 

planning (TOP) Reliability Standards because those Reliability Standards implement the 

SOLs and IROLs determined in the FAC Reliability Standards. 

39 Identical language appears in FAC-011-1, Requirement R2.3. Our analysis 

applies to that provision as well. 

40 Order No. 693 defined consequential load, at P 1794 n.461: “Consequential 

load is the load that is directly served by the elements that are removed from service as a 

result of the contingency.” 
Docket No. RM07-3-000 - 29 - 

Comments

51. NERC clarifies that the provision in FAC-010-1, Requirement R2.3 is limited to 

loss of load that is a direct result of the contingency, i.e., consequential load loss. Several 

commenters concur with that interpretation.41 NYSRC and NYISO state that in NPCC, 

firm-load shedding is only allowed following a recognized contingency if reliability 

cannot be assured for a subsequent contingency through normal control actions (citing 

dispatch and use of direct current sources). 

52. Ameren states that for the long term planning horizon, no load is dropped except 

for load served directly by an out-of-service facility. However, in the operational or near 

term planning horizon, operating guidelines may call for dropping load to mitigate 

overload or low-voltage conditions until the necessary system reinforcements or 

restorations are completed. Therefore, Ameren thinks a distinction is appropriate. 

Commission Determination

53. In response to the NYSRC and NYISO comments, the Commission reiterates its 

holding that addressed similar language on loss of load in Order No. 693, regarding 

Reliability Standard TPL-002-0. In Order No. 693, the Commission noted that “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 

 41 See, e.g., NYSRC, NYISO, Ontario IESO, SoCal Edison and Southern 

Comments. 
Docket No. RM07-3-000 - 30 - 

resort to prevent cascading failures.”42 Order No. 693 stated that the transmission system 

should not be planned to permit load shedding for a single contingency.43 Order No. 693 

directed NERC to clarify the planning Reliability Standard TPL-002-0 accordingly. The 

Commission reaches the same conclusion here. We will approve Reliability Standard 

FAC-010-1, Requirement R2.3 and the ERO should ensure that the clarification 

developed in response to Order No. 693 is made to the FAC Reliability Standards as well. 

Ameren’s comments concerning the operational timeframe do not affect FAC-010-1, 

which concerns the planning time frame. 

3. Loss of Shunt Device

54. The NOPR requested comment on Requirement R2.2 of FAC-010-1 and the 

corresponding Requirement R2.2 of FAC-011-1, which include the loss of a shunt device 

among the various single contingencies that a planning authority must address.44 The 

NOPR noted that although the TPL Reliability Standards implicitly require the loss of a 

shunt device to be addressed, they do not do so explicitly. Therefore, the NOPR 

requested comment whether NERC should revise the TPL Reliability Standards to be 

 42 Order No. 693 at P 1788. 

43 Id. P 1792 & n.460 and 1794 (stating “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”). 

44 NOPR at P 23, 33. 
Docket No. RM07-3-000 - 31 - 

consistent with FAC-010-1 and FAC-011-1 by explicitly requiring the consideration of a 

shunt device.

Comments

55. NERC explains that although the TPL Reliability Standards sets the foundation for 

the types of contingencies to be considered for the FAC Reliability Standards. While the 

FAC Reliability Standards were developed after TPL-001-0, TPL-002-0, TPL-003-0 and 

TPL-004-0 were approved by the NERC board, NERC and Southern report that the FAC 

Reliability Standards drafting team recognized that TPL Table 1 needed clarity. 

Accordingly, NERC states that the drafting team modified the language from Table 1 in 

an effort to add clarity. According to NERC, the intent of the FAC Reliability Standard 

drafting team was to use the TPL contingencies as the definitional basis for SOL 

determination. Moreover, NERC states that the contingencies used in the FAC 

Reliability Standards are consistent with the contingencies identified in the TPL 

Reliability Standards, with the exception of the shunt device noted. 

56. NERC notes that the TPL Reliability Standards are currently under revision. As 

the TPL Reliability Standards are modified, NERC states that conforming changes may 

need to be made to the FAC Reliability Standards to maintain consistency between the 

TPL Reliability Standards and the FAC Reliability Standards. At this time, NERC does 

not recommend modifying the TPL Reliability Standards to include a specific reference 

to shunt devices based on these FAC Reliability Standards and states that such a 

Commission directive is not necessary. 
Docket No. RM07-3-000 - 32 - 

57. Commenters disagree whether the TPL Reliability Standards should be updated to 

address the loss of a shunt devise. Ameren and ISO/RTO Council state that the TPL 

requirements should be clarified to address shunt devices, while NRECA does not believe 

that a loss of a shunt device should be specifically named as a single contingency in the 

TPL Reliability Standards. Furthermore, NRECA believes that such a determination is 

within the ERO’s technical expertise, is entitled to due weight and should therefore be 

pursued by the ERO, rather than the Commission. 

Commission Determination

58. As discussed, the FAC Reliability Standards explicitly reference shunt devices as 

one of the contingencies to be examined in setting SOLs, whereas the TPL Reliability 

Standards do not explicitly reference shunt devises. NERC reports that this difference is 

a result of administrative lag in the preparation of the lists of single contingencies to be 

accounted for in analyses under the two sets of Reliability Standards. Based on NERC’s 

statement that it is currently addressing disparate treatment of shunt devices by revising 

the appropriate TPL Reliability Standards through the Reliability Standards development 

process, we will accept Requirement R2.2 of FAC-010-1 and Requirement R2.2 of FAC011-1. Given the current efforts to promote consistency among planning, operations and 

TTC calculations and assumptions, the Commission expects NERC to address any 

inconsistencies in the treatment of shunt devices in revised TPL Reliability Standards. In 

the event that an alternative approach is developed and proposed by the ERO, NERC is 
Docket No. RM07-3-000 - 33 - 

required to provide an adequate justification for any differing treatment among the 

particular facilities considered in the various Reliability Standards. 

4. Load Forecast Error under FAC-011-1

59. As described in the NOPR, Requirement R2.3.2 of FAC-011-1 provides that the 

system’s response to a single contingency may include, inter alia, “[i]nterruption of other 

network customers, only if the system has already been adjusted, or is being adjusted, 

following at least one prior outage, or, if the real-time operating conditions are more 

adverse than anticipated in the corresponding studies, e.g., load greater than studied.”45 

In the NOPR, the Commission requested that NERC clarify the meaning of the phrase “if 

the real-time operating conditions are more adverse than anticipated in the corresponding 

studies, e.g., load greater than studied.” In particular, the Commission questioned 

whether this provision treats load forecast error as a contingency and would allow an 

interruption due to an inaccurate weather forecast. 

Comments

60. NERC states that deviations between anticipated conditions and real-time 

conditions, such as load forecast errors, are not contingencies by definition in the NERC 

glossary. However, in real-time, the operators must take the actions necessary to 

maintain bulk electric system reliability given current conditions. Available actions 

include load shedding if operating conditions warrant. 

 45 NOPR at P 25. 
Docket No. RM07-3-000 - 34 - 

61. NERC states that when the real-time operating conditions do not match the 

assumed studied conditions, the deviation can reach a magnitude such that the operator 

must take actions different from those anticipated by the study. From that perspective, 

the study error has the same affect on the bulk electric system as many actual 

contingencies. While these deviations do not meet the approved definition of a 

“contingency” in NERC’s glossary, NERC states that system operators need to react to 

these unexpected circumstances expeditiously and interruption of other network 

customers is allowed and expected if conditions warrant such an action. NERC maintains 

that this provision is necessary to ensure that system operators have the ability to shed 

load without penalty to preserve the integrity of the bulk electric system. Thus, while it 

does not classify and study forecast error as a “contingency,” NERC asserts that a 

significant gap between actual and studied conditions (such as a large error in load 

forecast) can be treated as though it were a contingency under the proposed Reliability 

Standard. 

62. NERC states that all anticipatory studies must begin with a reasonable set of 

assumptions.46 According to NERC, when “real time” approaches that time period that 

was assessed by the particular anticipatory study, real time conditions may not replicate 

 46 See NERC Comments at 26. NERC states that these assumptions would 

include: (1) existing and scheduled transmission outages for that time period, (2) existing 

and scheduled generation outages for that time period, (3) projected generation dispatch 

for that time period, (4) predicted status of voltage control devices, and (5) load level and 

load diversity for the future time period being scheduled. 
Docket No. RM07-3-000 - 35 - 

the predicted state. For example, unscheduled transmission outages may have occurred, 

generation outages may have occurred, the system could be operating with one or more 

Transmission Loading Relief procedures or other congestion management action such as 

redispatch in effect requiring a different generation dispatch than anticipated when the 

applicable study was being conducted. Moreover, the actual load level and load diversity 

could be different than forecasted and used in the corresponding study, or the 

transmission facility loading levels could be significantly higher than studied because any 

of or all of the conditions above – either on the system being studied or on near-by 

systems. 

63. NERC asserts that FAC-011-1, Requirement R2.3.2 allows interruption of network 

customers following a contingency and in anticipation of the next potential unscheduled 

event if the real-time operating conditions are more adverse than anticipated. The 

adjustment in response to an unscheduled outage or load forecast error, for example, 

would be to return to a reliable state, recognizing the conditions as they exist at the time 

— available generation, transmission configuration, available reactive resources, load 

level and load diversity, and conditions on other systems. 

64. Similarly, FirstEnergy argues that no change should be made, because FAC-011-1 

is intended to permit a system operator to implement the best reliability response, but 

does not require an inquiry into the cause of system conditions. 

65. ISO/RTO Council views “load greater than studied” as providing an example of 

when “real-time operating conditions are more adverse then studied,” not as a qualifier of 
Docket No. RM07-3-000 - 36 - 

that language. ISO/RTO Council does not support treating load forecast error as a 

contingency. While load forecast error may be unpredicted, normally time is available 

for adjustments. Commenters note that operating reserve requirements should provide 

sufficient margin for error, as reflected in the NERC glossary.47 

66. Southern and NRECA comment that load forecast error is not a contingency, but is 

a failure in one element of the data that make up the day-ahead study base case. The dayahead study is used to identify contingencies where reliability criteria may not be met 

(that is, SOLs are exceeded). Southern argues that the purpose of this process is to lessen 

the potential for problems occurring in real time. The day-ahead study is used to 

schedule resources and outages, and adjustments are made in real time as actual 

conditions differ from forecasted conditions. To respond to changing conditions, a 

system operator may rely on switching procedures, redispatch, curtailments and load 

shedding, but load shedding should be avoided. 

67. NRECA argues that, because the matter is technical, it should be addressed by the 

ERO, through the Reliability Standards development process and not through a 

Commission rulemaking. Ameren notes that other load shedding conditions exist and 

suggests that the list of examples be expanded or that the specific reference to load 

forecast errors be removed to avoid confusion. Duke maintains that the phrase, “or if 

real-time operating conditions are more adverse than anticipated in the corresponding 

 47 See, e.g., ISO/RTO Council and NRECA Comments. 
Docket No. RM07-3-000 - 37 - 

studies, e.g., load greater than studied,” should be deleted because the focus of 

Requirement R2.3.2 is that a response to a second contingency may include interruption 

of non-consequential load, while extreme weather, while a possibility, is unrelated to 

SOL methodology or contingencies. 

Commission Determination

68. The Commission agrees with Southern, NRECA and ISO/RTO Council that load 

forecast error is not a contingency and should not be treated as such for the purposes of 

complying with mandatory Reliability Standards. NERC has failed to support its 

assertion that a significant gap between actual and studied conditions (such as a large 

error in load forecast) can be treated as though it were a contingency under the proposed 

Reliability Standard. While such a situation may cause unanticipated contingencies to 

become critical, correcting for load forecast error is not accomplished by treating the 

error as a contingency, but is addressed under other Reliability Standards. For instance, 

transmission operators are required to modify their plans whenever they receive 

information or forecasts that are different from what they used in their present plans. 

Furthermore, variations in weather forecasts that result in load forecast errors are more 

properly addressed through operating reserve requirements.48 Once the operating reserve 

 48 See, e.g., NERC, Request for Approval of Reliability Standards, Glossary of 

Terms Used in Reliability Standards, at 12 (April 4, 2006) (April 2006 Reliability 

Standards Filing) (defining Operating Reserve as “That capability above firm system 

demand required to provide for regulation, load forecast errors, equipment forced and 

 (continued...) 
Docket No. RM07-3-000 - 38 - 

is activated, BAL-002-0 requires correction through system adjustments to alleviate 

reliance on operating reserves within 90 minutes rather than treating the incorrect forecast 

as a contingency.49 NERC’s interpretation could be used to justify not taking timely 

emergency action prior to load shedding, or to influence how other Reliability Standards 

are interpreted, which could result in moving to “lowest common denominator” 

Reliability Standards. 

69. The Commission does not find that NERC’s interpretation is required by the text 

of FAC-011-1, Requirement R2.3.2. When read in connection with Requirement R2.3, it 

is clear that the operating conditions “more adverse than anticipated,” referred to in subRequirement R2.3.2 are exacerbating circumstances that are distinct from the actual 

contingency to be addressed that is referred to in Requirement R2.3. It is the existence of 

the exacerbating circumstance in combination with a separate and distinct contingency 

that triggers the potential for an interruption of network customers in R2.3.2. However, 

that reading does not support treating “load greater than studied” as a contingency. 

70. The Commission disagrees with NERC’s reading of sub-Requirement R2.3.2 and 

interpretation of the phrase “load greater than studied.” However, the Commission finds 

 

scheduled outages and local area protection. It consists of spinning and non-spinning 

reserves” (emphasis added)). 

49 See Reliability Standard BAL-002-0, sub-Requirements R4.2 and R6.2. See 

also EOP-002-1 (requiring Energy Emergency Alert 1 to be declared if a balancing 

authority, reserve sharing group or load serving entity is concerned about sustaining its 

required Operating Reserves). 
Docket No. RM07-3-000 - 39 - 

that the meaning of Requirement R.2.3 and sub-Requirement R.2.3.2 is not otherwise 

unclear. Therefore, keeping with our approach in this Final Rule, we approve FAC-011-

1, but direct NERC to revise the Reliability Standard through the Reliability Standards 

development process to address our concern. This could, for example, be accomplished 

by deleting the phrase, “e.g., load greater than studied” from sub-Requirement R.2.3.2. 

71. Ameren requests that the Commission consider a new issue not raised in the 

NOPR. Ameren should raise its concern with NERC in the Reliability Standards 

development process. 

5. Other Issues

72. Midwest ISO requests that the Commission reject FAC-010-1 because calculations 

for the 5 to 10 year planning horizon do not provide useful guidance on potential 

expansions to planners or system operators. Midwest ISO supports the use of SOLs and 

IROLs in the operating horizon to properly secure the system but notes that, in the longterm planning horizon, SOLs and IROLs are used to identify system vulnerabilities, 

which may then be addressed in short-term operating studies. Midwest ISO states that 

operational data may be fed into models to ensure that no limits are reached and that the 

system can operate safely given the projected uses, outages and resources. However, 

Midwest ISO argues that developing SOLs and IROLs in the long-term planning horizon 

would not be useful, since there is no reason to believe that interface transfer limits, so 

calculated, would ever be reached or utilized in real time operations. 
Docket No. RM07-3-000 - 40 - 

73. Midwest ISO supports a requirement for appropriate operational studies and cites 

an example examining the feasibility of a 1,000 MW projected interchange based on 

expected loads, resources and firm transactions. However, Midwest ISO does not see 

value in additional studies to determine the ultimate MW transfer limits in a similar 

interchange, because the system operator could not justify use of the facilities to achieve 

limits that are well beyond current system needs. Midwest ISO asserts that other 

planning processes, such as new generation deliverability studies or transmission 

feasibility studies are the appropriate means to accommodate requests for higher transfer 

limits. 

74. NYSRC and NYISO maintain that Requirement R2.4 of FAC-011-1 should 

require consideration of credible multiple element Category C contingency events for 

determining SOLs for the operating horizon, similar to Requirement R2.4 in FAC-010-1.

50 

According to NYSRC and NYISO, failure to consider this class of contingencies in 

determining SOLs during the operating horizon will compromise the reliability of the 

Bulk-Power System and weaken system reliability. NYSRC and NYISO maintain that 

 50 Requirement R2.4 of FAC-010-1 states “with all facilities in service and 

following multiple Contingencies identified in TPL-003 the system shall demonstrate 

transient, dynamic and voltage stability; all Facilities shall be operating with their Facility 

Ratings and within their thermal, voltage and stability limit; and Cascading Outages or 

uncontrolled separation shall not occur.” 
Docket No. RM07-3-000 - 41 - 

FAC-011-1 does not require a reliability coordinator to operate the real time system 

within SOLs determined from credible multiple contingency scenarios.51 

75. NYSRC and NYISO assert that they raised this issue with the Reliability 

Standards drafting team and that NYSRC and NYISO disagree with the drafting team 

about the result of considering credible multiple element contingency events for 

determining SOLs for the operating horizon. Further, they argue that FAC-011-1 is not 

consistent with the Blackout Report recommendation that NERC should not dilute the 

content of its existing Reliability Standards because FAC-011-1 is less stringent than 

prior practices in the Northeast and other regions. Other commenters request the 

Commission to reject the FAC Reliability Standards to permit NERC to address 

outstanding issues reflected in their pleadings.52

Commission Determination

76. The Commission finds that the Midwest ISO and NYSRC and NYISO have failed 

to raise any objection to the FAC Reliability Standards that would justify withholding our 

approval. Specifically, we note that Midwest ISO operates location-based marginal 

pricing markets using economic dispatch. Consequently, despite the fact that it may not 

rely on path-based transmission planning based on facility or path ratings, the FAC 

 51 See NYSRC and NYISO Comments at 4-5. 

52 See, e.g., NRECA Comments, Ameren Comments at 6 (arguing that the 

Commission should not accept Reliability Standards imposing conflicting obligations and 

should direct NERC to monitor interrelated Reliability Standards for consistency). 
Docket No. RM07-3-000 - 42 - 

Reliability Standards would not prevent Midwest ISO from performing appropriate 

planning for its system. To the extent that it seeks an accommodation for its planning 

processes it may seek a regional difference or other accommodation through the 

Reliability Standards development process. As identified by NERC in its comments, the 

SOLs developed pursuant to FAC-010-1 will be an input to calculating long-term ATC as 

required by Order Nos. 890 and 693.53

77. SOLs are also used by transmission providers to provide details to system users 

concerning available capacity for transmission service and to communicate justifications 

for denials of service requests, including long-term ATC. Transmission owners are 

required to make long-term TTC calculations in accordance with Order Nos. 890 and 

693. 

78. To the extent that Midwest ISO requests that the Commission consider new issues 

not raised in the NOPR, the Commission’s general practice is to direct that such 

comments be addressed in the NERC Reliability Standards development process. In 

Order No. 693, the Commission noted that various commenters provided specific 

suggestions to improve or otherwise modify a Reliability Standard to address issues that 

were not raised in the Commission’s NOPR addressing that Reliability Standard. In 

those cases, the Commission directed the ERO to consider such comments when it 

modifies the Reliability Standards according to NERC’s three-year review cycle. The 

 53 NERC Comments at 7. 
Docket No. RM07-3-000 - 43 - 

Commission, however, does not direct any outcome other than that the comments receive 

consideration.54 We direct a similar treatment to address the issue raised in the Midwest 

ISO’s comments. 

79. The Commission does not agree with NYSRC and NYISO’s suggestion that FAC011-1 must be revised so that SOLs for the operating horizon are determined based on 

both single and multiple contingencies. The FAC-011-1 methodology already requires 

the reliability coordinator to determine SOLs by considering both the multiple 

contingencies provided by the planning authority that could result in instability of the 

Bulk-Power System and the facility outages and minimum set of single contingencies that 

were previously considered. Requirements R3.3 and R4 direct each reliability 

coordinator to determine which stability limits arising from multiple contingencies it will 

apply and convey that information to other reliability coordinators, planning authorities 

and transmission operators. The list of multiple contingencies is supplied by the planning 

authority and is applicable for use in the operating horizon given the actual or expected 

system conditions. This is consistent with the Commission’s directives in Order No. 

693.55 If NYSRC and NYISO are concerned that the multiple contingency list is not 

adequate, they should raise those concerns in the Reliability Standards development 

process. 

 54 See Order No. 693 at P 188; Order No. 693-A at P 118. 

55 See id. P 1601-03. 
Docket No. RM07-3-000 - 44 - 

6. Effective Date

80. In the NOPR, the Commission proposed to approve FAC-010-1, FAC-011-1 and 

FAC-014-1 as mandatory and enforceable Reliability Standards, consistent with NERC’s 

original implementation plan beginning July 1, 2007 for Reliability Standard FAC-010-1; 

October 1, 2007 for FAC-011-1 and January 1, 2008 for FAC-014-1. 

Comments

81. In its September 2007 comments, NERC requested that the Commission adopt 

updated effective dates of July 1, 2008 for FAC-010-1, October 1, 2008 for FAC-011-1 

and January 1, 2009 for FAC-014-1. NERC explains that the proposed phased 

implementation schedule will provide each responsible entity sufficient time to determine 

stability limits associated with multiple contingencies, to update the system operating 

limits to comply with the new requirements, to communicate the limits to others, and to 

prepare the documentation necessary to demonstrate compliance. 

82. No commenter objected to NERC’s proposal to use staggered effective dates to 

implement the three Reliability Standards. However, Ontario IESO notes that FAC-010-

1 and FAC-011-1 became effective in Ontario, Canada on October 1, 2007, making 

implementation of the Reliability Standards in Ontario and the United States inconsistent 

so long as the Commission delays approval or remands the Reliability Standards. 

Commission Determination

83. The Commission agrees that it is appropriate in this instance to adopt NERC’s 

revised effective dates of July 1, 2008 for FAC-010-1, October 1, 2008 for FAC-011-1 
Docket No. RM07-3-000 - 45 - 

and January 1, 2009 for FAC-014-1. Given that this Final Rule will not be effective until 

January 2008, it is reasonable to allow responsible entities in the United States adequate 

time to comply with these Reliability Standards. 

84. As for Ontario IESO’s concerns with the different implementation dates in Ontario 

and the United States, we agree that effective dates should be coordinated if practicable. 

In these circumstances, however, we foresee no problems arising from the effective dates 

approved here. 

C. Western Interconnection Regional Difference

85. FAC-010-1 and FAC-011-1 each identify a list of contingencies to be studied in 

developing SOLs.56 Each of these Reliability Standards includes a regional difference for 

the Western Interconnection containing a different list of multiple contingencies from 

those to be considered in other regions (which are derived from Table 1 in the TPL 

Reliability Standards series). The NOPR observed that the detailed list of considerations 

and contingencies in the regional differences for the Western Interconnection appears to 

be more stringent and detailed than the set of contingencies provided for in FAC-010-1 

and FAC-011-1. The regional differences require WECC to evaluate multiple facility 

contingencies when developing SOLs under FAC-010-1 and FAC-011-1. The 

Commission proposed to approve the WECC regional difference for establishing SOLs.57 

 56 See FAC-010-1, Requirement 2.2 and FAC-011-1, Requirement 2.2. 

57 NOPR at P 18-19 (citing Order No. 672 at P 290-91).
Docket No. RM07-3-000 - 46 - 

86. However, the Commission expressed its concern that the regional difference 

provides that the Western Interconnection may make changes to the contingencies 

required to be studied or required responses to contingencies but does not specify the 

procedure for doing so. The regional difference states: 

The Western Interconnection may make changes 

(performance category adjustments) to the Contingencies 

required to be studied and/or the required responses to the 

Contingencies for specific facilities based on actual system 

performance and robust design. [58] 

87. The regional differences do not identify any process for making such changes or 

indicate whether the requirements for reasonable notice and opportunity for public 

comment, due process, openness and balance of interests will be met.59 Accordingly, the 

NOPR proposed that WECC identify its process to revise the list of contingencies and 

requested comment whether the regional difference should state the process. 

Comments

88. WECC explains that it has a process to evaluate probabilities for single 

contingencies and adjust performance requirements for facilities, known as the “Seven 

Step Process for Performance Category Upgrade Request” (Seven Step Process).60 

 58 See, e.g., FAC-011-1, section E.1.4 (incorporating the WECC regional 

difference). 

59 NOPR at P 20 (citing FPA section 215(c)(2)(D), 16 U.S.C. 824o(c)(2)(D) (2000 

& Supp. V 2005)). 

60 WECC Comments at 4 and Attachment A. 
Docket No. RM07-3-000 - 47 - 

WECC states that the Seven Step Process is a “stand-alone” process that is used for 

evaluating the probability of an event on a single facility and for adjusting performance 

requirements of that facility. According to WECC, the Seven Step Process applies to 

individual facilities and not entire “outage categories.” 

89. WECC states that the Seven Step Process was adopted after full due process at the 

WECC Planning Coordination Committee level and when it was approved by the WECC 

board of directors. WECC describes its process through which it will review an 

applicant’s “request [for] a change to a path’s performance Category level.”61 The 

performance category level is an outage performance standard assigned to each path 

under the WECC planning standards.62 The Seven Step Process is largely a technical 

description of the proposed change, which includes a single page workflow diagram 

describing the approval procedures.63 

90. NERC describes the WECC process as a stand-alone process used for evaluating 

the probability of an event on a single facility and for adjusting performance 

requirements of that facility, that is not used to determine which categories of events are 

to be considered when rating facilities or for adjusting performance requirements of 

entire categories. 

 61 Seven Step Process at 1. 

62 Id. 

63 Id., Attachment B. 
Docket No. RM07-3-000 - 48 - 

91. WECC states, while it does not object to including appropriate language in the 

regional difference describing generally the criteria modification process, it prefers not to 

have the regional differences specifically modified to include the Seven Step Process. 

WECC expresses concern that, if included in the Reliability Standards, changes to the 

Seven Step Process would then be made through the NERC ballot body process rather 

than the WECC Reliability Standards Development process. 

92. Santa Clara comments that the contingency revision process should be open and 

states the WECC regional difference should explicitly state the process. 

Commission Determination

93. In the NOPR, we noted that Order No. 672 explains that “uniformity of Reliability 

Standards should be the goal and the practice, the rule rather than the exception.”64 As a 

general matter, the Commission has stated that 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.65 Regional differences 

must still be just, reasonable, not unduly discriminatory or preferential and in the public 

interest.66 

 64 Order No. 672 at P 290. 

65 Id. P 291. 

66 Id. 
Docket No. RM07-3-000 - 49 - 

94. No party has objected to the operative provisions of the WECC regional 

difference. Furthermore, the regional difference contains terms that are more stringent 

than the requirements established for the rest of the continent. Therefore, consistent with 

Order No. 672, the Commission approves the WECC regional differences for FAC-010-1 

and FAC-011-1, incorporating separate lists of contingencies to be considered in the 

Western Interconnection. 

95. WECC’s explanation of its Seven Step Process adequately addresses the 

Commission’s concerns stated in the NOPR. The Commission was concerned that the 

language of the WECC regional difference would, in effect, allow WECC to revise the 

content of a mandatory and enforceable Reliability Standard without the approval of the 

ERO or the Commission. WECC makes clear that that is not the case. WECC explains 

that the intent of the regional difference is not to allow WECC to change or adjust entire 

category performance requirements. Rather, the intent is to evaluate the probability of an 

event on a single facility and adjust performance requirements of that facility. WECC 

states that this evaluation could result in performance requirements for the outage of a 

specific facility “more or less stringent based on the probability of that outage on that 

facility.”67

96. Further, the Seven Step Process, developed after a fair and open vetting at the 

Regional Entity, appears to provide adequate due process for the entity responsible for 

 67 WECC at 4. 
Docket No. RM07-3-000 - 50 - 

the performance of the facility that is the subject of a particular “adjustment.” 

Presumably, this process would also provide sufficient documentation of the change so 

that, for example, an auditor would have the ability to identify the change and evaluate an 

entity’s performance with the regional standard taking the change into consideration. 

The Commission finds that it is not necessary to modify the regional differences to 

expressly mention the Seven Step Process. Accordingly, the Commission approves the 

WECC regional difference for the reasons discussed above. Our approval is made with 

the understanding any WECC-approved change would not result in less stringent criteria 

for Western Interconnection facilities than those defined in the main body of FAC-010-1 

and FAC-011-1. 

D. New Glossary Terms

97. NERC proposes to add or revise four terms in the NERC glossary, Cascading 

Outages, Delayed Fault Clearing, Interconnection Reliability Operating Limit (IROL) 

and Interconnection Reliability Operating Limit Tv (IROL Tv). The Commission stated 

in the NOPR that there could be multiple interpretations of some of these terms.68 

Therefore, the Commission proposed to clarify the terms Cascading Outages, IROL, and 

IROL Tv, as discussed below. With the exception of the proposed definition of 

Cascading Outages, which we remand, the Commission approves the proposed 

definitions, as discussed below. 

 68 NOPR at P 38-43. 
Docket No. RM07-3-000 - 51 - 

1. Cascading Outages

98. Although the glossary does not currently include a definition of Cascading Outage, 

it includes the following approved definition of Cascading: 

Cascading: The uncontrolled successive loss of system 

elements triggered by an incident at any location. Cascading 

results in widespread electric service interruption that cannot 

be restrained from sequentially spreading beyond an area 

predetermined by studies.[69] 

NERC proposes the following new definition of Cascading Outages: 

Cascading Outages: The uncontrolled successive loss of Bulk 

Electric System facilities triggered by an incident (or 

condition) at any location resulting in the interruption of 

electric service that cannot be restrained from spreading 

beyond a pre-determined area. 

99. The NOPR stated that the extent of an outage that would be considered a cascade 

is ambiguous in the current term Cascading. The Commission noted that the new 

definition of Cascading Outages includes a similar phrase “a pre-determined area,” which 

may lead to different interpretations of the extent of an outage that would be considered a 

Cascading Outage. In the NOPR, the Commission stated that it understands that this 

phrase could be interpreted to refer to a scope as small as the elements that would be 

removed from service by local protective relays to as large as the entire balancing 

authority. The Commission objected to the possibility that the Cascading Outages 

definition might consider the loss of an entire balancing authority as a non-cascading 

 69 April 2006 Reliability Standards Filing, Glossary at 2. 
Docket No. RM07-3-000 - 52 - 

event. The NOPR sought comment on the Commission’s proposal to accept the glossary 

definition but clarify the scope of an acceptable “pre-determined area.” Such an area 

would not extend beyond “the loss of facilities in the bulk electric systems that are 

beyond those that would be removed from service by primary or backup protective 

relaying associated with the initiating event.” 

Comments

100. NERC, EEI and APPA, Ameren, Duke, PG&E, Southern and Xcel disagree with 

the Commission’s interpretation of the term Cascading Outages. While FirstEnergy, 

Southern and MidAmerican agree that NERC’s proposed definition of Cascading 

Outages may be open to interpretation, they also object to the Commission’s 

interpretation of the term. Several commenters, including Duke, NRECA and Ameren, 

assert that the Commission’s proposal is overly prescriptive. 

101. According to NERC, as well as EEI and APPA, the term was designed to provide 

a classification for an event, not to identify attributes of an event such as scope, risk or 

acceptable impact. As EEI and APPA understand the term, Cascading Outages will be 

used to describe facts and circumstances in the analysis of widespread uncontrolled 

outages that take place when there are unexpected equipment failures or strong electrical 

disturbances. The analyses of these highly unusual and large-scale events, however, will 

take place through processes described in the NERC Rules of Procedure. EEI and APPA 

maintain that the key to NERC’s proposed definition of Cascading Outages is 

“uncontrolled” and that the scope of the outage is unknown. 
Docket No. RM07-3-000 - 53 - 

102. NERC agrees with the Commission’s concern that the definition of Cascading 

Outages was not intended to allow for the loss of an entire balancing authority unless 

such an area conforms to the area predetermined by studies. However, commenters 

maintain that there are additional safety nets that are intended to confine an outage to a 

pre-set area of the bulk electric system, including special protection systems, protective 

relays, remedial action schemes, and underfrequency and undervoltage load shedding 

applications. According to commenters, the Commission’s proposed interpretation 

appears to ignore the role of transmission operators in managing and containing outage 

situations and the use of these systems.70 

103. ISO/RTO Council notes that system planning studies examining the extent of 

outages anticipate the operation of protective relay options providing primary protection, 

with backup protective relays provided by “secondary protection, zone 2 protection and 

special protection systems.” ISO/RTO Council requests a clarification as to what backup 

protective relaying means and whether or not planned operation of a special protection 

system to contain impacts of outages is regarded as backup protection. 

104. Several commenters maintain that the Commission’s proposed interpretation of 

the term Cascading Outages is too broad. NERC, Ameren, PG&E, Southern, and EEI 

and APPA assert that this interpretation would result in too many outages being defined 

as Cascading Outages under the Commission’s interpretation. They maintain that even 

 70 See, e.g., NERC, EEI and APPA, and Duke Comments. 
Docket No. RM07-3-000 - 54 - 

an outage that is contained exactly as planned could be designated as a Cascading 

Outage. Further, NERC states that the implication of applying the Commission’s 

definition to the TPL evaluations required in Table 1 would be extraordinary in scope and 

impact and the cost would be prohibitive. Additionally, NERC and Southern state that 

the Commission’s interpretation is in conflict with Table 1 in the TPL-001-0 through 

TPL-004-0 Reliability Standards that the Commission approved in Order No. 693. 

105. NERC, therefore, recommends that the Commission reconsider its proposal to 

accept and interpret the term Cascading Outages. According to NERC, adoption of the 

Commission’s proposed understanding would require a review of all NERC Reliability 

Standards that rely on the Cascading Outages definition to be certain that the intent of the 

Reliability Standards does not also change. If the definition of Cascading Outages needs 

to be changed, several commenters, including NERC, FirstEnergy and Southern, maintain 

that changes should be made through NERC’s stakeholder process. Some commenters 

offer alternative definitions or clarifications for Cascading Outages.71

106. Ameren disagrees that the proposed phrase “beyond a pre-determined area” would 

invite system users to expand or contract their understanding of such an area without 

limit. Ameren argues that the concern that the pre-defined area be defined as too small is 

unfounded because the existing definition already requires that the outage not be local in 

nature, that is, result in outages beyond the site of the initial failure. Furthermore, the 

 71 See Duke, ISO/RTO Council and MidAmerican Comments. 
Docket No. RM07-3-000 - 55 - 

definition cannot be defined too large, since the scope for operation and planning 

authorities is already established. 

107. Similarly, PG&E and Southern argue that the Commission’s proposal is not 

necessary, because the Reliability Standards address outages in relation to the severity of 

their impact on the grid. PG&E maintains that the Reliability Standards limit application 

of the definition to an entire balancing authority, because the Reliability Standards 

require a technical analysis of the appropriate boundary, and distribution of the 

methodology used to define a “predetermined area.” Therefore, according to PG&E, 

such a “predetermined area” could only be defined to mean the loss of an entire balancing 

authority when technically appropriate. 

108. MidAmerican requests that the Commission direct NERC to re-focus planning 

Reliability Standards away from the ambiguous definition of cascade and develop a 

definition based on maximum loss of load allowed for a given contingency, such as 1,000 

MW. MidAmerican supports its 1,000 MW threshold as being a significant loss, while 

not exceeding the load for most balancing authorities. 

109. Southern argues that as written, the phrase “that adversely impact the reliability of 

the bulk electric system” modifies Cascading Outages and not a violated system 

operating limit. Southern proposes that the phrase should be left in because it codifies an 

appropriate distinction between Cascading Outages that affect reliability and other 

localized events that create a controlled separation that do not impact the reliability of the 

system. 
Docket No. RM07-3-000 - 56 - 

110. Xcel is concerned that the Commission’s comments indicate an intent to restrict 

the use of controlled outages to prevent the escalation of system contingencies. Xcel 

states that the Commission’s proposed definition represents a departure from historical 

interpretation and application of the term and could have significant unintended 

consequences. 

Commission Determination

111. The Commission will not adopt the proposed interpretation of Cascading Outages 

contained in the NOPR. Rather, for the reasons discussed below, we remand the term 

Cascading Outages. If it chooses, NERC may refile a revised definition that addresses 

our concerns. 

112. The present definition of Cascading provides that “[c]ascading results in 

widespread electric service interruption that cannot be restrained from sequentially 

spreading beyond an area predetermined by studies.” In contrast, the proposed definition 

of Cascading Outages describes an interruption “that cannot be restrained from spreading 

beyond a pre-determined area.” Although the language is somewhat similar, it removes 

the qualifying language “by studies.” NERC provides no explanation for this change. 

The Commission is concerned that the removal of this phrase in the definition of 

Cascading Outage would allow an entity to identify a “predetermined area” based on 

considerations other than engineering criteria. For example, under the proposed 

definition of Cascading Outages, an entity could predetermine that an outage could 

spread to the edge of its footprint without considering the event to be a Cascading 
Docket No. RM07-3-000 - 57 - 

Outage. The Commission is concerned that the limits placed on outages should be 

determined by sound engineering practices. 

113. Adding to the ambiguity, NERC has provided definitions of Cascading and 

Cascading Outages that seem to describe the same concept – uncontrolled successive loss 

of elements or facilities – but did not explain any distinction between the two terms. Nor 

did NERC explain why the new term is necessary and requires a separate definition. 

Because NERC did not describe either the need for two definitions that seem to address 

the same matter or the variations between the two, the Commission remands NERC’s 

proposed definition of Cascading Outages. 

114. If NERC decides to propose a new definition of Cascading Outages, the 

Commission would expect any proposed definition to be defined in terms of an area 

determined by engineering studies, consistent with the definition of Cascading. In 

addition, the Commission is concerned with the consistent, objective development of 

criteria with which the “pre-determined area” would be determined. Therefore, the 

Commission suggests that NERC develop criteria, to be found in a new Reliability 

Standard or guidance document, that would be used to define the extent of an outage, 

beyond which would be considered a Cascading Outage. 

115. Further, the terms Cascading and Cascading Outages contain other nuanced 

differences. For example, the “loss of system elements” is changed to “loss of Bulk 

Electric System facilities” and “triggered by an incident” is changed to “triggered by an 

incident (or condition).” The implications of these changes are not clear to the 
Docket No. RM07-3-000 - 58 - 

Commission. Accordingly, if NERC submits a revised definition of Cascading Outage, it 

should explain the purpose and meaning of changes from the term Cascading. 

116. Given the concerns raised by commenters that the extent of an outage may vary, 

the Commission will not grant at this time MidAmerican’s request to direct NERC to refocus planning Reliability Standards away from the definition of cascade. Further, 

MidAmerican requests that the Commission consider new issues not raised in the NOPR. 

MidAmerican should raise these issues in the NERC Reliability Standards development 

process. 

117. In response to ISO/RTO Council’s request, the Commission clarifies that by 

“backup protective relaying,” the NOPR intended the compliance guidance to be 

consistent with Table 1 of the TPL Reliability Standards. Table 1 identifies the 

categories, contingencies, and system limits or impacts for normal and emergency 

conditions on the bulk electric system. A common requirement for each of the category 

A, B and C contingencies found in Table 1 is that after all of the system, demand and 

transfer impacts have been accommodated for specific contingencies, there will not be 

cascading outages of the bulk electric system. Since all of the planned and controlled 

aspects have been accommodated in this table, anything beyond these planned and 

controlled aspects should be a cascading outage. 
Docket No. RM07-3-000 - 59 - 

2. IROL

118. The approved definition of IROL in the NERC glossary is: 

The value (such as MW, MVar, Amperes, Frequency or 

Volts) derived from, or a subset of the System Operating 

Limits, which if exceeded, could expose a widespread area of 

the Bulk Electric System to instability, uncontrolled 

separation(s) or cascading outages.[72] 

NERC proposes to modify the definition to state: 

Interconnection Reliability Operating Limit (IROL): A 

system operating limit that, if violated, could lead to 

instability, uncontrolled separation, or Cascading Outages 

that adversely impact the reliability of the bulk electric 

system. 

119. The NOPR proposed to accept the revised definition of IROL with the 

understanding that all IROLs impact bulk electric system reliability.73 The Commission 

stated that it was concerned that the revised IROL definition could be interpreted so that 

violations of some IROLs that do not adversely impact reliability are acceptable, due to 

exceptions based on the phrase “that adversely impacts the reliability of the bulk electric 

system.” The NOPR indicated that the revised definition is otherwise consistent with the 

intent of the statute. 

 72 April 2006 Reliability Standards Filing, Glossary at 7. 

73 NOPR at P 42. 
Docket No. RM07-3-000 - 60 - 

Comments

120. NERC, EEI and APPA, WECC and ISO/RTO Council agree with the 

Commission’s interpretation of the definition of IROL. NERC states that an appropriate 

reading of the IROL definition does require that it impact reliability; otherwise it is not an 

IROL. The IROL definition does not suggest that there is a subclass of IROLs that do not 

impact reliability. Ameren supports the clarification and suggests that the phrase “that 

will adversely affect the reliability of the Bulk-Power System” should be deleted so that 

all IROLs are treated the same. 

121. Although EEI and APPA agree with the Commission, they respectfully suggest 

that the Commission in the future defer initially to NERC on matters of technical 

interpretation. 

122. SoCal Edison suggests that the IROL definition be revised to add the words 

“across an interconnection” after the initial phrase “[a] system operating limit” to clarify 

that an IROL relates to an SOL across a transmission operator’s “area, interconnection or 

region.” 

Commission Determination

123. As proposed in the NOPR, the Commission accepts NERC’s definition of IROL. 

In response to EEI and APPA, the Commission believes that, where a potential ambiguity 

exists, it is appropriate to clarify what the Commission believes it is approving. In Order 

No. 693, the Commission approved the proposed Reliability Standards with certain 
Docket No. RM07-3-000 - 61 - 

clarifications.74 The Commission does not intend to unilaterally modify definitions; 

however, the Commission must ensure that it correctly understands NERC’s intent while 

giving “due weight” to the technical expertise of the ERO.75 Promoting such clarity is an 

important aspect of approving both Reliability Standards and glossary terms. 

124. With regard to SoCal Edison’s concerns, these are new matters not raised in the 

NOPR that should be addressed in the NERC Reliability Standards development process. 

3. IROL Tv

125. The NOPR proposed to accept the proposed IROL Tv definition.76 However, the 

Commission noted that Order No. 693 identified two interpretations of when an entity 

 74 Order No. 693 at P 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”), P 1606 (“Commenters did not take issue with the proposed interpretation of 

the term ‘deliverability’ .... The Commission adopts this proposed interpretation”). 

75 Id. P 8 (citing section 215(d)(2) of the FPA and 18 CFR 39.5(c)(1), (3) and 

stating “the Commission will give due weight to the technical expertise of the ERO with 

respect to the content of a Reliability Standard or to a Regional Entity organized on an 

Interconnection-wide basis with respect to a proposed Reliability Standard or a proposed 

modification to a Reliability Standard to be applicable within that Interconnection. 

However, the Commission will not defer to the ERO or to such a Regional Entity with 

respect to the effect of a proposed Reliability Standard or proposed modification to a 

Reliability Standard on competition.”). See also Order No. 672 at P 40. 

76 NOPR at P 43. Interconnection Reliability Operating Limit Tv (IROL Tv): The 

maximum time that an Interconnection Reliability Operating Limit can be violated before 

the risk to the interconnection or other Reliability Coordinator Area(s) becomes greater 

than acceptable. Each Interconnection Reliability Operating Limit’s Tv shall be less than 

or equal to 30 minutes. 
Docket No. RM07-3-000 - 62 - 

exceeds an IROL.77 The Commission stated that the definition of IROL Tv does not 

distinguish between those two interpretations. Therefore, the Commission proposed to 

accept the definition of IROL Tv with the understanding that the only time it is acceptable 

to violate an IROL is in the limited time after a contingency has occurred and the 

operators are taking action to eliminate the violation.

Comments

126. NERC agrees that the definition of IROL Tv does not distinguish between the two 

possible interpretations of when an entity exceeds an IROL contained in Order No. 693. 

NERC, Ameren and Southern agree with the Commission that the only time it is 

acceptable to violate an IROL is in the limited time after a contingency has occurred and 

the operators are taking action to eliminate the violation. WECC reports that this is 

consistent with WECC’s interpretation. 

127. The ISO/RTO Council disagrees that the only time an IROL can be exceeded is 

for a contingency. According to ISO/RTO Council, IROL Tv should be less than or equal 

to 30 minutes with the understanding that the only time it is acceptable to violate an 

IROL is in the limited time after a contingency has occurred and the operators are taking 

 77 See Order No. 693 at P 946 & n.303. Order No. 693 explained that 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. 
Docket No. RM07-3-000 - 63 - 

action to eliminate the violation. ISO/RTO Council would, however, propose to expand 

this understanding to include the situation where no contingencies have occurred but the 

IROL is exceeded due to system condition changes, such as unanticipated external 

interchange schedules, redispatch, morning and evening load pick-up, or other events that 

cause a rapid change in transmission loading. 

Commission Determination

128. The Commission approves NERC’s proposed definition of IROL Tv based on the 

Commission’s understanding explained in the NOPR and affirmed by NERC. ISO/RTO 

Council essentially seeks to expand the definition of IROL Tv to apply to additional 

circumstances. This matter is best addressed by ISO/RTO Council in the NERC 

Reliability Standards development process. 

E. Violation Risk Factors

129. Violation Risk Factors delineate the relative risk to the Bulk-Power System 

associated with the violation of each Requirement and are used by NERC and the 

Regional Entities to determine financial penalties for violating a Reliability Standard. 

NERC assigns a lower, medium or high Violation Risk Factor for each mandatory 
Docket No. RM07-3-000 - 64 - 

Reliability Standard Requirement.78 The Commission also established guidelines for 

evaluating the validity of each Violation Risk Factor assignment.79 

130. In separate filings, NERC identified Violation Risk Factors for each Requirement 

of proposed Reliability Standards FAC-010-1, FAC-011-1 and FAC-014-1.80 NERC’s 

filings requested that the Commission approve the Violation Risk Factors when it takes 

action on the associated Reliability Standards. 

131. The NOPR proposed to approve most of the Violation Risk Factors for Reliability 

Standards FAC-010-1, FAC-011-1 and FAC-014-1. However, as discussed below, 

several of the Violation Risk Factors submitted for Reliability Standards FAC-010-1, 

FAC-011-1 and FAC-014-1 raise concerns. 

 78 The specific definitions of high, medium and lower are provided in North 

American Electric Reliability Corp., 119 FERC ¶ 61,145, at P 9 (Violation Risk Factor 

Order), order on reh’g, 120 FERC ¶ 61,145 (2007) (Violation Risk Factor Rehearing). 

79 The guidelines are: (1) Consistency with the conclusions of the Blackout 

Report; (2) Consistency within a Reliability Standard; (3) Consistency among Reliability 

Standards; (4) Consistency with NERC’s Definition of the Violation Risk Factor Level; 

and (5) Treatment of Requirements that Co-mingle More Than One Obligation. The 

Commission also explained that this list was not necessarily all-inclusive and that it 

retained the flexibility to consider additional guidelines in the future. A detailed 

explanation is provided in Violation Risk Factor Rehearing, 120 FERC ¶ 61,145, at P 8-

13. 

80 See NERC, Request for Approval of Violation Risk Factors for Version 1 

Reliability Standards, Docket No. RR07-10-000, Exh. A (March 23, 2007), as 

supplemented May 4, 2007. To date, the Commission has addressed only those Violation 

Risk Factors pertaining to the 83 Reliability Standards approved in Order No. 693. 

Violation Risk Factor Order, 119 FERC ¶ 61,145. 
Docket No. RM07-3-000 - 65 - 

1. General Issues

Comments 

132. Commenters generally oppose the Commission’s proposal for raising the 

Violation Risk Factors. Further, they generally ask that changes to the Violation Risk 

Factors be made through the Reliability Standards development process. 

133. Progress Energy maintains that violations associated with planning Reliability 

Standards cannot be high risk because such violations do not pose an imminent danger to 

the Bulk-Power System. Progress Energy contends that planning Reliability Standards 

are implemented over a long-term planning horizon. Progress Energy states that entities 

continually update load and other forecasts and assumptions relied on to determine future 

transmission and distribution system needs. As these assumptions change, so do the 

transmission plans. Progress Energy states that utilities provide constant oversight, 

frequent reviews, audits and evaluations of the planning process over the entire multiyear planning horizon. According to Progress Energy, with this type of control and 

oversight, it is highly unlikely that an inaccurate forecast or misassumption early in the 

planning horizon could result in an operational reliability concern. Consequently, 

planning authorities and reliability coordinators have adequate time to analyze, determine 

and correct planning violations before they could have an operational impact. 

134. Progress Energy also states that unnecessarily increasing Violation Risk Factors 

for planning Reliability Standards may have unintended consequences. According to 

Progress Energy, assigning overly conservative Violation Risk Factors will cause 
Docket No. RM07-3-000 - 66 - 

planning and reliability coordinators to focus more time and resources on satisfying those 

Reliability Standards, potentially to the detriment of other Reliability Standards. It 

maintains that the level of the Violation Risk Factor is intended to communicate the 

importance of the Reliability Standards and, consequently, the resources that should be 

devoted to its implementation and the magnitude of the penalty associated with its 

violation. Further, to avoid potentially costly penalties associated with violation of 

higher risk factors, Progress Energy maintains that planning and reliability coordinators 

may take a more conservative approach with their assumptions, which could quite 

literally result in lower TTC and ATC determinations than would otherwise be available. 

Commission Determination

135. NERC submitted 72 Violation Risk Factors corresponding to the Requirements 

and sub-requirements in the three FAC Reliability Standards. The Commission, giving 

due weight to the technical expertise of NERC as the ERO, concludes that the vast 

majority of NERC’s designations accurately assess the reliability risk associated with the 

corresponding Requirements and are consistent with the guidelines set forth in the 

Commission’s prior orders addressing Violation Risk Factors. Therefore, the 

Commission approves 63 of these Violation Risk Factor designations. However, the 

Commission concludes that nine filed Violation Risk Factors for FAC Reliability 

Standards Requirements are not consistent with these guidelines and also concludes that 

one Requirement where no Violation Risk Factor was filed should have been assigned a 

Violation Risk Factor consistent with an identically worded Requirement from another 
Docket No. RM07-3-000 - 67 - 

FAC Reliability Standard. Thus, the Commission directs NERC to modify these ten 

Violation Risk Factors.81 

136. NERC and other commenters, such as APPA and EEI, ask the Commission to 

defer to NERC on the determination of Violation Risk Factors and, instead, allow NERC 

to reconsider the designations using the Reliability Standards development process. The 

Commission has previously determined that Violation Risk Factors are not a part of the 

Reliability Standards.82 In developing its Violation Risk Factor filing, NERC has had an 

opportunity to fully vet the FAC Violation Risk Factors through the Reliability Standards 

development process. The Commission believes that, for those Violation Risk Factors 

that do not comport with the Commission’s previously-articulated guidelines for 

analyzing Violation Risk Factor designations, there is little benefit in once again allowing 

the Reliability Standards development process to reconsider a designation based on the 

Commission’s concerns. Therefore, we will not allow NERC to reconsider the Violation 

Risk Factor designations in this instance but, rather, direct below that NERC make 

specific modifications to its designations. NERC must submit a compliance filing with 

 81 The ten Violation Risk Factors to which the Commission directs modification 

include Requirement R3.4 for FAC-011-1, where NERC did not assign a Violation Risk 

Factor. In this instance, the Commission assigns a Violation Risk Factor to the subject 

Requirement that is consistent with the Violation Risk Factor assigned to an identical 

Requirement for another Reliability Standard, FAC-010-1, Requirement R2.3. 

82 Violation Risk Factor Rehearing, 120 FERC ¶ 61,145, at P 11-16, citing North 

American Reliability Corp., 118 FERC ¶ 61,030, at P 91, order on clarification and reh'g, 

119 FERC ¶ 61,046 (2007). 
Docket No. RM07-3-000 - 68 - 

the revised Violation Risk Factors no later than 90 days before the effective date of the 

relevant Reliability Standard. 

137. That being said, NERC may choose the procedural vehicle to change the ten 

Violation Risk Factors consistent with the Commission’s directives. NERC may use the 

Reliability Standards development process, so long as it meets Commission-imposed 

deadlines.83 In this instance, the Commission sees no vital reason to direct NERC to use 

section 1403 of its Rules of Procedure to revise the Violation Risk Factors below, so long 

as the revised Violation Risk Factors address the Commission’s concerns and are filed no 

less than 90 days before the effective date of the relevant Reliability Standard. The 

Commission also notes that NERC should file Violation Severity Levels before the FAC 

Reliability Standards become effective. 

138. In revising the Violation Risk Factors, NERC must address the Commission’s 

concerns, as outlined below, and also follow the five guidelines for evaluating the 

validity of each Violation Risk Factor assignment. Consistent with the Violation Risk 

Factor Order, the Commission directs NERC to submit a complete Violation Risk Factor 

matrix encompassing each Commission-approved Reliability Standard and including the 

correct corresponding version number for each Requirement when it files revised 

Violation Risk Factors for the FAC Reliability Standards. 

 83See North American Electric Reliability Corp., 118 FERC ¶ 61,030, at P 91, 

order on compliance, 119 FERC ¶ 61,046, at P 33 (2007).
Docket No. RM07-3-000 - 69 - 

139. Progress Energy incorrectly claims that a planning Reliability Standard will never 

qualify for a high Violation Risk Factor. According to NERC, a high risk requirement 

includes: 

 (b) . . . a requirement in a planning time frame that, if 

violated, could, under emergency, abnormal, or restorative 

conditions anticipated by the preparations, directly cause or 

contribute to Bulk-Power System instability, separation, or a 

cascading sequence of failures, or could place the Bulk-Power 

System at an unacceptable risk of instability, separation, or 

cascading failures, or could hinder restoration to a normal 

condition [emphasis added]. 

140. A Violation Risk Factor assigned to Requirements of planning-related Reliability 

Standards represent, in a planning time frame, the potential reliability risk, under 

emergency, abnormal, or restorative conditions anticipated by the preparations to the 

Bulk-Power System. As such, how much time a planning authority or reliability 

coordinator has to identify and correct a violation of a planning-related Requirement is 

irrelevant in the assignment of an appropriate Violation Risk Factor. 

141. The Commission also disagrees with Progress Energy that overly conservative 

Violation Risk Factor assignments may result in the lowering of TTC and ATC 

determinations because planning and reliability coordinators may take a more 

conservative approach with assumptions to avoid potentially costly penalties. Progress 

Energy did not assert any specific deficiency regarding the relationship between planning 

Reliability Standards and TTC and ATC determinations. Because Violation Risk Factors 

do not determine the actions a responsible entity must take, but merely measure the risk 
Docket No. RM07-3-000 - 70 - 

of violating a Requirement to the reliability of the Bulk-Power System, it is the specific 

Requirements in a given Reliability Standard that establish the relationship between 

planning Reliability Standards and TTC and ATC determinations, not the assignment of a 

Violation Risk Factor. If Progress Energy has specific concerns that a Reliability 

Standard is having an unduly detrimental effect on TTC or ATC determinations, it should 

raise such issues in the Reliability Standards development process. 

Comments on WECC Violation Risk Factors

142. In the NOPR, the Commission noted that there are no Violation Risk Factors 

applicable to the WECC regional differences and that certain portions of the WECC 

regional differences lack levels of non-compliance. The NOPR requested comment on 

whether it should require WECC to develop Violation Risk Factors and the levels of noncompliance for the regional differences. The NOPR also requested comment on how 

WECC should assess penalties in the interim, if it were tasked with such a responsibility. 

143. NERC states that WECC believes that it should be required to develop Violation 

Risk Factors for its regional differences. WECC indicates that it will initiate efforts to 

develop Violation Risk Factors for the regional differences identified in FAC-010-1 and 

FAC-011-1. In the interim, WECC proposes to assess penalties for non-compliance by 

adopting the same Violation Risk Factor for each WECC regional difference as is 

identified for NERC Requirements R2.4 and R2.5 for FAC-010-0 and Requirement R3.3 

for FAC-011-1 that the WECC regional differences replace. It is WECC’s intention to 

propose that the WECC regional differences should have the same Violation Risk Factors 
Docket No. RM07-3-000 - 71 - 

as NERC Requirements R2.4 and R2.5 in FAC-010-1 and Requirement R3.3 for FAC011-1 when it goes through its process to develop the Violation Risk Factors. 

144. WECC notes that levels of non-compliance already exist in section D.3 in both 

FAC-010-1 and FAC-011-1. For penalty calculations in the interim, before Violation 

Risk Factors and levels of non-compliance consistent with NERC’s methodology are 

developed, WECC intends to apply the Violation Risk Factors established for NERC 

Requirements R2.4 and R2.5 for FAC-010-1 and Requirement R3.3 for FAC-011-1. 

145. Santa Clara agrees that WECC should develop the Violation Risk Factors and 

levels of non-compliance for the WECC regional differences. 

Commission Determination 

146. Furthermore, the Commission agrees that it is appropriate to permit WECC to 

develop the Violation Risk Factors that are applicable to the WECC regional differences. 

The Commission also takes note of WECC’s proposal to assign the same Violation Risk 

Factors to the WECC regional differences as are assigned to NERC Requirements R2.4 

and R2.5 in FAC-010-1 and Requirement R3.3 for FAC-011-1. The Commission 

believes that WECC’s approach is reasonable and approves of that proposal. Should the 

NERC process arrive at a different conclusion, WECC and NERC must justify any 

disparate treatment in their filing of WECC Violation Risk Factors. To accommodate the 

WECC process and, in light of the fact that the NERC Violation Risk Factors will also 

apply until WECC develops its own, we direct WECC to file Violation Risk Factors for 

the FAC-010-1 and FAC-011-1 no later than the effective date of the applicable 
Docket No. RM07-3-000 - 72 - 

Reliability Standard. The Commission will address issues related to the development of 

Violation Risk Factors for the WECC regional differences after they have been filed for 

approval. Similarly, WECC should file Violation Severity Levels at the same time it files 

Violation Risk Factors. 

2. Requirements R2 and R2.1 - R2.2.3 for FAC-010-1 and FAC011-1

147. The NOPR proposed to direct NERC to modify the lower Violation Risk Factor 

assigned to FAC-010-1, Requirement R2 and the medium Violation Risk Factor assigned 

to sub-Requirements R2.1 - R2.2.3 based on guideline 4, which assesses whether a 

Violation Risk Factor conforms to NERC’s definition for the assigned risk level. The 

Commission proposed to require NERC to assign each of these requirements a high 

Violation Risk Factor. 

148. FAC-010-1, Requirement R2 requires each planning authority’s SOL 

methodology to include a requirement that SOLs provide for bulk electric system 

performance consistent with a stable pre-contingency (sub-Requirement R2.1) and postcontingency (sub-Requirements R2.2 - R2.2.3) bulk electric system using an accurate 

system topology with all facilities operating within their ratings and without postcontingency cascading outages or uncontrolled separation. 

149. Requirement R2.1 of FAC-010-1 requires each planning authority’s SOL 

methodology to include a requirement that SOLs developed must provide for bulk 

electric system performance consistent with transient, dynamic and voltage stability in a 
Docket No. RM07-3-000 - 73 - 

pre-contingency state and with all facilities in service. In the NOPR, the Commission 

stated that it believes that a lower Violation Risk Factor is inappropriate because 

Requirement R2.1 of FAC-010-1 is not administrative in nature. The Commission stated 

that it believes that a violation of Requirement R2.1 could directly cause or contribute to 

Bulk-Power System instability, separation or cascading failures, because a violation of 

Requirement R2.1 means that the system is in an unreliable state even before the system 

is subject to a contingency. Therefore, we proposed to require NERC to change the 

Violation Risk Factor for Requirement R.2.1 to high. 

150. The Commission had similar concerns with respect to FAC-010-1, Requirement 

R2.2 because it specifically states that, with regard to post-contingency bulk electric 

system performance, “[c]ascading outages or uncontrolled separation shall not occur.” 

Therefore, the Commission reasoned that if Requirement R2.2 is violated for any one of 

the specific contingencies as described in Requirements R2.2.1 – R2.2.3, cascading 

outages or uncontrolled separation of the Bulk-Power System may occur, which would 

merit a high Violation Risk Factor.84 

151. The Commission had similar concerns with the Violation Risk Factor assignments 

of Requirement R2 and sub-Requirements R2.1 - 2.2.3 of FAC-011-1, which contain 

language similar to Requirements in FAC-010-1. Consequently, the NOPR proposed to 

modify the Violation Risk Factors for these Requirements and sub-Requirements to high. 

 84 NOPR at P 53. 
Docket No. RM07-3-000 - 74 - 

Comments

152. NERC disagrees that it should assign high Violation Risk Factors for 

Requirements R2 and R2.1 - R2.2.3 for FAC-010-1. NERC agrees that the lower 

Violation Risk Factor assignment for Requirement R2 of FAC-010-1 merits 

reconsideration but does not agree that the Violation Risk Factor assignment for 

Requirement R2 or the sub-Requirements should be changed from medium to high. 

NERC proposes to process this proposed change through the Commission-approved 

Reliability Standards development process. 

153. NERC believes that FAC-010-1, Requirement R2 and its subparts should only 

have a single Violation Risk Factor and this should be medium. NERC maintains that 

Requirement R2 does not include any obligations to conduct analyses or assessments, but 

merely lists topics that must be included in the SOL methodology. NERC states that the 

requirements to follow the methodology in setting the SOLs are included in FAC-014-1. 

According to NERC, if FAC-010-1 Requirement R2 were violated, the Bulk-Power 

System would not experience instability, separation, or cascading failures in real-time. 

All of the uses of the SOLs developed with the methodology in FAC-010-1 are for 

planning purposes. While failure to comply with Requirement R2 and its subrequirements over the long term may affect the ability to effectively monitor, control, or 

restore the Bulk-Power System, NERC states that a violation of theses requirements is 

unlikely to lead to Bulk-Power System instability, separation, or cascading failures. 
Docket No. RM07-3-000 - 75 - 

154. Ameren argues that, because the FAC Reliability Standards at issue in this 

proceeding are administrative in nature and are not operational Reliability Standards, a 

high Violation Risk Factor is inappropriate. Because the Reliability Standards establish 

methodologies, a violation does not directly threaten reliability. 

155. In response to the Commission’s proposal in the NOPR, NERC agrees that FAC011-1, Requirement R2 and its sub-requirements merit consideration for a high Violation 

Risk Factor assignment. NERC proposes to process this proposed change through its 

Reliability Standards development process. According to NERC, if the methodology for 

setting real-time limits is not correct, then the resultant real-time limits may be incorrect 

and operating to these incorrect limits could directly lead to Bulk-Power System 

instability, separation, or cascading failures. 

156. For the reasons discussed in the general issues section, above, Progress Energy 

disagrees that the Violation Risk Factors should be modified. Ameren asserts that the 

Commission approved lower and medium Violation Risk Factors for Requirements in 

FAC-008-1 and FAC-009-1, which deal with setting and communicating the 

methodologies for facility ratings and are comparable to FAC-010-1 and FAC-011-1, in 

the Violation Risk Factor Order. To be consistent with other approved Violation Risk 

Factors, Ameren argues that the Commission should not order changes to the Violation 

Risk Factors for FAC-010-1 and FAC-011-1. 
Docket No. RM07-3-000 - 76 - 

Commission Determination

157. NERC, Progress Energy and Ameren argue that the failure to have a methodology 

to develop SOLs that is only used in the planning horizon will not cause or contribute to 

Bulk-Power System instability, separation, or cascading failures in real-time. The 

Commission disagrees. The SOLs and remedial measures determined during 

transmission planning ensure Reliable Operation in real-time. As the Commission stated 

in Order No. 693, 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.85 Also, the Blackout Report cited 

FirstEnergy for violation of the then-effective NERC Planning Standard 1A, Category 

C.3 – the equivalent of FAC-10-1, sub-Requirement R2.3.3.86 The Blackout Report also 

found that had FirstEnergy conducted adequate planning studies on voltage stability (e.g., 

 85 See Order No. 693 at P 1683. 

86 Blackout Report at 41. 
Docket No. RM07-3-000 - 77 - 

FAC-010-1, Requirement R2.2), it would not have set its minimum acceptable voltage at 

90 percent.87 

158. Because the SOLs and remedial measures determined during transmission 

planning ensure Reliable Operation in real-time, the Commission believes that violations 

of planning requirements of the SOL methodology Reliability Standards present the same 

potential reliability risks as violations in the operating time horizon. Our determination is 

consistent with the NERC proposed, and Commission approved definition of a high 

Violation Risk Factor, which considers the violation of Requirements relevant to the 

planning time horizon. 

159. With regard to FAC-010-1, Requirement R2, and FAC-011-1, Requirement R2, 

the Commission agrees with NERC that Requirement R2, without its sub-Requirements, 

includes no required performance or outcome. As such, no Violation Risk Factor needs 

to be assigned to Requirement R2 in either FAC-010-1 or FAC-011-1. Further, the 

Commission agrees with NERC that FAC-010-1, sub-Requirements R2.2.1-R2.2.3 are 

topics to be included in an SOL methodology which do not require an assessment or 

analysis to be performed. As such, a medium Violation Risk Factor is appropriate. 

160. However, with regard to FAC-010-1, sub-Requirements R2.1 and R2.2, the 

Commission disagrees with NERC that a medium Violation Risk Factor is appropriate. 

Sub-Requirements R2.1-R2.2 require that the planning authority’s SOL methodology 

 87 Id. at 42. 
Docket No. RM07-3-000 - 78 - 

must include Requirements for SOLs to demonstrate transient, dynamic, and voltage 

stability performance pre- and post-contingency. 

161. The Commission believes that violations of FAC-010-1, sub-Requirements R2.1 

and R2.2 present similar, if not the same, risk to Bulk-Power System reliability as 

violations of TPL-001-0, Requirement R1 and TPL-002-0, Requirement R1. TPL-001-0, 

Requirement R1 establishes reliable pre-contingency Bulk-Power System performance. 

NERC proposed, and the Commission approved, a high Violation Risk Factor for TPL001-0, Requirement R1. TPL-002-0, Requirement R1 establishes reliable postcontingency Bulk-Power System performance. The Commission directed, and NERC 

revised, the Violation Risk Factor assignment for TPL-002-0, Requirement R1 to high to 

be consistent with the pre-contingency performance Requirement of TPL-001-0, 

Requirement R1. The Commission believes both TPL Requirements establish similar, if 

not the same, Bulk-Power System performance metrics as FAC-010-1, Requirements 

R2.1 and R2.2. 

162. Further, contrary to NERC’s position, the Commission believes that to 

demonstrate the pre- and post-contingency performance metrics required by 

Requirements R2.1-R2.2 an assessment or analysis would need to be performed. As 

such, Requirements R2.1-R2.2 provide for actions that go beyond NERC’s 

characterization of the subject of the requirements as limited to a list of topics that must 

be included in a methodology. Therefore, we conclude that these Requirements are more 
Docket No. RM07-3-000 - 79 - 

properly treated as implementation or operational requirements that may have a direct 

impact on reliability. 

163. For the same reasons, the Commission does not agree with Ameren’s argument 

that the Commission’s proposal is inconsistent with prior Violation Risk Factor 

determinations made for what Ameren believes to be comparable Requirements of 

Reliability Standards FAC-008-1 and FAC-009-1.88 As examples in support of its 

argument, Ameren points to the Commission approved medium Violation Risk Factors 

for FAC-008-1, Requirements R1.3.1-R1.3 and the lower Violation Risk Factors for the 

remaining Requirements, all of which establish topics that do not incorporate a 

performance metric to be included in a methodology. Ameren also points to the medium 

Violation Risk Factor assignments for Requirements of FAC-009-1 that establish facility 

ratings based on a methodology. As the Commission states previously in this order, 

FAC-010-1 and FAC-011-1 do not merely establish documentation, methodologies, and 

administrative tasks, as is the case for the Requirements that Ameren points to as 

examples of inconsistencies. The FAC-010-1 and FAC-011-1 Requirements at issue 

require the Bulk-Power System to demonstrate transient, dynamic, and voltage stability 

performance pre- and post-contingency. The Commission believes that, to demonstrate 

the pre- and post-contingency performance metrics required by these Requirements, an 

assessment or analysis would need to be performed. The Commission approved high 

 88 Ameren Comments at 14-15. 
Docket No. RM07-3-000 - 80 - 

Violation Risk Factors for similar Bulk-Power System performance metrics. As such, the 

Requirements at issue go beyond the establishment and documentation of a methodology 

as Ameren suggests and are fully consistent with the Violation Risk Factor assignments 

the Commission has previously approved. 

164. The Commission agrees with NERC that the Requirements to follow a 

methodology when determining SOLs are included in FAC-014-1. However, as the 

Commission states above, FAC-010-1, Requirements R2.1-R2.2 establish the 

performance metrics of the SOL methodology used. Thus, if the planning authority’s 

methodology to develop SOLs does not meet the demonstrated performance metrics of 

these Requirements in a planning time horizon, then under emergency, abnormal, or 

restorative conditions, the Bulk-Power System would be at risk of instability, separation, 

or cascading failures. 

165. With regard to the determination of SOLs for the operations time horizon 

established by Reliability Standard FAC-011-1, Requirement 2 and its sub-Requirements, 

NERC comments, “if the methodology for setting real-time limits is not correct, then the 

resultant real-time limits may be incorrect and operating to these incorrect limits could 

directly lead to bulk-power system instability, separation, or cascading failures.”89 As 

such, NERC’s statement supports the Commission’s rationale that FAC-011-1, 

Requirements R2.1-R2.2.3 merit consideration of a high Violation Risk Factor. 

 89 NERC Comments at 39. 
Docket No. RM07-3-000 - 81 - 

Consistent with the previous Commission determination in this order that time horizons 

are irrelevant in the determination of an appropriate Violation Risk Factor assignment, 

and to ensure consistency with the conclusions of the Blackout Report (guideline 1) and 

among similar Requirements of Reliability Standards (guideline 3), the Commission 

directs NERC to revise the Violation Risk Factor assigned to FAC-010-1, Requirements 

R2.1-R2.2 to high. 

166. Similar to FAC-010-1, Requirements R2.2.1-R2.2.3, the Commission believes that 

FAC-011-1, Requirements R2.2.1-R2.2.3 describe topics to be included in an SOL 

methodology and do not require an assessment or analysis to be performed. Therefore, 

the Commission believes a medium Violation Risk Factor is appropriate for these 

Requirements. Consequently, the Violation Risk Factor assignments for FAC-011-1, 

Requirements R2.2.1 - R2.2.3 do not need to be revised as the Commission proposed in 

the NOPR. 

3. FAC-014-1, Requirement R5

167. In the NOPR, the Commission proposed to require NERC to assign a high 

Violation Risk Factor to FAC-014-1, Requirement R5 and sub-Requirements R5.1 - 

5.1.4. The Commission was concerned that NERC’s proposal was not consistent with the 

findings of the Blackout Report. 

168. Requirement R5 requires that the reliability coordinator, planning authority and 

transmission planner each provide its SOLs and IROLs to those entities that have a 

reliability-related need for those limits and provide a written request that includes a 
Docket No. RM07-3-000 - 82 - 

schedule for delivery of those limits. Sub-Requirements R5.1 - R5.1.4 comprise the list 

of supporting information to be provided. 

169. The Blackout Report identified ineffective communications as one common factor 

of the August 2003 blackout and other previous major blackouts90 and explained that, 

“[u]nder normal conditions, parties with reliability responsibility need to communicate 

important and prioritized information to each other in a timely way, to help preserve the 

integrity of the grid.”91 Because the Blackout Report, as well as reports on other previous 

major blackouts, determined that the timely communication of important and prioritized 

information, in this case, SOLs and IROLs, to entities that have a reliability-related need 

for those limits are crucial in maintaining the reliability of the Bulk-Power System, the 

Commission stated that it believed assigning a medium Violation Risk Factor assignment 

to FAC-014-1, Requirement R5 and sub-Requirements R5.1 - 5.1.4 was not consistent 

with the findings of the Blackout Report. The Commission, therefore, proposed to 

require NERC to assign a high Violation Risk Factor to these Requirements. 

Comments

170. NERC does not agree with the Commission’s proposed modification to FAC-014-

1, Requirement R5 and its subparts. NERC maintains that, while failure to act to prevent 

and/or mitigate an instance of exceeding an IROL is expected to result in adverse system 

 90 Blackout Report at 107. 

91 Id. at 109. 
Docket No. RM07-3-000 - 83 - 

consequences, FAC-014-1, Requirement R5 is not aimed at preventing and/or mitigating 

an IROL. Rather, according to NERC, FAC-014-1, Requirement R5 is aimed at 

communicating information to others. NERC agrees that effective communication is one 

factor that can contribute to Bulk-Power System instability, separation, or cascading 

failures, meriting a medium Violation Risk Factor. 

171. However, NERC does not agree that the failure to communicate the actual or 

potential existence of SOLs and IROLs to those entities that are not required to resolve 

those limits will result in Bulk-Power System instability, separation, or cascading. 

NERC maintains that the impact of not notifying adjacent entities of an actual or potential 

IROL is a medium risk as it only impacts the ability of neighboring entities to effectively 

monitor the Bulk-Power System. Further, NERC notes that IRO-015-1, Requirement R1 

requires that the reliability coordinator to make notifications and exchange reliabilityrelated information with other reliability coordinators. This requirement was approved 

by the Commission with the medium Violation Risk Factor assignment. This FAC-014-

1, Requirement R5 is of a similar nature to IRO-015-1, Requirement R1 and should 

therefore maintain its medium Violation Risk Factor assignment. 

172. For the same reasons discussed above, Progress Energy argues that the 

Commission should not modify the Violation Risk Factor to high. Ameren asserts that 

the Commission approved medium Violation Risk Factors for Requirements in FAC-013-

1, which sets procedures for establishing and communicating transfer capabilities and is 

comparable to FAC-014-1, in the Violation Risk Factor Order. To be consistent with 
Docket No. RM07-3-000 - 84 - 

other approved Violation Risk Factors, Ameren argues that the Commission should not 

order changes to the Violation Risk Factors for FAC-014-1. 

Commission Determination

173. The Commission agrees with NERC that FAC-014-1, Requirement R5 is not 

aimed at the prevention and/or mitigation of IROLs, but rather the communication of 

SOL and IROL information. However, NERC’s argument is flawed in that Requirement 

R5 requires reliability coordinators, planning authorities and transmission planners to 

communicate and provide SOL and IROL information to entities that have a reliabilityrelated need for those limits. NERC’s comments, on the other hand, focus on provision 

of information to entities that are not required to resolve those limits. Therefore, a failure 

to notify adjacent entities of an actual or potential IROL creates a demonstrable risk 

because it impairs the ability of neighboring entities to effectively monitor the BulkPower System. In addition, the Commission believes that this Requirement applies to 

both real-time operations and the planning time frames, by ensuring that inter-dependent 

IROLs in adjacent footprints are duly considered in the planning time frame and timely 

remedial actions are taken in real-time operation. 

174. In the Violation Risk Factor Order, the Commission applied guideline 1 to ensure 

critical areas identified as causes of that and other previous major blackouts are 

appropriately assigned Violation Risk Factors. Ineffective communication was identified 
Docket No. RM07-3-000 - 85 - 

as a factor common to the August 2003 blackout and other previous major blackouts.92 

Further, the Blackout Report stated that “[i]neffective communications contributed to a 

lack of situational awareness and precluded effective actions to prevent the cascade.”93 

175. For the reasons stated above and lessons learned from previous blackouts, the 

Commission believes Violation Risk Factor for Requirement R5 and the subrequirements in R5.1 should be assigned as high to reflect the potential reliability risk of 

not communicating IROLs to adjacent entities that have a reliability-related need for the 

information. Since SOLs are determined to maintain Bulk-Power System facilities 

within acceptable operating limits, the communication of those limits to those with a 

reliability related need, ensures the protection of Bulk-Power System facilities, thus 

preventing cascading failures of the interconnected grid, the Commission directs NERC 

to assign a high Violation Risk Factor to FAC-014-1, Requirement R5 and subRequirements R5.1. 

176. The Commission also disagrees with NERC that the Commission’s proposal to 

revise Violation Risk Factors for Requirement R5 and its sub-Requirements is 

inconsistent with previously approved Violation Risk Factor assignments. NERC’s 

reference to the medium Violation Risk Factor assigned to IRO-015-1, Requirement R1 

and Ameren’s reference to the medium Violation Risk Factor assigned to FAC-013-1 

 92 Id. at 109. 

93 Id. at 161.
Docket No. RM07-3-000 - 86 - 

Requirements are not inconsistencies. In both instances, the information that is to be 

provided is not specifically relevant to SOLs and IROLs, where the Commission has 

approved high Violation Risk Factors. For example, the high Violation Risk Factor the 

Commission proposed in the NOPR is consistent with previously approved Violation 

Risk Factor assignments for similar Requirements R4 and R5 of Reliability Standard 

IRO-004-1. Reliability Standard IRO-004-1, Requirements R4 and R5 establish the 

provision and sharing of system study information, respectively, relevant to the 

determination of SOLs and IROLs. NERC proposed, and the Commission approved a 

high Violation Risk Factor for IRO-004-1, Requirements R4 and R5. As such, to ensure 

consistency with the conclusions of the Blackout Report and among similar 

Requirements of other Reliability Standards, the Commission directs NERC to revise the 

Violation Risk Factors for FAC-014-1, Requirements R5 and R5.1 to high. 

177. The Commission believes, however, that FAC-014-1, Requirements R5.1.1 - 

R5.1.4 provide supporting information. Therefore, the Commission believes a medium 

Violation Risk Factor is appropriate for these Requirements and the Violation Risk Factor 

assignments for FAC-014-1, Requirements R5.1.1-R5.1.4 do not need to be revised as the 

Commission proposed in the NOPR. 

4. FAC-010-1, Requirement 3.6 

178. Reliability Standard FAC-010-1, Requirement 3.6 establishes the criteria for 

determining, in the planning time horizon, when violating an SOL qualifies as an IROL, 

and criteria for developing any associated IROL Tv. NERC proposed to assign 
Docket No. RM07-3-000 - 87 - 

Requirement 3.6 a lower Violation Risk Factor. However, NERC proposed a medium 

Violation Risk Factor assignment to Reliability Standard FAC-011-1, Requirement R3.7 

which establishes the same criteria in the operating time horizon. The Commission 

believes that the criteria for determining when violating an SOL qualifies as an IROL 

should be the same regardless of whether in the planning time horizon or the operating 

time horizon. This fact is supported by the Blackout Report finding that FirstEnergy did 

not have an adequate criterion to determine voltage stability in both the planning and 

operating time frames. That failure led to the company in adopting an inappropriate 90 

percent minimum acceptable voltage factor.94 Based on these facts, the Commission 

concludes that the potential reliability risk to the Bulk-Power system for a violation of 

those criteria in the planning horizon is the same as the potential reliability risk in the 

operating horizon. The Commission expects consistency between similar, and in this 

instance, identically-worded, Requirements of Reliability Standards. Therefore, the 

Commission directs NERC to ensure that the proposed Violation Risk Factor for FAC010-1, Requirement R3.6 is changed from lower to medium. 

5. FAC-011-1, Requirement 3.4 

179. NERC did not propose a Violation Risk Factor assignment for Reliability Standard 

FAC-011-1, Requirement R3.4. Requirement R3.4 establishes a requirement that a 

Reliability Coordinator’s SOL methodology include a description of the level of detail to 

 94 Blackout Report at 42. 
Docket No. RM07-3-000 - 88 - 

be reflected in the system models that are used in the operating time frame. NERC 

assigned a lower Violation Risk Factor to FAC-010-1, Requirement 3.3 which establishes 

the same requirement for Planning Authorities’ SOL methodologies in the planning time 

frame. Consistent with the definition of a lower Violation Risk Factor, the Commission 

believes that a violation of FAC-011-1, Requirement 3.4 would not be expected to affect 

the electrical state or capability or the Bulk-Power System or the ability to effectively 

monitor and control the Bulk-Power System. As such, and to ensure consistency among 

similar Requirements of Reliability Standards, the Commission believes a lower 

Violation Risk Factor assignment is appropriate for FAC-011-1, Requirement R3.4. 

IV. Information Collection Statement

180. The Office of Management and Budget (OMB) regulations require that OMB 

approve certain reporting and recordkeeping (collections of information) imposed by an 

agency.95 The information collection requirements in this Final Rule are identified under 

the Commission data collection, FERC-725D “Facilities Design, Connections and 

Maintenance Reliability Standards.” Under section 3507(d) of the Paperwork Reduction 

Act of 1995,96 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 

 95 5 CFR 1320.11 (2007). 

96 44 U.S.C. 3507(d). 
Docket No. RM07-3-000 - 89 - 

First Street, N.E., Washington, D.C. 20426 [Attention: Michael Miller, Office of the 

Chief Information Officer], phone: (202) 502-8415, fax: (202) 208-2425, e-mail: 

Michael.Miller@ferc.gov. Comments on the requirements of the proposed rule may be 

sent to the Office of Information and Regulatory Affairs, Office of Management and 

Budget, Washington, D.C. 20503 [Attention: Desk Officer for the Federal Energy 

Regulatory Commission], fax: 202-395-7285, e-mail: oira_submission@omb.eop.gov. 

181. 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.

182. The NOPR proposed to approve three new Reliability Standards developed by 

NERC as the ERO. The NOPR stated that the three proposed Reliability Standards do 

not require responsible entities to file information with the Commission. Nor, with the 

exception of a three year self-certification of compliance, do the Reliability Standards 

require responsible entities to file information with the ERO or Regional Entities. 

However, the Reliability Standards do require responsible entities to develop and 
Docket No. RM07-3-000 - 90 - 

maintain certain information for a specified period of time, subject to inspection by the 

ERO or Regional Entities.97 

183. Burden Estimate: Our estimate below regarding the number of respondents is 

based on the NERC compliance registry as of April 2007. NERC and the Regional 

Entities have identified approximately 170 Investor-Owned Utilities, and 80 Large 

Municipals and Cooperatives. NERC’s compliance registry indicates that there is a 

significant amount of overlap among the entities that perform these functions. In some 

instances, a single entity may be registered under all four of these functions. Thus, the 

Commission estimates that the total number of entities required to comply with the 

information “reporting” or development requirements of the proposed Reliability 

Standards is approximately 250 entities. About two-thirds of these entities are investorowned utilities and one-third is a combination of municipal and cooperative 

organizations. 

184. The Public Reporting burden for the requirements approved in the Final Rule is as 

follows: 

 97 See NOPR at P 60-61 for a description of this information. 
Docket No. RM07-3-000 - 91 - 

Data Collection No. of 

Respondents 

No. of 

Responses 

Hours Per 

Respondent 

Total Annual 

Hours 

FERC-725D

Reporting: 90 Reporting: 

15,300 

Investor-Owned 

Utilities 

170 1 

Recordkeeping: 

210 

Recordkeeping: 

35,700 

Reporting: 90 Reporting: 

7,200 

Large 

Municipals and 

Cooperatives 

80 1 

Recordkeeping: 

210 

Recordkeeping: 

16,800 

Total 250 75,000 

Total Hours: (Reporting 22,500 hours + Recordkeeping 52,500 hours) = 75,000 hours. 

(FTE=Full Time Equivalent or 2,080 hours) 

Total Annual hours for Collection: (Reporting + recordkeeping = 75,000 hours. 

Information Collection Costs: The Commission projects the average annualized cost to 

be the total annual hours (reporting) 22,500 times $120 = $2,700,000. 

Recordkeeping = 52,500 @ $40/hour = $2,100,000 

Labor (file/record clerk @ $17 an hour + supervisory @23 an hour) 

Storage 1,800 sq. ft. x $925 (off site storage) = $1,665,000 

Total costs = $6,465,000. 
Docket No. RM07-3-000 - 92 - 

The Commission believes that this estimate may be conservative because most if not all 

of the applicable entities currently perform SOL calculations and the proposed Reliability 

Standards will provide a common methodology for those calculations. 

Title: FERC-725D Facilities Design, Connections and Maintenance Reliability 

Standards. 

Action: Proposed Collection of Information. 

OMB Control No: 1902-0247. 

Respondents: Business or other for profit, and/or not for profit institutions. 

Frequency of Responses: One time to initially comply with the rule, and then on 

occasion as needed to revise or modify. In addition, annual and three-year selfcertification requirements will apply. 

Necessity of the Information: The three Reliability Standards, if adopted, would 

implement the Congressional mandate of the Energy Policy Act of 2005 to develop 

mandatory and enforceable Reliability Standards to better ensure the reliability of the 

nation’s Bulk-Power System. Specifically, the three proposed Reliability Standards 

would ensure that system operating limits or SOLs used in the reliability planning and 

operation of the Bulk-Power System are determined based on an established 

methodology. 

Internal review: The Commission has reviewed the requirements pertaining to 

mandatory Reliability Standards for the Bulk-Power System and determined the proposed 

requirements are necessary to meet the statutory provisions of the Energy Policy Act of 

2005. These requirements conform to the Commission’s plan for efficient information 
Docket No. RM07-3-000 - 93 - 

collection, communication and management within the energy industry. The 

Commission has assured itself, by means of internal review, that there is specific, 

objective support for the burden estimates associated with the information requirements. 

V. Environmental Analysis

185. 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.98 The Commission has categorically excluded certain actions 

from this requirement as not having a significant effect on the human environment. The 

actions proposed here fall within the categorical exclusion in the Commission's 

regulations for rules that are clarifying, corrective or procedural, for information 

gathering, analysis, and dissemination.99 Accordingly, neither an environmental impact 

statement nor environmental assessment is required. 

VI. Regulatory Flexibility Act Certification

186. The Regulatory Flexibility Act of 1980 (RFA)100 generally requires a description 

and analysis of final rules that will have significant economic impact on a substantial 

number of small entities. Most of the entities, i.e., planning authorities, reliability 

 98 Order No. 486, Regulations Implementing the National Environmental Policy

Act, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs., Regulations Preambles 1986-

1990 ¶ 30,783 (1987). 

99 18 CFR 380.4(a)(5) (2007). 

100 5 U.S.C. 601-612. 
Docket No. RM07-3-000 - 94 - 

coordinators, transmission planners and transmission operators, to which the 

requirements of this Final Rule apply do not fall within the definition of small entities.101 

187. As indicated above, based on available information regarding NERC’s compliance 

registry, approximately 250 entities will be responsible for compliance with the three new 

Reliability Standards. It is estimated that one-third of the responsible entities, about 80 

entities, would be municipal and cooperative organizations. The approved Reliability 

Standards would apply to planning authorities, transmission planners, transmission 

operators and reliability coordinators, which tend to be larger entities. Thus, the 

Commission believes that only a portion, approximately 30 to 40 of the municipal and 

cooperative organizations to which the approved Reliability Standards will apply, qualify 

as small entities.102 The Commission does not consider this a substantial number. 

 101 The RFA definition of “small entity” refers to the definition provided in the 

Small Business Act (SBA), which defines a “small business concern” as a business that is 

independently owned and operated and that is not dominant in its field of operation. See

15 U.S.C. 632. 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 preceding year. 

102 According to the Department of Energy’s (DOE) Energy Information 

Administration (EIA), there were 3,284 electric utility companies in the United States in 

2005, and 3,029 of these electric utilities qualify as small entities under the SBA 

definition. Among these 3,284 electric utility companies are: (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; and (4) 219 privately owned utilities, of which 104 could be 

considered small entity private utilities. See Energy Information Administration 

Database, Form EIA-861, DOE (2005), available at

http://www.eia.doe.gov/cneaf/electricity/page/eia861.html. 
Docket No. RM07-3-000 - 95 - 

Moreover, as discussed above, the approved Reliability Standards will not be a burden on 

the industry since most if not all of the applicable entities currently perform SOL 

calculations and the approved Reliability Standards will simply provide a common 

methodology for those calculations. Accordingly, the Commission certifies that the 

approved Reliability Standards will not have a significant adverse impact on a substantial 

number of small entities. 

188. Based on this understanding, the Commission certifies that this rule will not have a 

significant economic impact on a substantial number of small entities. Accordingly, no 

regulatory flexibility analysis is required. 

VII. Document Availability

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

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

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

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

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

Washington D.C. 20426. 

190. 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. 
Docket No. RM07-3-000 - 96 - 

191. User assistance is available for eLibrary and the FERC’s website during normal 

business hours from FERC’s Online Support at 202-502-6652 (toll free at 1-866-208-

3676) or email at ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 

502-8371, TTY (202)502-8659. E-mail the Public Reference Room at 

public.referenceroom@ferc.gov. 

VIII. Effective Date and Congressional Notification

192. These regulations are effective [insert date 30 days from publication in 

FEDERAL REGISTER]. The Commission has determined, with the concurrence of the 

Administrator of the Office of Information and Regulatory Affairs of OMB, that this rule 

is not a “major rule” as defined in section 351 of the Small Business Regulatory 

Enforcement Fairness Act of 1996. 

By the Commission. 

( S E A L ) 

Kimberly D. Bose, 

 Secretary. 
 - 97 - 

Appendix A: Commission Directed Revisions to Violation Risk Factor Assignments 

Violation Risk Factor Standard 

Number 

Requirement 

Number Text of Requirement NERC 

Proposal 

Commission 

Determination 

Guideline 

 FAC-010-1 R2 The Planning Authority’s SOL Methodology shall 

include a requirement that SOLs provide BES 

performance consistent with the following: 

 LOWER Explanatory 

Text 

----- 

 FAC-010-1 R2.1 In the pre-contingency state, the BES shall 

demonstrate transient, dynamic and voltage 

stability; all Facilities shall be within their Facility 

Ratings and within their thermal, voltage and 

stability limits. In the determination of SOLs, the 

BES condition used shall reflect current or expected 

system conditions and shall reflect changes to 

system topology such as Facility outages. 

MEDIUM HIGH 3 

 (Consistent 

with 

FAC-011-1 

R2.1) 

 FAC-010-1 R2.2 Following the single Contingencies[1] identified in 

Requirement 2.2.1 through Requirement 2.2.3, the 

system shall demonstrate transient, dynamic and 

voltage stability; all Facilities shall be operating 

within their Facility Ratings and within their 

thermal, voltage and stability limits; and Cascading 

Outages or uncontrolled separation shall not occur. 

MEDIUM HIGH 3 

 (Consistent 

with 

FAC-011-1 

R2.2) 

 FAC-010-1 R3.6 Criteria for determining when violating a SOL 

qualifies as an Interconnection Reliability 

Operating Limit (IROL) and criteria for developing 

any associated IROL Tv. 

 LOWER MEDIUM 3 

 (Consistent 

with 

FAC-011-1 

R3.7) 

 FAC-011-1 *R2 The Reliability Coordinator’s SOL Methodology 

shall include a requirement that SOLs provide BES 

performance consistent with the following: 

MEDIUM Explanatory 

Text 

----- 

 FAC-011-1 *R2.1 In the pre-contingency state, the BES shall 

demonstrate transient, dynamic and voltage 

stability; all Facilities shall be within their Facility 

Ratings and within their thermal, voltage and 

stability limits. In the determination of SOLs, the 

BES condition used shall reflect current or expected 

system conditions and shall reflect changes to 

system topology such as Facility outages. 

MEDIUM HIGH ----- 

 FAC-011-1 *R2.2 Following the single Contingencies[1] identified in 

Requirement 2.2.1 through Requirement 2.2.3, the 

system shall demonstrate transient, dynamic and 

voltage stability; all Facilities shall be operating 

within their Facility Ratings and within their 

thermal, voltage and stability limits; and Cascading 

Outages or uncontrolled separation shall not occur. 

MEDIUM HIGH ----- 

FAC-011-1 R3.4 Level of detail of system models used to determine 

SOLs. 

Not 

assigned 

LOWER 3 

 (Consistent 

with 
 - 98 - 

Violation Risk Factor Standard 

Number 

Requirement 

Number Text of Requirement NERC 

Proposal 

Commission 

Determination 

Guideline 

FAC-010-1 

R3.3) 

 FAC-014-1 R5 The Reliability Coordinator, Planning Authority 

and Transmission Planner shall each provide its 

SOLs and IROLs to those entities that have a 

reliability-related need for those limits and provide 

a written request that includes a schedule for 

delivery of those limits as follows: 

MEDIUM HIGH 1, 3 

(Consistent 

with 

IRO-004-1 

R4 & R5) 

 FAC-014-1 R5.1 The Reliability Coordinator shall provide its SOLs 

(including the subset of SOLs that are IROLs) to 

adjacent Reliability Coordinators and Reliability 

Coordinators who indicate a reliability-related need 

for those limits, and to the Transmission Operators, 

Transmission Planners, Transmission Service 

Providers and Planning Authorities within its 

Reliability Coordinator Area. For each IROL, the 

Reliability Coordinator shall provide the following 

supporting information: 

MEDIUM HIGH 1, 3 

(Consistent 

with 

IRO-004-1 

R4 & R5) 

* Requirements whose proposed Violation Risk Factor assignment NERC identifies as meriting reconsideration 

Guideline 1: Violation Risk Factor assignment not consistent with Final Blackout Report conclusions 

Guideline 3: Violation Risk Factor assignment not consistent among Reliability Standards with similar Reliability Requirements
 - 99 - 

Appendix B: Commenters on Notice of Proposed Rulemaking

ABBREVIATION ENTITY 

Ameren Ameren Service Co. 

APPA American Public Power Association 

BPA+

 Bonneville Power Administration 

Duke Duke Energy Corporation 

EEI Edison Electric Institute 

EPSA Electric Power Supply Association 

FirstEnergy+

 FirstEnergy Service Company 

IESO Independent Electricity System Operator of 

Ontario 

ISO/RTO Council ISO/RTO Council 

MidAmerican MidAmerican Energy Company and PacifiCorp 

Midwest ISO Midwest Independent Transmission System 

Operator, Inc. 

NERC North American Electric Reliability Corp. 

NYISO+

 New York Independent System Operator, Inc. 

NRECA National Rural Electric Cooperative 

Association 

NYSRC New York State Reliability Council, LLC 

Ontario IESO+

 Ontario Independent Electricity System 

Operator 

Progress Energy Progress Energy, Inc. 

Santa Clara City of Santa Clara, California, doing business 

as Silicon Valley Power 

SoCal Edison Southern California Edison Company 

Southern Southern Company Services, Inc. 

WECC Western Electricity Coordinating Council 

Xcel Xcel Energy Services 

+ Comments filed out-of-time 
 - 100 - 

Appendix C: FAC Reliability Standards 
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