[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
[[Page 1771]]
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
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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.
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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\
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\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\
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\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.
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\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.
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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\
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\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.
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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.
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\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.
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\89\ NERC Comments at 39.
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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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