[Federal Register Volume 73, Number 6 (Wednesday, January 9, 2008)]
[Rules and Regulations]
[Pages 1770-1810]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E7-25488]



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Part IV





Department of Energy





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Federal Energy Regulatory Commission



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18 CFR Part 40



Facilities Design, Connections and Maintenance Reliability Standards; 
Final Rule

  Federal Register / Vol. 73, No. 6 / Wednesday, January 9, 2008 / 
Rules and Regulations  

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DEPARTMENT OF ENERGY

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, DOE.

ACTION: Final rule.

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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 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.

DATES: Effective Date: The approval granted in this order becomes 
effective due February 8, 2008.

FOR FURTHER INFORMATION CONTACT: Christy Walsh (Legal Information), 
Office of the General Counsel, Federal Energy Regulatory Commission, 
888 First Street, NE., Washington, DC 20426, (202) 502-6523.
    Robert Snow (Technical Information), Office of Electric 
Reliability, Division of Reliability Standards, Federal Energy 
Regulatory Commission, 888 First Street, NE., Washington, DC 20426, 
(202) 502-6716.

SUPPLEMENTARY INFORMATION: Before Commissioners: Joseph T. Kelliher, 
Chairman; Suedeen G. Kelly, Marc Spitzer, Philip D. Moeller, and Jon 
Wellinghoff.

 
                                                              Paragraph
                                                                Number
 
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
    E. Violation Risk Factors..............................          129
        1. General Issues..................................          132
        2. Requirements R2 and R2.1--R2.2.3 for FAC-010-1            147
         and FAC-011-1.....................................
        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 accepts three

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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\
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    \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).
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    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 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.
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    \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).
    \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).
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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. 693 \5\ and established this rulemaking proceeding to review the 
three new Reliability Standards.
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    \5\ On March 16, 2007, the Commission approved 83 of the 107 
Reliability Standards initially filed by NERC. See Mandatory 
Reliability Standards for the Bulk-Power 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).
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    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:
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    \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.''

    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.
    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\
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    \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).
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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. 890\8\ 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

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clarifications to NERC's glossary revisions.
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    \8\ Preventing Undue Discrimination and Preference in 
Transmission Service, Order No. 890, 72 FR 12266 (Mar. 15, 2007), 
FERC Stats. & Regs. ] 31,241 (2007).
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    11. After submitting these FAC Reliability Standards, NERC filed 
proposed Violation Risk Factors that correspond to each Requirement of 
the proposed Reliability Standards.\9\ 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.
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    \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 
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).
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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 accepts the WECC regional 
differences contained in FAC-010-1 and FAC-011-1. The Commission will 
discuss particular issues below as appropriate.\11\
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    \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 Web 
site, https://standards.nerc.net/.
    \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.
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    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.
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    \12\ In Order No. 693 at P 1893-98, the Commission approved the 
NERC glossary, directing specific modifications to the document.
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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 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\
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    \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.
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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\]
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    \15\ Order No. 693 at P 185.

    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 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\
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    \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.
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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 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\
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    \19\ NOPR at P 18-19 (citing Order No. 890 at P 290-95).
    \20\ Order No. 890 at P 290-95.
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    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

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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 
long-term 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 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 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 FAC-011-1 assumptions and conditions. The NERC comments 
describe this coordination:
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    \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.

    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 transparency 
requirements and mitigate potential for the exercise of undue 
discrimination.\23\
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    \23\ NERC Comments at 18-20.

    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\
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    \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).
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    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\
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    \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.
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    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 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.
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    \28\ See NERC Comments at 9-10 for a description of the 
methodologies.
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    27. EEI and APPA are concerned that the Commission may be 
duplicating

[[Page 1774]]

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 rely on physical path 
reservations within their boundaries. Therefore, these commenters 
conclude that ATC calculation is not critical.\29\
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    \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.
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    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 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    32. Ameren states that Reliability Standards should not impose 
inconsistent obligations on system users, but notes some calculations 
that appear similar may be different due to different applications. For 
instance, SOL system limit calculations may differ from planning 
calculations due to their application to different timeframes. 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 planning assumptions and that SOL contingencies must 
``be in balance'' with ATC contingencies.
---------------------------------------------------------------------------

    \31\ See, e.g., NYSRC and NYISO, and NRECA Comments.
---------------------------------------------------------------------------

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

[[Page 1775]]

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.
    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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.
    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    40. Several commenters note that SOL, ATC and TTC perform different 
functions.\36\ These commenters concur that while assumptions should 
generally be consistent, 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.
---------------------------------------------------------------------------

    \36\ See ISO/RTO Council and Southern Comments.
---------------------------------------------------------------------------

    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.
    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.
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

[[Page 1776]]

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 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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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.''
---------------------------------------------------------------------------

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).
---------------------------------------------------------------------------

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

    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 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.
---------------------------------------------------------------------------

    \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'').
---------------------------------------------------------------------------

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

    \44\ NOPR at P 23, 33.
---------------------------------------------------------------------------

Comments
    55. NERC explains that although the TPL Reliability Standards sets 
the

[[Page 1777]]

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.
    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 FAC-011-1. 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 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.
---------------------------------------------------------------------------

    \45\ NOPR at P 25.
---------------------------------------------------------------------------

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.
    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 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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

[[Page 1778]]

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 than studied,'' not as a qualifier of 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\
---------------------------------------------------------------------------

    \47\ See, e.g., ISO/RTO Council and NRECA Comments.
---------------------------------------------------------------------------

    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 day-ahead 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 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 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.
---------------------------------------------------------------------------

    \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 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).
---------------------------------------------------------------------------

    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 sub-
Requirement 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 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 
long-term 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.
    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

[[Page 1779]]

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 FAC-011-1 does not require a reliability coordinator to 
operate the real time system within SOLs determined from credible 
multiple contingency scenarios.\51\
---------------------------------------------------------------------------

    \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.''
    \51\ See NYSRC and NYISO Comments at 4-5.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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 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\
---------------------------------------------------------------------------

    \53\ NERC Comments at 7.
---------------------------------------------------------------------------

    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 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.
---------------------------------------------------------------------------

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

    79. The Commission does not agree with NYSRC and NYISO's suggestion 
that FAC-011-1 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.
---------------------------------------------------------------------------

    \55\ See id. P 1601-03.
---------------------------------------------------------------------------

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

[[Page 1780]]

NERC's revised 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. 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).
---------------------------------------------------------------------------

    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\]
---------------------------------------------------------------------------

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

    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.
---------------------------------------------------------------------------

    \59\ NOPR at P 20 (citing FPA section 215(c)(2)(D), 16 U.S.C. 
824o(c)(2)(D) (2000 & Supp. V 2005)).
---------------------------------------------------------------------------

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\ 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.''
---------------------------------------------------------------------------

    \60\ WECC Comments at 4 and Attachment A.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \61\ Seven Step Process at 1.
    \62\ Id.
    \63\ Id., Attachment B.
---------------------------------------------------------------------------

    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.
    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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \67\ WECC at 4.
---------------------------------------------------------------------------

    96. Further, the Seven Step Process, developed after a fair and 
open vetting at the Regional Entity, appears to

[[Page 1781]]

provide adequate due process for the entity responsible for 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.
---------------------------------------------------------------------------

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\]
---------------------------------------------------------------------------

    \69\ April 2006 Reliability Standards Filing, Glossary at 2.

---------------------------------------------------------------------------
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 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.
    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\
---------------------------------------------------------------------------

    \70\ See, e.g., NERC, EEI and APPA, and Duke Comments.
---------------------------------------------------------------------------

    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 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

[[Page 1782]]

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\
---------------------------------------------------------------------------

    \71\ See Duke, ISO/RTO Council and MidAmerican Comments.
---------------------------------------------------------------------------

    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 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.
    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 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 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 re-focus 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.

[[Page 1783]]

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\
---------------------------------------------------------------------------

    \72\ April 2006 Reliability Standards Filing, Glossary at 7.

---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------

    \73\ NOPR at P 42.
---------------------------------------------------------------------------

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 
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.
---------------------------------------------------------------------------

    \74\ Order No. 693 at P 278 (``The Commission finds that these 
Reliability Standards, with the interpretations provided by the 
Commission in the standard-by-standard discussion, meet the 
statutory criteria for approval as written and should be 
approved''), 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.
---------------------------------------------------------------------------

    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 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.
---------------------------------------------------------------------------

    \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.
    \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.
---------------------------------------------------------------------------

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 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 Reliability 
Standard

[[Page 1784]]

Requirement.\78\ The Commission also established guidelines for 
evaluating the validity of each Violation Risk Factor assignment.\79\
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    \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.
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    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
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 multi-year 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 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 FAC Reliability Standard. Thus, the Commission 
directs NERC to modify these ten Violation Risk Factors.\81\
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    \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.
---------------------------------------------------------------------------

    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 the revised Violation Risk Factors no later than 
90 days before the effective date of the relevant Reliability Standard.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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

[[Page 1785]]

Commission also notes that NERC should file Violation Severity Levels 
before the FAC Reliability Standards become effective.
---------------------------------------------------------------------------

    \83\ See North American Electric Reliability Corp., 118 FERC ] 
61,030, at P 91, order on compliance, 119 FERC ] 61,046, at P 33 
(2007).
---------------------------------------------------------------------------

    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.
    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 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 non-compliance 
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 as NERC Requirements R2.4 and R2.5 in FAC-010-1 and Requirement 
R3.3 for FAC-011-1 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 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 FAC-011-1
    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 post-contingency (sub-Requirements R2.2-
R2.2.3) bulk electric system using an accurate system topology with all 
facilities operating within their ratings and without post-contingency 
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

[[Page 1786]]

consistent with transient, dynamic and voltage stability in a 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\
---------------------------------------------------------------------------

    \84\ NOPR at P 53.
---------------------------------------------------------------------------

    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.
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 sub-
requirements 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.
    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 FAC-011-1, 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.
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., FAC-
010-1, Requirement R2.2), it would not have set its minimum acceptable 
voltage at 90 percent.\87\
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    \85\ See Order No. 693 at P 1683.
    \86\ Blackout Report at 41.
    \87\ Id. at 42.
---------------------------------------------------------------------------

    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-

[[Page 1787]]

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 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 TPL-001-
0, Requirement R1. TPL-002-0, Requirement R1 establishes reliable post-
contingency 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 
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 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.
---------------------------------------------------------------------------

    \88\ Ameren Comments at 14-15.
---------------------------------------------------------------------------

    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. 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.
---------------------------------------------------------------------------

    \89\ NERC Comments at 39.
---------------------------------------------------------------------------

    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 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 
blackouts \90\ 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

[[Page 1788]]

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.
---------------------------------------------------------------------------

    \90\ Blackout Report at 107.
    \91\ Id. at 109.
---------------------------------------------------------------------------

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 
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 make notifications and exchange reliability-related 
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 
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 reliability-
related 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 
Bulk-Power 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 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\
---------------------------------------------------------------------------

    \92\ Id. at 109.
    \93\ Id. at 161.
---------------------------------------------------------------------------

    175. For the reasons stated above and lessons learned from previous 
blackouts, the Commission believes Violation Risk Factor for 
Requirement R5 and the sub-requirements 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 
sub-Requirements 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 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.

[[Page 1789]]

NERC proposed to assign 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 FAC-010-1, Requirement R3.6 is 
changed from lower to medium.
---------------------------------------------------------------------------

    \94\ Blackout Report at 42.
---------------------------------------------------------------------------

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 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 First Street, NE., Washington, DC. 20426 [Attention: Michael 
Miller, Office of the Chief Information Officer], phone: (202) 502-
8415, fax: (202) 208-2425, e-mail: [email protected]. 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, DC 20503 [Attention: Desk Officer for the Federal Energy 
Regulatory Commission], fax: 202-395-7285, e-mail: [email protected].
---------------------------------------------------------------------------

    \95\ 5 CFR 1320.11 (2007).
    \96\ 44 U.S.C. 3507(d).
---------------------------------------------------------------------------

    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 maintain certain information for a 
specified period of time, subject to inspection by the ERO or Regional 
Entities.\97\
---------------------------------------------------------------------------

    \97\ See NOPR at P 60-61 for a description of this information.
---------------------------------------------------------------------------

    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 
investor-owned 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:

----------------------------------------------------------------------------------------------------------------
          Data collection
-----------------------------------    Number of       Number of     Hours per respondent    Total annual hours
             FERC-725D                respondents      responses
----------------------------------------------------------------------------------------------------------------
Investor-Owned Utilities..........             170               1  Reporting: 90........  Reporting: 15,300.
                                    ..............  ..............  Recordkeeping: 210...  Recordkeeping:
                                                                                            35,700.
Large Municipals and Cooperatives.              80               1  Reporting: 90........  Reporting: 7,200.
                                    ..............  ..............  Recordkeeping: 210...  Recordkeeping:
                                                                                            16,800.
                                   -----------------------------------------------------------------------------
    Total.........................             250  ..............  .....................  75,000.
----------------------------------------------------------------------------------------------------------------


[[Page 1790]]

    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.
    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 self-certification 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 
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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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 
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\
---------------------------------------------------------------------------

    \100\ 5 U.S.C. 601-612.
    \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.
---------------------------------------------------------------------------

    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. 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.
---------------------------------------------------------------------------

    \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 1,842 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.
---------------------------------------------------------------------------

    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 p.m. 
Eastern time) at 888 First Street, NE., Room 2A, Washington DC 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.
    191. User assistance is available for eLibrary and the FERC's Web 
site during normal business hours from FERC's Online Support at 202-
502-6652 (toll free at 1-866-208-3676) or e-mail at 
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. E-mail the

[[Page 1791]]

Public Reference Room at [email protected].

VIII. Effective Date and Congressional Notification

    192. These regulations are effective February 8, 2008. 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.
Kimberly D. Bose,
Secretary.

Appendix A: Commission Directed Revisions to Violation Risk Factor 
Assignments

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                    Violation risk factor
                                                                                        ---------------------------------------------
   Standard  number    Requirement  number              Text of requirement                                         Commission             Guideline
                                                                                            NERC  proposal         determination
--------------------------------------------------------------------------------------------------------------------------------------------------------
FAC-010-1............  R2.................  The Planning Authority's SOL Methodology     Lower..............  Explanatory Text......  ..................
                                             shall include a requirement that SOLs
                                             provide BES performance consistent with
                                             the following:
FAC-010-1............  R2.1...............  In the pre-contingency state, the BES shall  Medium.............  High..................  3 (Consistent with
                                             demonstrate transient, dynamic and voltage                                                FAC-011-1 R2.1).
                                             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
FAC-010-1............  R2.2...............  Following the single Contingencies \1\       Medium.............  High..................  3 (Consistent with
                                             identified in Requirement 2.2.1 through                                                   FAC-011-1 R2.2).
                                             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
FAC-010-1............  R3.6...............  Criteria for determining when violating a    Lower..............  Medium................  3 (Consistent with
                                             SOL qualifies as an Interconnection                                                       FAC-011-1 R3.7).
                                             Reliability Operating Limit (IROL) and
                                             criteria for developing any associated
                                             IROL Tv
FAC-011-1............  R2*................  The Reliability Coordinator's SOL            Medium.............  Explanatory Text        ..................
                                             Methodology shall include a requirement
                                             that SOLs provide BES performance
                                             consistent with the following:
FAC-011-1............  R2.1*..............  In the pre-contingency state, the BES shall  Medium.............  High                    ..................
                                             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
FAC-011-1............  R2.2*..............  Following the single Contingencies \1\       Medium.............  High                    ..................
                                             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
FAC-011-1............  R3.4...............  Level of detail of system models used to     Not assigned.......  Lower.................  3 (Consistent with
                                             determine SOLs                                                                            FAC-010-1 R3.3).
FAC-014-1............  R5.................  The Reliability Coordinator, Planning        Medium.............  High..................  1, 3 (Consistent
                                             Authority and Transmission Planner shall                                                  with IRO-004-1 R4
                                             each provide its SOLs and IROLs to those                                                  & R5).
                                             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:
FAC-014-1............  R5.1...............  The Reliability Coordinator shall provide    Medium.............  High..................  1, 3 (Consistent
                                             its SOLs (including the subset of SOLs                                                    with IRO-004-1 R4
                                             that are IROLs) to adjacent Reliability                                                   & R5).
                                             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:
--------------------------------------------------------------------------------------------------------------------------------------------------------
* 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.


[[Page 1792]]

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.

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[FR Doc. E7-25488 Filed 1-8-08; 8:45 am]
BILLING CODE 6717-01-C