Mandatory Reliability Standards for Interconnection Reliability Operating Limits, 16240-16250 [2011-6778]
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Federal Register / Vol. 76, No. 56 / Wednesday, March 23, 2011 / Rules and Regulations
(including all conditions and limitations
stipulated in the exemption) will be
taken to ensure safety. The FAA further
stated that ‘‘operations authorized under
these exemptions are specifically not air
tour, sightseeing, or air carrier
operations’’ and that the agency ‘‘in
determining the public interest derived
in any grant of exemption of this nature,
will take into consideration the number
of existing operational aircraft and
petitioners available to provide the
historic service to the public.’’
Consistent with the 2007 policy
statement, the FAA has accommodated
several industry requests to allow
operation of more modern-day military
jet aircraft (e.g., the McDonnell Douglas
F–4 Phantom and the McDonnellDouglas A–4 Skyhawk) under the LHFE
policy. To ensure safety, there are over
45 conditions and limitations the
exemption holder must comply with in
order to operate under the provisions of
the exemption. The FAA has found,
however, that operators have sometimes
misinterpreted these conditions and
limitations as permitting operations that
the FAA did not contemplate or intend.
FAA Policy
The evolution of LHFE operations in
the private sector, along with
availability of newer and more capable
former military aircraft, has raised
public safety and public policy concerns
that the FAA needs to assess.
Accordingly, the FAA is placing a
moratorium on the issuance of any new
LHFE exemptions, including addition of
new aircraft to current exemptions.
Current LHFE exemption holders can
continue to operate under their current
exemption. If the exemption is due to
expire during the moratorium, the FAA
will accept and process petitions to
extend current exemptions in
accordance with the established
regulatory exemption process. If a
change is required (i.e. removal of an
aircraft) the FAA will accept these
changes in accordance with the
regulatory processes. Additionally,
during the moratorium, as petitioners
request extensions to their LHFE
exemption, the FAA will add the
following clarifying limitations to all
LHFE exemptions to ensure consistent
application of current LHFE policy: 1.
Passengers are prohibited from
manipulating the aircraft flight controls
when the aircraft is operated under the
LHFE exemption, and 2. No aerobatics
may be performed in the aircraft while
operating under the LHFE exemption.
Finally, the FAA will begin its
evaluation of the current LHFE
exemption policies and practices, to
include evaluation of safety to the
paying members of the public who have
an expectation of aircraft safety and who
may not understand the inherent risks
associated with such flight. The FAA
expects to publish a new proposed
LHFE policy for comment on or before
September 30, 2012.
Issued in Washington, DC, on March 15,
2011.
John W. McGraw,
Acting Director, Flight Standards Service.
[FR Doc. 2011–6712 Filed 3–22–11; 8:45 am]
BILLING CODE 4910–13–P
DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
Reliability Standards were submitted to
the Commission for approval by the
North American Electric Reliability
Corporation (NERC), which the
Commission has certified as the Electric
Reliability Organization responsible for
developing and enforcing mandatory
Reliability Standards. The Reliability
Standards were designed to prevent
instability, uncontrolled separation, or
cascading outages that adversely impact
the reliability of the interconnection by
ensuring that the reliability coordinator
has the data necessary to assess its
reliability coordinator area during the
operations horizon and that it takes
prompt action to prevent or mitigate
instances of exceeding Interconnection
Reliability.
Operating Limits. The Commission
also approves the addition of two new
terms to the NERC Glossary of Terms.
In addition, the Commission approves
NERC’s proposed revisions to Reliability
Standards EOP–001–1, IRO–002–2,
IRO–004–2, IRO–005–3, TOP–003–1,
TOP–005–2, and TOP–006–2, which
remove requirements for the reliability
coordinator to monitor and analyze
system operating limits other than
interconnection reliability operating
limits.
Effective Date: This Rule will
become effective May 23, 2011.
FOR FURTHER INFORMATION CONTACT:
Darrell Piatt (Technical Information),
Office of Electric Reliability, Division of
Reliability Standards, Federal Energy
Regulatory Commission, 888 First
Street, NE., Washington, DC 20426.
Telephone: (202) 502–6687.
A. Cory Lankford (Legal Information),
Office of the General Counsel, Federal
Energy Regulatory Commission, 888
First Street, NE., Washington, DC 20426.
Telephone: (202) 502–6711.
William Edwards (Legal Information),
Office of the General Counsel, Federal
Energy Regulatory Commission, 888
First Street, NE., Washington, DC 20426.
Telephone: (202) 502–6669.
SUPPLEMENTARY INFORMATION:
DATES:
18 CFR Part 40
[Docket No. RM10–15–000; Order No. 748]
Mandatory Reliability Standards for
Interconnection Reliability Operating
Limits
Federal Energy Regulatory
Commission, DOE.
ACTION: Final rule.
AGENCY:
Under section 215 of the
Federal Power Act, the Federal Energy
Regulatory Commission (Commission)
approves three new Interconnection
Reliability Operations and Coordination
Reliability Standards and seven revised
Reliability Standards related to
Emergency Preparedness and
Operations, Interconnection Reliability
Operations and Coordination, and
Transmission Operations. These
SUMMARY:
Table of Contents
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Paragraph
Nos.
I. Background ............................................................................................................................................................................................
A. Mandatory Reliability Standards ..........................................................................................................................................
B. Order No. 693 Directives ......................................................................................................................................................
C. NERC Petition ........................................................................................................................................................................
1. IRO–008–1 ................................................................................................................................................................
2. IRO–009–1 ................................................................................................................................................................
3. IRO–010–1a ..............................................................................................................................................................
D. Notice of Proposed Rulemaking ...........................................................................................................................................
II. Discussion ............................................................................................................................................................................................
A. Division of Responsibilities for SOLs and IROLs ...............................................................................................................
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16241
Paragraph
Nos.
1. Continued Analysis of SOLs by Reliability Coordinators .....................................................................................
2. Documented Methodology to Identify System Operating Limit Information ......................................................
3. Current Practices for the Prevention and Mitigation of SOLs and IROLs and the Monitoring Capability of
the Reliability Coordinator ......................................................................................................................................
4. Reliability Coordinator’s Procedures for Selecting the SOLs for Evaluation by the Interchange Distribution
Calculator ..................................................................................................................................................................
5. Current Functional Model .......................................................................................................................................
B. Operational Analyses and Real-time Assessments ..............................................................................................................
C. Reliability Coordinator Actions to Operate Within IROLs .................................................................................................
D. IRO–010–1a ............................................................................................................................................................................
E. Violation Severity Levels and Violation Risk Factors .........................................................................................................
III. Information Collection Statement ......................................................................................................................................................
IV. Environmental Analysis .....................................................................................................................................................................
V. Regulatory Flexibility Act ...................................................................................................................................................................
VI. Document Availability .......................................................................................................................................................................
VII. Effective Date and Congressional Notification ................................................................................................................................
Before Commissioners: Jon Wellinghoff,
Chairman; Marc Spitzer, Philip D. Moeller,
John R. Norris, and Cheryl A. LaFleur.
Final Rule
Issued March 17, 2011.
1. Under section 215 of the Federal
Power Act (FPA),1 the Federal Energy
Regulatory Commission (Commission)
approves three new Interconnection
Reliability Operations and Coordination
(IRO) Reliability Standards and seven
revised Reliability Standards related to
Emergency Preparedness and
Operations (EOP), IRO, and
Transmission Operations (TOP). The
proposed Reliability Standards were
submitted to the Commission for
approval by the North American Electric
Reliability Corporation (NERC), which
the Commission has certified as the
Electric Reliability Organization (ERO)
responsible for developing and
enforcing mandatory Reliability
Standards.2 These Reliability Standards
were designed to prevent instability,
uncontrolled separation, or cascading
outages that adversely impact the
reliability of the interconnection by
ensuring that the reliability coordinator
has the data necessary to assess its
reliability coordinator area during the
operations horizon and that it takes
prompt action to prevent or mitigate
instances of exceeding Interconnection
Reliability Operating Limits (IROL).3
The Commission also approves the
addition of two new terms to the NERC
1 16
U.S.C. 824o (2006).
American Electric Reliability Corp., 116
FERC ¶ 61,062, order on reh’g & compliance, 117
FERC ¶ 61,126 (2006), aff’d sub nom. Alcoa, Inc. v.
FERC, 564 F.3d 1342 (DC Cir. 2009).
3 NERC defines IROLs as the value (such as MW,
MVar, Amperes, Frequency or Volts) derived from,
or a subset of the SOLs, which if exceeded, could
expose a widespread area of the bulk electric
system to instability, uncontrolled separation, or
cascading outages. See NERC Glossary, available at
https://www.nerc.com/docs/standards/rs/
Glossary_of_Terms_2010April20.pdf.
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Glossary of Terms (NERC Glossary). In
addition, the Commission approves
NERC’s proposed revisions to Reliability
Standards EOP–001–1, IRO–002–2,
IRO–004–2, IRO–005–3, TOP–003–1,
TOP–005–2, and TOP–006–2, which
remove requirements for the reliability
coordinator to monitor and analyze
system operating limits (SOL) 4 other
than IROLs.
2. In addition, the Commission asks
the ERO to evaluate certain issues
through ongoing standards development
and working group projects and to
develop appropriate revisions as
necessary. These issues regard the scope
of the reliability coordinator’s
responsibility under these and other
IRO Reliability Standards. In particular,
the Commission identifies, based on the
comments received, certain issues
regarding the delineation of the
responsibility of the reliability
coordinator to analyze, monitor and
communicate to other operating entities
the class of SOLs identified as ‘‘gridimpactive’’ SOLs by NERC.
I. Background
A. Mandatory Reliability Standards
3. Section 215 of the FPA requires a
Commission-certified ERO to develop
mandatory and enforceable Reliability
Standards, which are subject to
Commission review and approval. Once
approved, the Reliability Standards are
enforced by the ERO, subject to
Commission oversight, or by the
Commission independently.
B. Order No. 693 Directives
4. On March 16, 2007, the
Commission issued Order No. 693,
approving 83 of the 107 initial
4 NERC defines SOLs as the value (such as MW,
MVar, Amperes, Frequency or Volts) that satisfies
the most limiting of the prescribed operating
criteria for a specific system configuration to ensure
operation within acceptable reliability criteria. Id.
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33
34
37
38
45
52
56
64
73
78
79
80
83
Reliability Standards filed by NERC,
including the currently-effective IRO
Reliability Standards.5 Under section
215(d)(5) of the FPA, the Commission
directed NERC to develop modifications
to the IRO Reliability Standards to
address certain issues identified by the
Commission.
5. With respect to IRO–001–1, the
Commission directed the ERO to
develop modifications to eliminate the
regional reliability organization as an
applicable entity.6 The Commission also
directed the ERO to modify IRO–002–1
to require a minimum set of capabilities
that must be made available to the
reliability coordinator to ensure that a
reliability coordinator has the
capabilities it needs to perform its
functions.7 With respect to IRO–003–2,
the Commission directed the ERO to
develop a modification to create criteria
to define the term ‘‘critical facilities’’ in
a reliability coordinator’s area and its
adjacent systems.8 The Commission also
directed the ERO to modify IRO–004–1
to require the next-day analysis to
identify control actions that can be
implemented and effective within 30
minutes after a contingency. In addition,
the Commission directed the ERO to
consider adding Measures and Levels of
Non-Compliance to Reliability
Standards IRO–004–1 and IRO–005–1
that are commensurate with the
magnitude, duration, frequency and
causes of the violations and whether
these occur during normal or
contingency conditions.9
5 Mandatory Reliability Standards for the BulkPower System, Order No. 693, 72 FR 16416 (Apr.
4, 2007), FERC Stats. & Regs. ¶ 31,242, order on
reh’g, Order No. 693–A, 120 FERC ¶ 61,053 (2007).
6 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at
P 896.
7 Id. P 908.
8 Id. P 914.
9 Id. P 935. NERC has subsequently replaced
Levels of Non-Compliance with Violation Severity
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6. The Commission also directed the
ERO to conduct a survey on IROL
practices and actual operating
experiences by requiring reliability
coordinators to report any violations of
IROLs, their causes, the date and time,
the durations and magnitudes in which
actual operations exceed IROLs to the
ERO on a monthly basis for one year
beginning two months after the effective
date of Order No. 693.10 On October 31,
2008, NERC filed the results of its yearlong survey with the Commission.11 On
February 8, 2009, NERC supplemented
those results in a second filing.12
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C. NERC Petition
7. On December 31, 2009, NERC
submitted a petition to the Commission
(NERC Petition) 13 seeking approval of
proposed Reliability Standards IRO–
008–1, IRO–009–1, and IRO–010–1a.
Under these Reliability Standards,
reliability coordinators must analyze
and monitor IROLs within their WideArea 14 to prevent instability,
uncontrolled separation, or cascading
outages that adversely impact the
reliability of the interconnection. These
Reliability Standards do not require the
reliability coordinator to analyze and
monitor SOLs other than IROLs or to
take preventive action to avoid or
mitigate SOL violations within their
reliability coordinator area. In
developing the proposed IRO Reliability
Standards, NERC determined that it was
necessary to retire or modify certain
requirements from several existing
Reliability Standards. Therefore, NERC
proposed revisions to Reliability
Standards EOP–001–1,15 IRO–002–2,
Levels. See Order on Violation Severity Levels
Proposed by the Electric Reliability Organization,
123 FERC ¶ 61,284 (Violation Severity Level Order),
order on reh’g, 125 FERC ¶ 61,212 (2008).
10 Id. P 951.
11 NERC, Compliance Filing, Docket No. RM06–
16–006 (filed Oct. 31, 2008).
12 NERC, Compliance Filing, Docket No. RM06–
16–006 (filed Feb. 8, 2009).
13 North American Electric Reliability Corp., Dec.
31, 2009 Petition for Approval of Proposed New
and Revised Reliability Standards for Operating
Within Interconnection Operating Limits.
14 The term ‘‘Wide-Area’’ is defined in the NERC
Glossary, approved by the Commission. As defined,
Wide-Area includes not only the reliability
coordinators’ area, but also critical flow and status
information from adjacent reliability coordinator
areas as determined by detailed system studies to
allow the calculation of IROLs. See NERC Glossary
available at https://www.nerc.com/docs/standards/
rs/Glossary_of_Terms_2010April20.pdf.
15 Concurrent with its Petition in this Docket,
NERC filed a petition in Docket No. RM10–16–000
seeking approval of certain Emergency
Preparedness and Operations Reliability Standards.
NERC, Petition for Approval of Three Emergency
Preparedness and Operations Reliability Standards,
Docket No. RM10–16–000 (filed Dec. 31, 2009). As
part of its Petition in RM10–16–000, NERC
proposed to retire Requirement R3.4 of EOP–001–
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IRO–004–2, IRO–005–3, TOP–003–1,
TOP–005–2, and TOP–006–2, which
remove requirements for the reliability
coordinator to monitor and analyze
SOLs other than IROLs. NERC also
requests approval of new definitions
‘‘Operational Planning Analysis’’ and
‘‘Real-time Assessment.’’
8. These IRO Reliability Standards
together with the proposed revisions to
existing Reliability Standards divide
responsibility for SOLs and IROLs
between reliability coordinators and
transmission operators according to the
Functional Model.16 In its Petition,
NERC explains that having two entities
with the same primary responsibility is
not supported by the Functional
Model.17 However, NERC notes that
these IRO Reliability Standards should
not imply that the reliability coordinator
will not look at its future operations
with respect to specific SOLs.18 NERC
states that the reliability coordinator
must look at its future operations with
respect to specific SOLs to ensure that
their transmission operators are taking
actions at appropriate times, but the
primary responsibility for SOLs rests
with the transmission operators.
9. NERC explains that, under the new
IRO Reliability Standards, the reliability
coordinator retains overall visibility of
all operations within its Wide-Area
view, including some SOLs, although
the transmission operator is primarily
responsible for actions related to
SOLs.19 NERC states that the IRO
Reliability Standards were developed in
support of the authority and assignment
of tasks in the Functional Model.20
NERC explains that under the
Functional Model, while reliability
coordinators will assign their
transmission operators tasks associated
with IROLs, the reliability coordinator
has ultimate responsibility for these
tasks, and the reliability coordinator is
sanctioned if these tasks are not
performed as required by the Reliability
Standards.21
0. Each petition proposes unique changes to EOP–
001–0 reflecting the distinct issues addressed by the
respective Reliability Standards drafting teams. In
this Final Rule, the Commission is addressing
Version 2 of EOP–001 contained in Exhibit B of the
NERC Petition which reflects both the IRO and the
EOP proposed changes.
16 NERC, Reliability Functional Model, version 5,
at 30 (Dec. 2009), available at https://www.nerc.com/
files/Functional_Model_V5_Final_2009Dec1.pdf
(NERC Functional Model).
17 In its comments, NERC cites specific tasks
outlined in the Functional Model for the respective
duties of the reliability coordinator and
transmission operator with respect to SOLs and
IROLs. NERC Comments at 14.
18 NERC Petition at 77.
19 Id. at 78.
20 Id. at 7–9.
21 Id. at 8.
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10. NERC further explains that, in a
similar fashion, the Functional Model
assigns responsibility for SOLs that are
not IROLs to the transmission operator.
But, NERC states, this too is a shared
responsibility.22 NERC states that,
where the Transmission Operator has
primary responsibility for developing
the SOLs within its transmission
operator area, the transmission operator
may request the assistance of its
reliability coordinator in developing
these SOLs. In addition, NERC points
out that reliability coordinators are
responsible for ensuring that
transmission operators develop SOLs for
its reliability coordinator area in
accordance with a methodology
developed by the reliability
coordinator.23 NERC states that the
transmission operator must share its
SOLs with its reliability coordinator,
and the reliability coordinator must
share any SOLs it develops with its
transmission operator. NERC also states
that the reliability coordinator monitors
the status of some, but not all, SOLs.
1. IRO–008–1
11. Reliability Standard IRO–008–1
has the stated purpose of preventing
instability, uncontrolled separation, or
cascading outages that adversely impact
the reliability of the interconnection by
ensuring that the bulk electric system is
assessed during the operations horizon.
The proposed Reliability Standard
applies to reliability coordinators. IRO–
008–1 requires the reliability
coordinator to use analyses and
assessments as methods of achieving the
stated goal. The Reliability Standard
requires analysis of the reliability
coordinator’s Wide-Area ahead of time
and during real-time. It also requires
communication with the entities that
need to take specific operational actions
based on the analyses and assessments.
12. Reliability Standard IRO–008–1
contains three requirements.
Requirement R1 requires each reliability
coordinator to perform an Operational
Planning Analysis to assess whether the
planned operations for the next day
within its Wide-Area will exceed any of
its IROLs during anticipated normal and
contingency event conditions.
Requirement R2 requires the reliability
coordinator to perform a Real-Time
Assessment at least once every 30
minutes to determine if its Wide Area is
exceeding any IROLs or is expected to
exceed any IROLs. Requirement R3
requires a reliability coordinator to
share the results of an Operational
22 Id.
at 9.
Reliability Standard FAC–011–1,
Requirement R3.
23 NERC
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Planning Analysis or Real-Time
Assessment that indicates the need for
specific operational actions to prevent
or mitigate an instance of exceeding an
IROL with those entities that are
expected to take those actions.
13. NERC also requests approval of
two new terms that appear in IRO–008–
1: ‘‘Operational Planning Analysis’’ and
‘‘Real-time Assessment.’’ Operational
Planning Analysis is defined as:
An analysis of the expected system
conditions for the next day’s operation. (That
analysis may be performed either a day ahead
or as much as 12 months ahead.) Expected
system conditions include things such as
load forecast(s), generation output levels, and
known system constraints (transmission
facility outages, generator outages, equipment
limitations, etc.).
NERC states that the definition was
designed to provide greater specificity
regarding the day-ahead study.
14. The proposed term ‘‘Real-time
Assessment’’ is defined as ‘‘[a]n
examination of existing and expected
system conditions, conducted by
collecting and reviewing immediately
available data.’’ NERC states that the
purpose of the new term is to assure that
the reliability coordinator is required to
conduct a real-time assessment,
including situations in which the
reliability coordinator is operating
without its primary analysis facilities
and has implemented the work-around
requirements of IRO–002–2,
Requirement R8.
2. IRO–009–1
15. As proposed, Reliability Standard,
IRO–009–1 is designed to prevent
instability, uncontrolled separation, or
cascading outages that adversely impact
the reliability of the interconnection by
‘‘ensuring prompt action to prevent or
mitigate instances of exceeding
[IROLs].’’ Proposed Reliability Standard
IRO–009–1 applies only to reliability
coordinators.
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3. IRO–010–1a
16. NERC proposes the addition of a
new Reliability Standard, IRO–010–1a 24
to the current suite of IRO Reliability
Standards. IRO–010–1a is designed to
prevent instability, uncontrolled
separation, or cascading outages that
adversely impact the reliability of the
interconnection by mandating that the
reliability coordinator have the data it
needs to monitor and assess the
operation of its reliability coordinator
area.
24 Because
the interpretation for IRO–010–1 was
completed before the filing of IRO–010–1, NERC
requests Commission approval of IRO–010–1a,
which includes the standard as interpreted.
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17. The requirements in the
Reliability Standard specify a formal
request process for the reliability
coordinator to explicitly identify the
data and information it needs for
reliability; and require the entities with
the data to provide it as requested. The
Reliability Standard applies to the
reliability coordinator and to the other
functional entities that must supply data
to the reliability coordinator.25 This
includes entities that have been
identified as owners, users, or operators
of the Bulk-Power System.
D. Notice of Proposed Rulemaking
18. On November 18, 2010, the
Commission issued a Notice of
Proposed Rulemaking (NOPR)
proposing to approve Reliability
Standards IRO–008–1, IRO–009–1, and
IRO–010–1a; revised Reliability
Standards EOP–001–1, IRO–002–2,
IRO–004–2, IRO–005–3, TOP–003–1,
TOP–005–2, and TOP–006–2; and the
two new NERC Glossary terms.
19. In the NOPR, the Commission
agreed with NERC that it is appropriate
to develop requirements for Reliability
Standards that offer a clear division of
responsibilities among reliability
coordinators and transmission
operators. In addition, the Commission
sought ERO and public comment to
ensure that the proposed Reliability
Standards will not create a reliability
gap by the inappropriate division of
responsibilities for analyzing,
monitoring and resolving SOLs and
IROLs between transmission operators
and reliability coordinators respectively.
20. In response to the NOPR, NERC
and a number of parties filed comments.
PJM Interconnection L.L.C., ISO New
England, New York Independent System
Operator, Inc., California Independent
System Operation Corporation and
Southwest Power Pool submitted joint
comments (Joint Commenters). The
Edison Electric Institute (EEI), Midwest
Independent Transmission System
Operator, Inc. (Midwest ISO), and
Western Electricity Coordinating
Council (WECC) also submitted timely
comments. American Electric Power
Service Corp. (AEP) filed comments one
day out-of-time.
II. Discussion
21. The Commission hereby adopts its
NOPR proposals and approves new
Reliability Standards IRO–008–1, IRO–
25 The requirements in the standard are
specifically applicable to the following functional
entities: (1) Reliability coordinator[s]; (2) balancing
authority; (3) generator owner; (4) generator
operator; (5) interchange authority; (6) load-serving
entity; (7) transmission operator; and (8)
transmission owner.
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009–1, and IRO–010–1a; revised
Reliability Standards EOP–001–1, IRO–
002–2, IRO–004–2, IRO–005–3, TOP–
003–1, TOP–005–2, and TOP–006–2;
and the two new NERC Glossary terms:
‘‘Operational Planning Analysis’’ and
‘‘Real-time Assessment.’’ In approving
these Reliability Standards, the
Commission concludes that they are
just, reasonable, not unduly
discriminatory or preferential, and in
the public interest. These Reliability
Standards serve an important reliability
purpose in seeking to prevent
instability, uncontrolled separation, or
cascading outages that adversely impact
the reliability of the interconnection by
ensuring that the reliability coordinator
has the data necessary to assess its
reliability coordinator area during the
operations horizon and that it takes
prompt action to prevent or mitigate
instances of exceeding IROLs. Moreover,
they clearly identify the entities to
which they apply and contain clear and
enforceable requirements. Commenters
addressed many of the Commission
concerns discussed in the NOPR and in
some areas the ERO has indicated that
it is continuing to study some issues
related to the Commission concerns.
The Commission encourages the ERO,
applying its technical expertise, to
continue such reviews and make any
necessary changes to applicable
Reliability Standards.
A. Division of Responsibilities for SOLs
and IROLs
22. In the NOPR, the Commission
sought comment on a number of issues
related to NERC’s division of
responsibilities for SOLs and IROLs
between reliability coordinators and
transmission operators. NERC
acknowledges in its Petition that the
transmission operator must develop and
share its SOLs with its reliability
coordinator, and the reliability
coordinator must share any SOLs it
develops with its transmission
operator.26 NERC also states that it is
currently working on a project to
identify a subset of SOLs, other than
IROLs, that the transmission operator
and reliability coordinator must
continuously analyze and monitor.27
Therefore, in the NOPR, the
Commission sought comment on
whether there is a need for reliability
coordinators to continue to analyze, in
addition to continuing to monitor and
coordinate data on, SOLs other than
26 NERC
Petition at 77.
identifies this as ‘‘Project 2007–03: Realtime Operations,’’ available at https://
www.nerc.com/filez/standards/Realtime_Operations_Project_2007–03.html.
27 NERC
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IROLs.28 The Commission also sought
comment on whether the reliability
coordinator should have a documented
methodology for identifying the SOL
information it needs to fulfill its
responsibilities for day-ahead analysis,
monitoring and real-time assessments,
and operational control within the
reliability coordinator’s area.
23. The Commission requested
information from NERC, reliability
coordinators, and other interested
entities on the current practices of
reliability coordinators and
transmission operators with respect to
coordinating operational responsibilities
for monitoring, day ahead and real-time
assessments. The Commission also
asked for comments on Bulk-Power
System operations related to SOLs and
IROLs, on the practical division of
responsibilities for preventing and
mitigating SOL and IROL violations,
and the monitoring capabilities of the
reliability coordinator with respect to
IROLs as well as other SOLs.
Additionally, the Commission asked
whether a reliability coordinator can
provide an accurate assessment of the
Bulk-Power System to its transmission
operators on a Wide-Area basis, without
evaluating: (1) The operating
environment of SOLs that will impact
the transmission operators within the
reliability coordinator’s areas; (2) SOLs
that have the potential to become IROLs;
and, (3) the existing IROLs within the
reliability coordinator area. The
Commission further sought comment as
to whether a transmission operator can
provide reliable operating assessments
or make reliable operating instructions
on an SOL that is on the border between
two different transmission operator’s
areas. The Commission also requested
comment on whether the reliability
coordinator should have responsibility
to monitor certain SOLs other than
IROLs, and whether such a
responsibility would place an
unreasonable burden on reliability
coordinators.
24. The Commission noted that IRO–
006–4.1 requires the reliability
coordinator to model SOLs and IROLs
in the Interchange Distribution
Calculator (IDC) to perform the
Transmission Loading Relief
procedures. We sought comment on
how reliability coordinators in the
Eastern Interconnection select the SOLs
for evaluation in the IDC and the extent
of any burden this has caused the
reliability coordinator.
28 Under NERC FAC–011–2, reliability
coordinators must have a documented methodology
for use in developing SOLs within its reliability
coordinator area.
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25. Finally, the Commission also
sought comments from NERC and the
public as to how the current Functional
Model represents the delineation of
assessment and operating
responsibilities between the reliability
coordinator and transmission operator
with respect to SOLs and IROLs.
Comments
1. Continued Analysis of SOLs by
Reliability Coordinators
26. NERC states in its comments, that
the proposed IRO Reliability Standards
appropriately distinguish which entity
has primary responsibility for SOLs.
Further, Bulk-Power System reliability
practices assign responsibilities for
analyzing and resolving conditions to
the entities closest to it, so that the
entity with the closest eye to the
condition can quickly assess and resolve
it. NERC asserts that it is appropriate for
transmission operators to maintain
primary responsibility for SOLs, and for
reliability coordinators to maintain
primary responsibility for IROLs. NERC
also explains that, while SOLs are
typically associated with the prevention
of facility damage or the accelerated
degradation of equipment life, only a
subset of SOLs are used to analyze and
monitor local area reliability and,
therefore, the proposed IRO standards
are silent on the reliability coordinator’s
responsibility with respect to SOLs.
27. NERC notes in its Petition, that the
proposed Reliability Standards ‘‘should
not imply that the Reliability
Coordinator will not look at its future
operations with respect to specific
SOLs.’’ 29 NERC also states that ‘‘[t]he
Reliability Coordinator retains the
overall visibility of all operations within
its Wide-Area view, including some
SOLs, although the transmission
operator is primarily responsible for
actions related to SOLs.’’ 30 NERC also
notes that the reliability coordinator can
monitor the transmission operator’s
actions to resolve SOLs and provides, as
an example, that the reliability
coordinator can study real-time
operating trends to help determine
whether an asset is trending toward a
‘‘grid-impactive SOL.’’ 31
28. In its comments, NERC provides
the results of a survey conducted in
response to the NOPR in which each of
the nine reliability coordinators in the
Eastern Interconnection responded that,
29 NERC
Petition at 9.
Petition at 10.
31 NERC Comments at 7. NERC does not offer a
definition of the term ‘‘grid-impactive SOL,’’ but we
understand it to mean an SOL that the reliability
coordinator monitor so that it does not develop into
an IROL.
30 NERC
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for SOLs that it monitors, the SOLs were
developed in a coordinated fashion with
the transmission operators in its area.
The survey responses did not suggest
that any transmission operator withheld
important SOL information from
reliability coordinators, nor did any
reliability coordinator indicate that
transmission operators were not willing
to work with the reliability coordinators
in monitoring SOLs for Bulk-Power
System reliability. NERC contends that
this survey demonstrates that current
operating practices are effective to
ensure that reliability coordinators are
able to obtain sufficient information
from transmission operators in order to
analyze and monitor certain SOLs other
than IROLs.
29. NERC also notes that, since the
completion of the proposed IRO
standards, the industry has been
working to improve the clarity of
Reliability Standard requirements
regarding the transmission operator’s
primary responsibility for SOLs through
the Real-time Operations Standard
Drafting Team (Project 2007–03). For
example, NERC explains that the
Standard Drafting Team has proposed to
add a requirement to TOP–001–2 that
would require each transmission
operator to inform its reliability
coordinator of all SOLs which, while
not IROLs, have been identified by the
transmission operator as supporting its
local area reliability based on its
assessment of its Operational Planning
Analysis. NERC states that, by using
tools that properly model Wide-Area
conditions, the reliability coordinators
are able to identify and help resolve
lower-level issues that may not
explicitly be included in the reliability
coordinator modeling capabilities. EEI
supports NERC’s comments to the
NOPR and believes that the Commission
should encourage the NERC reliability
coordinators working group to engage
these issues with NERC stakeholders,
especially the NERC Planning and
Operating Committees.
30. The Joint Commenters support the
proposed primary division of
responsibilities for SOLs and IROLs
between reliability coordinators and
transmission operators. They contend,
though, that the proposed division
should not be interpreted as implying
that a reliability coordinator should not
monitor any SOLs. The Joint
Commenters further contend that it was
not intended that the proposed
Reliability Standards would remove all
responsibility for SOLs from the
reliability coordinator, but to establish a
clear distinction of responsibilities and
authority. The Joint Commenters state
that they would not support a formal
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requirement that would assign primary
responsibility for analyzing and
resolving SOLs to a reliability
coordinator since the primary
responsibility is correctly assigned to
the transmission operator that is most
familiar with their respective operating
limits and local Bulk-Power System
characteristics.
31. Midwest ISO states that it is
necessary for reliability coordinators to
analyze, monitor, and coordinate some
SOLs other than IROLs and that the
Reliability Standards should reflect this
best practice. Midwest ISO believes the
Commission should encourage the
efforts currently underway at NERC
towards the development of Reliability
Standards addressing the role of
reliability coordinators with regard to
analyzing SOLs, other than IROLs, that
are important to the reliable operation of
the Bulk-Power System.
32. AEP states that it generally
supports the proposed Reliability
Standards but that it agrees with
concerns raised by the Commission that
if reliability coordinators are not
monitoring other SOLs, there is a
potential gap in monitoring for SOLs
that have the potential to become IROLs.
AEP argues that performing an annual
IROL identification would be
insufficient because it could miss some
opportunities to identify these
potentially new IROLs when they could
be material. AEP asserts that, at a
minimum, reliability coordinators
should be required to be involved in
SOLs that could border two different
transmission operators’ areas to ensure
the activities are appropriately
coordinated. AEP states that reliability
coordinators and transmission operators
should develop this subset of SOLs
through joint analysis, or agreement.
AEP requests that the Commission
direct NERC to develop a modification
to proposed Reliability Standards EOP–
001–1, IRO–002–2, IRO–004–2, IRO–
005–3, TOP–003–1, TOP–005–2, and
TOP–006–2, to require reliability
coordinators to work together with
transmission operators in developing
and monitoring SOLs that border
multiple transmission operators’ areas.
2. Documented Methodology To Identify
System Operating Limit Information
33. NERC asserts that, because
proposed Reliability Standard IRO–008–
1 requires reliability coordinators to use
tools to model transmission and
generation assets based on ratings
provided by asset owners, it is
unnecessary to impose an additional
requirement that the reliability
coordinator have a documented
methodology for identifying the SOL
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information it needs because the
systems and controls in place already
provide the information needed by the
reliability coordinators. The Joint
Commenters also believe that such a
methodology is unnecessary because, in
its defined role, a reliability coordinator
already will have access to, and be
provided with, the appropriate set of
SOLs from the transmission operator.
3. Current Practices for the Prevention
and Mitigation of SOLs and IROLs and
the Monitoring Capability of the
Reliability Coordinator
34. NERC states that current practices
give the reliability coordinators the
ability to provide assessments of the
Bulk-Power System to their
transmission operators on a Wide-Area
basis. NERC believes it is unnecessary to
require reliability coordinators to have
additional responsibility to monitor
SOLs other than IROLs. NERC also notes
that there are checks in place that allow
the reliability coordinator to monitor
SOLs that could turn into IROLs. As an
example, NERC points out that IRO–
010–1a requires reliability coordinators
to conduct Operational Planning
Analyses and Real-Time Assessments to
identify any IROLs that may be
exceeded.
35. NERC states that the electric
power industry is predicated on
interdependencies. NERC describes the
interdependency of transmission
operators and reliability coordinators as
enabling the reliability coordinator both
to control IROLs and flows, and to be
aware of local issues, giving the
reliability coordinator the ability to
monitor SOLs that may become IROLs
within the reliability coordinators areas.
NERC further explains that it is working
on Project 2007–03—Real-Time
Operations to develop proposed
revisions to the TOP standards that
require a transmission operator to
perform Operational Planning Analyses
for its transmission operator area. NERC
states that Project 2007–03 is
considering revisions to the Reliability
Standards that would require
observation of SOL limits in adjoining
areas.
36. The Joint Commenters state that
the proposed IRO Reliability Standards
hold reliability coordinators to the
proper assessment of information
required to provide accurate
assessments on a Wide-Area basis. The
Joint Commenters also caution that
‘‘accurate assessments’’ do not equate to
precise results and the Commission
should refrain from mandating that
reliability coordinators provide accurate
assessments.
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16245
4. Reliability Coordinator’s Procedures
for Selecting the SOLs for Evaluation by
the Interchange Distribution Calculator
37. NERC states that reliability
coordinators in the Eastern
Interconnection select which SOLs to
evaluate in the interchange distribution
calculator based on information
received from the transmission
operators indicating that the
transmission operator has a facility that
is approaching or exceeding its SOL
and/or IROL. NERC states that the
interchange distribution calculator is a
congestion management tool that helps
the reliability coordinators deal with
transmission constraints. In the survey
conducted by NERC of reliability
coordinators, one reliability coordinator
responded that it publishes most of its
information for use by any entity that
may wish to use the information in its
reliability assessments. Another
reliability coordinator responded that it
does not enter SOLs in its area into the
interchange distribution calculator, but
flowgates are entered into the
interchange distribution calculator that
may have SOLs or IROLs associated
with them. Entering the flowgates
allows an entity to determine if external
schedules are impacting the flowgate.
5. Current Functional Model
38. NERC argues that Version 5 of the
NERC Functional Model makes a clear
distinction between the duties of the
reliability coordinator and transmission
operator with respect to SOLs and
IROLs in certain task descriptions.32
Similarly, the Joint Commenters state
that the latest NERC Functional Model
divides reliability components and
allocates them to ‘‘unique’’ baskets of
tasks which include a fundamental
reliability task to do Wide-Area analysis
and another task for local analysis.
Commission Determination
39. As we stated in the NOPR, we
believe that it is appropriate for
Reliability Standards requirements to
offer a clear division of responsibilities
among reliability coordinators and
transmission operators. The
preponderance of comments to the
NOPR supports Commission approval of
the Reliability Standards as proposed by
NERC, including the proposed division
of responsibilities. For the reasons
described below, we approve the
division of responsibility for SOLs and
IROLs among transmission operators
and reliability coordinators as expressed
in the proposed Reliability Standards.
40. NERC and others suggest that
these Reliability Standards are not
32 See
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intended to remove all responsibility for
the analysis and monitoring SOLs from
the reliability coordinator. We agree.
These Reliability Standards generally
establish a clear distinction of primary
responsibility for SOLs and IROLs
between the transmission operator and
reliability coordinator respectively. As
NERC notes, however, the reliability
coordinator will continue to have the
ability and the responsibility to analyze
and monitor SOLs that could turn into
IROLs. For example, Requirements R5
and R6 of Reliability Standard IRO–
002–2 require the reliability coordinator
to monitor the important elements that
could be critical to SOLs and IROLs
within the reliability coordinator’s area
and surrounding reliability coordinator
areas. In addition, the proposed IRO
Reliability Standards require the
reliability coordinator to conduct
Operational Planning Analyses and
Real-time Assessments of its reliability
coordinator area. As NERC explained,
the Operational Planning Analyses look
at the expected system conditions and
potential reliability impacts, with a
focus on any impacts that affect the
Wide-Area. Although a transmission
operator lacks the tools to predict the
impact on the surrounding transmission
operator areas due to any changes in
flow between inter-area facilities, a
reliability coordinator addresses these
facilities in its Wide-Area modeling
capabilities.
41. As the Commission noted in its
NOPR, Reliability Standard IRO–002–2
continues to require each reliability
coordinator to monitor SOLs other than
IROLs both within its reliability
coordinator area and in surrounding
reliability coordinator areas.
Specifically, under Requirement R4 of
IRO–002–2, each reliability coordinator
must have detailed real-time monitoring
capability of its reliability coordinator
area and sufficient monitoring
capability of its surrounding reliability
coordinator areas to ensure that
potential or actual SOL or IROL
violations are identified and analyzed.
In addition, under Requirement R5,
each reliability coordinator must
monitor bulk electric system elements
such as generators, transmission lines,
buses, transformers and breakers that
could result in SOL or IROL violations
within its reliability coordinator area.
Further, as the Commission noted in the
NOPR, the reliability coordinator must
resolve potential or actual violations of
SOL ratings by implementing a local or
area-wide transmission loading relief
procedure under Reliability Standard
IRO–006–4.1.
42. Nevertheless, as noted by NERC
and other commenters, there exists a
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subset of ‘‘grid-impactive’’ SOLs other
than IROLs that the Commission
believes may warrant closer analysis by
the reliability coordinator, in addition to
the analysis being conducted by the
transmission operator, that focuses on
whether these particular ‘‘gridimpactive’’ SOLs could become IROLs.
The Commission believes that there can
be considerable benefit derived from
some overlap in the responsibility for
analyzing and monitoring these ‘‘gridimpactive’’ SOLs since, by definition,
every IROL emanated from an SOL.
While the proposed Reliability
Standards continue to commit the
reliability coordinator to the analysis
and monitoring of SOLs that may
become IROLs, a subset of SOLs, such
as these ‘‘grid-impactive’’ SOLs, may
deserve a more defined analysis and
monitoring role on the part of the
reliability coordinator.
43. We acknowledge NERC’s and
industry’s continuing efforts to improve
the clarity of standard requirements
regarding SOLs through the Real-time
Operations Standard Drafting Team
(Project 2007–03). We believe that the
issues concerning the analysis and
monitoring of ‘‘grid-impactive’’ SOLs
that we note here can be raised and
considered in this or other ongoing
projects. NERC comments that it is
working on Project 2007–03 to develop
revisions to the TOP Reliability
Standards that require transmission
operators to perform operational
planning analyses for their local areas.
NERC also comments that this project is
also considering revisions that would
require that SOL limits in adjoining
areas be observed. In addition, there are
other open projects, such as Project
2006–06—Reliability Coordination,
which is analyzing appropriate
reliability coordinator functions and
responsibilities. In consideration of
these ongoing efforts, we will not direct
specific modifications to these
Reliability Standards and, rather, accept
NERC’s commitment to exercise its
technical expertise to study these issues
and develop appropriate revisions to
applicable Standards as may be
necessary.
44. Because the study and monitoring
of SOLs and IROLs is an issue at the
very core of Bulk-Power System
reliability, the Commission agrees with
EEI that the NERC Reliability
Coordinators Working Group should
engage the issues raised in this
proceeding with NERC stakeholders,
including the NERC Planning and
Operating committees, to determine
whether a need exists to further refine
the delineation of responsibilities
between the reliability coordinator and
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transmission operator for analyzing a
class of ‘‘grid-impactive’’ SOLs.
Depending on the results of that review,
we further encourage NERC, working
through its standard development
process, to develop appropriate
modifications to these and any other
related Reliability Standards as
necessary.
B. Operational Analyses and Real-time
Assessments
45. In the NOPR, the Commission
sought comment on the prudence of
using an Operational Planning Analysis
up to twelve months old. The
Commission asked whether this
timeframe is reasonable or whether the
timeframe should be shorter to ensure
that the analysis is not outdated. In
addition, the Commission sought
comment on whether the definition
should include measurable criteria to
determine whether it is appropriate to
use an existing analysis.
46. Further, the Commission
requested comments on the meaning of
‘‘immediately available data’’ within the
proposed definition of the NERC
Glossary definition of Real-Time
Assessment. The Commission proposed
to direct NERC to modify the definition
of ‘‘Real-time Assessment’’ to specify
that the type of data to be relied upon
by a reliability coordinator in
conducting a Real-time Assessment
must be based on adequate analysis
capabilities such as state estimation,
pre- and post-contingency analysis
capabilities (thermal, stability, and
voltage), and wide-area overview
displays referenced in Requirement R6
of IRO–002–2.
Comments
47. In response to the Commission’s
questions regarding the use of an
existing Operational Planning Analysis,
NERC states that it is unlikely that a
reliability coordinator would
deliberately rely on an Operational
Planning Analysis that does not reflect
its expected system conditions. NERC
asserts that a reliability coordinator will
rely on a twelve-month old operational
planning analysis only if system
conditions have not changed over that
time period. NERC states that the
proposed definition of Operational
Planning Analysis was developed, based
on stakeholder comments, to apply not
only to studies conducted for the day
ahead, but also for future use in possibly
developing requirements for seasonal
studies. Thus, NERC explains, the
definition includes the option of
performing an Operational Planning
Analysis up to twelve months ahead.
NERC further explains that the
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facility ratings to be exceeded. NERC
therefore contends that it would add
confusion to the process to require both
the reliability coordinator and
transmission operator to develop action
plans for every SOL.
54. Similarly, WECC does not believe
that reliability coordinators should be
required to have action plans developed
and implemented for SOLs apart from
IROLs. WECC argues that requiring the
reliability coordinator to second guess
rather than defer to the more granular
view and detailed view of the
transmission operators or balancing
authorities undermines and
substantially changes the roles of each
function without any foreseeable benefit
to overall reliability.
Commission Determination
49. The Commission approves the
definitions of ‘‘Operational Planning
Analysis’’ and ‘‘Real-time Assessment’’
without modification.
50. The Commission agrees with
NERC that the reliability coordinator
should rely on a twelve-month old
Operational Planning Analysis study
only if system conditions have not
changed from those originally studied.
Consistent with the views of NERC, we
expect that reliability coordinators will
rely on Operational Planning Analysis
that reflect expected system conditions.
Accordingly, we accept the definition as
proposed.
51. Similarly, we find it is
unnecessary to direct NERC to modify
the definition of ‘‘Real-time Assessment’’
to specify that the type of data to be
relied upon by a reliability coordinator
in conducting a Real-time Assessment
as proposed in the NOPR. Instead, the
Commission will allow industry to
complete Project 2009–02, which is
working towards consensus on the set of
data and capabilities the reliability
coordinators need to perform their tasks.
We expect NERC to use its technical
expertise to develop any modifications
to the definition of Real-time
Assessment as may be necessary as a
result of this ongoing project.
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definition includes key elements that
provide measurable criteria in assessing
an entity’s Operational Planning
Analysis.
48. In response to the Commission’s
questions regarding the proposed
definition of Real-time Assessment,
NERC and the Joint Commenters state
that the industry is currently working
towards consensus on the set of data
and capabilities the reliability
coordinators need to perform their tasks
via the Real-time Reliability Monitoring
and Analysis Capabilities Standards
Development Team (Project 2009–02).
Accordingly, NERC asks the
Commission to refrain from directing
modifications pending completion of
the project.
Commission Determination
55. The Commission agrees with
NERC that requiring both the reliability
coordinator and transmission operator
to develop action plans for every SOL
may add confusion to the process. As a
result, the Commission approves IRO–
009–1, without modification. However,
the Reliability Coordinator Working
Group should further study this issue
and determine if there is a need for
reliability coordinators to have action
plans developed and implemented with
respect to certain grid-impactive SOLs.
C. Reliability Coordinator Actions To
Operate Within IROLs
52. In the NOPR, the Commission
sought comment on whether reliability
coordinators should have action plans
developed and implemented with
respect to other SOLs apart from IROLs
and if so, which SOLs.
Comments
53. NERC states that transmission
operators already are responsible for
developing action plans for preventing
and/or mitigating conditions that cause
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D. IRO–010–1a
56. In the NOPR, the Commission
expressed concern that Reliability
Standard IRO–010–1a does not require
reliability coordinators to specify a list
of minimum data needed for reliable
operation of the Bulk-Power System.
The Commission, therefore, sought
comment on whether a minimum list of
data is necessary for the effective
sharing of data between neighboring
reliability coordinators and, if so, what
data should be included. The
Commission also sought comment on
how compatibility of data between
neighboring reliability coordinators can
be assured without a list of minimum
data in this proposed Reliability
Standard.
57. In its discussion of Reliability
Standard TOP–003–1, the Commission
noted that Requirement R3 of proposed
Reliability Standard IRO–010–1a
requires entities to provide data and
information to the reliability
coordinator in accordance with the
reliability coordinator’s specifications.
The Commission expressed concern that
this requirement does not specify outage
coordination data and, therefore, the
reliability coordinator may not receive
adequate outage coordination data to
support the Operational Planning
Analysis. Accordingly, the Commission
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16247
sought comment on whether IRO–010–
1a should specify necessary outage
coordination data.
Comments
58. NERC, the Joint Commenters and
Midwest ISO contend that requiring a
minimum list of data is not necessary
for the effective sharing of data between
neighboring reliability coordinators.
NERC argues that requiring a list of
minimum data not only could impair an
entity’s ability to provide the data to the
reliability coordinator quickly, but
could prevent a reliability coordinator
from obtaining needed data quickly.
NERC also notes that, during the
development of the proposed Reliability
Standard, the reliability coordinators
that were polled indicated they already
were receiving the data they needed
without any issues and that the data and
information they received varied from
one reliability coordinator to another.
The Joint Commenters argue that it is
unnecessary to develop such a
requirement because two interconnected
parties can agree upon the appropriate
type and level of data it needs from the
other, taking into consideration their
respective tools and capabilities.
Midwest ISO argues that many
reliability coordinators already have
developed coordination agreements
with their neighbors that identify the
information necessary for effective data
sharing. Midwest ISO contends that a
generic list of minimum data could be
inadequate to meet regional needs and
could create conflicts with existing
coordination agreements. Midwest ISO
further contends that a minimum list
could curb creativity and innovation as
capabilities develop new uses for data.
59. NERC and the Joint Commenters
also urge the Commission to refrain
from requiring NERC to modify IRO–
010–1a to specify the necessary outage
coordination data for all reliability
coordinators. They contend that such an
approach would not account for the
significantly varying facilities located
within the reliability coordinators’ area
and allow for the flexibility to specify
the data needed for its respective area.
60. Reiterating comments it raised
during the standard development
process, WECC opposes the requirement
in R1.2 that the parties reach mutual
agreement with respect to the format of
the data and information that the
reliability coordinator receives. WECC
argues that, due to the large number of
entities that must provide data to the
reliability coordinator, the requirement
for mutually agreeable formats may
cause the reliability coordinator to
receive data in a multitude of diverse
formats. WECC also believes that
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requiring mutually agreeable data
formats could delay the submission of
data by a submitting entity until
agreement can be reached via
negotiation or dispute resolution. WECC
argues that more than one party is
involved in the formulation of an
agreeable format yet only a reliability
coordinator will be found noncompliant when the reliability
coordinator and transmission operators
or balancing authorities within the
reliability coordinator area fail to reach
an agreement over an acceptable format.
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Commission Determination
61. The Commission agrees with
commenters that it is unnecessary to
direct NERC to develop a specific list of
minimum data for the effective sharing
of data between neighboring reliability
coordinators under Reliability Standard
IRO–010–1a. NERC and other entities
confirm that reliability coordinators
currently obtain necessary data without
such a specific list. In addition, as
commenters point out, a minimum list
may conflict with coordination
agreements currently in place which
identify the information necessary for
effective data sharing. With regard to the
concern expressed in the NOPR
regarding outage coordination data, we
accept that reliability coordinators
currently obtain necessary data. If, in
the future, reliability coordinators are
not able to obtain the necessary outage
coordination data, we would ask NERC
to consider whether a Reliability
Standard should be developed for the
reliability coordinators to obtain such
data.
62. In response to WECC’s concerns
about the submission of data in
mutually agreeable formats under
Requirement R1.2, we do not believe
any modification is necessary. As NERC
states in its Petition, by specifying that
the format must be mutually agreeable,
the standard supports efficiency by
precluding the submission of data that
is in a format that cannot be used. We
agree. NERC states that current data
exchange formats are acceptable.
Therefore, entities can continue to
utilize existing agreements regarding
data exchange. While disputes may arise
in the future, the Reliability Standard
does not dictate a specific dispute
resolution process in the interpretation
leaving reliability coordinators and
other entities options for informal
resolution of a dispute on the format of
data and flexibility in choosing a
dispute resolution process to reach an
agreement.
63. Accordingly, the Commission
approves IRO–010–1a as submitted.
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E. Violation Severity Levels and
Violation Risk Factors
64. In the event of a violation of a
Reliability Standard, NERC establishes
the initial value range for the
corresponding base penalty amount. To
do so, NERC assigns a violation risk
factor for each requirement of a
Reliability Standard that relates to the
expected or potential impact of a
violation of the requirement on the
reliability of the Bulk-Power System. In
addition, NERC defines up to four
violation severity levels—Lower,
Moderate, High, and Severe—as
measurements for the degree to which
the requirement was violated in a
specific circumstance.
65. In Order No. 705, the Commission
approved 63 of NERC’s 72 proposed
violation risk factors for the version one
FAC Reliability Standards and directed
NERC to file violation severity level
assignments before the version one FAC
Reliability Standards become
effective.33 Subsequently, NERC
developed violation severity levels for
each requirement of the Commissionapproved FAC Reliability Standards, as
measurements for the degree to which
the requirement was violated in a
specific circumstance.
66. On June 19, 2008, the Commission
issued its Violation Severity Level Order
approving the violation severity level
assignments filed by NERC for the 83
Reliability Standards approved in Order
No. 693.34 In that order, the Commission
offered four guidelines for evaluating
the validity of violation severity levels,
and ordered a number of reports and
further compliance filing to bring the
remainder of NERC’s violation severity
levels into conformance with the
Commission’s guidelines. The four
guidelines are: (1) Violation severity
level assignments should not have the
unintended consequence of lowering
the current level of compliance; (2)
violation severity level assignments
should ensure uniformity and
consistency among all approved
Reliability Standards in the
determination of penalties; 35 (3)
violation severity level assignments
should be consistent with the
corresponding requirement; and (4)
violation severity level assignments
should be based on a single violation,
33 Facilities Design, Connections and
Maintenance Reliability Standards, Order No. 705,
121 FERC ¶ 61,296, at P 137 (2007).
34 Violation Severity Level Order, 123 FERC
¶ 61,284.
35 Guideline 2 contains two sub-parts: (a) the
single violation severity level assignment category
for binary requirements should be consistent and
(b) violation severity levels assignments should not
contain ambiguous language.
PO 00000
Frm 00018
Fmt 4700
Sfmt 4700
not a cumulative number of
violations.36 The Commission found
that these guidelines will provide a
consistent and objective means for
assessing, inter alia, the consistency,
fairness and potential consequences of
violation severity level assignments.
The Commission noted that these
guidelines were not intended to replace
NERC’s own guidance classifications,
but rather, to provide an additional level
of analysis to determine the validity of
violation severity level assignments.
67. On August 10, 2009, NERC
submitted an informational filing setting
forth a summary of revised guidelines
that NERC intends to use in determining
the assignment of violation risk factors
and violation severity levels for
Reliability Standards. NERC states that
these revised guidelines were consistent
with Commission’s guidelines. On May
5, 2010, NERC submitted the subject
informational filing as a supplement to
its pending March 5, 2010 Violation
Severity Level Order compliance
filing.37
NERC Proposal
68. NERC proposes a complete set of
violation severity levels and violation
risk factors for proposed new Reliability
Standards IRO–008–1, IRO–009–1, and
IRO–010–1a. In addition, NERC
proposes to apply the existing set of
violation severity levels and violation
risk factors assigned to the proposed
modified requirements.
69. NERC states that it developed the
violation severity levels for the new IRO
Reliability Standards before the
Commission issued its June 19, 2008
Order on violation severity levels.38
NERC also notes that the proposed
violation severity levels were developed
before NERC proposed a new
methodology for assigning violation
severity levels and violation risk
factors.39 As a result, NERC states that
some of the proposed violation severity
levels do not comport with the
Commission’s guidelines on violation
severity levels and some do not comport
with the NERC’s revised guidelines.
NERC identified differences and
committed to propose revisions to the
violation severity levels.
36 Violation Severity Level Order, 123 FERC
¶ 61,284 at P 17.
37 North American Reliability Corporation, Filing
of the North American Electric Reliability
Corporation regarding the Assignment of Violation
Risk Factors and Violation Severity Levels, Docket
No. RR08–4–005 (filed May 5, 2010).
38 Id.
39 NERC, Informational Filing Regarding the
Assignment of Violation Risk Factors and Violation
Severity Levels, Docket Nos. RM08–11–000, RR07–
9–000, and RR07–10–000 (filed Aug. 10, 2009).
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70. Separately from NERC’s Petition
here, on March 5, 2010, NERC
submitted the first of two VSL
compliance filings (Filing 1) to the
Commission’s VSL Orders,40 which
contained the VSL assignments for the
original set of 83 Reliability Standards
approved by the Commission and NUC–
001–2. In addition, NERC requested an
extension for filing the remaining VSLs
until the 3rd quarter of 2010. On July 6,
2010, the Commission issued a Notice of
Extension of Time up to and including
December 1, 2010, for Filing 2.41 On
December 1, 2010, NERC submitted a
compliance filing to the Commission in
Docket No. RR08–04–006 (Filing 2). In
Filing 2, NERC submitted VSLs both for
Reliability Standards that are pending at
the Commission and Reliability
Standards previously approved by the
Commission. Filing 2 includes VSLs to
supersede those in NERC’s Petition in
Docket No. RM10–15–000 for EOP–001–
1, IRO–002–2, IRO–004–2, IRO–005–3,
IRO–008–1, IRO–009–1, IRO–010–1,
IRO–010–1a, TOP–003–1, TOP–005–2,
and TOP–006–2.42
NOPR Proposal
71. In the NOPR, the Commission
proposed to accept the proposed
violation risk factors and violation
severity levels presented in NERC’s
petition. In addition, the Commission
proposed to accept NERC’s commitment
to review the proposed violation risk
factors and violation severity levels to
ensure compliance with the
Commission’s guidelines. Accordingly,
we proposed to direct NERC to submit
a compliance filing within six months of
the effective date of the final rule in this
proceeding that would provide the
results of NERC’s review including any
modifications necessary to comply with
the Commission’s guidelines on
violation risk factors and violation
severity levels.
Commission Determination
72. Because a determination has not
yet been made regarding NERC’s ‘‘rollup’’ approach pending before the
Commission in Docket Nos. RR08–4–
005 and RR08–4–006, the Commission
will defer discussion on the proposed
violation risk factors and violation
severity levels assigned to IRO–008–1,
IRO–009–1, and IRO–010–1a, until after
the Commission issues a final order
acting on NERC’s petition in these
proceedings.
III. Information Collection Statement
73. The information collection
requirements in this Final Rule are
identified under the Commission data
collection FERC–725A, ‘‘Mandatory
Reliability Standards for the Bulk-Power
System.’’ The information collection
requirements are being submitted to the
Office of Management and Budget
(OMB) for review under section 3507(d)
of the Paperwork Reduction Act of
1995.43 OMB’s regulations require OMB
to approve certain information
collection requirements imposed by
agency rule.44
74. The Commission approves new
Reliability Standards IRO–008–1, IRO–
009–1, and IRO–010–1a; revised
Reliability Standards EOP–001–1, IRO–
002–2, IRO–004–2, IRO–005–3, TOP–
003–1, TOP–005–2, and TOP–006–2;
and the two new NERC Glossary terms:
‘‘Operational Planning Analysis’’ and
‘‘Real-time Assessment.’’ The three new
Reliability Standards (IRO–008–1, IRO–
009–1 and IRO–010–1a, governing
reliability coordinator analyses,
operational actions and data collection)
replace parts of the currently-effective
Reliability Standards EOP–001–0, IRO–
002–1, IRO–004–1, IRO–005–2, TOP–
003–0, TOP–005–1 and TOP–006–1
approved by the Commission in Order
No. 693.
16249
75. Thus, this final rule does not
impose entirely new burdens on the
affected entities. With the exception of
the addition of Interchange Authority as
an applicable entity in IRO–010–1a, the
currently-effective standards EOP–001–
0, IRO–002–1, IRO–004–1, IRO–005–2,
TOP–003–0, TOP–005–1 and TOP–006–
1 require actions by the same applicable
group of entities. IRO–010–1a clarifies
that balancing authorities, generator
owners, generator operators, interchange
authorities, load-serving entities,
reliability coordinators, transmission
operators, and transmission owners
shall provide data and information, as
specified, to the reliability
coordinator(s) with which it has a
reliability relationship.45 The
requirements of IRO–008–1 and IRO–
009–1 provide clarification from
existing requirements, dictating the
analysis and operational roles of the
reliability coordinator.
76. Public Reporting Burden: Our
estimate below regarding the number of
respondents is based on the NERC
compliance registry as of September 28,
2010. According to the NERC
compliance registry, there are 134
balancing authorities, 824 generator
owners, 773 generator operators, 61
interchange authorities, 541 loadserving entities, 26 reliability
coordinators, 178 transmission
operators, and 332 transmission owners
that would be involved in providing
information. However, under NERC’s
compliance registration program,
entities may be registered for multiple
functions, and as such there is some
duplication of functions regarding the
number of registered entities that would
be required to provide information.
Given these parameters, the
Commission estimates that the Public
Reporting burden for the requirements
contained in the final rule is as follows:
Number of
respondents
Number of
annual
responses
Hours per
respondent
Total annual
hours
(A)
FERC–725A data collection
(B)
(C)
(A × B × C)
26
*1
8
208
1,501
*1
8
12,008
Total ..........................................................................................
erowe on DSK5CLS3C1PROD with RULES
Reliability Coordinators distribution of data specification to entities
Balancing Authorities, Generator Owners, Generator Operators,
Interchange Authorities, Load-serving Entities, Reliability Coordinators, Transmission Operators, and Transmission Owners
reporting data to their Reliability Coordinator ..............................
............................
............................
............................
12,216
*As needed.
40 North American Electric Reliability Corp., 123
FERC ¶ 61,284 (2008), order on reh’g, 125 FERC
¶ 61,212 (2008) (VSL Orders).
41 North American Electric Reliability
Corporation, Docket No. RR08–4–005 (Jul. 6, 2010)
VerDate Mar<15>2010
15:27 Mar 22, 2011
Jkt 223001
(granting an extension of time for submitting this
VSL compliance filing up to and including
December 1, 2010).
42 See NERC, Compliance Filing, Docket No.
RR08–4–006, at 2 n.6 (filed Dec. 1, 2010).
PO 00000
Frm 00019
Fmt 4700
Sfmt 4700
43 44
U.S.C. 3507(d).
CFR 1320.11.
45 Proposed Reliability Standard IRO–010–1a,
Requirement R3.
44 5
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Federal Register / Vol. 76, No. 56 / Wednesday, March 23, 2011 / Rules and Regulations
• Total Information Collection Costs:
The Commission estimated that it
would require 12,216 total annual hours
for the information collection (reporting
and recordkeeping) and that the average
annualized costs would be $1,465,920
(12,216 hours @ $120/hour).
Title: FERC–725A, Mandatory
Reliability Standards for the Bulk-Power
System.
Action: Proposed Revision to FERC–
725A.
OMB Control No.: 1902–0244.
Respondents: Businesses or other forprofit institutions; not-for-profit
institutions.
Frequency of Responses: On
Occasion.
Necessity of the Information: This
Final Rule approves three Reliability
Standards that pertain to
interconnection reliability operating
limits and seven modified Reliability
Standards that pertain to emergency
preparedness and operations,
interconnection reliability operations
and coordination, and transmission
operations. This Final Rule also
approves the addition of two new terms
to the NERC Glossary of Terms. The
Reliability Standards that pertain to
interconnection reliability operating
limits will require reliability
coordinators and transmission operators
to coordinate data on system operating
limits and interconnection reliability
operating limits. This Final Rule finds
the Reliability Standards and related
definitions just, reasonable, not unduly
discriminatory or preferential, and in
the public interest.
77. Interested persons may obtain
information on the reporting
requirements by contacting: Federal
Energy Regulatory Commission, Attn:
Ellen Brown, Office of the Executive
Director, 888 First Street, NE.
Washington, DC 20426, E-mail:
DataClearance@ferc.gov, Tel: (202) 502–
8663, Fax: (202) 273–0873. Comments
on the requirements of this final rule
may also 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]. For security
reasons, comments should be sent by email to OMB at
oira_submission@omb.eop.gov. Please
reference OMB Control Number 1902–
0244, RIN 1902–AE17, and the docket
number of this final rule in your
submission.
IV. Environmental Analysis
78. The Commission is required to
prepare an Environmental Assessment
or an Environmental Impact Statement
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15:27 Mar 22, 2011
Jkt 223001
for any action that may have a
significant adverse effect on the human
environment.46 The Commission has
categorically excluded certain actions
from this requirement as not having a
significant effect on the human
environment. The actions directed 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.47
Accordingly, neither an environmental
impact statement nor environmental
assessment is required.
V. Regulatory Flexibility Act
79. The Regulatory Flexibility Act of
1980 (RFA) 48 generally requires a
description and analysis of final rules
that will have significant economic
impact on a substantial number of small
entities. The requirements of this rule
would apply primarily to reliability
coordinators, which do not fall within
the definition of small entities.49
Moreover, the proposed Reliability
Standards reflect a continuation of
existing requirements for reliability
coordinators and other entities to
monitor, analyze, prevent, and mitigate
the occurrence of operating limit
violations on the Bulk-Power System.
The one exception is the proposed new
requirements in Reliability Standard
IRO–010–1a for interchange authorities,
which also do not fall within the
definition of small entities. Based on the
foregoing, the Commission certifies that
this proposed rule will not have a
significant impact on a substantial
number of small entities. Accordingly,
no regulatory flexibility analysis is
required.
VI. Document Availability
46 Regulations Implementing the National
Environmental Policy Act, Order No. 486, 52 FR
47897 (Dec. 17, 1987), FERC Stats. & Regs.,
Regulations Preambles 1986–1990 ¶ 30,783 (1987).
47 18 CFR 380.4(a)(5) (2010).
48 5 U.S.C. 601–612.
49 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.
Frm 00020
Fmt 4700
Sfmt 4700
VII. Effective Date and Congressional
Notification
83. These regulations are effective
May 23, 2011. 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.
List of Subjects in 18 CFR Part 40
Electric power, Electric utilities,
Reporting and recordkeeping
requirements.
By the Commission.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. 2011–6778 Filed 3–22–11; 8:45 am]
BILLING CODE 6717–01–P
80. 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 (https://www.ferc.gov)
and in FERC’s Public Reference Room
during normal business hours (8:30 a.m.
PO 00000
to 5 p.m. Eastern time) at 888 First
Street, NE., Room 2A, Washington DC
20426.
81. 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.
82. User assistance is available for
eLibrary and the FERC’s Web site during
normal business hours from FERC
Online Support at 202–502–6652 (toll
free at 1–866–208–3676) or e-mail at
ferconlinesupport@ferc.gov, or the
Public Reference Room at (202) 502–
8371, TTY (202) 502–8659. E-mail the
Public Reference Room at
public.referenceroom@ferc.gov.
DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
18 CFR Part 40
[Docket No. RM10–10–000; Order No. 747]
Planning Resource Adequacy
Assessment Reliability Standard
Federal Energy Regulatory
Commission, DOE.
ACTION: Final rule.
AGENCY:
Under section 215(d)(2) of the
Federal Power Act, the Federal Energy
Regulatory Commission approves
regional Reliability Standard, BAL–502–
RFC–02 (Planning Resource Adequacy
Analysis, Assessment and
SUMMARY:
E:\FR\FM\23MRR1.SGM
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]]>Agencies
[Federal Register Volume 76, Number 56 (Wednesday, March 23, 2011)]
[Rules and Regulations]
[Pages 16240-16250]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2011-6778]
=======================================================================
-----------------------------------------------------------------------
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 40
[Docket No. RM10-15-000; Order No. 748]
Mandatory Reliability Standards for Interconnection Reliability
Operating Limits
AGENCY: Federal Energy Regulatory Commission, DOE.
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: Under section 215 of the Federal Power Act, the Federal Energy
Regulatory Commission (Commission) approves three new Interconnection
Reliability Operations and Coordination Reliability Standards and seven
revised Reliability Standards related to Emergency Preparedness and
Operations, Interconnection Reliability Operations and Coordination,
and Transmission Operations. These Reliability Standards were submitted
to the Commission for approval by the North American Electric
Reliability Corporation (NERC), which the Commission has certified as
the Electric Reliability Organization responsible for developing and
enforcing mandatory Reliability Standards. The Reliability Standards
were designed to prevent instability, uncontrolled separation, or
cascading outages that adversely impact the reliability of the
interconnection by ensuring that the reliability coordinator has the
data necessary to assess its reliability coordinator area during the
operations horizon and that it takes prompt action to prevent or
mitigate instances of exceeding Interconnection Reliability.
Operating Limits. The Commission also approves the addition of two
new terms to the NERC Glossary of Terms.
In addition, the Commission approves NERC's proposed revisions to
Reliability Standards EOP-001-1, IRO-002-2, IRO-004-2, IRO-005-3, TOP-
003-1, TOP-005-2, and TOP-006-2, which remove requirements for the
reliability coordinator to monitor and analyze system operating limits
other than interconnection reliability operating limits.
DATES: Effective Date: This Rule will become effective May 23, 2011.
FOR FURTHER INFORMATION CONTACT: Darrell Piatt (Technical Information),
Office of Electric Reliability, Division of Reliability Standards,
Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426. Telephone: (202) 502-6687.
A. Cory Lankford (Legal Information), Office of the General
Counsel, Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426. Telephone: (202) 502-6711.
William Edwards (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426. Telephone: (202) 502-6669.
SUPPLEMENTARY INFORMATION:
Table of Contents
Paragraph
Nos.
I. Background............................................... 3
A. Mandatory Reliability Standards...................... 3
B. Order No. 693 Directives............................. 4
C. NERC Petition........................................ 7
1. IRO-008-1........................................ 11
2. IRO-009-1........................................ 15
3. IRO-010-1a....................................... 16
D. Notice of Proposed Rulemaking........................ 18
II. Discussion.............................................. 21
A. Division of Responsibilities for SOLs and IROLs...... 22
[[Page 16241]]
1. Continued Analysis of SOLs by Reliability 26
Coordinators.......................................
2. Documented Methodology to Identify System 33
Operating Limit Information........................
3. Current Practices for the Prevention and 34
Mitigation of SOLs and IROLs and the Monitoring
Capability of the Reliability Coordinator..........
4. Reliability Coordinator's Procedures for 37
Selecting the SOLs for Evaluation by the
Interchange Distribution Calculator................
5. Current Functional Model......................... 38
B. Operational Analyses and Real-time Assessments....... 45
C. Reliability Coordinator Actions to Operate Within 52
IROLs..................................................
D. IRO-010-1a........................................... 56
E. Violation Severity Levels and Violation Risk Factors. 64
III. Information Collection Statement....................... 73
IV. Environmental Analysis.................................. 78
V. Regulatory Flexibility Act............................... 79
VI. Document Availability................................... 80
VII. Effective Date and Congressional Notification.......... 83
Before Commissioners: Jon Wellinghoff, Chairman; Marc Spitzer,
Philip D. Moeller, John R. Norris, and Cheryl A. LaFleur.
Final Rule
Issued March 17, 2011.
1. Under section 215 of the Federal Power Act (FPA),\1\ the Federal
Energy Regulatory Commission (Commission) approves three new
Interconnection Reliability Operations and Coordination (IRO)
Reliability Standards and seven revised Reliability Standards related
to Emergency Preparedness and Operations (EOP), IRO, and Transmission
Operations (TOP). The proposed Reliability Standards were submitted to
the Commission for approval by the North American Electric Reliability
Corporation (NERC), which the Commission has certified as the Electric
Reliability Organization (ERO) responsible for developing and enforcing
mandatory Reliability Standards.\2\ These Reliability Standards were
designed to prevent instability, uncontrolled separation, or cascading
outages that adversely impact the reliability of the interconnection by
ensuring that the reliability coordinator has the data necessary to
assess its reliability coordinator area during the operations horizon
and that it takes prompt action to prevent or mitigate instances of
exceeding Interconnection Reliability Operating Limits (IROL).\3\ The
Commission also approves the addition of two new terms to the NERC
Glossary of Terms (NERC Glossary). In addition, the Commission approves
NERC's proposed revisions to Reliability Standards EOP-001-1, IRO-002-
2, IRO-004-2, IRO-005-3, TOP-003-1, TOP-005-2, and TOP-006-2, which
remove requirements for the reliability coordinator to monitor and
analyze system operating limits (SOL) \4\ other than IROLs.
---------------------------------------------------------------------------
\1\ 16 U.S.C. 824o (2006).
\2\ North American Electric Reliability Corp., 116 FERC ]
61,062, order on reh'g & compliance, 117 FERC ] 61,126 (2006), aff'd
sub nom. Alcoa, Inc. v. FERC, 564 F.3d 1342 (DC Cir. 2009).
\3\ NERC defines IROLs as the value (such as MW, MVar, Amperes,
Frequency or Volts) derived from, or a subset of the SOLs, which if
exceeded, could expose a widespread area of the bulk electric system
to instability, uncontrolled separation, or cascading outages. See
NERC Glossary, available at https://www.nerc.com/docs/standards/rs/Glossary_of_Terms_2010April20.pdf.
\4\ NERC defines SOLs as the value (such as MW, MVar, Amperes,
Frequency or Volts) that satisfies the most limiting of the
prescribed operating criteria for a specific system configuration to
ensure operation within acceptable reliability criteria. Id.
---------------------------------------------------------------------------
2. In addition, the Commission asks the ERO to evaluate certain
issues through ongoing standards development and working group projects
and to develop appropriate revisions as necessary. These issues regard
the scope of the reliability coordinator's responsibility under these
and other IRO Reliability Standards. In particular, the Commission
identifies, based on the comments received, certain issues regarding
the delineation of the responsibility of the reliability coordinator to
analyze, monitor and communicate to other operating entities the class
of SOLs identified as ``grid-impactive'' SOLs by NERC.
I. Background
A. Mandatory Reliability Standards
3. Section 215 of the FPA requires a Commission-certified ERO to
develop mandatory and enforceable Reliability Standards, which are
subject to Commission review and approval. Once approved, the
Reliability Standards are enforced by the ERO, subject to Commission
oversight, or by the Commission independently.
B. Order No. 693 Directives
4. On March 16, 2007, the Commission issued Order No. 693,
approving 83 of the 107 initial Reliability Standards filed by NERC,
including the currently-effective IRO Reliability Standards.\5\ Under
section 215(d)(5) of the FPA, the Commission directed NERC to develop
modifications to the IRO Reliability Standards to address certain
issues identified by the Commission.
---------------------------------------------------------------------------
\5\ Mandatory Reliability Standards for the Bulk-Power System,
Order No. 693, 72 FR 16416 (Apr. 4, 2007), FERC Stats. & Regs. ]
31,242, order on reh'g, Order No. 693-A, 120 FERC ] 61,053 (2007).
---------------------------------------------------------------------------
5. With respect to IRO-001-1, the Commission directed the ERO to
develop modifications to eliminate the regional reliability
organization as an applicable entity.\6\ The Commission also directed
the ERO to modify IRO-002-1 to require a minimum set of capabilities
that must be made available to the reliability coordinator to ensure
that a reliability coordinator has the capabilities it needs to perform
its functions.\7\ With respect to IRO-003-2, the Commission directed
the ERO to develop a modification to create criteria to define the term
``critical facilities'' in a reliability coordinator's area and its
adjacent systems.\8\ The Commission also directed the ERO to modify
IRO-004-1 to require the next-day analysis to identify control actions
that can be implemented and effective within 30 minutes after a
contingency. In addition, the Commission directed the ERO to consider
adding Measures and Levels of Non-Compliance to Reliability Standards
IRO-004-1 and IRO-005-1 that are commensurate with the magnitude,
duration, frequency and causes of the violations and whether these
occur during normal or contingency conditions.\9\
---------------------------------------------------------------------------
\6\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 896.
\7\ Id. P 908.
\8\ Id. P 914.
\9\ Id. P 935. NERC has subsequently replaced Levels of Non-
Compliance with Violation Severity Levels. See Order on Violation
Severity Levels Proposed by the Electric Reliability Organization,
123 FERC ] 61,284 (Violation Severity Level Order), order on reh'g,
125 FERC ] 61,212 (2008).
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[[Page 16242]]
6. The Commission also directed the ERO to conduct a survey on IROL
practices and actual operating experiences by requiring reliability
coordinators to report any violations of IROLs, their causes, the date
and time, the durations and magnitudes in which actual operations
exceed IROLs to the ERO on a monthly basis for one year beginning two
months after the effective date of Order No. 693.\10\ On October 31,
2008, NERC filed the results of its year-long survey with the
Commission.\11\ On February 8, 2009, NERC supplemented those results in
a second filing.\12\
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\10\ Id. P 951.
\11\ NERC, Compliance Filing, Docket No. RM06-16-006 (filed Oct.
31, 2008).
\12\ NERC, Compliance Filing, Docket No. RM06-16-006 (filed Feb.
8, 2009).
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C. NERC Petition
7. On December 31, 2009, NERC submitted a petition to the
Commission (NERC Petition) \13\ seeking approval of proposed
Reliability Standards IRO-008-1, IRO-009-1, and IRO-010-1a. Under these
Reliability Standards, reliability coordinators must analyze and
monitor IROLs within their Wide-Area \14\ to prevent instability,
uncontrolled separation, or cascading outages that adversely impact the
reliability of the interconnection. These Reliability Standards do not
require the reliability coordinator to analyze and monitor SOLs other
than IROLs or to take preventive action to avoid or mitigate SOL
violations within their reliability coordinator area. In developing the
proposed IRO Reliability Standards, NERC determined that it was
necessary to retire or modify certain requirements from several
existing Reliability Standards. Therefore, NERC proposed revisions to
Reliability Standards EOP-001-1,\15\ IRO-002-2, IRO-004-2, IRO-005-3,
TOP-003-1, TOP-005-2, and TOP-006-2, which remove requirements for the
reliability coordinator to monitor and analyze SOLs other than IROLs.
NERC also requests approval of new definitions ``Operational Planning
Analysis'' and ``Real-time Assessment.''
---------------------------------------------------------------------------
\13\ North American Electric Reliability Corp., Dec. 31, 2009
Petition for Approval of Proposed New and Revised Reliability
Standards for Operating Within Interconnection Operating Limits.
\14\ The term ``Wide-Area'' is defined in the NERC Glossary,
approved by the Commission. As defined, Wide-Area includes not only
the reliability coordinators' area, but also critical flow and
status information from adjacent reliability coordinator areas as
determined by detailed system studies to allow the calculation of
IROLs. See NERC Glossary available at https://www.nerc.com/docs/standards/rs/Glossary_of_Terms_2010April20.pdf.
\15\ Concurrent with its Petition in this Docket, NERC filed a
petition in Docket No. RM10-16-000 seeking approval of certain
Emergency Preparedness and Operations Reliability Standards. NERC,
Petition for Approval of Three Emergency Preparedness and Operations
Reliability Standards, Docket No. RM10-16-000 (filed Dec. 31, 2009).
As part of its Petition in RM10-16-000, NERC proposed to retire
Requirement R3.4 of EOP-001-0. Each petition proposes unique changes
to EOP-001-0 reflecting the distinct issues addressed by the
respective Reliability Standards drafting teams. In this Final Rule,
the Commission is addressing Version 2 of EOP-001 contained in
Exhibit B of the NERC Petition which reflects both the IRO and the
EOP proposed changes.
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8. These IRO Reliability Standards together with the proposed
revisions to existing Reliability Standards divide responsibility for
SOLs and IROLs between reliability coordinators and transmission
operators according to the Functional Model.\16\ In its Petition, NERC
explains that having two entities with the same primary responsibility
is not supported by the Functional Model.\17\ However, NERC notes that
these IRO Reliability Standards should not imply that the reliability
coordinator will not look at its future operations with respect to
specific SOLs.\18\ NERC states that the reliability coordinator must
look at its future operations with respect to specific SOLs to ensure
that their transmission operators are taking actions at appropriate
times, but the primary responsibility for SOLs rests with the
transmission operators.
---------------------------------------------------------------------------
\16\ NERC, Reliability Functional Model, version 5, at 30 (Dec.
2009), available at https://www.nerc.com/files/Functional_Model_V5_Final_2009Dec1.pdf (NERC Functional Model).
\17\ In its comments, NERC cites specific tasks outlined in the
Functional Model for the respective duties of the reliability
coordinator and transmission operator with respect to SOLs and
IROLs. NERC Comments at 14.
\18\ NERC Petition at 77.
---------------------------------------------------------------------------
9. NERC explains that, under the new IRO Reliability Standards, the
reliability coordinator retains overall visibility of all operations
within its Wide-Area view, including some SOLs, although the
transmission operator is primarily responsible for actions related to
SOLs.\19\ NERC states that the IRO Reliability Standards were developed
in support of the authority and assignment of tasks in the Functional
Model.\20\ NERC explains that under the Functional Model, while
reliability coordinators will assign their transmission operators tasks
associated with IROLs, the reliability coordinator has ultimate
responsibility for these tasks, and the reliability coordinator is
sanctioned if these tasks are not performed as required by the
Reliability Standards.\21\
---------------------------------------------------------------------------
\19\ Id. at 78.
\20\ Id. at 7-9.
\21\ Id. at 8.
---------------------------------------------------------------------------
10. NERC further explains that, in a similar fashion, the
Functional Model assigns responsibility for SOLs that are not IROLs to
the transmission operator. But, NERC states, this too is a shared
responsibility.\22\ NERC states that, where the Transmission Operator
has primary responsibility for developing the SOLs within its
transmission operator area, the transmission operator may request the
assistance of its reliability coordinator in developing these SOLs. In
addition, NERC points out that reliability coordinators are responsible
for ensuring that transmission operators develop SOLs for its
reliability coordinator area in accordance with a methodology developed
by the reliability coordinator.\23\ NERC states that the transmission
operator must share its SOLs with its reliability coordinator, and the
reliability coordinator must share any SOLs it develops with its
transmission operator. NERC also states that the reliability
coordinator monitors the status of some, but not all, SOLs.
---------------------------------------------------------------------------
\22\ Id. at 9.
\23\ NERC Reliability Standard FAC-011-1, Requirement R3.
---------------------------------------------------------------------------
1. IRO-008-1
11. Reliability Standard IRO-008-1 has the stated purpose of
preventing instability, uncontrolled separation, or cascading outages
that adversely impact the reliability of the interconnection by
ensuring that the bulk electric system is assessed during the
operations horizon. The proposed Reliability Standard applies to
reliability coordinators. IRO-008-1 requires the reliability
coordinator to use analyses and assessments as methods of achieving the
stated goal. The Reliability Standard requires analysis of the
reliability coordinator's Wide-Area ahead of time and during real-time.
It also requires communication with the entities that need to take
specific operational actions based on the analyses and assessments.
12. Reliability Standard IRO-008-1 contains three requirements.
Requirement R1 requires each reliability coordinator to perform an
Operational Planning Analysis to assess whether the planned operations
for the next day within its Wide-Area will exceed any of its IROLs
during anticipated normal and contingency event conditions. Requirement
R2 requires the reliability coordinator to perform a Real-Time
Assessment at least once every 30 minutes to determine if its Wide Area
is exceeding any IROLs or is expected to exceed any IROLs. Requirement
R3 requires a reliability coordinator to share the results of an
Operational
[[Page 16243]]
Planning Analysis or Real-Time Assessment that indicates the need for
specific operational actions to prevent or mitigate an instance of
exceeding an IROL with those entities that are expected to take those
actions.
13. NERC also requests approval of two new terms that appear in
IRO-008-1: ``Operational Planning Analysis'' and ``Real-time
Assessment.'' Operational Planning Analysis is defined as:
An analysis of the expected system conditions for the next day's
operation. (That analysis may be performed either a day ahead or as
much as 12 months ahead.) Expected system conditions include things
such as load forecast(s), generation output levels, and known system
constraints (transmission facility outages, generator outages,
equipment limitations, etc.).
NERC states that the definition was designed to provide greater
specificity regarding the day-ahead study.
14. The proposed term ``Real-time Assessment'' is defined as ``[a]n
examination of existing and expected system conditions, conducted by
collecting and reviewing immediately available data.'' NERC states that
the purpose of the new term is to assure that the reliability
coordinator is required to conduct a real-time assessment, including
situations in which the reliability coordinator is operating without
its primary analysis facilities and has implemented the work-around
requirements of IRO-002-2, Requirement R8.
2. IRO-009-1
15. As proposed, Reliability Standard, IRO-009-1 is designed to
prevent instability, uncontrolled separation, or cascading outages that
adversely impact the reliability of the interconnection by ``ensuring
prompt action to prevent or mitigate instances of exceeding [IROLs].''
Proposed Reliability Standard IRO-009-1 applies only to reliability
coordinators.
3. IRO-010-1a
16. NERC proposes the addition of a new Reliability Standard, IRO-
010-1a \24\ to the current suite of IRO Reliability Standards. IRO-010-
1a is designed to prevent instability, uncontrolled separation, or
cascading outages that adversely impact the reliability of the
interconnection by mandating that the reliability coordinator have the
data it needs to monitor and assess the operation of its reliability
coordinator area.
---------------------------------------------------------------------------
\24\ Because the interpretation for IRO-010-1 was completed
before the filing of IRO-010-1, NERC requests Commission approval of
IRO-010-1a, which includes the standard as interpreted.
---------------------------------------------------------------------------
17. The requirements in the Reliability Standard specify a formal
request process for the reliability coordinator to explicitly identify
the data and information it needs for reliability; and require the
entities with the data to provide it as requested. The Reliability
Standard applies to the reliability coordinator and to the other
functional entities that must supply data to the reliability
coordinator.\25\ This includes entities that have been identified as
owners, users, or operators of the Bulk-Power System.
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\25\ The requirements in the standard are specifically
applicable to the following functional entities: (1) Reliability
coordinator[s]; (2) balancing authority; (3) generator owner; (4)
generator operator; (5) interchange authority; (6) load-serving
entity; (7) transmission operator; and (8) transmission owner.
---------------------------------------------------------------------------
D. Notice of Proposed Rulemaking
18. On November 18, 2010, the Commission issued a Notice of
Proposed Rulemaking (NOPR) proposing to approve Reliability Standards
IRO-008-1, IRO-009-1, and IRO-010-1a; revised Reliability Standards
EOP-001-1, IRO-002-2, IRO-004-2, IRO-005-3, TOP-003-1, TOP-005-2, and
TOP-006-2; and the two new NERC Glossary terms.
19. In the NOPR, the Commission agreed with NERC that it is
appropriate to develop requirements for Reliability Standards that
offer a clear division of responsibilities among reliability
coordinators and transmission operators. In addition, the Commission
sought ERO and public comment to ensure that the proposed Reliability
Standards will not create a reliability gap by the inappropriate
division of responsibilities for analyzing, monitoring and resolving
SOLs and IROLs between transmission operators and reliability
coordinators respectively.
20. In response to the NOPR, NERC and a number of parties filed
comments. PJM Interconnection L.L.C., ISO New England, New York
Independent System Operator, Inc., California Independent System
Operation Corporation and Southwest Power Pool submitted joint comments
(Joint Commenters). The Edison Electric Institute (EEI), Midwest
Independent Transmission System Operator, Inc. (Midwest ISO), and
Western Electricity Coordinating Council (WECC) also submitted timely
comments. American Electric Power Service Corp. (AEP) filed comments
one day out-of-time.
II. Discussion
21. The Commission hereby adopts its NOPR proposals and approves
new Reliability Standards IRO-008-1, IRO-009-1, and IRO-010-1a; revised
Reliability Standards EOP-001-1, IRO-002-2, IRO-004-2, IRO-005-3, TOP-
003-1, TOP-005-2, and TOP-006-2; and the two new NERC Glossary terms:
``Operational Planning Analysis'' and ``Real-time Assessment.'' In
approving these Reliability Standards, the Commission concludes that
they are just, reasonable, not unduly discriminatory or preferential,
and in the public interest. These Reliability Standards serve an
important reliability purpose in seeking to prevent instability,
uncontrolled separation, or cascading outages that adversely impact the
reliability of the interconnection by ensuring that the reliability
coordinator has the data necessary to assess its reliability
coordinator area during the operations horizon and that it takes prompt
action to prevent or mitigate instances of exceeding IROLs. Moreover,
they clearly identify the entities to which they apply and contain
clear and enforceable requirements. Commenters addressed many of the
Commission concerns discussed in the NOPR and in some areas the ERO has
indicated that it is continuing to study some issues related to the
Commission concerns. The Commission encourages the ERO, applying its
technical expertise, to continue such reviews and make any necessary
changes to applicable Reliability Standards.
A. Division of Responsibilities for SOLs and IROLs
22. In the NOPR, the Commission sought comment on a number of
issues related to NERC's division of responsibilities for SOLs and
IROLs between reliability coordinators and transmission operators. NERC
acknowledges in its Petition that the transmission operator must
develop and share its SOLs with its reliability coordinator, and the
reliability coordinator must share any SOLs it develops with its
transmission operator.\26\ NERC also states that it is currently
working on a project to identify a subset of SOLs, other than IROLs,
that the transmission operator and reliability coordinator must
continuously analyze and monitor.\27\ Therefore, in the NOPR, the
Commission sought comment on whether there is a need for reliability
coordinators to continue to analyze, in addition to continuing to
monitor and coordinate data on, SOLs other than
[[Page 16244]]
IROLs.\28\ The Commission also sought comment on whether the
reliability coordinator should have a documented methodology for
identifying the SOL information it needs to fulfill its
responsibilities for day-ahead analysis, monitoring and real-time
assessments, and operational control within the reliability
coordinator's area.
---------------------------------------------------------------------------
\26\ NERC Petition at 77.
\27\ NERC identifies this as ``Project 2007-03: Real-time
Operations,'' available at https://www.nerc.com/filez/standards/Real-time_Operations_Project_2007-03.html.
\28\ Under NERC FAC-011-2, reliability coordinators must have a
documented methodology for use in developing SOLs within its
reliability coordinator area.
---------------------------------------------------------------------------
23. The Commission requested information from NERC, reliability
coordinators, and other interested entities on the current practices of
reliability coordinators and transmission operators with respect to
coordinating operational responsibilities for monitoring, day ahead and
real-time assessments. The Commission also asked for comments on Bulk-
Power System operations related to SOLs and IROLs, on the practical
division of responsibilities for preventing and mitigating SOL and IROL
violations, and the monitoring capabilities of the reliability
coordinator with respect to IROLs as well as other SOLs. Additionally,
the Commission asked whether a reliability coordinator can provide an
accurate assessment of the Bulk-Power System to its transmission
operators on a Wide-Area basis, without evaluating: (1) The operating
environment of SOLs that will impact the transmission operators within
the reliability coordinator's areas; (2) SOLs that have the potential
to become IROLs; and, (3) the existing IROLs within the reliability
coordinator area. The Commission further sought comment as to whether a
transmission operator can provide reliable operating assessments or
make reliable operating instructions on an SOL that is on the border
between two different transmission operator's areas. The Commission
also requested comment on whether the reliability coordinator should
have responsibility to monitor certain SOLs other than IROLs, and
whether such a responsibility would place an unreasonable burden on
reliability coordinators.
24. The Commission noted that IRO-006-4.1 requires the reliability
coordinator to model SOLs and IROLs in the Interchange Distribution
Calculator (IDC) to perform the Transmission Loading Relief procedures.
We sought comment on how reliability coordinators in the Eastern
Interconnection select the SOLs for evaluation in the IDC and the
extent of any burden this has caused the reliability coordinator.
25. Finally, the Commission also sought comments from NERC and the
public as to how the current Functional Model represents the
delineation of assessment and operating responsibilities between the
reliability coordinator and transmission operator with respect to SOLs
and IROLs.
Comments
1. Continued Analysis of SOLs by Reliability Coordinators
26. NERC states in its comments, that the proposed IRO Reliability
Standards appropriately distinguish which entity has primary
responsibility for SOLs. Further, Bulk-Power System reliability
practices assign responsibilities for analyzing and resolving
conditions to the entities closest to it, so that the entity with the
closest eye to the condition can quickly assess and resolve it. NERC
asserts that it is appropriate for transmission operators to maintain
primary responsibility for SOLs, and for reliability coordinators to
maintain primary responsibility for IROLs. NERC also explains that,
while SOLs are typically associated with the prevention of facility
damage or the accelerated degradation of equipment life, only a subset
of SOLs are used to analyze and monitor local area reliability and,
therefore, the proposed IRO standards are silent on the reliability
coordinator's responsibility with respect to SOLs.
27. NERC notes in its Petition, that the proposed Reliability
Standards ``should not imply that the Reliability Coordinator will not
look at its future operations with respect to specific SOLs.'' \29\
NERC also states that ``[t]he Reliability Coordinator retains the
overall visibility of all operations within its Wide-Area view,
including some SOLs, although the transmission operator is primarily
responsible for actions related to SOLs.'' \30\ NERC also notes that
the reliability coordinator can monitor the transmission operator's
actions to resolve SOLs and provides, as an example, that the
reliability coordinator can study real-time operating trends to help
determine whether an asset is trending toward a ``grid-impactive SOL.''
\31\
---------------------------------------------------------------------------
\29\ NERC Petition at 9.
\30\ NERC Petition at 10.
\31\ NERC Comments at 7. NERC does not offer a definition of the
term ``grid-impactive SOL,'' but we understand it to mean an SOL
that the reliability coordinator monitor so that it does not develop
into an IROL.
---------------------------------------------------------------------------
28. In its comments, NERC provides the results of a survey
conducted in response to the NOPR in which each of the nine reliability
coordinators in the Eastern Interconnection responded that, for SOLs
that it monitors, the SOLs were developed in a coordinated fashion with
the transmission operators in its area. The survey responses did not
suggest that any transmission operator withheld important SOL
information from reliability coordinators, nor did any reliability
coordinator indicate that transmission operators were not willing to
work with the reliability coordinators in monitoring SOLs for Bulk-
Power System reliability. NERC contends that this survey demonstrates
that current operating practices are effective to ensure that
reliability coordinators are able to obtain sufficient information from
transmission operators in order to analyze and monitor certain SOLs
other than IROLs.
29. NERC also notes that, since the completion of the proposed IRO
standards, the industry has been working to improve the clarity of
Reliability Standard requirements regarding the transmission operator's
primary responsibility for SOLs through the Real-time Operations
Standard Drafting Team (Project 2007-03). For example, NERC explains
that the Standard Drafting Team has proposed to add a requirement to
TOP-001-2 that would require each transmission operator to inform its
reliability coordinator of all SOLs which, while not IROLs, have been
identified by the transmission operator as supporting its local area
reliability based on its assessment of its Operational Planning
Analysis. NERC states that, by using tools that properly model Wide-
Area conditions, the reliability coordinators are able to identify and
help resolve lower-level issues that may not explicitly be included in
the reliability coordinator modeling capabilities. EEI supports NERC's
comments to the NOPR and believes that the Commission should encourage
the NERC reliability coordinators working group to engage these issues
with NERC stakeholders, especially the NERC Planning and Operating
Committees.
30. The Joint Commenters support the proposed primary division of
responsibilities for SOLs and IROLs between reliability coordinators
and transmission operators. They contend, though, that the proposed
division should not be interpreted as implying that a reliability
coordinator should not monitor any SOLs. The Joint Commenters further
contend that it was not intended that the proposed Reliability
Standards would remove all responsibility for SOLs from the reliability
coordinator, but to establish a clear distinction of responsibilities
and authority. The Joint Commenters state that they would not support a
formal
[[Page 16245]]
requirement that would assign primary responsibility for analyzing and
resolving SOLs to a reliability coordinator since the primary
responsibility is correctly assigned to the transmission operator that
is most familiar with their respective operating limits and local Bulk-
Power System characteristics.
31. Midwest ISO states that it is necessary for reliability
coordinators to analyze, monitor, and coordinate some SOLs other than
IROLs and that the Reliability Standards should reflect this best
practice. Midwest ISO believes the Commission should encourage the
efforts currently underway at NERC towards the development of
Reliability Standards addressing the role of reliability coordinators
with regard to analyzing SOLs, other than IROLs, that are important to
the reliable operation of the Bulk-Power System.
32. AEP states that it generally supports the proposed Reliability
Standards but that it agrees with concerns raised by the Commission
that if reliability coordinators are not monitoring other SOLs, there
is a potential gap in monitoring for SOLs that have the potential to
become IROLs. AEP argues that performing an annual IROL identification
would be insufficient because it could miss some opportunities to
identify these potentially new IROLs when they could be material. AEP
asserts that, at a minimum, reliability coordinators should be required
to be involved in SOLs that could border two different transmission
operators' areas to ensure the activities are appropriately
coordinated. AEP states that reliability coordinators and transmission
operators should develop this subset of SOLs through joint analysis, or
agreement. AEP requests that the Commission direct NERC to develop a
modification to proposed Reliability Standards EOP-001-1, IRO-002-2,
IRO-004-2, IRO-005-3, TOP-003-1, TOP-005-2, and TOP-006-2, to require
reliability coordinators to work together with transmission operators
in developing and monitoring SOLs that border multiple transmission
operators' areas.
2. Documented Methodology To Identify System Operating Limit
Information
33. NERC asserts that, because proposed Reliability Standard IRO-
008-1 requires reliability coordinators to use tools to model
transmission and generation assets based on ratings provided by asset
owners, it is unnecessary to impose an additional requirement that the
reliability coordinator have a documented methodology for identifying
the SOL information it needs because the systems and controls in place
already provide the information needed by the reliability coordinators.
The Joint Commenters also believe that such a methodology is
unnecessary because, in its defined role, a reliability coordinator
already will have access to, and be provided with, the appropriate set
of SOLs from the transmission operator.
3. Current Practices for the Prevention and Mitigation of SOLs and
IROLs and the Monitoring Capability of the Reliability Coordinator
34. NERC states that current practices give the reliability
coordinators the ability to provide assessments of the Bulk-Power
System to their transmission operators on a Wide-Area basis. NERC
believes it is unnecessary to require reliability coordinators to have
additional responsibility to monitor SOLs other than IROLs. NERC also
notes that there are checks in place that allow the reliability
coordinator to monitor SOLs that could turn into IROLs. As an example,
NERC points out that IRO-010-1a requires reliability coordinators to
conduct Operational Planning Analyses and Real-Time Assessments to
identify any IROLs that may be exceeded.
35. NERC states that the electric power industry is predicated on
interdependencies. NERC describes the interdependency of transmission
operators and reliability coordinators as enabling the reliability
coordinator both to control IROLs and flows, and to be aware of local
issues, giving the reliability coordinator the ability to monitor SOLs
that may become IROLs within the reliability coordinators areas. NERC
further explains that it is working on Project 2007-03--Real-Time
Operations to develop proposed revisions to the TOP standards that
require a transmission operator to perform Operational Planning
Analyses for its transmission operator area. NERC states that Project
2007-03 is considering revisions to the Reliability Standards that
would require observation of SOL limits in adjoining areas.
36. The Joint Commenters state that the proposed IRO Reliability
Standards hold reliability coordinators to the proper assessment of
information required to provide accurate assessments on a Wide-Area
basis. The Joint Commenters also caution that ``accurate assessments''
do not equate to precise results and the Commission should refrain from
mandating that reliability coordinators provide accurate assessments.
4. Reliability Coordinator's Procedures for Selecting the SOLs for
Evaluation by the Interchange Distribution Calculator
37. NERC states that reliability coordinators in the Eastern
Interconnection select which SOLs to evaluate in the interchange
distribution calculator based on information received from the
transmission operators indicating that the transmission operator has a
facility that is approaching or exceeding its SOL and/or IROL. NERC
states that the interchange distribution calculator is a congestion
management tool that helps the reliability coordinators deal with
transmission constraints. In the survey conducted by NERC of
reliability coordinators, one reliability coordinator responded that it
publishes most of its information for use by any entity that may wish
to use the information in its reliability assessments. Another
reliability coordinator responded that it does not enter SOLs in its
area into the interchange distribution calculator, but flowgates are
entered into the interchange distribution calculator that may have SOLs
or IROLs associated with them. Entering the flowgates allows an entity
to determine if external schedules are impacting the flowgate.
5. Current Functional Model
38. NERC argues that Version 5 of the NERC Functional Model makes a
clear distinction between the duties of the reliability coordinator and
transmission operator with respect to SOLs and IROLs in certain task
descriptions.\32\ Similarly, the Joint Commenters state that the latest
NERC Functional Model divides reliability components and allocates them
to ``unique'' baskets of tasks which include a fundamental reliability
task to do Wide-Area analysis and another task for local analysis.
---------------------------------------------------------------------------
\32\ See NERC Functional Model at 31, 37.
---------------------------------------------------------------------------
Commission Determination
39. As we stated in the NOPR, we believe that it is appropriate for
Reliability Standards requirements to offer a clear division of
responsibilities among reliability coordinators and transmission
operators. The preponderance of comments to the NOPR supports
Commission approval of the Reliability Standards as proposed by NERC,
including the proposed division of responsibilities. For the reasons
described below, we approve the division of responsibility for SOLs and
IROLs among transmission operators and reliability coordinators as
expressed in the proposed Reliability Standards.
40. NERC and others suggest that these Reliability Standards are
not
[[Page 16246]]
intended to remove all responsibility for the analysis and monitoring
SOLs from the reliability coordinator. We agree. These Reliability
Standards generally establish a clear distinction of primary
responsibility for SOLs and IROLs between the transmission operator and
reliability coordinator respectively. As NERC notes, however, the
reliability coordinator will continue to have the ability and the
responsibility to analyze and monitor SOLs that could turn into IROLs.
For example, Requirements R5 and R6 of Reliability Standard IRO-002-2
require the reliability coordinator to monitor the important elements
that could be critical to SOLs and IROLs within the reliability
coordinator's area and surrounding reliability coordinator areas. In
addition, the proposed IRO Reliability Standards require the
reliability coordinator to conduct Operational Planning Analyses and
Real-time Assessments of its reliability coordinator area. As NERC
explained, the Operational Planning Analyses look at the expected
system conditions and potential reliability impacts, with a focus on
any impacts that affect the Wide-Area. Although a transmission operator
lacks the tools to predict the impact on the surrounding transmission
operator areas due to any changes in flow between inter-area
facilities, a reliability coordinator addresses these facilities in its
Wide-Area modeling capabilities.
41. As the Commission noted in its NOPR, Reliability Standard IRO-
002-2 continues to require each reliability coordinator to monitor SOLs
other than IROLs both within its reliability coordinator area and in
surrounding reliability coordinator areas. Specifically, under
Requirement R4 of IRO-002-2, each reliability coordinator must have
detailed real-time monitoring capability of its reliability coordinator
area and sufficient monitoring capability of its surrounding
reliability coordinator areas to ensure that potential or actual SOL or
IROL violations are identified and analyzed. In addition, under
Requirement R5, each reliability coordinator must monitor bulk electric
system elements such as generators, transmission lines, buses,
transformers and breakers that could result in SOL or IROL violations
within its reliability coordinator area. Further, as the Commission
noted in the NOPR, the reliability coordinator must resolve potential
or actual violations of SOL ratings by implementing a local or area-
wide transmission loading relief procedure under Reliability Standard
IRO-006-4.1.
42. Nevertheless, as noted by NERC and other commenters, there
exists a subset of ``grid-impactive'' SOLs other than IROLs that the
Commission believes may warrant closer analysis by the reliability
coordinator, in addition to the analysis being conducted by the
transmission operator, that focuses on whether these particular ``grid-
impactive'' SOLs could become IROLs. The Commission believes that there
can be considerable benefit derived from some overlap in the
responsibility for analyzing and monitoring these ``grid-impactive''
SOLs since, by definition, every IROL emanated from an SOL. While the
proposed Reliability Standards continue to commit the reliability
coordinator to the analysis and monitoring of SOLs that may become
IROLs, a subset of SOLs, such as these ``grid-impactive'' SOLs, may
deserve a more defined analysis and monitoring role on the part of the
reliability coordinator.
43. We acknowledge NERC's and industry's continuing efforts to
improve the clarity of standard requirements regarding SOLs through the
Real-time Operations Standard Drafting Team (Project 2007-03). We
believe that the issues concerning the analysis and monitoring of
``grid-impactive'' SOLs that we note here can be raised and considered
in this or other ongoing projects. NERC comments that it is working on
Project 2007-03 to develop revisions to the TOP Reliability Standards
that require transmission operators to perform operational planning
analyses for their local areas. NERC also comments that this project is
also considering revisions that would require that SOL limits in
adjoining areas be observed. In addition, there are other open
projects, such as Project 2006-06--Reliability Coordination, which is
analyzing appropriate reliability coordinator functions and
responsibilities. In consideration of these ongoing efforts, we will
not direct specific modifications to these Reliability Standards and,
rather, accept NERC's commitment to exercise its technical expertise to
study these issues and develop appropriate revisions to applicable
Standards as may be necessary.
44. Because the study and monitoring of SOLs and IROLs is an issue
at the very core of Bulk-Power System reliability, the Commission
agrees with EEI that the NERC Reliability Coordinators Working Group
should engage the issues raised in this proceeding with NERC
stakeholders, including the NERC Planning and Operating committees, to
determine whether a need exists to further refine the delineation of
responsibilities between the reliability coordinator and transmission
operator for analyzing a class of ``grid-impactive'' SOLs. Depending on
the results of that review, we further encourage NERC, working through
its standard development process, to develop appropriate modifications
to these and any other related Reliability Standards as necessary.
B. Operational Analyses and Real-time Assessments
45. In the NOPR, the Commission sought comment on the prudence of
using an Operational Planning Analysis up to twelve months old. The
Commission asked whether this timeframe is reasonable or whether the
timeframe should be shorter to ensure that the analysis is not
outdated. In addition, the Commission sought comment on whether the
definition should include measurable criteria to determine whether it
is appropriate to use an existing analysis.
46. Further, the Commission requested comments on the meaning of
``immediately available data'' within the proposed definition of the
NERC Glossary definition of Real-Time Assessment. The Commission
proposed to direct NERC to modify the definition of ``Real-time
Assessment'' to specify that the type of data to be relied upon by a
reliability coordinator in conducting a Real-time Assessment must be
based on adequate analysis capabilities such as state estimation, pre-
and post-contingency analysis capabilities (thermal, stability, and
voltage), and wide-area overview displays referenced in Requirement R6
of IRO-002-2.
Comments
47. In response to the Commission's questions regarding the use of
an existing Operational Planning Analysis, NERC states that it is
unlikely that a reliability coordinator would deliberately rely on an
Operational Planning Analysis that does not reflect its expected system
conditions. NERC asserts that a reliability coordinator will rely on a
twelve-month old operational planning analysis only if system
conditions have not changed over that time period. NERC states that the
proposed definition of Operational Planning Analysis was developed,
based on stakeholder comments, to apply not only to studies conducted
for the day ahead, but also for future use in possibly developing
requirements for seasonal studies. Thus, NERC explains, the definition
includes the option of performing an Operational Planning Analysis up
to twelve months ahead. NERC further explains that the
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definition includes key elements that provide measurable criteria in
assessing an entity's Operational Planning Analysis.
48. In response to the Commission's questions regarding the
proposed definition of Real-time Assessment, NERC and the Joint
Commenters state that the industry is currently working towards
consensus on the set of data and capabilities the reliability
coordinators need to perform their tasks via the Real-time Reliability
Monitoring and Analysis Capabilities Standards Development Team
(Project 2009-02). Accordingly, NERC asks the Commission to refrain
from directing modifications pending completion of the project.
Commission Determination
49. The Commission approves the definitions of ``Operational
Planning Analysis'' and ``Real-time Assessment'' without modification.
50. The Commission agrees with NERC that the reliability
coordinator should rely on a twelve-month old Operational Planning
Analysis study only if system conditions have not changed from those
originally studied. Consistent with the views of NERC, we expect that
reliability coordinators will rely on Operational Planning Analysis
that reflect expected system conditions. Accordingly, we accept the
definition as proposed.
51. Similarly, we find it is unnecessary to direct NERC to modify
the definition of ``Real-time Assessment'' to specify that the type of
data to be relied upon by a reliability coordinator in conducting a
Real-time Assessment as proposed in the NOPR. Instead, the Commission
will allow industry to complete Project 2009-02, which is working
towards consensus on the set of data and capabilities the reliability
coordinators need to perform their tasks. We expect NERC to use its
technical expertise to develop any modifications to the definition of
Real-time Assessment as may be necessary as a result of this ongoing
project.
C. Reliability Coordinator Actions To Operate Within IROLs
52. In the NOPR, the Commission sought comment on whether
reliability coordinators should have action plans developed and
implemented with respect to other SOLs apart from IROLs and if so,
which SOLs.
Comments
53. NERC states that transmission operators already are responsible
for developing action plans for preventing and/or mitigating conditions
that cause facility ratings to be exceeded. NERC therefore contends
that it would add confusion to the process to require both the
reliability coordinator and transmission operator to develop action
plans for every SOL.
54. Similarly, WECC does not believe that reliability coordinators
should be required to have action plans developed and implemented for
SOLs apart from IROLs. WECC argues that requiring the reliability
coordinator to second guess rather than defer to the more granular view
and detailed view of the transmission operators or balancing
authorities undermines and substantially changes the roles of each
function without any foreseeable benefit to overall reliability.
Commission Determination
55. The Commission agrees with NERC that requiring both the
reliability coordinator and transmission operator to develop action
plans for every SOL may add confusion to the process. As a result, the
Commission approves IRO-009-1, without modification. However, the
Reliability Coordinator Working Group should further study this issue
and determine if there is a need for reliability coordinators to have
action plans developed and implemented with respect to certain grid-
impactive SOLs.
D. IRO-010-1a
56. In the NOPR, the Commission expressed concern that Reliability
Standard IRO-010-1a does not require reliability coordinators to
specify a list of minimum data needed for reliable operation of the
Bulk-Power System. The Commission, therefore, sought comment on whether
a minimum list of data is necessary for the effective sharing of data
between neighboring reliability coordinators and, if so, what data
should be included. The Commission also sought comment on how
compatibility of data between neighboring reliability coordinators can
be assured without a list of minimum data in this proposed Reliability
Standard.
57. In its discussion of Reliability Standard TOP-003-1, the
Commission noted that Requirement R3 of proposed Reliability Standard
IRO-010-1a requires entities to provide data and information to the
reliability coordinator in accordance with the reliability
coordinator's specifications. The Commission expressed concern that
this requirement does not specify outage coordination data and,
therefore, the reliability coordinator may not receive adequate outage
coordination data to support the Operational Planning Analysis.
Accordingly, the Commission sought comment on whether IRO-010-1a should
specify necessary outage coordination data.
Comments
58. NERC, the Joint Commenters and Midwest ISO contend that
requiring a minimum list of data is not necessary for the effective
sharing of data between neighboring reliability coordinators. NERC
argues that requiring a list of minimum data not only could impair an
entity's ability to provide the data to the reliability coordinator
quickly, but could prevent a reliability coordinator from obtaining
needed data quickly. NERC also notes that, during the development of
the proposed Reliability Standard, the reliability coordinators that
were polled indicated they already were receiving the data they needed
without any issues and that the data and information they received
varied from one reliability coordinator to another. The Joint
Commenters argue that it is unnecessary to develop such a requirement
because two interconnected parties can agree upon the appropriate type
and level of data it needs from the other, taking into consideration
their respective tools and capabilities. Midwest ISO argues that many
reliability coordinators already have developed coordination agreements
with their neighbors that identify the information necessary for
effective data sharing. Midwest ISO contends that a generic list of
minimum data could be inadequate to meet regional needs and could
create conflicts with existing coordination agreements. Midwest ISO
further contends that a minimum list could curb creativity and
innovation as capabilities develop new uses for data.
59. NERC and the Joint Commenters also urge the Commission to
refrain from requiring NERC to modify IRO-010-1a to specify the
necessary outage coordination data for all reliability coordinators.
They contend that such an approach would not account for the
significantly varying facilities located within the reliability
coordinators' area and allow for the flexibility to specify the data
needed for its respective area.
60. Reiterating comments it raised during the standard development
process, WECC opposes the requirement in R1.2 that the parties reach
mutual agreement with respect to the format of the data and information
that the reliability coordinator receives. WECC argues that, due to the
large number of entities that must provide data to the reliability
coordinator, the requirement for mutually agreeable formats may cause
the reliability coordinator to receive data in a multitude of diverse
formats. WECC also believes that
[[Page 16248]]
requiring mutually agreeable data formats could delay the submission of
data by a submitting entity until agreement can be reached via
negotiation or dispute resolution. WECC argues that more than one party
is involved in the formulation of an agreeable format yet only a
reliability coordinator will be found non-compliant when the
reliability coordinator and transmission operators or balancing
authorities within the reliability coordinator area fail to reach an
agreement over an acceptable format.
Commission Determination
61. The Commission agrees with commenters that it is unnecessary to
direct NERC to develop a specific list of minimum data for the
effective sharing of data between neighboring reliability coordinators
under Reliability Standard IRO-010-1a. NERC and other entities confirm
that reliability coordinators currently obtain necessary data without
such a specific list. In addition, as commenters point out, a minimum
list may conflict with coordination agreements currently in place which
identify the information necessary for effective data sharing. With
regard to the concern expressed in the NOPR regarding outage
coordination data, we accept that reliability coordinators currently
obtain necessary data. If, in the future, reliability coordinators are
not able to obtain the necessary outage coordination data, we would ask
NERC to consider whether a Reliability Standard should be developed for
the reliability coordinators to obtain such data.
62. In response to WECC's concerns about the submission of data in
mutually agreeable formats under Requirement R1.2, we do not believe
any modification is necessary. As NERC states in its Petition, by
specifying that the format must be mutually agreeable, the standard
supports efficiency by precluding the submission of data that is in a
format that cannot be used. We agree. NERC states that current data
exchange formats are acceptable. Therefore, entities can continue to
utilize existing agreements regarding data exchange. While disputes may
arise in the future, the Reliability Standard does not dictate a
specific dispute resolution process in the interpretation leaving
reliability coordinators and other entities options for informal
resolution of a dispute on the format of data and flexibility in
choosing a dispute resolution process to reach an agreement.
63. Accordingly, the Commission approves IRO-010-1a as submitted.
E. Violation Severity Levels and Violation Risk Factors
64. In the event of a violation of a Reliability Standard, NERC
establishes the initial value range for the corresponding base penalty
amount. To do so, NERC assigns a violation risk factor for each
requirement of a Reliability Standard that relates to the expected or
potential impact of a violation of the requirement on the reliability
of the Bulk-Power System. In addition, NERC defines up to four
violation severity levels--Lower, Moderate, High, and Severe--as
measurements for the degree to which the requirement was violated in a
specific circumstance.
65. In Order No. 705, the Commission approved 63 of NERC's 72
proposed violation risk factors for the version one FAC Reliability
Standards and directed NERC to file violation severity level
assignments before the version one FAC Reliability Standards become
effective.\33\ Subsequently, NERC developed violation severity levels
for each requirement of the Commission-approved FAC Reliability
Standards, as measurements for the degree to which the requirement was
violated in a specific circumstance.
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\33\ Facilities Design, Connections and Maintenance Reliability
Standards, Order No. 705, 121 FERC ] 61,296, at P 137 (2007).
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66. On June 19, 2008, the Commission issued its Violation Severity
Level Order approving the violation severity level assignments filed by
NERC for the 83 Reliability Standards approved in Order No. 693.\34\ In
that order, the Commission offered four guidelines for evaluating the
validity of violation severity levels, and ordered a number of reports
and further compliance filing to bring the remainder of NERC's
violation severity levels into conformance with the Commission's
guidelines. The four guidelines are: (1) Violation severity level
assignments should not have the unintended consequence of lowering the
current level of compliance; (2) violation severity level assignments
should ensure uniformity and consistency among all approved Reliability
Standards in the determination of penalties; \35\ (3) violation
severity level assignments should be consistent with the corresponding
requirement; and (4) violation severity level assignments should be
based on a single violation, not a cumulative number of violations.\36\
The Commission found that these guidelines will provide a consistent
and objective means for assessing, inter alia, the consistency,
fairness and potential consequences of violation severity level
assignments. The Commission noted that these guidelines were not
intended to replace NERC's own guidance classifications, but rather, to
provide an additional level of analysis to determine the validity of
violation severity level assignments.
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\34\ Violation Severity Level Order, 123 FERC ] 61,284.
\35\ Guideline 2 contains two sub-parts: (a) the single
violation severity level assignment category for binary requirements
should be consistent and (b) violation severity levels assignments
should not contain ambiguous language.
\36\ Violation Severity Level Order, 123 FERC ] 61,284 at P 17.
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67. On August 10, 2009, NERC submitted an informational filing
setting forth a summary of revised guidelines that NERC intends to use
in determining the assignment of violation risk factors and violation
severity levels for Reliability Standards. NERC states that these
revised guidelines were consistent with Commission's guidelines. On May
5, 2010, NERC submitted the subject informational filing as a
supplement to its pending March 5, 2010 Violation Severity Level Order
compliance filing.\37\
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\37\ North American Reliability Corporation, Filing of the North
American Electric Reliability Corporation regarding the Assignment
of Violation Risk Factors and Violation Severity Levels, Docket No.
RR08-4-005 (filed May 5, 2010).
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