SUpplemental Petition Retire Rel Standard TOP-007-WECC-1a

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
North American Electric Reliability
Corporation

)
)

Docket No. RM16-10-000

SUPPLEMENTAL INFORMATION FOR PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION AND WESTERN
ELECTRICITY COORDINATING COUNCIL FOR APPROVAL OF RETIREMENT OF
REGIONAL RELIABILITY STANDARD TOP-007-WECC-1a
The North American Electric Reliability Corporation (“NERC”) and the Western
Electricity Coordinating Council (“WECC”) hereby submit supplemental information
(“Supplement”) to their March 23, 2016 petition (“Petition”) filed in the above-captioned docket
requesting approval of the retirement of WECC regional Reliability Standard TOP-007-WECC1a – System Operating Limits. 1 This Supplement provides additional background information on
TOP-007-WECC-1a, the purpose of the proposed retirement, and the manner in which the
reliability of the 40 Transmission paths currently subject to TOP-007-WECC-1a is addressed
under the continent-wide Transmission Operations (“TOP”) and Interconnection Reliability
Operations and Coordination (“IRO”) Reliability Standards. 2
As discussed below, regional Reliability Standard TOP-007-WECC-1a reflects a historical,
path-centric operating paradigm unique to the Western Interconnection. This paradigm is focused
on identifying a single, pre-determined transfer capability value for an entire Transmission path,

1

Unless otherwise designated herein, all capitalized terms shall have the meaning set forth in the Glossary of
Terms Used in NERC Reliability Standards (“NERC Glossary”), available at
http://www.nerc.com/files/Glossary_of_Terms.pdf.

2
As provided in Section 4 of the standard, regional Reliability Standard TOP-007-WECC-1a applies only to
the 40 Transmission paths listed in the table titled “Major WECC Transfer Paths in the Bulk Electric System,”
provided at https://www.wecc.biz/Reliability/TableMajorPaths4-28-08.pdf.

1

which, if operated within, was intended to provide for reliable operation by preventing a predetermined limiting Contingency from resulting in an exceedance of a specific thermal Facility
Rating, system voltage limit, or stability limit. With the development of advanced applications for
Real-time analysis, however, the paradigm upon which TOP-007-WECC-1a is based no longer
aligns with current operating practices nor does it provide an optimal framework for reliably
operating the Bulk-Power System (“BPS”).
The purpose of the proposed retirement of TOP-007-WECC-1a is to shift away from the
path-centric paradigm and allow entities in the Western Interconnection to align their operating
practices with the framework established in the continent-wide TOP/IRO Reliability Standards
approved in Order No. 817. 3 As the Federal Energy Regulatory Commission (“FERC” or
“Commission”) recognized, that framework provides for a comprehensive and reliable approach
to, among other things, achieving the objective of operating within acceptable pre- and postContingency reliability criteria (i.e., within System Operating Limits (“SOLs”) and
Interconnection Reliability Operating Limits (“IROL”). 4 The retirement of TOP-007-WECC-1a
would have no adverse effect on reliability. As discussed below, there is no reliability need to
continue the historical, path-centric approach reflected in TOP-007-WECC-1a or to treat the
facilities comprising the 40 Transmission paths subject to TOP-007-WECC-1a any differently than
all other facilities are treated under the continent-wide TOP/IRO Reliability Standards. Each of
the facilities comprising these 40 Transmission paths would be monitored in accordance with the
Commission-approved TOP/IRO Reliability Standards and subject to associated mitigation

3

Transmission Operations Reliability Standards and Interconnection Reliability Operations and
Coordination Reliability Standards, Order No. 817, 153 FERC ¶ 61,178, 80 Fed. Reg. 73977 (2015).

4

Id. at PP 14-17.

2

requirements should there be an expected or actual exceedance of an SOL or IROL on those
facilities.
Following additional discussion of the history of TOP-007-WECC-1a (Section I.a), the
operational paradigm underlying the regional standard (Section I.b), and the purpose of retiring
the regional standard (Section II), this Supplement discusses the following:
•

The manner in which Peak Reliability (“Peak”), as the Reliability Coordinator for the
Western Interconnection (except in Alberta, Canada), and Transmission Operators and
Balancing Authorities would continue to monitor and assess conditions on the 40
Transmission paths under the continent-wide TOP/IRO Reliability Standards. (Section
III.a).

•

Whether the 30-minute mitigation requirement in TOP-007-WECC-1a would continue to
apply to the 40 Transmission paths following retirement of the standard and, if not, the
basis for no longer applying such a requirement to each path. (Section III.b).

•

The process for establishing SOLs and IROLs for each of the facilities comprising the 40
Transmission paths and the type of limitations associated with those paths. (Section III.c).

•

Peak’s intent to modify its methodology for establishing SOLs and IROLs and the manner
in which such revisions could impact the evaluation of the 40 Transmission paths under
the TOP/IRO Reliability Standards. (Section III.d).

•

Peak’s use of a 1000 MW threshold in its current methodology for determining IROLs and
the manner in which that threshold applies to the 40 Transmission paths subject to TOP007-WECC-1a. (Section III.e).

I.

Background
a. History of Regional Reliability Standard TOP-007-WECC-1a
Regional Reliability Standard TOP-007-WECC-1a and the operating paradigm upon which

it is based derive from the reliability criteria in WECC’s Reliability Management System
(“RMS”), which predates the enactment of the Energy Policy Act of 2005 (“EPAct 2005”) 5 and
NERC’s mandatory Reliability Standards under Section 215 of the Federal Power Act (“FPA”). 6

5

Energy Policy Act of 2005, Pub. L. No. 109-58, Title XII, Subtitle A, 119 Stat. 594, 941 (2005).

6

16 U.S.C. § 824o (2012).

3

The RMS, which is no longer in effect, was developed in the late 1990s in response to a series of
black-outs in the Western Interconnection and established the reliability criteria to which
Transmission Operators in the Western Interconnection agreed to be bound. 7 Among other things,
the RMS reliability criteria set forth an operating paradigm focused on identifying a single, predetermined maximum flow value for major WECC Transmission paths and requiring Transmission
Operators to operate within that value to achieve reliable operations.
More specifically, the RMS criteria provided that actual power flows for certain major
Transmission paths in the Western Interconnection shall at no time exceed the Operating Transfer
Capability Limits (“OTC”) for those paths for more than 20 minutes for stability limited paths or
for more than 30 minutes for thermally limited paths. 8 As provided in the RMS, OTC is
determined on a seasonal basis and represents “the maximum amount of actual power that can be
transferred over direct or parallel transmission elements comprising: (1) an interconnection from
one Control Area to another Control Area; 9 or (2) a transfer path within a Control Area. 10 The
OTC thus reflected a pre-determined transfer capability value for an entire path (a “Path OTC”)
which, if operated within, was intended to prevent a pre-determined limiting Contingency from
7

The RMS was initially established by Western Systems Coordinating Council (“WSCC”), which is one of
the three predecessor entities to WECC. WECC was formed on April 18, 2002, by the merger of the WSCC,
Southwest Regional Transmission Association, and Western Regional Transmission Association. The Commission
approved the initial RMS criteria in 1999. Western Systems Coordinating Council, 87 FERC ¶ 61,060 (1999).

8

Under the RMS, OTC is defined as “the maximum value of the most critical system operating parameter(s)
which meets: (a) precontingency criteria as determined by equipment loading capability and acceptable voltage
conditions, (b) transient criteria as determined by equipment loading capability and acceptable voltage conditions,
(c) transient performance criteria, and (d) post contingency loading and voltage criteria.”

9

The RMS defined “Control Area” as “an electric system or systems, bounded by interconnection metering
and telemetry, capable of controlling generation to maintain its interchange schedule with other Control Areas and
contributing to frequency regulation of the Western Interconnection. As used herein, the term ‘Control Area’ shall
have the same meaning as the term ‘Balancing Authority Area’ or ‘Balancing Authority,’ as applicable, as such
terms are used in the NERC Standards.”

10

In this respect, OTC is closely associated with the NERC Glossary term “Total Transfer Capability,” which
is defined as “[t]he amount of electric power that can be moved or transferred reliably from one area to another area
of the interconnected transmission systems by way of all transmission lines (or paths) between those areas under
specified system conditions.”

4

resulting in an exceedance of a specified thermal Facility Rating, system voltage limit, or stability
limit.11 The OTC criteria essentially married the concept of operating limits and transfer limits in
a single parameter for WECC Transmission paths.
Following the enactment of EPAct 2005 and the establishment of mandatory Reliability
Standards applicable to all owners, operators, and users of the BPS, WECC sought to translate
certain of its existing practices under its RMS reliability criteria into regional Reliability Standards
to supplement the continent-wide Reliability Standards the Commission approved in Order No.
693. 12 To that end, WECC established a task force to identify criteria in the RMS that should be
binding on all BPS users, owners, and operators in the Western Interconnection, not just the
Transmission Operators subject to the RMS. The task force chose eight of the identified criteria,
which had the highest priority and could be implemented in the near term for translation into
regional Reliability Standards.
The task force recommended the continued application of the Path OTC paradigm on the
assumption that it would continue to provide an effective way to ensure that the system was
operated within acceptable limits, consistent with the analysis tools available at that time. The
primary processes and analysis tools that operators in the Western Interconnection used to achieve
pre- and post-Contingency reliability at that time included: (1) offline studies performed by
engineers; and (2) SCADA systems monitored by System Operators. At that time, state estimation,
Real-time Contingency analysis, and other control room analysis tools more widely used today to

11

For example, a thermally limited OTC was a pre-determined WECC path transfer capability value that was
intended to prevent an identified Contingency from causing exceedance of an identified Facility’s thermal facility
rating. A transient stability limited OTC was a pre-determined WECC path transfer capability value that was
intended to prevent an identified Contingency from resulting in violation of WECC-established transient voltage dip
criteria or transient frequency dip criteria.
12

Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, 72 FR 16416 (2007), FERC
Stats. & Regs. ¶ 31,242, order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053 (2007).

5

assess conditions in the day-ahead time horizon and in Real-time were in their infancy and not
generally used in operations in the Western Interconnection. Further, there was no continent-wide
requirement to conduct Operational Planning Analyses (“OPAs”) or Real-time Assessments
(“RTAs”).
On March 26, 2007, NERC filed for Commission approval eight WECC regional
Reliability Standards, including WECC-TOP-STD-007-0, based on the task force’s
recommendation. 13

Regional Reliability Standard WECC-TOP-STD-007-0 was a direct

translation of the OTC reliability criteria from the RMS and identified 40 Transmission paths
subject to the requirements therein. In filing for approval, NERC and WECC noted that WECCTOP-STD-007-0 was more stringent than the corresponding continent-wide Reliability Standard
TOP-007-0 in that the regional standard provided that any exceedances of OTC, regardless of
whether there was also an applicable IROL designation, be addressed within 30 minutes (and 20
minutes for stability limited paths).
On June 8, 2007, the Commission approved the eight WECC regional Reliability Standards
as mandatory and enforceable in the Western Interconnection. 14 The Commission found that
WECC-TOP-STD-007-0 met the criteria for regional Reliability Standards as it was more stringent
than the corresponding continent-wide Reliability Standard TOP-007-0. 15 The Commission also
directed modifications to WECC-TOP-STD-007-0 to address certain shortcomings with respect to
formatting, aligning WECC regional definitions with the NERC Glossary, and removing
compliance and measure references. 16
13

North American Electric Reliability Corporation, Request for Approval of Regional Reliability Standards
of the Western Electricity Coordinating Council, Docket No. RR07-11-000 (Mar. 26, 2007).

14

North American Electric Reliability Corporation, 119 FERC ¶ 61,260 (2007).

15

Id. at P 104.

16

Id. at P 110.

6

In response to the Commission’s directive and to make certain other changes, on March
25, 2009, NERC submitted a petition for approval of regional Reliability Standard TOP-007WECC-1, which was designed to replace and improve upon WECC-TOP-STD-007-0. 17 In Order
No. 752, issued on April 21, 2011, the Commission approved TOP-007-WECC-1 and the
retirement of WECC-TOP-STD-007-0. 18

Regional Reliability Standard TOP-007-WECC-1

carries forward the operating paradigm from the RMS and WECC-TOP-STD-007-0 focused on
identifying a single, pre-determined maximum transfer capability flow value for an entire
Transmission path and requiring Transmission Operators to operate within that value to achieve
reliable operations. 19
Among other changes, TOP-007-WECC-1a uses the continent-wide NERC Glossary term
“SOL” rather than the WECC regional term “OTC.” Although, as the Commission recognized,
those terms do not have a one-to-one relationship, 20 the change in terminology was not intended
to and did not substantively modify the obligation under the regional standard or existing practices
in the Western Interconnection for establishing the single, pre-determined transfer value within
which the 40 applicable Transmission paths must be operated. 21 As stated in Order No. 752, the
Commission initially questioned the appropriateness of the change in terminology:

17

Petition of the North American Electric Reliability Corporation for Approval of Proposed Western
Electricity Coordinating Council Regional Reliability Standard TOP-007-WECC-1 – System Operating Limits,
Docket No. RM09-14-000 (Mar. 25, 2009).
18

North American Electric Reliability Corporation, Order No. 752, 135 FERC ¶ 61,062, 76 Fed. Reg. 23470
(2011). On June 18, 2014, the Commission issued approved an interpretation to TOP-007-WECC-1, such that the
numbering of the standard became TOP-007-WECC-1a. N. Elec. Reliability Corp., Docket No. RD14-18-000 (June
18, 2014) (unpublished letter order).
19

Specifically, Requirement R1 of TOP-007-WECC-1 provides: “When the actual power flow exceeds an SOL
for a Transmission path, the Transmission Operators shall take immediate action to reduce the actual power flow
across the path such that at no time shall the power flow for the Transmission path exceed the SOL for more than 30
minutes.”
20

As noted above, OTC marries the concepts of transfer capability and operating limits, and, in that respect,
more closely align with the NERC Glossary term “Total Transfer Capability” than the term “SOL.”

21

Order No. 752 at PP 32-35.

7

In the NOPR, the Commission questioned the appropriateness of replacing the term
“operating transfer capability” limit as used in the currently-effective Reliability
Standard TOP-STD-007-0, with the term “SOL,” as used in TOP-007-WECC-1.
The Commission stated that the term “SOL” is used within the Western
Interconnection to refer to the facility or element that presents the most limiting of
the prescribed operating criteria for the rated system path. Whereas, the OTC limit
corresponds to the “maximum amount of actual power transferred over direct or
parallel transmission elements from one transmission operator to another
transmission operator.” The Commission expressed concern that the terms SOL
and OTC appear to measure different things. 22
Nevertheless, the Commission approved the change in response to WECC’s comments that
the replacement of “OTC” with “SOL” was to address the Commission’s concerns regarding the
proliferation of regional terms and would not substantively change existing practices nor the
manner in which the requirement would be enforced. 23 WECC stated that the methodologies for
establishing SOLs and OTCs in the Western Interconnection are the same and result in the same
value. 24 As a result, OTCs became SOLs in the Western Interconnection.
In addition to the change in terms, TOP-007-WECC-1 extended the mitigation time for
returning flows on stability limited paths to within the “Path SOL” from 20 minutes to 30 minutes.
The Commission approved the extension on the grounds that having a uniform time for both
stability-limited and thermally-limited paths would reduce confusion among operators. 25
b. Legacy Operational Paradigm Reflected in TOP-007-WECC-1a
The Path OTC/SOL concept developed under the RMS and carried forward into WECC
regional Reliability Standards TOP-STD-007-0 and, ultimately, TOP-007-WECC-1a, presumes an
operational paradigm characterized by the following:

22

Order No. 752 at P 32 (internal citations omitted).

23

Order No. 752 at P 35.

24

The SOL methodology for the Western Interconnection developed pursuant to the Facilities Design,
Connections, and Maintenance (“FAC”) group of Reliability Standards was consistent with the manner in which it
calculated OTC under the RMS and WECC-TOP-STD-007-0.

25

Id. at P 31.

8

•

A study, assessment, or analysis needs to be performed ahead of time to establish a Path
OTC/SOL that achieves acceptable Bulk Electric System (“BES”) system performance.

•

The established Path OTC/SOL (a maximum flow value on an interface or cut plane) is
then communicated and coordinated with operators and other impacted entities prior to
implementation.

•

Transmission Operators are then given Operating Plans for operating below the Path
OTC/SOL with the presumption that doing so will result in reliable operations.
More specifically, under this paradigm, Transmission Operators in the Western

Interconnection, through their participation in sub-regional study groups, perform seasonal studies
for each of the applicable Transmission paths to determine a Path SOL for use during the upcoming
season. A primary objective of these seasonal studies is to confirm that the WECC Path Rating
for each applicable path is achievable, given the expected system conditions for that season. 26 If
the seasonal study demonstrates that the WECC Path Rating is achievable for that season, the
WECC Path Rating becomes the Path SOL for the season. If the seasonal study shows that WECC
Path Rating (plus some margin) is reached without encountering pre- or post-Contingency
reliability issues, the Path is considered to be “flow limited” for that season and the “flow limited”
WECC Path Rating serves as the seasonal Path SOL. If the seasonal study does not demonstrate
that the WECC Path Rating is achievable for that season, the Transmission Operator determines,
in accordance with the Reliability Coordinator’s SOL methodology under Reliability Standard
FAC-011, a lesser Path flow value that provides for acceptable thermal, voltage, and stability
criteria performance for the pre- and post-Contingency state. This value becomes the Path SOL
for the season. The establishment of the Path OTC/SOL included Transfer Capability, scheduling
limits, allocations, and commercial considerations.

26

Each year WECC publishes the WECC Path Rating Catalog, which identifies ratings for all of the defined
paths in WECC, not just the 40 paths subject to TOP-007-WECC-1a. The ratings are most closely related to a Total
Transfer Capability, as defined in the NERC Glossary.

9

As noted, once the seasonal Path SOL is established, it is communicated to Transmission
Operators, along with an operating plan for operating below the Path SOL. The operating plan
sets forth the steps operators must take to meet the 30-minute requirement in the event of an
exceedance of the Path SOL. Throughout the season, the Transmission Operator may reduce the
Path SOL as necessary based on their studies of anticipated outage conditions. Under TOP-007WECC-1a, when the actual power flow on an applicable Transmission path exceeds its Path
OTC/SOL in Real-time operations, operators must initiate actions, up to and including preContingency load shedding, in accordance with the operating plan, to reduce that Path’s flow
below the Path SOL within 30 minutes.
To illustrate, WECC Path 30 (TOT 1A) – which is comprised of the following three
transmission lines: (1) the Bears Ears-Bonanza 345 kV line, the Hayden-Artesia 138 kV line, and
the Meeker-Rangely 138 kV line – currently has a Path SOL of 650 MW for flows going east to
west. The 650 MW Path SOL is based on transfer studies indicating that if there is a Contingency
outage of the Bears Ears-Bonanza 345 kV line when east to west flows on Path 30 (TOT 1A)
exceed 650 MW, there is a significant risk that the Hayden-Artesia 138 kV line would exceed its
emergency Facility Rating. As a result, a Path SOL of 650 MW was established to help ensure
that a Contingency of the Bears Ears – Bonanza 345 kV line does not cause the Hayden – Artesia
138 kV line to exceed its emergency Facility Rating at that transfer level. Under TOP-007-WECC1a, should flows on the Path exceed 650 MW, Transmission Operators must take action, up to and
including load shedding, to reduce the flow below that level within 30 minutes, regardless of the
results of Real-time Contingency analysis.
II.

Purpose of Retirement of TOP-007-WECC-1a
The purpose of the proposed retirement of TOP-007-WECC-1a, along with the planned

modifications to Peak’s SOL methodology, is to move away from the historical Path SOL
10

paradigm, decoupling operating limits and transfer capability, and allow entities in the Western
Interconnection to align their operating practices with the framework established in the revised
TOP/IRO Reliability Standards approved in Order No. 817. As discussed below, the use of the
Path OTC/SOL paradigm, unique to the Western Interconnection, has not always provided an
optimal framework for reliably operating the BPS and is not necessary for reliable operations. As
recognized in Order No. 817, the revised TOP/IRO Reliability Standards – which are focused on
identifying SOLs and IROLs on a facility-by-facility basis (as opposed to an entire Transmission
path) and using OPAs and RTAs to assess conditions and identify expected or actual SOL or IROL
exceedances – provide a comprehensive approach to achieving the objective of operating within
acceptable pre- and post-Contingency reliability criteria. 27 The retirement of TOP-007-WECC-1a
and alignment with the continent-wide TOP/IRO Reliability Standards would help ensure that
SOLs are developed for each BES facility that comprise the 40 applicable Transmission paths and
that those SOLs (and any IROLs) accurately reflect Real-time operating limits. The retirement
will also avoid duplication and potential confusion upon the effective date of the revised TOP/IRO
standards stemming from the disparate operating paradigms reflected in TOP-007-WECC-1a and
the revised TOP/IRO standards.
a. The Operational Paradigm Reflected in TOP-007-WECC-1a Does Not Provide an
Optimal Framework for Reliable Operations
As noted above, given the analysis tools available at the time the RMS was first developed,
the presumption was that operating within the Path OTC/SOL would result in acceptable system
performance for the pre- and post-Contingency operating states and an efficient use of the
Transmission system. That has not always been the case. The application of the Path SOL

27

Order No. 817 at PP 16-17.

11

construct has not always resulted in Path SOL values that represented the appropriate limits for
reliably operating the facilities comprising the Transmission paths given existing conditions (i.e.,
the Path SOL value did not provide for acceptable performance pre- and post-Contingency). As
acknowledged in the joint FERC-NERC report titled Arizona-Southern California Outage on
September 8, 2011, Causes and Recommendations (the “Southwest Outage Report”), the
September 8, 2011 event in the Southwest occurred even though the facilities on the relevant
Transmission paths were operated within their pre-determined Path SOLs. 28 While Transfer
Capability values reflected in the Path SOL are appropriate for determining scheduling limitations,
using these pre-determined Transfer Capability values as Real-time operating limits poses
significant reliability gaps.
At the other end of the spectrum, the use of a pre-determined OTC/SOL for an entire path
as contemplated under TOP-007-WECC-1a and Peak’s SOL methodology has not always resulted
in an efficient use of the Transmission system. There have been instances where actual flows
exceeded the Path SOL and the requirements of TOP-007-WECC-1a necessitated that entities take
extreme and disruptive actions to reduce the flow, such as pre-Contingency load shedding, even
though Real-time analysis did not confirm the presence of an actual reliability issue. In such
circumstances, TOP-007-WECC-1a prevented operators in the Western Interconnection from
efficiently and reliably operating the system based on Real-Time analysis.
Following the Southwest Outage Report and with the proliferation of advanced
applications, such as state estimation and Real-time Contingency analysis, entities in the Western
Interconnection have come to understand that reliance on a single pre-determined Path SOL value

28
FERC and NERC, Arizona-Southern California Outage on September 8, 2011, Causes and
Recommendations (Apr. 27, 2012), at 99-100, available at http://www.ferc.gov/legal/staff-reports/04-27-2012-fercnerc-report.pdf.

12

may not always provide reasonable assurance of reliable operations. As a result and consistent
with the findings and recommendations of the Southwest Outage Report, entities in the Western
Interconnection have been making changes in their operating practices to improve reliability,
including, among other things, increased reliance on day-ahead and Real-Time Assessments of
operating conditions, and to differentiate between Real-time operating limits and transfer
capability. As part of that transition, entities in the Western Interconnection are seeking to move
away from the historical, path-centric paradigm unique to the Western Interconnection and align
their practices with the framework in the revised continent-wide TOP/IRO Reliability Standards
by, among other things, (1) modifying Peak’s SOL methodology to establish SOLs for each BES
Facility, not entire Paths, based on Facility Ratings, voltage limits, and stability limits, and (2)
retiring regional Reliability Standard TOP-007-WECC-1a. 29
b. The Revised TOP/IRO Standards Provide a More Efficient and Effective
Framework for Operating the BPS Within Acceptable Pre- and Post-Contingency
Criteria
In contrast to the operational paradigm in TOP-007-WECC-1a, as the Commission
recognized in Order No. 817, the revised TOP/IRO Reliability Standards provide a
“comprehensive framework as well as important improvements to ensure that the bulk electric
system is operated within pre-established limits while enhancing situational awareness and
strengthening operations planning.” 30

Additionally, the Commission stated that the revised

29
Entities in the Western Interconnection would continue to use Transfer Capability values that respect SOLs
for purposes of scheduling transmission service but, for the reasons stated above, would no longer combine transfer
limits and operating limits into a single, pre-determined value for measuring reliable operation on an entire
Transmission path.
30

Order No. 817 at 14.

13

TOP/IRO Reliability Standards “address the coordinated efforts to plan and reliably operate the
bulk electric system under both normal and abnormal conditions.” 31
The continent-wide revised TOP/IRO Reliability Standards reflect, in large measure, the
operating paradigm contemplated by the Southwest Outage Report. 32 The TOP/IRO Reliability
Standards approved in Order No. 817 contemplate SOLs and IROLs as dynamic values reflecting
Facility Ratings, voltage limits, transient Stability limits, and voltage Stability limits, determined
for each BES facility based on assessments of expected or actual conditions to ensure acceptable
performance pre- and post-Contingency. 33 The use of a single pre-determined Path SOL value, as
reflected in TOP-007-WECC-1a and Peak’s current SOL methodology, is not consistent with the
framework contemplated in the revised TOP/IRO Standards and exists only in TOP-007-WECC1a as a legacy of an operating paradigm established in the late 1990s. As stated in the whitepaper
titled “System Operating Limit Definition and Exceedance Clarification” (the “SOL
Whitepaper”) 34 underpinning the development of the revised TOP/IRO Reliability Standards:
Some have interpreted the language in approved FAC-011-2, Requirement R2 to
imply that the objective is to perform prior studies to determine a specific MW flow
value (SOL) that ensures operation within the criteria specified in approved FAC011-2, Requirement R2 sub-requirements, the assumption being that if the system
is operated within this pre-determined SOL value, then all of the pre- and postContingency requirements described in approved FAC-011-2, Requirement R2 will
be met. The SDT believes this approach may not capture the complete intent of the
SOL concept within approved FAC-011-2, which is both:

31

Id.

32

As the Commission recognized, the revisions to the TOP/IRO standards and the definitions of OPA and
RTA addressed multiple recommendations in the Southwest Outage Report. Order No. 817 at P 17.

33

Order No. 817 at P 16 (recognizing that “the TOP/IRO Standards approved [in Order No. 817] address the
possibility that additional SOLs could develop or occur in the same-day or Real-Time operational time horizon and,
therefore, would pose an operational risk to the interconnected transmission network if not addressed.”).
34

The SOL Whitepaper is available at
http://www.nerc.com/pa/Stand/Prjct201403RvsnstoTOPandIROStndrds/2014_03_fifth_posting_white_paper_sol_ex
ceedance_20150108_clean.pdf.

14

1. Know the Facility Ratings, voltage limits, transient Stability limits, and
voltage Stability limits, and
2. Ensure that they are all observed in both the pre- and post-Contingency state
by performing a Real-time Assessment.
SOLs are based on Normal and Emergency (short-term) Facility Ratings, voltage
limits, transient Stability limits, and voltage Stability limits – any of which can be
the most restrictive limit at any point in time pre- or post-Contingency. For
example, if an area of the BES is at no risk of encroaching upon Stability or voltage
limitations in the pre- or post-Contingency state, and the most restrictive limitations
in that area are pre- or post-Contingency exceedance of Facility Ratings, then the
thermal Facility Ratings in that area are the most limiting SOLs. Conversely, if an
area is not at risk of instability and no Facilities are approaching their thermal
Facility Ratings, but the area is prone to pre- or post-Contingency low voltage
conditions, then the voltage limits in that area are the most limiting SOLs. 35
Based on this understanding of SOLs, the TOP/IRO Reliability Standards approved in
Order No. 817 set forth requirements for operating within SOLs and IROLs, focusing on the use
of OPAs and RTAs to assess conditions and identify the relevant SOLs and IROLs for each BES
facility and any expected or actual exceedances of those limits. Specifically, during the operations
planning time horizon, Reliability Coordinators and Transmission Operators must perform OPAs
to assess whether the planned operations for the next-day will exceed SOLs (and IROLs for the
Reliability Coordinator) within their area. 36 If the OPA identifies any potential exceedances, the
Reliability Coordinator and Transmission Operator must have an Operating Plan to address the
exceedance. 37 In Real-time, Reliability Coordinators and Transmission Operators must perform
RTA every 30 minutes to determine whether there are any expected or actual exceedances of SOLs
(and IROLs for the Reliability Coordinator) based on Real-time conditions. 38 If the RTA identifies
any such exceedances, the Reliability Coordinator and Transmission Operator must initiate its

35

SOL Whitepaper at 3 (emphasis added).

36

IRO-008-2, Requirement R1; TOP-004-2, Requirement R1.

37

IRO-008-2, Requirement R2; TOP-004-2, Requirement R2.

38

IRO-008-2, Requirement R4; TOP-001-3, Requirement R13.

15

Operating Plan to mitigate the SOL exceedance. 39 If there is an expected or actual IROL
exceedance identified in the RTA, the exceedance must be resolved within the IROL Tv, which
can be no longer than 30 minutes. 40
The WECC Path 30 (TOT 1A) example, discussed above, helps illustrate the need to retire
TOP-007-WECC-1a. As described above, WECC Path 30 (TOT 1A) currently has a Path SOL of
650 MW for flows going east to west based on transfer studies indicating that a Contingency of
the Bears Ears – Bonanza 345 kV line may cause the Hayden – Artesia 138 kV line to exceed its
emergency Facility Rating at transfer levels exceeding 650 MW. As a result of these studies, the
relevant entities in the Western Interconnection monitor for that Contingency in their Real-time
Contingency analysis. If TOP-007-WECC-1a is not retired, Transmission Operators may be
required to monitor the Bears Ears – Bonanza 345kV line Contingency under two conflicting
paradigms.
Under the revised TOP/IRO Reliability Standards, Transmission Operators and Peak, as
the Reliability Coordinator, would (1) perform OPAs and RTAs to determine, among other things,
if conditions are such that the loss of the Bears Ears – Bonanza 345kV line were to cause the
Hayden – Artesia 138 kV line to exceed its emergency Facility Rating and, (2) if so, take action to
mitigate that SOL exceedance in accordance with the applicable Operating Plan. If the emergency
Facility Rating for the Hayden – Artesia line were also designated as an IROL, the mitigating
actions would have to occur with IROL Tv.
NERC understands that it is possible for Real-time Contingency analysis to show that even
if flows on the Transmission path exceeded the 650 MW Path SOL, the expected or actual

39

IRO-008-2, Requirement R5; TOP-001-3, Requirement R14.

40

IRO-009-2, Requirements R1-R4; TOP-001-3, Requirement R12.

16

operating conditions may be such that a Contingency of the Bears Ears – Bonanza 345kV line
would not cause the Hayden – Artesia 138 kV line to exceed its emergency Facility Rating at the
time. Conversely, NERC understands that it is also possible for Real-time Contingency analysis
to show that even if flows were below the 650 MW Path SOL, the conditions may be such that a
Contingency of the Bears Ears – Bonanza 345kV line would cause the Hayden – Artesia 138 kV
line to exceed its emergency Facility Rating at the time. Under the revised TOP/IRO Reliability
Standards, the assessment of conditions through OPAs and RTAs would show whether the SOL
for the Hayden – Artesia 138 kV line would actually be exceeded as a result of the that Contingency
and the relevant entities would be required to act to maintain reliability in their areas under
Reliability Standards IRO-001-4, Requirement R1 and TOP-001-3, Requirement R1.
In contrast, under TOP-007-WECC-1a, the results of OPAs and RTAs are irrelevant.
Should flows on WECC Path 30 (TOT 1A) exceed 650 MW, Transmission Operators must take
action, up to and including load shedding, to reduce the flow below that level within 30 minutes,
regardless of whether Real-Time Contingency analysis identifies an expected or actual exceedance
of the emergency Facility Rating for the Hayden – Artesia 138 kV line. On the other hand, if RealTime Contingency analysis identifies that such an SOL exceedance is expected to occur or is
actually occurring in Real-time even if flows were below 650 MW, TOP-007-WECC-1a would
not require any action because the Path SOL is not exceeded. In short, under TOP-007-WECC1a, entities in the Western Interconnection may be required to take mitigating action (redispatching
generation, curtailing schedules, and even shedding load) when Real-time tools indicate that no
action is necessary. In other circumstances, TOP-007-WECC-1a would not require any mitigating

17

action when Real-time tools indicates a potential or actual reliability issue (i.e., the use of Path
SOLs could sometimes mask actual reliability problems). 41
Given the requirements in the revised TOP/IRO Reliability Standards, the question is
whether there is any continuing reliability need to monitor and address the Bears Ears – Bonanza
345kV line Contingency under the TOP-007-WECC-1a paradigm and risk operator confusion as
to the appropriate operating limit for Real-time operations. As the example above highlights, as
compared to the legacy practices reflected in TOP-007-WECC-1a, the framework established in
the revised TOP/IRO standards provides for a more efficient and accurate mechanism to identify
and respond to potential reliability issues. As the Commission acknowledged in Order No. 817
and as discussed in greater in the following sections, the revised TOP/IRO Reliability Standards
“provide a comprehensive framework…to ensure that the bulk electric system is operated within
pre-established limits while enhancing situational awareness and strengthening operations
planning.” 42 There is no reliability need to continue the historical, path-centric approach reflected
in TOP-007-WECC-1a or to treat the facilities comprising the 40 Transmission paths subject to
TOP-007-WECC-1a any differently than all other facilities are treated under the continent-wide
TOP/IRO Reliability Standards. Each of the facilities comprising the 40 Transmission paths would
be monitored in accordance with the Commission-approved TOP/IRO Reliability Standards and
subject to associated mitigation requirements should there be an expected or actual exceedance of
an SOL or IROL on those facilities.

41

Of course, if Real-time analysis indicates a potential or actual reliability issue, Transmission Operators
would take action to address the issue, in accordance with the continent-wide standards.
42

Order No. 817 at 14 (emphasis added).

18

III.

Application of the Revised TOP/IRO Reliability Standards to the 40 Transmission
Paths
The remainder of this Supplement discusses manner in which the reliability of the 40

Transmission paths currently subject to TOP-007-WECC-1a is addressed under the revised
TOP/IRO Reliability Standards. This section is organized as follows:
•

Section III.a explains the manner in which the 40 Transmission paths subject to TOP-007WECC-1a would be monitored under the continent-wide TOP and IRO Reliability
Standards.

•

Section III.b discusses whether the 30-minute mitigation requirement in TOP-007-WECC1a would continue to apply to the 40 Transmission paths following retirement.

•

Section III.c discusses the manner in which SOLs and IROLs are established for each of
the facilities comprising the 40 Transmission paths and the types of limitations associated
with those paths.

•

Section III.d discusses Peak’s intent to modify its methodology for establishing SOLs and
IROLs and the manner in which such revisions could impact the evaluation of the 40
Transmission paths.

•

Section III.e discusses Peak’s use of a 1000 MW threshold in its current methodology for
determining IROLs and its application to the 40 Transmission paths.
a. Each of the Facilities Comprising the 40 Transmission Paths Must be Monitored
Under the Continent-wide TOP/IRO Reliability Standards to Help Ensure Reliable
Operation
Upon the retirement of regional Reliability Standard TOP-007-WECC-1a and the

modifications to Peak’s SOL methodology, Transmission paths in the Western Interconnection
would no longer have a single, uniquely monitored Path SOL. 43 Instead, each facility comprising
the 40 Transmission paths would be separately monitored in accordance with the requirements in
the continent-wide TOP-IRO Reliability Standards. With respect to monitoring those facilities,
the TOP/IRO Reliability Standards affirmatively obligate Transmission Operators and Reliability

43

The only exception would be if the Transmission path is directly associated with an identified and
monitored stability limit.

19

Coordinators to monitor facilities in their areas to ensure they have the necessary situational
awareness to maintain reliable operations, as follows:
•

TOP-001-3, Requirement R10 requires each Transmission Operator to perform the
following as necessary for determining SOL exceedances within its Transmission Operator
Area: (1) within its Transmission Operator Area, monitor Facilities and the status of
Special Protection Systems, and (2) outside its Transmission Operator Area, obtain and
utilize status, voltages, and flow data for Facilities and the status of Special Protection
Systems.

•

IRO-002-4, Requirement R11 obligates Reliability Coordinators to monitor Facilities, the
status of Special Protection Systems, and non-BES facilities identified as necessary by the
Reliability Coordinator, within its Reliability Coordinator Area and neighboring Reliability
Coordinator Areas to identify any SOL exceedances and to determine any IROL
exceedances within its Reliability Coordinator Area.
With two exceptions, the facilities comprising each of the 40 paths subject TOP-007-

WECC-1a are designated as BES facilities. 44 Under IRO-002-4, Requirement R11, the Reliability
Coordinator is responsible for monitoring both BES Facilities and non-BES facilities that have an
impact on the BES. Further, in accordance with directives in order No. 817, NERC is developing
modifications to TOP-001-3, Requirement R10 to require Transmission Operators to also monitor
non-BES facilities that could adversely impact BPS reliability. Accordingly, each of the facilities
comprising the 40 Transmission paths, including non-BES facilities, would be subject to these
monitoring requirements to ensure, among other things, that the facilities are operated within their
SOLs and IROLs. In addition, as discussed above, the facilities comprising the 40 Transmission
paths would be evaluated in OPAs and RTAs. 45
To ensure that Reliability Coordinators and Transmission Operators have the data
necessary to perform their OPAs, RTAs, and Real-time monitoring obligations, the TOP/IRO
44

The two facilities that do not meet the BES definition are (1) Dry Gulch 115/69-kV transformer – Path 6 –
West of Hatwai, and (2) Drum-Summit 60-kV line – Path 24 – PG&E-Sierra.

45

In performing OPAs and RTAs, entities must consider the following inputs: load forecasts, generation
output levels, Interchange, known Protection System and Special Protection System status or degradation,
Transmission outages, generator outages, Facility Ratings, and identified phase angle and equipment limitations

20

Reliability Standards (IRO-010-2 and TOP-003-3) establish requirements for the provision of
information and data, including non-BES data, needed by Transmission Operators and Reliability
Coordinators to fulfill their planning and operational responsibilities. Under Reliability Standards
IRO-008-2 and TOP-003-3, Reliability Coordinators and Transmission Operators would collect
information and data pertaining to the facilities comprising the 40 Transmission paths to help
maintain situational awareness and reliable operations.
b. Each of the Facilities Comprising the 40 Transmission Paths Would be Subject to
Mitigation Requirements under the Continent-wide TOP and IRO Reliability
Standards Designed to Ensure Reliable Operations
Regional Reliability Standard TOP-007-WECC-1a establishes a 30-minute mitigation
period for all exceedances of Path SOLs, regardless of risk to the BPS. As described above, the
application of the 30-minute mitigation requirement to all Path SOLs is a legacy of the RMS
program. 46 WECC is not aware of any specific technical studies or analysis supporting application
of the 30-minute mitigation time to each Path SOL; instead, the 30-minute period seems to have
originated as an agreement between participants in the RMS that 30 minutes represents a
reasonable amount of time to require Transmission Operators to return flow on the path to within
the Path OTC/SOL.
In contrast, the revised TOP/IRO Reliability Standards do not create a uniform timeframe
for addressing all SOL or IROL exceedances; instead, those standards create a risk-based
framework for addressing SOL and IROL exceedances. As discussed below, depending on risk to
the BPS, the required mitigation period could be less than 30 minutes and, in other cases, be greater
than 30 minutes.

46

As discussed above, the RMS originally required mitigation within 20 minutes for stability limited paths or
for more than 30 minutes for thermally limited paths. The mitigation timeframe was modified to 30 minutes for all
Path SOLs with the approval of TOP-007-WECC-1a.

21

The revised TOP/IRO Reliability Standards establish the following requirements in the
day-ahead time frame for mitigating potential SOL and IROL exceedances:
•

Each Transmission Operator is required to conduct an OPA to assess whether its planned
operations for the next day will exceed any of its SOLs. (TOP-001-3, Requirement R1).

•

Similarly, each Reliability Coordinator is required to conduct an OPA to assess whether its
planned operations for the next day will exceed any SOLs and IROLs within its Wide Area.
(IRO-008-2, Requirement R1).

•

If the Transmission Operator’s OPA identifies any potential SOL exceedances, the
Transmission Operator must: (1) have an Operating Plan to mitigate that exceedance; (2)
notify entities identified in the Operating Plan as to their role under those plans; and (3)
provide its Operating Plan for next-day operations to its Reliability Coordinator. (TOP001-3, Requirements R2, R3 and R6). The Operating Plan must include specific
plans/strategies to prevent an SOL exceedance (i.e., pre-Contingency actions) or mitigate
the impact of the SOL exceedance (i.e., post-Contingency actions). The Operating Plan
must contain appropriate timeframes for initiating the actions required under the plan to
maintain reliable operations and/or return the system to within applicable SOLs.

•

If the Reliability Coordinator’s OPA identifies any potential SOL or IROL exceedances,
the Reliability Coordinator must: (1) have a coordinated Operating Plan for next day
operations to address the potential exceedances, which considers the Operating Plans
provided by its Transmission Operators; and (2) notify other impacted entities of their role
under the plan. (IRO-008-2, Requirements R2 and R3).

•

Additionally, for each IROL that the Reliability Coordinator identifies one or more days
prior to the operating day, the Reliability Coordinator must have one or more Operating
Processes, Procedures, or Plans that identify actions the Reliability Coordinator shall take
or actions the Reliability Coordinator shall direct others to take (up to and including load
shedding) that can be implemented in time to prevent the identified IROL exceedance and
to mitigate the magnitude and duration of an IROL exceedance such that the IROL
exceedance is relieved within the IROL’s Tv, which is defined as the maximum time, not
to exceed 30 minutes, that an IROL can be violated before the risk to the interconnection
or other Reliability Coordinator Area(s) becomes greater than acceptable. (IRO-009-2,
Requirement R1).
For the operating day, the revised TOP/IRO Reliability Standards establish the following

requirements for mitigating expected or actual SOL and IROL exceedances:
•

Each Transmission Operator must perform an RTA every 30 minutes to assess conditions
and determine whether there are any actual or expected SOL exceedances. (TOP-001-3,
Requirement R13).

22

•

The Reliability Coordinator must also perform an RTA every 30 minutes to assess
conditions and determine whether there are any actual or expected SOL or IROL
exceedances. (IRO-008-2, Requirement R4).

•

If the results of its RTA indicates an actual or expected condition that results in, or could
result in, a SOL or IROL exceedance within its Wide Area, the Reliability Coordinator
shall notify impacted Transmission Operators and Balancing Authorities within its
Reliability Coordinator Area, and other impacted Reliability Coordinators as indicated in
its Operating Plan. (IRO-008-2, Requirement R5).

•

Further, the Transmission Operator must initiate its Operating Plan to mitigate a SOL
exceedance identified as part of its Real-time monitoring or RTA and inform its Reliability
Coordinator of actions taken to return the System to within limits when a SOL has been
exceeded. (TOP-001-3, Requirement R1).

•

Given the more severe impact of IROL exceedances, the Transmission Operator is
prohibited from operating outside any IROL for a continuous duration exceeding its
associated IROL Tv. (TOP-001-3, Requirement R1).

•

Additionally, for expected or actual IROL exceedances identified through its Real-time
monitoring or RTA, the Reliability Coordinator must (1) initiate one or more Operating
Processes, Procedures, or Plans to prevent an expected IROL exceedance; and (2) act or
direct others to act so that the magnitude and duration of an actual IROL exceedance is
mitigated within the IROL’s Tv. (IRO-009-2, Requirements R2 and R3).
Under this framework, the applicable mitigation period depends on whether the SOL is

also designated as an IROL and the facts and circumstances presented by the exceedance. Given
the increased severity of adverse reliability impact of an IROL exceedance, the maximum period
allowed for operating outside an IROL is 30 minutes, as described above. The application of IROL
Tv, however, could result in a mitigation period of less than 30 minutes as, in some cases, the risk
to the Interconnection or other Reliability Coordinator Areas would become greater than
acceptable within 5-10 minutes of the IROL exceedance or even immediately. As such, under the
Revised TOP/IRO Reliability Standards, upon the retirement of TOP-007-WECC-1a, if any
facilities comprising the 40 applicable Transmission paths has an IROL, the mitigation period for
exceedances of that IROL would be equivalent to the time provided in TOP-007-WECC -1a for
Path SOL exceedances, if not less.

23

For (non-IROL) SOL exceedances, the revised TOP/IRO Reliability Standards recognize
that a maximum mitigation period applicable to all SOL exceedances is not necessary or prudent
as the mitigation period should depend on the potential impact of that exceedance over time. The
TOP/IRO Reliability Standards thus provide Reliability Coordinators and Transmission Operators
the flexibility to determine the appropriate mitigation time periods. As described above, when
there is an SOL exceedance in Real-time, the Transmission Operator is required to implement
mitigating strategies consistent with its Operating Plan. Operating Plans can include specific
Operating Procedures or more general Operating Processes and should include both pre- and postContingency mitigation plans/strategies. As described in the SOL Whitepaper, Operating Plans
must include appropriate timelines to escalate the level of mitigating plans/strategies to ensure
acceptable BES performance is maintained and prevent SOL exceedances from becoming an IROL
exceedance. 47 As such, an Operating Plan must include the appropriate time element to return the
system to within acceptable Normal and Emergency (short-term) Ratings and/or operating limits.
The timeframes set forth in the Operating Plan could require action in less than 30 minutes
or greater than 30 minutes, depending on the facts and circumstances. For instance, depending on
the time-value rating of the facility, the Operating Plan could lay out certain actions to be taken
prior to the exceedance, within five minutes of the exceedance, and within 30 minutes, within 60
minutes if the problem was not resolved. Ultimately, however, Reliability Standards IRO-001-4,
Requirement R1 and TOP-001-3, Requirement R1 create affirmative obligations for Reliability
Coordinators and Transmission Operators, respectively, to act to maintain the reliability of their
area via their own actions or by issuing Operating Instructions. As a result, should an entity’s

47

SOL Whitepaper at 7-8.

24

Operating Plan fail to require action in timely manner so as to maintain reliability in its area, it
risks violating those requirements.
Upon the effective date of the revised TOP/IRO Standards and the retirement of TOP-007WECC-1a, Reliability Coordinators and Transmission Operators would be subject to these
mitigation requirements for all BES facilities in the Western Interconnection, including those
comprising each of the 40 Transmission paths currently subject to TOP-007-WECC-1a.
Additionally, under the FAC Reliability Standards, Peak, as the Reliability Coordinator for the
Western Interconnection (except Alberta, Canada), is obligated to determine which SOLs for the
facilities comprising the 40 Transmission paths, as well as any others in the Western
Interconnection, would meet the criteria for an IROL designation such that a maximum 30-minute
time period would continue to apply to those facilities upon the retirement of TOP-007-WECC1a. Any failure to properly designate IROLs may be a violation of requirements in the FAC
Reliability Standard (FAC-014-2).
In deciding to move away from the historical approach reflected in TOP-007-WECC-1a,
WECC did not identify any reliability need to continue the Path SOL paradigm and treat the
facilities comprising the 40 applicable Transmission paths any differently from any other BES
facility. The 40 paths subject to TOP-007-WECC-1a were originally selected for different
treatment as part of the RMS in the late 1990s. There are no records of any technical studies or
analysis to document the criteria under which the paths were chosen for inclusion in the RMS.
The identification of the 40 Transmission paths seems to have been an attempt to capture many of
the high-voltage transmission lines between the historical WSCC control areas. Similarly, as noted
above, application of the 30-minute mitigation period to all exceedances of Path SOLs seems to

25

be a remnant of an agreement as to a reasonable, uniform time period for mitigating action rather
than an analysis of the reliability effects of such exceedances.
c. SOLs and IROLs, Where Applicable, Must be Established for Each of the Facilities
Comprising the 40 Transmission Paths in Accordance with Peak’s SOL
Methodology
As described above, under the revised TOP/IRO Reliability Standards, all BES facilities
must be operated within SOLs and, as applicable, IROLs. In accordance with the requirements of
the FAC Reliability Standards, Transmission Operators must, consistent with their Reliability
Coordinator’s SOL methodology, establish SOLs for each of their BES facilities. Additionally,
the Reliability Coordinator must determine which of those SOLs warrant designation as an IROL.
As contemplated in the FAC and TOP/IRO standards, SOLs and IROLs are determined based on
seasonal studies, outage coordination studies, OPAs, and RTAs. As noted above, certain SOL
values are dynamic, reflecting changing operating conditions. Similarly, an SOL may become an
IROL when certain conditions are present but not under other conditions.
As contemplated in Peak’s document outlining expected modifications to its SOL
methodology (“Draft SOL Methodology Document”), posted to its website on September 9, 2016,
all BES Facilities in the Western Interconnection, including those that comprise the 40
Transmission paths currently subject to TOP-007-WECC-1a, would be monitored in the operations
time horizon for pre- and post-Contingency performance in an iterative fashion as Real-time
approaches: first via seasonal assessments, then through the IRO-017 outage coordination process
studies, followed by OPAs, and finally through RTAs. 48 For each of these iterative steps,
Transmission Operators will determine whether Facility Ratings or system voltage limits would
be expected to be exceeded in the pre- or post-Contingency state, or whether any instability risks
48

The Draft SOL Methodology Document is available at:
https://www.peakrc.com/whatwedo/sol/Pages/default.aspx.

26

would need to be addressed via established stability limits. In studying the system and assessing
conditions for determining SOLs, Transmission Operators would be responsible under Peak’s
expected SOL methodology for stressing the system, identifying any instability risks, and
determining the extent to which transmission interfaces and load areas should be stressed in
identifying stability SOLs. Although the extent to which the system should be stressed depends
on a variety of factors, to accurately determine stability SOLs, the system should be stressed up
to, and slightly beyond, reasonable maximum stressed conditions. Any stability limitation that
results from studies would be identified as an SOL.
Peak’s SOL Methodology would then be applied to determine whether any of the SOLs
qualify as an IROL. NERC understands that Peak currently monitors three IROLs in its area and
is continuously performing studies to identify other limits that may qualify as IROLs. Peak
reviews studies performed by Planning Coordinators, seasonal studies performed by sub-regional
study groups, and outage studies and OPAs performed by Transmission Operators to determine
the existence of IROLs. Peak also collaborates with Transmission Operators to identify additional
risks in the system for instability or potential Cascading in Real-time operations. If any of these
analyses reveals risks associated with instability, Cascading, or uncontrolled separation, these risks
would be addressed via IROLs as appropriate per Peak’s SOL Methodology.
As it relates to establishing SOLs and IROLs, Peak conducted an examination of the 40
Transmission paths to understand and document the type of limitation associated with each of the
paths. Attachment A hereto provides the results of that investigation so as to provide the
Commission additional information about the 40 Transmission paths and the types of issues
entities in the Western Interconnection currently monitor. The information in Attachment A is
based on data from planning studies that established the WECC Path Rating and Transmission

27

Operator reports since January 2015. Peak noted that the limitations on these paths change based
on Transmission Operator assessments of anticipated operating conditions, including Facility
outages. Peak’s objective in gathering this information was to identify paths that were flagged as
being transient stability limited or voltage stability limited since January 1, 2015 and for use in its
determinations of whether any of these limitations warrant an IROL designation going forward.
The following are some key observations from the data in the attachment:
•

Of the 40 Transmission paths, only two were identified as being limited by transient
stability or voltage stability. One of the two stability limits has already been designated as
an IROL (i.e., the NW Washington IROL).

•

25 Transmission paths are thermally limited.

•

15 of the Transmission paths are thermally based proxy limits (i.e., limitations placed on
the path to address a post-Contingency thermal limit exceedance on a non-Path Facility).

•

Three of the Transmission paths are limited by steady state voltage, voltage dip criteria, or
voltage deviation.

•

Six of the Transmission paths are combinations of thermally limited or voltage limited
depending on either direction of flow or season.

•

The limitation on 16 Transmission paths is established by multiple contingency events.
d. The Expected Modifications to Peak’s SOL Methodology are Designed to Enbsure
that SOLs and IROLs are Developed Consistent with the Framework Established
in the Revised TOP/IRO Standards
As noted in the Petition, NERC and WECC understand that Peak expects to issue a revised

SOL methodology as part of the transition away from the path-centric paradigm, with an effective
date of April 1, 2017. The April 1, 2017 effective date is designed to coincide with the effective
date of the revised TOP/IRO Reliability Standards. Consistent with the proposed retirement of
TOP-007-WECC-1a, under the revised SOL methodology, NERC and WECC understand that
SOLs for the 40 Transmission paths subject to TOP-007-WECC-1a will no longer reflect a single
pre-determined value for the entire path. Instead, as discussed above, the SOL methodology would

28

focus on determining SOLs on a facility-by-facility basis and reflect Facility Ratings, system
voltage limits, and stability limitations used in operations.
Peak’s Draft SOL Methodology Document describes the manner in which BES facilities
in the Western Interconnection, including facilities comprising the 40 Transmission paths will be
evaluated for SOL and IROL designations. As discussed therein and as noted above, for stability
limitations, Transmission Operators are required to stress the system to determine the existence of
any stability limitations. When stability limitations are established, they must be established in a
manner that most accurately and directly addresses the instability risk, and they must be established
on an interface that most accurately and directly monitors the instability risk. Accordingly,
stability limitations may or may not coincide with defined WECC Paths. Neither historical
presumptions/practices regarding system monitoring nor commercial/contractual arrangements
should influence where stability limitations are most accurately established and monitored for
reliability. Additionally, Facility Ratings and system voltage limits will be monitored for the preand post-Contingency state as SOLs, and any identified stability limitations will be monitored as
SOLs (or IROLs, if applicable).
e. The Expected Modifications to Peak’s SOL Methodology Would Eliminate the
1,000 MW Threshold for Determining IROLs
As the Commission noted in Order No. 817, Peak’s SOL methodology currently includes
a 1,000 MW threshold as part of its IROL determinations. 49 NERC and WECC understand that as
part of its modifications to its SOL methodology, Peak expects to remove the 1,000 MW criteria.
NERC and WECC understand that Peak’s revised SOL methodology would contain a description
of instability, Cascading, and uncontrolled separation that necessitate the need to establishing an

49

Order No. 817 at P 27.

29

SOL as an IROL without use of a load loss threshold. Accordingly, the 1,000 MW threshold would
not be applied to the facilities comprising the 40 Transmission paths upon the issuance of the
modified SOL methodology, which is expected to occur on the proposed effective date of the new
TOP/IRO Reliability Standards and the proposed retirement of TOP-007-WECC-1a. In any event,
the specifics related to Peak’s SOL methodology and the appropriate designation of IROLs is a
matter of compliance with Reliability Standard FAC-011-2 and should not affect the
Commission’s analysis of whether regional Reliability Standard TOP-007-WECC-1a should be
retired.
IV.

Conclusion
For the reasons discussed in the Petition and in this Supplement, NERC and WECC

respectfully request that the Commission approve retirement of regional Reliability Standard TOP007-WECC-1a, effective April 1, 2017.
Respectfully Submitted
/s/ Shamai Elstein
Sandy Mooy
Associate General Counsel
Chris Albrecht
Legal Counsel
Steve Rueckert
Director of Standards
Western Electricity Coordinating Council
155 North 400 West, Suite 200
Salt Lake City, UT 84103
(801) 582-0353
smooy@wecc.biz
calbrecht@wecc.biz
steve@wecc.biz

Charles A. Berardesco
Senior Vice President and General Counsel
Shamai Elstein
Senior Counsel
Gizelle Wray
Associate Counsel
North American Electric Reliability Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
charlie.berardesco@nerc.net
shamai.elstein@nerc.net
gizelle.wray@nerc.net

Counsel for the Western Electricity
Coordinating Council

Counsel for the North American Electric
Reliability Corporation

Date: November 16, 2016
30

Attachment A

Vic Howell
Manager, Ops Engineering Support
970-613-3537
vhowell@peakrc.com

Peak Reliability performed an investigation of each of the paths listed in the TOP-007WECC-1a “Major WECC Transfer Paths in the Bulk Electric System”. The investigation
examined the 2016 WECC Path Rating Catalog as well as TOP-provided Path Reports
submitted since January 1, 2015. The objective of this investigation was to understand
and document the type of limitation associated with each of the TOP-007-WECC-1a
Paths.
The WECC Path Rating Catalog provides a description of the type of limitation
associated with each path based on the planning studies that established the WECC
Path Rating.
Per Peak’s current SOL Methodology for the Operations Horizon and Peak’s IRO-010
Data specification, TOPs are required to provide Peak with a daily Path Report for each
of the WECC Paths, including the TOP-007-WECC-1a Paths. The Path Report identifies
the type of limitation for each path (thermal, voltage, transient stability, voltage stability)
and any relevant transmission or generation facility outage that is associated with that
limitation. The limitation on these Paths change frequently based on TOP assessments
of anticipating operating conditions, including Facility outages. Peak’s objective was to
identify Paths that were flagged as being transient stability limited or voltage stability
limited since January 1, 2015.
The results of the investigation are captured in the attached spreadsheet. A few key
observations can be gleaned from the data:
1. Of the 40 Paths listed in the “Major WECC Transfer Paths in the Bulk Electric
System”, only two Paths were identified as being limited by transient stability or
voltage stability. One of the two stability limited Paths is addressed via the NW
Washington IROL currently in place.
2. Twenty seven Paths are strictly thermally limited.
3. Fifteen of the Path limitations are thermally based proxy limits – these are
limitations placed on the Path to address a post-Contingency thermal limit
exceedance on a non-Path Facility.
4. Three Paths are limited by steady state voltage, voltage dip criteria, or voltage
deviation.
5. Six Paths are combinations of thermally limited or voltage limited depending on
either direction of flow or season.
6. Sixteen Paths have the limit established by multiple contingency events.

PEAK RELIABILITY — CORPORATE OFFICE
7600 NE 41st STREET • SUITE 150 • VANCOUVER • WASHINGTON • 98662-7934
4850 HAHNS PEAK DRIVE • SUITE 120 • LOVELAND • COLORADO • 80538-6001

November 2016

Page - 2

Peak’s next steps are to perform a more thorough investigation of Path 1 which is
limited by frequency performance within AESO. Peak will collaborate with the TOPs
associated with that Path to determine if an IROL should be established.
Peak intends to continue to monitor all BES Facilities for pre- and post-Contingency
performance as part of its Operational Planning Analyses (OPA) and Real-time
Assessments (RTA). Under the new Reliability Standards, TOPs are required to do the
same. Any SOL exceedance identified in a TOP or RC OPA is required to have an
Operating Plan to address the SOL exceedance. Additionally, any SOL exceedance
identified in an RTA is required to have an Operating Plan implemented to address that
SOL exceedance. Peak intends to continue using the Operating Guides that were
collaboratively developed for each WECC Path. These Path Operating Guides provide
RC System Operators and TOP System Operators with steps that can be taken when
flow on the path is causing or contributing to an SOL Exceedance.
The IRO-017-1 Outage Coordination process (final version posted on 10/03/2016)
requires that each TOP identify any instability risks that arise as a result of the outage
conditions. If any new instability risks arise due to the outage, the TOP is responsible for
establishing outage-specific stability limits and communicating the instability risk,
stability limits and any associated Operating Plans to the RC. Peak will investigate each
stability limitation and will apply its SOL Methodology to determine whether the stability
limitation qualifies as an IROL.

PEAK RELIABILITY — CORPORATE OFFICE
7600 NE 41st STREET • SUITE 150 • VANCOUVER • WASHINGTON • 98662-7934
4850 HAHNS PEAK DRIVE • SUITE 120 • LOVELAND • COLORADO • 80538-6001

Alberta - British Columbia

Path Operator Limiting Facility Part of Path Path Limitation
on
E-W: AESO frequency performance critierion
AESO, BCHA
W-E: thermal

1
3

Northwest - British Columbia

BCHA

on

4

West of Cascades - North

BPA

stability

5

West of Cascades - South

BPA

off

6
8

West of Hatwai
Montana-to-Northwest

BPA
NWMT

off
on

14

Idaho-to-Northwest

IPCO

on

15
16
17

Midway - Los Banos
Idaho - Sierra
Borah West

CISO
SPPC
IPCO

off
off
on

18
19
20

Montana-Idaho
Bridger West
Path C (Pre-Gateway)

NWMT
PAC
PAC

on
on
N/A

22

Southwest of Four Corners

APS

on

24

PG&E - Sierra

CISO

on

26
27
30
31

CISO
LADWP
WACM
WACM

on
off
on
off

32
34
35
36

Northern-Southern California
Intermountain Power Project DC
TOT 1A
TOT 2A
Pavant - Gonder 230kV;
Intermountain-Gonder 230kV
(Paths 78 and 79)
TOT 2C
TOT 3

SPPC
PACE
NEVP
WACM

off
off
on
on

39
45

TOT 5
SDG&E - CFE

WACM
CISO

off
on

46

West of Colorado River

CISO

off

47
48

Southern New Mexico (NM1)
Northern New Mexico

EPEC
PNM

N/A
on

49
50
51

East of the Colorado River
Cholla - Pinnacle Peak
Southern Navajo

APS
APS
APS

on
off
off

55
61
65
66
73

Brownlee East
Lugo - Victorville 500kV
Pacific DC Intertie (PDCI)
California-Oregon Intertie (COI)
North of John Day

IPCO
CISO
LADWP
CISO
BPA

on
on
off
on
off

Alturas Project
Montana Southeast

SPPC
NWMT
CAISO
BPA

off
on
N/A
N/A

TOP-007-WECC-1a Path?

76
80
SCIT
COI/PDCI – North of John Day
cutplane

Path Name

Associated Contingency(ies)
E-W Loss of Cranbrook-Bennett 500kV tie violates AESO frequency
performance criteria
W-E Loss of
generation within AESO
Loss of Custer-Ingldow 1 & 2 and separation of BCHydro

thermal
voltage-stability limited, thermal
( voltage stability limit monitored by NW Washington IROL) Schultz-Raver #1 500kV & Schultz-Echo Lake #1 500kV
John Day-Marion & Buckley-Marion 500kV or Ashe-Marion &
Buckley-Marion 500kV
thermal summer low voltage in winter
Bell-Coulee 500kV & Westside-Coulee 230kV or breaker failure
@Taft 500kV4
thermal
E-W thermal W-E. pre contingency voltage
Garrison-Taft #1&2 500kV
Hemingway-Summer Lake 500kV or Lolo-Oxbow 230kV & Hells
Canyon-Brownlee 230kV
thermal
Midway-Gates & Midway-Lost Banos 500kV or 2 Palo Verde Units
or Los Banos-Tesla & Los Banos Tracy 500kV or Tesla-Midway 1&2
500kV
thermal
Humboldt-Coyote Creek 345kV or Coyote Creek-Valmy (S-N)
thermal
Kinport-Midpoint & Borah-Adelaide-Midpoint #1 345kV
thermal
Bridger-Three-Mile Knoll & Bridger-Populus 345kV (N-S) or BradyAntelope 230kV (S-N)
thermal and voltage limited
thermal limit, voltage dip and frequency dip criterion
Jim Bridger-Populus #1 or #2 345kV
Simultaneous loss of any 2 Path 19 lines
voltage
Four Corners-Moenkopi 500kV line or either Four Corners-Cholla
345kV lines
thermal
Drum PH or Drum-Rio Oso #1 115kV or Drum Summit 1&2 115kV
or Goldhill-Placer #2 115kV or Halsey Jct-Newark #1&2 115kV
thermal
Midway-Vincent #1&2 500kV or Midway-Vincent #1 & WhirlwindMidway 500kV
thermal
Loss of the IPPDC bi-pole line.
thermal or post contingency voltage deviation
Craig-Bonanza 345kV
thermal
Montrose-San Juan 345kV
thermal

IPP-Gonder 230kV (E-W) or Robinson-Gonder 345kV (W-E)
Sigurd-Three Peaks 345 or Three Peaks-Red Butte 345
Simultaneous Intermountain-Adelanto DC line outage
TOT 3 operating matrix; limiting contingencies vary
Hayden-Gore Pass 230kV or Craig-Ault 345kV or Hayden-Foidel
Creek 230kV
thermal
Imperial Valley-Miguel 500kV
thermal
Imperial Valley North Gila 500kV or Palo Verde-Colorado River
500kV
thermal
Springerville-Macho Springs 345kV or West Mesa-Arroyo 345kV or
Greenlee-Hidalgo 345kV
voltage
Four Corners-Rio Puerco 345kV or San Juan-Rio Puerco 345kV
thermal
Navajo-Crystal 500kV or Perkins-Mead 500kV or North Gilathermal
Imperial Valley 500kV
Four Corners-Cholla 345kV
thermal
Yavapai-Westwing 500kV
thermal
Hemingway-Summer Lake 500kV or two Jim Bridger 345kV lines or
any two Brownlee-Boise Bench 230kV lines
thermal
Mohave-Lugo 500kV or Eldorado-Lugo 500kV
thermal
Loss of PDCI bi-pole line
thermal
Malin Round Mt 1 & 2
thermal
ALIS stressed to reasonability limits with no limitation found Two Palo Verde Units or PDCI Bi-pole
N-S post disturance voltage deviation Malin-Hilltop 230kV
system
S-N thermal
N-S Midpoint-Humboldt 345kV
Broadview-Garrison #1&2 500kV
thermal
ALIS stressed to reasonability limits with no limitation found Tested to reasonability limit with no issues identified
ALIS stressed to reasonability limits with no limitation found Loss of two Palo Verde units
thermal
thermal
thermal
thermal