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pdfUNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
North American Electric Reliability
Corporation
) Docket No. ____________
)
PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARD
TPL-007-4
Lauren A. Perotti
Senior Counsel
Marisa Hecht
Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, DC 20005
(202) 400-3000
(202) 644-8099 – facsimile
[email protected]
[email protected]
Counsel for the North American Electric
Reliability Corporation
February 7, 2020
TABLE OF CONTENTS
I. SUMMARY ............................................................................................................................ 2
II. NOTICES AND COMMUNICATIONS ................................................................................ 4
III. BACKGROUND .................................................................................................................... 4
A.
Regulatory Framework .................................................................................................... 4
B.
NERC Reliability Standards Development Procedure .................................................... 5
C.
Procedural History of Proposed Reliability Standard TPL-007-4 ................................... 6
1.
Reliability Standard TPL-007-1 ................................................................................... 6
2.
Reliability Standard TPL-007-2 ................................................................................... 7
3.
Reliability Standard TPL-007-3 ................................................................................... 9
4.
Project 2019-01 Modifications to TPL-007-3 .............................................................. 9
IV. JUSTIFICATION FOR APPROVAL .................................................................................. 10
A.
Corrective Action Plans to Address Vulnerabilities Identified through Supplemental
GMD Vulnerability Assessments ............................................................................................. 11
B.
Corrective Action Plan Deadline Extensions................................................................. 13
C.
Enforceability of Proposed Reliability Standard TPL-007-4......................................... 16
V. EFFECTIVE DATE .............................................................................................................. 17
VI. CONCLUSION ..................................................................................................................... 18
Exhibit A
Proposed Reliability Standard TPL-007-4 – Transmission System Planned
Performance for Geomagnetic Disturbance Operations
Exhibit B
Implementation Plan for Proposed Reliability Standard TPL-007-4
Exhibit C
Analysis of Violation Risk Factors and Violation Severity Levels
Exhibit D
Technical Rationale
Exhibit E
Order No. 672 Criteria for Proposed Reliability Standard TPL-007-4
Exhibit F
Summary of Development History and Complete Record of Development
Exhibit G
Standard Drafting Team Roster for Project 2019-01
Exhibit H
Consideration of Directives
i
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
North American Electric Reliability
Corporation
) Docket No. ____________
)
PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARD TPL-007-4
Pursuant to Section 215(d)(1) of the Federal Power Act (“FPA”) 1 and Section 39.5 of the
regulations of the Federal Energy Regulatory Commission (“FERC” or “Commission”), 2 the
North American Electric Reliability Corporation (“NERC”) 3 hereby requests Commission
approval of proposed Reliability Standard TPL-007-4 (Transmission System Planned Performance
for Geomagnetic Disturbance Events) (Exhibit A), the associated implementation plan (Exhibit
B), the Violation Risk Factors (“VRFs”) and Violation Severity Levels (“VSLs”) (Exhibit C), and
the retirement of currently effective Reliability Standard TPL-007-3. The NERC Board of Trustees
(“Board”) adopted proposed Reliability Standard TPL-007-4 on February 6, 2020.
Proposed Reliability Standard TPL-007-4 requires owners and operators of the Bulk Power
System (“BPS”) to conduct initial and on-going vulnerability assessments of the potential impact
of defined geomagnetic disturbance (“GMD”) events on BPS equipment and the BPS as a whole.
The modifications in the proposed standard address the Commission’s directives in Order No. 851 4
related to requirements for Corrective Action Plans. Specifically, and as discussed further herein,
the proposed modifications would: (i) require entities to develop Corrective Action Plans for
1
16 U.S.C. § 824o (2018).
18 C.F.R. § 39.5 (2019).
3
The Commission certified NERC as the electric reliability organization (“ERO”) in accordance with Section
215 of the FPA on July 20, 2006. N. Am. Elec. Reliability Corp., 116 FERC ¶ 61,062 (2006).
4
Geomagnetic Disturbance Reliability Standard; Reliability Standard for Transmission System Planned
Performance for Geomagnetic Disturbance Events, Order No. 851, 165 FERC ¶ 61,124 (2018) (“Order No. 851”).
2
1
vulnerabilities identified through supplemental GMD Vulnerability Assessments; and (ii) require
entities to seek approval from the ERO of any extensions of time for the completion of Corrective
Action Plan items. NERC requests that the Commission approve the proposed Reliability Standard
and related elements as just, reasonable, not unduly discriminatory or preferential, and in the public
interest. NERC also requests that the Commission approve the proposed implementation plan
(Exhibit B).
Pursuant to Section 39.5(a) of the Commission’s regulations, 5 this petition presents the
technical basis and purpose of proposed Reliability Standard TPL-007-4, a summary of the
development history (Exhibit F), and a demonstration that the proposed Reliability Standard meets
the criteria identified by the Commission in Order No. 672 (Exhibit E). 6
I.
SUMMARY
Proposed Reliability Standard TPL-007-4 requires entities to conduct initial and on-going
assessments of the potential impact of two defined GMD events, the benchmark GMD event and
the supplemental GMD event, on BPS equipment and the BPS as a whole. The benchmark GMD
event is intended to simulate the wide area impacts of a severe GMD event. The supplemental
GMD event is designed to account for the localized peak effects of severe GMD events on systems
and equipment. In the standard, the assessments based on these defined events are referred to as
benchmark GMD Vulnerability Assessments and supplemental GMD Vulnerability Assessments,
respectively. If entities identify system performance issues through their GMD Vulnerability
Assessments, they must take action to mitigate these issues.
5
18 C.F.R. § 39.5(a).
The Commission specified in Order No. 672 certain general factors it would consider when assessing whether
a particular Reliability Standard is just and reasonable. See Rules Concerning Certification of the Electric Reliability
Organization; and Procedures for the Establishment, Approval, and Enforcement of Electric Reliability Standards,
Order No. 672, 114 FERC ¶ 61,104, order on reh’g, Order No. 672-A, 114 FERC ¶ 61,328 (2006) (“Order No. 672”).
6
2
Proposed Reliability Standard TPL-007-4 improves upon the currently effective version of
the TPL-007 standard by enhancing requirements related to Corrective Action Plans as directed
by the Commission in Order No. 851. In this Order, the Commission approved Reliability Standard
TPL-007-2 but directed NERC to revise the TPL-007 standard as follows:
•
revise the standard to require Corrective Action Plans for assessed supplemental
GMD vulnerabilities; 7 and
•
replace the provision in Requirement R7 Part R7.4 that would allow entities to selfextend Corrective Action Plan implementation deadlines with a process through
which extensions of time are considered on a case-by-case basis. 8
The proposed standard addresses the Commission’s Order No. 851 directives by:
•
requiring an applicable entity to develop a Corrective Action Plan if system
performance issues are identified through the supplemental GMD Vulnerability
Assessment; and
•
requiring an applicable entity to seek approval for any requests to extend Corrective
Action Plan implementation deadlines, requests that NERC and the Regional
Entities would then consider on a case-by-case basis.
For these reasons, and as discussed more fully in this petition, NERC respectfully requests
that the Commission approve the proposed standard as just, reasonable, not unduly discriminatory
or preferential, and in the public interest.
7
8
See Order No. 851 at PP 29 and 39.
Id. at P 54.
3
II.
NOTICES AND COMMUNICATIONS
Notices and communications with respect to this filing may be addressed to: 9
Lauren Perotti*
Senior Counsel
Marisa Hecht*
Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, DC 20005
(202) 400-3000
(202) 644-8099 – facsimile
[email protected]
[email protected]
III.
Howard Gugel*
Vice President of Engineering and Standards
North American Electric Reliability
Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
[email protected]
BACKGROUND
A.
Regulatory Framework
In the Energy Policy Act of 2005, 10 Congress entrusted the Commission with the duties of
approving and enforcing rules to ensure the reliability of the BPS. Congress also entrusted the
Commission with certifying an Electric Reliability Organization (“ERO”) charged with
developing and enforcing mandatory Reliability Standards, subject to Commission approval.
Section 215(b)(1) of the FPA states that all users, owners, and operators of the BPS in the United
States will be subject to Commission-approved Reliability Standards. 11 Section 215(d)(5) of the
FPA authorizes the Commission to order the ERO to submit a new or modified Reliability
Standard. 12 Section 39.5(a) of the Commission’s regulations requires the ERO to file with the
Commission for its approval each Reliability Standard that the ERO proposes should become
9
Persons to be included on the Commission’s service list are identified by an asterisk. NERC respectfully
requests a waiver of Rule 203 of the Commission’s regulations, 18 C.F.R. § 385.203, to allow the inclusion of more
than two persons on the service list in this proceeding.
10
16 U.S.C. § 824o.
11
Id. § 824o(b)(1).
12
Id. § 824o(d)(5).
4
mandatory and enforceable in the United States and each modification to a Reliability Standard
that the ERO proposes should be made effective. 13
The Commission is vested with the regulatory responsibility to approve Reliability
Standards that protect the reliability of the BPS and to ensure that such Reliability Standards are
just, reasonable, not unduly discriminatory or preferential, and in the public interest. Pursuant to
Section 215(d)(2) of the FPA 14 and Section 39.5(c) of the Commission’s regulations, “the
Commission will give due weight to the technical expertise of the Electric Reliability
Organization” with respect to the content of a Reliability Standard. 15
B.
NERC Reliability Standards Development Procedure
The proposed Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development process. 16 NERC
develops Reliability Standards in accordance with Section 300 (Reliability Standards
Development) of its Rules of Procedure and the NERC Standard Processes Manual. 17
In its order certifying NERC as the Commission’s ERO, the Commission found that
NERC’s proposed rules provide for reasonable notice and opportunity for public comment, due
process, openness, and a balance of interests in developing Reliability Standards, 18 and thus satisfy
certain of the criteria for approving Reliability Standards. 19 The development process is open to
any person or entity with a legitimate interest in the reliability of the BPS. NERC considers the
13
18 C.F.R. § 39.5(a).
16 U.S.C. § 824o(d)(2).
15
18 C.F.R. § 39.5(c)(1).
16
Order No. 672 at P 334.
17
The NERC Rules of Procedure is available at https://www.nerc.com/AboutNERC/Pages/Rules-ofProcedure.aspx. The NERC Standard Processes Manual is available at
https://www.nerc.com/comm/SC/Documents/Appendix_3A_StandardsProcessesManual.pdf.
18
N. Am. Elec. Reliability Corp., 116 FERC ¶ 61,062 at P 250.
19
Order No. 672 at PP 268, 270.
14
5
comments of all stakeholders, and stakeholders must approve, and the NERC Board of Trustees
must adopt, a Reliability Standard before the Reliability Standard is submitted to the Commission
for approval.
C.
Procedural History of Proposed Reliability Standard TPL-007-4
This section summarizes the history of the TPL-007 standard and the development of
proposed Reliability Standard TPL-007-4.
1. Reliability Standard TPL-007-1
On January 21, 2015, NERC filed a petition requesting Commission approval of Reliability
Standard TPL-007-1, the second-stage GMD Reliability Standard contemplated by the
Commission in Order No. 779. 20 The Commission approved Reliability Standard TPL-007-1 in
Order No. 830, issued on September 22, 2016. 21 In its Order, the Commission directed NERC to
revise the TPL-007 standard as follows:
•
revise the benchmark GMD event definition so that the reference peak geoelectric
field amplitude component is not based solely on spatially-averaged data; 22
•
revise Requirement R6 to require registered entities to apply spatially averaged and
non-spatially averaged peak geoelectric field values, or some equally and efficient
alternative, when conducting thermal impact assessments; 23
•
revise the standard to require entities to collect geomagnetically induced current
monitoring and magnetometer data as necessary to enable model validation and
situational awareness; 24 and
20
Petition of the North American Electric Reliability Corporation for Approval of Proposed Reliability
Standard TPL-007-1 Transmission System Planned Performance for Geomagnetic Disturbance Events, Docket No.
RM15-11-000 (Jan. 21, 2015); Reliability Standards for Geomagnetic Disturbances, Order No. 779, 143 FERC ¶
61,147 (2013), reh’g denied, 144 FERC ¶ 61,113 (2013) (directing the development of Reliability Standards to address
GMDs in two stages).
21
Reliability Standard for Transmission System Planned Performance for Geomagnetic Disturbance Events,
Order No. 830, 156 FERC ¶ 61,215 (2016) at P 1 (“Order No. 830”).
22
Id. at P 44.
23
Id. at P 65.
24
Id. at P 88.
6
•
revise requirements for Corrective Action Plans to include: (i) a one-year deadline
for the development of any necessary Corrective Action Plans; (ii) a two-year
deadline for the implementation of non-hardware mitigation; and (iii) a four-year
deadline for the implementation of hardware mitigation. 25
In addition to these standard-modification directives, the Commission directed NERC to
undertake certain activities intended to enhance knowledge of GMDs and their potential impacts
on reliability. 26
2. Reliability Standard TPL-007-2
On January 22, 2018, NERC submitted Reliability Standard TPL-007-2 for Commission
approval. Reliability Standard TPL-007-2 was developed in response to the Commission’s
directives in Order No. 830. The standard added new requirements for GMD Vulnerability
Assessments and thermal impact assessments to be performed based on the supplemental GMD
event, a second defined event that accounts for localized peak effects of GMDs and which was not
based on spatially-averaged data. Reliability Standard TPL-007-2 included the deadlines specified
by the Commission in Order No. 830 for the development and completion of any necessary
Corrective Action Plans to address system performance issues resulting from the benchmark GMD
event. Additionally, Reliability Standard TPL-007-2 contained new requirements for obtaining
GIC monitor and magnetometer data.
The Commission approved Reliability Standard TPL-007-2 in Order No. 851, issued
November 15, 2018. 27 In approving the standard, the Commission found that it represented an
25
Id. at PP 101-102.
See Order No. 830 at P 77 (directing NERC to submit a work plan describing how NERC would research
specific GMD-related topics identified by the Commission and other topics at NERC’s discretion) and PP 89, 93
(directing NERC to collect GIC and magnetometer data pursuant to Section 1600 of the NERC Rules of Procedure
and to make the information available). The Commission accepted NERC’s revised GMD research work plan in Order
No. 851. See Order No. 851 at P 65. NERC provides periodic updates to the Commission regarding work performed
under this plan in Docket No. RM15-11-003.
27
Geomagnetic Disturbance Reliability Standard; Reliability Standard for Transmission Planned Performance
for Geomagnetic Disturbance Events, Order No. 851, 165 FERC 61,124 (2018).
26
7
improvement over TPL-007-1 and complied with several of the Commission’s Order No. 830
directives. The Commission, however, directed NERC to develop and submit two sets of
modifications to the standard relating to requirements for Corrective Action Plans.
First, the Commission noted that Reliability Standard TPL-007-2 required applicable
entities to assess supplemental GMD event vulnerabilities, but did not require entities to develop
formal Corrective Action Plans to address those vulnerabilities. The Commission stated that it saw
“no basis, technical or otherwise, for not requiring corrective action plans for assessed
supplemental GMD event vulnerabilities while requiring corrective action plans for assessed
benchmark GMD event vulnerabilities consistent with the Commission’s directions in Order Nos.
779 and 830.” 28 The Commission therefore directed NERC to revise the standard to require
Corrective Action Plans for assessed supplemental GMD vulnerabilities. 29
Second, the Commission noted that Reliability Standard TPL-007-2, Requirement R7.4
would allow applicable entities, “under certain conditions, to extend corrective action plan
implementation deadlines without prior approval.” 30 The Commission stated, “Based on our
consideration of the record, we believe that the case-by-case review process contemplated by
Order No. 830 is the appropriate means for considering extension requests. Accordingly… we
direct that NERC develop modifications to Reliability Standard TPL-007-2 to replace the timeextension provision in Requirement R7.4 with a process through which extensions of time are
considered on a case-by-case basis.” 31
28
29
30
31
Id. at P 48.
Id.; see also Order No. 851 at PP 29 and 39.
Id. at P 54.
Id. at P 54.
8
The Commission directed NERC to submit these modifications within 12 months of the
effective date of Reliability Standard TPL-007-2, 32 or by July 1, 2020. The Commission also
directed NERC to prepare and submit a report addressing how often and why entities are exceeding
Corrective Action Plan deadlines as well as the disposition of extension requests. 33 The
Commission directed that this report be submitted within 12 months from the date on which
applicable entities must comply with the last requirement of Reliability Standard TPL-007-2. 34
3. Reliability Standard TPL-007-3
On February 21, 2019, NERC provided an informational notice to the Commission
regarding Reliability Standard TPL-007-3. 35 Reliability Standard TPL-007-3 added a regional
Variance option for Canadian jurisdictions; no changes were made to any requirement or
compliance element that would be mandatory and enforceable in the United States. To provide for
consistency in standard versions used throughout North America, NERC transitioned all U.S.based entities to Reliability Standard TPL-007-3 on July 1, 2019. All phased-in compliance dates
for U.S.-based entities were carried forward unchanged from the Commission-approved TPL-0072 implementation plan.
4. Project 2019-01 Modifications to TPL-007-3
In February 2019, NERC initiated Project 2019-01 Modifications to TPL-007-3 to address
the Commission’s directives in Order No. 851. Following one 45-day formal comment period and
initial ballot, proposed Reliability Standard TPL-007-4 was posted for a 10-day final ballot from
November 13, 2019 through November 22, 2019. The proposed standard received a 78.95 percent
32
33
34
35
Id. at P 4.
Id. at P 30.
Id.
Informational Filing regarding Reliability Standard TPL-007-3, Docket No. RM18-8-000 (Feb. 21, 2019).
9
approval rating, with 94.52 percent quorum. The NERC Board of Trustees adopted the proposed
standard on February 6, 2020.
IV.
JUSTIFICATION FOR APPROVAL
As discussed below and in Exhibits E and H, proposed Reliability Standard TPL-007-4
addresses the Commission’s directives from Order No. 851, satisfies the Commission’s criteria in
Order No. 672, and is just, reasonable, not unduly discriminatory or preferential, and in the public
interest. NERC respectfully requests that the Commission approve the proposed standard and
related elements.
The purpose of proposed Reliability Standard TPL-007-4, which remains unchanged from
prior versions of the standard, is to “[e]stablish requirements for Transmission system planned
performance during geomagnetic disturbance (GMD) events.” The applicability of the proposed
standard also remains unchanged from prior versions: the proposed standard would continue to
apply to: (1) Planning Coordinators and Transmission Planners whose planning areas have a
Facility that includes a power transformer with a high side, wye-grounded winding with terminal
voltage greater than 200 kV; 36 and (2) Transmission Owners and Generator Owners that own a
Facility that includes such equipment.
Consistent with the Commission’s directives in Order No. 851, proposed Reliability
Standard TPL-007-4 reflects two sets of revisions related to requirements for Corrective Action
Plans. First, proposed Reliability Standard TPL-007-4 adds a new Requirement R11 that would
require an applicable entity to develop and implement a Corrective Action Plan if it determines
that its system would experience performance issues from the supplemental GMD event. Second,
proposed Reliability Standard TPL-007-4 revises Requirement R7 so that an applicable entity
36
A power transformer with a “high side wye-grounded winding” refers to a power transformer with windings
on the high voltage side that are connected in a wye configuration and have a grounded neutral connection.
10
would be required to submit to its Compliance Enforcement Authority any request to extend a
Corrective Action Plan deadline from the two and four years provided in the standard for nonhardware and hardware mitigation, respectively. NERC and Regional Entity staff would then
consider each extension request on a case-by-case basis. The revisions, and how they address the
Commission’s directives from Order No. 851, are discussed in detail in the following sections.
A.
Corrective Action Plans to Address Vulnerabilities Identified through
Supplemental GMD Vulnerability Assessments
Currently effective Reliability Standard TPL-007-3 Requirement R8 requires entities to
perform a supplemental GMD Vulnerability Assessment at least once every 60 calendar months.
Consistent with the Commission’s directive in Order No. 851, 37 proposed Reliability Standard
TPL-007-4 would require an applicable entity to develop a Corrective Action Plan if it determines,
through this assessment, that its system would experience performance issues from the
supplemental GMD event.
Proposed Reliability Standard TPL-007-4 addresses the Commission’s Order No. 851
directive by striking, in its entirety, Requirement R8.3 of the currently effective standard:
8.3.
If the analysis concludes there is Cascading caused by the
supplemental GMD event described in Attachment 1, an evaluation
of possible actions designed to reduce the likelihood or mitigate the
consequences and adverse impacts of the event(s) shall be
conducted.
In its place, a new Requirement, R11, is proposed. 38 Proposed Requirement R11 mirrors
Requirement R7, which relates to Corrective Action Plans developed to address issues identified
through benchmark GMD Vulnerability Assessments. Proposed Requirement R11 provides as
follows:
37
See Order No. 851 at PP 29, 39.
As shown in Exhibit A, currently effective Requirements R11 and R12 would become Requirements R12
and R13.
38
11
R11.
Each responsible entity, as determined in Requirement R1, that concludes
through the supplemental GMD Vulnerability Assessment conducted in
Requirement R8 that their System does not meet the performance
requirements for the steady state planning supplemental GMD event
contained in Table 1, shall develop a Corrective Action Plan (CAP)
addressing how the performance requirements will be met. The CAP shall:
11.1.
List System deficiencies and the associated actions needed to
achieve required System performance. Examples of such actions
include:
•
Installation, modification, retirement, or removal of
Transmission and generation Facilities and any associated
equipment.
•
Installation, modification, or removal of Protection Systems or
Remedial Action Schemes.
•
Use of Operating Procedures, specifying how long they will be
needed as part of the CAP.
•
Use of Demand-Side Management, new technologies, or other
initiatives.
11.2.
Be developed within one year of completion of the supplemental
GMD Vulnerability Assessment.
11.3.
Include a timetable, subject to approval for any extension sought
under Part 11.4, for implementing the selected actions from Part
11.1. The timetable shall:
11.3.1. Specify implementation of non-hardware mitigation, if any,
within two years of development of the CAP; and
11.3.2. Specify implementation of hardware mitigation, if any,
within four years of development of the CAP.
11.4.
Be submitted to the CEA with a request for extension of time if the
responsible entity is unable to implement the CAP within the
timetable provided in Part 11.3. The submitted CAP shall document
the following:
11.4.1. Circumstances causing the delay for fully or partially
implementing the selected actions in Part 11.1 and how those
circumstances are beyond the control of the responsible
entity;
11.4.2. Revisions to the selected actions in Part 11.1, if any,
including utilization of Operating Procedures, if applicable;
and
11.4.3. Updated timetable for implementing the selected actions in
Part 11.1.
12
11.5.
Be provided: (i) to the responsible entity’s Reliability Coordinator,
adjacent Planning Coordinator(s), adjacent Transmission
Planner(s), and functional entities referenced in the CAP within 90
calendar days of development or revision, and (ii) to any functional
entity that submits a written request and has a reliability-related need
within 90 calendar days of receipt of such request or within 90
calendar days of development or revision, whichever is later.
11.5.1. If a recipient of the CAP provides documented comments on
the CAP, the responsible entity shall provide a documented
response to that recipient within 90 calendar days of receipt
of those comments.
Proposed Requirement R11 is intended to provide the same content, notification, and
deadline requirements for Corrective Action Plans developed in response to the supplemental
GMD Vulnerability Assessment that are required for Corrective Action Plans developed in
response to the benchmark GMD Vulnerability Assessment. This includes the same provisions for
seeking extensions of Corrective Action Plan deadlines. Proposed Requirement R11 Parts 11.3
and 11.4 therefore mirror the proposed revisions to Requirement R7 Parts 7.3 and 7.4, which are
discussed more fully below.
B.
Corrective Action Plan Deadline Extensions
Currently effective Reliability Standard TPL-007-3 Requirement R7 Part 7.3 provides that
an entity shall include in its Corrective Action Plan a timetable for implementing selected
mitigation actions that: (i) specifies implementation of non-hardware mitigation, if any, within two
years of development of the Corrective Action Plan; and (ii) specifies implementation of hardware
mitigation, if any, within four years of development of the Corrective Action Plan. Requirement
R7 Part 7.4 specifies the steps that the entity must follow should situations beyond the control of
the entity prevent implementation within that timetable. Consistent with the Commission’s
directive in Order No. 851, 39 proposed Reliability Standard TPL-007-4 Requirement R7 Part 7.4
39
Order No. 851 at P 54.
13
would no longer allow entities to extend the two and four-year implementation deadlines without
prior approval. Instead, the entity would be required to submit a detailed request for extension to
its Compliance Enforcement Authority. Such extensions would then be considered, prospectively,
on a case-by-case basis.
Proposed Reliability Standard TPL-007-4 addresses the Commission’s directive by
revising Requirement R7 Parts 7.3 and 7.4 of the currently effective standard as follows:
R7.
Each responsible entity, as determined in Requirement R1, that concludes
through the benchmark GMD Vulnerability Assessment conducted in
Requirement R4 that their System does not meet the performance
requirements for the steady state planning benchmark GMD event
contained in Table 1, shall develop a Corrective Action Plan (CAP)
addressing how the performance requirements will be met. The CAP shall:
***
7.3.
Include a timetable, subject to revision by the responsible entity in
approval for any extension sought under Part 7.4, for implementing
the selected actions from Part 7.1. The timetable shall:
7.3.1. Specify implementation of non-hardware mitigation, if any,
within two years of development of the CAP; and
7.3.2. Specify implementation of hardware mitigation, if any,
within four years of development of the CAP.
7.4.
Be revised if situations beyond submitted to the control
Compliance Enforcement Authority (CEA) with a request for
extension of time if the responsible entity determined in
Requirement R1 prevent implementation of is unable to
implement the CAP within the timetable for implementation
provided in Part 7.3. The revised submitted CAP shall document
the following, and be updated at least once every 12 calendar
months until implemented:
7.4.1. Circumstances causing the delay for fully or partially
implementing the selected actions in Part 7.1 and how those
circumstances are beyond the control of the responsible
entity;
7.4.2. Description of the original CAP, and any previous changes
to the CAP, with the associated timetable(s) for
implementing the selected actions in Part 7.1; and
14
7.4.3.7.4.2. Revisions to the selected actions in Part 7.1, if any,
including utilization of Operating Procedures, if applicable,;
and the updated timetable for implementing the selected
actions.
7.4.3. Updated timetable for implementing the selected actions in
Part 7.1.
As noted in the previous section, these revisions are also reflected in new Requirement R11 Parts
11.3 and 11.4 pertaining to Corrective Action Plans for the supplemental GMD Vulnerability
Assessment.
As with currently effective Reliability Standard TPL-007-3, proposed Reliability Standard
TPL-007-4 Requirement R7 Part 7.4 would continue to require entities to explain how the
circumstances for the implementation delay are due to factors outside of the entity’s control. Such
circumstances could include, but are not limited to, delays resulting from: (i) regulatory or legal
processes, such as permitting; (ii) stakeholder processes required by tariff, (iii) equipment lead
times; or (iv) inability to acquire necessary right-of-way. Proposed Reliability Standard TPL-0074 Requirement R7 Part 7.4 would also continue to require the entity to include revisions to
mitigation actions and an updated timetable for implementation. The notable difference from the
currently effective standard to the proposed standard is that an applicable entity may no longer
extend an implementation deadline on its own; rather, it would be required to submit a request for
a deadline extension to its Compliance Enforcement Authority.
While proposed TPL-007-4 properly focuses on the responsibilities of applicable entities,
NERC is mindful of the Commission’s expectation in Order No. 851 that the process for
considering such extensions “will be timely and efficient such that applicable entities will receive
prompt responses” after submitting their requests. 40 To this end, NERC Compliance Assurance
40
Order No. 851 at PP 55.
15
staff has developed a draft process document to address how NERC and Regional Entity
Compliance Monitoring and Enforcement staff will jointly review requests for extensions to TPL007-4 Corrective Action Plans. The purpose of this process document is to promote a timely,
structured, and consistent approach to extension request submittals and processing. 41 NERC
Compliance Assurance staff will maintain this process document under existing ERO Enterprise
processes and will review and update it as needed. As directed by the Commission in Order No.
851, NERC will prepare and submit a report addressing how often and why applicable entities are
exceeding Corrective Action Plan deadlines and the disposition of extension requests within 12
months from the date on which applicable entities must comply with the last requirement of
Reliability Standard TPL-007-4. 42
C.
Enforceability of Proposed Reliability Standard TPL-007-4
Proposed Reliability Standard TPL-007-4 includes measures in support of each
requirement to ensure that requirements are enforced in a clear, consistent, non-preferential
manner, without prejudice to any party. The proposed standard also includes VRFs and VSLs for
each requirement, which are used to help determine appropriate sanctions if an applicable entity
violates a requirement. VRFs assess the impact to reliability of violating a specific requirement,
while VSLs provide guidance on the way that NERC will enforce requirements.
The proposed standard includes VRFs and VSLs for Requirements R1 through R10, R12
(formerly R11), and R13 (formerly R12) that are substantively the same as those which were
41
Two drafts of the draft process document, titled the TPL-007-4 Corrective Action Plan Extension Review
Process, were posted for information alongside the draft TPL-007-4 standard. See Ex. F (Summary of Development
and Complete Record of Development) at items 15 and 31.
42
Order No. 851 at P 25. As noted in Section V below, the implementation plan for proposed Reliability
Standard TPL-007-4 carries forward the existing phased-in compliance schedule established by the TPL-007-2
implementation plan.
16
approved by the Commission in Order Nos. 830 and 851. 43 The proposed VRF assignment for new
Requirement R11 is High, to promote consistency among the standard’s requirements for
Corrective Action Plans. Similarly, the proposed VSL assignment for new Requirement R11
mirrors the existing VSLs for Requirement R7. As discussed in Exhibit C, these VRFs and VSLs
comport with NERC and Commission guidelines related to their assignment.
V.
EFFECTIVE DATE
NERC respectfully requests that the Commission approve NERC’s proposed
implementation plan, attached to this petition as Exhibit B. Under this plan, proposed Reliability
Standard TPL-007-4 would become effective on the first day of the first calendar quarter that is
six months after Commission approval. NERC requests retirement of Reliability Standard TPL007-3 immediately prior to the effective date of TPL-007-4.
The proposed TPL-007-4 implementation plan integrates the new and revised Corrective
Action Plan requirements in proposed Reliability Standard TPL-007-4 with the existing phased-in
compliance date timeframe under the TPL-007-3 implementation plan.
44
Assuming the
Commission’s order approving the proposed standard becomes effective before June 2023,
applicable entities would be required to develop any required Corrective Action Plans under new
Requirement R11 (supplemental GMD Vulnerability Assessment) by the same date presently
required for Corrective Action Plans under existing Requirement R7 (benchmark GMD
Vulnerability Assessment).
43
The VSL for Requirement R7 was modified slightly to more closely reflect the language of the Requirement.
The VSL for Requirement R8 was modified to eliminate reference to the stricken subpart.
44
For U.S.-based entities, the TPL-007-3 implementation plan carried forward the phased-in compliance dates
approved by the Commission in the TPL-007-2 implementation plan.
17
VI.
CONCLUSION
For the reasons set forth above, NERC respectfully requests that the Commission approve
proposed Reliability Standard TPL-007-4 and related elements, the proposed implementation plan,
and the retirement of currently effective Reliability Standard TPL-007-3 as discussed herein.
Respectfully submitted,
/s/ Lauren A. Perotti
Lauren A. Perotti
Senior Counsel
Marisa Hecht
Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
[email protected]
[email protected]
Counsel for the North American Electric
Reliability Corporation
Date: February 7, 2020
18
Exhibit A1
Proposed Reliability Standard TPL-007-4 – Transmission
System Planned Performance for Geomagnetic Disturbance Operations
(Clean)
RELIABILITY | RESILIENCE | SECURITY
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
A. Introduction
1.
Title:
Events
Transmission System Planned Performance for Geomagnetic Disturbance
2.
Number:
TPL-007-4
3.
Purpose:
Establish requirements for Transmission system planned performance
during geomagnetic disturbance (GMD) events.
4.
Applicability:
4.1. Functional Entities:
4.1.1. Planning Coordinator with a planning area that includes a Facility or
Facilities specified in 4.2;
4.1.2. Transmission Planner with a planning area that includes a Facility or
Facilities specified in 4.2;
4.1.3. Transmission Owner who owns a Facility or Facilities specified in 4.2; and
4.1.4. Generator Owner who owns a Facility or Facilities specified in 4.2.
4.2. Facilities:
4.2.1. Facilities that include power transformer(s) with a high side, wyegrounded winding with terminal voltage greater than 200 kV.
5.
Effective Date: See Implementation Plan for TPL-007-4.
6.
Background: During a GMD event, geomagnetically-induced currents (GIC) may cause
transformer hot-spot heating or damage, loss of Reactive Power sources, increased
Reactive Power demand, and Misoperation(s), the combination of which may result in
voltage collapse and blackout.
B. Requirements and Measures
R1.
Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall
identify the individual and joint responsibilities of the Planning Coordinator and
Transmission Planner(s) in the Planning Coordinator’s planning area for maintaining
models, performing the study or studies needed to complete benchmark and
supplemental GMD Vulnerability Assessments, and implementing process(es) to
obtain GMD measurement data as specified in this standard. [Violation Risk Factor:
Lower] [Time Horizon: Long-term Planning]
Page 1 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
M1. Each Planning Coordinator, in conjunction with its Transmission Planners, shall provide
documentation on roles and responsibilities, such as meeting minutes, agreements,
copies of procedures or protocols in effect between entities or between departments
of a vertically integrated system, or email correspondence that identifies an
agreement has been reached on individual and joint responsibilities for maintaining
models, performing the study or studies needed to complete benchmark and
supplemental GMD Vulnerability Assessments, and implementing process(es) to
obtain GMD measurement data in accordance with Requirement R1.
R2. Each responsible entity, as determined in Requirement R1, shall maintain System
models and GIC System models of the responsible entity’s planning area for
performing the study or studies needed to complete benchmark and supplemental
GMD Vulnerability Assessments. [Violation Risk Factor: High] [Time Horizon: Longterm Planning]
M2. Each responsible entity, as determined in Requirement R1, shall have evidence in
either electronic or hard copy format that it is maintaining System models and GIC
System models of the responsible entity’s planning area for performing the study or
studies needed to complete benchmark and supplemental GMD Vulnerability
Assessments.
R3. Each responsible entity, as determined in Requirement R1, shall have criteria for
acceptable System steady state voltage performance for its System during the GMD
events described in Attachment 1. [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]
M3. Each responsible entity, as determined in Requirement R1, shall have evidence, such
as electronic or hard copies of the criteria for acceptable System steady state voltage
performance for its System in accordance with Requirement R3.
Benchmark GMD Vulnerability Assessment(s)
R4. Each responsible entity, as determined in Requirement R1, shall complete a
benchmark GMD Vulnerability Assessment of the Near-Term Transmission Planning
Horizon at least once every 60 calendar months. This benchmark GMD Vulnerability
Assessment shall use a study or studies based on models identified in Requirement R2,
document assumptions, and document summarized results of the steady state
analysis. [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
4.1. The study or studies shall include the following conditions:
4.1.1. System On-Peak Load for at least one year within the Near-Term
Transmission Planning Horizon; and
4.1.2. System Off-Peak Load for at least one year within the Near-Term
Transmission Planning Horizon.
Page 2 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
4.2. The study or studies shall be conducted based on the benchmark GMD event
described in Attachment 1 to determine whether the System meets the
performance requirements for the steady state planning benchmark GMD event
contained in Table 1.
4.3. The benchmark GMD Vulnerability Assessment shall be provided: (i) to the
responsible entity’s Reliability Coordinator, adjacent Planning Coordinators, and
adjacent Transmission Planners within 90 calendar days of completion, and (ii) to
any functional entity that submits a written request and has a reliability-related
need within 90 calendar days of receipt of such request or within 90 calendar
days of completion of the benchmark GMD Vulnerability Assessment, whichever
is later.
4.3.1. If a recipient of the benchmark GMD Vulnerability Assessment provides
documented comments on the results, the responsible entity shall
provide a documented response to that recipient within 90 calendar days
of receipt of those comments.
M4. Each responsible entity, as determined in Requirement R1, shall have dated evidence
such as electronic or hard copies of its benchmark GMD Vulnerability Assessment
meeting all of the requirements in Requirement R4. Each responsible entity, as
determined in Requirement R1, shall also provide evidence, such as email records,
web postings with an electronic notice of posting, or postal receipts showing recipient
and date, that it has distributed its benchmark GMD Vulnerability Assessment: (i) to
the responsible entity’s Reliability Coordinator, adjacent Planning Coordinators, and
adjacent Transmission Planners within 90 calendar days of completion, and (ii) to any
functional entity that submits a written request and has a reliability-related need
within 90 calendar days of receipt of such request or within 90 calendar days of
completion of the benchmark GMD Vulnerability Assessment, whichever is later, as
specified in Requirement R4. Each responsible entity, as determined in Requirement
R1, shall also provide evidence, such as email notices or postal receipts showing
recipient and date, that it has provided a documented response to comments received
on its benchmark GMD Vulnerability Assessment within 90 calendar days of receipt of
those comments in accordance with Requirement R4.
R5. Each responsible entity, as determined in Requirement R1, shall provide GIC flow
information to be used for the benchmark thermal impact assessment of transformers
specified in Requirement R6 to each Transmission Owner and Generator Owner that
owns an applicable Bulk Electric System (BES) power transformer in the planning area.
The GIC flow information shall include: [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]
5.1. The maximum effective GIC value for the worst case geoelectric field orientation
for the benchmark GMD event described in Attachment 1. This value shall be
provided to the Transmission Owner or Generator Owner that owns each
applicable BES power transformer in the planning area.
Page 3 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
5.2. The effective GIC time series, GIC(t), calculated using the benchmark GMD event
described in Attachment 1 in response to a written request from the
Transmission Owner or Generator Owner that owns an applicable BES power
transformer in the planning area. GIC(t) shall be provided within 90 calendar
days of receipt of the written request and after determination of the maximum
effective GIC value in Part 5.1.
M5. Each responsible entity, as determined in Requirement R1, shall provide evidence,
such as email records, web postings with an electronic notice of posting, or postal
receipts showing recipient and date, that it has provided the maximum effective GIC
values to the Transmission Owner and Generator Owner that owns each applicable
BES power transformer in the planning area as specified in Requirement R5, Part 5.1.
Each responsible entity, as determined in Requirement R1, shall also provide evidence,
such as email records, web postings with an electronic notice of posting, or postal
receipts showing recipient and date, that it has provided GIC(t) in response to a
written request from the Transmission Owner or Generator Owner that owns an
applicable BES power transformer in the planning area.
R6. Each Transmission Owner and Generator Owner shall conduct a benchmark thermal
impact assessment for its solely and jointly owned applicable BES power transformers
where the maximum effective GIC value provided in Requirement R5, Part 5.1, is 75 A
per phase or greater. The benchmark thermal impact assessment shall: [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]
6.1. Be based on the effective GIC flow information provided in Requirement R5;
6.2. Document assumptions used in the analysis;
6.3. Describe suggested actions and supporting analysis to mitigate the impact of
GICs, if any; and
6.4. Be performed and provided to the responsible entities, as determined in
Requirement R1, within 24 calendar months of receiving GIC flow information
specified in Requirement R5, Part 5.1.
M6. Each Transmission Owner and Generator Owner shall have evidence such as electronic
or hard copies of its benchmark thermal impact assessment for all of its solely and
jointly owned applicable BES power transformers where the maximum effective GIC
value provided in Requirement R5, Part 5.1, is 75 A per phase or greater, and shall
have evidence such as email records, web postings with an electronic notice of
posting, or postal receipts showing recipient and date, that it has provided its thermal
impact assessment to the responsible entities as specified in Requirement R6.
R7.
Each responsible entity, as determined in Requirement R1, that concludes through
the benchmark GMD Vulnerability Assessment conducted in Requirement R4 that
their System does not meet the performance requirements for the steady state
planning benchmark GMD event contained in Table 1, shall develop a Corrective
Page 4 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Action Plan (CAP) addressing how the performance requirements will be met. The CAP
shall: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
7.1. List System deficiencies and the associated actions needed to achieve required
System performance. Examples of such actions include:
•
Installation, modification, retirement, or removal of Transmission and
generation Facilities and any associated equipment.
•
Installation, modification, or removal of Protection Systems or Remedial
Action Schemes.
•
Use of Operating Procedures, specifying how long they will be needed as
part of the CAP.
•
Use of Demand-Side Management, new technologies, or other initiatives.
7.2. Be developed within one year of completion of the benchmark GMD
Vulnerability Assessment.
7.3. Include a timetable, subject to approval for any extension sought under Part 7.4,
for implementing the selected actions from Part 7.1. The timetable shall:
7.3.1. Specify implementation of non-hardware mitigation, if any, within two
years of development of the CAP; and
7.3.2. Specify implementation of hardware mitigation, if any, within four years
of development of the CAP.
7.4. Be submitted to the Compliance Enforcement Authority (CEA) with a request for
extension of time if the responsible entity is unable to implement the CAP within
the timetable provided in Part 7.3. The submitted CAP shall document the
following:
7.4.1. Circumstances causing the delay for fully or partially implementing the
selected actions in Part 7.1 and how those circumstances are beyond the
control of the responsible entity;
7.4.2. Revisions to the selected actions in Part 7.1, if any, including utilization of
Operating Procedures, if applicable; and
7.4.3. Updated timetable for implementing the selected actions in Part 7.1.
7.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent
Planning Coordinator(s), adjacent Transmission Planner(s), and functional
entities referenced in the CAP within 90 calendar days of development or
revision, and (ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later.
Page 5 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
7.5.1. If a recipient of the CAP provides documented comments on the CAP, the
responsible entity shall provide a documented response to that recipient
within 90 calendar days of receipt of those comments.
M7. Each responsible entity, as determined in Requirement R1, that concludes, through
the benchmark GMD Vulnerability Assessment conducted in Requirement R4, that the
responsible entity’s System does not meet the performance requirements for the
steady state planning benchmark GMD event contained in Table 1 shall have evidence
such as dated electronic or hard copies of its CAP including timetable for
implementing selected actions, as specified in Requirement R7. Each responsible
entity, as determined in Requirement R1, shall also provide evidence, such as email
records or postal receipts showing recipient and date, that it submitted a request for
extension to the CEA if the responsible entity is unable to implement the CAP within
the timetable provided in Part 7.3. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records, web postings with
an electronic notice of posting, or postal receipts showing recipient and date, that it
has distributed its CAP or relevant information, if any, (i) to the responsible entity’s
Reliability Coordinator, adjacent Planning Coordinator(s), adjacent Transmission
Planner(s), and functional entities referenced in the CAP within 90 calendar days of
development or revision, and (ii) to any functional entity that submits a written
request and has a reliability-related need within 90 calendar days of receipt of such
request or within 90 calendar days of development or revision, whichever is later as
specified in Requirement R7. Each responsible entity, as determined in Requirement
R1, shall also provide evidence, such as email notices or postal receipts showing
recipient and date, that it has provided a documented response to comments received
on its CAP within 90 calendar days of receipt of those comments, in accordance with
Requirement R7.
Supplemental GMD Vulnerability Assessment(s)
R8.
Each responsible entity, as determined in Requirement R1, shall complete a
supplemental GMD Vulnerability Assessment of the Near-Term Transmission Planning
Horizon at least once every 60 calendar months. This supplemental GMD Vulnerability
Assessment shall use a study or studies based on models identified in Requirement
R2, document assumptions, and document summarized results of the steady state
analysis. [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
8.1. The study or studies shall include the following conditions:
8.1.1. System On-Peak Load for at least one year within the Near-Term
Transmission Planning Horizon; and
8.1.2. System Off-Peak Load for at least one year within the Near-Term
Transmission Planning Horizon.
Page 6 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
8.2. The study or studies shall be conducted based on the supplemental GMD event
described in Attachment 1 to determine whether the System meets the
performance requirements for the steady state planning supplemental GMD
event contained in Table 1.
8.3. The supplemental GMD Vulnerability Assessment shall be provided: (i) to the
responsible entity’s Reliability Coordinator, adjacent Planning Coordinators,
adjacent Transmission Planners within 90 calendar days of completion, and (ii) to
any functional entity that submits a written request and has a reliability-related
need within 90 calendar days of receipt of such request or within 90 calendar
days of completion of the supplemental GMD Vulnerability Assessment,
whichever is later.
8.3.1. If a recipient of the supplemental GMD Vulnerability Assessment
provides documented comments on the results, the responsible entity
shall provide a documented response to that recipient within 90 calendar
days of receipt of those comments.
M8. Each responsible entity, as determined in Requirement R1, shall have dated evidence
such as electronic or hard copies of its supplemental GMD Vulnerability Assessment
meeting all of the requirements in Requirement R8. Each responsible entity, as
determined in Requirement R1, shall also provide evidence, such as email records,
web postings with an electronic notice of posting, or postal receipts showing recipient
and date, that it has distributed its supplemental GMD Vulnerability Assessment: (i) to
the responsible entity’s Reliability Coordinator, adjacent Planning Coordinators,
adjacent Transmission Planners within 90 calendar days of completion, and (ii) to any
functional entity that submits a written request and has a reliability-related need
within 90 calendar days of receipt of such request or within 90 calendar days of
completion of the supplemental GMD Vulnerability Assessment, whichever is later, as
specified in Requirement R8. Each responsible entity, as determined in Requirement
R1, shall also provide evidence, such as email notices or postal receipts showing
recipient and date, that it has provided a documented response to comments
received on its supplemental GMD Vulnerability Assessment within 90 calendar days
of receipt of those comments in accordance with Requirement R8.
R9.
Each responsible entity, as determined in Requirement R1, shall provide GIC flow
information to be used for the supplemental thermal impact assessment of
transformers specified in Requirement R10 to each Transmission Owner and
Generator Owner that owns an applicable Bulk Electric System (BES) power
transformer in the planning area. The GIC flow information shall include: [Violation
Risk Factor: Medium] [Time Horizon: Long-term Planning]
9.1. The maximum effective GIC value for the worst case geoelectric field orientation
for the supplemental GMD event described in Attachment 1. This value shall be
provided to the Transmission Owner or Generator Owner that owns each
applicable BES power transformer in the planning area.
Page 7 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
9.2. The effective GIC time series, GIC(t), calculated using the supplemental GMD
event described in Attachment 1 in response to a written request from the
Transmission Owner or Generator Owner that owns an applicable BES power
transformer in the planning area. GIC(t) shall be provided within 90 calendar
days of receipt of the written request and after determination of the maximum
effective GIC value in Part 9.1.
M9. Each responsible entity, as determined in Requirement R1, shall provide evidence,
such as email records, web postings with an electronic notice of posting, or postal
receipts showing recipient and date, that it has provided the maximum effective GIC
values to the Transmission Owner and Generator Owner that owns each applicable
BES power transformer in the planning area as specified in Requirement R9, Part 9.1.
Each responsible entity, as determined in Requirement R1, shall also provide
evidence, such as email records, web postings with an electronic notice of posting, or
postal receipts showing recipient and date, that it has provided GIC(t) in response to a
written request from the Transmission Owner or Generator Owner that owns an
applicable BES power transformer in the planning area.
R10. Each Transmission Owner and Generator Owner shall conduct a supplemental
thermal impact assessment for its solely and jointly owned applicable BES power
transformers where the maximum effective GIC value provided in Requirement R9,
Part 9.1, is 85 A per phase or greater. The supplemental thermal impact assessment
shall: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
10.1. Be based on the effective GIC flow information provided in Requirement R9;
10.2. Document assumptions used in the analysis;
10.3. Describe suggested actions and supporting analysis to mitigate the impact of
GICs, if any; and
10.4. Be performed and provided to the responsible entities, as determined in
Requirement R1, within 24 calendar months of receiving GIC flow information
specified in Requirement R9, Part 9.1.
M10. Each Transmission Owner and Generator Owner shall have evidence such as
electronic or hard copies of its supplemental thermal impact assessment for all of its
solely and jointly owned applicable BES power transformers where the maximum
effective GIC value provided in Requirement R9, Part 9.1, is 85 A per phase or greater,
and shall have evidence such as email records, web postings with an electronic notice
of posting, or postal receipts showing recipient and date, that it has provided its
supplemental thermal impact assessment to the responsible entities as specified in
Requirement R10.
R11. Each responsible entity, as determined in Requirement R1, that concludes through
the supplemental GMD Vulnerability Assessment conducted in Requirement R8 that
their System does not meet the performance requirements for the steady state
planning supplemental GMD event contained in Table 1, shall develop a Corrective
Page 8 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Action Plan (CAP) addressing how the performance requirements will be met. The CAP
shall: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
11.1. List System deficiencies and the associated actions needed to achieve required
System performance. Examples of such actions include:
•
Installation, modification, retirement, or removal of Transmission and
generation Facilities and any associated equipment.
•
Installation, modification, or removal of Protection Systems or Remedial
Action Schemes.
•
Use of Operating Procedures, specifying how long they will be needed as
part of the CAP.
•
Use of Demand-Side Management, new technologies, or other initiatives.
11.2. Be developed within one year of completion of the supplemental GMD
Vulnerability Assessment.
11.3. Include a timetable, subject to approval for any extension sought under Part
11.4, for implementing the selected actions from Part 11.1. The timetable shall:
11.3.1. Specify implementation of non-hardware mitigation, if any, within two
years of development of the CAP; and
11.3.2. Specify implementation of hardware mitigation, if any, within four years
of development of the CAP.
11.4. Be submitted to the CEA with a request for extension of time if the responsible
entity is unable to implement the CAP within the timetable provided in Part 11.3.
The submitted CAP shall document the following:
11.4.1. Circumstances causing the delay for fully or partially implementing the
selected actions in Part 11.1 and how those circumstances are beyond
the control of the responsible entity;
11.4.2. Revisions to the selected actions in Part 11.1, if any, including utilization
of Operating Procedures, if applicable; and
11.4.3. Updated timetable for implementing the selected actions in Part 11.1.
11.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent
Planning Coordinator(s), adjacent Transmission Planner(s), and functional
entities referenced in the CAP within 90 calendar days of development or
revision, and (ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later.
11.5.1. If a recipient of the CAP provides documented comments on the CAP, the
responsible entity shall provide a documented response to that recipient
within 90 calendar days of receipt of those comments.
Page 9 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
M11. Each responsible entity, as determined in Requirement R1, that concludes, through
the supplemental GMD Vulnerability Assessment conducted in Requirement R8, that
the responsible entity’s System does not meet the performance requirements for the
steady state planning supplemental GMD event contained in Table 1 shall have
evidence such as dated electronic or hard copies of its CAP including timetable for
implementing selected actions, as specified in Requirement R11. Each responsible
entity, as determined in Requirement R1, shall also provide evidence, such as email
records or postal receipts showing recipient and date, that it submitted a request for
extension to the CEA if the responsible entity is unable to implement the CAP within
the timetable provided in Part 11.3. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records, web postings with
an electronic notice of posting, or postal receipts showing recipient and date, that it
has distributed its CAP or relevant information, if any, (i) to the responsible entity’s
Reliability Coordinator, adjacent Planning Coordinator(s), adjacent Transmission
Planner(s), and functional entities referenced in the CAP within 90 calendar days of
development or revision, and (ii) to any functional entity that submits a written
request and has a reliability-related need within 90 calendar days of receipt of such
request or within 90 calendar days of development or revision, whichever is later as
specified in Requirement R11. Each responsible entity, as determined in Requirement
R1, shall also provide evidence, such as email notices or postal receipts showing
recipient and date, that it has provided a documented response to comments received
on its CAP within 90 calendar days of receipt of those comments, in accordance with
Requirement R11.
GMD Measurement Data Processes
R12. Each responsible entity, as determined in Requirement R1, shall implement a process
to obtain GIC monitor data from at least one GIC monitor located in the Planning
Coordinator’s planning area or other part of the system included in the Planning
Coordinator’s GIC System model. [Violation Risk Factor: Lower] [Time Horizon: Longterm Planning]
M12. Each responsible entity, as determined in Requirement R1, shall have evidence such
as electronic or hard copies of its GIC monitor location(s) and documentation of its
process to obtain GIC monitor data in accordance with Requirement R12.
R13. Each responsible entity, as determined in Requirement R1, shall implement a process
to obtain geomagnetic field data for its Planning Coordinator’s planning area.
[Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
M13. Each responsible entity, as determined in Requirement R1, shall have evidence such
as electronic or hard copies of its process to obtain geomagnetic field data for its
Planning Coordinator’s planning area in accordance with Requirement R13.
C. Compliance
1.
Compliance Monitoring Process
Page 10 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
Authority may ask an entity to provide other evidence to show that it was
compliant for the full-time period since the last audit.
The applicable entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
•
For Requirements R1, R2, R3, R5, R6, R9, and R10, each responsible entity
shall retain documentation as evidence for five years.
•
For Requirements R4 and R8, each responsible entity shall retain
documentation of the current GMD Vulnerability Assessment and the
preceding GMD Vulnerability Assessment.
•
For Requirement R7 and R11, each responsible entity shall retain
documentation as evidence for five years or until all actions in the
Corrective Action Plan are completed, whichever is later.
•
For Requirements R12 and R13, each responsible entity shall retain
documentation as evidence for three years.
1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.
Page 11 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Table 1: Steady State Planning GMD Event
Steady State:
a. Voltage collapse, Cascading and uncontrolled islanding shall not occur.
b. Generation loss is acceptable as a consequence of the steady state planning GMD events.
c. Planned System adjustments such as Transmission configuration changes and re-dispatch of generation are allowed if such
adjustments are executable within the time duration applicable to the Facility Ratings.
Category
Initial Condition
Event
Interruption of
Firm
Transmission
Service Allowed
Load Loss
Allowed
Benchmark GMD
Event – GMD
Event with
Outages
1. System as may be
postured in response
to space weather
information1, and then
2. GMD event2
Reactive Power compensation devices
and other Transmission Facilities
removed as a result of Protection
System operation or Misoperation due
to harmonics during the GMD event
Yes3
Yes3
Supplemental
GMD Event – GMD
Event with
Outages
1. System as may be
postured in response
to space weather
information1, and then
2. GMD event2
Reactive Power compensation devices
and other Transmission Facilities
removed as a result of Protection
System operation or Misoperation due
to harmonics during the GMD event
Yes
Yes
Table 1: Steady State Performance Footnotes
1. The System condition for GMD planning may include adjustments to posture the System that are executable in response to
space weather information.
2. The GMD conditions for the benchmark and supplemental planning events are described in Attachment 1.
3. Load loss as a result of manual or automatic Load shedding (e.g., UVLS) and/or curtailment of Firm Transmission Service may
be used to meet BES performance requirements during studied GMD conditions. The likelihood and magnitude of Load loss or
curtailment of Firm Transmission Service should be minimized.
Page 12 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
R1.
R2.
Lower VSL
N/A
N/A
Violation Severity Levels
Moderate VSL
N/A
N/A
High VSL
Severe VSL
N/A
The Planning Coordinator, in
conjunction with its
Transmission Planner(s),
failed to determine and
identify individual or joint
responsibilities of the
Planning Coordinator and
Transmission Planner(s) in
the Planning Coordinator’s
planning area for
maintaining models,
performing the study or
studies needed to complete
benchmark and
supplemental GMD
Vulnerability Assessments,
and implementing
process(es) to obtain GMD
measurement data as
specified in this standard.
The responsible entity did
not maintain either System
models or GIC System
models of the responsible
entity’s planning area for
performing the studies
The responsible entity did
not maintain both System
models and GIC System
models of the responsible
entity’s planning area for
performing the studies
Page 13 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
needed to complete
benchmark and
supplemental GMD
Vulnerability Assessments.
R3.
R4.
N/A
N/A
N/A
The responsible entity
completed a benchmark
GMD Vulnerability
Assessment, but it was more
than 60 calendar months
and less than or equal to 64
calendar months since the
last benchmark GMD
Vulnerability Assessment.
The responsible entity’s
completed benchmark GMD
Vulnerability Assessment
failed to satisfy one of the
elements listed in
Requirement R4, Parts 4.1
through 4.3;
OR
The responsible entity
completed a benchmark
GMD Vulnerability
Assessment, but it was more
than 64 calendar months
and less than or equal to 68
calendar months since the
The responsible entity’s
completed benchmark GMD
Vulnerability Assessment
failed to satisfy two of the
elements listed in
Requirement R4, Parts 4.1
through 4.3;
OR
The responsible entity
completed a benchmark
GMD Vulnerability
Assessment, but it was more
than 68 calendar months
and less than or equal to 72
calendar months since the
Severe VSL
needed to complete
benchmark and
supplemental GMD
Vulnerability Assessments.
The responsible entity did
not have criteria for
acceptable System steady
state voltage performance
for its System during the
GMD events described in
Attachment 1 as required.
The responsible entity’s
completed benchmark GMD
Vulnerability Assessment
failed to satisfy three of the
elements listed in
Requirement R4, Parts 4.1
through 4.3;
OR
The responsible entity
completed a benchmark
GMD Vulnerability
Assessment, but it was more
than 72 calendar months
since the last benchmark
Page 14 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
R5.
R6.
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
last benchmark GMD
Vulnerability Assessment.
last benchmark GMD
Vulnerability Assessment.
GMD Vulnerability
Assessment;
OR
The responsible entity does
not have a completed
benchmark GMD
Vulnerability Assessment.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 90
calendar days and less than
or equal to 100 calendar
days after receipt of a
written request.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 100
calendar days and less than
or equal to 110 calendar
days after receipt of a
written request.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 110
calendar days after receipt
of a written request.
The responsible entity did
not provide the maximum
effective GIC value to the
Transmission Owner and
Generator Owner that owns
each applicable BES power
transformer in the planning
area;
OR
The responsible entity did
not provide the effective GIC
time series, GIC(t), upon
written request.
The responsible entity failed
to conduct a benchmark
thermal impact assessment
for 5% or less or one of its
solely owned and jointly
owned applicable BES power
The responsible entity failed
to conduct a benchmark
thermal impact assessment
for more than 5% up to (and
including) 10% or two of its
solely owned and jointly
The responsible entity failed
to conduct a benchmark
thermal impact assessment
for more than 10% up to
(and including) 15% or three
of its solely owned and
The responsible entity failed
to conduct a benchmark
thermal impact assessment
for more than 15% or more
than three of its solely
owned and jointly owned
Page 15 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase;
OR
The responsible entity
conducted a benchmark
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase
but did so more than 24
calendar months and less
than or equal to 26 calendar
months of receiving GIC flow
information specified in
Requirement R5, Part 5.1.
owned applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase;
OR
The responsible entity
conducted a benchmark
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase
but did so more than 26
calendar months and less
than or equal to 28 calendar
months of receiving GIC flow
information specified in
Requirement R5, Part 5.1;
OR
The responsible entity failed
to include one of the
jointly owned applicable BES
power transformers
(whichever is greater) where
the maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase;
OR
The responsible entity
conducted a benchmark
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase
but did so more than 28
calendar months and less
than or equal to 30 calendar
months of receiving GIC flow
information specified in
Requirement R5, Part 5.1;
OR
The responsible entity failed
to include two of the
applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase;
OR
The responsible entity
conducted a benchmark
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase
but did so more than 30
calendar months of receiving
GIC flow information
specified in Requirement R5,
Part 5.1;
OR
The responsible entity failed
to include three of the
required elements as listed
Page 16 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
required elements as listed
in Requirement R6, Parts 6.1
through 6.3.
required elements as listed
in Requirement R6, Parts 6.1
through 6.3.
in Requirement R6, Parts 6.1
through 6.3.
The responsible entity’s
Corrective Action Plan failed
to comply with one of the
elements in Requirement
R7, Parts 7.1 through 7.5.
The responsible entity’s
Corrective Action Plan failed
to comply with two of the
elements in Requirement R7,
Parts 7.1 through 7.5.
The responsible entity’s
Corrective Action Plan failed
to comply with three of the
elements in Requirement
R7, Parts 7.1 through 7.5.
The responsible entity’s
Corrective Action Plan failed
to comply with four or more
of the elements in
Requirement R7, Parts 7.1
through 7.5;
OR
The responsible entity did
not develop a Corrective
Action Plan as required by
Requirement R7.
The responsible entity
completed a supplemental
GMD Vulnerability
Assessment, but it was more
than 60 calendar months
and less than or equal to 64
calendar months since the
last supplemental GMD
Vulnerability Assessment.
The responsible entity’s
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
one of the elements listed in
Requirement R8, Parts 8.1
through 8.3;
OR
The responsible entity
completed a supplemental
GMD Vulnerability
Assessment, but it was more
The responsible entity’s
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
two of the elements listed in
Requirement R8, Parts 8.1
through 8.3;
OR
The responsible entity
completed a supplemental
GMD Vulnerability
Assessment, but it was more
The responsible entity’s
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
three of the elements listed
in Requirement R8, Parts 8.1
through 8.3;
OR
The responsible entity
completed a supplemental
GMD Vulnerability
Assessment, but it was more
R7.
R8.
Page 17 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
R9.
R10.
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
than 64 calendar months
and less than or equal to 68
calendar months since the
last supplemental GMD
Vulnerability Assessment.
than 68 calendar months
and less than or equal to 72
calendar months since the
last supplemental GMD
Vulnerability Assessment.
than 72 calendar months
since the last supplemental
GMD Vulnerability
Assessment;
OR
The responsible entity does
not have a completed
supplemental GMD
Vulnerability Assessment.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 90
calendar days and less than
or equal to 100 calendar
days after receipt of a
written request.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 100
calendar days and less than
or equal to 110 calendar
days after receipt of a
written request.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 110
calendar days after receipt
of a written request.
The responsible entity did
not provide the maximum
effective GIC value to the
Transmission Owner and
Generator Owner that owns
each applicable BES power
transformer in the planning
area;
OR
The responsible entity did
not provide the effective GIC
time series, GIC(t), upon
written request.
The responsible entity failed
to conduct a supplemental
thermal impact assessment
for 5% or less or one of its
The responsible entity failed
to conduct a supplemental
thermal impact assessment
for more than 5% up to (and
The responsible entity failed
to conduct a supplemental
thermal impact assessment
for more than 10% up to
The responsible entity failed
to conduct a supplemental
thermal impact assessment
for more than 15% or more
Page 18 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
solely owned and jointly
owned applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase;
OR
The responsible entity
conducted a supplemental
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase
but did so more than 24
calendar months and less
than or equal to 26 calendar
months of receiving GIC flow
information specified in
Requirement R9, Part 9.1.
including) 10% or two of its
solely owned and jointly
owned applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase;
OR
The responsible entity
conducted a supplemental
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase
but did so more than 26
calendar months and less
than or equal to 28 calendar
months of receiving GIC flow
information specified in
Requirement R9, Part 9.1
OR
(and including) 15% or three
of its solely owned and
jointly owned applicable BES
power transformers
(whichever is greater) where
the maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase;
OR
The responsible entity
conducted a supplemental
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase
but did so more than 28
calendar months and less
than or equal to 30 calendar
months of receiving GIC flow
information specified in
Requirement R9, Part 9.1;
OR
than three of its solely
owned and jointly owned
applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase;
OR
The responsible entity
conducted a supplemental
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase
but did so more than 30
calendar months of receiving
GIC flow information
specified in Requirement R9,
Part 9.1;
OR
Page 19 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
R11.
Violation Severity Levels
Lower VSL
The responsible entity’s
Corrective Action Plan failed
to comply with one of the
elements in Requirement
R11, Parts 11.1 through
11.5.
Moderate VSL
High VSL
Severe VSL
The responsible entity failed
to include one of the
required elements as listed
in Requirement R10, Parts
10.1 through 10.3.
The responsible entity failed
to include two of the
required elements as listed
in Requirement R10, Parts
10.1 through 10.3.
The responsible entity failed
to include three of the
required elements as listed
in Requirement R10, Parts
10.1 through 10.3.
The responsible entity’s
Corrective Action Plan failed
to comply with three of the
elements in Requirement
R11, Parts 11.1 through
11.5.
The responsible entity’s
Corrective Action Plan failed
to comply with four or more
of the elements in
Requirement R11, Parts 11.1
through 11.5;
OR
The responsible entity did
not develop a Corrective
Action Plan as required by
Requirement R11.
The responsible entity’s
Corrective Action Plan failed
to comply with two of the
elements in Requirement
R11, Parts 11.1 through
11.5.
Page 20 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
R12.
R13.
Violation Severity Levels
Lower VSL
N/A
N/A
Moderate VSL
N/A
N/A
High VSL
N/A
N/A
Severe VSL
The responsible entity did
not implement a process to
obtain GIC monitor data
from at least one GIC
monitor located in the
Planning Coordinator’s
planning area or other part
of the system included in the
Planning Coordinator’s GIC
System Model.
The responsible entity did
not implement a process to
obtain geomagnetic field
data for its Planning
Coordinator’s planning area.
Page 21 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
D. Regional Variances
D.A. Regional Variance for Canadian Jurisdictions
This Variance shall be applicable in those Canadian jurisdictions where the Variance
has been approved for use by the applicable governmental authority or has otherwise
become effective in the jurisdiction.
This variance replaces all references to “Attachment 1” in the standard with
“Attachment 1 or Attachment 1-CAN.”
In addition, this Variance replaces Requirement R7, Part 7.3 through Part 7.5 and
Requirement R11, Part 11.3 through Part 11.5 with the following:
D.A.7.3. Include a timetable, subject to revision by the responsible entity in Part
D.A.7.4, for implementing the selected actions from Part 7.1. The timetable
shall:
D.A.7.3.1. Specify implementation of non-hardware mitigation, if any, within
two years of the later of the development of the CAP or receipt of
regulatory approvals, if required; and
D.A.7.3.2. Specify implementation of hardware mitigation, if any, within four
years of the later of the development of the CAP or receipt of
regulatory approvals, if required.
D.A.7.4. Be revised if the responsible entity is unable to implement the CAP within
the timetable for implementation provided in Part D.A.7.3. The revised CAP
shall document the following:
D.A.7.4.1 Circumstances causing the delay for fully or partially implementing the
selected actions in Part 7.1 and how those circumstances are beyond
the control of the responsible entity;
D.A.7.4.2 Revisions to the selected actions in Part 7.1, if any, including utilization
of Operating Procedures if applicable; and
D.A.7.4.3 Updated timetable for implementing the selected actions in Part 7.1.
D.A.7.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent
Planning Coordinator(s), adjacent Transmission Planner(s), and functional
entities referenced in the CAP within 90 calendar days of development or
revision, (ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later, and
(iii) to the Compliance Enforcement Authority or Applicable Governmental
Authority when revised under D.A.7.4 within 90 calendar days of revision.
D.A.7.5.1 If a recipient of the CAP provides documented comments on the CAP,
the responsible entity shall provide a documented response to that
recipient within 90 calendar days of receipt of those comments.
Page 22 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
D.A.M.7. Each responsible entity, as determined in Requirement R1, that concludes,
through the benchmark GMD Vulnerability Assessment conducted in
Requirement R4, that the responsible entity’s System does not meet the
performance requirements for the steady state planning benchmark GMD
event contained in Table 1 shall have evidence such as dated electronic or
hard copies of its CAP including timetable for implementing selected actions,
as specified in Requirement R7. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records or postal
receipts showing recipient and date, that it has revised its CAP if situations
beyond the responsible entity's control prevent implementation of the CAP
within the timetable specified. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records, web
postings with an electronic notice of posting, or postal receipts showing
recipient and date, that it has distributed its CAP or relevant information, if
any, (i) to the responsible entity’s Reliability Coordinator, adjacent Planning
Coordinator(s), adjacent Transmission Planner(s), and functional entities
referenced in the CAP within 90 calendar days of development or revision,
(ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later as
specified in Requirement R7, and (iii) to the Compliance Enforcement
Authority or Applicable Governmental Authority when revised under D.A.7.4
within 90 calendar days of revision. Each responsible entity, as determined
in Requirement R1, shall also provide evidence, such as email notices or
postal receipts showing recipient and date, that it has provided a
documented response to comments received on its CAP within 90 calendar
days of receipt of those comments, in accordance with Requirement R7.
D.A.11.3.Include a timetable, subject to revision by the responsible entity in Part
D.A.11.4, for implementing the selected actions from Part 11.1. The
timetable shall:
D.A.11.3.1. Specify implementation of non-hardware mitigation, if any, within
two years of the later of the development of the CAP or receipt of
regulatory approvals, if required; and
D.A.11.3.2. Specify implementation of hardware mitigation, if any, within four
years of the later of the development of the CAP or receipt of
regulatory approvals, if required.
D.A.11.4. Be revised if the responsible entity is unable to implement the CAP within
the timetable for implementation provided in Part D.A.11.3. The revised CAP
shall document the following:
D.A.11.4.1 Circumstances causing the delay for fully or partially implementing
the selected actions in Part 11.1 and how those circumstances are
beyond the control of the responsible entity;
Page 23 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
D.A.11.4.2 Revisions to the selected actions in Part 11.1, if any, including
utilization of Operating Procedures if applicable; and
D.A.11.4.3 Updated timetable for implementing the selected actions in Part
11.1.
D.A.11.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent
Planning Coordinator(s), adjacent Transmission Planner(s), and functional
entities referenced in the CAP within 90 calendar days of development or
revision, (ii) to any functional entity that submits a written request and has
a reliability-related need within 90 calendar days of receipt of such request
or within 90 calendar days of development or revision, whichever is later,
and (iii) to the Compliance Enforcement Authority or Applicable
Governmental Authority when revised under D.A.11.4 within 90 calendar
days of revision.
D.A.11.5.1. If a recipient of the CAP provides documented comments on the
CAP, the responsible entity shall provide a documented response to
that recipient within 90 calendar days of receipt of those comments.
Page 24 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
D.A.M.11. Each responsible entity, as determined in Requirement R1, that concludes,
through the supplemental GMD Vulnerability Assessment conducted in
Requirement R8, that the responsible entity’s System does not meet the
performance requirements for the steady state planning supplemental GMD
event contained in Table 1 shall have evidence such as dated electronic or
hard copies of its CAP including timetable for implementing selected actions,
as specified in Requirement R11. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records or postal
receipts showing recipient and date, that it has revised its CAP if situations
beyond the responsible entity's control prevent implementation of the CAP
within the timetable specified. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records, web
postings with an electronic notice of posting, or postal receipts showing
recipient and date, that it has distributed its CAP or relevant information, if
any, (i) to the responsible entity’s Reliability Coordinator, adjacent Planning
Coordinator(s), adjacent Transmission Planner(s), and functional entities
referenced in the CAP within 90 calendar days of development or revision,
(ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later as
specified in Requirement R11, and (iii) to the Compliance Enforcement
Authority or Applicable Governmental Authority when revised under
D.A.11.4 within 90 calendar days of revision. Each responsible entity, as
determined in Requirement R1, shall also provide evidence, such as email
notices or postal receipts showing recipient and date, that it has provided a
documented response to comments received on its CAP within 90 calendar
days of receipt of those comments, in accordance with Requirement R11.
Page 25 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
E. Associated Documents
Attachment 1
Attachment 1-CAN
Page 26 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Version History
Version
1
Date
Action
December 17, 2014 Adopted by the NERC Board of Trustees
Change
Tracking
New
Revised to
respond to
directives in FERC
Order No. 830.
2
November 9, 2017
Adopted by the NERC Board of Trustees
2
November 25, 2018
FERC Order issued approving TPL-007-2.
Docket No. RM18-8-000
3
February 7, 2019
Adopted by the NERC Board of Trustees
Canadian
Variance
Adopted by the NERC Board of Trustees
Revised to
respond to
directives in FERC
Order. 851
4
February 6, 2020
Page 27 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Attachment 1
Calculating Geoelectric Fields for the Benchmark and Supplemental GMD Events
The benchmark GMD event 1 defines the geoelectric field values used to compute GIC flows that
are needed to conduct a benchmark GMD Vulnerability Assessment. It is composed of the
following elements: (1) a reference peak geoelectric field amplitude of 8 V/km derived from
statistical analysis of historical magnetometer data; (2) scaling factors to account for local
geomagnetic latitude; (3) scaling factors to account for local earth conductivity; and (4) a
reference geomagnetic field time series or waveform to facilitate time-domain analysis of GMD
impact on equipment.
The supplemental GMD event is composed of similar elements as described above, except (1) the
reference peak geoelectric field amplitude is 12 V/km over a localized area; and (2) the
geomagnetic field time series or waveform includes a local enhancement in the waveform. 2
The regional geoelectric field peak amplitude used in GMD Vulnerability Assessment, Epeak, can
be obtained from the reference geoelectric field value of 8 V/km for the benchmark GMD event
(1) or 12 V/km for the supplemental GMD event (2) using the following relationships:
𝐸𝐸𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝 = 8 × 𝛼𝛼 × 𝛽𝛽 𝑏𝑏 (𝑉𝑉 ⁄𝑘𝑘𝑘𝑘)
𝐸𝐸𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝 = 12 × 𝛼𝛼 × 𝛽𝛽 𝑠𝑠 (𝑉𝑉 ⁄𝑘𝑘𝑘𝑘)
(1)
(2)
where, α is the scaling factor to account for local geomagnetic latitude, and β is a scaling factor
to account for the local earth conductivity structure. Subscripts b and s for the β scaling factor
denote association with the benchmark or supplemental GMD events, respectively.
Scaling the Geomagnetic Field
The benchmark and supplemental GMD events are defined for geomagnetic latitude of 60° and
must be scaled to account for regional differences based on geomagnetic latitude. Table 2
provides a scaling factor correlating peak geoelectric field to geomagnetic latitude. Alternatively,
the scaling factor α is computed with the empirical expression:
𝛼𝛼 = 0.001 × 𝑒𝑒 (0.115×𝐿𝐿)
(3)
where, L is the geomagnetic latitude in degrees and 0.1 ≤ α ≤ 1.
1 The Benchmark Geomagnetic Disturbance Event Description, May 2016 is available on the Related Information webpage for
TPL-007-1: http://www.nerc.com/pa/Stand/TPL0071RD/Benchmark_clean_May12_complete.pdf.
2 The extent of local enhancements is on the order of 100 km in North-South (latitude) direction but longer in East-West
(longitude) direction. The local enhancement in the geomagnetic field occurs over the time period of 2-5 minutes. Additional
information is available in the Supplemental Geomagnetic Disturbance Event Description, October 2017 white paper on the
Project 2013-03 Geomagnetic Disturbance Mitigation project webpage: http://www.nerc.com/pa/Stand/Pages/Project-201303-Geomagnetic-Disturbance-Mitigation.aspx.
Page 28 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
For large planning areas that cover more than one scaling factor from Table 2, the GMD
Vulnerability Assessment should be based on a peak geoelectric field that is:
•
calculated by using the most conservative (largest) value for α; or
•
calculated assuming a non-uniform or piecewise uniform geomagnetic field.
Table 2: Geomagnetic Field Scaling Factors for the
Benchmark and Supplemental GMD
Events
Geomagnetic Latitude
(Degrees)
Scaling Factor1
(α)
≤ 40
0.10
45
0.2
50
0.3
54
0.5
56
0.6
57
0.7
58
0.8
59
0.9
≥ 60
1.0
Scaling the Geoelectric Field
The benchmark GMD event is defined for the reference Quebec earth model described in Table
4. The peak geoelectric field, Epeak, used in a GMD Vulnerability Assessment may be obtained by
either:
•
Calculating the geoelectric field for the ground conductivity in the planning area and the
reference geomagnetic field time series scaled according to geomagnetic latitude, using
a procedure such as the plane wave method described in the NERC GMD Task Force GIC
Application Guide; 3 or
•
Using the earth conductivity scaling factor β from Table 3 that correlates to the ground
conductivity map in Figure 1 or Figure 2. Along with the scaling factor α from equation
(3) or Table 2, β is applied to the reference geoelectric field using equation (1 or 2, as
applicable) to obtain the regional geoelectric field peak amplitude Epeak to be used in
GMD Vulnerability Assessments. When a ground conductivity model is not available, the
responsible entity should use the largest β factor of adjacent physiographic regions or a
technically justified value.
Available at the NERC GMD Task Force project webpage: http://www.nerc.com/comm/PC/Pages/Geomagnetic-DisturbanceTask-Force-(GMDTF)-2013.aspx.
3
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
The earth models used to calculate Table 3 for the United States were obtained from publicly
available information published on the U. S. Geological Survey website. 4 The models used to
calculate Table 3 for Canada were obtained from Natural Resources Canada (NRCan) and reflect
the average structure for large regions. A planner can also use specific earth model(s) with
documented justification and the reference geomagnetic field time series to calculate the β
factor(s) as follows:
(4)
𝛽𝛽𝑏𝑏 = 𝐸𝐸 ⁄8 for the benchmark GMD event
(5)
𝛽𝛽𝑠𝑠 = 𝐸𝐸 ⁄12 for the supplemental GMD
where, E is the absolute value of peak geoelectric in V/km obtained from the technically justified
earth model and the reference geomagnetic field time series.
For large planning areas that span more than one β scaling factor, the most conservative (largest)
value for β may be used in determining the peak geoelectric field to obtain conservative results.
Alternatively, a planner could perform analysis using a non-uniform or piecewise uniform
geoelectric field.
Applying the Localized Peak Geoelectric Field in the Supplemental GMD Event
The peak geoelectric field of the supplemental GMD event occurs in a localized area. 5 Planners
have flexibility to determine how to apply the localized peak geoelectric field over the planning
area in performing GIC calculations. Examples of approaches are:
•
Apply the peak geoelectric field (12 V/km scaled to the planning area) over the entire
planning area;
•
Apply a spatially limited (12 V/km scaled to the planning area) peak geoelectric field (e.g.,
100 km in North-South latitude direction and 500 km in East-West longitude direction)
over a portion(s) of the system, and apply the benchmark GMD event over the rest of the
system; or
•
Other methods to adjust the benchmark GMD event analysis to account for the localized
geoelectric field enhancement of the supplemental GMD event.
Available at http://geomag.usgs.gov/conductivity/.
See the Supplemental Geomagnetic Disturbance Description white paper located on the Project 2013-03 Geomagnetic
Disturbance Mitigation project webpage: http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspx.
4
5
Page 30 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
FL-1
Figure 1: Physiographic Regions of the Continental United States 6
Figure 2: Physiographic Regions of Canada
6
Additional map detail is available at the U.S. Geological Survey: http://geomag.usgs.gov/.
Page 31 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Table 3: Geoelectric Field Scaling Factors
Earth model
Scaling Factor
Benchmark Event
(βb)
Scaling Factor
Supplemental
Event
(βs)
AK1A
0.56
0.51
AK1B
0.56
0.51
AP1
0.33
0.30
AP2
0.82
0.78
BR1
0.22
0.22
CL1
0.76
0.73
CO1
0.27
0.25
CP1
0.81
0.77
CP2
0.95
0.86
FL1
0.76
0.73
CS1
0.41
0.37
IP1
0.94
0.90
IP2
0.28
0.25
IP3
0.93
0.90
IP4
0.41
0.35
NE1
0.81
0.77
PB1
0.62
0.55
PB2
0.46
0.39
PT1
1.17
1.19
SL1
0.53
0.49
SU1
0.93
0.90
BOU
0.28
0.24
FBK
0.56
0.56
PRU
0.21
0.22
BC
0.67
0.62
PRAIRIES
0.96
0.88
SHIELD
1.0
1.0
ATLANTIC
0.79
0.76
Page 32 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Scaling factors in Table 3 are dependent upon the frequency content of the reference storm.
Consequently, the benchmark GMD event and the supplemental GMD event may produce
different scaling factors for a given earth model.
Table 4: Reference Earth Model (Quebec)
Layer Thickness (km)
Resistivity (Ω-m)
15
20,000
10
200
125
1,000
200
100
∞
3
Reference Geomagnetic Field Time Series or Waveform for the Benchmark GMD
Event 7
The geomagnetic field measurement record of the March 13-14 1989 GMD event, measured at
the NRCan Ottawa geomagnetic observatory, is the basis for the reference geomagnetic field
waveform to be used to calculate the GIC time series, GIC(t), required for transformer thermal
impact assessment.
The geomagnetic latitude of the Ottawa geomagnetic observatory is 55°; therefore, the
amplitudes of the geomagnetic field measurement data were scaled up to the 60° reference
geomagnetic latitude (see Figure 3) such that the resulting peak geoelectric field amplitude
computed using the reference earth model was 8 V/km (see Figures 4 and 5). The sampling rate
for the geomagnetic field waveform is 10 seconds. 8 To use this geoelectric field time series when
a different earth model is applicable, it should be scaled with the appropriate benchmark
conductivity scaling factor βb.
Refer to the Benchmark Geomagnetic Disturbance Event Description white paper for details on the determination of the
reference geomagnetic field waveform: http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx.
8 The data file of the benchmark geomagnetic field waveform is available on the Related Information webpage for TPL-007-1:
http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx.
7
Page 33 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Figure 3: Benchmark Geomagnetic Field Waveform
Red Bn (Northward), Blue Be (Eastward)
Figure 4: Benchmark Geoelectric Field Waveform
EE (Eastward)
Page 34 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Figure 5: Benchmark Geoelectric Field Waveform
EN (Northward)
Reference Geomagnetic Field Time Series or Waveform for the Supplemental GMD
Event 9
The geomagnetic field measurement record of the March 13-14, 1989 GMD event, measured at
the NRCan Ottawa geomagnetic observatory, is the basis for the reference geomagnetic field
waveform to be used to calculate the GIC time series, GIC(t), required for transformer thermal
impact assessment for the supplemental GMD event. The supplemental GMD event waveform
differs from the benchmark GMD event waveform in that the supplemental GMD event
waveform has a local enhancement.
The geomagnetic latitude of the Ottawa geomagnetic observatory is 55°; therefore, the
amplitudes of the geomagnetic field measurement data were scaled up to the 60° reference
geomagnetic latitude (see Figure 6) such that the resulting peak geoelectric field amplitude
computed using the reference earth model was 12 V/km (see Figure7). The sampling rate for the
geomagnetic field waveform is 10 seconds. 10 To use this geoelectric field time series when a
different earth model is applicable, it should be scaled with the appropriate supplemental
conductivity scaling factor βs.
Refer to the Supplemental Geomagnetic Disturbance Event Description white paper for details on the determination of the
reference geomagnetic field waveform: http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspx.
10 The data file of the benchmark geomagnetic field waveform is available on the NERC GMD Task Force project webpage:
http://www.nerc.com/comm/PC/Pages/Geomagnetic-Disturbance-Task-Force-(GMDTF)-2013.aspx.
9
Page 35 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
4000
2000
Time (min)
200
400
600
800
1000
1200
1400
1600
1800
2000
Bx, By (nT)
0
-2000
-4000
-6000
-8000
-10000
Figure 6: Supplemental Geomagnetic Field Waveform
Red BN (Northward), Blue BE (Eastward)
12 V/km
Figure 7: Supplemental Geoelectric Field Waveform
Blue EN (Northward), Red EE (Eastward)
Page 36 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Attachment 1-CAN
Attachment 1-CAN provides an alternative that a Canadian entity may use in lieu of the
benchmark or supplemental GMD event(s) defined in Attachment 1 for performing GMD
Vulnerability Assessment(s).
A Canadian entity may use the provisions of Attachment 1-CAN if it has regionally specific
information that provides a technically justified means to re-define a 1-in-100 year GMD
planning event(s) within its planning area.
Information for the Alternative Methodology
GMD Vulnerability Assessment(s) require the use of geophysical and engineering models.
Canadian-specific data is available and growing. Ongoing research allows for more accurate
characterization of regional parameters used in these models. Such Canadian-specific data
includes geomagnetic field, earth conductivity, and geomagnetically induced current
measurements that can be used for modeling and simulation validation.
Information used to calculate geoelectric fields for the benchmark and supplemental GMD events
shall be clearly documented and technically justified. For example, the factors involved in the
calculation of geoelectric fields are geomagnetic field variations and an earth transfer
function(s). 1 Technically justified information used in modelling geomagnetic field variations may
include: technical documents produced by governmental entities such as Natural Resources
Canada; technical papers published in peer-reviewed journals; and data sets gathered using
sound scientific principles. An earth transfer function may rely on magnetotelluric measurements
or earth conductivity models.
Modeling assumptions shall also be clearly documented and technically justified. An entity may
use sensitivity analysis to identify how the assumptions affect the results.
A simplified model may be used to perform a GMD Vulnerability Assessment(s), as long as the
model is more conservative than a more detailed model.
When interpreting assessment results, the entity shall consider the maturity of the modeling,
toolset, and techniques applied.
Geomagnetic Disturbance Planning Events
The 1-in-100 year planning event shall be based on regionally specific data and technically
justifiable statistical analyses (e.g., extreme value theory) and applied to the benchmark and
supplemental GMD Vulnerability Assessment(s).
For the benchmark GMD Vulnerability Assessment(s), an entity shall consider the large-scale
spatial structure of the GMD event. For the supplemental GMD Vulnerability Assessment(s), an
The “earth transfer function” is the relationship between the electric fields and magnetic field variations at the surface of the
earth.
1
Page 37 of 38
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
entity shall consider the small-scale spatial structure of the GMD event (e.g., using magnetometer
measurements or realistic electrojet calculations).
Page 38 of 38
Exhibit A2
Proposed Reliability Standard TPL-007-4 – Transmission
System Planned Performance for Geomagnetic Disturbance Operations
(Redline to TPL-007-3)
RELIABILITY | RESILIENCE | SECURITY
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
A. Introduction
1.
Title:
Events
Transmission System Planned Performance for Geomagnetic Disturbance
2.
Number:
TPL-007-34
3.
Purpose:
Establish requirements for Transmission system planned performance
during geomagnetic disturbance (GMD) events.
4.
Applicability:
4.1. Functional Entities:
4.1.1. Planning Coordinator with a planning area that includes a Facility or
Facilities specified in 4.2;
4.1.2. Transmission Planner with a planning area that includes a Facility or
Facilities specified in 4.2;
4.1.3. Transmission Owner who owns a Facility or Facilities specified in 4.2; and
4.1.4. Generator Owner who owns a Facility or Facilities specified in 4.2.
4.2. Facilities:
4.2.1. Facilities that include power transformer(s) with a high side, wyegrounded winding with terminal voltage greater than 200 kV.
5.
Effective Date: See Implementation Plan for TPL-007-34.
6.
Background: During a GMD event, geomagnetically-induced currents (GIC) may cause
transformer hot-spot heating or damage, loss of Reactive Power sources, increased
Reactive Power demand, and Misoperation(s), the combination of which may result in
voltage collapse and blackout.
The only difference between TPL-007-3 and TPL-007-2 is that TPL-007-3 adds a
Canadian Variance to address regulatory practices/processes within Canadian
jurisdictions and to allow the use of Canadian-specific data and research to define and
implement alternative GMD event(s) that achieve at least an equivalent reliability
objective of that in TPL-007-2.
C.B.
R1.
Requirements and Measures
Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall
identify the individual and joint responsibilities of the Planning Coordinator and
Transmission Planner(s) in the Planning Coordinator’s planning area for maintaining
models, performing the study or studies needed to complete benchmark and
supplemental GMD Vulnerability Assessments, and implementing process(es) to
obtain GMD measurement data as specified in this standard. [Violation Risk Factor:
Lower] [Time Horizon: Long-term Planning]
Page 1 of 50
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
M1. Each Planning Coordinator, in conjunction with its Transmission Planners, shall provide
documentation on roles and responsibilities, such as meeting minutes, agreements,
copies of procedures or protocols in effect between entities or between departments
of a vertically integrated system, or email correspondence that identifies an
agreement has been reached on individual and joint responsibilities for maintaining
models, performing the study or studies needed to complete benchmark and
supplemental GMD Vulnerability Assessments, and implementing process(es) to
obtain GMD measurement data in accordance with Requirement R1.
R2. Each responsible entity, as determined in Requirement R1, shall maintain System
models and GIC System models of the responsible entity’s planning area for
performing the study or studies needed to complete benchmark and supplemental
GMD Vulnerability Assessments. [Violation Risk Factor: High] [Time Horizon: Longterm Planning]
M2. Each responsible entity, as determined in Requirement R1, shall have evidence in
either electronic or hard copy format that it is maintaining System models and GIC
System models of the responsible entity’s planning area for performing the study or
studies needed to complete benchmark and supplemental GMD Vulnerability
Assessments.
R3. Each responsible entity, as determined in Requirement R1, shall have criteria for
acceptable System steady state voltage performance for its System during the GMD
events described in Attachment 1. [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]
M3. Each responsible entity, as determined in Requirement R1, shall have evidence, such
as electronic or hard copies of the criteria for acceptable System steady state voltage
performance for its System in accordance with Requirement R3.
Benchmark GMD Vulnerability Assessment(s)
R4. Each responsible entity, as determined in Requirement R1, shall complete a
benchmark GMD Vulnerability Assessment of the Near-Term Transmission Planning
Horizon at least once every 60 calendar months. This benchmark GMD Vulnerability
Assessment shall use a study or studies based on models identified in Requirement R2,
document assumptions, and document summarized results of the steady state
analysis. [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
4.1. The study or studies shall include the following conditions:
4.1.1. System On-Peak Load for at least one year within the Near-Term
Transmission Planning Horizon; and
4.1.2. System Off-Peak Load for at least one year within the Near-Term
Transmission Planning Horizon.
Page 2 of 50
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
4.2. The study or studies shall be conducted based on the benchmark GMD event
described in Attachment 1 to determine whether the System meets the
performance requirements for the steady state planning benchmark GMD event
contained in Table 1.
4.3. The benchmark GMD Vulnerability Assessment shall be provided: (i) to the
responsible entity’s Reliability Coordinator, adjacent Planning Coordinators, and
adjacent Transmission Planners within 90 calendar days of completion, and (ii) to
any functional entity that submits a written request and has a reliability-related
need within 90 calendar days of receipt of such request or within 90 calendar
days of completion of the benchmark GMD Vulnerability Assessment, whichever
is later.
4.3.1. If a recipient of the benchmark GMD Vulnerability Assessment provides
documented comments on the results, the responsible entity shall
provide a documented response to that recipient within 90 calendar days
of receipt of those comments.
M4. Each responsible entity, as determined in Requirement R1, shall have dated evidence
such as electronic or hard copies of its benchmark GMD Vulnerability Assessment
meeting all of the requirements in Requirement R4. Each responsible entity, as
determined in Requirement R1, shall also provide evidence, such as email records,
web postings with an electronic notice of posting, or postal receipts showing recipient
and date, that it has distributed its benchmark GMD Vulnerability Assessment: (i) to
the responsible entity’s Reliability Coordinator, adjacent Planning Coordinators, and
adjacent Transmission Planners within 90 calendar days of completion, and (ii) to any
functional entity that submits a written request and has a reliability-related need
within 90 calendar days of receipt of such request or within 90 calendar days of
completion of the benchmark GMD Vulnerability Assessment, whichever is later, as
specified in Requirement R4. Each responsible entity, as determined in Requirement
R1, shall also provide evidence, such as email notices or postal receipts showing
recipient and date, that it has provided a documented response to comments received
on its benchmark GMD Vulnerability Assessment within 90 calendar days of receipt of
those comments in accordance with Requirement R4.
R5. Each responsible entity, as determined in Requirement R1, shall provide GIC flow
information to be used for the benchmark thermal impact assessment of transformers
specified in Requirement R6 to each Transmission Owner and Generator Owner that
owns an applicable Bulk Electric System (BES) power transformer in the planning area.
The GIC flow information shall include: [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]
5.1. The maximum effective GIC value for the worst case geoelectric field orientation
for the benchmark GMD event described in Attachment 1. This value shall be
provided to the Transmission Owner or Generator Owner that owns each
applicable BES power transformer in the planning area.
Page 3 of 50
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
5.2. The effective GIC time series, GIC(t), calculated using the benchmark GMD event
described in Attachment 1 in response to a written request from the
Transmission Owner or Generator Owner that owns an applicable BES power
transformer in the planning area. GIC(t) shall be provided within 90 calendar
days of receipt of the written request and after determination of the maximum
effective GIC value in Part 5.1.
M5. Each responsible entity, as determined in Requirement R1, shall provide evidence,
such as email records, web postings with an electronic notice of posting, or postal
receipts showing recipient and date, that it has provided the maximum effective GIC
values to the Transmission Owner and Generator Owner that owns each applicable
BES power transformer in the planning area as specified in Requirement R5, Part 5.1.
Each responsible entity, as determined in Requirement R1, shall also provide evidence,
such as email records, web postings with an electronic notice of posting, or postal
receipts showing recipient and date, that it has provided GIC(t) in response to a
written request from the Transmission Owner or Generator Owner that owns an
applicable BES power transformer in the planning area.
R6. Each Transmission Owner and Generator Owner shall conduct a benchmark thermal
impact assessment for its solely and jointly owned applicable BES power transformers
where the maximum effective GIC value provided in Requirement R5, Part 5.1, is 75 A
per phase or greater. The benchmark thermal impact assessment shall: [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]
6.1. Be based on the effective GIC flow information provided in Requirement R5;
6.2. Document assumptions used in the analysis;
6.3. Describe suggested actions and supporting analysis to mitigate the impact of
GICs, if any; and
6.4. Be performed and provided to the responsible entities, as determined in
Requirement R1, within 24 calendar months of receiving GIC flow information
specified in Requirement R5, Part 5.1.
M6. Each Transmission Owner and Generator Owner shall have evidence such as electronic
or hard copies of its benchmark thermal impact assessment for all of its solely and
jointly owned applicable BES power transformers where the maximum effective GIC
value provided in Requirement R5, Part 5.1, is 75 A per phase or greater, and shall
have evidence such as email records, web postings with an electronic notice of
posting, or postal receipts showing recipient and date, that it has provided its thermal
impact assessment to the responsible entities as specified in Requirement R6.
R7.
Each responsible entity, as determined in Requirement R1, that concludes through
the benchmark GMD Vulnerability Assessment conducted in Requirement R4 that
their System does not meet the performance requirements for the steady state
planning benchmark GMD event contained in Table 1, shall develop a Corrective
Page 4 of 50
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Action Plan (CAP) addressing how the performance requirements will be met. The CAP
shall: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
7.1. List System deficiencies and the associated actions needed to achieve required
System performance. Examples of such actions include:
•
Installation, modification, retirement, or removal of Transmission and
generation Facilities and any associated equipment.
•
Installation, modification, or removal of Protection Systems or Remedial
Action Schemes.
•
Use of Operating Procedures, specifying how long they will be needed as
part of the CAP.
•
Use of Demand-Side Management, new technologies, or other initiatives.
7.2. Be developed within one year of completion of the benchmark GMD
Vulnerability Assessment.
7.3. Include a timetable, subject to revision by the responsible entity inapproval for
any extension sought under Part 7.4, for implementing the selected actions from
Part 7.1. The timetable shall:
7.3.1. Specify implementation of non-hardware mitigation, if any, within two
years of development of the CAP; and
7.3.2. Specify implementation of hardware mitigation, if any, within four years
of development of the CAP.
7.4. Be revised if situations beyondsubmitted to the controlCompliance Enforcement
Authority (CEA) with a request for extension of time if the responsible entity
determined in Requirement R1 prevent implementation ofis unable to
implement the CAP within the timetable for implementation provided in Part
7.3. The revisedsubmitted CAP shall document the following, and be updated at
least once every 12 calendar months until implemented:
7.4.1. Circumstances causing the delay for fully or partially implementing the
selected actions in Part 7.1 and how those circumstances are beyond the
control of the responsible entity;
7.4.2. Description of the original CAP, and any previous changes to the CAP,
with the associated timetable(s) for implementing the selected actions in
Part 7.1; and
7.4.3.7.4.2. Revisions to the selected actions in Part 7.1, if any, including
utilization of Operating Procedures, if applicable,; and the updated
timetable for implementing the selected actions.
7.4.3. Updated timetable for implementing the selected actions in Part 7.1.
Page 5 of 50
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
7.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent
Planning Coordinator(s), adjacent Transmission Planner(s), and functional
entities referenced in the CAP within 90 calendar days of development or
revision, and (ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later.
7.5.1. If a recipient of the CAP provides documented comments on the
resultsCAP, the responsible entity shall provide a documented response
to that recipient within 90 calendar days of receipt of those comments.
M7. Each responsible entity, as determined in Requirement R1, that concludes, through
the benchmark GMD Vulnerability Assessment conducted in Requirement R4, that the
responsible entity’s System does not meet the performance requirements for the
steady state planning benchmark GMD event contained in Table 1 shall have evidence
such as dated electronic or hard copies of its CAP including timetable for
implementing selected actions, as specified in Requirement R7. Each responsible
entity, as determined in Requirement R1, shall also provide evidence, such as email
records or postal receipts showing recipient and date, that it has revised its
CAPsubmitted a request for extension to the CEA if situations beyond the responsible
entity's control prevent implementation ofentity is unable to implement the CAP
within the timetable specified.provided in Part 7.3. Each responsible entity, as
determined in Requirement R1, shall also provide evidence, such as email records,
web postings with an electronic notice of posting, or postal receipts showing recipient
and date, that it has distributed its CAP or relevant information, if any, (i) to the
responsible entity’s Reliability Coordinator, adjacent Planning Coordinator(s), adjacent
Transmission Planner(s), and functional entities referenced in the CAP within 90
calendar days of development or revision, and (ii) to any functional entity that submits
a written request and has a reliability-related need within 90 calendar days of receipt
of such request or within 90 calendar days of development or revision, whichever is
later as specified in Requirement R7. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email notices or postal receipts
showing recipient and date, that it has provided a documented response to comments
received on its CAP within 90 calendar days of receipt of those comments, in
accordance with Requirement R7.
Supplemental GMD Vulnerability Assessment(s)
R8.
Each responsible entity, as determined in Requirement R1, shall complete a
supplemental GMD Vulnerability Assessment of the Near-Term Transmission Planning
Horizon at least once every 60 calendar months. This supplemental GMD Vulnerability
Assessment shall use a study or studies based on models identified in Requirement
R2, document assumptions, and document summarized results of the steady state
analysis. [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
8.1. The study or studies shall include the following conditions:
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8.1.1. System On-Peak Load for at least one year within the Near-Term
Transmission Planning Horizon; and
8.1.2. System Off-Peak Load for at least one year within the Near-Term
Transmission Planning Horizon.
8.2. The study or studies shall be conducted based on the supplemental GMD event
described in Attachment 1 to determine whether the System meets the
performance requirements for the steady state planning supplemental GMD
event contained in Table 1.
8.3. If the analysis concludes there is Cascading caused by the supplemental GMD
event described in Attachment 1, an evaluation of possible actions designed to
reduce the likelihood or mitigate the consequences and adverse impacts of the
event(s) shall be conducted.
8.4.8.3.
The supplemental GMD Vulnerability Assessment shall be provided:
(i) to the responsible entity’s Reliability Coordinator, adjacent Planning
Coordinators, adjacent Transmission Planners within 90 calendar days of
completion, and (ii) to any functional entity that submits a written request and
has a reliability-related need within 90 calendar days of receipt of such request
or within 90 calendar days of completion of the supplemental GMD Vulnerability
Assessment, whichever is later.
8.4.1.8.3.1. If a recipient of the supplemental GMD Vulnerability Assessment
provides documented comments on the results, the responsible entity
shall provide a documented response to that recipient within 90 calendar
days of receipt of those comments.
M8. Each responsible entity, as determined in Requirement R1, shall have dated evidence
such as electronic or hard copies of its supplemental GMD Vulnerability Assessment
meeting all of the requirements in Requirement R8. Each responsible entity, as
determined in Requirement R1, shall also provide evidence, such as email records,
web postings with an electronic notice of posting, or postal receipts showing recipient
and date, that it has distributed its supplemental GMD Vulnerability Assessment: (i) to
the responsible entity’s Reliability Coordinator, adjacent Planning Coordinators,
adjacent Transmission Planners within 90 calendar days of completion, and (ii) to any
functional entity that submits a written request and has a reliability-related need
within 90 calendar days of receipt of such request or within 90 calendar days of
completion of the supplemental GMD Vulnerability Assessment, whichever is later, as
specified in Requirement R8. Each responsible entity, as determined in Requirement
R1, shall also provide evidence, such as email notices or postal receipts showing
recipient and date, that it has provided a documented response to comments
received on its supplemental GMD Vulnerability Assessment within 90 calendar days
of receipt of those comments in accordance with Requirement R8.
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R9.
Each responsible entity, as determined in Requirement R1, shall provide GIC flow
information to be used for the supplemental thermal impact assessment of
transformers specified in Requirement R10 to each Transmission Owner and
Generator Owner that owns an applicable Bulk Electric System (BES) power
transformer in the planning area. The GIC flow information shall include: [Violation
Risk Factor: Medium] [Time Horizon: Long-term Planning]
9.1. The maximum effective GIC value for the worst case geoelectric field orientation
for the supplemental GMD event described in Attachment 1. This value shall be
provided to the Transmission Owner or Generator Owner that owns each
applicable BES power transformer in the planning area.
9.2. The effective GIC time series, GIC(t), calculated using the supplemental GMD
event described in Attachment 1 in response to a written request from the
Transmission Owner or Generator Owner that owns an applicable BES power
transformer in the planning area. GIC(t) shall be provided within 90 calendar
days of receipt of the written request and after determination of the maximum
effective GIC value in Part 9.1.
M9. Each responsible entity, as determined in Requirement R1, shall provide evidence,
such as email records, web postings with an electronic notice of posting, or postal
receipts showing recipient and date, that it has provided the maximum effective GIC
values to the Transmission Owner and Generator Owner that owns each applicable
BES power transformer in the planning area as specified in Requirement R9, Part 9.1.
Each responsible entity, as determined in Requirement R1, shall also provide
evidence, such as email records, web postings with an electronic notice of posting, or
postal receipts showing recipient and date, that it has provided GIC(t) in response to a
written request from the Transmission Owner or Generator Owner that owns an
applicable BES power transformer in the planning area.
R10. Each Transmission Owner and Generator Owner shall conduct a supplemental
thermal impact assessment for its solely and jointly owned applicable BES power
transformers where the maximum effective GIC value provided in Requirement R9,
Part 9.1, is 85 A per phase or greater. The supplemental thermal impact assessment
shall: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
10.1. Be based on the effective GIC flow information provided in Requirement R9;
10.2. Document assumptions used in the analysis;
10.3. Describe suggested actions and supporting analysis to mitigate the impact of
GICs, if any; and
10.4. Be performed and provided to the responsible entities, as determined in
Requirement R1, within 24 calendar months of receiving GIC flow information
specified in Requirement R9, Part 9.1.
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M10. Each Transmission Owner and Generator Owner shall have evidence such as
electronic or hard copies of its supplemental thermal impact assessment for all of its
solely and jointly owned applicable BES power transformers where the maximum
effective GIC value provided in Requirement R9, Part 9.1, is 85 A per phase or greater,
and shall have evidence such as email records, web postings with an electronic notice
of posting, or postal receipts showing recipient and date, that it has provided its
supplemental thermal impact assessment to the responsible entities as specified in
Requirement R10.
R11. Each responsible entity, as determined in Requirement R1, that concludes through
the supplemental GMD Vulnerability Assessment conducted in Requirement R8 that
their System does not meet the performance requirements for the steady state
planning supplemental GMD event contained in Table 1, shall develop a Corrective
Action Plan (CAP) addressing how the performance requirements will be met. The CAP
shall: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
11.1. List System deficiencies and the associated actions needed to achieve required
System performance. Examples of such actions include:
•
Installation, modification, retirement, or removal of Transmission and
generation Facilities and any associated equipment.
•
Installation, modification, or removal of Protection Systems or Remedial
Action Schemes.
•
Use of Operating Procedures, specifying how long they will be needed as
part of the CAP.
•
Use of Demand-Side Management, new technologies, or other initiatives.
11.2. Be developed within one year of completion of the supplemental GMD
Vulnerability Assessment.
11.3. Include a timetable, subject to approval for any extension sought under Part
11.4, for implementing the selected actions from Part 11.1. The timetable shall:
11.3.1. Specify implementation of non-hardware mitigation, if any, within two
years of development of the CAP; and
11.3.2. Specify implementation of hardware mitigation, if any, within four years
of development of the CAP.
11.4. Be submitted to the CEA with a request for extension of time if the responsible
entity is unable to implement the CAP within the timetable provided in Part 11.3.
The submitted CAP shall document the following:
11.4.1. Circumstances causing the delay for fully or partially implementing the
selected actions in Part 11.1 and how those circumstances are beyond
the control of the responsible entity;
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11.4.2. Revisions to the selected actions in Part 11.1, if any, including utilization
of Operating Procedures, if applicable; and
11.4.3. Updated timetable for implementing the selected actions in Part 11.1.
11.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent
Planning Coordinator(s), adjacent Transmission Planner(s), and functional
entities referenced in the CAP within 90 calendar days of development or
revision, and (ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later.
11.5.1. If a recipient of the CAP provides documented comments on the CAP, the
responsible entity shall provide a documented response to that recipient
within 90 calendar days of receipt of those comments.
M11. Each responsible entity, as determined in Requirement R1, that concludes, through
the supplemental GMD Vulnerability Assessment conducted in Requirement R8, that
the responsible entity’s System does not meet the performance requirements for the
steady state planning supplemental GMD event contained in Table 1 shall have
evidence such as dated electronic or hard copies of its CAP including timetable for
implementing selected actions, as specified in Requirement R11. Each responsible
entity, as determined in Requirement R1, shall also provide evidence, such as email
records or postal receipts showing recipient and date, that it submitted a request for
extension to the CEA if the responsible entity is unable to implement the CAP within
the timetable provided in Part 11.3. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records, web postings with
an electronic notice of posting, or postal receipts showing recipient and date, that it
has distributed its CAP or relevant information, if any, (i) to the responsible entity’s
Reliability Coordinator, adjacent Planning Coordinator(s), adjacent Transmission
Planner(s), and functional entities referenced in the CAP within 90 calendar days of
development or revision, and (ii) to any functional entity that submits a written
request and has a reliability-related need within 90 calendar days of receipt of such
request or within 90 calendar days of development or revision, whichever is later as
specified in Requirement R11. Each responsible entity, as determined in Requirement
R1, shall also provide evidence, such as email notices or postal receipts showing
recipient and date, that it has provided a documented response to comments received
on its CAP within 90 calendar days of receipt of those comments, in accordance with
Requirement R11.
GMD Measurement Data Processes
R11.R12. Each responsible entity, as determined in Requirement R1, shall implement a
process to obtain GIC monitor data from at least one GIC monitor located in the
Planning Coordinator’s planning area or other part of the system included in the
Planning Coordinator’s GIC System model. [Violation Risk Factor: Lower] [Time
Horizon: Long-term Planning]
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M11.M12. Each responsible entity, as determined in Requirement R1, shall have evidence
such as electronic or hard copies of its GIC monitor location(s) and documentation of
its process to obtain GIC monitor data in accordance with Requirement R11R12.
R12.R13. Each responsible entity, as determined in Requirement R1, shall implement a
process to obtain geomagnetic field data for its Planning Coordinator’s planning area.
[Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
M12.M13. Each responsible entity, as determined in Requirement R1, shall have evidence
such as electronic or hard copies of its process to obtain geomagnetic field data for its
Planning Coordinator’s planning area in accordance with Requirement R12R13.
D.C.
1.
Compliance
Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
Authority may ask an entity to provide other evidence to show that it was
compliant for the full-time period since the last audit.
The applicable entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
•
For Requirements R1, R2, R3, R5, R6, R9, and R10, each responsible entity
shall retain documentation as evidence for five years.
•
For Requirements R4 and R8, each responsible entity shall retain
documentation of the current GMD Vulnerability Assessment and the
preceding GMD Vulnerability Assessment.
•
For Requirement R7 and R11, each responsible entity shall retain
documentation as evidence for five years or until all actions in the
Corrective Action Plan are completed, whichever is later.
•
For Requirements R11R12 and R12R13, each responsible entity shall retain
documentation as evidence for three years.
1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
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TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.
Page 12 of 50
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Table 1: Steady State Planning GMD Event
Steady State:
a. Voltage collapse, Cascading and uncontrolled islanding shall not occur.
b. Generation loss is acceptable as a consequence of the steady state planning GMD events.
c. Planned System adjustments such as Transmission configuration changes and re-dispatch of generation are allowed if such
adjustments are executable within the time duration applicable to the Facility Ratings.
Category
Initial Condition
Event
Interruption of
Firm
Transmission
Service Allowed
Load Loss
Allowed
Benchmark GMD
Event -– GMD
Event with
Outages
1. System as may be
postured in response
to space weather
information1, and then
2. GMD event2
Reactive Power compensation devices
and other Transmission Facilities
removed as a result of Protection
System operation or Misoperation due
to harmonics during the GMD event
Yes3
Yes3
Supplemental
GMD Event -–
GMD Event with
Outages
1. System as may be
postured in response
to space weather
information1, and then
2. GMD event2
Reactive Power compensation devices
and other Transmission Facilities
removed as a result of Protection
System operation or Misoperation due
to harmonics during the GMD event
Yes
Yes
Table 1: Steady State Performance Footnotes
1. The System condition for GMD planning may include adjustments to posture the System that are executable in response to
space weather information.
2. The GMD conditions for the benchmark and supplemental planning events are described in Attachment 1.
3. Load loss as a result of manual or automatic Load shedding (e.g., UVLS) and/or curtailment of Firm Transmission Service may
be used to meet BES performance requirements during studied GMD conditions. The likelihood and magnitude of Load loss or
curtailment of Firm Transmission Service should be minimized.
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Violation Severity Levels
R#
R1.
R2.
Lower VSL
N/A
N/A
Violation Severity Levels
Moderate VSL
High VSL
Severe VSL
N/A
N/A
The Planning Coordinator,
in conjunction with its
Transmission Planner(s),
failed to determine and
identify individual or joint
responsibilities of the
Planning Coordinator and
Transmission Planner(s) in
the Planning Coordinator’s
planning area for
maintaining models,
performing the study or
studies needed to complete
benchmark and
supplemental GMD
Vulnerability Assessments,
and implementing
process(es) to obtain GMD
measurement data as
specified in this standard.
N/A
The responsible entity did
not maintain either System
models or GIC System
models of the responsible
entity’s planning area for
performing the studies
The responsible entity did
not maintain both System
models and GIC System
models of the responsible
entity’s planning area for
performing the studies
Page 14 of 50
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
needed to complete
benchmark and
supplemental GMD
Vulnerability Assessments.
R3.
R4.
N/A
The responsible entity
completed a benchmark
GMD Vulnerability
Assessment, but it was
more than 60 calendar
months and less than or
equal to 64 calendar
months since the last
benchmark GMD
Vulnerability Assessment.
N/A
N/A
The responsible entity’s
completed benchmark GMD
Vulnerability Assessment
failed to satisfy one of the
elements listed in
Requirement R4, Parts 4.1
through 4.3;
OR
The responsible entity
completed a benchmark
GMD Vulnerability
Assessment, but it was
more than 64 calendar
months and less than or
equal to 68 calendar
The responsible entity’s
completed benchmark GMD
Vulnerability Assessment
failed to satisfy two of the
elements listed in
Requirement R4, Parts 4.1
through 4.3;
OR
The responsible entity
completed a benchmark
GMD Vulnerability
Assessment, but it was
more than 68 calendar
months and less than or
equal to 72 calendar
Severe VSL
needed to complete
benchmark and
supplemental GMD
Vulnerability Assessments.
The responsible entity did
not have criteria for
acceptable System steady
state voltage performance
for its System during the
GMD events described in
Attachment 1 as required.
The responsible entity’s
completed benchmark GMD
Vulnerability Assessment
failed to satisfy three of the
elements listed in
Requirement R4, Parts 4.1
through 4.3;
OR
The responsible entity
completed a benchmark
GMD Vulnerability
Assessment, but it was
more than 72 calendar
months since the last
Page 15 of 50
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
R5.
R6.
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
months since the last
benchmark GMD
Vulnerability Assessment.
months since the last
benchmark GMD
Vulnerability Assessment.
benchmark GMD
Vulnerability Assessment;
OR
The responsible entity does
not have a completed
benchmark GMD
Vulnerability Assessment.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written
request, but did so more
than 90 calendar days and
less than or equal to 100
calendar days after receipt
of a written request.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written
request, but did so more
than 100 calendar days and
less than or equal to 110
calendar days after receipt
of a written request.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written
request, but did so more
than 110 calendar days
after receipt of a written
request.
The responsible entity did
not provide the maximum
effective GIC value to the
Transmission Owner and
Generator Owner that owns
each applicable BES power
transformer in the planning
area;
OR
The responsible entity did
not provide the effective
GIC time series, GIC(t), upon
written request.
The responsible entity failed
to conduct a benchmark
thermal impact assessment
for 5% or less or one of its
solely owned and jointly
owned applicable BES
The responsible entity failed
to conduct a benchmark
thermal impact assessment
for more than 5% up to (and
including) 10% or two of its
solely owned and jointly
The responsible entity failed
to conduct a benchmark
thermal impact assessment
for more than 10% up to
(and including) 15% or three
of its solely owned and
The responsible entity failed
to conduct a benchmark
thermal impact assessment
for more than 15% or more
than three of its solely
owned and jointly owned
Page 16 of 50
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R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
power transformers
(whichever is greater)
where the maximum
effective GIC value provided
in Requirement R5, Part 5.1,
is 75 A or greater per phase;
OR
The responsible entity
conducted a benchmark
thermal impact assessment
for its solely owned and
jointly owned applicable
BES power transformers
where the maximum
effective GIC value provided
in Requirement R5, Part 5.1,
is 75 A or greater per phase
but did so more than 24
calendar months and less
than or equal to 26 calendar
months of receiving GIC
flow information specified
in Requirement R5, Part 5.1.
owned applicable BES
power transformers
(whichever is greater)
where the maximum
effective GIC value provided
in Requirement R5, Part 5.1,
is 75 A or greater per phase;
OR
The responsible entity
conducted a benchmark
thermal impact assessment
for its solely owned and
jointly owned applicable
BES power transformers
where the maximum
effective GIC value provided
in Requirement R5, Part 5.1,
is 75 A or greater per phase
but did so more than 26
calendar months and less
than or equal to 28 calendar
months of receiving GIC
flow information specified
in Requirement R5, Part 5.1;
OR
The responsible entity failed
to include one of the
jointly owned applicable
BES power transformers
(whichever is greater)
where the maximum
effective GIC value provided
in Requirement R5, Part 5.1,
is 75 A or greater per phase;
OR
The responsible entity
conducted a benchmark
thermal impact assessment
for its solely owned and
jointly owned applicable
BES power transformers
where the maximum
effective GIC value provided
in Requirement R5, Part 5.1,
is 75 A or greater per phase
but did so more than 28
calendar months and less
than or equal to 30 calendar
months of receiving GIC
flow information specified
in Requirement R5, Part 5.1;
OR
The responsible entity failed
to include two of the
applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase;
OR
The responsible entity
conducted a benchmark
thermal impact assessment
for its solely owned and
jointly owned applicable
BES power transformers
where the maximum
effective GIC value provided
in Requirement R5, Part 5.1,
is 75 A or greater per phase
but did so more than 30
calendar months of
receiving GIC flow
information specified in
Requirement R5, Part 5.1;
OR
The responsible entity failed
to include three of the
required elements as listed
Page 17 of 50
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R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
required elements as listed
in Requirement R6, Parts
6.1 through 6.3.
required elements as listed
in Requirement R6, Parts
6.1 through 6.3.
in Requirement R6, Parts
6.1 through 6.3.
The responsible entity’s
Corrective Action Plan failed
to comply with one of the
elements in Requirement
R7, Parts 7.1 through 7.5.
The responsible entity’s
Corrective Action Plan failed
to comply with two of the
elements in Requirement
R7, Parts 7.1 through 7.5.
The responsible entity’s
Corrective Action Plan failed
to comply with three of the
elements in Requirement
R7, Parts 7.1 through 7.5.
The responsible entity’s
Corrective Action Plan failed
to comply with four or more
of the elements in
Requirement R7, Parts 7.1
through 7.5;
OR
The responsible entity did
not havedevelop a
Corrective Action Plan as
required by Requirement
R7.
The responsible entity's
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
one of elements listed in
Requirement R8, Parts 8.1
through 8.4;
OR
The responsible entity
completed a supplemental
GMD Vulnerability
The responsible entity’s
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
twoone of the elements
listed in Requirement R8,
Parts 8.1 through 8.43;
OR
The responsible entity
completed a supplemental
GMD Vulnerability
The responsible entity’s
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
threetwo of the elements
listed in Requirement R8,
Parts 8.1 through 8.43;
OR
The responsible entity
completed a supplemental
GMD Vulnerability
The responsible entity’s
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
fourthree of the elements
listed in Requirement R8,
Parts 8.1 through 8.43;
OR
The responsible entity
completed a supplemental
GMD Vulnerability
R7.
R8.
Severe VSL
Page 18 of 50
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
R9.
R10.
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
Assessment, but it was
more than 60 calendar
months and less than or
equal to 64 calendar
months since the last
supplemental GMD
Vulnerability Assessment.
Assessment, but it was
more than 64 calendar
months and less than or
equal to 68 calendar
months since the last
supplemental GMD
Vulnerability Assessment.
Assessment, but it was
more than 68 calendar
months and less than or
equal to 72 calendar
months since the last
supplemental GMD
Vulnerability Assessment.
Assessment, but it was
more than 72 calendar
months since the last
supplemental GMD
Vulnerability Assessment;
OR
The responsible entity does
not have a completed
supplemental GMD
Vulnerability Assessment.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written
request, but did so more
than 90 calendar days and
less than or equal to 100
calendar days after receipt
of a written request.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written
request, but did so more
than 100 calendar days and
less than or equal to 110
calendar days after receipt
of a written request.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written
request, but did so more
than 110 calendar days
after receipt of a written
request.
The responsible entity did
not provide the maximum
effective GIC value to the
Transmission Owner and
Generator Owner that owns
each applicable BES power
transformer in the planning
area;
OR
The responsible entity did
not provide the effective
GIC time series, GIC(t), upon
written request.
The responsible entity failed The responsible entity failed The responsible entity failed The responsible entity failed
to conduct a supplemental
to conduct a supplemental
to conduct a supplemental
to conduct a supplemental
thermal impact assessment thermal impact assessment thermal impact assessment thermal impact assessment
Page 19 of 50
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
for 5% or less or one of its
solely owned and jointly
owned applicable BES
power transformers
(whichever is greater)
where the maximum
effective GIC value provided
in Requirement R9, Part 9.1,
is 85 A or greater per phase;
OR
The responsible entity
conducted a supplemental
thermal impact assessment
for its solely owned and
jointly owned applicable
BES power transformers
where the maximum
effective GIC value provided
in Requirement R9, Part 9.1,
is 85 A or greater per phase
but did so more than 24
calendar months and less
than or equal to 26 calendar
months of receiving GIC
flow information specified
in Requirement R9, Part 9.1.
for more than 5% up to (and
including) 10% or two of its
solely owned and jointly
owned applicable BES
power transformers
(whichever is greater)
where the maximum
effective GIC value provided
in Requirement R9, Part 9.1,
is 85 A or greater per phase;
OR
The responsible entity
conducted a supplemental
thermal impact assessment
for its solely owned and
jointly owned applicable
BES power transformers
where the maximum
effective GIC value provided
in Requirement R9, Part 9.1,
is 85 A or greater per phase
but did so more than 26
calendar months and less
than or equal to 28 calendar
months of receiving GIC
flow information specified
in Requirement R9, Part 9.1
for more than 10% up to
(and including) 15% or three
of its solely owned and
jointly owned applicable
BES power transformers
(whichever is greater)
where the maximum
effective GIC value provided
in Requirement R9, Part 9.1,
is 85 A or greater per phase;
OR
The responsible entity
conducted a supplemental
thermal impact assessment
for its solely owned and
jointly owned applicable
BES power transformers
where the maximum
effective GIC value provided
in Requirement R9, Part 9.1,
is 85 A or greater per phase
but did so more than 28
calendar months and less
than or equal to 30 calendar
months of receiving GIC
flow information specified
in Requirement R9, Part 9.1;
for more than 15% or more
than three of its solely
owned and jointly owned
applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase;
OR
The responsible entity
conducted a supplemental
thermal impact assessment
for its solely owned and
jointly owned applicable
BES power transformers
where the maximum
effective GIC value provided
in Requirement R9, Part 9.1,
is 85 A or greater per phase
but did so more than 30
calendar months of
receiving GIC flow
information specified in
Requirement R9, Part 9.1;
OR
Page 20 of 50
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
R11.
Violation Severity Levels
Lower VSL
The responsible entity’s
Corrective Action Plan failed
to comply with one of the
elements in Requirement
R11, Parts 11.1 through
11.5.
Moderate VSL
High VSL
Severe VSL
OR
The responsible entity failed
to include one of the
required elements as listed
in Requirement R10, Parts
10.1 through 10.3.
OR
The responsible entity failed
to include two of the
required elements as listed
in Requirement R10, Parts
10.1 through 10.3.
The responsible entity failed
to include three of the
required elements as listed
in Requirement R10, Parts
10.1 through 10.3.
The responsible entity’s
Corrective Action Plan failed
to comply with two of the
elements in Requirement
R11, Parts 11.1 through
11.5.
The responsible entity’s
Corrective Action Plan failed
to comply with three of the
elements in Requirement
R11, Parts 11.1 through
11.5.
The responsible entity’s
Corrective Action Plan failed
to comply with four or more
of the elements in
Requirement R11, Parts
11.1 through 11.5;
OR
The responsible entity did
not develop a Corrective
Action Plan as required by
Requirement R11.
Page 21 of 50
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
R11R12.
R12R13.
Violation Severity Levels
Lower VSL
N/A
N/A
Moderate VSL
N/A
N/A
High VSL
N/A
N/A
Severe VSL
The responsible entity did
not implement a process to
obtain GIC monitor data
from at least one GIC
monitor located in the
Planning Coordinator’s
planning area or other part
of the system included in
the Planning Coordinator’s
GIC System Model.
The responsible entity did
not implement a process to
obtain geomagnetic field
data for its Planning
Coordinator’s planning area.
Page 22 of 50
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
E.D.
Regional Variances
D.A. Regional Variance for Canadian Jurisdictions
This Variance shall be applicable in those Canadian jurisdictions where the Variance
has been approved for use by the applicable governmental authority or has otherwise
become effective in the jurisdiction.
AllThis variance replaces all references to “Attachment 1” in the standard are replaced
with “Attachment 1 or Attachment 1-CAN.”
In addition, this Variance replaces Requirement R7, Part 7.3 through Part 7.5 and
Requirement R11, Part 11.3 through Part 11.5 with the following:
D.A.7.3. Include a timetable, subject to revision by the responsible entity in Part
D.A.7.4, for implementing the selected actions from Part 7.1. The timetable
shall:
D.A.7.3.1. Specify implementation of non-hardware mitigation, if any, within
two years of the later of the development of the CAP or receipt of
regulatory approvals, if required; and
D.A.7.3.2. Specify implementation of hardware mitigation, if any, within four
years of the later of the development of the CAP or receipt of
regulatory approvals, if required.
D.A.7.4. Be revised if the responsible entity is unable to implement the CAP
within the timetable for implementation provided in Part D.A.7.3. The
revised CAP shall document the following:
D.A.7.4.1 Circumstances causing the delay for fully or partially implementing the
selected actions in Part 7.1 and how those circumstances are beyond
the control of the responsible entity;
D.A.7.4.2 Revisions to the selected actions in Part 7.1, if any, including utilization
of Operating Procedures if applicable; and
D.A.7.4.3 Updated timetable for implementing the selected actions in Part 7.1.
D.A.7.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent
Planning Coordinator(s), adjacent Transmission Planner(s), and functional
entities referenced in the CAP within 90 calendar days of development or
revision, (ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later, and
(iii) to the Compliance Enforcement Authority or Applicable Governmental
Authority when revised under D.A.7.4 within 90 calendar days of revision.
D.A.7.5.1 If a recipient of the CAP provides documented comments on the CAP,
the responsible entity shall provide a documented response to that
recipient within 90 calendar days of receipt of those comments.
Page 23 of 50
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
D.A.M.7. Each responsible entity, as determined in Requirement R1, that concludes,
through the benchmark GMD Vulnerability Assessment conducted in
Requirement R4, that the responsible entity’s System does not meet the
performance requirements for the steady state planning benchmark GMD
event contained in Table 1 shall have evidence such as dated electronic or
hard copies of its CAP including timetable for implementing selected actions,
as specified in Requirement R7. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records or postal
receipts showing recipient and date, that it has revised its CAP if situations
beyond the responsible entity's control prevent implementation of the CAP
within the timetable specified. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records, web
postings with an electronic notice of posting, or postal receipts showing
recipient and date, that it has distributed its CAP or relevant information, if
any, (i) to the responsible entity’s Reliability Coordinator, adjacent Planning
Coordinator(s), adjacent Transmission Planner(s), and functional entities
referenced in the CAP within 90 calendar days of development or revision,
(ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later as
specified in Requirement R7, and (iii) to the Compliance Enforcement
Authority or Applicable Governmental Authority when revised under D.A.7.4
within 90 calendar days of revision. Each responsible entity, as determined
in Requirement R1, shall also provide evidence, such as email notices or
postal receipts showing recipient and date, that it has provided a
documented response to comments received on its CAP within 90 calendar
days of receipt of those comments, in accordance with Requirement R7.
D.A.11.3.Include a timetable, subject to revision by the responsible entity in Part
D.A.11.4, for implementing the selected actions from Part 11.1. The
timetable shall:
D.A.11.3.1. Specify implementation of non-hardware mitigation, if any, within
two years of the later of the development of the CAP or receipt of
regulatory approvals, if required; and
D.A.11.3.2. Specify implementation of hardware mitigation, if any, within four
years of the later of the development of the CAP or receipt of
regulatory approvals, if required.
D.A.11.4. Be revised if the responsible entity is unable to implement the CAP within
the timetable for implementation provided in Part D.A.11.3. The revised CAP
shall document the following:
D.A.11.4.1 Circumstances causing the delay for fully or partially implementing
the selected actions in Part 11.1 and how those circumstances are
beyond the control of the responsible entity;
Page 24 of 50
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
D.A.11.4.2 Revisions to the selected actions in Part 11.1, if any, including
utilization of Operating Procedures if applicable; and
D.A.11.4.3 Updated timetable for implementing the selected actions in Part
11.1.
D.A.11.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent
Planning Coordinator(s), adjacent Transmission Planner(s), and functional
entities referenced in the CAP within 90 calendar days of development or
revision, (ii) to any functional entity that submits a written request and has
a reliability-related need within 90 calendar days of receipt of such request
or within 90 calendar days of development or revision, whichever is later,
and (iii) to the Compliance Enforcement Authority or Applicable
Governmental Authority when revised under D.A.11.4 within 90 calendar
days of revision.
D.A.11.5.1. If a recipient of the CAP provides documented comments on the
CAP, the responsible entity shall provide a documented response to
that recipient within 90 calendar days of receipt of those comments.
Page 25 of 50
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
D.A.M.11. Each responsible entity, as determined in Requirement R1, that concludes,
through the supplemental GMD Vulnerability Assessment conducted in
Requirement R8, that the responsible entity’s System does not meet the
performance requirements for the steady state planning supplemental GMD
event contained in Table 1 shall have evidence such as dated electronic or
hard copies of its CAP including timetable for implementing selected actions,
as specified in Requirement R11. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records or postal
receipts showing recipient and date, that it has revised its CAP if situations
beyond the responsible entity's control prevent implementation of the CAP
within the timetable specified. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records, web
postings with an electronic notice of posting, or postal receipts showing
recipient and date, that it has distributed its CAP or relevant information, if
any, (i) to the responsible entity’s Reliability Coordinator, adjacent Planning
Coordinator(s), adjacent Transmission Planner(s), and functional entities
referenced in the CAP within 90 calendar days of development or revision,
(ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later as
specified in Requirement R11, and (iii) to the Compliance Enforcement
Authority or Applicable Governmental Authority when revised under
D.A.11.4 within 90 calendar days of revision. Each responsible entity, as
determined in Requirement R1, shall also provide evidence, such as email
notices or postal receipts showing recipient and date, that it has provided a
documented response to comments received on its CAP within 90 calendar
days of receipt of those comments, in accordance with Requirement R11.
Page 26 of 50
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
F.E.
Associated Documents
Attachment 1
Attachment 1-CAN
Page 27 of 50
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Version History
Version
1
Date
Action
December 17, 2014 Adopted by the NERC Board of Trustees
Change
Tracking
New
Revised to
respond to
directives in FERC
Order No. 830.
2
November 9, 2017
Adopted by the NERC Board of Trustees
2
November 25, 2018
FERC Order issued approving TPL-007-2.
Docket No. RM18-8-000
3
February 7, 2019
Adopted by the NERC Board of Trustees
Canadian
Variance
Adopted by the NERC Board of Trustees
Revised to
respond to
directives in FERC
Order. 851
4
February 6, 2020
Page 28 of 50
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Attachment 1
Calculating Geoelectric Fields for the Benchmark and Supplemental GMD Events
The benchmark GMD event 1 defines the geoelectric field values used to compute GIC flows that
are needed to conduct a benchmark GMD Vulnerability Assessment. It is composed of the
following elements: (1) a reference peak geoelectric field amplitude of 8 V/km derived from
statistical analysis of historical magnetometer data; (2) scaling factors to account for local
geomagnetic latitude; (3) scaling factors to account for local earth conductivity; and (4) a
reference geomagnetic field time series or waveform to facilitate time-domain analysis of GMD
impact on equipment.
The supplemental GMD event is composed of similar elements as described above, except (1) the
reference peak geoelectric field amplitude is 12 V/km over a localized area; and (2) the
geomagnetic field time series or waveform includes a local enhancement in the waveform. 2
The regional geoelectric field peak amplitude used in GMD Vulnerability Assessment, Epeak, can
be obtained from the reference geoelectric field value of 8 V/km for the benchmark GMD event
(1) or 12 V/km for the supplemental GMD event (2) using the following relationships:
𝐸𝐸𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝 = 8 × 𝛼𝛼 × 𝛽𝛽 𝑏𝑏 (𝑉𝑉 ⁄𝑘𝑘𝑘𝑘)
𝐸𝐸𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝 = 12 × 𝛼𝛼 × 𝛽𝛽 𝑠𝑠 (𝑉𝑉 ⁄𝑘𝑘𝑘𝑘)
(1)
(2)
where, α is the scaling factor to account for local geomagnetic latitude, and β is a scaling factor
to account for the local earth conductivity structure. Subscripts b and s for the β scaling factor
denote association with the benchmark or supplemental GMD events, respectively.
Scaling the Geomagnetic Field
The benchmark and supplemental GMD events are defined for geomagnetic latitude of 60° and
must be scaled to account for regional differences based on geomagnetic latitude. Table 2
provides a scaling factor correlating peak geoelectric field to geomagnetic latitude. Alternatively,
the scaling factor α is computed with the empirical expression:
𝛼𝛼 = 0.001 × 𝑒𝑒 (0.115×𝐿𝐿)
(3)
where, L is the geomagnetic latitude in degrees and 0.1 ≤ α ≤ 1.
1 The Benchmark Geomagnetic Disturbance Event Description, May 2016 is available on the Related Information webpage for
TPL-007-1: http://www.nerc.com/pa/Stand/TPL0071RD/Benchmark_clean_May12_complete.pdf.
2 The extent of local enhancements is on the order of 100 km in North-South (latitude) direction but longer in East-West
(longitude) direction. The local enhancement in the geomagnetic field occurs over the time period of 2-5 minutes. Additional
information is available in the Supplemental Geomagnetic Disturbance Event Description, October 2017 white paper on the
Project 2013-03 Geomagnetic Disturbance Mitigation project webpage: http://www.nerc.com/pa/Stand/Pages/Project-201303-Geomagnetic-Disturbance-Mitigation.aspx.
Page 29 of 50
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
For large planning areas that cover more than one scaling factor from Table 2, the GMD
Vulnerability Assessment should be based on a peak geoelectric field that is:
•
calculated by using the most conservative (largest) value for α; or
•
calculated assuming a non-uniform or piecewise uniform geomagnetic field.
Table 2: Geomagnetic Field Scaling Factors for the
Benchmark and Supplemental GMD
Events
Geomagnetic Latitude
(Degrees)
Scaling Factor1
(α)
≤ 40
0.10
45
0.2
50
0.3
54
0.5
56
0.6
57
0.7
58
0.8
59
0.9
≥ 60
1.0
Scaling the Geoelectric Field
The benchmark GMD event is defined for the reference Quebec earth model described in Table
4. The peak geoelectric field, Epeak, used in a GMD Vulnerability Assessment may be obtained by
either:
•
Calculating the geoelectric field for the ground conductivity in the planning area and the
reference geomagnetic field time series scaled according to geomagnetic latitude, using
a procedure such as the plane wave method described in the NERC GMD Task Force GIC
Application Guide; 3 or
•
Using the earth conductivity scaling factor β from Table 3 that correlates to the ground
conductivity map in Figure 1 or Figure 2. Along with the scaling factor α from equation
(3) or Table 2, β is applied to the reference geoelectric field using equation (1 or 2, as
applicable) to obtain the regional geoelectric field peak amplitude Epeak to be used in
GMD Vulnerability Assessments. When a ground conductivity model is not available, the
planningresponsible entity should use the largest β factor of adjacent physiographic
regions or a technically justified value.
Available at the NERC GMD Task Force project webpage: http://www.nerc.com/comm/PC/Pages/Geomagnetic-DisturbanceTask-Force-(GMDTF)-2013.aspx.
3
Page 30 of 50
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
The earth models used to calculate Table 3 for the United States were obtained from publicly
available information published on the U. S. Geological Survey website. 4 The models used to
calculate Table 3 for Canada were obtained from Natural Resources Canada (NRCan) and reflect
the average structure for large regions. A planner can also use specific earth model(s) with
documented justification and the reference geomagnetic field time series to calculate the β
factor(s) as follows:
(4)
𝛽𝛽𝑏𝑏 = 𝐸𝐸 ⁄8 for the benchmark GMD event
(5)
𝛽𝛽𝑠𝑠 = 𝐸𝐸 ⁄12 for the supplemental GMD
where, E is the absolute value of peak geoelectric in V/km obtained from the technically justified
earth model and the reference geomagnetic field time series.
For large planning areas that span more than one β scaling factor, the most conservative (largest)
value for β may be used in determining the peak geoelectric field to obtain conservative results.
Alternatively, a planner could perform analysis using a non-uniform or piecewise uniform
geoelectric field.
Applying the Localized Peak Geoelectric Field in the Supplemental GMD Event
The peak geoelectric field of the supplemental GMD event occurs in a localized area. 5 Planners
have flexibility to determine how to apply the localized peak geoelectric field over the planning
area in performing GIC calculations. Examples of approaches are:
•
Apply the peak geoelectric field (12 V/km scaled to the planning area) over the entire
planning area;
•
Apply a spatially limited (12 V/km scaled to the planning area) peak geoelectric field (e.g.,
100 km in North-South latitude direction and 500 km in East-West longitude direction)
over a portion(s) of the system, and apply the benchmark GMD event over the rest of the
system; or
•
Other methods to adjust the benchmark GMD event analysis to account for the localized
geoelectric field enhancement of the supplemental GMD event.
Available at http://geomag.usgs.gov/conductivity/.
See the Supplemental Geomagnetic Disturbance Description white paper located on the Project 2013-03 Geomagnetic
Disturbance Mitigation project webpage: http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspx.
4
5
Page 31 of 50
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
FL-1
Figure 1: Physiographic Regions of the Continental United States 6
Figure 2: Physiographic Regions of Canada
6
Additional map detail is available at the U.S. Geological Survey: http://geomag.usgs.gov/.
Page 32 of 50
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Table 3: Geoelectric Field Scaling Factors
Earth model
Scaling Factor
Benchmark Event
(βb)
Scaling Factor
Supplemental
Event
(βs)
AK1A
0.56
0.51
AK1B
0.56
0.51
AP1
0.33
0.30
AP2
0.82
0.78
BR1
0.22
0.22
CL1
0.76
0.73
CO1
0.27
0.25
CP1
0.81
0.77
CP2
0.95
0.86
FL1
0.76
0.73
CS1
0.41
0.37
IP1
0.94
0.90
IP2
0.28
0.25
IP3
0.93
0.90
IP4
0.41
0.35
NE1
0.81
0.77
PB1
0.62
0.55
PB2
0.46
0.39
PT1
1.17
1.19
SL1
0.53
0.49
SU1
0.93
0.90
BOU
0.28
0.24
FBK
0.56
0.56
PRU
0.21
0.22
BC
0.67
0.62
PRAIRIES
0.96
0.88
SHIELD
1.0
1.0
ATLANTIC
0.79
0.76
Page 33 of 50
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Scaling factors in Table 3 are dependent upon the frequency content of the reference storm.
Consequently, the benchmark GMD event and the supplemental GMD event may produce
different scaling factors for a given earth model.
Rationale: Scaling factors in Table 3 are dependent upon the frequency content of the reference
storm. Consequently, the benchmark GMD event and the supplemental GMD event may produce
different scaling factors for a given earth model.
The scaling factor associated with the benchmark GMD event for the Florida earth model (FL1)
has been updated based on the earth model published on the USGS public website.
Table 4: Reference Earth Model (Quebec)
Layer Thickness (km)
Resistivity (Ω-m)
15
20,000
10
200
125
1,000
200
100
∞
3
Reference Geomagnetic Field Time Series or Waveform for the Benchmark GMD
Event 7
The geomagnetic field measurement record of the March 13-14 1989 GMD event, measured at
the NRCan Ottawa geomagnetic observatory, is the basis for the reference geomagnetic field
waveform to be used to calculate the GIC time series, GIC(t), required for transformer thermal
impact assessment.
The geomagnetic latitude of the Ottawa geomagnetic observatory is 55°; therefore, the
amplitudes of the geomagnetic field measurement data were scaled up to the 60° reference
geomagnetic latitude (see Figure 3) such that the resulting peak geoelectric field amplitude
computed using the reference earth model was 8 V/km (see Figures 4 and 5). The sampling rate
for the geomagnetic field waveform is 10 seconds. 8 To use this geoelectric field time series when
a different earth model is applicable, it should be scaled with the appropriate benchmark
conductivity scaling factor βb.
Refer to the Benchmark Geomagnetic Disturbance Event Description white paper for details on the determination of the
reference geomagnetic field waveform: http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx.
8 The data file of the benchmark geomagnetic field waveform is available on the Related Information webpage for TPL-007-1:
http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx.
7
Page 34 of 50
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Figure 3: Benchmark Geomagnetic Field Waveform
Red Bn (Northward), Blue Be (Eastward)
Figure 4: Benchmark Geoelectric Field Waveform
EE (Eastward)
Page 35 of 50
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Figure 5: Benchmark Geoelectric Field Waveform
EN (Northward)
Reference Geomagnetic Field Time Series or Waveform for the Supplemental GMD
Event 9
The geomagnetic field measurement record of the March 13-14, 1989 GMD event, measured at
the NRCan Ottawa geomagnetic observatory, is the basis for the reference geomagnetic field
waveform to be used to calculate the GIC time series, GIC(t), required for transformer thermal
impact assessment for the supplemental GMD event. The supplemental GMD event waveform
differs from the benchmark GMD event waveform in that the supplemental GMD event
waveform has a local enhancement.
The geomagnetic latitude of the Ottawa geomagnetic observatory is 55°; therefore, the
amplitudes of the geomagnetic field measurement data were scaled up to the 60° reference
geomagnetic latitude (see Figure 6) such that the resulting peak geoelectric field amplitude
computed using the reference earth model was 12 V/km (see Figure7). The sampling rate for the
geomagnetic field waveform is 10 seconds. 10 To use this geoelectric field time series when a
different earth model is applicable, it should be scaled with the appropriate supplemental
conductivity scaling factor βs.
Refer to the Supplemental Geomagnetic Disturbance Event Description white paper for details on the determination of the
reference geomagnetic field waveform: http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspx.
10 The data file of the benchmark geomagnetic field waveform is available on the NERC GMD Task Force project webpage:
http://www.nerc.com/comm/PC/Pages/Geomagnetic-Disturbance-Task-Force-(GMDTF)-2013.aspx.
9
Page 36 of 50
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
4000
2000
Time (min)
200
400
600
800
1000
1200
1400
1600
1800
2000
Bx, By (nT)
0
-2000
-4000
-6000
-8000
-10000
Figure 6: Supplemental Geomagnetic Field Waveform
Red BN (Northward), Blue BE (Eastward)
12 V/km
Figure 7: Supplemental Geoelectric Field Waveform
Blue EN (Northward), Red EE (Eastward)
Page 37 of 50
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Attachment 1-CAN
Attachment 1-CAN provides an alternative that a Canadian entity may use in lieu of the
benchmark or supplemental GMD event(s) defined in Attachment 1 for performing GMD
Vulnerability Assessment(s).
A Canadian entity may use the provisions of Attachment 1-CAN if it has regionally specific
information that provides a technically justified means to re-define a 1-in-100 year GMD
planning event(s) within its planning area.
Information for the Alternative Methodology
GMD Vulnerability Assessment(s) require the use of geophysical and engineering models.
Canadian-specific data is available and growing. Ongoing research allows for more accurate
characterization of regional parameters used in these models. Such Canadian-specific data
includes geomagnetic field, earth conductivity, and geomagnetically induced current
measurements that can be used for modeling and simulation validation.
Information used to calculate geoelectric fields for the benchmark and supplemental GMD events
shall be clearly documented and technically justified. For example, the factors involved in the
calculation of geoelectric fields are geomagnetic field variations and an earth transfer
function(s). [1] 1 Technically justified information used in modelling geomagnetic field variations
may include: technical documents produced by governmental entities such as Natural Resources
Canada; technical papers published in peer-reviewed journals; and data sets gathered using
sound scientific principles. An earth transfer function may rely on magnetotelluric measurements
or earth conductivity models.
Modeling assumptions shall also be clearly documented and technically justified. An entity may
use sensitivity analysis to identify how the assumptions affect the results.
A simplified model may be used to perform a GMD Vulnerability Assessment(s), as long as the
model is more conservative than a more detailed model.
When interpreting assessment results, the entity shall consider the maturity of the modeling,
toolset, and techniques applied.
Geomagnetic Disturbance Planning Events
The 1-in-100 year planning event shall be based on regionally specific data and technically
justifiable statistical analyses (e.g., extreme value theory) and applied to the benchmark and
supplemental GMD Vulnerability Assessment(s).
The “earth transfer function” is the relationship between the electric fields and magnetic field variations at the surface of the
earth.
1 The “earth transfer function” is the relationship between the electric fields and magnetic field variations at the surface of the
earth.
[1]
Page 38 of 50
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
For the benchmark GMD Vulnerability Assessment(s), an entity shall consider the large-scale
spatial structure of the GMD event. For the supplemental GMD Vulnerability Assessment(s), an
entity shall consider the small-scale spatial structure of the GMD event (e.g., using magnetometer
measurements or realistic electrojet calculations).
Page 39 of 50
TPL-007-34 – Supplemental Material
Guidelines and Technical Basis
The diagram below provides an overall view of the GMD Vulnerability Assessment process:
Geomagnetic
Field
B(t)
Earth
Conductivity
Model
Potential
Mitigation
Measures
Geoelectric
Field
E(t)
dc
System
Model
GIC
Transformer vars
Model
(Electrical)
GIC(t)
Power Flow
Analysis
Transformer
Model
(Thermal)
Fail
Bus
Voltages
Line Loading &
var Reserves
Assessment
Criteria
Operating
Procedures
and
Pass
Mitigation
Measures
(if needed)
Temp(t)
Critical Temperatures
The requirements in this standard cover various aspects of the GMD Vulnerability Assessment
process.
Benchmark GMD Event (Attachment 1)
The benchmark GMD event defines the geoelectric field values used to compute GIC flows that
are needed to conduct a benchmark GMD Vulnerability Assessment. The Benchmark
Geomagnetic Disturbance Event Description, May 2016 11 white paper includes the event
description, analysis, and example calculations.
Supplemental GMD Event (Attachment 1)
The supplemental GMD event defines the geoelectric field values used to compute GIC flows that
are needed to conduct a supplemental GMD Vulnerability Assessment. The Supplemental
Geomagnetic Disturbance Event Description, October 2017 12 white paper includes the event
description and analysis.
Requirement R2
A GMD Vulnerability Assessment requires a GIC System model, which is a dc representation of
the System, to calculate GIC flow. In a GMD Vulnerability Assessment, GIC simulations are used
to determine transformer Reactive Power absorption and transformer thermal response. Details
for developing the GIC System model are provided in the NERC GMD Task Force guide:
Application Guide for Computing Geomagnetically-Induced Current in the Bulk Power System,
December 2013. 13
Underground pipe-type cables present a special modeling situation in that the steel pipe that
encloses the power conductors significantly reduces the geoelectric field induced into the
http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx.
http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-Disturbance-Mitigation.aspx.
13 http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GIC%20Application
%20Guide%202013_approved.pdf.
11
12
Page 40 of 50
TPL-007-34 – Supplemental Material
conductors themselves, while they remain a path for GIC. Solid dielectric cables that are not
enclosed by a steel pipe will not experience a reduction in the induced geoelectric field. A
planning entity should account for special modeling situations in the GIC system model, if
applicable.
Requirement R4
The Geomagnetic Disturbance Planning Guide, 14 December 2013 developed by the NERC GMD
Task Force provides technical information on GMD-specific considerations for planning studies.
Requirement R5
The benchmark thermal impact assessment of transformers specified in Requirement R6 is based
on GIC information for the benchmark GMD Event. This GIC information is determined by the
planning entity through simulation of the GIC System model and must be provided to the entity
responsible for conducting the thermal impact assessment. GIC information should be provided
in accordance with Requirement R5 each time the GMD Vulnerability Assessment is performed
since, by definition, the GMD Vulnerability Assessment includes a documented evaluation of
susceptibility to localized equipment damage due to GMD.
The maximum effective GIC value provided in Part 5.1 is used for the benchmark thermal impact
assessment. Only those transformers that experience an effective GIC value of 75 A or greater
per phase require evaluation in Requirement R6.
GIC(t) provided in Part 5.2 is used to convert the steady state GIC flows to time-series GIC data
for the benchmark thermal impact assessment of transformers. This information may be needed
by one or more of the methods for performing a benchmark thermal impact assessment.
Additional information is in the following section and the Transformer Thermal Impact
Assessment White Paper, 15 October 2017.
The peak GIC value of 75 Amps per phase has been shown through thermal modeling to be a
conservative threshold below which the risk of exceeding known temperature limits established
by technical organizations is low.
Requirement R6
The benchmark thermal impact assessment of a power transformer may be based on
manufacturer-provided GIC capability curves, thermal response simulation, thermal impact
screening, or other technically justified means. Approaches for conducting the assessment are
presented in the Transformer Thermal Impact Assessment White Paper ERO Enterprise-Endorsed
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GMD%20Planning
%20Guide_approved.pdf.
15 http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-Disturbance-Mitigation.aspx.
14
Page 41 of 50
TPL-007-34 – Supplemental Material
Implementation Guidance 16 for this requirement. This ERO-Endorsed document is posted on the
NERC Compliance Guidance 17 webpage.
Transformers are exempt from the benchmark thermal impact assessment requirement if the
effective GIC value for the transformer is less than 75 A per phase, as determined by a GIC analysis
of the System. Justification for this criterion is provided in the Screening Criterion for Transformer
Thermal Impact Assessment White Paper, 18 October 2017. A documented design specification
exceeding this value is also a justifiable threshold criterion that exempts a transformer from
Requirement R6.
The benchmark threshold criteria and its associated transformer thermal impact must be
evaluated on the basis of effective GIC. Refer to the white papers for additional information.
Requirement R7
Technical considerations for GMD mitigation planning, including operating and equipment
strategies, are available in Chapter 5 of the Geomagnetic Disturbance Planning Guide, 19
December 2013. Additional information is available in the 2012 Special Reliability Assessment
Interim Report: Effects of Geomagnetic Disturbances on the Bulk-Power System, 20 February 2012.
Requirement R8
The Geomagnetic Disturbance Planning Guide, 21 December 2013 developed by the NERC GMD
Task Force provides technical information on GMD-specific considerations for planning studies.
The supplemental GMD Vulnerability Assessment process is similar to the benchmark GMD
Vulnerability Assessment process described under Requirement R4.
Requirement R9
The supplemental thermal impact assessment specified of transformers in Requirement R10 is
based on GIC information for the supplemental GMD Event. This GIC information is determined
by the planning entity through simulation of the GIC System model and must be provided to the
entity responsible for conducting the thermal impact assessment. GIC information should be
provided in accordance with Requirement R9 each time the GMD Vulnerability Assessment is
performed since, by definition, the GMD Vulnerability Assessment includes a documented
evaluation of susceptibility to localized equipment damage due to GMD.
http://www.nerc.com/pa/comp/guidance/EROEndorsedImplementationGuidance/TPL-007-1_Transformer_Thermal_Impact_
Assessment_White_Paper.pdf.
17 http://www.nerc.com/pa/comp/guidance/Pages/default.aspx.
18 http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-Disturbance-Mitigation.aspx.
19 http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GMD%20Planning
%20Guide_approved.pdf.
20 http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2012GMD.pdf.
21 http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GMD%20Planning
%20Guide_approved.pdf.
16
Page 42 of 50
TPL-007-34 – Supplemental Material
The maximum effective GIC value provided in Part 9.1 is used for the supplemental thermal
impact assessment. Only those transformers that experience an effective GIC value of 85 A or
greater per phase require evaluation in Requirement R10.
GIC(t) provided in Part 9.2 is used to convert the steady state GIC flows to time-series GIC data
for the supplemental thermal impact assessment of transformers. This information may be
needed by one or more of the methods for performing a supplemental thermal impact
assessment. Additional information is in the following section.
The peak GIC value of 85 Amps per phase has been shown through thermal modeling to be a
conservative threshold below which the risk of exceeding known temperature limits established
by technical organizations is low.
Requirement R10
The supplemental thermal impact assessment of a power transformer may be based on
manufacturer-provided GIC capability curves, thermal response simulation, thermal impact
screening, or other technically justified means. Approaches for conducting the assessment are
presented in the Transformer Thermal Impact Assessment White Paper ERO Enterprise-Endorsed
Implementation Guidance 22 discussed in the Requirement R6 section above. A later version of the
Transformer Thermal Impact Assessment White Paper, 23 October 2017, has been developed to
include updated information pertinent to the supplemental GMD event and supplemental
thermal impact assessment.
Transformers are exempt from the supplemental thermal impact assessment requirement if the
effective GIC value for the transformer is less than 85 A per phase, as determined by a GIC analysis
of the System. Justification for this criterion is provided in the revised Screening Criterion for
Transformer Thermal Impact Assessment White Paper, 24 October 2017. A documented design
specification exceeding this value is also a justifiable threshold criterion that exempts a
transformer from Requirement R10.
The supplemental threshold criteria and its associated transformer thermal impact must be
evaluated on the basis of effective GIC. Refer to the white papers for additional information.
Requirement R11
Technical considerations for GIC monitoring are contained in Chapter 6 of the 2012 Special
Reliability Assessment Interim Report: Effects of Geomagnetic Disturbances on the Bulk-Power
System, 25 February 2012. GIC monitoring is generally performed by Hall effect transducers that
are attached to the neutral of the wye-grounded transformer. Data from GIC monitors is useful
for model validation and situational awareness.
http://www.nerc.com/pa/comp/guidance/EROEndorsedImplementationGuidance/TPL-007-1_Transformer_Thermal_Impact_
Assessment_White_Paper.pdf.
23 http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-Disturbance-Mitigation.aspx.
24 http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-Disturbance-Mitigation.aspx.
25 http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2012GMD.pdf.
22
Page 43 of 50
TPL-007-34 – Supplemental Material
Responsible entities consider the following in developing a process for obtaining GIC monitor
data:
•
Monitor locations. An entity's operating process may be constrained by location of
existing GIC monitors. However, when planning for additional GIC monitoring installations
consider that data from monitors located in areas found to have high GIC based on system
studies may provide more useful information for validation and situational awareness
purposes. Conversely, data from GIC monitors that are located in the vicinity of
transportation systems using direct current (e.g., subways or light rail) may be unreliable.
•
Monitor specifications. Capabilities of Hall effect transducers, existing and planned,
should be considered in the operating process. When planning new GIC monitor
installations, consider monitor data range (e.g., -500 A through + 500 A) and ambient
temperature ratings consistent with temperatures in the region in which the monitor will
be installed.
•
Sampling Interval. An entity's operating process may be constrained by capabilities of
existing GIC monitors. However, when possible specify data sampling during periods of
interest at a rate of 10 seconds or faster.
•
Collection Periods. The process should specify when the entity expects GIC data to be
collected. For example, collection could be required during periods where the Kp index is
above a threshold, or when GIC values are above a threshold. Determining when to
discontinue collecting GIC data should also be specified to maintain consistency in data
collection.
•
Data format. Specify time and value formats. For example, Greenwich Mean Time (GMT)
(MM/DD/YYYY HH:MM:SS) and GIC Value (Ampere). Positive (+) and negative (-) signs
indicate direction of GIC flow. Positive reference is flow from ground into transformer
neutral. Time fields should indicate the sampled time rather than system or SCADA time
if supported by the GIC monitor system.
•
Data retention. The entity's process should specify data retention periods, for example 1
year. Data retention periods should be adequately long to support availability for the
entity's model validation process and external reporting requirements, if any.
•
Additional information. The entity's process should specify collection of other
information necessary for making the data useful, for example monitor location and type
of neutral connection (e.g., three-phase or single-phase).
Requirement R12
Magnetometers measure changes in the earth's magnetic field. Entities should obtain data from
the nearest accessible magnetometer. Sources of magnetometer data include:
Page 44 of 50
TPL-007-34 – Supplemental Material
•
Observatories such as those operated by U.S. Geological Survey and Natural Resources
Canada, see figure below for locations: 26
•
•
Research institutions and academic universities;
Entities with installed magnetometers.
Entities that choose to install magnetometers should consider equipment specifications and data
format protocols contained in the latest version of the INTERMAGNET Technical Reference
Manual, Version 4.6, 2012. 27
26
27
http://www.intermagnet.org/index-eng.php.
http://www.intermagnet.org/publications/intermag_4-6.pdf.
Page 45 of 50
TPL-007-34 – Supplemental Material
Rationale
During development of TPL-007-1, text boxes were embedded within the standard to explain the
rationale for various parts of the standard. The text from the rationale text boxes was moved to
this section upon approval of TPL-007-1 by the NERC Board of Trustees. In developing TPL-007-2,
the SDT has made changes to the sections below only when necessary for clarity. Changes are
marked with brackets [ ].
Rationale for Applicability:
Instrumentation transformers and station service transformers do not have significant impact on
geomagnetically-induced current (GIC) flows; therefore, these transformers are not included in
the applicability for this standard.
Terminal voltage describes line-to-line voltage.
Rationale for R1:
In some areas, planning entities may determine that the most effective approach to conduct a
GMD Vulnerability Assessment is through a regional planning organization. No requirement in
the standard is intended to prohibit a collaborative approach where roles and responsibilities are
determined by a planning organization made up of one or more Planning Coordinator(s).
Rationale for R2:
A GMD Vulnerability Assessment requires a GIC System model to calculate GIC flow which is used
to determine transformer Reactive Power absorption and transformer thermal response.
Guidance for developing the GIC System model is provided in the Application Guide Computing
Geomagnetically-Induced Current in the Bulk-Power System, 28 December 2013, developed by the
NERC GMD Task Force.
The System model specified in Requirement R2 is used in conducting steady state power flow
analysis that accounts for the Reactive Power absorption of power transformer(s) due to GIC in
the System.
The GIC System model includes all power transformer(s) with a high side, wye-grounded winding
with terminal voltage greater than 200 kV. The model is used to calculate GIC flow in the network.
The projected System condition for GMD planning may include adjustments to the System that
are executable in response to space weather information. These adjustments could include, for
example, recalling or postponing maintenance outages.
The Violation Risk Factor (VRF) for Requirement R2 is changed from Medium to High. This change
is for consistency with the VRF for approved standard TPL-001-4 Requirement R1, which is
proposed for revision in the NERC filing dated August 29, 2014 (Docket No. RM12-1-000). NERC
guidelines require consistency among Reliability Standards.
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GIC%20Application
%20Guide%202013_approved.pdf.
28
Page 46 of 50
TPL-007-34 – Supplemental Material
Rationale for R3:
Requirement R3 allows a responsible entity the flexibility to determine the System steady state
voltage criteria for System steady state performance in Table 1. Steady state voltage limits are
an example of System steady state performance criteria.
Rationale for R4:
The GMD Vulnerability Assessment includes steady state power flow analysis and the supporting
study or studies using the models specified in Requirement R2 that account for the effects of GIC.
Performance criteria are specified in Table 1.
At least one System On-Peak Load and at least one System Off-Peak Load must be examined in
the analysis.
Distribution of GMD Vulnerability Assessment results provides a means for sharing relevant
information with other entities responsible for planning reliability. Results of GIC studies may
affect neighboring systems and should be taken into account by planners.
The Geomagnetic Disturbance Planning Guide, 29 December 2013 developed by the NERC GMD
Task Force provides technical information on GMD-specific considerations for planning studies.
The provision of information in Requirement R4, Part 4.3, shall be subject to the legal and
regulatory obligations for the disclosure of confidential and/or sensitive information.
Rationale for R5:
This GIC information is necessary for determining the thermal impact of GIC on transformers in
the planning area and must be provided to entities responsible for performing the thermal impact
assessment so that they can accurately perform the assessment. GIC information should be
provided in accordance with Requirement R5 as part of the GMD Vulnerability Assessment
process since, by definition, the GMD Vulnerability Assessment includes documented evaluation
of susceptibility to localized equipment damage due to GMD.
The maximum effective GIC value provided in Part 5.1 is used for transformer thermal impact
assessment.
GIC(t) provided in Part 5.2 can alternatively be used to convert the steady state GIC flows to timeseries GIC data for transformer thermal impact assessment. This information may be needed by
one or more of the methods for performing a thermal impact assessment. Additional guidance is
available in the Transformer Thermal Impact Assessment White Paper, 30 October 2017.
A Transmission Owner or Generator Owner that desires GIC(t) may request it from the planning
entity. The planning entity shall provide GIC(t) upon request once GIC has been calculated, but
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GMD%20Planning
%20Guide_approved.pdf.
30 http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-Disturbance-Mitigation.aspx.
29
Page 47 of 50
TPL-007-34 – Supplemental Material
no later than 90 calendar days after receipt of a request from the owner and after completion of
Requirement R5, Part 5.1.
The provision of information in Requirement R5 shall be subject to the legal and regulatory
obligations for the disclosure of confidential and/or sensitive information.
Rationale for R6:
The transformer thermal impact screening criterion has been revised from 15 A per phase to 75
A per phase [for the benchmark GMD event]. Only those transformers that experience an
effective GIC value of 75 A per phase or greater require evaluation in Requirement R6. The
justification is provided in the Screening Criterion for Transformer Thermal Impact Assessment
White Paper, 31 October 2017.
The thermal impact assessment may be based on manufacturer-provided GIC capability curves,
thermal response simulation, thermal impact screening, or other technically justified means. The
transformer thermal assessment will be repeated or reviewed using previous assessment results
each time the planning entity performs a GMD Vulnerability Assessment and provides GIC
information as specified in Requirement R5. Approaches for conducting the assessment are
presented in the Transformer Thermal Impact Assessment White Paper, 32 October 2017.
Thermal impact assessments are provided to the planning entity, as determined in Requirement
R1, so that identified issues can be included in the GMD Vulnerability Assessment (R4), and the
Corrective Action Plan (R7) as necessary.
Thermal impact assessments of non-BES transformers are not required because those
transformers do not have a wide-area effect on the reliability of the interconnected Transmission
system.
The provision of information in Requirement R6, Part 6.4, shall be subject to the legal and
regulatory obligations for the disclosure of confidential and/or sensitive information.
Rationale for R7:
The proposed requirement addresses directives in Order No. 830 for establishing Corrective
Action Plan (CAP) deadlines associated with GMD Vulnerability Assessments. In Order No. 830,
FERC directed revisions to TPL-007 such that CAPs are developed within one year from the
completion of GMD Vulnerability Assessments (P 101). Furthermore, FERC directed
establishment of implementation deadlines after the completion of the CAP as follows (P 102):
•
Two years for non-hardware mitigation; and
•
Four years for hardware mitigation.
The objective of Part 7.4 is to provide awareness to potentially impacted entities when
implementation of planned mitigation is not achievable within the deadlines established in Part
31
32
http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-Disturbance-Mitigation.aspx.
http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-Disturbance-Mitigation.aspx.
Page 48 of 50
TPL-007-34 – Supplemental Material
7.3. Examples of situations beyond the control of the of the responsible entity (see Section 7.4)
include, but are not limited to:
•
Delays resulting from regulatory/legal processes, such as permitting;
•
Delays resulting from stakeholder processes required by tariff;
•
Delays resulting from equipment lead times; or
Delays resulting from the inability to acquire necessary Right-of-Way.
Rationale for Table 3:
Table 3 has been revised to use the same ground model designation, FL1, as is being used by
USGS. The calculated scaling factor for FL1 is 0.74. [The scaling factor associated with the
benchmark GMD event for the Florida earth model (FL1) has been updated to 0.76 in TPL-007-2
based on the earth model published on the USGS public website.]
Rationale for R8 – R10:
The proposed requirements address directives in Order No. 830 for revising the benchmark GMD
event used in GMD Vulnerability Assessments (P 44, P 47-49). The requirements add a
supplemental GMD Vulnerability Assessment based on the supplemental GMD event that
accounts for localized peak geoelectric fields.
Rationale for R11 – R12:
The proposed requirements address directives in Order No. 830 for requiring responsible
entities to collect GIC monitoring and magnetometer data as necessary to enable model
validation and situational awareness (P 88; P. 90-92). GMD measurement data refers to GIC
monitor data and geomagnetic field data in Requirements R11 and R12, respectively. See the
Guidelines and Technical Basis section of this standard for technical information.
The objective of Requirement R11 is for entities to obtain GIC data for the Planning
Coordinator's planning area or other part of the system included in the Planning Coordinator's
GIC System model to inform GMD Vulnerability Assessments. Technical considerations for GIC
monitoring are contained in Chapter 9 of the 2012 Special Reliability Assessment Interim
Report: Effects of Geomagnetic Disturbances on the Bulk-Power System (NERC 2012 GMD
Report). GIC monitoring is generally performed by Hall effect transducers that are attached to
the neutral of the transformer and measure dc current flowing through the neutral.
The objective of Requirement R12 is for entities to obtain geomagnetic field data for the
Planning Coordinator's planning area to inform GMD Vulnerability Assessments.
Magnetometers provide geomagnetic field data by measuring changes in the earth's magnetic
field. Sources of geomagnetic field data include:
•
Observatories such as those operated by U.S. Geological Survey, Natural Resources
Canada, research organizations, or university research facilities;
•
Installed magnetometers; and
•
Commercial or third-party sources of geomagnetic field data.
Page 49 of 50
TPL-007-34 – Supplemental Material
Geomagnetic field data for a Planning Coordinator’s planning area is obtained from one or
more of the above data sources located in the Planning Coordinator’s planning area, or by
obtaining a geomagnetic field data product for the Planning Coordinator’s planning area from a
government or research organization. The geomagnetic field data product does not need to be
derived from a magnetometer or observatory within the Planning Coordinator’s planning area.
Page 50 of 50
Exhibit B
Implementation Plan
RELIABILITY | RESILIENCE | SECURITY
Implementation Plan
Project 2019-01 Modifications to TPL-007-3
Applicable Standard
•
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Requested Retirement
•
TPL-007-3 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Prerequisite Standard
None
Applicable Entities
•
Planning Coordinator with a planning area that includes a Facility or Facilities specified in Section 4.2 of
the standard;
•
Transmission Planner with a planning area that includes a Facility or Facilities specified in Section 4.2 of
the standard;
•
Transmission Owner who owns a Facility or Facilities specified in Section 4.2 of the standard; and
•
Generator Owner who owns a Facility or Facilities specified in Section 4.2 of the standard.
Section 4.2 states that the standard applies to facilities that include power transformer(s) with a high-side,
wye-grounded winding with terminal voltage greater than 200 kV.
Terms in the NERC Glossary of Terms
There are no new, modified, or retired terms.
Background
On November 15, 2018, the Federal Energy Regulatory Commission (FERC) issued Order No. 851 approving
Reliability Standard TPL-007-2 and its associated implementation plan. In the order, FERC also directed
NERC to develop certain modifications to the standard. FERC established a deadline of 12 months from the
effective date of Reliability Standard TPL-007-2 to submit a revised standard (July 1, 2020).
On February 7, 2019, the NERC Board of Trustees adopted Reliability Standard TPL-007-3, which added a
Variance option for applicable entities in Canadian jurisdictions. No continent-wide requirements were
changed. Under the terms of its implementation plan, Reliability Standard TPL-007-3 became effective in
the United States on July 1, 2019. All phased-in compliance dates from the TPL-007-2 implementation plan
were carried forward unchanged in the TPL-007-3 implementation plan.
RELIABILITY | RESILIENCE | SECURITY
General Considerations
This implementation plan is intended to integrate the new and revised requirements in TPL-007-4 in the
existing timeframe under the TPL-007-3 implementation plan.
Effective Date
The effective date for the proposed Reliability Standard is provided below. Where the standard drafting
team identified the need for a longer implementation period for compliance with a particular section of
the proposed Reliability Standard (e.g., an entire Requirement or a portion thereof), the additional time for
compliance with that section is specified below. These phased-in compliance dates represent the dates
that entities must begin to comply with that particular section of the Reliability Standard, even where the
Reliability Standard goes into effect at an earlier date.
Reliability Standard TPL-007-4
Where approval by an applicable governmental authority is required, the standard shall become effective
on the first day of the first calendar quarter that is six (6) months after the effective date of the applicable
governmental authority’s order approving the standard, or as otherwise provided for by the applicable
governmental authority.
Where approval by an applicable governmental authority is not required, the standard shall become
effective on the first day of the first calendar quarter that is six (6) months after the date the standard is
adopted by the NERC Board of Trustees, or as otherwise provided for in that jurisdiction.
Phased-In Compliance Dates
Compliance Date for TPL-007-4 Requirements R1, R2, R5, and R9
Entities shall be required to comply with Requirements R1, R2, R5, and R9 upon the effective date of
Reliability Standard TPL-007-4.
Compliance Date for TPL-007-4 Requirements R12 and R13
Entities shall not be required to comply with Requirements R12 and R13 until the later of: (i) July 1, 2021;
or (ii) the effective date of Reliability Standard TPL-007-4.
Compliance Date for TPL-007-4 Requirements R6 and R10
Entities shall not be required to comply with Requirements R6 and R10 until the later of: (i) January 1,
2022; or (ii) the effective date of Reliability Standard TPL-007-4.
Compliance Date for TPL-007-4 Requirements R3, R4, and R8
Entities shall not be required to comply with Requirements R3, R4, and R8 until the later of: (i) January 1,
2023; or (ii) the effective date of Reliability Standard TPL-007-4.
Compliance Date for TPL-007-4 Requirement R7
Entities shall not be required to comply with Requirement R7 until the later of: (i) January 1, 2024; or (ii)
the effective date of Reliability Standard TPL-007-4.
Implementation Plan
Project 2019-01 Modifications to TPL-007-3 | November 2019
2
Compliance Date for TPL-007-4 Requirement R11
Entities shall not be required to comply with Requirement R11 until the later of: (i) January 1, 2024; or (ii)
six (6) months after the effective date of Reliability Standard TPL-007-4.
Retirement Date
Standard TPL-007-3
Reliability Standard TPL-007-3 shall be retired immediately prior to the effective date of TPL-007-4 in the
particular jurisdiction in which the revised standard is becoming effective.
Initial Performance of Periodic Requirements
Transmission Owners and Generator Owners are not required to comply with Requirement R6 prior to the
compliance date for Requirement R6, regardless of when geomagnetically-induced current (GIC) flow
information specified in Requirement R5, Part 5.1 is received.
Transmission Owners and Generator Owners are not required to comply with Requirement R10 prior to
the compliance date for Requirement R10, regardless of when GIC flow information specified in
Requirement R9, Part 9.1 is received.
Implementation Plan
Project 2019-01 Modifications to TPL-007-3 | November 2019
3
Exhibit C
Analysis of Violation Risk Factors and Violation Severity Levels
RELIABILITY | RESILIENCE | SECURITY
Violation Risk Factor and Violation Severity Level Justification
Project 2019-01 Modifications to TPL-007-3
This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in TPL-007-4. Each requirement is assigned a VRF and a VSL. These elements support the determination of
an initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as defined in
the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the following NERC criteria and FERC Guidelines when
developing the VRFs and VSLs for the requirements.
NERC Criteria for Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.
RELIABILITY | RESILIENCE | SECURITY
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical state
or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that is
administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or restorative
conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric System, or the
ability to effectively monitor, control, or restore the Bulk Electric System.
FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report
FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•
Emergency operations
•
Vegetation management
•
Operator personnel training
•
Protection systems and their coordination
•
Operating tools and backup facilities
•
Reactive power and voltage control
•
System modeling and data exchange
•
Communication protocol and facilities
•
Requirements to determine equipment ratings
•
Synchronized data recorders
•
Clearer criteria for operationally critical facilities
•
Appropriate use of transmission loading relief.
VRF and VSL Justifications
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Guideline (2) – Consistency within a Reliability Standard
FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.
Guideline (3) – Consistency among Reliability Standards
FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards would
be treated comparably.
Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.
Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability Standard.
VRF and VSL Justifications
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NERC Criteria for Violation Severity Levels
VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and may
have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL
Moderate VSL
The performance or product
measured almost meets the full
intent of the requirement.
The performance or product
measured meets the majority of
the intent of the requirement.
High VSL
The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.
Severe VSL
The performance or product
measured does not
substantively meet the intent of
the requirement.
FERC Order of Violation Severity Levels
The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard meet
the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance
Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than was
required when levels of non-compliance were used.
Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
VRF and VSL Justifications
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Guideline (4) – Violation Severity Level Assignment Should Be Based on A Single Violation, Not on A Cumulative Number of
Violations
Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | November 2019
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VRF Justification for TPL-007-4, Requirement R1
The VRF did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R1
The VSL did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VRF Justification for TPL-007-4, Requirement R2
The VRF did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R2
The VSL did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VRF Justification for TPL-007-4, Requirement R3
The VRF did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R3
The VSL did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VRF Justification for TPL-007-4, Requirement R4
The VRF did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R4
The VSL did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VRF Justification for TPL-007-4, Requirement R5
The VRF did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R5
The VSL did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VRF Justification for TPL-007-4, Requirement R6
The VRF did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | November 2019
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VSL Justification for TPL-007-4, Requirement R6
The VSL did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VRF Justification for TPL-007-4, Requirement R7
The VRF did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R7
The VSL did not substantively change from the TPL-007-3 Reliability Standard or FERC-approved TPL-007-2 Reliability Standard. In the Severe
VSL, the word “have” was replaced with “develop” to more closely reflect the language of the Requirement.
VRF Justification for TPL-007-4, Requirement R8
The VRF did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R8
The justification is provided on the following pages.
VRF Justification for TPL-007-4, Requirement R9
The VRF did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R9
The VSL did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VRF Justification for TPL-007-4, Requirement R10
The VRF did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R10
The VSL did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VRF Justification for TPL-007-4, Requirement R11
The justification is provided on the following pages.
VSL Justification for TPL-007-4, Requirement R11
The justification is provided on the following pages.
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | November 2019
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VRF Justification for TPL-007-4, Requirement R12
Requirement R12 was previously Requirement R11 in TPL-007-3. The VRF did not change from the TPL-007-3 Reliability Standard or the FERCapproved TPL-007-2 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R12
Requirement R12 was previously Requirement R11 in TPL-007-3. The VSL did not change from the TPL-007-3 Reliability Standard or the FERCapproved TPL-007-2 Reliability Standard.
VRF Justification for TPL-007-4, Requirement R13
Requirement R13 was previously Requirement R12 in TPL-007-3. The VRF did not change from the TPL-007-3 Reliability Standard or the FERCapproved TPL-007-2 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R13
Requirement R13 was previously Requirement R12 in TPL-007-3. The VSL did not change from the TPL-007-3 Reliability Standard or the FERCapproved TPL-007-2 Reliability Standard.
VRF and VSL Justifications
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VSLs for TPL-007-4, Requirement R8
Lower
Moderate
High
The responsible entity
completed a supplemental GMD
Vulnerability Assessment, but it
was more than 60 calendar
months and less than or equal
to 64 calendar months since the
last supplemental GMD
Vulnerability Assessment.
The responsible entity’s
completed supplemental GMD
Vulnerability Assessment failed
to satisfy one of elements listed
in Requirement R8, Parts 8.1
through 8.3;
OR
The responsible entity’s
completed supplemental GMD
Vulnerability Assessment failed
to satisfy two of the elements
listed in Requirement R8, Parts
8.1 through 8.3;
OR
The responsible entity
completed a supplemental GMD
Vulnerability Assessment, but it
was more than 64 calendar
months and less than or equal
to 68 calendar months since the
last supplemental GMD
Vulnerability Assessment.
The responsible entity
completed a supplemental GMD
Vulnerability Assessment, but it
was more than 68 calendar
months and less than or equal
to 72 calendar months since the
last supplemental GMD
Vulnerability Assessment.
Severe
The responsible entity’s
completed supplemental GMD
Vulnerability Assessment failed
to satisfy three of the elements
listed in Requirement R8, Parts
8.1 through 8.3;
OR
The responsible entity
completed a supplemental GMD
Vulnerability Assessment, but it
was more than 72 calendar
months since the last
supplemental GMD Vulnerability
Assessment;
OR
The responsible entity does not
have a completed supplemental
GMD Vulnerability Assessment.
VRF and VSL Justifications
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VSL Justifications for TPL-007-4, Requirement R8
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency
in the Determination of
Penalties
The proposed VSLs retain the VSLs from the TPL-007-3 Reliability Standard, approved by FERC in TPL-0072, with the exception of removing one part of the lower VSL to reflect the removal of subpart 8.3 in
proposed TPL-007-4. As a result, the proposed VSLs do not lower the current level of compliance.
The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting
uniformity and consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | November 2019
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FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
Each VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | November 2019
11
VSLs for TPL-007-4, Requirement R11
Lower
The responsible entity’s
Corrective Action Plan failed to
comply with one of the
elements in Requirement R11,
Parts 11.1 through 11.5.
Moderate
The responsible entity’s
Corrective Action Plan failed to
comply with two of the
elements in Requirement R11,
Parts 11.1 through 11.5.
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | November 2019
High
The responsible entity’s
Corrective Action Plan failed to
comply with three of the
elements in Requirement R11,
Parts 11.1 through 11.5.
Severe
The responsible entity’s
Corrective Action Plan failed to
comply with four or more of the
elements in Requirement R11,
Parts 11.1 through 11.5;
OR
The responsible entity did not
develop a Corrective Action Plan
as required by Requirement
R11.
12
VSL Justifications for TPL-007-4, Requirement R11
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency
in the Determination of
Penalties
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of
lowering the level of compliance. Further, the VSLs are consistent with those assigned for Requirement R7,
pertaining to Corrective Action Plans for benchmark GMD Vulnerability Assessments.
The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting
uniformity and consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VRF and VSL Justifications
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VSL Justifications for TPL-007-4, Requirement R11
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
Each VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
VRF Justifications for TPL-007-4, Requirement R11
Proposed VRF
Lower
NERC VRF Discussion
A VRF of High is being proposed for this requirement.
FERC VRF G1 Discussion
N/A
Guideline 1- Consistency
with Blackout Report
FERC VRF G2 Discussion
Guideline 2- Consistency
within a Reliability Standard
The proposed VRF is consistent among other FERC approved VRFs within the standard, specifically
Requirement R7 pertaining to Corrective Action Plans for benchmark GMD Vulnerability Assessments.
VRF and VSL Justifications
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VRF Justifications for TPL-007-4, Requirement R11
Proposed VRF
Lower
FERC VRF G3 Discussion
A VRF of High is consistent with Reliability Standard TPL‐001‐4 Requirement R2 which requires
Transmission Planners and Planning Coordinators to include a Corrective Action Plan that addresses
identified performance issues in the annual Planning Assessment.
Guideline 3- Consistency
among Reliability Standards
FERC VRF G4 Discussion
Guideline 4- Consistency
with NERC Definitions of
VRFs
FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Comingle More than One
Obligation
The VRF of High is consistent with the NERC VRF Definition. Failure to develop a Corrective Action Plan
that addresses issues identified in a supplemental GMD Vulnerability Assessment could place the Bulk
Electric System at an unacceptable risk of instability, separation, or cascading failures.
This requirement does not co‐mingle a higher‐risk reliability objective with a lesser‐ risk reliability
objective.
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | November 2019
15
Exhibit D
Technical Rationale
RELIABILITY | RESILIENCE | SECURITY
Transmission System
Planned Performance for
Geomagnetic Disturbance
Events
Technical Rationale and Justification for
Reliability Standard TPL-007-4
November 2019
RELIABILITY | RESILIENCE | SECURITY
NERC | Report Title | Report Date
I
Table of Contents
Preface ....................................................................................................................................................................... iii
Introduction ............................................................................................................................................................... iv
Background ............................................................................................................................................................ iv
General Considerations ..............................................................................................................................................1
Rationale for Applicability.......................................................................................................................................1
Benchmark GMD Event (TPL-007-4 Attachment 1) .................................................................................................1
Supplemental GMD Event (TPL-007-4 Attachment 1) .............................................................................................1
Requirement R2..........................................................................................................................................................2
Requirement R4..........................................................................................................................................................3
Requirement R5..........................................................................................................................................................4
Requirement R6..........................................................................................................................................................5
Requirement R7..........................................................................................................................................................6
Supplemental GMD Vulnerability Assessment ...........................................................................................................7
Requirement R8..........................................................................................................................................................8
Requirement R9..........................................................................................................................................................9
Requirement R10..................................................................................................................................................... 10
Requirement R11..................................................................................................................................................... 11
Requirement R12..................................................................................................................................................... 12
Requirement R13..................................................................................................................................................... 13
References ............................................................................................................................................................... 14
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
ii
Preface
Electricity is a key component of the fabric of modern society and the Electric Reliability Organization (ERO)
Enterprise serves to strengthen that fabric. The vision for the ERO Enterprise, which is comprised of the North
American Electric Reliability Corporation (NERC) and the six Regional Entities (REs), is a highly reliable and secure
North American bulk power system (BPS). Our mission is to assure the effective and efficient reduction of risks to
the reliability and security of the grid.
Reliability | Resilience | Security
Because nearly 400 million citizens in North America are counting on us
The North American BPS is divided into six RE boundaries as shown in the map and corresponding table below.
The multicolored area denotes overlap as some load-serving entities participate in one Region while associated
Transmission Owners/Operators participate in another.
MRO
Midwest Reliability Organization
NPCC
Northeast Power Coordinating Council
RF
ReliabilityFirst
SERC
SERC Reliability Corporation
Texas RE
Texas Reliability Entity
WECC
Western Electricity Coordinating Council
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
iii
Introduction
Background
This document explains the technical rationale and justification for the proposed Reliability Standard TPL-007-4 –
Transmission System Planned Performance for Geomagnetic Disturbance Events. It provides stakeholders and the
ERO Enterprise with an understanding of the technical requirements in the Reliability Standard. It also contains
information on the standard drafting team’s intent in drafting the requirements. This document, the Technical
Rationale and Justification for TPL-007-4, is not a Reliability Standard and should not be considered mandatory
and enforceable.
The first version of the standard, TPL-007-1, approved by FERC in Order No. 779 [1], requires entities to assess the
impact to their systems from a defined event referred to as the “Benchmark GMD Event.” The second version of
the standard, TPL-007-2, adds new Requirements R8, R9, and R10 to require responsible entities to assess the
potential implications of a “Supplemental GMD Event” on their equipment and systems in accordance with FERC’s
directives in Order No. 830 [2]. Some GMD events have shown localized enhancements of the geomagnetic field.
The supplemental GMD event was developed to represent conditions associated with such localized enhancement
during a severe GMD event for use in a GMD Vulnerability Assessment. The third version of the standard, TPL007-3, adds a Canadian variance for Canadian Registered Entities to leverage operating experience, observed GMD
effects, and on-going research efforts for defining alternative Benchmark GMD Events and/or Supplemental GMD
Events that appropriately reflect Canadian-specific geographical and geological characteristics. No continent-wide
requirements were changed between the second and the third versions of the standard. The fourth version of the
standard, TPL-007-4, addresses the directives issued by FERC in Order No. 851 [3] to modify Reliability Standard
TPL-007-3. FERC directed NERC to submit modifications to: (1) require the development and implementation of
corrective action plans to mitigate assessed supplemental GMD event vulnerabilities (P 29); and (2) to replace the
corrective action plan time-extension provision in TPL-007-3 with a process through which extensions of time are
considered on a case-by-case basis (P 54).
The requirements in this standard cover various aspects of the GMD Vulnerability Assessment process. Figure 1
provides an overall view of the GMD Vulnerability Assessment process:
Figure 1. GMD Vulnerability Assessment Process.
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
iv
General Considerations
Rationale for Applicability
Reliability Standard TPL-007-4 is applicable to Facilities that include power transformer(s) with a high side, wyegrounded winding with terminal voltage greater than 200 kV.
Instrumentation transformers and station service transformers do not have significant impact on geomagneticallyinduced current (GIC) flows; therefore, these types of transformers are not included in the applicability for this
standard. Terminal voltage describes line-to-line voltage.
Benchmark GMD Event (TPL-007-4 Attachment 1)
The benchmark GMD event defines the geoelectric field values used to compute GIC flows that are needed to
conduct a benchmark GMD Vulnerability Assessment. The Benchmark Geomagnetic Disturbance Event
Description, May 2016 [4], includes the event description, analysis, and example calculations.
Supplemental GMD Event (TPL-007-4 Attachment 1)
The supplemental GMD event defines the geoelectric field values used to compute GIC flows that are needed to
conduct a supplemental GMD Vulnerability Assessment. The Supplemental Geomagnetic Disturbance Event
Description, October 2017 [5], includes the event description and analysis.
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
1
Requirement R2
A GMD Vulnerability Assessment requires a GIC System model, which is a dc representation of the System, to
calculate GIC flow. In a GMD Vulnerability Assessment, GIC simulations are used to determine transformer
Reactive Power absorption and transformer thermal response. Guidance for developing the GIC System model are
provided in the Application Guide – Computing Geomagnetically-Induced Current in the Bulk-Power System,
December 2013 [6].
System models specified in Requirement R2 are used in conducting steady state power flow analysis, that accounts
for the Reactive Power absorption of power transformer(s) due to GIC flow in the System, when performing GMD
Vulnerability Assessments. Additional System modeling considerations could include facilities less than 200 kV.
The GIC System model includes all power transformer(s) with a high side, wye-grounded winding with terminal
voltage greater than 200 kV. The model is used to calculate GIC flow in the network.
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
2
Requirement R4
The Geomagnetic Disturbance Planning Guide, December 2013 [7], provides technical information on GMDspecific considerations for planning studies.
The GMD Vulnerability Assessment includes steady state power flow analysis and the supporting study or studies
using the models specified in Requirement R2 that account for the effects of GIC. Performance criteria are
specified in Table 1: Steady State Planning GMD Event found in TPL-007-4. At least one System On-Peak Load and
at least one System Off-Peak Load shall be included in the in the study or studies (see Requirement R4).
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
3
Requirement R5
The benchmark thermal impact assessment of transformers, specified in Requirement R6, is based on GIC
information for the benchmark GMD Event. This GIC information is determined by the responsible entity through
simulation of the GIC System model and shall be provided to the entity responsible for conducting the thermal
impact assessment (see Requirement R5). GIC information for the benchmark thermal impact assessment should
be provided in accordance with Requirement R5 each time the benchmark GMD Vulnerability Assessment is
performed since, by definition, the GMD Vulnerability Assessment includes a documented evaluation of
susceptibility to localized equipment damage due to GMD.
The peak GIC value of 75 A per phase, in the benchmark GMD Vulnerability Assessment, has been shown through
thermal modeling to be a conservative threshold below which the risk of exceeding known temperature limits
established by technical organizations is low.
This GIC information is necessary for determining the benchmark thermal impact of GIC on transformers in the
planning area and shall be provided to entities responsible for performing the thermal impact assessment so that
they can accurately perform the assessment (see Requirement R5). GIC information should be provided in
accordance with Requirement R5 as part of the benchmark GMD Vulnerability Assessment process since, by
definition, the GMD Vulnerability Assessment includes documented evaluation of susceptibility to localized
equipment damage due to GMD.
GIC(t) provided in Part 5.2 can be used to convert the steady state GIC flows to time-series GIC data for the
benchmark transformer thermal impact assessment. This information may be needed by one or more of the
methods for performing a thermal impact assessment. Additional guidance is available in the Transformer Thermal
Impact Assessment White Paper, October 2017 [8].
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
4
Requirement R6
The transformer thermal assessment will be repeated or reviewed using previous assessment results each time
the responsible entity performs a GMD Vulnerability Assessment and provides GIC information as specified in
Requirement R5.
Thermal assessments for transformers with a high side, grounded-wye winding greater than 200 kV are required
because the damage of these types of transformers may have an effect on the wide-area reliability of the
interconnected Transmission System.
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
5
Requirement R7
This requirement addresses directives in FERC Order No. 851 to replace the time-extension provision in
Requirement R7.4 of TPL-007-2 (and TPL-007-3) with a process through which extensions of time are considered
on a case-by-case basis.
Technical considerations for GMD mitigation planning, including operating and equipment strategies, are available
in Chapter 5 of the Geomagnetic Disturbance Planning Guide, December 2013 [7]. Additional information is
available in the 2012 Special Reliability Assessment Interim Report: Effects of Geomagnetic Disturbances on the
Bulk Power System, February 2012 [9].
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
6
Supplemental GMD Vulnerability Assessment
The requirements, R8-R11, address directives in FERC Order No. 830 for revising the benchmark GMD event used
in GMD Vulnerability Assessments (PP 44, 47-49). The requirements add a supplemental GMD Vulnerability
Assessment based on the supplemental GMD event that accounts for localized peak geoelectric fields.
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
7
Requirement R8
The Geomagnetic Disturbance Planning Guide, December 2013 [7], provides technical information on GMDspecific considerations for planning studies.
The GMD Vulnerability Assessment includes steady state power flow analysis and the supporting study or studies
using the models specified in Requirement R2 that account for the effects of GIC. Performance criteria are
specified in Table 1: Steady State Planning GMD Event found in TPL-007-4. At least one System On-Peak Load and
at least one System Off-Peak Load shall be included in the study or studies (see Requirement R8).
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
8
Requirement R9
The supplemental thermal impact assessment of transformers, specified in Requirement R10, is based on GIC
information for the supplemental GMD Event. This GIC information is determined by the responsible entity
through simulation of the GIC System model and shall be provided to the entity responsible for conducting the
thermal impact assessment (see Requirement R9). GIC information for the supplemental thermal impact
assessment should be provided in accordance with Requirement R9 each time the supplemental GMD
Vulnerability Assessment is performed since, by definition, the GMD Vulnerability Assessment includes a
documented evaluation of susceptibility to localized equipment damage due to GMD.
The peak GIC value of 85 A per phase, in the supplemental GMD Vulnerability Assessment, has been shown
through thermal modeling to be a conservative threshold below which the risk of exceeding known temperature
limits established by technical organizations is low.
This GIC information is necessary for determining the supplemental thermal impact of GIC on transformers in the
planning area and shall be provided to entities responsible for performing the thermal impact assessment so that
they can accurately perform the assessment (see Requirement R9). GIC information should be provided in
accordance with Requirement R9 as part of the supplemental GMD Vulnerability Assessment process since, by
definition, the GMD Vulnerability Assessment includes documented evaluation of susceptibility to localized
equipment damage due to GMD.
GIC(t) provided in Part 9.2 can be used to convert the steady state GIC flows to time-series GIC data for the
supplemental transformer thermal impact assessment. This information may be needed by one or more of the
methods for performing a thermal impact assessment. Additional guidance is available in the Transformer Thermal
Impact Assessment White Paper, October 2017 [8].
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
9
Requirement R10
The supplemental thermal impact assessment of a power transformer may be based on manufacturer-provided
GIC capability curves, thermal response simulation, thermal impact screening, or other technically justified means.
Justification for this criterion is provided in the Screening Criterion for Transformer Thermal Impact Assessment
White Paper, October 2017 [10].
The transformer thermal assessment will be repeated or reviewed using previous assessment results each time
the responsible entity performs a GMD Vulnerability Assessment and provides GIC information as specified in
Requirement R9.
Thermal assessments for transformers with a high side, grounded-wye winding greater than 200 kV are required
because the damage of these types of transformers may have an effect on the wide-area reliability of the
interconnected Transmission System.
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
10
Requirement R11
The requirement addresses directives in FERC Order No. 851 to develop and submit modifications to Reliability
Standard TPL-007-2 (and TPL-007-3) to require corrective action plans for the assessed supplemental GMD event
vulnerabilities.
Technical considerations for GMD mitigation planning, including operating and equipment strategies, are available
in Chapter 5 of the Geomagnetic Disturbance Planning Guide, December 2013 [7]. Additional information is
available in the 2012 Special Reliability Assessment Interim Report: Effects of Geomagnetic Disturbances on the
Bulk Power System, February 2012 [9].
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
11
Requirement R12
GMD measurement data refers to GIC monitor data and geomagnetic field data in Requirements R12 and R13,
respectively. This requirement addresses directives in FERC Order No. 830 for requiring responsible entities to
collect GIC monitoring data as necessary to enable model validation and situational awareness (PP 88, 90-92).
Technical considerations for GIC monitoring are contained in Chapter 9 of the 2012 Special Reliability Assessment
Interim Report: Effects of Geomagnetic Disturbances on the Bulk Power System, February 2012 [9]. GIC monitoring
is generally performed by Hall effect transducers that are attached to the neutral of the wye-grounded
transformer and measure dc current flowing through the neutral. Data from GIC monitors is useful for model
validation and situational awareness.
The objective of Requirement R12 is for entities to obtain GIC data for the Planning Coordinator’s planning area
or other part of the system included in the Planning Coordinator’s GIC System model to inform GMD Vulnerability
Assessments. Technical considerations for GIC monitoring are contained in Chapter 9 of the 2012 Special Reliability
Assessment Interim Report: Effects of Geomagnetic Disturbances on the Bulk Power System, February 2012 [9].
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
12
Requirement R13
GMD measurement data refers to GIC monitor data and geomagnetic field data in Requirements R12 and R13,
respectively. This requirement addresses directives in FERC Order No. 830 for requiring responsible entities to
collect magnetometer data as necessary to enable model validation and situational awareness (PP 88, 90-92).
The objective of Requirement R13 is for entities to obtain geomagnetic field data for the Planning Coordinator’s
planning area to inform GMD Vulnerability Assessments.
Magnetometers provide geomagnetic field data by measuring changes in the earth’s magnetic field. Sources of
geomagnetic field data include:
•
Observatories such as those operated by U.S. Geological Survey, Natural Resources Canada, research
organizations, or university research facilities;
•
Installed magnetometers; and
•
Commercial or third-party sources of geomagnetic field data.
Geomagnetic field data for a Planning Coordinator’s planning area is obtained from one or more of the above data
sources located in the Planning Coordinator’s planning area, or by obtaining a geomagnetic field data product for
the Planning Coordinator’s planning area from a government or research organization. The geomagnetic field data
product does not need to be derived from a magnetometer or observatory within the Planning Coordinator’s
planning area.
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
13
References
1. FERC Order No. 779,
https://www.nerc.com/FilingsOrders/us/FERCOrdersRules/Order779_GMD_RM12-22_20130516.pdf
2. FERC Order No. 830,
https://www.nerc.com/filingsorders/us/FERCOrdersRules/E-4.pdf
3. FERC Order No. 851,
https://www.nerc.com/FilingsOrders/us/FERCOrdersRules/E-3_Order%20No%20851.pdf
4. Benchmark Geomagnetic Disturbance Event Description, NERC, Atlanta, GA, May 12,
2016, https://www.nerc.com/pa/Stand/TPL0071RD/Benchmark_clean_May12_complete.pdf
5. Supplemental Geomagnetic Disturbance Event Description, NERC, Atlanta, GA, October
2017, https://www.nerc.com/pa/Stand/Project201303GeomagneticDisturbanceMitigation/Supplement
al_GMD_Event_Description_2017_October_Clean.pdf
6. Application Guide – Computing Geomagnetically-Induced Current in the Bulk-Power System, NERC,
Atlanta, GA, December,
2013, https://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%2
02013/GIC%20Application%20Guide%202013_approved.pdf
7. Geomagnetic Disturbance Planning Guide, NERC, Atlanta, GA, December,
2013, https://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%2
02013/GMD%20Planning%20Guide_approved.pdf
8. Transformer Thermal Impact Assessment White Paper, NERC, Atlanta, GA, October
2017, https://www.nerc.com/pa/Stand/Project201303GeomagneticDisturbanceMitigation/Thermal_Im
pact_Assessment_2017_October_Clean.pdf
9. 2012 Special Reliability Assessment Interim Report: Effects of Geomagnetic Disturbances on the Bulk
Power System, NERC, Atlanta, GA, February,
2012, https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2012GMD.pdf
10. Screening Criterion for Transformer Thermal Impact Assessment White Paper, NERC, Atlanta, GA,
October
2017, https://www.nerc.com/pa/Stand/Project201303GeomagneticDisturbanceMitigation/Screening_Cr
iterion_Clean_2017_October_Clean.pdf
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
14
Exhibit E
Order No. 672 Criteria for Proposed Reliability Standard TPL-007-4
RELIABILITY | RESILIENCE | SECURITY
Exhibit E — Order No. 672 Criteria
Order No. 672 Criteria
In Order No. 672, 1 the Commission identified a number of criteria it will use to analyze
Reliability Standards proposed for approval to ensure they are just, reasonable, not unduly
discriminatory or preferential, and in the public interest. The discussion below identifies these
factors and explains how the proposed Reliability Standard has met or exceeded the criteria.
1.
Proposed Reliability Standards must be designed to achieve a specified reliability goal
and must contain a technically sound means to achieve that goal. 2
Proposed Reliability Standard TPL-007-4 addresses the unique risks posed by a high-
impact, low-frequency geomagnetic disturbance (“GMD”) event on the reliable operation of the
Bulk-Power System (“BPS”) and is responsive to the Commission’s directives in Order No. 851.
As with prior versions of the TPL-007 standard, the proposed standard is based on sound scientific
and technical principles.
Currently effective Reliability Standard TPL-007-3 requires applicable entities to conduct
initial and on-going assessments of the potential impact of two defined GMD events, the
1
Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the
Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672, 114 FERC ¶ 61,104,
order on reh’g, Order No. 672-A, 114 FERC ¶ 61,328 (2006) (“Order No. 672”).
2
See Order No. 672 at P 321 (“The proposed Reliability Standard must address a reliability concern that falls
within the requirements of section 215 of the FPA. That is, it must provide for the reliable operation of Bulk-Power
System facilities. It may not extend beyond reliable operation of such facilities or apply to other facilities. Such
facilities include all those necessary for operating an interconnected electric energy transmission network, or any
portion of that network, including control systems. The proposed Reliability Standard may apply to any design of
planned additions or modifications of such facilities that is necessary to provide for reliable operation. It may also
apply to Cybersecurity protection.”).
See Order No. 672 at P 324 (“The proposed Reliability Standard must be designed to achieve a specified
reliability goal and must contain a technically sound means to achieve this goal. Although any person may propose a
topic for a Reliability Standard to the ERO, in the ERO’s process, the specific proposed Reliability Standard should
be developed initially by persons within the electric power industry and community with a high level of technical
expertise and be based on sound technical and engineering criteria. It should be based on actual data and lessons
learned from past operating incidents, where appropriate. The process for ERO approval of a proposed Reliability
Standard should be fair and open to all interested persons.”).
benchmark GMD event and the supplemental GMD event, on BPS equipment and the BPS as a
whole. The standard presently requires entities to develop and implement Corrective Action Plans
to protect against instability, uncontrolled separation, and cascading failures of the BPS identified
through benchmark GMD Vulnerability Assessments. The standard also contains requirements for
implementing processes to collect GMD monitoring data.
Proposed Reliability Standard TPL-007-4 improves upon the current version of the
standard and addresses the Order No. 851 directives by: (i) requiring entities to develop Corrective
Action Plans for vulnerabilities identified through supplemental GMD Vulnerability
Assessments; 3 and (ii) requiring entities to seek approval from the ERO of any extensions of time
for the completion of Corrective Action Plan items. 4
2.
Proposed Reliability Standards must be applicable only to users, owners, and
operators of the bulk power system, and must be clear and unambiguous as to what
is required and who is required to comply. 5
The proposed Reliability Standard is clear and unambiguous as to what is required and who
is required to comply, in accordance with Order No. 672. Consistent with currently effective
Reliability Standard TPL-007-3, proposed Reliability Standard TPL-007-4 is applicable to: (1)
Planning Coordinators with a planning area that includes a power transformer(s) with a high side,
wye-grounded winding with terminal voltage greater than 200 kV; (2) Transmission Planners with
a planning area that includes a power transformer(s) with a high side, wye-grounded winding with
terminal voltage greater than 200 kV; (3) Transmission Owners that own a Facility or Facilities
3
Geomagnetic Disturbance Reliability Standard; Reliability Standard for Transmission System Planned
Performance for Geomagnetic Disturbance Events, Order No. 851, 165 FERC ¶ 61,124 (2018) at PP 29 and 39.
4
Id. at P 54.
5
See Order No. 672 at P 322 (“The proposed Reliability Standard may impose a requirement on any user,
owner, or operator of such facilities, but not on others.”).
See Order No. 672 at P 325 (“The proposed Reliability Standard should be clear and unambiguous regarding
what is required and who is required to comply. Users, owners, and operators of the Bulk-Power System must know
what they are required to do to maintain reliability.”).
2
that include a power transformer(s) with a high side, wye-grounded winding with terminal voltage
greater than 200 kV; and (4) Generator Owners that own a Facility or Facilities that include a
power transformer(s) with a high side, wye-grounded winding with terminal voltage greater than
200 kV. 6 The proposed Reliability Standard clearly articulates the actions that such entities must
take to comply with the standard.
3.
A proposed Reliability Standard must include clear and understandable
consequences and a range of penalties (monetary and/or non-monetary) for a
violation. 7
The Violation Risk Factors (“VRFs”) and Violation Severity Levels (“VSLs”) for the
proposed Reliability Standard comport with NERC and Commission guidelines related to their
assignment. The assignment of the severity level for each VSL is consistent with the corresponding
requirement and the VSLs should ensure uniformity and consistency in the determination of
penalties. The VSLs do not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations. For these reasons, the
proposed Reliability Standard includes clear and understandable consequences in accordance with
Order No. 672.
4.
A proposed Reliability Standard must identify clear and objective criterion or
measure for compliance, so that it can be enforced in a consistent and non preferential
manner. 8
The proposed Reliability Standard contains measures that support each requirement by
clearly identifying what is required and how the requirement will be enforced. These measures
6
A power transformer with a “high side wye-grounded winding” refers to a power transformer with windings
on the high voltage side that are connected in a wye configuration and have a grounded neutral connection.
7
See Order No. 672 at P 326 (“The possible consequences, including range of possible penalties, for violating
a proposed Reliability Standard should be clear and understandable by those who must comply.”).
8
See Order No. 672 at P 327 (“There should be a clear criterion or measure of whether an entity is in
compliance with a proposed Reliability Standard. It should contain or be accompanied by an objective measure of
compliance so that it can be enforced and so that enforcement can be applied in a consistent and non-preferential
manner.”).
3
help provide clarity regarding how the requirements will be enforced and help ensure that the
requirements will be enforced in a clear, consistent, and non-preferential manner and without
prejudice to any party.
5.
Proposed Reliability Standards should achieve a reliability goal effectively and
efficiently, but do not necessarily have to reflect “best practices” without regard to
implementation cost or historical regional infrastructure design. 9
The proposed Reliability Standard achieves its reliability goals effectively and efficiently
in accordance with Order No. 672. The proposed Reliability Standard clearly enumerates the
responsibilities of applicable entities with respect to conducting initial and on-going assessments
of the potential impact of defined GMD events on BPS equipment and the BPS as a whole and
provides entities the flexibility to select appropriate mitigation strategies to address identified
vulnerabilities.
6.
Proposed Reliability Standards cannot be “lowest common denominator,” i.e., cannot
reflect a compromise that does not adequately protect Bulk-Power System reliability.
Proposed Reliability Standards can consider costs to implement for smaller entities,
but not at consequences of less than excellence in operating system reliability. 10
The proposed Reliability Standard does not reflect a “lowest common denominator”
approach. To the contrary, the proposed Reliability Standard contains significant reliability
benefits for the BPS and addresses directives and concerns identified by the Commission in Order
9
See Order No. 672 at P 328 (“The proposed Reliability Standard does not necessarily have to reflect the
optimal method, or ‘best practice,’ for achieving its reliability goal without regard to implementation cost or historical
regional infrastructure design. It should however achieve its reliability goal effectively and efficiently.”).
10
See Order No. 672 at P 329 (“The proposed Reliability Standard must not simply reflect a compromise in the
ERO’s Reliability Standard development process based on the least effective North American practice—the so-called
‘lowest common denominator’—if such practice does not adequately protect Bulk-Power System reliability. Although
the Commission will give due weight to the technical expertise of the ERO, we will not hesitate to remand a proposed
Reliability Standard if we are convinced it is not adequate to protect reliability.”).
See Order No. 672 at P 330 (“A proposed Reliability Standard may take into account the size of the entity
that must comply with the Reliability Standard and the cost to those entities of implementing the proposed Reliability
Standard. However, the ERO should not propose a ‘lowest common denominator’ Reliability Standard that would
achieve less than excellence in operating system reliability solely to protect against reasonable expenses for supporting
this vital national infrastructure. For example, a small owner or operator of the Bulk-Power System must bear the cost
of complying with each Reliability Standard that applies to it.”).
4
No. 851. The provisions of the proposed standard raise the level of preparedness by requiring
applicable entities to develop Corrective Action Plans to address system performance issues
identified through supplemental GMD Vulnerability Assessments. The proposed standard also
revises requirements for Corrective Action Plans so that entities would be required to submit any
requests to extend Corrective Action Plan deadlines to NERC and the Regional Entities, so that
such requests may be considered on a case-by-case basis.
7.
Proposed Reliability Standards must be designed to apply throughout North America
to the maximum extent achievable with a single Reliability Standard while not
favoring one geographic area or regional model. It should take into account regional
variations in the organization and corporate structures of transmission owners and
operators, variations in generation fuel type and ownership patterns, and regional
variations in market design if these affect the proposed Reliability Standard. 11
The proposed Reliability Standard applies consistently throughout North America and does
not favor one geographic area or regional model. The proposed standard includes technicallyjustified scaling factors that allow for entity-specific tailoring of the benchmark and supplemental
GMD events. This approach provides for consistent application of the proposed Reliability
Standard throughout North America while still accounting for the varying impact GMD events
may have on each region.
The proposed Reliability Standard, like the currently effective standard, also contains a
regional Variance option for Canadian entities. This Variance accounts for differences in
regulatory processes in some Canadian jurisdictions with respect to implementation of Corrective
Action Plans. This Variance also provides an option which would allow Canadian entities to
11
See Order No. 672 at P 331 (“A proposed Reliability Standard should be designed to apply throughout the
interconnected North American Bulk-Power System, to the maximum extent this is achievable with a single Reliability
Standard. The proposed Reliability Standard should not be based on a single geographic or regional model but should
take into account geographic variations in grid characteristics, terrain, weather, and other such factors; it should also
take into account regional variations in the organizational and corporate structures of transmission owners and
operators, variations in generation fuel type and ownership patterns, and regional variations in market design if these
affect the proposed Reliability Standard.”).
5
perform assessments using regionally specific information where such information provides a
technically justified means to re-define one or more 1-in-100 year GMD planning event(s) within
its planning area.
8.
Proposed Reliability Standards should cause no undue negative effect on competition
or restriction of the grid beyond any restriction necessary for reliability. 12
Proposed Reliability Standard TPL-007-4 has no undue negative effect on competition and
does not unreasonably restrict the available transmission capacity or limit the use of the BPS in a
preferential manner. The proposed standard requires the same performance by each of the
applicable entities. The information sharing required by the proposed standard is necessary for
reliability and can be accomplished without presenting any market or competition-related
concerns.
9.
The implementation time for the proposed Reliability Standard is reasonable. 13
The proposed effective date for proposed Reliability Standard TPL-007-4 is just and
reasonable and appropriately balances the urgency in the need to implement the standard against
the reasonableness of the time allowed for those who must comply to develop necessary
procedures, software, facilities, staffing, or other relevant capability. The proposed TPL-007-4
implementation plan integrates the new and revised Corrective Action Plan requirements in
proposed Reliability Standard TPL-007-4 with the existing phased-in compliance date timeframe
12
See Order No. 672 at P 332 (“As directed by section 215 of the FPA, FERC itself will give special attention
to the effect of a proposed Reliability Standard on competition. The ERO should attempt to develop a proposed
Reliability Standard that has no undue negative effect on competition. Among other possible considerations, a
proposed Reliability Standard should not unreasonably restrict available transmission capability on the Bulk-Power
System beyond any restriction necessary for reliability and should not limit use of the Bulk-Power System in an unduly
preferential manner. It should not create an undue advantage for one competitor over another.”).
13
See Order No. 672 at P 333 (“In considering whether a proposed Reliability Standard is just and reasonable,
the Commission will consider also the timetable for implementation of the new requirements, including how the
proposal balances any urgency in the need to implement it against the reasonableness of the time allowed for those
who must comply to develop the necessary procedures, software, facilities, staffing or other relevant capability.”).
6
under the TPL-007-3 implementation plan. 14 Assuming the Commission’s order approving the
proposed standard becomes effective before June 2023, applicable entities would be required to
develop any required Corrective Action Plans under new Requirement R11 (supplemental GMD
Vulnerability Assessment) by the same date presently required for Corrective Action Plans under
existing Requirement R7 (benchmark GMD Vulnerability Assessment). The proposed
implementation plan is attached as Exhibit B to this Petition.
10.
The Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development
process. 15
The proposed Reliability Standard was developed in accordance with NERC’s
Commission-approved, ANSI-accredited processes for developing and approving Reliability
Standards. Exhibit F includes a summary of the Reliability Standard development proceedings,
and details the processes followed to develop the proposed Reliability Standard. These processes
included, among other things, multiple comment periods, pre-ballot review periods, and balloting
periods. Additionally, all meetings of the standard drafting team were properly noticed and open
to the public.
14
For U.S.-based entities, the TPL-007-3 implementation plan carried forward the phased-in compliance dates
approved by the Commission in the TPL-007-2 implementation plan.
15
See Order No. 672 at P 334 (“Further, in considering whether a proposed Reliability Standard meets the legal
standard of review, we will entertain comments about whether the ERO implemented its Commission-approved
Reliability Standard development process for the development of the particular proposed Reliability Standard in a
proper manner, especially whether the process was open and fair. However, we caution that we will not be sympathetic
to arguments by interested parties that choose, for whatever reason, not to participate in the ERO’s Reliability Standard
development process if it is conducted in good faith in accordance with the procedures approved by the
Commission.”).
7
11.
NERC must explain any balancing of vital public interests in the development of
proposed Reliability Standards. 16
NERC has identified no competing public interests regarding the request for approval of
this proposed Reliability Standard. No comments were received that indicated the proposed
Reliability Standard conflicts with other vital public interests.
12.
Proposed Reliability Standards must consider any other appropriate factors. 17
No other negative factors relevant to whether the proposed Reliability Standard is just and
reasonable were identified.
16
See Order No. 672 at P 335 (“Finally, we understand that at times development of a proposed Reliability
Standard may require that a particular reliability goal must be balanced against other vital public interests, such as
environmental, social and other goals. We expect the ERO to explain any such balancing in its application for approval
of a proposed Reliability Standard.”).
17
See Order No. 672 at P 323 (“In considering whether a proposed Reliability Standard is just and reasonable,
we will consider the following general factors, as well as other factors that are appropriate for the particular Reliability
Standard proposed.”).
8
Exhibit F
Summary of Development History
and Complete Record of Development
RELIABILITY | RESILIENCE | SECURITY
Summary of Development History
The following is a summary of the development record for proposed Reliability Standard
TPL-007-4.
I.
Overview of the Standard Drafting Team
When evaluating a proposed Reliability Standard, the Commission is expected to give “due
weight” to the technical expertise of the ERO. 1 The technical expertise of the ERO is derived from
the standard drafting team (“SDT”) selected to lead each project in accordance with Section 4.3 of
the NERC Standard Processes Manual, Appendix 3A to the NERC Rules of Procedure. 2 For this
project, the SDT consisted of industry experts, all with a diverse set of experiences. A roster of the
Project 2019-01 Modifications to TPL-007-3 SDT members is included in Exhibit G.
II.
Standard Development History
A. Standard Authorization Request Development
On February 20, 2019, the Standards Committee authorized posting a Standards
Authorization Request (“SAR”) as well as the solicitation of nominations for the Project 2019-01
Revisions to TPL-007-3 SDT. 3 The SAR was posted for a 30-day informal comment period from
February 25, 2019 through March 26, 2019 and the drafting team nominations were open for the
same period. The SAR received 24 sets of responses, including comments from approximately 67
different people from approximately 51 companies, representing 7 industry segments. 4
1
Section 215(d)(2) of the Federal Power Act; 16 U.S.C. § 824(d)(2) (2018).
The NERC Standard Processes Manual is available at
https://www.nerc.com/FilingsOrders/us/RuleOfProcedureDL/SPM_Clean_Mar2019.pdf.
3
NERC, Minutes – Standards Committee Conference Call (February 20, 2019), Agenda Item 6,
https://www.nerc.com/comm/SC/Agenda%20Highlights%20and%20Minutes/Standards_Committee_Meeting_Minu
tes_%20Approve_March_20_2019.pdf.
4
Comment Report – Project 2019-01 Modifications to TPL-007-3 SAR,
https://www.nerc.com/pa/Stand/Project201901ModificationstoTPL0073/2019-01_rawcomments_Word_032719.pdf.
2
1
B. First Posting – Formal Comment Period and Initial Ballot
An initial draft of proposed Reliability Standard TPL-007-4 – Transmission System
Planned Performance for Geomagnetic Disturbance Events was posted for a 45-day formal
comment period from July 26, 2019 through September 9, 2019, along with the implementation
plan and other supporting documents. There were 66 sets of responses, including comments from
approximately 133 different individuals and approximately 98 companies, representing all 10
industry segments. 5 An initial ballot was open for the final ten days of the comment period from
August 30, 2019 through September 9, 2019. The proposed standard received 70.84 percent
approval with a quarum of 91.44 percent. 6 A simultaneous non-binding poll for the VRFs and
VSLs received 71.04 percent support with a quarum of 88.81 percent. 7
C. Final Ballot
Proposed Reliability Standard TPL-007-4 was posted for a 10-day final ballot period from
November 13, 2019 through November 22, 2019. The proposed standard received a 78.95 percent
approval rating, with 94.52 percent quorum. 8
D. Board of Trustees Adoption
On February 6, 2020, the NERC Board of Trustees adopted proposed Reliability Standard
TPL-007-4, the Implementation Plan, and the associated VRFs and VSLs.
5
NERC, Consideration of Comments — Project 2019-01 Modifications to TPL-007-3,
https://www.nerc.com/pa/Stand/Project201901ModificationstoTPL0073/201901_Response%20to%20Comments_Final%20Ballot.pdf.
6
NERC, Ballot Results — 2019-01 Modifications to TPL-007-3 TPL-007-4 IN 1 ST,
https://sbs.nerc.net/BallotResults/Index/366.
7
NERC, Ballot Results — 2019-01 Modifications to TPL-007-3 TPL-007-4 Non-binding Poll IN 1 NB,
https://sbs.nerc.net/BallotResults/Index/367.
8
NERC, Ballot Results — 2019-01 Modifications to TPL-007-3 TPL-007-4 FN 2 ST,
https://sbs.nerc.net/BallotResults/Index/398.
2
Complete History of Development
3
2/6/2020
Project 2019-01 Modifications to TPL-007-3
Project 2019-01 Modifications to TPL-007-3
Related Files
Status
A 10-day final ballot for TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events concluded at 8 p.m. Eastern, Friday, November 22, 2019.
The ERO CAP Extension Request Review Process was developed by NERC Compliance Assurance staff and was provided for informa onal purposes only. It was not part of the
material being balloted.
Background
The first version of the standard, TPL-007-1, requires entities to assess the impact to their systems from a defined event referred to as the “Benchmark GMD Event.” The second version of the
standard adds new Requirements R8, R9, and R10 to require responsible entities to assess the potential implications of a “Supplemental GMD Event” on their equipment and systems in
accordance with the FERC’s directives in Order No. 830. The third version of the standard adds a Canadian variance for Canadian Registered Entities to leverage operating experience, observed
GMD effects, and on-going research efforts for defining alternative Benchmark GMD Events and/or Supplemental GMD Events that appropriately reflect their specific geographical and geological
characteristics Background Information. This project will address the directives issued by FERC in Order No. 851 to modify Reliability Standard TPL-007-3. FERC directed NERC to submit
modifications to: (1) require the development and implementation of corrective action plans to mitigate assessed supplemental GMD event vulnerabilities (P 29); and (2) to replace the corrective
action plan time-extension provision in Requirement R7.4 with a process through which extensions of time are considered on a case-by-case basis (P 54).
Standard(s) Affected – TPL-007-3
Purpose/Industry Need
This project will address the directives issued by FERC in Order No. 851 to modify Reliability Standard TPL-007-3.
Subscribe to the Project 2019-01 Modifications to TPL-007-3 Observer Distribution List
Select "NERC Email Distribution Lists" from the "Applications" drop-down menu and specify “Project 2019-01 Modifications to TPL-007-3 Observer List” in the Description Box.
Draft
Actions
Dates
Results
11/13/19 - 11/22/19
(34) TPL-007-4
Consideration of
Comments
Final
TPL-007-4
(23) Clean | Redline to Last Posted (24)
(25) Redline to Last Approved
(26) Implementation Plan
Supporting Materials
(27) Technical Rationale for TPL-007-4
(28) Implementation Guidance for TPL-007-4
Final Ballot
(33) Info
Ballot Results
Vote
(29) VRF/VSL Justification
(30) Consideration of Directives
TPL-007-4 CAP Extension Request Review Process
(31) Clean | Redline to Last Posted (32)
Draft 1
TPL-007-4
Initial Ballot
(7) Clean | Redline (8)
(20) Info
(9) Implementation Plan
Vote
Ballot Results
8/30/19 - 9/9/19
(21) TPL-007-4
(22) Non-Binding Poll
Results
Supporting Materials
(10) Unofficial Comment Form (Word)
Comment Period
(11) Technical Rationale for TPL-007-4
(17) Info
(12) Implementation Guidance for TPL-007-4
7/26/19 - 9/9/19
(18) Comments Received (19) Consideration of
Comments
Submit Comments
(13) VRF/VSL Justification
(14) Consideration of Directives
(15) Draft ERO Process Update
Join Ballot Pools
7/26/19 - 8/26/19
(16) Draft Reliability Standard Audit Worksheet (RSAW) Update
Send RSAW feedback to:
[email protected]
https://www.nerc.com/pa/Stand/Pages/Project2019-01ModificationstoTPL-007-3.aspx
1/2
2/6/2020
Project 2019-01 Modifications to TPL-007-3
Drafting Team Nominations
Supporting Materials
(5) Unofficial Nomination Form (Word)
Nomination Period
(6) Info
02/25/19 - 03/26/19
Submit Nominations
(1) Standard Authorization Request
Supporting Materials
(2) Unofficial Comment Form (Word)
Comment Period
(3) Info
Submit Comments
https://www.nerc.com/pa/Stand/Pages/Project2019-01ModificationstoTPL-007-3.aspx
02/25/19 - 03/26/19
(4) Comments Received
2/2
Standard Authorization Request (SAR)
Complete and please email this form, with
Complete
and please
email this form, with
attachment(s)
to: [email protected]
attachment(s) to: [email protected]
SAR Title:
The North American Electric Reliability Corporation (NERC)
welcomes suggestions to improve the reliability of the bulk
power system through improved Reliability Standards.
Requested information
Revisions to TPL-007-3 Transmission System Planned Performance for
Geomagnetic Disturbance
Date Submitted:
SAR Requester
Name:
Soo Jin Kim
Organization: NERC
Telephone:
404-446-9742
Email:
[email protected]
SAR Type (Check as many as apply)
New Standard
Imminent Action/ Confidential Issue (SPM
Revision to Existing Standard
Section 10)
Add, Modify or Retire a Glossary Term
Variance development or revision
Withdraw/retire an Existing Standard
Other (Please specify)
Justification for this proposed standard development project (Check all that apply to help NERC
prioritize development)
Regulatory Initiation
NERC Standing Committee Identified
Emerging Risk (Reliability Issues Steering
Enhanced Periodic Review Initiated
Committee) Identified
Industry Stakeholder Identified
Reliability Standard Development Plan
Industry Need (What Bulk Electric System (BES) reliability benefit does the proposed project provide?):
On November 15, 2018, the Federal Energy Regulatory Commission (FERC) issued Order No. 851 in
order to modify Reliability Standard TPL-007-2.
Purpose or Goal (How does this proposed project provide the reliability-related benefit described
above?):
This project will address the directives issued by FERC in Order No. 851 to modify Reliability Standard
TPL-007-2. FERC directed NERC to submit modifications to: (1) require the development and
implementation of corrective action plans to mitigate assessed supplemental GMD event vulnerabilities
(P 29); and (2) to replace the corrective action plan time-extension provision in Requirement R7.4 with a
process through which extensions of time are considered on a case-by-case basis (P 54). NERC was
directed to submit the modified Reliability Standard for approval within 12 months from the effective
date of Reliability Standard TPL-007-2.
Requested information
Project Scope (Define the parameters of the proposed project):
This project will address the directives issued by FERC in Order No. 851 to modify Reliability Standard
TPL-007-3.
Detailed Description (Describe the proposed deliverable(s) with sufficient detail for a drafting team to
execute the project. If you propose a new or substantially revised Reliability Standard or definition,
provide: (1) a technical justification 1which includes a discussion of the reliability-related benefits of
developing a new or revised Reliability Standard or definition, and (2) a technical foundation document
(e.g. research paper) to guide development of the Standard or definition):
The Standard Drafting Team (SDT) will address FERC’s directives in Order No. 851 that require the
development and completion of corrective actions plans to mitigate assessed supplemental GMD event
vulnerabilities. The SDT will also modify the provisions in Reliability Standard TPL-007-3, Requirement
R7.4 that allows applicable entities to exceed deadlines for completing corrective action plan tasks
when situations beyond the control of the responsible entity arise.
The SDT will also need to evaluate the Canadian variance and make any appropriate changes to the
variance based on the modifications arising from FERC Order No. 851.
Cost Impact Assessment, if known (Provide a paragraph describing the potential cost impacts associated
with the proposed project):
The potential cost impacts associated with adding corrective action plan requirements for supplemental
GMD event vulnerabilities are unknown at this time.
Please describe any unique characteristics of the BES facilities that may be impacted by this proposed
standard development project (e.g. Dispersed Generation Resources):
Not Applicable
To assist the NERC Standards Committee in appointing a drafting team with the appropriate members,
please indicate to which Functional Entities the proposed standard(s) should apply (e.g. Transmission
Operator, Reliability Coordinator, etc. See the most recent version of the NERC Functional Model for
definitions):
Planning Coordinator, Transmission Planner, Transmission Owner, Generator Owner
Do you know of any consensus building activities 2 in connection with this SAR? If so, please provide any
recommendations or findings resulting from the consensus building activity.
No
Are there any related standards or SARs that should be assessed for impact as a result of this proposed
project? If so which standard(s) or project number(s)?
Project 2018-01 TPL-007-3 (Canadian Variance). EOP-010-1 Geomagnetic Disturbance Operations
Are there alternatives (e.g. guidelines, white paper, alerts, etc.) that have been considered or could
meet the objectives? If so, please list the alternatives.
The NERC Rules of Procedure require a technical justification for new or substantially revised Reliability Standards. Please attach pertinent
information to this form before submittal to NERC.
2 Consensus building activities are occasionally conducted by NERC and/or project review teams. They typically are conducted to obtain
industry inputs prior to proposing any standard development project to revise, or develop a standard or definition.
1
Standard Authorization Request (SAR)
2
Requested information
Order No. 830 GMD Research Work Plan could help to inform the SDT while making the required
modifications to the standard laid out in Order No. 851.
Reliability Principles
Does this proposed standard development project support at least one of the following Reliability
Principles (Reliability Interface Principles)? Please check all those that apply.
1. Interconnected bulk power systems shall be planned and operated in a coordinated manner
to perform reliably under normal and abnormal conditions as defined in the NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled within
defined limits through the balancing of real and reactive power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk power systems
shall be made available to those entities responsible for planning and operating the systems
reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power systems
shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and maintained
for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems shall be
trained, qualified, and have the responsibility and authority to implement actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored and
maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Market Interface Principles
Does the proposed standard development project comply with all of the
following Market Interface Principles?
1. A reliability standard shall not give any market participant an unfair competitive
advantage.
2. A reliability standard shall neither mandate nor prohibit any specific market
structure.
3. A reliability standard shall not preclude market solutions to achieving compliance
with that standard.
4. A reliability standard shall not require the public disclosure of commercially
sensitive information. All market participants shall have equal opportunity to
access commercially non-sensitive information that is required for compliance
with reliability standards.
Standard Authorization Request (SAR)
Enter
(yes/no)
Yes
Yes
Yes
Yes
3
Identified Existing or Potential Regional or Interconnection Variances
Region(s)/
Explanation
Interconnection
The only difference between TPL-007-3 and TPL-007-2 is that TPL-007-3 adds a Canadian
TPL-007-3
Variance to address regulatory practices/processes within Canadian jurisdictions and to
Canadian
allow the use of Canadian-specific data and research to define and implement
Variance
alternative GMD event(s) that achieve at least an equivalent reliability objective of the
defined benchmark and supplemental GMD events in TPL-007-2 Attachment 1.
For Use by NERC Only
SAR Status Tracking (Check off as appropriate)
Draft SAR reviewed by NERC Staff
Draft SAR presented to SC for acceptance
DRAFT SAR approved for posting by the SC
Final SAR endorsed by the SC
SAR assigned a Standards Project by NERC
SAR denied or proposed as Guidance
document
Version History
Version
Date
Owner
Change Tracking
1
June 3, 2013
1
August 29, 2014
Standards Information Staff
Updated template
2
January 18, 2017
Standards Information Staff
Revised
2
June 28, 2017
Standards Information Staff
Updated template
Standard Authorization Request (SAR)
Revised
4
Unofficial Comment Form
Project 2019-01 Modifications to TPL-007-3
Do not use this form for submitting comments. Use the Standards Balloting and Commenting System
(SBS) to submit comments on the Project 2019-01 Modifications to TPL-007-3 Standard Authorization
Request (SAR). Comments must be submitted by 8 p.m. Eastern, Tuesday, March 26, 2019.
m. Eastern, Thursday, August 20, 2015
Additional information is available on the project page. If you have questions, contact Senior Standards
Developer, Alison Oswald (via email), or at 404-446-9668.
Background Information
The first version of the standard, TPL-007-1, requires entities to assess the impact to their systems from a
defined event referred to as the “Benchmark GMD Event.” The second version of the standard adds new
Requirements R8, R9, and R10 to require responsible entities to assess the potential implications of a
“Supplemental GMD Event” on their equipment and systems in accordance with the FERC’s directives in
Order No. 830. The third version of the standard adds a Canadian variance for Canadian Registered
Entities to leverage operating experience, observed GMD effects, and on-going research efforts for
defining alternative Benchmark GMD Events and/or Supplemental GMD Events that appropriately reflect
their specific geographical and geological characteristics Background Information. This project will address
the directives issued by FERC in Order No. 851 to modify Reliability Standard TPL-007-3. FERC directed
NERC to submit modifications to: (1) require the development and implementation of corrective action
plans to mitigate assessed supplemental GMD event vulnerabilities (P 29); and (2) to replace the
corrective action plan time-extension provision in Requirement R7.4 with a process through which
extensions of time are considered on a case-by-case basis (P 54).
Questions
1. Do you agree with the proposed scope as described in the SAR? If you do not agree, or if you agree
but have comments or suggestions for the project scope please provide your recommendation and
explanation.
Yes
No
Comments:
2. Provide any additional comments for the Standrds Drafting Team to consider, if desired.
Comments:
Unofficial Comment Form
2019-01 Modifications to TPL-007-3 | February 2019
2
Standards Announcement
Project 2019-01 Modifications to TPL-007-3
Informal Comment Period Open through March 26, 2019
Now Available
A 30-day informal comment period for the Project 2019-01 Modifications to TPL-007-3 Standard
Authorization Request (SAR), is open through 8 p.m. Eastern, Tuesday, March 26, 2019.
Commenting
Use the Standards Balloting and Commenting System (SBS) to submit comments. If you experience issues
navigating the SBS, contact Linda Jenkins. An unofficial Word version of the comment form is posted on
the project page.
•
If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential
error messages, or system lock-out, contact NERC IT support directly
at https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5 p.m. Eastern).
•
Passwords expire every 6 months and must be reset.
•
The SBS is not supported for use on mobile devices.
•
Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.
Next Steps
The drafting team will review all responses received during the comment period and determine the next
steps of the project.
For more information on the Standards Development Process, refer to the Standard Processes
Manual.
For more information or assistance, contact Senior Standards Developer, Alison Oswald (via email) or at
404-446-9668.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Comment Report
Project Name:
Project 2019-01 Modifications to TPL-007-3
Comment Period Start Date:
2/25/2019
Comment Period End Date:
3/26/2019
Associated Ballots:
There were 24 sets of responses, including comments from approximately 67 different people from approximately 51 companies
representing 7 of the Industry Segments as shown in the table on the following pages.
Questions
1. Do you agree with the proposed scope as described in the SAR? If you do not agree, or if you agree but have comments or suggestions for
the project scope please provide your recommendation and explanation.
2. Provide any additional comments for the Standards Drafting Team to consider, if desired.
Organization
Name
Name
BC Hydro and Adrian
Power
Andreoiu
Authority
Electric
Reliability
Council of
Texas, Inc.
Duke Energy
MRO
Brandon
Gleason
Colby
Bellville
Dana Klem
Segment(s)
1,3,5
Region
WECC
2
1,3,5,6
1,2,3,4,5,6
Group Name
Group
Member Name
Group
Group
Member
Member
Organization Segment(s)
BC Hydro
Hootan
Jarollahi
BC Hydro and 3
Power
Authority
WECC
Helen Hamilton BC Hydro and 5
Harding
Power
Authority
WECC
Adrian
Andreoiu
BC Hydro and 1
Power
Authority
WECC
Brandon
Gleason
Electric
Reliability
Council of
Texas, Inc.
Texas RE
Ali Miremadi
California ISO 2
WECC
Helen Lainis
IESO
2
NPCC
Charles Yeung Southwest
Power Pool,
Inc. (RTO)
2
MRO
Gregory
Campoli
New York
Independent
System
Operator
2
NPCC
Terry Bilke
Midcontinent 2
Independent
System
Operator, Inc.
MRO
Doug Hils
Duke Energy
1
RF
Lee Schuster
Duke Energy
3
FRCC
Dale Goodwine Duke Energy
5
SERC
Greg Cecil
Duke Energy
6
RF
Joseph
DePoorter
Madison Gas
& Electric
3,4,5,6
MRO
Larry Heckert
Alliant Energy 4
MRO
Amy Casucelli
Xcel Energy
1,3,5,6
MRO
Michael
Brytowski
Great River
Energy
1,3,5,6
MRO
Jodi Jensen
Western Area 1,6
Power
ISO/RTO
Standards
Review
Committee
2019-01
Modifications
to TPL-007-3
FRCC,RF,SERC
MRO
Duke Energy
MRO NSRF
2
Group
Member
Region
MRO
Administration
Kayleigh
Wilkerson
ACES Power
Marketing
Jodirah
Green
1,3,4,5,6
1,3,5,6
MRO
Mahmood Safi Omaha Public 1,3,5,6
Power District
MRO
Brad Parret
Minnesota
Powert
1,5
MRO
Terry Harbour
MidAmerican
Energy
Company
1,3
MRO
Tom Breene
Wisconsin
3,5,6
Public Service
Corporation
MRO
Jeremy Voll
Basin Electric 1
Power
Cooperative
MRO
Kevin Lyons
Central Iowa
Power
Cooperative
1
MRO
Mike Morrow
Midcontinent
ISO
2
MRO
MRO,NA - Not
ACES
John Shaver
Applicable,RF,SERC,WECC Standard
Collaborations
Lincoln
Electric
System
Arizona
1
Electric Power
Cooperative,
Inc.
WECC
Hoosier
Energy Rural
Electric
Cooperative,
Inc.
1
SERC
Greg Froehling Rayburn
Country
Electric
Cooperative,
Inc.
3,6
Texas RE
Kevin Lyons
1
MRO
Bob Solomon
Central Iowa
Power
Cooperative
Ginger Mercier Prairie Power 1,3
, Inc.
SERC
Kagen DelRio
North Carolina 3,4,5
Electric
Membership
Cooperative
SERC
Ryan Strom
Buckeye
RF
5
Power, Inc.
Eversource
Energy
Quintin Lee
1,3
PSEG - Public Sean Cavote 1,3
Service
Electric and
Gas Co.
Southwest
Power Pool,
Inc. (RTO)
Shannon
Mickens
2
Eversource
Group
FRCC,NPCC,RF
MRO,SPP RE
PSEG REs
Tara Lightner
Sunflower
1
Electric Power
Cooperative
MRO
Sharon
Flannery
Eversource
Energy
3
NPCC
Quintin Lee
Eversource
Energy
1
NPCC
Tim Kucey
PSEG - PSEG 5
Fossil LLC
NPCC
Karla Barton
PSEG - PSEG 6
Energy
Resources
and Trade
LLC
RF
Jeffrey Mueller PSEG - Public 3
Service
Electric and
Gas Co.
RF
Joseph Smith
PSEG - Public 1
Service
Electric and
Gas Co.
RF
Southwest
Power Pool
Inc.
2
MRO
Louis Guidry
Cleco
1,3,5,6
SERC
Tara Lightner
Sunflower
1
Electric Power
Corporation
SPP
Shannon
Standards
Mickens
Review Group
MRO
1. Do you agree with the proposed scope as described in the SAR? If you do not agree, or if you agree but have comments or suggestions for
the project scope please provide your recommendation and explanation.
Thomas Foltz - AEP - 3,5
Answer
No
Document Name
Comment
It is our view that the original purpose of the supplemental event is to investigate the impact of local enhancement of the generated electric field from a
GMD event on the transmission grid. This requires industry to take a study approach in which the GICs are calculated with the higher, enhanced
electric field magnitude of 12 V/km (adjusted for location and ground properties) applied to some smaller defined area while outside of this area the
benchmark electric field magnitude of 8 V/km (also adjusted for location and ground properties) is applied. This smaller area is then systematically
moved across the system and the calculations are repeated. This is necessary as the phenomenon could occur anywhere on the system. Using this
Version 2 methodology, every part of the system is ultimately evaluated with the higher electric field magnitude.
In our view, the supplemental event represents a more extreme scenario. As such, adding a corrective action plan requirement to the supplemental
event obviates the need for studying the benchmark event. Rather than pursuing a Corrective Action Plan for the existing Supplemental GMD
Vulnerability Assessment, we believe the SDT should instead pursue only one single GMD Vulnerability Assessment using a reference peak geoelectric
field amplitude not determined soley by non-spatially averaged data. This would be preferable to requiring two GMD Vulnerability Assessments, both
having Corrective Action Plans and each having their own unique reference peak geoelectric field amplitude. When the Supplemental GMD Vulnerability
Assessment was originally developed and proposed, there was no CAP envisioned for it. Because of this, one could argue the merits of having two
unique assessments, as each were different not only in reference peak amplitude, but in obligations as well. What is being suggested in this SAR
however, is essentially having two GMD Vulnerability Assessments requiring Corrective Action Plans but with different reference peak geoelectric field
amplitudes (one presumably higher than the other). It would be unnecessarily burdensome, as well as illogical, to have essentially the same obligations
for both a baseline and supplemental vulnerability assessment. One again, we believe a more prudent path would be for the SDT to determine an
agreeable reference peak geoelectric field amplitude for a single GMD Vulnerability Assessment that potentially requires a Corrective Action Plan.
Likes
0
Dislikes
0
Response
Joyce Gundry - Public Utility District No. 1 of Chelan County - 1,3,5,6
Answer
No
Document Name
Comment
CHPD does not agree with requiring the development and implementation of corrective action plans to mitigate assessed supplemental GMD event
vulnerabilities. Entities have only just begun the process of evaluating the benchmark GMD event and developing mitigation measures. The industry is
in the preliminary stages of assessing and developing mitigation measures for GMD events and has not had much time to develop engineeringjudgement, experience, or expertise in this field. Revising the standard to include CAPs for the supplementary GMD event is not appropriate at this time
as the industry is still building a foundation for this type of system event analysis and exploring mitigation measures. Without a sound foundation
developed, requiring CAPs for the supplemental GMD event could lead to unnecessary mitigation measures and an immense amount of industry
resources spent on a still developing science. CHPD suggests that the benchmark GMD event be fully vetted before moving onto additional scenarios
such as the supplemental event.
CHPD does not agree with replacing the corrective action plan time-extension provision in Requirement R7.4 with a process through which extensions
of time are considered on a case-by-case basis. Since R7.4 is for “situations beyond the control of the entity,” it does not matter if the extensions are
considered on a case-by-case basis as the entity will not be able to comply with the CAP timeline as the situation was beyond their control. Adding the
case-by-case basis would increase the administrative burden to entities while adding very little benefit to the reliability of the BPS.
Likes
0
Dislikes
0
Response
Preston Walker - PJM Interconnection, L.L.C. - 2 - SERC,RF
Answer
No
Document Name
Comment
PJM agrees with simulating and studying the impacts of localized peak geoelectric fields covered under the supplemental GMD event in the GMD
Vulnerability Assessment. These efforts help to improve the overall understanding of the impacts to the BES as well as gauge system performance
under more severe conditions. However, the supplemental GMD event should be considered as an extreme event and although useful to create
situational awareness, it should not mandate design requirements. The situation is analogous to TPL-001-4 extreme (low probability) events where only
an evaluation is performed of the possible actions designed to reduce the likelihood or mitigate the consequences of those events. PJM recommends
that the Drafting Team not require Corrective Action Plan(s) for the supplemental GMD event.
Likes
0
Dislikes
0
Response
Matthew Lewis - Lower Colorado River Authority - 1,5
Answer
No
Document Name
Comment
NERC TPL-001-4 sets forth requirements for TPs to establish a Corrective Action Plan when the analysis indicates an inability of the System to meet
the performance requirements for planning events shown in Table 1. The analysis of an extreme event in Table 1 that results in Cascading caused by
the occurrence of extreme events, an evaluation of possible actions designed to reduce the likelihood or mitigate the consequences and adverse
impacts of the event(s) shall be conducted, but no Corrective Action Plan is required under an extreme event. Since the supplimental analysis may be
considered an extreme event to the benchment assessment, then the CAP would not be required for the supplemental analysis to be consistant with
TPL-001-4.
Likes
Dislikes
0
0
Response
Leonard Kula - Independent Electricity System Operator - 2
Answer
Yes
Document Name
Comment
Given that FERC order No. 851 extends the corrective action plan to the supplemental GMD event vulnerabilities, the scope should include
adding a variance similar to D.A. 7.3. for the new requirement to cover the CAP timelines/milestones associated with regulatory approvals in
Canada, where applicable.
Likes
0
Dislikes
0
Response
Quintin Lee - Eversource Energy - 1,3, Group Name Eversource Group
Answer
Yes
Document Name
Comment
The proposed scope of the SAR is appropriate to address FERC order 851. However, we suggest expanding the scope of the SAR to provide the
Standard Drafting Team with the ability to consider making a revision to “Table 1: Steady State Planning GMD Event”. The recommendation is to add an
item “d.” to the “Steady State:” criteria: “d. System steady state voltage performance shall be within the criteria established in Requirement R3.”
Likes
0
Dislikes
0
Response
Dana Klem - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO NSRF
Answer
Yes
Document Name
Comment
The NSRF agrees with the proposed scope as described in the Standard. The proposed scope is appropriate to address FERC directives in Order 851.
The NSRF would like to suggest that the SDT consider modifying the standard to include only one Corrective Action Plan for Requirement R7 that will
mitigate performance issues identified in the benchmark GMD Vulnerability Assessment (R4) and/or the supplemental GMD Vulnerability Assessment
(R8). If an entity identifies vulnerabilities for the benchmark and the supplemental assessment, the NSRF believes that the CAP for the more severe
supplemental assessment will mitigate the vulnerabilities identified in the benchmark assessment.
Likes
0
Dislikes
0
Response
John Allen - City Utilities of Springfield, Missouri - 1,3,4
Answer
Yes
Document Name
Comment
City Utilities supports comments from the MRO NSRF.
Likes
0
Dislikes
0
Response
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
BPA fully supports efforts already in flight to refine the earth resistance modeling and modification to software study tools to produce results that more
closely represent real-life GIC conditions. These refinements are expected to obtain computation of locally varying electric field magnitude and direction
for use in computing GIC flow in a modeled transmission network, such that, calculated GIC flow more closely represents actual flows during a GMD
event. BPA is aware of work being done by vendors of commercially available study software, and geophysics researchers, to refine GIC modeling in
alignment with the present level of understanding of the physics involved. The path they are on is clearly heading towards obtaining more refined
computation capabilities, within the study tools we use for GIC analysis work, where small area localized conditions are included.
BPA’s concern is that this capability does not presently exist within the study tools, and as such, study work would be using widely varying
assumptions. BPA believes this variability will increase the likelihood of results that are not representative of actual GIC flow and increase the risk of
developing corrective actions that are not beneficial or make matters worse. Worse in that, an action may actually put the system in a less stable state
after the action when compared to riding through the event without taking an action that is actually unnecessary. BPA believes that this Reliability
Standard (TPL-007) should not request study work beyond the capacities of the study tools until those tools are made capable of producing refined
studies requested by the FERC order No. 851.
Likes
0
Dislikes
Response
0
Richard Vine - California ISO - 2
Answer
Yes
Document Name
Comment
The California ISO supports the comments of the ISO/RTO Council Standards Review Committee (SRC)
Likes
0
Dislikes
0
Response
Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,SERC,RF, Group Name ACES Standard Collaborations
Answer
Yes
Document Name
Comment
To replace the Corrective Action Plan time-extension provision in Requirement R7.4 with a process through, which extensions of time are considered on
a case-by-case basis please consider the following:
(1) A clear criteria for approval and disapproval of the extension of time.
(2) An appeal process for revisiting timetables that are not agreed upon by the Responsible Entity and the Regional Entity.
(3) Clearly identifying what supporting documentation is acceptable in the new process.
Another item for consideration is to attach a guideline to the standard that addresses the following questions:
(1) How will the reviews be scheduled and address who are the participants and their role in the new process?
(2) What means will this review be conducted (conference call or in-person)
(3) Does the review team have time parameters they will enforce?
(4) Will there be circumstances that would be able to by-pass the review and provide a standard extention time that if there are circumstances outside
of those, then the case review be concluded?
Likes
0
Dislikes
Response
0
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO, Group Name SPP Standards Review Group
Answer
Yes
Document Name
Comment
The SPP Standards Review Group (SSRG) supports the proposed scope as described in the SAR.
The SSRG recommends the Standards Drafting Team (SDT) consider the potential of redundancy in the development of two Correction Action Plans
(CAPs).
The SSRG reviewed Paragraph 2, from Attachment 1, Calculating Geoelectric Fields for the Benchmark and Supplemental GMD Events. The SSRG
recommends that the SDT consider that one CAP could cover both studies.
“The supplemental GMD event is composed of similar elements as described above (Benchmark), except (1) the reference peak geoelectric field
amplitude is 12 V/km over a localized area; and (2) the geomagnetic field time series or waveform includes a local enhancement in the waveform2.
Likes
0
Dislikes
0
Response
Sean Cavote - PSEG - Public Service Electric and Gas Co. - 1,3, Group Name PSEG REs
Answer
Yes
Document Name
Comment
The proposed scope of the SAR is appropriate to address FERC order 851. However, we suggest expanding the scope of the SAR to provide the
Standard Drafting Team with the ability to consider making a revision to “Table 1: Steady State Planning GMD Event.” The recommendation is to add an
item “d.” to the “Steady State:” criteria: “d. System steady state voltage performance shall be within the criteria established in Requirement R3.”
Likes
0
Dislikes
0
Response
Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2, Group Name ISO/RTO Standards Review Committee 2019-01 Modifications to
TPL-007-3
Answer
Yes
Document Name
Comment
ISO/RTO Standards Review Committee ("SRC") members CAISO, ERCOT, IESO, MISO, NYISO, and SPP agree that the scope of the SAR aligns with
the directives of FERC in Order No. 851.
Likes
0
Dislikes
0
Response
Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
faranak sarbaz - Los Angeles Department of Water and Power - 1,3,5,6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
Response
0
Eric Shaw - Oncor Electric Delivery - 1 - Texas RE
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Anton Vu - Los Angeles Department of Water and Power - 1,3,5,6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Richard Jackson - U.S. Bureau of Reclamation - 1,5
Answer
Document Name
Comment
Yes
Likes
0
Dislikes
0
Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Colby Bellville - Duke Energy - 1,3,5,6 - FRCC,SERC,RF, Group Name Duke Energy
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Adrian Andreoiu - BC Hydro and Power Authority - 1,3,5, Group Name BC Hydro
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
Response
0
2. Provide any additional comments for the Standrds Drafting Team to consider, if desired.
Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2, Group Name ISO/RTO Standards Review Committee 2019-01 Modifications to
TPL-007-3
Answer
Document Name
Comment
None.
Likes
0
Dislikes
0
Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO, Group Name SPP Standards Review Group
Answer
Document Name
Comment
The SSRG recommends the SDT consider developing a non-exclusive list of extension examples.
Likes
0
Dislikes
0
Response
Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,SERC,RF, Group Name ACES Standard Collaborations
Answer
Document Name
Comment
It is stated in the SAR that “The potential cost impacts associated with adding corrective action plan requirements for supplemental GMD event
vulnerabilities are unknown at this time.”
Cost Impacts are an important aspect to be studied. Considerations of estimated time-extensions cost impacts and company budget cycles is
requested to be measured in the time-extension decisions.
Thank you for the opportunity to comment.
Likes
0
Dislikes
0
Response
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment
None
Likes
0
Dislikes
0
Response
Richard Jackson - U.S. Bureau of Reclamation - 1,5
Answer
Document Name
Comment
Reclamation recommends the standards authorization request process include input from FERC so as to thoroughly scope each standard to ensure it
includes all of FERC’s desired content prior to it being submitted for FERC approval. This would help eliminate the potential for changes to new
standards being ordered simultaneously with the approval of the same standard. Reclamation also recommends FERC provide ample time for NERC to
develop standards to avoid the problem of improperly scoped standards being quickly thrown together simply to meet short deadlines.
Likes
0
Dislikes
0
Response
John Allen - City Utilities of Springfield, Missouri - 1,3,4
Answer
Document Name
Comment
City Utilities supports comments from the MRO NSRF.
Likes
0
Dislikes
0
Response
Dana Klem - MRO - 1,2,3,4,5,6 - MRO, Group Name MRO NSRF
Answer
Document Name
Comment
The NSRF suggest expanding the scope of the SAR to provide the SDT with the ability to consider removing or revising requirement R11 and R12. The
requirements to have a process to collect GMD data is not necessary in TPL-007 because that data will not be used in the Planning Analysis.
Furthermore, the GMD data is not needed to complete the benchmark or supplemental vulnerability assessments.
As an example, see the MISO TPL-007-2 flowchart below. The monitoring requirements are outside the requirement flowchart for Planning Analysis and
vulnerability assessment. If this data is needed for GMD research, I believed these requirements are covered by the Section 1600 data request.
Likes
0
Dislikes
0
Response
Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5
Answer
Document Name
Comment
Nothing further
Likes
0
Dislikes
0
Response
faranak sarbaz - Los Angeles Department of Water and Power - 1,3,5,6
Answer
Document Name
Comment
it would be beneficial to develop a guideline with as much as details as possible for entities to follow.
Likes
0
Dislikes
Response
0
Unofficial Nomination Form
Project 2019-01 Modifications to TPL-007-3
Standard Drafting Team
Do not use this form for submitting nominations. Use the electronic form to submit nominations for
Project 2019-01 Modifications to TPL-007-3 standard drafting team (SDT) members by 8 p.m. Eastern,
Tuesday, March 26, 2019. This unofficial version is provided to assist nominees in compiling the
information necessary to submit the electronic form.
Additional information is available on the project page. If you have questions, contact Senior Standards
Developer, Alison Oswald (via email), or at 404-446-9668.
By submitting a nomination form, you are indicating your willingness and agreement to actively
participate in face-to-face meetings and conference calls.
Previous drafting or review team experience is beneficial, but not required. A brief description of the
desired qualifications, expected commitment, and other pertinent information is included below.
Transmission System Planned Performance for Geomagnetic Disturbance Events
On November 15, 2018, the Federal Energy Regulatory Commission (FERC) issued an Order No. 851
directing NERC to develop and submit modifications to Reliability Standard TPL-007-3 to require the
development and completion of corrective action plans to mitigate assessed supplemental GMD event
vulnerabilities. In addition, Order No. 851 directs NERC to modify the provisions in TPL-007-3,
Requirement R7.4 that allows applicable entities to exceed deadlines for completing corrective action
plan tasks when situations beyond the control of the responsible entity arises. FERC directs NERC to
submit the modifications for approval within 12 months from the effective date of Reliability Standard
TPL-007-3.
Standard affected: TPL-007-3
A significant time commitment is expected of SDT members to meet the regulatory deadline
established in Order No. 851. SDT activities include participation in technical conferences, stakeholder
communications and outreach events, periodic drafting team meetings and conference calls.
Approximately one face-to-face meeting per quarter can be expected (on average three full working
days each meeting) with conference calls scheduled as needed to meet the agreed-upon timeline the
drafting team sets forth. NERC is seeking individuals from the United States and Canada who possess
experience in transmission planning and an understanding of GMD studies.
Name:
Organization:
Address:
Telephone:
Email:
Please briefly describe your experience and qualifications to serve on the requested Standard
Drafting Team (Bio):
If you are currently a member of any NERC drafting team, please list each team here:
Not currently on any active SAR or standard drafting team.
Currently a member of the following SAR or standard drafting team(s):
If you previously worked on any NERC drafting team please identify the team(s):
No prior NERC SAR or standard drafting team.
Prior experience on the following team(s):
Select each NERC Region in which you have experience relevant to the Project for which you are
volunteering:
Texas RE
FRCC
MRO
NPCC
RF
SERC
Unofficial Nomination Form
Project 2019-01 Modifications to TPL-007-3 | February 2019
WECC
NA – Not Applicable
2
Select each Industry Segment that you represent:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, and Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations and Regional Entities
NA – Not Applicable
Select each Function 1 in which you have current or prior expertise:
Balancing Authority
Compliance Enforcement Authority
Distribution Provider
Generator Operator
Generator Owner
Interchange Authority
Load-serving Entity
Market Operator
Planning Coordinator
Transmission Operator
Transmission Owner
Transmission Planner
Transmission Service Provider
Purchasing-selling Entity
Reliability Coordinator
Reliability Assurer
Resource Planner
Provide the names and contact information for two references who could attest to your technical
qualifications and your ability to work well in a group:
1
Name:
Telephone:
Organization:
Email:
These functions are defined in the NERC Functional Model, which is available on the NERC web site.
Unofficial Nomination Form
Project 2019-01 Modifications to TPL-007-3 | February 2019
3
Name:
Telephone:
Organization:
Email:
Provide the name and contact information of your immediate supervisor or a member of your
management who can confirm your organization’s willingness to support your active participation.
Name:
Telephone:
Title:
Email:
Unofficial Nomination Form
Project 2019-01 Modifications to TPL-007-3 | February 2019
4
Standards Announcement
Project 2019-01 Modifications to TPL-007-3
Nomination Period Open through March 26, 2019
Now Available
Nominations are being sought for standard drafting team members through 8 p.m. Eastern,
Tuesday, March 26, 2019.
Use the electronic form to submit a nomination. If you experience any difficulties using the
electronic form, contact Linda Jenkins. An unofficial Word version of the nomination form is posted
on the Drafting Team Vacancies page and the project page.
By submitting a nomination form, you are indicating your willingness and agreement to actively
participate in face-to-face meetings and conference calls.
The time commitment for this project is expected to be one face-to-face meetings per quarter (on
average three full working days each meeting) with conference calls scheduled as needed to meet
the agreed upon timeline the team sets forth. Team members may also have side projects, either
individually or by sub-group, to present for discussion and review. Lastly, an important component
of the SDT effort is outreach. Members of the team will be expected to conduct industry outreach
during the development process to support a successful ballot.
Previous drafting team experience is beneficial but not required. See the project page and unofficial
nomination form for additional information.
Next Steps
The Standards Committee is expected to appoint members to the standard drafting team in April
2019. Nominees will be notified shortly after they have been appointed.
For information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Senior Standards Developer, Alison Oswald (via email) or at
404-446-9668.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement | Project 2019-01 Modifications to TPL-007-3
Nomination Period |February 25, 2019 – March 26, 2019
2
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).
Description of Current Draft
This is the first draft of proposed standard for formal 45-day comment period.
Completed Actions
Date
Standards Committee approved Standard Authorization Request
(SAR) for posting
February 20, 2019
SAR posted for comment
February 25 –
March 27, 2019
Anticipated Actions
Date
45-day formal comment period with ballot
July – September
2019
45-day formal comment period with additional ballot
October –
December 2019
45-day formal comment period with second additional ballot
January – March
2020
10-day final ballot
April 2020
Board adoption
May 2020
Draft 1 of TPL-007-4
July 2019
Page 1 of 39
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
A. Introduction
1.
Title:
Events
Transmission System Planned Performance for Geomagnetic Disturbance
2.
Number:
TPL-007-4
3.
Purpose:
Establish requirements for Transmission system planned performance
during geomagnetic disturbance (GMD) events.
4.
Applicability:
4.1. Functional Entities:
4.1.1. Planning Coordinator with a planning area that includes a Facility or
Facilities specified in 4.2;
4.1.2. Transmission Planner with a planning area that includes a Facility or
Facilities specified in 4.2;
4.1.3. Transmission Owner who owns a Facility or Facilities specified in 4.2; and
4.1.4. Generator Owner who owns a Facility or Facilities specified in 4.2.
4.2. Facilities:
4.2.1. Facilities that include power transformer(s) with a high side, wyegrounded winding with terminal voltage greater than 200 kV.
5.
Effective Date: See Implementation Plan for TPL-007-4.
6.
Background: During a GMD event, geomagnetically-induced currents (GIC) may cause
transformer hot-spot heating or damage, loss of Reactive Power sources, increased
Reactive Power demand, and Misoperation(s), the combination of which may result in
voltage collapse and blackout.
B. Requirements and Measures
R1.
Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall
identify the individual and joint responsibilities of the Planning Coordinator and
Transmission Planner(s) in the Planning Coordinator’s planning for maintaining
models, performing the study or studies needed to complete benchmark and
supplemental GMD Vulnerability Assessments, and implementing process(es) to
obtain GMD measurement data as specified in this standard. [Violation Risk Factor:
Lower] [Time Horizon: Long-term Planning]
Draft 1 of TPL-007-4
July 2019
Page 2 of 39
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
M1. Each Planning Coordinator, in conjunction with its Transmission Planners, shall provide
documentation on roles and responsibilities, such as meeting minutes, agreements,
copies of procedures or protocols in effect between entities or between departments
of a vertically integrated system, or email correspondence that identifies an
agreement has been reached on individual and joint responsibilities for maintaining
models, performing the study or studies needed to complete benchmark and
supplemental GMD Vulnerability Assessments, and implementing process(es) to
obtain GMD measurement data in accordance with Requirement R1.
R2. Each responsible entity, as determined in Requirement R1, shall maintain System
models and GIC System models of the responsible entity’s planning area for
performing the study or studies needed to complete benchmark and supplemental
GMD Vulnerability Assessments. [Violation Risk Factor: High] [Time Horizon: Longterm Planning]
M2. Each responsible entity, as determined in Requirement R1, shall have evidence in
either electronic or hard copy format that it is maintaining System models and GIC
System models of the responsible entity’s planning area for performing the study or
studies needed to complete benchmark and supplemental GMD Vulnerability
Assessments.
R3. Each responsible entity, as determined in Requirement R1, shall have criteria for
acceptable System steady state voltage performance for its System during the GMD
events described in Attachment 1. [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]
M3. Each responsible entity, as determined in Requirement R1, shall have evidence, such
as electronic or hard copies of the criteria for acceptable System steady state voltage
performance for its System in accordance with Requirement R3.
Benchmark GMD Vulnerability Assessment(s)
R4. Each responsible entity, as determined in Requirement R1, shall complete a
benchmark GMD Vulnerability Assessment of the Near-Term Transmission Planning
Horizon at least once every 60 calendar months. This benchmark GMD Vulnerability
Assessment shall use a study or studies based on models identified in Requirement R2,
document assumptions, and document summarized results of the steady state
analysis. [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
4.1. The study or studies shall include the following conditions:
4.1.1. System On-Peak Load for at least one year within the Near-Term
Transmission Planning Horizon; and
4.1.2. System Off-Peak Load for at least one year within the Near-Term
Transmission Planning Horizon.
Draft 1 of TPL-007-4
July 2019
Page 3 of 39
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
4.2. The study or studies shall be conducted based on the benchmark GMD event
described in Attachment 1 to determine whether the System meets the
performance requirements for the steady state planning benchmark GMD event
contained in Table 1.
4.3. The benchmark GMD Vulnerability Assessment shall be provided: (i) to the
responsible entity’s Reliability Coordinator, adjacent Planning Coordinators, and
adjacent Transmission Planners within 90 calendar days of completion, and (ii) to
any functional entity that submits a written request and has a reliability-related
need within 90 calendar days of receipt of such request or within 90 calendar
days of completion of the benchmark GMD Vulnerability Assessment, whichever
is later.
4.3.1. If a recipient of the benchmark GMD Vulnerability Assessment provides
documented comments on the results, the responsible entity shall
provide a documented response to that recipient within 90 calendar days
of receipt of those comments.
M4. Each responsible entity, as determined in Requirement R1, shall have dated evidence
such as electronic or hard copies of its benchmark GMD Vulnerability Assessment
meeting all of the requirements in Requirement R4. Each responsible entity, as
determined in Requirement R1, shall also provide evidence, such as email records,
web postings with an electronic notice of posting, or postal receipts showing recipient
and date, that it has distributed its benchmark GMD Vulnerability Assessment: (i) to
the responsible entity’s Reliability Coordinator, adjacent Planning Coordinators, and
adjacent Transmission Planners within 90 calendar days of completion, and (ii) to any
functional entity that submits a written request and has a reliability-related need
within 90 calendar days of receipt of such request or within 90 calendar days of
completion of the benchmark GMD Vulnerability Assessment, whichever is later, as
specified in Requirement R4. Each responsible entity, as determined in Requirement
R1, shall also provide evidence, such as email notices or postal receipts showing
recipient and date, that it has provided a documented response to comments received
on its benchmark GMD Vulnerability Assessment within 90 calendar days of receipt of
those comments in accordance with Requirement R4.
R5. Each responsible entity, as determined in Requirement R1, shall provide GIC flow
information to be used for the benchmark thermal impact assessment of transformers
specified in Requirement R6 to each Transmission Owner and Generator Owner that
owns an applicable Bulk Electric System (BES) power transformer in the planning area.
The GIC flow information shall include: [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]
5.1. The maximum effective GIC value for the worst case geoelectric field orientation
for the benchmark GMD event described in Attachment 1. This value shall be
provided to the Transmission Owner or Generator Owner that owns each
applicable BES power transformer in the planning area.
Draft 1 of TPL-007-4
July 2019
Page 4 of 39
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
5.2. The effective GIC time series, GIC(t), calculated using the benchmark GMD event
described in Attachment 1 in response to a written request from the
Transmission Owner or Generator Owner that owns an applicable BES power
transformer in the planning area. GIC(t) shall be provided within 90 calendar
days of receipt of the written request and after determination of the maximum
effective GIC value in Part 5.1.
M5. Each responsible entity, as determined in Requirement R1, shall provide evidence,
such as email records, web postings with an electronic notice of posting, or postal
receipts showing recipient and date, that it has provided the maximum effective GIC
values to the Transmission Owner and Generator Owner that owns each applicable
BES power transformer in the planning area as specified in Requirement R5, Part 5.1.
Each responsible entity, as determined in Requirement R1, shall also provide evidence,
such as email records, web postings with an electronic notice of posting, or postal
receipts showing recipient and date, that it has provided GIC(t) in response to a
written request from the Transmission Owner or Generator Owner that owns an
applicable BES power transformer in the planning area.
R6. Each Transmission Owner and Generator Owner shall conduct a benchmark thermal
impact assessment for its solely and jointly owned applicable BES power transformers
where the maximum effective GIC value provided in Requirement R5, Part 5.1, is 75 A
per phase or greater. The benchmark thermal impact assessment shall: [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]
6.1. Be based on the effective GIC flow information provided in Requirement R5;
6.2. Document assumptions used in the analysis;
6.3. Describe suggested actions and supporting analysis to mitigate the impact of
GICs, if any; and
6.4. Be performed and provided to the responsible entities, as determined in
Requirement R1, within 24 calendar months of receiving GIC flow information
specified in Requirement R5, Part 5.1.
M6. Each Transmission Owner and Generator Owner shall have evidence such as electronic
or hard copies of its benchmark thermal impact assessment for all of its solely and
jointly owned applicable BES power transformers where the maximum effective GIC
value provided in Requirement R5, Part 5.1, is 75 A per phase or greater, and shall
have evidence such as email records, web postings with an electronic notice of
posting, or postal receipts showing recipient and date, that it has provided its thermal
impact assessment to the responsible entities as specified in Requirement R6.
R7.
Each responsible entity, as determined in Requirement R1, that concludes through
the benchmark GMD Vulnerability Assessment conducted in Requirement R4 that
their System does not meet the performance requirements for the steady state
planning benchmark GMD event contained in Table 1, shall develop a Corrective
Draft 1 of TPL-007-4
July 2019
Page 5 of 39
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Action Plan (CAP) addressing how the performance requirements will be met. The CAP
shall: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
7.1. List System deficiencies and the associated actions needed to achieve required
System performance. Examples of such actions include:
•
Installation, modification, retirement, or removal of Transmission and
generation Facilities and any associated equipment.
•
Installation, modification, or removal of Protection Systems or Remedial
Action Schemes.
•
Use of Operating Procedures, specifying how long they will be needed as
part of the CAP.
•
Use of Demand-Side Management, new technologies, or other initiatives.
7.2. Be developed within one year of completion of the benchmark GMD
Vulnerability Assessment.
7.3. Include a timetable, subject to ERO approval for any extension sought under Part
7.4, for implementing the selected actions from Part 7.1. The timetable shall:
7.3.1. Specify implementation of non-hardware mitigation, if any, within two
years of development of the CAP; and
7.3.2. Specify implementation of hardware mitigation, if any, within four years
of development of the CAP.
7.4. Be submitted to the ERO with a request for extension if the responsible entity is
unable to implement the CAP within the timetable provided in Part 7.3. The
submitted CAP shall document the following:
7.4.1. Circumstances causing the delay for fully or partially implementing the
selected actions in Part 7.1 and how those circumstances are beyond the
control of the responsible entity;
7.4.2. Revisions to the selected actions in Part 7.1, if any, including utilization of
Operating Procedures, if applicable; and
7.4.3. Updated timetable for implementing the selected actions in Part 7.1.
7.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent
Planning Coordinator(s), adjacent Transmission Planner(s), and functional
entities referenced in the CAP within 90 calendar days of development or
revision, and (ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later.
7.5.1. If a recipient of the CAP provides documented comments on the CAP, the
responsible entity shall provide a documented response to that recipient
within 90 calendar days of receipt of those comments.
Draft 1 of TPL-007-4
July 2019
Page 6 of 39
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
M7. Each responsible entity, as determined in Requirement R1, that concludes, through
the benchmark GMD Vulnerability Assessment conducted in Requirement R4, that the
responsible entity’s System does not meet the performance requirements for the
steady state planning benchmark GMD event contained in Table 1 shall have evidence
such as dated electronic or hard copies of its CAP including timetable for
implementing selected actions, as specified in Requirement R7. Each responsible
entity, as determined in Requirement R1, shall also provide evidence, such as email
records or postal receipts showing recipient and date, that it submitted a request for
extension to the ERO if the responsible entity is unable to implement the CAP within
the timetable provided in Part 7.3. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records, web postings with
an electronic notice of posting, or postal receipts showing recipient and date, that it
has distributed its CAP or relevant information, if any, (i) to the responsible entity’s
Reliability Coordinator, adjacent Planning Coordinator(s), adjacent Transmission
Planner(s), and functional entities referenced in the CAP within 90 calendar days of
development or revision, and (ii) to any functional entity that submits a written
request and has a reliability-related need within 90 calendar days of receipt of such
request or within 90 calendar days of development or revision, whichever is later as
specified in Requirement R7. Each responsible entity, as determined in Requirement
R1, shall also provide evidence, such as email notices or postal receipts showing
recipient and date, that it has provided a documented response to comments received
on its CAP within 90 calendar days of receipt of those comments, in accordance with
Requirement R7.
Supplemental GMD Vulnerability Assessment(s)
R8.
Each responsible entity, as determined in Requirement R1, shall complete a
supplemental GMD Vulnerability Assessment of the Near-Term Transmission Planning
Horizon at least once every 60 calendar months. This supplemental GMD Vulnerability
Assessment shall use a study or studies based on models identified in Requirement
R2, document assumptions, and document summarized results of the steady state
analysis. [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
8.1. The study or studies shall include the following conditions:
8.1.1. System On-Peak Load for at least one year within the Near-Term
Transmission Planning Horizon; and
8.1.2. System Off-Peak Load for at least one year within the Near-Term
Transmission Planning Horizon.
8.2. The study or studies shall be conducted based on the supplemental GMD event
described in Attachment 1 to determine whether the System meets the
performance requirements for the steady state planning supplemental GMD
event contained in Table 1.
Draft 1 of TPL-007-4
July 2019
Page 7 of 39
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
8.3. The supplemental GMD Vulnerability Assessment shall be provided: (i) to the
responsible entity’s Reliability Coordinator, adjacent Planning Coordinators,
adjacent Transmission Planners within 90 calendar days of completion, and (ii) to
any functional entity that submits a written request and has a reliability-related
need within 90 calendar days of receipt of such request or within 90 calendar
days of completion of the supplemental GMD Vulnerability Assessment,
whichever is later.
8.3.1. If a recipient of the supplemental GMD Vulnerability Assessment
provides documented comments on the results, the responsible entity
shall provide a documented response to that recipient within 90 calendar
days of receipt of those comments.
M8. Each responsible entity, as determined in Requirement R1, shall have dated evidence
such as electronic or hard copies of its supplemental GMD Vulnerability Assessment
meeting all of the requirements in Requirement R8. Each responsible entity, as
determined in Requirement R1, shall also provide evidence, such as email records,
web postings with an electronic notice of posting, or postal receipts showing recipient
and date, that it has distributed its supplemental GMD Vulnerability Assessment: (i) to
the responsible entity’s Reliability Coordinator, adjacent Planning Coordinators,
adjacent Transmission Planners within 90 calendar days of completion, and (ii) to any
functional entity that submits a written request and has a reliability-related need
within 90 calendar days of receipt of such request or within 90 calendar days of
completion of the supplemental GMD Vulnerability Assessment, whichever is later, as
specified in Requirement R8. Each responsible entity, as determined in Requirement
R1, shall also provide evidence, such as email notices or postal receipts showing
recipient and date, that it has provided a documented response to comments
received on its supplemental GMD Vulnerability Assessment within 90 calendar days
of receipt of those comments in accordance with Requirement R8.
R9.
Each responsible entity, as determined in Requirement R1, shall provide GIC flow
information to be used for the supplemental thermal impact assessment of
transformers specified in Requirement R10 to each Transmission Owner and
Generator Owner that owns an applicable Bulk Electric System (BES) power
transformer in the planning area. The GIC flow information shall include: [Violation
Risk Factor: Medium] [Time Horizon: Long-term Planning]
9.1. The maximum effective GIC value for the worst case geoelectric field orientation
for the supplemental GMD event described in Attachment 1. This value shall be
provided to the Transmission Owner or Generator Owner that owns each
applicable BES power transformer in the planning area.
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
9.2. The effective GIC time series, GIC(t), calculated using the supplemental GMD
event described in Attachment 1 in response to a written request from the
Transmission Owner or Generator Owner that owns an applicable BES power
transformer in the planning area. GIC(t) shall be provided within 90 calendar
days of receipt of the written request and after determination of the maximum
effective GIC value in Part 9.1.
M9. Each responsible entity, as determined in Requirement R1, shall provide evidence,
such as email records, web postings with an electronic notice of posting, or postal
receipts showing recipient and date, that it has provided the maximum effective GIC
values to the Transmission Owner and Generator Owner that owns each applicable
BES power transformer in the planning area as specified in Requirement R9, Part 9.1.
Each responsible entity, as determined in Requirement R1, shall also provide
evidence, such as email records, web postings with an electronic notice of posting, or
postal receipts showing recipient and date, that it has provided GIC(t) in response to a
written request from the Transmission Owner or Generator Owner that owns an
applicable BES power transformer in the planning area.
R10. Each Transmission Owner and Generator Owner shall conduct a supplemental
thermal impact assessment for its solely and jointly owned applicable BES power
transformers where the maximum effective GIC value provided in Requirement R9,
Part 9.1, is 85 A per phase or greater. The supplemental thermal impact assessment
shall: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
10.1. Be based on the effective GIC flow information provided in Requirement R9;
10.2. Document assumptions used in the analysis;
10.3. Describe suggested actions and supporting analysis to mitigate the impact of
GICs, if any; and
10.4. Be performed and provided to the responsible entities, as determined in
Requirement R1, within 24 calendar months of receiving GIC flow information
specified in Requirement R9, Part 9.1.
M10. Each Transmission Owner and Generator Owner shall have evidence such as
electronic or hard copies of its supplemental thermal impact assessment for all of its
solely and jointly owned applicable BES power transformers where the maximum
effective GIC value provided in Requirement R9, Part 9.1, is 85 A per phase or greater,
and shall have evidence such as email records, web postings with an electronic notice
of posting, or postal receipts showing recipient and date, that it has provided its
supplemental thermal impact assessment to the responsible entities as specified in
Requirement R10.
R11. Each responsible entity, as determined in Requirement R1, that concludes through
the supplemental GMD Vulnerability Assessment conducted in Requirement R8 that
their System does not meet the performance requirements for the steady state
planning supplemental GMD event contained in Table 1, shall develop a Corrective
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Action Plan (CAP) addressing how the performance requirements will be met. The CAP
shall: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
11.1. List System deficiencies and the associated actions needed to achieve required
System performance. Examples of such actions include:
•
Installation, modification, retirement, or removal of Transmission and
generation Facilities and any associated equipment.
•
Installation, modification, or removal of Protection Systems or Remedial
Action Schemes.
•
Use of Operating Procedures, specifying how long they will be needed as
part of the CAP.
•
Use of Demand-Side Management, new technologies, or other initiatives.
11.2. Be developed within one year of completion of the supplemental GMD
Vulnerability Assessment.
11.3. Include a timetable, subject to ERO approval for any extension sought under Part
11.4, for implementing the selected actions from Part 11.1. The timetable shall:
11.3.1. Specify implementation of non-hardware mitigation, if any, within two
years of development of the CAP; and
11.3.2. Specify implementation of hardware mitigation, if any, within four years
of development of the CAP.
11.4. Be submitted to the ERO with a request for extension if the responsible entity is
unable to implement the CAP within the timetable provided in Part 11.3. The
submitted CAP shall document the following:
11.4.1. Circumstances causing the delay for fully or partially implementing the
selected actions in Part 11.1 and how those circumstances are beyond
the control of the responsible entity;
11.4.2. Revisions to the selected actions in Part 11.1, if any, including utilization
of Operating Procedures, if applicable; and
11.4.3. Updated timetable for implementing the selected actions in Part 11.1.
11.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent
Planning Coordinator(s), adjacent Transmission Planner(s), and functional
entities referenced in the CAP within 90 calendar days of development or
revision, and (ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later.
11.5.1. If a recipient of the CAP provides documented comments on the CAP, the
responsible entity shall provide a documented response to that recipient
within 90 calendar days of receipt of those comments.
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
M11. Each responsible entity, as determined in Requirement R1, that concludes, through
the supplemental GMD Vulnerability Assessment conducted in Requirement R8, that
the responsible entity’s System does not meet the performance requirements for the
steady state planning supplemental GMD event contained in Table 1 shall have
evidence such as dated electronic or hard copies of its CAP including timetable for
implementing selected actions, as specified in Requirement R11. Each responsible
entity, as determined in Requirement R1, shall also provide evidence, such as email
records or postal receipts showing recipient and date, that it submitted a request for
extension to the ERO if the responsible entity is unable to implement the CAP within
the timetable provided in Part 11.3. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records, web postings with
an electronic notice of posting, or postal receipts showing recipient and date, that it
has distributed its CAP or relevant information, if any, (i) to the responsible entity’s
Reliability Coordinator, adjacent Planning Coordinator(s), adjacent Transmission
Planner(s), and functional entities referenced in the CAP within 90 calendar days of
development or revision, and (ii) to any functional entity that submits a written
request and has a reliability-related need within 90 calendar days of receipt of such
request or within 90 calendar days of development or revision, whichever is later as
specified in Requirement R11. Each responsible entity, as determined in Requirement
R1, shall also provide evidence, such as email notices or postal receipts showing
recipient and date, that it has provided a documented response to comments received
on its CAP within 90 calendar days of receipt of those comments, in accordance with
Requirement R11.
GMD Measurement Data Processes
R12. Each responsible entity, as determined in Requirement R1, shall implement a process
to obtain GIC monitor data from at least one GIC monitor located in the Planning
Coordinator’s planning area or other part of the system included in the Planning
Coordinator’s GIC System model. [Violation Risk Factor: Lower] [Time Horizon: Longterm Planning]
M12. Each responsible entity, as determined in Requirement R1, shall have evidence such
as electronic or hard copies of its GIC monitor location(s) and documentation of its
process to obtain GIC monitor data in accordance with Requirement R12.
R13. Each responsible entity, as determined in Requirement R1, shall implement a process
to obtain geomagnetic field data for its Planning Coordinator’s planning area.
[Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
M13. Each responsible entity, as determined in Requirement R1, shall have evidence such
as electronic or hard copies of its process to obtain geomagnetic field data for its
Planning Coordinator’s planning area in accordance with Requirement R13.
C. Compliance
1.
Compliance Monitoring Process
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
Authority may ask an entity to provide other evidence to show that it was
compliant for the full-time period since the last audit.
The applicable entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
•
For Requirements R1, R2, R3, R5, R6, R9, and R10, each responsible entity
shall retain documentation as evidence for five years.
•
For Requirements R4 and R8, each responsible entity shall retain
documentation of the current GMD Vulnerability Assessment and the
preceding GMD Vulnerability Assessment.
•
For Requirement R7 and R11, each responsible entity shall retain
documentation as evidence for five years or until all actions in the
Corrective Action Plan are completed, whichever is later.
•
For Requirements R12 and R13, each responsible entity shall retain
documentation as evidence for three years.
1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Table 1: Steady State Planning GMD Event
Steady State:
a. Voltage collapse, Cascading and uncontrolled islanding shall not occur.
b. Generation loss is acceptable as a consequence of the steady state planning GMD events.
c. Planned System adjustments such as Transmission configuration changes and re-dispatch of generation are allowed if such
adjustments are executable within the time duration applicable to the Facility Ratings.
Category
Initial Condition
Event
Interruption of
Firm
Transmission
Service Allowed
Load Loss
Allowed
Benchmark GMD
Event – GMD
Event with
Outages
1. System as may be
postured in response
to space weather
information1, and then
2. GMD event2
Reactive Power compensation devices
and other Transmission Facilities
removed as a result of Protection
System operation or Misoperation due
to harmonics during the GMD event
Yes3
Yes3
Supplemental
GMD Event – GMD
Event with
Outages
1. System as may be
postured in response
to space weather
information1, and then
2. GMD event2
Reactive Power compensation devices
and other Transmission Facilities
removed as a result of Protection
System operation or Misoperation due
to harmonics during the GMD event
Yes
Yes
Table 1: Steady State Performance Footnotes
1. The System condition for GMD planning may include adjustments to posture the System that are executable in response to
space weather information.
2. The GMD conditions for the benchmark and supplemental planning events are described in Attachment 1.
3. Load loss as a result of manual or automatic Load shedding (e.g., UVLS) and/or curtailment of Firm Transmission Service may
be used to meet BES performance requirements during studied GMD conditions. The likelihood and magnitude of Load loss or
curtailment of Firm Transmission Service should be minimized.
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
R1.
R2.
Draft 1 of TPL-007-4
July 2019
Lower VSL
N/A
N/A
Violation Severity Levels
Moderate VSL
N/A
N/A
High VSL
Severe VSL
N/A
The Planning Coordinator, in
conjunction with its
Transmission Planner(s),
failed to determine and
identify individual or joint
responsibilities of the
Planning Coordinator and
Transmission Planner(s) in
the Planning Coordinator’s
planning area for
maintaining models,
performing the study or
studies needed to complete
benchmark and
supplemental GMD
Vulnerability Assessments,
and implementing
process(es) to obtain GMD
measurement data as
specified in this standard.
The responsible entity did
not maintain either System
models or GIC System
models of the responsible
entity’s planning area for
performing the studies
The responsible entity did
not maintain both System
models and GIC System
models of the responsible
entity’s planning area for
performing the studies
Page 14 of 39
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
needed to complete
benchmark and
supplemental GMD
Vulnerability Assessments.
R3.
R4.
N/A
N/A
N/A
The responsible entity
completed a benchmark
GMD Vulnerability
Assessment, but it was more
than 60 calendar months
and less than or equal to 64
calendar months since the
last benchmark GMD
Vulnerability Assessment.
The responsible entity’s
completed benchmark GMD
Vulnerability Assessment
failed to satisfy one of the
elements listed in
Requirement R4, Parts 4.1
through 4.3;
OR
The responsible entity
completed a benchmark
GMD Vulnerability
Assessment, but it was more
than 64 calendar months
and less than or equal to 68
calendar months since the
The responsible entity’s
completed benchmark GMD
Vulnerability Assessment
failed to satisfy two of the
elements listed in
Requirement R4, Parts 4.1
through 4.3;
OR
The responsible entity
completed a benchmark
GMD Vulnerability
Assessment, but it was more
than 68 calendar months
and less than or equal to 72
calendar months since the
Draft 1 of TPL-007-4
July 2019
Severe VSL
needed to complete
benchmark and
supplemental GMD
Vulnerability Assessments.
The responsible entity did
not have criteria for
acceptable System steady
state voltage performance
for its System during the
GMD events described in
Attachment 1 as required.
The responsible entity’s
completed benchmark GMD
Vulnerability Assessment
failed to satisfy three of the
elements listed in
Requirement R4, Parts 4.1
through 4.3;
OR
The responsible entity
completed a benchmark
GMD Vulnerability
Assessment, but it was more
than 72 calendar months
since the last benchmark
Page 15 of 39
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
R5.
R6.
Lower VSL
Moderate VSL
High VSL
Severe VSL
last benchmark GMD
Vulnerability Assessment.
last benchmark GMD
Vulnerability Assessment.
GMD Vulnerability
Assessment;
OR
The responsible entity does
not have a completed
benchmark GMD
Vulnerability Assessment.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 90
calendar days and less than
or equal to 100 calendar
days after receipt of a
written request.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 100
calendar days and less than
or equal to 110 calendar
days after receipt of a
written request.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 110
calendar days after receipt
of a written request.
The responsible entity did
not provide the maximum
effective GIC value to the
Transmission Owner and
Generator Owner that owns
each applicable BES power
transformer in the planning
area;
OR
The responsible entity did
not provide the effective GIC
time series, GIC(t), upon
written request.
The responsible entity failed
to conduct a benchmark
thermal impact assessment
for 5% or less or one of its
solely owned and jointly
owned applicable BES power
The responsible entity failed
to conduct a benchmark
thermal impact assessment
for more than 5% up to (and
including) 10% or two of its
solely owned and jointly
The responsible entity failed
to conduct a benchmark
thermal impact assessment
for more than 10% up to
(and including) 15% or three
of its solely owned and
The responsible entity failed
to conduct a benchmark
thermal impact assessment
for more than 15% or more
than three of its solely
owned and jointly owned
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July 2019
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase;
OR
The responsible entity
conducted a benchmark
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase
but did so more than 24
calendar months and less
than or equal to 26 calendar
months of receiving GIC flow
information specified in
Requirement R5, Part 5.1.
owned applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase;
OR
The responsible entity
conducted a benchmark
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase
but did so more than 26
calendar months and less
than or equal to 28 calendar
months of receiving GIC flow
information specified in
Requirement R5, Part 5.1;
OR
The responsible entity failed
to include one of the
jointly owned applicable BES
power transformers
(whichever is greater) where
the maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase;
OR
The responsible entity
conducted a benchmark
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase
but did so more than 28
calendar months and less
than or equal to 30 calendar
months of receiving GIC flow
information specified in
Requirement R5, Part 5.1;
OR
The responsible entity failed
to include two of the
applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase;
OR
The responsible entity
conducted a benchmark
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase
but did so more than 30
calendar months of receiving
GIC flow information
specified in Requirement R5,
Part 5.1;
OR
The responsible entity failed
to include three of the
required elements as listed
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
required elements as listed
in Requirement R6, Parts 6.1
through 6.3.
required elements as listed
in Requirement R6, Parts 6.1
through 6.3.
in Requirement R6, Parts 6.1
through 6.3.
The responsible entity’s
Corrective Action Plan failed
to comply with one of the
elements in Requirement
R7, Parts 7.1 through 7.5.
The responsible entity’s
Corrective Action Plan failed
to comply with two of the
elements in Requirement R7,
Parts 7.1 through 7.5.
The responsible entity’s
Corrective Action Plan failed
to comply with three of the
elements in Requirement
R7, Parts 7.1 through 7.5.
The responsible entity’s
Corrective Action Plan failed
to comply with four or more
of the elements in
Requirement R7, Parts 7.1
through 7.5;
OR
The responsible entity did
not develop a Corrective
Action Plan as required by
Requirement R7.
The responsible entity
completed a supplemental
GMD Vulnerability
Assessment, but it was more
than 60 calendar months
and less than or equal to 64
calendar months since the
last supplemental GMD
Vulnerability Assessment.
The responsible entity’s
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
one of the elements listed in
Requirement R8, Parts 8.1
through 8.3;
OR
The responsible entity
completed a supplemental
GMD Vulnerability
Assessment, but it was more
The responsible entity’s
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
two of the elements listed in
Requirement R8, Parts 8.1
through 8.3;
OR
The responsible entity
completed a supplemental
GMD Vulnerability
Assessment, but it was more
The responsible entity’s
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
three of the elements listed
in Requirement R8, Parts 8.1
through 8.3;
OR
The responsible entity
completed a supplemental
GMD Vulnerability
Assessment, but it was more
R7.
R8.
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
R9.
R10.
Lower VSL
Moderate VSL
High VSL
Severe VSL
than 64 calendar months
and less than or equal to 68
calendar months since the
last supplemental GMD
Vulnerability Assessment.
than 68 calendar months
and less than or equal to 72
calendar months since the
last supplemental GMD
Vulnerability Assessment.
than 72 calendar months
since the last supplemental
GMD Vulnerability
Assessment;
OR
The responsible entity does
not have a completed
supplemental GMD
Vulnerability Assessment.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 90
calendar days and less than
or equal to 100 calendar
days after receipt of a
written request.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 100
calendar days and less than
or equal to 110 calendar
days after receipt of a
written request.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 110
calendar days after receipt
of a written request.
The responsible entity did
not provide the maximum
effective GIC value to the
Transmission Owner and
Generator Owner that owns
each applicable BES power
transformer in the planning
area;
OR
The responsible entity did
not provide the effective GIC
time series, GIC(t), upon
written request.
The responsible entity failed
to conduct a supplemental
thermal impact assessment
for 5% or less or one of its
The responsible entity failed
to conduct a supplemental
thermal impact assessment
for more than 5% up to (and
The responsible entity failed
to conduct a supplemental
thermal impact assessment
for more than 10% up to
The responsible entity failed
to conduct a supplemental
thermal impact assessment
for more than 15% or more
Draft 1 of TPL-007-4
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
solely owned and jointly
owned applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase;
OR
The responsible entity
conducted a supplemental
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase
but did so more than 24
calendar months and less
than or equal to 26 calendar
months of receiving GIC flow
information specified in
Requirement R9, Part 9.1.
including) 10% or two of its
solely owned and jointly
owned applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase;
OR
The responsible entity
conducted a supplemental
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase
but did so more than 26
calendar months and less
than or equal to 28 calendar
months of receiving GIC flow
information specified in
Requirement R9, Part 9.1
OR
(and including) 15% or three
of its solely owned and
jointly owned applicable BES
power transformers
(whichever is greater) where
the maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase;
OR
The responsible entity
conducted a supplemental
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase
but did so more than 28
calendar months and less
than or equal to 30 calendar
months of receiving GIC flow
information specified in
Requirement R9, Part 9.1;
OR
than three of its solely
owned and jointly owned
applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase;
OR
The responsible entity
conducted a supplemental
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase
but did so more than 30
calendar months of receiving
GIC flow information
specified in Requirement R9,
Part 9.1;
OR
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
R11.
Lower VSL
The responsible entity’s
Corrective Action Plan failed
to comply with one of the
elements in Requirement
R11, Parts 11.1 through
11.5.
Draft 1 of TPL-007-4
July 2019
Moderate VSL
High VSL
Severe VSL
The responsible entity failed
to include one of the
required elements as listed
in Requirement R10, Parts
10.1 through 10.3.
The responsible entity failed
to include two of the
required elements as listed
in Requirement R10, Parts
10.1 through 10.3.
The responsible entity failed
to include three of the
required elements as listed
in Requirement R10, Parts
10.1 through 10.3.
The responsible entity’s
Corrective Action Plan failed
to comply with three of the
elements in Requirement
R11, Parts 11.1 through
11.5.
The responsible entity’s
Corrective Action Plan failed
to comply with four or more
of the elements in
Requirement R11, Parts 11.1
through 11.5;
OR
The responsible entity did
not develop a Corrective
Action Plan as required by
Requirement R11.
The responsible entity’s
Corrective Action Plan failed
to comply with two of the
elements in Requirement
R11, Parts 11.1 through
11.5.
Page 21 of 39
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
R12.
R13.
Draft 1 of TPL-007-4
July 2019
Violation Severity Levels
Lower VSL
N/A
N/A
Moderate VSL
N/A
N/A
High VSL
N/A
N/A
Severe VSL
The responsible entity did
not implement a process to
obtain GIC monitor data
from at least one GIC
monitor located in the
Planning Coordinator’s
planning area or other part
of the system included in the
Planning Coordinator’s GIC
System Model.
The responsible entity did
not implement a process to
obtain geomagnetic field
data for its Planning
Coordinator’s planning area.
Page 22 of 39
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
D. Regional Variances
D.A. Regional Variance for Canadian Jurisdictions
This Variance shall be applicable in those Canadian jurisdictions where the Variance
has been approved for use by the applicable governmental authority or has otherwise
become effective in the jurisdiction.
This variance replaces all references to “Attachment 1” in the standard with
“Attachment 1 or Attachment 1-CAN.”
In addition, this Variance replaces Requirement R7, Part 7.3 through Part 7.5 and
Requirement R11, Part 11.3 through Part 11.5 with the following:
D.A.7.3. Include a timetable, subject to revision by the responsible entity in Part
D.A.7.4, for implementing the selected actions from Part 7.1. The timetable
shall:
D.A.7.3.1. Specify implementation of non-hardware mitigation, if any, within
two years of the later of the development of the CAP or receipt of
regulatory approvals, if required; and
D.A.7.3.2. Specify implementation of hardware mitigation, if any, within four
years of the later of the development of the CAP or receipt of
regulatory approvals, if required.
D.A.7.4. Be revised if the responsible entity is unable to implement the CAP within
the timetable for implementation provided in Part D.A.7.3. The revised CAP
shall document the following:
D.A.7.4.1 Circumstances causing the delay for fully or partially implementing the
selected actions in Part 7.1 and how those circumstances are beyond
the control of the responsible entity;
D.A.7.4.2 Revisions to the selected actions in Part 7.1, if any, including utilization
of Operating Procedures if applicable; and
D.A.7.4.3 Updated timetable for implementing the selected actions in Part 7.1.
D.A.7.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent
Planning Coordinator(s), adjacent Transmission Planner(s), and functional
entities referenced in the CAP within 90 calendar days of development or
revision, (ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later, and
(iii) to the Compliance Enforcement Authority or Applicable Governmental
Authority when revised under D.A.7.4 within 90 calendar days of revision.
D.A.7.5.1 If a recipient of the CAP provides documented comments on the CAP,
the responsible entity shall provide a documented response to that
recipient within 90 calendar days of receipt of those comments.
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July 2019
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
D.A.M.7. Each responsible entity, as determined in Requirement R1, that concludes,
through the benchmark GMD Vulnerability Assessment conducted in
Requirement R4, that the responsible entity’s System does not meet the
performance requirements for the steady state planning benchmark GMD
event contained in Table 1 shall have evidence such as dated electronic or
hard copies of its CAP including timetable for implementing selected actions,
as specified in Requirement R7. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records or postal
receipts showing recipient and date, that it has revised its CAP if situations
beyond the responsible entity's control prevent implementation of the CAP
within the timetable specified. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records, web
postings with an electronic notice of posting, or postal receipts showing
recipient and date, that it has distributed its CAP or relevant information, if
any, (i) to the responsible entity’s Reliability Coordinator, adjacent Planning
Coordinator(s), adjacent Transmission Planner(s), and functional entities
referenced in the CAP within 90 calendar days of development or revision,
(ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later as
specified in Requirement R7, and (iii) to the Compliance Enforcement
Authority or Applicable Governmental Authority when revised under D.A.7.4
within 90 calendar days of revision. Each responsible entity, as determined
in Requirement R1, shall also provide evidence, such as email notices or
postal receipts showing recipient and date, that it has provided a
documented response to comments received on its CAP within 90 calendar
days of receipt of those comments, in accordance with Requirement R7.
D.A.11.3.Include a timetable, subject to revision by the responsible entity in Part
D.A.11.4, for implementing the selected actions from Part 11.1. The
timetable shall:
D.A.11.3.1. Specify implementation of non-hardware mitigation, if any, within
two years of the later of the development of the CAP or receipt of
regulatory approvals, if required; and
D.A.11.3.2. Specify implementation of hardware mitigation, if any, within four
years of the later of the development of the CAP or receipt of
regulatory approvals, if required.
D.A.11.4. Be revised if the responsible entity is unable to implement the CAP within
the timetable for implementation provided in Part D.A.11.3. The revised CAP
shall document the following:
D.A.11.4.1 Circumstances causing the delay for fully or partially implementing
the selected actions in Part 11.1 and how those circumstances are
beyond the control of the responsible entity;
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
D.A.11.4.2 Revisions to the selected actions in Part 11.1, if any, including
utilization of Operating Procedures if applicable; and
D.A.11.4.3 Updated timetable for implementing the selected actions in Part
11.1.
D.A.11.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent
Planning Coordinator(s), adjacent Transmission Planner(s), and functional
entities referenced in the CAP within 90 calendar days of development or
revision, (ii) to any functional entity that submits a written request and has
a reliability-related need within 90 calendar days of receipt of such request
or within 90 calendar days of development or revision, whichever is later,
and (iii) to the Compliance Enforcement Authority or Applicable
Governmental Authority when revised under D.A.11.4 within 90 calendar
days of revision.
D.A.11.5.1. If a recipient of the CAP provides documented comments on the
CAP, the responsible entity shall provide a documented response to
that recipient within 90 calendar days of receipt of those comments.
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
D.A.M.11. Each responsible entity, as determined in Requirement R1, that concludes,
through the supplemental GMD Vulnerability Assessment conducted in
Requirement R8, that the responsible entity’s System does not meet the
performance requirements for the steady state planning supplemental GMD
event contained in Table 1 shall have evidence such as dated electronic or
hard copies of its CAP including timetable for implementing selected actions,
as specified in Requirement R11. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records or postal
receipts showing recipient and date, that it has revised its CAP if situations
beyond the responsible entity's control prevent implementation of the CAP
within the timetable specified. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records, web
postings with an electronic notice of posting, or postal receipts showing
recipient and date, that it has distributed its CAP or relevant information, if
any, (i) to the responsible entity’s Reliability Coordinator, adjacent Planning
Coordinator(s), adjacent Transmission Planner(s), and functional entities
referenced in the CAP within 90 calendar days of development or revision,
(ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later as
specified in Requirement R11, and (iii) to the Compliance Enforcement
Authority or Applicable Governmental Authority when revised under
D.A.11.4 within 90 calendar days of revision. Each responsible entity, as
determined in Requirement R1, shall also provide evidence, such as email
notices or postal receipts showing recipient and date, that it has provided a
documented response to comments received on its CAP within 90 calendar
days of receipt of those comments, in accordance with Requirement R11.
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
E. Associated Documents
Attachment 1
Attachment 1-CAN
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Version History
Version
1
Date
Action
December 17, 2014 Adopted by the NERC Board of Trustees
Change
Tracking
New
Revised to
respond to
directives in FERC
Order No. 830.
2
November 9, 2017
Adopted by the NERC Board of Trustees
2
November 25, 2018
FERC Order issued approving TPL-007-2.
Docket No. RM18-8-000
3
February 7, 2019
Adopted by the NERC Board of Trustees
Canadian
Variance
Adopted by the NERC Board of Trustees
Revised to
respond to
directives in FERC
Order. 851
4
Draft 1 of TPL-007-4
July 2019
TBD
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Attachment 1
Calculating Geoelectric Fields for the Benchmark and Supplemental GMD Events
The benchmark GMD event 1 defines the geoelectric field values used to compute GIC flows that
are needed to conduct a benchmark GMD Vulnerability Assessment. It is composed of the
following elements: (1) a reference peak geoelectric field amplitude of 8 V/km derived from
statistical analysis of historical magnetometer data; (2) scaling factors to account for local
geomagnetic latitude; (3) scaling factors to account for local earth conductivity; and (4) a
reference geomagnetic field time series or waveform to facilitate time-domain analysis of GMD
impact on equipment.
The supplemental GMD event is composed of similar elements as described above, except (1) the
reference peak geoelectric field amplitude is 12 V/km over a localized area; and (2) the
geomagnetic field time series or waveform includes a local enhancement in the waveform.2
The regional geoelectric field peak amplitude used in GMD Vulnerability Assessment, E peak , can
be obtained from the reference geoelectric field value of 8 V/km for the benchmark GMD event
(1) or 12 V/km for the supplemental GMD event (2) using the following relationships:
𝐸𝐸𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝 = 8 × 𝛼𝛼 × 𝛽𝛽 𝑏𝑏 (𝑉𝑉 ⁄𝑘𝑘𝑘𝑘)
𝐸𝐸𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝 = 12 × 𝛼𝛼 × 𝛽𝛽 𝑠𝑠 (𝑉𝑉 ⁄𝑘𝑘𝑘𝑘)
(1)
(2)
where, α is the scaling factor to account for local geomagnetic latitude, and β is a scaling factor
to account for the local earth conductivity structure. Subscripts b and s for the β scaling factor
denote association with the benchmark or supplemental GMD events, respectively.
Scaling the Geomagnetic Field
The benchmark and supplemental GMD events are defined for geomagnetic latitude of 60° and
must be scaled to account for regional differences based on geomagnetic latitude. Table 2
provides a scaling factor correlating peak geoelectric field to geomagnetic latitude. Alternatively,
the scaling factor α is computed with the empirical expression:
𝛼𝛼 = 0.001 × 𝑒𝑒 (0.115×𝐿𝐿)
(3)
where, L is the geomagnetic latitude in degrees and 0.1 ≤ α ≤ 1.
The Benchmark Geomagnetic Disturbance Event Description, May 2016 is available on the Related Information webpage for
TPL-007-1: http://www.nerc.com/pa/Stand/TPL0071RD/Benchmark_clean_May12_complete.pdf.
2 The extent of local enhancements is on the order of 100 km in North-South (latitude) direction but longer in East-West
(longitude) direction. The local enhancement in the geomagnetic field occurs over the time period of 2-5 minutes. Additional
information is available in the Supplemental Geomagnetic Disturbance Event Description, October 2017 white paper on the
Project 2013-03 Geomagnetic Disturbance Mitigation project webpage: http://www.nerc.com/pa/Stand/Pages/Project-201303-Geomagnetic-Disturbance-Mitigation.aspx.
1
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
For large planning areas that cover more than one scaling factor from Table 2, the GMD
Vulnerability Assessment should be based on a peak geoelectric field that is:
•
calculated by using the most conservative (largest) value for α; or
•
calculated assuming a non-uniform or piecewise uniform geomagnetic field.
Table 2: Geomagnetic Field Scaling Factors for the
Benchmark and Supplemental GMD
Events
Geomagnetic Latitude
(Degrees)
Scaling Factor1
(α)
≤ 40
0.10
45
0.2
50
0.3
54
0.5
56
0.6
57
0.7
58
0.8
59
0.9
≥ 60
1.0
Scaling the Geoelectric Field
The benchmark GMD event is defined for the reference Quebec earth model described in Table
4. The peak geoelectric field, E peak , used in a GMD Vulnerability Assessment may be obtained by
either:
•
Calculating the geoelectric field for the ground conductivity in the planning area and the
reference geomagnetic field time series scaled according to geomagnetic latitude, using
a procedure such as the plane wave method described in the NERC GMD Task Force GIC
Application Guide; 3 or
•
Using the earth conductivity scaling factor β from Table 3 that correlates to the ground
conductivity map in Figure 1 or Figure 2. Along with the scaling factor α from equation
(3) or Table 2, β is applied to the reference geoelectric field using equation (1 or 2, as
applicable) to obtain the regional geoelectric field peak amplitude E peak to be used in
GMD Vulnerability Assessments. When a ground conductivity model is not available, the
planning entity should use the largest β factor of adjacent physiographic regions or a
technically justified value.
Available at the NERC GMD Task Force project webpage: http://www.nerc.com/comm/PC/Pages/Geomagnetic-DisturbanceTask-Force-(GMDTF)-2013.aspx.
3
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
The earth models used to calculate Table 3 for the United States were obtained from publicly
available information published on the U. S. Geological Survey website. 4 The models used to
calculate Table 3 for Canada were obtained from Natural Resources Canada (NRCan) and reflect
the average structure for large regions. A planner can also use specific earth model(s) with
documented justification and the reference geomagnetic field time series to calculate the β
factor(s) as follows:
𝛽𝛽𝑏𝑏 = 𝐸𝐸 ⁄8 for the benchmark GMD event
(4)
𝛽𝛽𝑠𝑠 = 𝐸𝐸 ⁄12 for the supplemental GMD
(5)
where, E is the absolute value of peak geoelectric in V/km obtained from the technically justified
earth model and the reference geomagnetic field time series.
For large planning areas that span more than one β scaling factor, the most conservative (largest)
value for β may be used in determining the peak geoelectric field to obtain conservative results.
Alternatively, a planner could perform analysis using a non-uniform or piecewise uniform
geoelectric field.
Applying the Localized Peak Geoelectric Field in the Supplemental GMD Event
The peak geoelectric field of the supplemental GMD event occurs in a localized area.5 Planners
have flexibility to determine how to apply the localized peak geoelectric field over the planning
area in performing GIC calculations. Examples of approaches are:
•
Apply the peak geoelectric field (12 V/km scaled to the planning area) over the entire
planning area;
•
Apply a spatially limited (12 V/km scaled to the planning area) peak geoelectric field (e.g.,
100 km in North-South latitude direction and 500 km in East-West longitude direction)
over a portion(s) of the system, and apply the benchmark GMD event over the rest of the
system; or
•
Other methods to adjust the benchmark GMD event analysis to account for the localized
geoelectric field enhancement of the supplemental GMD event.
Available at http://geomag.usgs.gov/conductivity/.
See the Supplemental Geomagnetic Disturbance Description white paper located on the Project 2013-03 Geomagnetic
Disturbance Mitigation project webpage: http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspx.
4
5
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
FL-1
Figure 1: Physiographic Regions of the Continental United States 6
Figure 2: Physiographic Regions of Canada
6
Additional map detail is available at the U.S. Geological Survey: http://geomag.usgs.gov/.
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Table 3: Geoelectric Field Scaling Factors
Draft 1 of TPL-007-4
July 2019
Earth model
Scaling Factor
Benchmark Event
(β b )
Scaling Factor
Supplemental
Event
(β s )
AK1A
0.56
0.51
AK1B
0.56
0.51
AP1
0.33
0.30
AP2
0.82
0.78
BR1
0.22
0.22
CL1
0.76
0.73
CO1
0.27
0.25
CP1
0.81
0.77
CP2
0.95
0.86
FL1
0.76
0.73
CS1
0.41
0.37
IP1
0.94
0.90
IP2
0.28
0.25
IP3
0.93
0.90
IP4
0.41
0.35
NE1
0.81
0.77
PB1
0.62
0.55
PB2
0.46
0.39
PT1
1.17
1.19
SL1
0.53
0.49
SU1
0.93
0.90
BOU
0.28
0.24
FBK
0.56
0.56
PRU
0.21
0.22
BC
0.67
0.62
PRAIRIES
0.96
0.88
SHIELD
1.0
1.0
ATLANTIC
0.79
0.76
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Scaling factors in Table 3 are dependent upon the frequency content of the reference storm.
Consequently, the benchmark GMD event and the supplemental GMD event may produce
different scaling factors for a given earth model.
Table 4: Reference Earth Model (Quebec)
Layer Thickness (km)
Resistivity (Ω-m)
15
20,000
10
200
125
1,000
200
100
∞
3
Reference Geomagnetic Field Time Series or Waveform for the Benchmark GMD
Event7
The geomagnetic field measurement record of the March 13-14 1989 GMD event, measured at
the NRCan Ottawa geomagnetic observatory, is the basis for the reference geomagnetic field
waveform to be used to calculate the GIC time series, GIC(t), required for transformer thermal
impact assessment.
The geomagnetic latitude of the Ottawa geomagnetic observatory is 55°; therefore, the
amplitudes of the geomagnetic field measurement data were scaled up to the 60° reference
geomagnetic latitude (see Figure 3) such that the resulting peak geoelectric field amplitude
computed using the reference earth model was 8 V/km (see Figures 4 and 5). The sampling rate
for the geomagnetic field waveform is 10 seconds.8 To use this geoelectric field time series when
a different earth model is applicable, it should be scaled with the appropriate benchmark
conductivity scaling factor β b .
Refer to the Benchmark Geomagnetic Disturbance Event Description white paper for details on the determination of the
reference geomagnetic field waveform: http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx.
8 The data file of the benchmark geomagnetic field waveform is available on the Related Information webpage for TPL-007-1:
http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx.
7
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Figure 3: Benchmark Geomagnetic Field Waveform
Red B n (Northward), Blue B e (Eastward)
Figure 4: Benchmark Geoelectric Field Waveform
E E (Eastward)
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Figure 5: Benchmark Geoelectric Field Waveform
E N (Northward)
Reference Geomagnetic Field Time Series or Waveform for the Supplemental GMD
Event9
The geomagnetic field measurement record of the March 13-14, 1989 GMD event, measured at
the NRCan Ottawa geomagnetic observatory, is the basis for the reference geomagnetic field
waveform to be used to calculate the GIC time series, GIC(t), required for transformer thermal
impact assessment for the supplemental GMD event. The supplemental GMD event waveform
differs from the benchmark GMD event waveform in that the supplemental GMD event
waveform has a local enhancement.
The geomagnetic latitude of the Ottawa geomagnetic observatory is 55°; therefore, the
amplitudes of the geomagnetic field measurement data were scaled up to the 60° reference
geomagnetic latitude (see Figure 6) such that the resulting peak geoelectric field amplitude
computed using the reference earth model was 12 V/km (see Figure7). The sampling rate for the
geomagnetic field waveform is 10 seconds. 10 To use this geoelectric field time series when a
different earth model is applicable, it should be scaled with the appropriate supplemental
conductivity scaling factor β s .
Refer to the Supplemental Geomagnetic Disturbance Event Description white paper for details on the determination of the
reference geomagnetic field waveform: http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspx.
10 The data file of the benchmark geomagnetic field waveform is available on the NERC GMD Task Force project webpage:
http://www.nerc.com/comm/PC/Pages/Geomagnetic-Disturbance-Task-Force-(GMDTF)-2013.aspx.
9
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
4000
2000
Time (min)
200
400
600
800
1000
1200
1400
1600
1800
2000
Bx, By (nT)
0
-2000
-4000
-6000
-8000
-10000
Figure 6: Supplemental Geomagnetic Field Waveform
Red B N (Northward), Blue B E (Eastward)
12 V/km
Figure 7: Supplemental Geoelectric Field Waveform
Blue E N (Northward), Red E E (Eastward)
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TPL-007-4 – Supplemental Material
Attachment 1-CAN
Attachment 1-CAN provides an alternative that a Canadian entity may use in lieu of the
benchmark or supplemental GMD event(s) defined in Attachment 1 for performing GMD
Vulnerability Assessment(s).
A Canadian entity may use the provisions of Attachment 1-CAN if it has regionally specific
information that provides a technically justified means to re-define a 1-in-100 year GMD
planning event(s) within its planning area.
Information for the Alternative Methodology
GMD Vulnerability Assessment(s) require the use of geophysical and engineering models.
Canadian-specific data is available and growing. Ongoing research allows for more accurate
characterization of regional parameters used in these models. Such Canadian-specific data
includes geomagnetic field, earth conductivity, and geomagnetically induced current
measurements that can be used for modeling and simulation validation.
Information used to calculate geoelectric fields for the benchmark and supplemental GMD events
shall be clearly documented and technically justified. For example, the factors involved in the
calculation of geoelectric fields are geomagnetic field variations and an earth transfer
function(s). 1 Technically justified information used in modelling geomagnetic field variations may
include: technical documents produced by governmental entities such as Natural Resources
Canada; technical papers published in peer-reviewed journals; and data sets gathered using
sound scientific principles. An earth transfer function may rely on magnetotelluric measurements
or earth conductivity models.
Modeling assumptions shall also be clearly documented and technically justified. An entity may
use sensitivity analysis to identify how the assumptions affect the results.
A simplified model may be used to perform a GMD Vulnerability Assessment(s), as long as the
model is more conservative than a more detailed model.
When interpreting assessment results, the entity shall consider the maturity of the modeling,
toolset, and techniques applied.
Geomagnetic Disturbance Planning Events
The 1-in-100 year planning event shall be based on regionally specific data and technically
justifiable statistical analyses (e.g., extreme value theory) and applied to the benchmark and
supplemental GMD Vulnerability Assessment(s).
For the benchmark GMD Vulnerability Assessment(s), an entity shall consider the large-scale
spatial structure of the GMD event. For the supplemental GMD Vulnerability Assessment(s), an
The “earth transfer function” is the relationship between the electric fields and magnetic field variations at the surface of the
earth.
1
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TPL-007-4 – Supplemental Material
entity shall consider the small-scale spatial structure of the GMD event (e.g., using magnetometer
measurements or realistic electrojet calculations).
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TPL-007-43 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).
Description of Current Draft
This is the first draft of proposed standard for formal 45-day comment period.
Completed Actions
Date
Standards Committee approved Standard Authorization Request
(SAR) for posting
February 20, 2019
SAR posted for comment
February 25 –
March 27, 2019
Anticipated Actions
Date
45-day formal comment period with ballot
July – September
2019
45-day formal comment period with additional ballot
October –
December 2019
45-day formal comment period with second additional ballot
January – March
2020
10-day final ballot
April 2020
Board adoption
May 2020
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TPL-007-43 – Transmission System Planned Performance for Geomagnetic Disturbance Events
A. Introduction
1.
Title:
Events
Transmission System Planned Performance for Geomagnetic Disturbance
2.
Number:
TPL-007-43
3.
Purpose:
Establish requirements for Transmission system planned performance
during geomagnetic disturbance (GMD) events.
4.
Applicability:
4.1. Functional Entities:
4.1.1. Planning Coordinator with a planning area that includes a Facility or
Facilities specified in 4.2;
4.1.2. Transmission Planner with a planning area that includes a Facility or
Facilities specified in 4.2;
4.1.3. Transmission Owner who owns a Facility or Facilities specified in 4.2; and
4.1.4. Generator Owner who owns a Facility or Facilities specified in 4.2.
4.2. Facilities:
4.2.1. Facilities that include power transformer(s) with a high side, wyegrounded winding with terminal voltage greater than 200 kV.
5.
Effective Date: See Implementation Plan for TPL-007-43.
6.
Background: During a GMD event, geomagnetically-induced currents (GIC) may cause
transformer hot-spot heating or damage, loss of Reactive Power sources, increased
Reactive Power demand, and Misoperation(s), the combination of which may result in
voltage collapse and blackout.
7.6.
The only difference between TPL-007-3 and TPL-007-2 is that TPL-007-3 adds a
Canadian Variance to address regulatory practices/processes within Canadian
jurisdictions and to allow the use of Canadian-specific data and research to define and
implement alternative GMD event(s) that achieve at least an equivalent reliability
objective of that in TPL-007-2.
B. Requirements and Measures
R1.
Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall
identify the individual and joint responsibilities of the Planning Coordinator and
Transmission Planner(s) in the Planning Coordinator’s planning for maintaining
models, performing the study or studies needed to complete benchmark and
supplemental GMD Vulnerability Assessments, and implementing process(es) to
obtain GMD measurement data as specified in this standard. [Violation Risk Factor:
Lower] [Time Horizon: Long-term Planning]
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M1. Each Planning Coordinator, in conjunction with its Transmission Planners, shall provide
documentation on roles and responsibilities, such as meeting minutes, agreements,
copies of procedures or protocols in effect between entities or between departments
of a vertically integrated system, or email correspondence that identifies an
agreement has been reached on individual and joint responsibilities for maintaining
models, performing the study or studies needed to complete benchmark and
supplemental GMD Vulnerability Assessments, and implementing process(es) to
obtain GMD measurement data in accordance with Requirement R1.
R2. Each responsible entity, as determined in Requirement R1, shall maintain System
models and GIC System models of the responsible entity’s planning area for
performing the study or studies needed to complete benchmark and supplemental
GMD Vulnerability Assessments. [Violation Risk Factor: High] [Time Horizon: Longterm Planning]
M2. Each responsible entity, as determined in Requirement R1, shall have evidence in
either electronic or hard copy format that it is maintaining System models and GIC
System models of the responsible entity’s planning area for performing the study or
studies needed to complete benchmark and supplemental GMD Vulnerability
Assessments.
R3. Each responsible entity, as determined in Requirement R1, shall have criteria for
acceptable System steady state voltage performance for its System during the GMD
events described in Attachment 1. [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]
M3. Each responsible entity, as determined in Requirement R1, shall have evidence, such
as electronic or hard copies of the criteria for acceptable System steady state voltage
performance for its System in accordance with Requirement R3.
Benchmark GMD Vulnerability Assessment(s)
R4. Each responsible entity, as determined in Requirement R1, shall complete a
benchmark GMD Vulnerability Assessment of the Near-Term Transmission Planning
Horizon at least once every 60 calendar months. This benchmark GMD Vulnerability
Assessment shall use a study or studies based on models identified in Requirement R2,
document assumptions, and document summarized results of the steady state
analysis. [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
4.1. The study or studies shall include the following conditions:
4.1.1. System On-Peak Load for at least one year within the Near-Term
Transmission Planning Horizon; and
4.1.2. System Off-Peak Load for at least one year within the Near-Term
Transmission Planning Horizon.
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4.2. The study or studies shall be conducted based on the benchmark GMD event
described in Attachment 1 to determine whether the System meets the
performance requirements for the steady state planning benchmark GMD event
contained in Table 1.
4.3. The benchmark GMD Vulnerability Assessment shall be provided: (i) to the
responsible entity’s Reliability Coordinator, adjacent Planning Coordinators, and
adjacent Transmission Planners within 90 calendar days of completion, and (ii) to
any functional entity that submits a written request and has a reliability-related
need within 90 calendar days of receipt of such request or within 90 calendar
days of completion of the benchmark GMD Vulnerability Assessment, whichever
is later.
4.3.1. If a recipient of the benchmark GMD Vulnerability Assessment provides
documented comments on the results, the responsible entity shall
provide a documented response to that recipient within 90 calendar days
of receipt of those comments.
M4. Each responsible entity, as determined in Requirement R1, shall have dated evidence
such as electronic or hard copies of its benchmark GMD Vulnerability Assessment
meeting all of the requirements in Requirement R4. Each responsible entity, as
determined in Requirement R1, shall also provide evidence, such as email records,
web postings with an electronic notice of posting, or postal receipts showing recipient
and date, that it has distributed its benchmark GMD Vulnerability Assessment: (i) to
the responsible entity’s Reliability Coordinator, adjacent Planning Coordinators, and
adjacent Transmission Planners within 90 calendar days of completion, and (ii) to any
functional entity that submits a written request and has a reliability-related need
within 90 calendar days of receipt of such request or within 90 calendar days of
completion of the benchmark GMD Vulnerability Assessment, whichever is later, as
specified in Requirement R4. Each responsible entity, as determined in Requirement
R1, shall also provide evidence, such as email notices or postal receipts showing
recipient and date, that it has provided a documented response to comments received
on its benchmark GMD Vulnerability Assessment within 90 calendar days of receipt of
those comments in accordance with Requirement R4.
R5. Each responsible entity, as determined in Requirement R1, shall provide GIC flow
information to be used for the benchmark thermal impact assessment of transformers
specified in Requirement R6 to each Transmission Owner and Generator Owner that
owns an applicable Bulk Electric System (BES) power transformer in the planning area.
The GIC flow information shall include: [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]
5.1. The maximum effective GIC value for the worst case geoelectric field orientation
for the benchmark GMD event described in Attachment 1. This value shall be
provided to the Transmission Owner or Generator Owner that owns each
applicable BES power transformer in the planning area.
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5.2. The effective GIC time series, GIC(t), calculated using the benchmark GMD event
described in Attachment 1 in response to a written request from the
Transmission Owner or Generator Owner that owns an applicable BES power
transformer in the planning area. GIC(t) shall be provided within 90 calendar
days of receipt of the written request and after determination of the maximum
effective GIC value in Part 5.1.
M5. Each responsible entity, as determined in Requirement R1, shall provide evidence,
such as email records, web postings with an electronic notice of posting, or postal
receipts showing recipient and date, that it has provided the maximum effective GIC
values to the Transmission Owner and Generator Owner that owns each applicable
BES power transformer in the planning area as specified in Requirement R5, Part 5.1.
Each responsible entity, as determined in Requirement R1, shall also provide evidence,
such as email records, web postings with an electronic notice of posting, or postal
receipts showing recipient and date, that it has provided GIC(t) in response to a
written request from the Transmission Owner or Generator Owner that owns an
applicable BES power transformer in the planning area.
R6. Each Transmission Owner and Generator Owner shall conduct a benchmark thermal
impact assessment for its solely and jointly owned applicable BES power transformers
where the maximum effective GIC value provided in Requirement R5, Part 5.1, is 75 A
per phase or greater. The benchmark thermal impact assessment shall: [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]
6.1. Be based on the effective GIC flow information provided in Requirement R5;
6.2. Document assumptions used in the analysis;
6.3. Describe suggested actions and supporting analysis to mitigate the impact of
GICs, if any; and
6.4. Be performed and provided to the responsible entities, as determined in
Requirement R1, within 24 calendar months of receiving GIC flow information
specified in Requirement R5, Part 5.1.
M6. Each Transmission Owner and Generator Owner shall have evidence such as electronic
or hard copies of its benchmark thermal impact assessment for all of its solely and
jointly owned applicable BES power transformers where the maximum effective GIC
value provided in Requirement R5, Part 5.1, is 75 A per phase or greater, and shall
have evidence such as email records, web postings with an electronic notice of
posting, or postal receipts showing recipient and date, that it has provided its thermal
impact assessment to the responsible entities as specified in Requirement R6.
R7.
Each responsible entity, as determined in Requirement R1, that concludes through
the benchmark GMD Vulnerability Assessment conducted in Requirement R4 that
their System does not meet the performance requirements for the steady state
planning benchmark GMD event contained in Table 1, shall develop a Corrective
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Action Plan (CAP) addressing how the performance requirements will be met. The CAP
shall: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
7.1. List System deficiencies and the associated actions needed to achieve required
System performance. Examples of such actions include:
Installation, modification, retirement, or removal of Transmission and
generation Facilities and any associated equipment.
Installation, modification, or removal of Protection Systems or Remedial
Action Schemes.
Use of Operating Procedures, specifying how long they will be needed as
part of the CAP.
Use of Demand-Side Management, new technologies, or other initiatives.
7.2. Be developed within one year of completion of the benchmark GMD
Vulnerability Assessment.
7.3. Include a timetable, subject to revision by the responsible entity ERO approval
for any extension sought under in Part 7.4, for implementing the selected actions
from Part 7.1. The timetable shall:
7.3.1. Specify implementation of non-hardware mitigation, if any, within two
years of development of the CAP; and
7.3.2. Specify implementation of hardware mitigation, if any, within four years
of development of the CAP.
7.4. Be submitted to the ERO with a request for extension revised if situations
beyond the control of the responsible entity is unable to determined in
Requirement R1 prevent implementation of the CAP within the timetable for
implementationprovided in Part 7.3. The submitted revised CAP shall document
the following, and be updated at least once every 12 calendar months until
implemented:
7.4.1. Circumstances causing the delay for fully or partially implementing the
selected actions in Part 7.1 and how those circumstances are beyond the
control of the responsible entity;
7.4.2.7.4.1. Description of the original CAP, and any previous changes to the
CAP, with the associated timetable(s) for implementing the selected
actions in Part 7.1; and
7.4.2. Revisions to the selected actions in Part 7.1, if any, including utilization of
Operating Procedures, if applicable; and,
7.4.3. and the Uupdated timetable for implementing the selected actions in
Part 7.1.
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7.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent
Planning Coordinator(s), adjacent Transmission Planner(s), and functional
entities referenced in the CAP within 90 calendar days of development or
revision, and (ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later.
7.5.1. If a recipient of the CAP provides documented comments on the CAP
results, the responsible entity shall provide a documented response to
that recipient within 90 calendar days of receipt of those comments.
M7. Each responsible entity, as determined in Requirement R1, that concludes, through
the benchmark GMD Vulnerability Assessment conducted in Requirement R4, that the
responsible entity’s System does not meet the performance requirements for the
steady state planning benchmark GMD event contained in Table 1 shall have evidence
such as dated electronic or hard copies of its CAP including timetable for
implementing selected actions, as specified in Requirement R7. Each responsible
entity, as determined in Requirement R1, shall also provide evidence, such as email
records or postal receipts showing recipient and date, that it submitted a request for
extension to the ERO if has revised its CAP if situations beyond the responsible entity's
is unable to control prevent implementation of the CAP within the timetable provided
in Part 7.3specified. Each responsible entity, as determined in Requirement R1, shall
also provide evidence, such as email records, web postings with an electronic notice of
posting, or postal receipts showing recipient and date, that it has distributed its CAP or
relevant information, if any, (i) to the responsible entity’s Reliability Coordinator,
adjacent Planning Coordinator(s), adjacent Transmission Planner(s), and functional
entities referenced in the CAP within 90 calendar days of development or revision, and
(ii) to any functional entity that submits a written request and has a reliability-related
need within 90 calendar days of receipt of such request or within 90 calendar days of
development or revision, whichever is later as specified in Requirement R7. Each
responsible entity, as determined in Requirement R1, shall also provide evidence, such
as email notices or postal receipts showing recipient and date, that it has provided a
documented response to comments received on its CAP within 90 calendar days of
receipt of those comments, in accordance with Requirement R7.
Supplemental GMD Vulnerability Assessment(s)
R8.
Each responsible entity, as determined in Requirement R1, shall complete a
supplemental GMD Vulnerability Assessment of the Near-Term Transmission Planning
Horizon at least once every 60 calendar months. This supplemental GMD Vulnerability
Assessment shall use a study or studies based on models identified in Requirement
R2, document assumptions, and document summarized results of the steady state
analysis. [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
8.1. The study or studies shall include the following conditions:
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8.1.1. System On-Peak Load for at least one year within the Near-Term
Transmission Planning Horizon; and
8.1.2. System Off-Peak Load for at least one year within the Near-Term
Transmission Planning Horizon.
8.2. The study or studies shall be conducted based on the supplemental GMD event
described in Attachment 1 to determine whether the System meets the
performance requirements for the steady state planning supplemental GMD
event contained in Table 1.
8.3. If the analysis concludes there is Cascading caused by the supplemental GMD
event described in Attachment 1, an evaluation of possible actions designed to
reduce the likelihood or mitigate the consequences and adverse impacts of the
event(s) shall be conducted.
8.4.8.3.
The supplemental GMD Vulnerability Assessment shall be provided:
(i) to the responsible entity’s Reliability Coordinator, adjacent Planning
Coordinators, adjacent Transmission Planners within 90 calendar days of
completion, and (ii) to any functional entity that submits a written request and
has a reliability-related need within 90 calendar days of receipt of such request
or within 90 calendar days of completion of the supplemental GMD Vulnerability
Assessment, whichever is later.
8.4.1.8.3.1. If a recipient of the supplemental GMD Vulnerability Assessment
provides documented comments on the results, the responsible entity
shall provide a documented response to that recipient within 90 calendar
days of receipt of those comments.
M8. Each responsible entity, as determined in Requirement R1, shall have dated evidence
such as electronic or hard copies of its supplemental GMD Vulnerability Assessment
meeting all of the requirements in Requirement R8. Each responsible entity, as
determined in Requirement R1, shall also provide evidence, such as email records,
web postings with an electronic notice of posting, or postal receipts showing recipient
and date, that it has distributed its supplemental GMD Vulnerability Assessment: (i) to
the responsible entity’s Reliability Coordinator, adjacent Planning Coordinators,
adjacent Transmission Planners within 90 calendar days of completion, and (ii) to any
functional entity that submits a written request and has a reliability-related need
within 90 calendar days of receipt of such request or within 90 calendar days of
completion of the supplemental GMD Vulnerability Assessment, whichever is later, as
specified in Requirement R8. Each responsible entity, as determined in Requirement
R1, shall also provide evidence, such as email notices or postal receipts showing
recipient and date, that it has provided a documented response to comments
received on its supplemental GMD Vulnerability Assessment within 90 calendar days
of receipt of those comments in accordance with Requirement R8.
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R9.
Each responsible entity, as determined in Requirement R1, shall provide GIC flow
information to be used for the supplemental thermal impact assessment of
transformers specified in Requirement R10 to each Transmission Owner and
Generator Owner that owns an applicable Bulk Electric System (BES) power
transformer in the planning area. The GIC flow information shall include: [Violation
Risk Factor: Medium] [Time Horizon: Long-term Planning]
9.1. The maximum effective GIC value for the worst case geoelectric field orientation
for the supplemental GMD event described in Attachment 1. This value shall be
provided to the Transmission Owner or Generator Owner that owns each
applicable BES power transformer in the planning area.
9.2. The effective GIC time series, GIC(t), calculated using the supplemental GMD
event described in Attachment 1 in response to a written request from the
Transmission Owner or Generator Owner that owns an applicable BES power
transformer in the planning area. GIC(t) shall be provided within 90 calendar
days of receipt of the written request and after determination of the maximum
effective GIC value in Part 9.1.
M9. Each responsible entity, as determined in Requirement R1, shall provide evidence,
such as email records, web postings with an electronic notice of posting, or postal
receipts showing recipient and date, that it has provided the maximum effective GIC
values to the Transmission Owner and Generator Owner that owns each applicable
BES power transformer in the planning area as specified in Requirement R9, Part 9.1.
Each responsible entity, as determined in Requirement R1, shall also provide
evidence, such as email records, web postings with an electronic notice of posting, or
postal receipts showing recipient and date, that it has provided GIC(t) in response to a
written request from the Transmission Owner or Generator Owner that owns an
applicable BES power transformer in the planning area.
R10. Each Transmission Owner and Generator Owner shall conduct a supplemental
thermal impact assessment for its solely and jointly owned applicable BES power
transformers where the maximum effective GIC value provided in Requirement R9,
Part 9.1, is 85 A per phase or greater. The supplemental thermal impact assessment
shall: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
10.1. Be based on the effective GIC flow information provided in Requirement R9;
10.2. Document assumptions used in the analysis;
10.3. Describe suggested actions and supporting analysis to mitigate the impact of
GICs, if any; and
10.4. Be performed and provided to the responsible entities, as determined in
Requirement R1, within 24 calendar months of receiving GIC flow information
specified in Requirement R9, Part 9.1.
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M10. Each Transmission Owner and Generator Owner shall have evidence such as
electronic or hard copies of its supplemental thermal impact assessment for all of its
solely and jointly owned applicable BES power transformers where the maximum
effective GIC value provided in Requirement R9, Part 9.1, is 85 A per phase or greater,
and shall have evidence such as email records, web postings with an electronic notice
of posting, or postal receipts showing recipient and date, that it has provided its
supplemental thermal impact assessment to the responsible entities as specified in
Requirement R10.
R11. Each responsible entity, as determined in Requirement R1, that concludes through
the supplemental GMD Vulnerability Assessment conducted in Requirement R8 that
their System does not meet the performance requirements for the steady state
planning supplemental GMD event contained in Table 1, shall develop a Corrective
Action Plan (CAP) addressing how the performance requirements will be met. The CAP
shall: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
11.1. List System deficiencies and the associated actions needed to achieve required
System performance. Examples of such actions include:
Installation, modification, retirement, or removal of Transmission and
generation Facilities and any associated equipment.
Installation, modification, or removal of Protection Systems or Remedial
Action Schemes.
Use of Operating Procedures, specifying how long they will be needed as
part of the CAP.
Use of Demand-Side Management, new technologies, or other initiatives.
11.2. Be developed within one year of completion of the supplemental GMD
Vulnerability Assessment.
11.3. Include a timetable, subject to ERO approval for any extension sought under Part
11.4, for implementing the selected actions from Part 11.1. The timetable shall:
11.3.1. Specify implementation of non-hardware mitigation, if any, within two
years of development of the CAP; and
11.3.2. Specify implementation of hardware mitigation, if any, within four years
of development of the CAP.
11.4. Be submitted to the ERO with a request for extension if the responsible entity is
unable to implement the CAP within the timetable provided in Part 11.3. The
submitted CAP shall document the following:
11.4.1. Circumstances causing the delay for fully or partially implementing the
selected actions in Part 11.1 and how those circumstances are beyond
the control of the responsible entity;
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11.4.2. Revisions to the selected actions in Part 11.1, if any, including utilization
of Operating Procedures, if applicable; and
11.4.3. Updated timetable for implementing the selected actions in Part 11.1.
11.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent
Planning Coordinator(s), adjacent Transmission Planner(s), and functional
entities referenced in the CAP within 90 calendar days of development or
revision, and (ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later.
11.5.1. If a recipient of the CAP provides documented comments on the CAP, the
responsible entity shall provide a documented response to that recipient
within 90 calendar days of receipt of those comments.
M11. Each responsible entity, as determined in Requirement R1, that concludes, through
the supplemental GMD Vulnerability Assessment conducted in Requirement R8, that
the responsible entity’s System does not meet the performance requirements for the
steady state planning supplemental GMD event contained in Table 1 shall have
evidence such as dated electronic or hard copies of its CAP including timetable for
implementing selected actions, as specified in Requirement R11. Each responsible
entity, as determined in Requirement R1, shall also provide evidence, such as email
records or postal receipts showing recipient and date, that it submitted a request for
extension to the ERO if the responsible entity is unable to implement the CAP within
the timetable provided in Part 11.3. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records, web postings with
an electronic notice of posting, or postal receipts showing recipient and date, that it
has distributed its CAP or relevant information, if any, (i) to the responsible entity’s
Reliability Coordinator, adjacent Planning Coordinator(s), adjacent Transmission
Planner(s), and functional entities referenced in the CAP within 90 calendar days of
development or revision, and (ii) to any functional entity that submits a written
request and has a reliability-related need within 90 calendar days of receipt of such
request or within 90 calendar days of development or revision, whichever is later as
specified in Requirement R11. Each responsible entity, as determined in Requirement
R1, shall also provide evidence, such as email notices or postal receipts showing
recipient and date, that it has provided a documented response to comments received
on its CAP within 90 calendar days of receipt of those comments, in accordance with
Requirement R11.
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GMD Measurement Data Processes
R11.R12. Each responsible entity, as determined in Requirement R1, shall implement a
process to obtain GIC monitor data from at least one GIC monitor located in the
Planning Coordinator'’s planning area or other part of the system included in the
Planning Coordinator'’s GIC System model. [Violation Risk Factor: Lower] [Time
Horizon: Long-term Planning]
M10.M12. Each responsible entity, as determined in Requirement R1, shall have evidence
such as electronic or hard copies of its GIC monitor location(s) and documentation of
its process to obtain GIC monitor data in accordance with Requirement R121.
R12.R13. Each responsible entity, as determined in Requirement R1, shall implement a
process to obtain geomagnetic field data for its Planning Coordinator’s planning area.
[Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
M11.M13. Each responsible entity, as determined in Requirement R1, shall have evidence
such as electronic or hard copies of its process to obtain geomagnetic field data for its
Planning Coordinator’s planning area in accordance with Requirement R132.
B.C.
1.
Compliance
Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
Authority may ask an entity to provide other evidence to show that it was
compliant for the full-time period since the last audit.
The applicable entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
For Requirements R1, R2, R3, R5, R6, R9, and R10, each responsible entity
shall retain documentation as evidence for five years.
For Requirements R4 and R8, each responsible entity shall retain
documentation of the current GMD Vulnerability Assessment and the
preceding GMD Vulnerability Assessment.
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For Requirement R7 and R11, each responsible entity shall retain
documentation as evidence for five years or until all actions in the
Corrective Action Plan are completed, whichever is later.
For Requirements R121 and R132, each responsible entity shall retain
documentation as evidence for three years.
1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.
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Table 1: Steady State Planning GMD Event
Steady State:
a. Voltage collapse, Cascading and uncontrolled islanding shall not occur.
b. Generation loss is acceptable as a consequence of the steady state planning GMD events.
c. Planned System adjustments such as Transmission configuration changes and re-dispatch of generation are allowed if such
adjustments are executable within the time duration applicable to the Facility Ratings.
Category
Initial Condition
Event
Interruption of
Firm
Transmission
Service Allowed
Load Loss
Allowed
Benchmark GMD
Event -– GMD
Event with
Outages
1. System as may be
postured in response
to space weather
information1, and then
2. GMD event2
Reactive Power compensation devices
and other Transmission Facilities
removed as a result of Protection
System operation or Misoperation due
to harmonics during the GMD event
Yes3
Yes3
Supplemental
GMD Event -–
GMD Event with
Outages
1. System as may be
postured in response
to space weather
information1, and then
2. GMD event2
Reactive Power compensation devices
and other Transmission Facilities
removed as a result of Protection
System operation or Misoperation due
to harmonics during the GMD event
Yes
Yes
Table 1: Steady State Performance Footnotes
1. The System condition for GMD planning may include adjustments to posture the System that are executable in response to
space weather information.
2. The GMD conditions for the benchmark and supplemental planning events are described in Attachment 1.
3. Load loss as a result of manual or automatic Load shedding (e.g., UVLS) and/or curtailment of Firm Transmission Service may
be used to meet BES performance requirements during studied GMD conditions. The likelihood and magnitude of Load loss or
curtailment of Firm Transmission Service should be minimized.
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Violation Severity Levels
R#
R1.
R2.
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Violation Severity Levels
Lower VSL
N/A
N/A
Moderate VSL
N/A
N/A
High VSL
Severe VSL
N/A
The Planning Coordinator, in
conjunction with its
Transmission Planner(s),
failed to determine and
identify individual or joint
responsibilities of the
Planning Coordinator and
Transmission Planner(s) in
the Planning Coordinator’s
planning area for
maintaining models,
performing the study or
studies needed to complete
benchmark and
supplemental GMD
Vulnerability Assessments,
and implementing
process(es) to obtain GMD
measurement data as
specified in this standard.
The responsible entity did
not maintain either System
models or GIC System
models of the responsible
entity’s planning area for
performing the studies
The responsible entity did
not maintain both System
models and GIC System
models of the responsible
entity’s planning area for
performing the studies
Page 15 of 47
TPL-007-43 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
needed to complete
benchmark and
supplemental GMD
Vulnerability Assessments.
R3.
R4.
N/A
N/A
N/A
The responsible entity
completed a benchmark
GMD Vulnerability
Assessment, but it was more
than 60 calendar months
and less than or equal to 64
calendar months since the
last benchmark GMD
Vulnerability Assessment.
The responsible entity'’s
completed benchmark GMD
Vulnerability Assessment
failed to satisfy one of the
elements listed in
Requirement R4, Parts 4.1
through 4.3;
OR
The responsible entity
completed a benchmark
GMD Vulnerability
Assessment, but it was more
than 64 calendar months
and less than or equal to 68
calendar months since the
The responsible entity'’s
completed benchmark GMD
Vulnerability Assessment
failed to satisfy two of the
elements listed in
Requirement R4, Parts 4.1
through 4.3;
OR
The responsible entity
completed a benchmark
GMD Vulnerability
Assessment, but it was more
than 68 calendar months
and less than or equal to 72
calendar months since the
Draft 1 of TPL-007-4
July 2019
Severe VSL
needed to complete
benchmark and
supplemental GMD
Vulnerability Assessments.
The responsible entity did
not have criteria for
acceptable System steady
state voltage performance
for its System during the
GMD events described in
Attachment 1 as required.
The responsible entity'’s
completed benchmark GMD
Vulnerability Assessment
failed to satisfy three of the
elements listed in
Requirement R4, Parts 4.1
through 4.3;
OR
The responsible entity
completed a benchmark
GMD Vulnerability
Assessment, but it was more
than 72 calendar months
since the last benchmark
Page 16 of 47
TPL-007-43 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
R5.
R6.
Lower VSL
Moderate VSL
High VSL
Severe VSL
last benchmark GMD
Vulnerability Assessment.
last benchmark GMD
Vulnerability Assessment.
GMD Vulnerability
Assessment;
OR
The responsible entity does
not have a completed
benchmark GMD
Vulnerability Assessment.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 90
calendar days and less than
or equal to 100 calendar
days after receipt of a
written request.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 100
calendar days and less than
or equal to 110 calendar
days after receipt of a
written request.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 110
calendar days after receipt
of a written request.
The responsible entity did
not provide the maximum
effective GIC value to the
Transmission Owner and
Generator Owner that owns
each applicable BES power
transformer in the planning
area;
OR
The responsible entity did
not provide the effective GIC
time series, GIC(t), upon
written request.
The responsible entity failed
to conduct a benchmark
thermal impact assessment
for 5% or less or one of its
solely owned and jointly
owned applicable BES power
The responsible entity failed
to conduct a benchmark
thermal impact assessment
for more than 5% up to (and
including) 10% or two of its
solely owned and jointly
The responsible entity failed
to conduct a benchmark
thermal impact assessment
for more than 10% up to
(and including) 15% or three
of its solely owned and
The responsible entity failed
to conduct a benchmark
thermal impact assessment
for more than 15% or more
than three of its solely
owned and jointly owned
Draft 1 of TPL-007-4
July 2019
Page 17 of 47
TPL-007-43 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase;
OR
The responsible entity
conducted a benchmark
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase
but did so more than 24
calendar months and less
than or equal to 26 calendar
months of receiving GIC flow
information specified in
Requirement R5, Part 5.1.
owned applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase;
OR
The responsible entity
conducted a benchmark
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase
but did so more than 26
calendar months and less
than or equal to 28 calendar
months of receiving GIC flow
information specified in
Requirement R5, Part 5.1;
OR
The responsible entity failed
to include one of the
jointly owned applicable BES
power transformers
(whichever is greater) where
the maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase;
OR
The responsible entity
conducted a benchmark
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase
but did so more than 28
calendar months and less
than or equal to 30 calendar
months of receiving GIC flow
information specified in
Requirement R5, Part 5.1;
OR
The responsible entity failed
to include two of the
applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase;
OR
The responsible entity
conducted a benchmark
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase
but did so more than 30
calendar months of receiving
GIC flow information
specified in Requirement R5,
Part 5.1;
OR
The responsible entity failed
to include three of the
required elements as listed
Draft 1 of TPL-007-4
July 2019
Page 18 of 47
TPL-007-43 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
required elements as listed
in Requirement R6, Parts 6.1
through 6.3.
required elements as listed
in Requirement R6, Parts 6.1
through 6.3.
in Requirement R6, Parts 6.1
through 6.3.
The responsible entity'’s
Corrective Action Plan failed
to comply with one of the
elements in Requirement
R7, Parts 7.1 through 7.5.
The responsible entity'’s
Corrective Action Plan failed
to comply with two of the
elements in Requirement R7,
Parts 7.1 through 7.5.
The responsible entity'’s
Corrective Action Plan failed
to comply with three of the
elements in Requirement
R7, Parts 7.1 through 7.5.
The responsible entity'’s
Corrective Action Plan failed
to comply with four or more
of the elements in
Requirement R7, Parts 7.1
through 7.5;
OR
The responsible entity did
not develop have a
Corrective Action Plan as
required by Requirement R7.
The responsible entity's
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
one of elements listed in
Requirement R8, Parts 8.1
through 8.4;
OR
The responsible entity
completed a supplemental
GMD Vulnerability
Assessment, but it was more
The responsible entity'’s
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
two one of the elements
listed in Requirement R8,
Parts 8.1 through 8.34;
OR
The responsible entity
completed a supplemental
GMD Vulnerability
Assessment, but it was more
The responsible entity'’s
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
three two of the elements
listed in Requirement R8,
Parts 8.1 through 8.34;
OR
The responsible entity
completed a supplemental
GMD Vulnerability
Assessment, but it was more
The responsible entity'’s
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
threefour of the elements
listed in Requirement R8,
Parts 8.1 through 8.34;
OR
The responsible entity
completed a supplemental
GMD Vulnerability
Assessment, but it was more
R7.
R8.
Draft 1 of TPL-007-4
July 2019
Page 19 of 47
TPL-007-43 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
R9.
R10.
Lower VSL
Moderate VSL
High VSL
Severe VSL
than 60 calendar months
and less than or equal to 64
calendar months since the
last supplemental GMD
Vulnerability Assessment.
than 64 calendar months
and less than or equal to 68
calendar months since the
last supplemental GMD
Vulnerability Assessment.
than 68 calendar months
and less than or equal to 72
calendar months since the
last supplemental GMD
Vulnerability Assessment.
than 72 calendar months
since the last supplemental
GMD Vulnerability
Assessment;
OR
The responsible entity does
not have a completed
supplemental GMD
Vulnerability Assessment.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 90
calendar days and less than
or equal to 100 calendar
days after receipt of a
written request.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 100
calendar days and less than
or equal to 110 calendar
days after receipt of a
written request.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 110
calendar days after receipt
of a written request.
The responsible entity did
not provide the maximum
effective GIC value to the
Transmission Owner and
Generator Owner that owns
each applicable BES power
transformer in the planning
area;
OR
The responsible entity did
not provide the effective GIC
time series, GIC(t), upon
written request.
The responsible entity failed
to conduct a supplemental
thermal impact assessment
for 5% or less or one of its
The responsible entity failed
to conduct a supplemental
thermal impact assessment
for more than 5% up to (and
The responsible entity failed
to conduct a supplemental
thermal impact assessment
for more than 10% up to
The responsible entity failed
to conduct a supplemental
thermal impact assessment
for more than 15% or more
Draft 1 of TPL-007-4
July 2019
Page 20 of 47
TPL-007-43 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
solely owned and jointly
owned applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase;
OR
The responsible entity
conducted a supplemental
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase
but did so more than 24
calendar months and less
than or equal to 26 calendar
months of receiving GIC flow
information specified in
Requirement R9, Part 9.1.
including) 10% or two of its
solely owned and jointly
owned applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase;
OR
The responsible entity
conducted a supplemental
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase
but did so more than 26
calendar months and less
than or equal to 28 calendar
months of receiving GIC flow
information specified in
Requirement R9, Part 9.1
OR
(and including) 15% or three
of its solely owned and
jointly owned applicable BES
power transformers
(whichever is greater) where
the maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase;
OR
The responsible entity
conducted a supplemental
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase
but did so more than 28
calendar months and less
than or equal to 30 calendar
months of receiving GIC flow
information specified in
Requirement R9, Part 9.1;
OR
than three of its solely
owned and jointly owned
applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase;
OR
The responsible entity
conducted a supplemental
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase
but did so more than 30
calendar months of receiving
GIC flow information
specified in Requirement R9,
Part 9.1;
OR
Draft 1 of TPL-007-4
July 2019
Page 21 of 47
TPL-007-43 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
R11.
Lower VSL
The responsible entity’s
Corrective Action Plan failed
to comply with one of the
elements in Requirement
R11, Parts 11.1 through
11.5.
N/A
Draft 1 of TPL-007-4
July 2019
Moderate VSL
High VSL
Severe VSL
The responsible entity failed
to include one of the
required elements as listed
in Requirement R10, Parts
10.1 through 10.3.
The responsible entity failed
to include two of the
required elements as listed
in Requirement R10, Parts
10.1 through 10.3.
The responsible entity failed
to include three of the
required elements as listed
in Requirement R10, Parts
10.1 through 10.3.
The responsible entity’s
Corrective Action Plan failed
to comply with three of the
elements in Requirement
R11, Parts 11.1 through
11.5.
N/A
The responsible entity’s
Corrective Action Plan failed
to comply with four or more
of the elements in
Requirement R11, Parts 11.1
through 11.5;
OR
The responsible entity did
not develop a Corrective
Action Plan as required by
Requirement R11.
The responsible entity did
not implement a process to
obtain GIC monitor data
from at least one GIC
monitor located in the
Planning Coordinator’s
planning area or other part
of the system included in the
Planning Coordinator’s GIC
System Model.
The responsible entity’s
Corrective Action Plan failed
to comply with two of the
elements in Requirement
R11, Parts 11.1 through
11.5.
N/A
Page 22 of 47
TPL-007-43 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
R12.
R13.
Draft 1 of TPL-007-4
July 2019
Violation Severity Levels
Lower VSL
N/A
N/A
Moderate VSL
N/A
N/A
High VSL
Severe VSL
N/A
The responsible entity did
not implement a process to
obtain GIC monitor data
from at least one GIC
monitor located in the
Planning Coordinator’s
planning area or other part
of the system included in the
Planning Coordinator’s GIC
System Model.
The responsible entity did
not implement a process to
obtain geomagnetic field
data for its Planning
Coordinator’s planning area.
N/A
The responsible entity did
not implement a process to
obtain geomagnetic field
data for its Planning
Coordinator’s planning area.
Page 23 of 47
TPL-007-43 – Transmission System Planned Performance for Geomagnetic Disturbance Events
C.D.
Regional Variances
D.A. Regional Variance for Canadian Jurisdictions
This Variance shall be applicable in those Canadian jurisdictions where the Variance
has been approved for use by the applicable governmental authority or has otherwise
become effective in the jurisdiction.
This variance replaces Aall references to “Attachment 1” in the standard are replaced
with “Attachment 1 or Attachment 1-CAN.”
In addition, this Variance replaces Requirement R7, Part 7.3 through Part 7.5 and
Requirement R11, Part 11.3 through Part 11.5 with the following:
D.A.7.3. Include a timetable, subject to revision by the responsible entity in Part
D.A.7.4, for implementing the selected actions from Part 7.1. The timetable
shall:
D.A.7.3.1. Specify implementation of non-hardware mitigation, if any, within
two years of the later of the development of the CAP or receipt of
regulatory approvals, if required; and
D.A.7.3.2. Specify implementation of hardware mitigation, if any, within four
years of the later of the development of the CAP or receipt of
regulatory approvals, if required.
D.A.7.4. Be revised if the responsible entity is unable to implement the CAP within the
timetable for implementation provided in Part D.A.7.3. The revised CAP shall
document the following:
D.A.7.4.1 Circumstances causing the delay for fully or partially implementing the
selected actions in Part 7.1 and how those circumstances are beyond
the control of the responsible entity;
D.A.7.4.2 Revisions to the selected actions in Part 7.1, if any, including utilization
of Operating Procedures if applicable; and
D.A.7.4.3 Updated timetable for implementing the selected actions in Part 7.1.
D.A.7.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent
Planning Coordinator(s), adjacent Transmission Planner(s), and functional
entities referenced in the CAP within 90 calendar days of development or
revision, (ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later, and
(iii) to the Compliance Enforcement Authority or Applicable Governmental
Authority when revised under D.A.7.4 within 90 calendar days of revision.
D.A.7.5.1 If a recipient of the CAP provides documented comments on the CAP,
the responsible entity shall provide a documented response to that
recipient within 90 calendar days of receipt of those comments.
Draft 1 of TPL-007-4
July 2019
Page 24 of 47
TPL-007-43 – Transmission System Planned Performance for Geomagnetic Disturbance Events
D.A.M.7. Each responsible entity, as determined in Requirement R1, that concludes,
through the benchmark GMD Vulnerability Assessment conducted in
Requirement R4, that the responsible entity’s System does not meet the
performance requirements for the steady state planning benchmark GMD
event contained in Table 1 shall have evidence such as dated electronic or
hard copies of its CAP including timetable for implementing selected actions,
as specified in Requirement R7. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records or postal
receipts showing recipient and date, that it has revised its CAP if situations
beyond the responsible entity's control prevent implementation of the CAP
within the timetable specified. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records, web
postings with an electronic notice of posting, or postal receipts showing
recipient and date, that it has distributed its CAP or relevant information, if
any, (i) to the responsible entity’s Reliability Coordinator, adjacent Planning
Coordinator(s), adjacent Transmission Planner(s), and functional entities
referenced in the CAP within 90 calendar days of development or revision,
(ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later as
specified in Requirement R7, and (iii) to the Compliance Enforcement
Authority or Applicable Governmental Authority when revised under D.A.7.4
within 90 calendar days of revision. Each responsible entity, as determined
in Requirement R1, shall also provide evidence, such as email notices or
postal receipts showing recipient and date, that it has provided a
documented response to comments received on its CAP within 90 calendar
days of receipt of those comments, in accordance with Requirement R7.
D.A.11.3. Include a timetable, subject to revision by the responsible entity in Part
D.A.11.4, for implementing the selected actions from Part 11.1. The
timetable shall:
D.A.11.3.1. Specify implementation of non-hardware mitigation, if any, within
two years of the later of the development of the CAP or receipt of
regulatory approvals, if required; and
D.A.11.3.2. Specify implementation of hardware mitigation, if any, within four
years of the later of the development of the CAP or receipt of
regulatory approvals, if required.
D.A.11.4. Be revised if the responsible entity is unable to implement the CAP within
the timetable for implementation provided in Part D.A.11.3. The revised CAP
shall document the following:
D.A.11.4.1 Circumstances causing the delay for fully or partially implementing
the selected actions in Part 11.1 and how those circumstances are
beyond the control of the responsible entity;
Draft 1 of TPL-007-4
July 2019
Page 25 of 47
TPL-007-43 – Transmission System Planned Performance for Geomagnetic Disturbance Events
D.A.11.4.2. Revisions to the selected actions in Part 11.1, if any, including
utilization of Operating Procedures if applicable; and
D.A.11.4.3. Updated timetable for implementing the selected actions in Part
11.1.
D.A.11.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent
Planning Coordinator(s), adjacent Transmission Planner(s), and functional
entities referenced in the CAP within 90 calendar days of development or
revision, (ii) to any functional entity that submits a written request and has
a reliability-related need within 90 calendar days of receipt of such request
or within 90 calendar days of development or revision, whichever is later,
and (iii) to the Compliance Enforcement Authority or Applicable
Governmental Authority when revised under D.A.11.4 within 90 calendar
days of revision.
D.A.11.5.1. If a recipient of the CAP provides documented comments on the
CAP, the responsible entity shall provide a documented response to
that recipient within 90 calendar days of receipt of those comments.
Draft 1 of TPL-007-4
July 2019
Page 26 of 47
TPL-007-43 – Transmission System Planned Performance for Geomagnetic Disturbance Events
D.A.M.11. Each responsible entity, as determined in Requirement R1, that concludes,
through the supplemental GMD Vulnerability Assessment conducted in
Requirement R8, that the responsible entity’s System does not meet the
performance requirements for the steady state planning supplemental GMD
event contained in Table 1 shall have evidence such as dated electronic or
hard copies of its CAP including timetable for implementing selected actions,
as specified in Requirement R11. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records or postal
receipts showing recipient and date, that it has revised its CAP if situations
beyond the responsible entity's control prevent implementation of the CAP
within the timetable specified. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records, web
postings with an electronic notice of posting, or postal receipts showing
recipient and date, that it has distributed its CAP or relevant information, if
any, (i) to the responsible entity’s Reliability Coordinator, adjacent Planning
Coordinator(s), adjacent Transmission Planner(s), and functional entities
referenced in the CAP within 90 calendar days of development or revision,
(ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later as
specified in Requirement R11, and (iii) to the Compliance Enforcement
Authority or Applicable Governmental Authority when revised under
D.A.11.4 within 90 calendar days of revision. Each responsible entity, as
determined in Requirement R1, shall also provide evidence, such as email
notices or postal receipts showing recipient and date, that it has provided a
documented response to comments received on its CAP within 90 calendar
days of receipt of those comments, in accordance with Requirement R11.
Draft 1 of TPL-007-4
July 2019
Page 27 of 47
TPL-007-43 – Transmission System Planned Performance for Geomagnetic Disturbance Events
D.E.
Associated Documents
Attachment 1
Attachment 1-CAN
Draft 1 of TPL-007-4
July 2019
Page 28 of 47
TPL-007-43 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Version History
Version
Date
1
December 17, 2014
Action
Change
Tracking
Adopted by the NERC Board of Trustees
New
Revised to
respond to
directives in FERC
Order No. 830.
2
November 9, 2017
Adopted by the NERC Board of Trustees
2
November 25, 2018
FERC Order issued approving TPL-007-2.
Docket No. RM18-8-000
3
February 7, 2019
Adopted by the NERC Board of Trustees
Canadian
Variance
Adopted by the NERC Board of Trustees
Revised to
respond to
directives in FERC
Order. 851
4
Draft 1 of TPL-007-4
July 2019
TBD
Page 29 of 47
TPL-007-43 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Attachment 1
Calculating Geoelectric Fields for the Benchmark and Supplemental GMD Events
The benchmark GMD event1 defines the geoelectric field values used to compute GIC flows that
are needed to conduct a benchmark GMD Vulnerability Assessment. It is composed of the
following elements: (1) a reference peak geoelectric field amplitude of 8 V/km derived from
statistical analysis of historical magnetometer data; (2) scaling factors to account for local
geomagnetic latitude; (3) scaling factors to account for local earth conductivity; and (4) a
reference geomagnetic field time series or waveform to facilitate time-domain analysis of GMD
impact on equipment.
The supplemental GMD event is composed of similar elements as described above, except (1) the
reference peak geoelectric field amplitude is 12 V/km over a localized area; and (2) the
geomagnetic field time series or waveform includes a local enhancement in the waveform.2
The regional geoelectric field peak amplitude used in GMD Vulnerability Assessment, Epeak, can
be obtained from the reference geoelectric field value of 8 V/km for the benchmark GMD event
(1) or 12 V/km for the supplemental GMD event (2) using the following relationships:
𝐸𝑝𝑒𝑎𝑘 = 8 × 𝛼 × 𝛽 𝑏 (𝑉 ⁄𝑘𝑚)
(1)
𝐸𝑝𝑒𝑎𝑘 = 12 × 𝛼 × 𝛽 𝑠 (𝑉 ⁄𝑘𝑚)
(2)
where, α is the scaling factor to account for local geomagnetic latitude, and β is a scaling factor
to account for the local earth conductivity structure. Subscripts b and s for the β scaling factor
denote association with the benchmark or supplemental GMD events, respectively.
Scaling the Geomagnetic Field
The benchmark and supplemental GMD events are defined for geomagnetic latitude of 60 and
must be scaled to account for regional differences based on geomagnetic latitude. Table 2
provides a scaling factor correlating peak geoelectric field to geomagnetic latitude. Alternatively,
the scaling factor is computed with the empirical expression:
𝛼 = 0.001 × 𝑒 (0.115×𝐿)
(3)
where, L is the geomagnetic latitude in degrees and 0.1 ≤ α ≤ 1.
1
The Benchmark Geomagnetic Disturbance Event Description, May 2016 is available on the Related Information webpage for
TPL-007-1: http://www.nerc.com/pa/Stand/TPL0071RD/Benchmark_clean_May12_complete.pdf.
2 The extent of local enhancements is on the order of 100 km in North-South (latitude) direction but longer in East-West
(longitude) direction. The local enhancement in the geomagnetic field occurs over the time period of 2-5 minutes. Additional
information is available in the Supplemental Geomagnetic Disturbance Event Description, October 2017 white paper on the
Project 2013-03 Geomagnetic Disturbance Mitigation project webpage: http://www.nerc.com/pa/Stand/Pages/Project-201303-Geomagnetic-Disturbance-Mitigation.aspx.
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For large planning areas that cover more than one scaling factor from Table 2, the GMD
Vulnerability Assessment should be based on a peak geoelectric field that is:
calculated by using the most conservative (largest) value for α; or
calculated assuming a non-uniform or piecewise uniform geomagnetic field.
Table 2: Geomagnetic Field Scaling Factors for the
Benchmark and Supplemental GMD
Events
Geomagnetic Latitude
(Degrees)
Scaling Factor1
()
≤ 40
0.10
45
0.2
50
0.3
54
0.5
56
0.6
57
0.7
58
0.8
59
0.9
≥ 60
1.0
Scaling the Geoelectric Field
The benchmark GMD event is defined for the reference Quebec earth model described in Table
4. The peak geoelectric field, Epeak, used in a GMD Vulnerability Assessment may be obtained by
either:
Calculating the geoelectric field for the ground conductivity in the planning area and the
reference geomagnetic field time series scaled according to geomagnetic latitude, using
a procedure such as the plane wave method described in the NERC GMD Task Force GIC
Application Guide;3 or
Using the earth conductivity scaling factor β from Table 3 that correlates to the ground
conductivity map in Figure 1 or Figure 2. Along with the scaling factor from equation
(3) or Table 2, β is applied to the reference geoelectric field using equation (1 or 2, as
applicable) to obtain the regional geoelectric field peak amplitude Epeak to be used in
GMD Vulnerability Assessments. When a ground conductivity model is not available, the
planning entity should use the largest β factor of adjacent physiographic regions or a
technically justified value.
3
Available at the NERC GMD Task Force project webpage: http://www.nerc.com/comm/PC/Pages/Geomagnetic-DisturbanceTask-Force-(GMDTF)-2013.aspx.
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The earth models used to calculate Table 3 for the United States were obtained from publicly
available information published on the U. S. Geological Survey website.4 The models used to
calculate Table 3 for Canada were obtained from Natural Resources Canada (NRCan) and reflect
the average structure for large regions. A planner can also use specific earth model(s) with
documented justification and the reference geomagnetic field time series to calculate the β
factor(s) as follows:
𝛽𝑏 = 𝐸 ⁄8 for the benchmark GMD event
(4)
𝛽𝑠 = 𝐸 ⁄12 for the supplemental GMD
(5)
where, E is the absolute value of peak geoelectric in V/km obtained from the technically justified
earth model and the reference geomagnetic field time series.
For large planning areas that span more than one β scaling factor, the most conservative (largest)
value for β may be used in determining the peak geoelectric field to obtain conservative results.
Alternatively, a planner could perform analysis using a non-uniform or piecewise uniform
geoelectric field.
Applying the Localized Peak Geoelectric Field in the Supplemental GMD Event
The peak geoelectric field of the supplemental GMD event occurs in a localized area.5 Planners
have flexibility to determine how to apply the localized peak geoelectric field over the planning
area in performing GIC calculations. Examples of approaches are:
Apply the peak geoelectric field (12 V/km scaled to the planning area) over the entire
planning area;
Apply a spatially limited (12 V/km scaled to the planning area) peak geoelectric field (e.g.,
100 km in North-South latitude direction and 500 km in East-West longitude direction)
over a portion(s) of the system, and apply the benchmark GMD event over the rest of the
system; or
Other methods to adjust the benchmark GMD event analysis to account for the localized
geoelectric field enhancement of the supplemental GMD event.
4
Available at http://geomag.usgs.gov/conductivity/.
See the Supplemental Geomagnetic Disturbance Description white paper located on the Project 2013-03 Geomagnetic
Disturbance Mitigation project webpage: http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspx.
5
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TPL-007-43 – Transmission System Planned Performance for Geomagnetic Disturbance Events
FL-1
Figure 1: Physiographic Regions of the Continental United States6
Figure 2: Physiographic Regions of Canada
6
Additional map detail is available at the U.S. Geological Survey: http://geomag.usgs.gov/.
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Table 3: Geoelectric Field Scaling Factors
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Earth model
Scaling Factor
Benchmark Event
( b)
Scaling Factor
Supplemental
Event
( s)
AK1A
0.56
0.51
AK1B
0.56
0.51
AP1
0.33
0.30
AP2
0.82
0.78
BR1
0.22
0.22
CL1
0.76
0.73
CO1
0.27
0.25
CP1
0.81
0.77
CP2
0.95
0.86
FL1
0.76
0.73
CS1
0.41
0.37
IP1
0.94
0.90
IP2
0.28
0.25
IP3
0.93
0.90
IP4
0.41
0.35
NE1
0.81
0.77
PB1
0.62
0.55
PB2
0.46
0.39
PT1
1.17
1.19
SL1
0.53
0.49
SU1
0.93
0.90
BOU
0.28
0.24
FBK
0.56
0.56
PRU
0.21
0.22
BC
0.67
0.62
PRAIRIES
0.96
0.88
SHIELD
1.0
1.0
ATLANTIC
0.79
0.76
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Scaling factors in Table 3 are dependent upon the frequency content of the reference storm.
Consequently, the benchmark GMD event and the supplemental GMD event may produce
different scaling factors for a given earth model.
Rationale: Scaling factors in Table 3 are dependent upon the frequency content of the
reference storm. Consequently, the benchmark GMD event and the supplemental GMD event
may produce different scaling factors for a given earth model.
The scaling factor associated with the benchmark GMD event for the Florida earth model (FL1)
has been updated based on the earth model published on the USGS public website.
Table 4: Reference Earth Model (Quebec)
Layer Thickness (km)
Resistivity (Ω-m)
15
20,000
10
200
125
1,000
200
100
∞
3
Reference Geomagnetic Field Time Series or Waveform for the Benchmark GMD
Event7
The geomagnetic field measurement record of the March 13-14 1989 GMD event, measured at
the NRCan Ottawa geomagnetic observatory, is the basis for the reference geomagnetic field
waveform to be used to calculate the GIC time series, GIC(t), required for transformer thermal
impact assessment.
The geomagnetic latitude of the Ottawa geomagnetic observatory is 55; therefore, the
amplitudes of the geomagnetic field measurement data were scaled up to the 60 reference
geomagnetic latitude (see Figure 3) such that the resulting peak geoelectric field amplitude
computed using the reference earth model was 8 V/km (see Figures 4 and 5). The sampling rate
for the geomagnetic field waveform is 10 seconds.8 To use this geoelectric field time series when
a different earth model is applicable, it should be scaled with the appropriate benchmark
conductivity scaling factor b.
7
Refer to the Benchmark Geomagnetic Disturbance Event Description white paper for details on the determination of the
reference geomagnetic field waveform: http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx.
8 The data file of the benchmark geomagnetic field waveform is available on the Related Information webpage for TPL-007-1:
http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx.
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Figure 3: Benchmark Geomagnetic Field Waveform
Red Bn (Northward), Blue Be (Eastward)
Figure 4: Benchmark Geoelectric Field Waveform
EE (Eastward)
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Figure 5: Benchmark Geoelectric Field Waveform
EN (Northward)
Reference Geomagnetic Field Time Series or Waveform for the Supplemental GMD
Event9
The geomagnetic field measurement record of the March 13-14, 1989 GMD event, measured at
the NRCan Ottawa geomagnetic observatory, is the basis for the reference geomagnetic field
waveform to be used to calculate the GIC time series, GIC(t), required for transformer thermal
impact assessment for the supplemental GMD event. The supplemental GMD event waveform
differs from the benchmark GMD event waveform in that the supplemental GMD event
waveform has a local enhancement.
The geomagnetic latitude of the Ottawa geomagnetic observatory is 55; therefore, the
amplitudes of the geomagnetic field measurement data were scaled up to the 60 reference
geomagnetic latitude (see Figure 6) such that the resulting peak geoelectric field amplitude
computed using the reference earth model was 12 V/km (see Figure7). The sampling rate for the
geomagnetic field waveform is 10 seconds.10 To use this geoelectric field time series when a
different earth model is applicable, it should be scaled with the appropriate supplemental
conductivity scaling factor s.
9
Refer to the Supplemental Geomagnetic Disturbance Event Description white paper for details on the determination of the
reference geomagnetic field waveform: http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspx.
10 The data file of the benchmark geomagnetic field waveform is available on the NERC GMD Task Force project webpage:
http://www.nerc.com/comm/PC/Pages/Geomagnetic-Disturbance-Task-Force-(GMDTF)-2013.aspx.
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Figure 6: Supplemental Geomagnetic Field Waveform
Red BN (Northward), Blue BE (Eastward)
12 V/km
Figure 7: Supplemental Geoelectric Field Waveform
Blue EN (Northward), Red EE (Eastward)
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TPL-007-43 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Attachment 1-CAN
Attachment 1-CAN provides an alternative that a Canadian entity may use in lieu of the
benchmark or supplemental GMD event(s) defined in Attachment 1 for performing GMD
Vulnerability Assessment(s).
A Canadian entity may use the provisions of Attachment 1-CAN if it has regionally specific
information that provides a technically justified means to re-define a 1-in-100 year GMD
planning event(s) within its planning area.
Information for the Alternative Methodology
GMD Vulnerability Assessment(s) require the use of geophysical and engineering models.
Canadian-specific data is available and growing. Ongoing research allows for more accurate
characterization of regional parameters used in these models. Such Canadian-specific data
includes geomagnetic field, earth conductivity, and geomagnetically induced current
measurements that can be used for modeling and simulation validation.
Information used to calculate geoelectric fields for the benchmark and supplemental GMD events
shall be clearly documented and technically justified. For example, the factors involved in the
calculation of geoelectric fields are geomagnetic field variations and an earth transfer
function(s).1[1] Technically justified information used in modelling geomagnetic field variations
may include: technical documents produced by governmental entities such as Natural Resources
Canada; technical papers published in peer-reviewed journals; and data sets gathered using
sound scientific principles. An earth transfer function may rely on magnetotelluric measurements
or earth conductivity models.
Modeling assumptions shall also be clearly documented and technically justified. An entity may
use sensitivity analysis to identify how the assumptions affect the results.
A simplified model may be used to perform a GMD Vulnerability Assessment(s), as long as the
model is more conservative than a more detailed model.
When interpreting assessment results, the entity shall consider the maturity of the modeling,
toolset, and techniques applied.
Geomagnetic Disturbance Planning Events
The 1-in-100 year planning event shall be based on regionally specific data and technically
justifiable statistical analyses (e.g., extreme value theory) and applied to the benchmark and
supplemental GMD Vulnerability Assessment(s).
1
The “earth transfer function” is the relationship between the electric fields and magnetic field variations at the surface of the
earth.
[1] The “earth transfer function” is the relationship between the electric fields and magnetic field variations at the surface of the
earth.
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For the benchmark GMD Vulnerability Assessment(s), an entity shall consider the large-scale
spatial structure of the GMD event. For the supplemental GMD Vulnerability Assessment(s), an
entity shall consider the small-scale spatial structure of the GMD event (e.g., using magnetometer
measurements or realistic electrojet calculations).
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TPL-007-43 – Supplemental Material
Guidelines and Technical Basis
The diagram below provides an overall view of the GMD Vulnerability Assessment process:
Geomagnetic
Field
B(t)
Earth
Conductivity
Model
Potential
Mitigation
Measures
Geoelectric
Field
E(t)
dc
System
Model
GIC
Transformer vars
Model
(Electrical)
GIC(t)
Power Flow
Analysis
Transformer
Model
(Thermal)
Fail
Bus
Voltages
Line Loading &
var Reserves
Assessment
Criteria
Operating
Procedures
and
Pass
Mitigation
Measures
(if needed)
Temp(t)
Critical Temperatures
The requirements in this standard cover various aspects of the GMD Vulnerability Assessment
process.
Benchmark GMD Event (Attachment 1)
The benchmark GMD event defines the geoelectric field values used to compute GIC flows that
are needed to conduct a benchmark GMD Vulnerability Assessment. The Benchmark
Geomagnetic Disturbance Event Description, May 201611 white paper includes the event
description, analysis, and example calculations.
Supplemental GMD Event (Attachment 1)
The supplemental GMD event defines the geoelectric field values used to compute GIC flows
that are needed to conduct a supplemental GMD Vulnerability Assessment. The Supplemental
Geomagnetic Disturbance Event Description, October 201712 white paper includes the event
description and analysis.
Requirement R2
A GMD Vulnerability Assessment requires a GIC System model, which is a dc representation of
the System, to calculate GIC flow. In a GMD Vulnerability Assessment, GIC simulations are used
to determine transformer Reactive Power absorption and transformer thermal response.
Details for developing the GIC System model are provided in the NERC GMD Task Force guide:
11
12
http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx.
http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-Disturbance-Mitigation.aspx.
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Application Guide for Computing Geomagnetically-Induced Current in the Bulk Power System,
December 2013.13
Underground pipe-type cables present a special modeling situation in that the steel pipe that
encloses the power conductors significantly reduces the geoelectric field induced into the
conductors themselves, while they remain a path for GIC. Solid dielectric cables that are not
enclosed by a steel pipe will not experience a reduction in the induced geoelectric field. A
planning entity should account for special modeling situations in the GIC system model, if
applicable.
Requirement R4
The Geomagnetic Disturbance Planning Guide,14 December 2013 developed by the NERC GMD
Task Force provides technical information on GMD-specific considerations for planning studies.
Requirement R5
The benchmark thermal impact assessment of transformers specified in Requirement R6 is
based on GIC information for the benchmark GMD Event. This GIC information is determined by
the planning entity through simulation of the GIC System model and must be provided to the
entity responsible for conducting the thermal impact assessment. GIC information should be
provided in accordance with Requirement R5 each time the GMD Vulnerability Assessment is
performed since, by definition, the GMD Vulnerability Assessment includes a documented
evaluation of susceptibility to localized equipment damage due to GMD.
The maximum effective GIC value provided in Part 5.1 is used for the benchmark thermal
impact assessment. Only those transformers that experience an effective GIC value of 75 A or
greater per phase require evaluation in Requirement R6.
GIC(t) provided in Part 5.2 is used to convert the steady state GIC flows to time-series GIC data
for the benchmark thermal impact assessment of transformers. This information may be
needed by one or more of the methods for performing a benchmark thermal impact
13
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GIC%20Application
%20Guide%202013_approved.pdf.
14 http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GMD%20Planning
%20Guide_approved.pdf.
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TPL-007-43 – Supplemental Material
assessment. Additional information is in the following section and the Transformer Thermal
Impact Assessment White Paper,15 October 2017.
The peak GIC value of 75 Amps per phase has been shown through thermal modeling to be a
conservative threshold below which the risk of exceeding known temperature limits established
by technical organizations is low.
Requirement R6
The benchmark thermal impact assessment of a power transformer may be based on
manufacturer-provided GIC capability curves, thermal response simulation, thermal impact
screening, or other technically justified means. Approaches for conducting the assessment are
presented in the Transformer Thermal Impact Assessment White Paper ERO EnterpriseEndorsed Implementation Guidance16 for this requirement. This ERO-Endorsed document is
posted on the NERC Compliance Guidance17 webpage.
Transformers are exempt from the benchmark thermal impact assessment requirement if the
effective GIC value for the transformer is less than 75 A per phase, as determined by a GIC
analysis of the System. Justification for this criterion is provided in the Screening Criterion for
Transformer Thermal Impact Assessment White Paper,18 October 2017. A documented design
specification exceeding this value is also a justifiable threshold criterion that exempts a
transformer from Requirement R6.
The benchmark threshold criteria and its associated transformer thermal impact must be
evaluated on the basis of effective GIC. Refer to the white papers for additional information.
Requirement R7
Technical considerations for GMD mitigation planning, including operating and equipment
strategies, are available in Chapter 5 of the Geomagnetic Disturbance Planning Guide,19
December 2013. Additional information is available in the 2012 Special Reliability Assessment
15
http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-Disturbance-Mitigation.aspx.
http://www.nerc.com/pa/comp/guidance/EROEndorsedImplementationGuidance/TPL-007-1_Transformer_Thermal_Impact_
Assessment_White_Paper.pdf.
17 http://www.nerc.com/pa/comp/guidance/Pages/default.aspx.
18 http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-Disturbance-Mitigation.aspx.
19 http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GMD%20Planning
%20Guide_approved.pdf.
16
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TPL-007-43 – Supplemental Material
Interim Report: Effects of Geomagnetic Disturbances on the Bulk-Power System, 20 February
2012.
Requirement R8
The Geomagnetic Disturbance Planning Guide,21 December 2013 developed by the NERC GMD
Task Force provides technical information on GMD-specific considerations for planning studies.
The supplemental GMD Vulnerability Assessment process is similar to the benchmark GMD
Vulnerability Assessment process described under Requirement R4.
Requirement R9
The supplemental thermal impact assessment specified of transformers in Requirement R10 is
based on GIC information for the supplemental GMD Event. This GIC information is determined
by the planning entity through simulation of the GIC System model and must be provided to the
entity responsible for conducting the thermal impact assessment. GIC information should be
provided in accordance with Requirement R9 each time the GMD Vulnerability Assessment is
performed since, by definition, the GMD Vulnerability Assessment includes a documented
evaluation of susceptibility to localized equipment damage due to GMD.
The maximum effective GIC value provided in Part 9.1 is used for the supplemental thermal
impact assessment. Only those transformers that experience an effective GIC value of 85 A or
greater per phase require evaluation in Requirement R10.
GIC(t) provided in Part 9.2 is used to convert the steady state GIC flows to time-series GIC data
for the supplemental thermal impact assessment of transformers. This information may be
needed by one or more of the methods for performing a supplemental thermal impact
assessment. Additional information is in the following section.
The peak GIC value of 85 Amps per phase has been shown through thermal modeling to be a
conservative threshold below which the risk of exceeding known temperature limits established
by technical organizations is low.
Requirement R10
The supplemental thermal impact assessment of a power transformer may be based on
manufacturer-provided GIC capability curves, thermal response simulation, thermal impact
screening, or other technically justified means. Approaches for conducting the assessment are
presented in the Transformer Thermal Impact Assessment White Paper ERO EnterpriseEndorsed Implementation Guidance22 discussed in the Requirement R6 section above. A later
20
http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2012GMD.pdf.
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GMD%20Planning
%20Guide_approved.pdf.
22 http://www.nerc.com/pa/comp/guidance/EROEndorsedImplementationGuidance/TPL-007-1_Transformer_Thermal_Impact_
Assessment_White_Paper.pdf.
21
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TPL-007-43 – Supplemental Material
version of the Transformer Thermal Impact Assessment White Paper,23 October 2017, has been
developed to include updated information pertinent to the supplemental GMD event and
supplemental thermal impact assessment.
Transformers are exempt from the supplemental thermal impact assessment requirement if the
effective GIC value for the transformer is less than 85 A per phase, as determined by a GIC
analysis of the System. Justification for this criterion is provided in the revised Screening
Criterion for Transformer Thermal Impact Assessment White Paper,24 October 2017. A
documented design specification exceeding this value is also a justifiable threshold criterion
that exempts a transformer from Requirement R10.
The supplemental threshold criteria and its associated transformer thermal impact must be
evaluated on the basis of effective GIC. Refer to the white papers for additional information.
Requirement R11
Technical considerations for GIC monitoring are contained in Chapter 6 of the 2012 Special
Reliability Assessment Interim Report: Effects of Geomagnetic Disturbances on the Bulk-Power
System, 25 February 2012. GIC monitoring is generally performed by Hall effect transducers that
are attached to the neutral of the wye-grounded transformer. Data from GIC monitors is useful
for model validation and situational awareness.
Responsible entities consider the following in developing a process for obtaining GIC monitor
data:
Monitor locations. An entity's operating process may be constrained by location of existing GIC
monitors. However, when planning for additional GIC monitoring installations consider that
data from monitors located in areas found to have high GIC based on system studies may
provide more useful information for validation and situational awareness purposes. Conversely,
data from GIC monitors that are located in the vicinity of transportation systems using direct
current (e.g., subways or light rail) may be unreliable.
Monitor specifications. Capabilities of Hall effect transducers, existing and planned, should be
considered in the operating process. When planning new GIC monitor installations, consider
23
http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-Disturbance-Mitigation.aspx.
http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-Disturbance-Mitigation.aspx.
25 http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2012GMD.pdf.
24
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TPL-007-43 – Supplemental Material
monitor data range (e.g., -500 A through + 500 A) and ambient temperature ratings consistent
with temperatures in the region in which the monitor will be installed.
Sampling Interval. An entity's operating process may be constrained by capabilities of existing
GIC monitors. However, when possible specify data sampling during periods of interest at a rate
of 10 seconds or faster.
Collection Periods. The process should specify when the entity expects GIC data to be
collected. For example, collection could be required during periods where the Kp index is above
a threshold, or when GIC values are above a threshold. Determining when to discontinue
collecting GIC data should also be specified to maintain consistency in data collection.
Data format. Specify time and value formats. For example, Greenwich Mean Time (GMT)
(MM/DD/YYYY HH:MM:SS) and GIC Value (Ampere). Positive (+) and negative (-) signs indicate
direction of GIC flow. Positive reference is flow from ground into transformer neutral. Time
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fields should indicate the sampled time rather than system or SCADA time if supported by the
GIC monitor system.
Data retention. The entity's process should specify data retention periods, for example 1 year.
Data retention periods should be adequately long to support availability for the entity's model
validation process and external reporting requirements, if any.
Additional information. The entity's process should specify collection of other information
necessary for making the data useful, for example monitor location and type of neutral
connection (e.g., three-phase or single-phase).
Requirement R12
Magnetometers measure changes in the earth's magnetic field. Entities should obtain data
from the nearest accessible magnetometer. Sources of magnetometer data include:
Observatories such as those operated by U.S. Geological Survey and Natural Resources Canada,
see figure below for locations:26
26
http://www.intermagnet.org/index-eng.php.
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Implementation Plan
Project 2019-01 Modifications to TPL-007-3
Applicable Standard
•
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Requested Retirement
•
TPL-007-3 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Prerequisite Standard
None
Applicable Entities
•
Planning Coordinator with a planning area that includes a Facility or Facilities specified in Section
4.2 of the standard;
•
Transmission Planner with a planning area that includes a Facility or Facilities specified in Section
4.2 of the standard;
•
Transmission Owner who owns a Facility or Facilities specified in Section 4.2 of the standard; and
•
Generator Owner who owns a Facility or Facilities specified in Section 4.2 of the standard.
Section 4.2 states that the standard applies to facilities that include power transformer(s) with a
high-side, wye-grounded winding with terminal voltage greater than 200 kV.
Terms in the NERC Glossary of Terms
There are no new, modified, or retired terms.
Background
On November 15, 2018, the Federal Energy Regulatory Commission (FERC) issued Order No. 851
approving Reliability Standard TPL-007-2 and its associated implementation plan. In the order, FERC
also directed NERC to develop certain modifications to the standard. FERC established a deadline of
12 months from the effective date of Reliability Standard TPL-007-2 to submit a revised standard
(July 1, 2020).
On February 7, 2019, the NERC Board of Trustees adopted Reliability Standard TPL-007-3, which
added a Variance option for applicable entities in Canadian jurisdictions. No continent-wide
requirements were changed. Under the terms of its implementation plan, Reliability Standard TPL007-3 became effective in the United States on July 1, 2019. All phased-in compliance dates from
the TPL-007-2 implementation plan were carried forward unchanged in the TPL-007-3
implementation plan.
General Considerations
This implementation plan is intended to integrate the new and revised requirements in TPL-007-4 in
the existing timeframe under the TPL-007-3 implementation plan.
Effective Date
The effective date for the proposed Reliability Standard is provided below. Where the standard
drafting team identified the need for a longer implementation period for compliance with a
particular section of the proposed Reliability Standard (e.g., an entire Requirement or a portion
thereof), the additional time for compliance with that section is specified below. These phased-in
compliance dates represent the dates that entities must begin to comply with that particular section
of the Reliability Standard, even where the Reliability Standard goes into effect at an earlier date.
Reliability Standard TPL-007-4
Where approval by an applicable governmental authority is required, the standard shall become
effective on the first day of the first calendar quarter that is six (6) months after the effective date of
the applicable governmental authority’s order approving the standard, or as otherwise provided for
by the applicable governmental authority.
Where approval by an applicable governmental authority is not required, the standard shall become
effective on the first day of the first calendar quarter that is six (6) months after the date the
standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that jurisdiction.
Phased-In Compliance Dates
Compliance Date for TPL-007-4 Requirements R1, R2, R5, and R9
Entities shall be required to comply with Requirements R1, R2, R5, and R9 upon the effective date of
Reliability Standard TPL-007-4.
Compliance Date for TPL-007-4 Requirements R12 and R13
Entities shall not be required to comply with Requirements R12 and R13 until the later of: (i) July 1,
2021; or (ii) the effective date of Reliability Standard TPL-007-4.
Compliance Date for TPL-007-4 Requirements R6 and R10
Entities shall not be required to comply with Requirements R6 and R10 until the later of: (i) January
1, 2022; or (ii) the effective date of Reliability Standard TPL-007-4.
Compliance Date for TPL-007-4 Requirements R3, R4, and R8
Entities shall not be required to comply with Requirements R3, R4, and R8 until the later of: (i)
January 1, 2023; or (ii) the effective date of Reliability Standard TPL-007-4.
Implementation Plan
Project 2019-01 Modifications to TPL-007-3 | July 2019
2
Compliance Date for TPL-007-4 Requirement R7
Entities shall not be required to comply with Requirement R7 until the later of: (i) January 1, 2024;
or (ii) the effective date of Reliability Standard TPL-007-4.
Compliance Date for TPL-007-4 Requirement R11
Entities shall not be required to comply with Requirement R11 until the later of: (i) January 1, 2024;
or (ii) six (6) months after the effective date of Reliability Standard TPL-007-4.
Retirement Date
Standard TPL-007-3
Reliability Standard TPL-007-3 shall be retired immediately prior to the effective date of TPL-007-4 in
the particular jurisdiction in which the revised standard is becoming effective.
Initial Performance of Periodic Requirements
Transmission Owners and Generator Owners are not required to comply with Requirement R6 prior
to the compliance date for Requirement R6, regardless of when geomagnetically-induced current
(GIC) flow information specified in Requirement R5, Part 5.1 is received.
Transmission Owners and Generator Owners are not required to comply with Requirement R10
prior to the compliance date for Requirement R10, regardless of when GIC flow information
specified in Requirement R9, Part 9.1 is received.
Implementation Plan
Project 2019-01 Modifications to TPL-007-3 | July 2019
3
Unofficial Comment Form
Project 2019-01 Modifications to TPL-007-3
Do not use this form for submitting comments. Use the Standards Balloting and Commenting System
(SBS) to submit comments on TPL-007-4 – Transmission System Planned Performance for Geomagnetic
Disturbance Events. Comments must be submitted by 8 p.m. Eastern, Monday, September 9, 2019.
m. Eastern, Thursday, August 20, 2015
Additional information is available on the project page. If you have questions, contact Senior Standards
Developer, Alison Oswald (via email), or at 404-446-9668.
Background Information
The first version of the standard, TPL-007-1, requires entities to assess the impact to their systems from a
defined event referred to as the “Benchmark GMD Event.” The second version of the standard, TPL-007-2,
adds new Requirements R8, R9, and R10 to require responsible entities to assess the potential
implications of a “Supplemental GMD Event” on their equipment and systems in accordance with the
FERC’s directives in Order No. 830. The third version of the standard, TPL-007-3, adds a Canadian variance
for Canadian Registered Entities to leverage operating experience, observed GMD effects, and on-going
research efforts for defining alternative Benchmark GMD Events and/or Supplemental GMD Events that
appropriately reflect their specific geographical and geological characteristics. No continent-wide
requirements were changed between the second and the third versions of the standard. This project will
address the directives issued by FERC in Order No. 851 to modify Reliability Standard TPL-007-3. FERC
directed NERC to submit modifications to: (1) require the development and implementation of corrective
action plans to mitigate assessed supplemental GMD event vulnerabilities (P 29); and (2) to replace the
corrective action plan time-extension provision in TPL-007-3 Requirement R7.4 with a process through
which extensions of time are considered on a case-by-case basis (P 54).
Questions
1. The SDT approach was to modify Requirement R7.4 to meet the directive in Order 851 to require
prior approval of extension requests for completing corrective action plan tasks. Do you agree that
R7 meets the directive? If you disagree please explain and provide alternative language and
rationale for how it meets the directive of the order.
Yes
No
Comments:
RELIABILITY | RESILIENCE | SECURITY
2. The SDT approach was to add Requirement R11 to meet the directive in Order No. 851 to “require
corrective action plans for assessed supplemental GMD event vulnerabilities.” R7 and R11 are the
same language applied to the benchmark and supplemental events respectively. Do you agree
that R11 meets the directive? If you disagree please explain and provide alternative language and
rationale for how it meets the directive of the order.
Yes
No
Comments:
3. Do you agree that the Canadian variance is written in a way that accommodates the regulatory
processes in Canada? If you disagree please explain and provide alternative language and rationale
for how it meets the directive of the order while accommodating Canadian regulatory processes.
Yes
No
Comments:
4. Do you agree that the standard language changes in Requirement R7, R8, and R11 proposed by the
SDT adequately address the directives in FERC Order No. 851? If you disagree please explain and
provide alternative language and rationale for how it meets the directive of the order.
Yes
No
Comments:
5. Do you have any comments on the modified VRF/VSL for Requirements R7, R8, and R11?
Yes
No
Comments:
6. Do you agree with the proposed Implementation Plan? If you think an alternate, shorter or longer
implementation time period is needed, please propose an alternate implementation plan and time
period, and provide a detailed explanation of actions planned to meet the implementation
deadline.
Yes
No
Comments:
Unofficial Comment Form | Project 2019-01 Modifications to TPL-007-3
TPL-007-4 | July-August, 2019
2
7. The SDT proposes that the modifications in TPL-007-4 meet the FERC directives in a cost effective
manner. Do you agree? If you do not agree, or if you agree but have suggestions for improvement
to enable more cost effective approaches, please provide your recommendation and, if
appropriate, technical or procedural justification.
Yes
No
Comments:
8. Provide any additional comments for the standard drafting team to consider, if desired.
Comments:
Unofficial Comment Form | Project 2019-01 Modifications to TPL-007-3
TPL-007-4 | July-August, 2019
3
July 2019 - DRAFT Technical Rationale
Pending Submittal for ERO Enterprise Endorsement
Transmission System
Planned Performance for
Geomagnetic Disturbance
Events
Technical Rationale and Justification for
Reliability Standard TPL-007-4
July 2019
NERC | Report Title | Report Date
I
Table of Contents
Preface ....................................................................................................................................................................... iii
Introduction ............................................................................................................................................................... iv
Background ............................................................................................................................................................ iv
Chapter 1 – General Considerations ..........................................................................................................................1
Rationale for Applicability.......................................................................................................................................1
Benchmark GMD Event (Attachment 1) ..................................................................................................................1
Supplemental GMD Event (Attachment 1) ..............................................................................................................1
Chapter 2 – Requirement R2 ......................................................................................................................................2
Chapter 3 – Requirement R4 ......................................................................................................................................3
Chapter 4 – Requirement R5 ......................................................................................................................................4
Chapter 5 – Requirement R6 ......................................................................................................................................5
Chapter 6 – Requirement R7 ......................................................................................................................................6
Chapter 7 – Supplemental GMD Vulnerability Assessment .......................................................................................7
Chapter 8 – Requirement R8 ......................................................................................................................................8
Chapter 9 – Requirement R9 ......................................................................................................................................9
Chapter 10 – Requirement R10 ............................................................................................................................... 10
Chapter 11 – Requirement R11 ............................................................................................................................... 11
Chapter 12 – Requirement R12 ............................................................................................................................... 12
Chapter 13 – Requirement R13 ............................................................................................................................... 13
References ............................................................................................................................................................... 14
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | July 2019
ii
Preface
The vision for the Electric Reliability Organization (ERO) Enterprise, which is comprised of the North American
Electric Reliability Corporation (NERC) and the seven Regional Entities (REs), is a highly reliable and secure North
American bulk power system (BPS). Our mission is to assure the effective and efficient reduction of risks to the
reliability and security of the grid.
The North American BPS is divided into seven RE boundaries as shown in the map and corresponding table
below. The multicolored area denotes overlap as some load-serving entities participate in one Region while
associated Transmission Owners/Operators participate in another.
FRCC
Florida Reliability Coordinating Council
MRO
Midwest Reliability Organization
NPCC
Northeast Power Coordinating Council
RF
ReliabilityFirst
SERC
SERC Reliability Corporation
Texas RE
Texas Reliability Entity
WECC
Western Electricity Coordinating Council
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | July 2019
iii
Introduction
Background
This document explains the technical rationale and justification for the proposed Reliability Standard TPL-007-4
Transmission System Planned Performance for Geomagnetic Disturbance Events. It provides stakeholders and the
ERO Enterprise with an understanding of the technical requirements in the Reliability Standard. It also contains
information on the standard drafting team’s intent in drafting the requirements. This document, the Technical
Rationale and Justification for TPL-007-4, is not a Reliability Standard and should not be considered mandatory
and enforceable.
The first version of the standard, TPL-007-1, approved by FERC in Order No. 779 [1], requires entities to assess the
impact to their systems from a defined event referred to as the “Benchmark GMD Event.” The second version of
the standard, TPL-007-2, adds new Requirements R8, R9, and R10 to require responsible entities to assess the
potential implications of a “Supplemental GMD Event” on their equipment and systems in accordance with FERC’s
directives in Order No. 830 [2]. Some GMD events have shown localized enhancements of the geomagnetic field.
The supplemental GMD event was developed to represent conditions associated with such localized enhancement
during a severe GMD event for use in a GMD Vulnerability Assessment. The third version of the standard, TPL007-3, adds a Canadian variance for Canadian Registered Entities to leverage operating experience, observed GMD
effects, and on-going research efforts for defining alternative Benchmark GMD Events and/or Supplemental GMD
Events that appropriately reflect Canadian-specific geographical and geological characteristics. No continent-wide
requirements were changed between the second and the third versions of the standard. The fourth version of the
standard, TPL-007-4, addresses the directives issued by FERC in Order No. 851 [3] to modify Reliability Standard
TPL-007-3. FERC directed NERC to submit modifications to: (1) require the development and implementation of
corrective action plans to mitigate assessed supplemental GMD event vulnerabilities (P 29); and (2) to replace the
corrective action plan time-extension provision in TPL-007-3 with a process through which extensions of time are
considered on a case-by-case basis (P 54).
The requirements in this standard cover various aspects of the GMD Vulnerability Assessment process. Figure 1
provides an overall view of the GMD Vulnerability Assessment process:
Figure 1. GMD Vulnerability Assessment Process.
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | July 2019
iv
Chapter 1 – General Considerations
Rationale for Applicability
Reliability Standard TPL-007-4 is applicable to Facilities that include power transformer(s) with a high side, wyegrounded winding with terminal voltage greater than 200 kV.
Instrumentation transformers and station service transformers do not have significant impact on geomagneticallyinduced current (GIC) flows; therefore, these types of transformers are not included in the applicability for this
standard. Terminal voltage describes line-to-line voltage.
Benchmark GMD Event (Attachment 1)
The benchmark GMD event defines the geoelectric field values used to compute GIC flows that are needed to
conduct a benchmark GMD Vulnerability Assessment. The Benchmark Geomagnetic Disturbance Event
Description, May 2016 [4], includes the event description, analysis, and example calculations.
Supplemental GMD Event (Attachment 1)
The supplemental GMD event defines the geoelectric field values used to compute GIC flows that are needed to
conduct a supplemental GMD Vulnerability Assessment. The Supplemental Geomagnetic Disturbance Event
Description, October 2017 [5], includes the event description and analysis.
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | July 2019
1
Chapter 2 – Requirement R2
A GMD Vulnerability Assessment requires a GIC System model, which is a dc representation of the System, to
calculate GIC flow. In a GMD Vulnerability Assessment, GIC simulations are used to determine transformer
Reactive Power absorption and transformer thermal response. Details for developing the GIC System model are
provided in the Application Guide – Computing Geomagnetically-Induced Current in the Bulk-Power System,
December 2013 [6].
A GMD Vulnerability Assessment requires a GIC System model to calculate GIC flow which is used to determine
transformer Reactive Power absorption and transformer thermal response. Guidance for developing the GIC
System model is provided in the Application Guide – Computing Geomagnetically-Induced Current in the BulkPower System, December 2013 [6].
The System model specified in Requirement R2 is used in conducting steady state power flow analysis that
accounts for the Reactive Power absorption of power transformer(s) due to GIC in the System.
The GIC System model includes all power transformer(s) with a high side, wye-grounded winding with terminal
voltage greater than 200 kV. The model is used to calculate GIC flow in the network.
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | July 2019
2
Chapter 3 – Requirement R4
The Geomagnetic Disturbance Planning Guide, December 2013 [7], provides technical information on GMDspecific considerations for planning studies.
The GMD Vulnerability Assessment includes steady state power flow analysis and the supporting study or studies
using the models specified in Requirement R2 that account for the effects of GIC. Performance criteria are
specified in Table 1: Steady State Planning GMD Event found in TPL-007-4. At least one System On-Peak Load and
at least one System Off-Peak Load must be examined in the analysis.
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | July 2019
3
Chapter 4 – Requirement R5
The benchmark thermal impact assessment of transformers specified in Requirement R6 is based on GIC
information for the benchmark GMD Event. This GIC information is determined by the planning entity through
simulation of the GIC System model and must be provided to the entity responsible for conducting the thermal
impact assessment. GIC information for the benchmark thermal impact assessment should be provided in
accordance with Requirement R5 each time the benchmark GMD Vulnerability Assessment is performed since, by
definition, the GMD Vulnerability Assessment includes a documented evaluation of susceptibility to localized
equipment damage due to GMD.
The peak GIC value of 75 Amps per phase, in the benchmark GMD Vulnerability Assessment, has been shown
through thermal modeling to be a conservative threshold below which the risk of exceeding known temperature
limits established by technical organizations is low.
This GIC information is necessary for determining the benchmark thermal impact of GIC on transformers in the
planning area and must be provided to entities responsible for performing the thermal impact assessment so that
they can accurately perform the assessment. GIC information should be provided in accordance with Requirement
R5 as part of the benchmark GMD Vulnerability Assessment process since, by definition, the GMD Vulnerability
Assessment includes documented evaluation of susceptibility to localized equipment damage due to GMD.
GIC(t) provided in Part 5.2 can be used to convert the steady state GIC flows to time-series GIC data for the
benchmark transformer thermal impact assessment. This information may be needed by one or more of the
methods for performing a thermal impact assessment. Additional guidance is available in the Transformer Thermal
Impact Assessment White Paper, October 2017 [8].
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | July 2019
4
Chapter 5 – Requirement R6
The benchmark thermal impact assessment of a power transformer may be based on manufacturer-provided GIC
capability curves, thermal response simulation, thermal impact screening, or other technically justified means.
Justification for this criterion is provided in the Screening Criterion for Transformer Thermal Impact Assessment
White Paper, October 2017 [9].
The transformer thermal assessment will be repeated or reviewed using previous assessment results each time
the planning entity performs a GMD Vulnerability Assessment and provides GIC information as specified in
Requirement R5.
Thermal impact assessments of non-BES transformers are not required because those transformers do not have
a wide-area effect on the reliability of the interconnected Transmission system.
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | July 2019
5
Chapter 6 – Requirement R7
The requirement addresses directives in FERC Order No. 851 to replace the time-extension provision in
Requirement R7.4 of TPL-007-2 (and TPL-007-3) with a process through which extensions of time are considered
on a case-by-case basis.
Technical considerations for GMD mitigation planning, including operating and equipment strategies, are available
in Chapter 5 of the Geomagnetic Disturbance Planning Guide, December 2013 [7]. Additional information is
available in the 2012 Special Reliability Assessment Interim Report: Effects of Geomagnetic Disturbances on the
Bulk Power System, February 2012 [10].
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | July 2019
6
Chapter 7 – Supplemental GMD Vulnerability Assessment
The requirements address directives in FERC Order No. 830 for revising the benchmark GMD event used in GMD
Vulnerability Assessments (PP 44, 47-49). The requirements add a supplemental GMD Vulnerability Assessment
based on the supplemental GMD event that accounts for localized peak geoelectric fields.
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | July 2019
7
Chapter 8 – Requirement R8
The Geomagnetic Disturbance Planning Guide, December 2013 [7], provides technical information on GMDspecific considerations for planning studies.
The supplemental GMD Vulnerability Assessment process is similar to the benchmark GMD Vulnerability
Assessment process described under Requirement R4.
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | July 2019
8
Chapter 9 – Requirement R9
The supplemental thermal impact assessment specified of transformers in Requirement R10 is based on GIC
information for the supplemental GMD Event. This GIC information is determined by the planning entity through
simulation of the GIC System model and must be provided to the entity responsible for conducting the thermal
impact assessment. GIC information for the supplemental thermal impact assessment should be provided in
accordance with Requirement R9 each time the supplemental GMD Vulnerability Assessment is performed since,
by definition, the GMD Vulnerability Assessment includes a documented evaluation of susceptibility to localized
equipment damage due to GMD.
The peak GIC value of 85 Amps per phase, in the supplemental GMD Vulnerability Assessment, has been shown
through thermal modeling to be a conservative threshold below which the risk of exceeding known temperature
limits established by technical organizations is low.
This GIC information is necessary for determining the supplemental thermal impact of GIC on transformers in the
planning area and must be provided to entities responsible for performing the thermal impact assessment so that
they can accurately perform the assessment. GIC information should be provided in accordance with Requirement
R5 as part of the supplemental GMD Vulnerability Assessment process since, by definition, the GMD Vulnerability
Assessment includes documented evaluation of susceptibility to localized equipment damage due to GMD.
GIC(t) provided in Part 9.2 can be used to convert the steady state GIC flows to time-series GIC data for the
supplemental transformer thermal impact assessment. This information may be needed by one or more of the
methods for performing a thermal impact assessment. Additional guidance is available in the Transformer Thermal
Impact Assessment White Paper, October 2017 [8].
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | July 2019
9
Chapter 10 – Requirement R10
The supplemental thermal impact assessment of a power transformer may be based on manufacturer-provided
GIC capability curves, thermal response simulation, thermal impact screening, or other technically justified means.
Justification for this criterion is provided in the Screening Criterion for Transformer Thermal Impact Assessment
White Paper, October 2017 [9].
The transformer thermal assessment will be repeated or reviewed using previous assessment results each time
the planning entity performs a GMD Vulnerability Assessment and provides GIC information as specified in
Requirement R9.
Thermal impact assessments of non-BES transformers are not required because those transformers do not have
a wide-area effect on the reliability of the interconnected Transmission system.
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | July 2019
10
Chapter 11 – Requirement R11
The requirement addresses directives in FERC Order No. 851 to develop and submit modifications to Reliability
Standard TPL-007-2 (and TPL-007-3) to require corrective action plans for the assessed supplemental GMD event
vulnerabilities.
Technical considerations for GMD mitigation planning, including operating and equipment strategies, are available
in Chapter 5 of the Geomagnetic Disturbance Planning Guide, December 2013 [7]. Additional information is
available in the 2012 Special Reliability Assessment Interim Report: Effects of Geomagnetic Disturbances on the
Bulk Power System, February 2012 [10].
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | July 2019
11
Chapter 12 – Requirement R12
GMD measurement data refers to GIC monitor data and geomagnetic field data in Requirements R12 and R13,
respectively. This requirement addresses directives in FERC Order No. 830 for requiring responsible entities to
collect GIC monitoring data as necessary to enable model validation and situational awareness (PP 88, 90-92).
Technical considerations for GIC monitoring are contained in Chapter 9 of the 2012 Special Reliability Assessment
Interim Report: Effects of Geomagnetic Disturbances on the Bulk Power System, February 2012 [10]. GIC
monitoring is generally performed by Hall effect transducers that are attached to the neutral of the wye-grounded
transformer and measure dc current flowing through the neutral. Data from GIC monitors is useful for model
validation and situational awareness.
The objective of Requirement R12 is for entities to obtain GIC data for the Planning Coordinator’s planning area
or other part of the system included in the Planning Coordinator's GIC System model to inform GMD Vulnerability
Assessments. Technical considerations for GIC monitoring are contained in Chapter 9 of the 2012 Special Reliability
Assessment Interim Report: Effects of Geomagnetic Disturbances on the Bulk Power System, February 2012 [10].
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | July 2019
12
Chapter 13 – Requirement R13
GMD measurement data refers to GIC monitor data and geomagnetic field data in Requirements R12 and R13,
respectively. This requirement addresses directives in FERC Order No. 830 for requiring responsible entities to
collect magnetometer data as necessary to enable model validation and situational awareness (PP 88, 90-92).
The objective of Requirement R13 is for entities to obtain geomagnetic field data for the Planning Coordinator's
planning area to inform GMD Vulnerability Assessments.
Magnetometers provide geomagnetic field data by measuring changes in the earth's magnetic field. Sources of
geomagnetic field data include:
•
Observatories such as those operated by U.S. Geological Survey, Natural Resources Canada, research
organizations, or university research facilities;
•
Installed magnetometers; and
•
Commercial or third-party sources of geomagnetic field data.
Geomagnetic field data for a Planning Coordinator’s planning area is obtained from one or more of the above data
sources located in the Planning Coordinator’s planning area, or by obtaining a geomagnetic field data product for
the Planning Coordinator’s planning area from a government or research organization. The geomagnetic field data
product does not need to be derived from a magnetometer or observatory within the Planning Coordinator’s
planning area.
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | July 2019
13
References
1. FERC Order No. 779,
https://www.nerc.com/FilingsOrders/us/FERCOrdersRules/Order779_GMD_RM12-22_20130516.pdf
2. FERC Order No. 830,
https://www.nerc.com/filingsorders/us/FERCOrdersRules/E-4.pdf
3. FERC Order No. 851,
https://www.nerc.com/FilingsOrders/us/FERCOrdersRules/E-3_Order%20No%20851.pdf
4. Benchmark Geomagnetic Disturbance Event Description, NERC, Atlanta, GA, May 12,
2016, https://www.nerc.com/pa/Stand/TPL0071RD/Benchmark_clean_May12_complete.pdf
5. Supplemental Geomagnetic Disturbance Event Description, NERC, Atlanta, GA, October
2017, https://www.nerc.com/pa/Stand/Project201303GeomagneticDisturbanceMitigation/Supplement
al_GMD_Event_Description_2017_October_Clean.pdf
6. Application Guide – Computing Geomagnetically-Induced Current in the Bulk-Power System, NERC,
Atlanta, GA, December,
2013, https://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%2
02013/GIC%20Application%20Guide%202013_approved.pdf
7. Geomagnetic Disturbance Planning Guide, NERC, Atlanta, GA, December,
2013, https://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%2
02013/GMD%20Planning%20Guide_approved.pdf
8. Transformer Thermal Impact Assessment White Paper, NERC, Atlanta, GA, October
2017, https://www.nerc.com/pa/Stand/Project201303GeomagneticDisturbanceMitigation/Thermal_Im
pact_Assessment_2017_October_Clean.pdf
9. Screening Criterion for Transformer Thermal Impact Assessment White Paper, NERC, Atlanta, GA,
October
2017, https://www.nerc.com/pa/Stand/Project201303GeomagneticDisturbanceMitigation/Screening_Cr
iterion_Clean_2017_October_Clean.pdf
10. 2012 Special Reliability Assessment Interim Report: Effects of Geomagnetic Disturbances on the Bulk
Power System, NERC, Atlanta, GA, February,
2012, https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2012GMD.pdf
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | July 2019
14
July 2019 - DRAFT Implementation Guidance
Pending Submittal for ERO Enterprise Endorsement
Transmission System
Planned Performance for
Geomagnetic Disturbance
Events
Implementation Guidance for
Reliability Standard TPL-007-4
July 2019
NERC | Report Title | Report Date
I
Table of Contents
Preface ....................................................................................................................................................................... iii
Introduction ............................................................................................................................................................... iv
Background ............................................................................................................................................................ iv
Chapter 1 – Requirement R1 ......................................................................................................................................1
Chapter 2 – Requirement R2 ......................................................................................................................................2
Chapter 3 – Requirement R3 ......................................................................................................................................3
Chapter 4 – Requirement R4 ......................................................................................................................................4
Chapter 5 – Requirement R5 ......................................................................................................................................5
Chapter 6 – Requirement R6 ......................................................................................................................................6
Chapter 7 – Requirement R7 ......................................................................................................................................7
Chapter 8 – Supplemental GMD Vulnerability Assessment .......................................................................................8
Chapter 9 – Requirement R8 ................................................................................................................................... 10
Chapter 10 – Requirement R9 ................................................................................................................................. 11
Chapter 11 – Requirement R10 ............................................................................................................................... 12
Chapter 12 – Requirement R11 ............................................................................................................................... 13
Chapter 13 – Requirement R12 ............................................................................................................................... 14
Chapter 14 – Requirement R13 ............................................................................................................................... 15
References ............................................................................................................................................................... 16
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | July 2019
ii
Preface
The vision for the Electric Reliability Organization (ERO) Enterprise, which is comprised of the North American
Electric Reliability Corporation (NERC) and the seven Regional Entities (REs), is a highly reliable and secure North
American bulk power system (BPS). Our mission is to assure the effective and efficient reduction of risks to the
reliability and security of the grid.
The North American BPS is divided into seven RE boundaries as shown in the map and corresponding table below.
The multicolored area denotes overlap as some load-serving entities participate in one Region while associated
Transmission Owners/Operators participate in another.
FRCC
Florida Reliability Coordinating Council
MRO
Midwest Reliability Organization
NPCC
Northeast Power Coordinating Council
RF
ReliabilityFirst
SERC
SERC Reliability Corporation
Texas RE
Texas Reliability Entity
WECC
Western Electricity Coordinating Council
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | July 2019
iii
Introduction
Background
The Standards Project 2019-01 Modifications to TPL-007-3 standard drafting team prepared this Implementation
Guidance to provide example approaches for compliance with the modifications to TPL-007 - Transmission System
Planned Performance for Geomagnetic Disturbance Events. Implementation Guidance does not prescribe the only
approach, but highlights one or more approaches that would be effective in achieving compliance with the
standard. Because Implementation Guidance only provides examples, entities may choose alternative approaches
based on engineering judgement, individual equipment and system conditions.
The first version of the standard, TPL-007-1 which was approved in FERC’s Order No. 779 [1], requires entities to
assess the impact to their systems from a defined event referred to as the “Benchmark GMD Event.” The second
version of the standard, TPL-007-2, adds new Requirements R8, R9, and R10 to require responsible entities to
assess the potential implications of a “Supplemental GMD Event” on their equipment and systems in accordance
with FERC’s directives in Order No. 830 [2]. Some GMD events have shown localized enhancements of the
geomagnetic field. The supplemental GMD event was developed to represent conditions associated with such
localized enhancement during a severe GMD event for use in a GMD Vulnerability Assessment. The third version
of the standard, TPL-007-3, adds a Canadian variance for Canadian Registered Entities to leverage operating
experience, observed GMD effects, and on-going research efforts for defining alternative Benchmark GMD Events
and/or Supplemental GMD Events that appropriately reflect their specific geographical and geological
characteristics. No continent-wide requirements were changed between the second and the third versions of the
standard. The fourth version, TPL-007-4, addresses the directives issued by FERC in Order No. 851 [3] to modify
Reliability Standard TPL-007-3. FERC directed NERC to submit modifications to: (1) require the development and
implementation of corrective action plans to mitigate assessed supplemental GMD event vulnerabilities (P 29);
and (2) to replace the corrective action plan time-extension provision in TPL-007-3 Requirement R7.4 with a
process through which extensions of time are considered on a case-by-case basis (P 54).
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | July 2019
iv
Chapter 1 – Requirement R1
In some areas, planning entities may determine that the most effective approach to conduct a GMD Vulnerability
Assessment is through a regional planning organization. No requirement in the standard is intended to prohibit a
collaborative approach where roles and responsibilities are determined by a planning organization made up of
one or more Planning Coordinator(s).
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | July 2019
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Chapter 2 – Requirement R2
The projected System condition for GMD planning may include adjustments to the System that are executable in
response to space weather information. These system adjustments could for example include recalling or
postponing maintenance outages.
Underground pipe-type cables present a special modeling situation in that the steel pipe that encloses the power
conductors significantly reduces the geoelectric field induced into the conductors themselves, while they remain
a path for GIC. Solid dielectric cables that are not enclosed by a steel pipe will not experience a reduction in the
induced geoelectric field. A planning entity should account for special modeling situations, such as this, in the GIC
system model, if applicable.
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | July 2019
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Chapter 3 – Requirement R3
Requirement R3 allows a responsible entity the flexibility to determine the System steady state voltage criteria
for System steady state performance in Table 1: Steady State Planning GMD Event found in TPL-007-4. Steady
state voltage limits are an example of System steady state performance criteria.
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | July 2019
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Chapter 4 – Requirement R4
Distribution of benchmark GMD Vulnerability Assessment results provides a means for sharing relevant
information with other entities responsible for planning reliability. Results of GIC studies may affect neighboring
systems and should be considered by transmission planners.
The provision of information in Requirement R4, Part 4.3, shall be subject to the legal and regulatory obligations
for the disclosure of confidential and/or sensitive information.
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | July 2019
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Chapter 5 – Requirement R5
The maximum effective GIC value provided in Part 5.1 is used for the benchmark thermal impact assessment. Only
those transformers that experience an effective GIC value of 75 A or greater per phase require evaluation in
Requirement R6.
A Transmission Owner or Generator Owner that desires GIC(t) may request it from the planning entity. The
planning entity shall provide GIC(t) upon request once GIC has been calculated, but no later than 90 calendar days
after receipt of a request from the owner and after completion of Requirement R5, Part 5.1.
The provision of information in Requirement R5 shall be subject to the legal and regulatory obligations for the
disclosure of confidential and/or sensitive information.
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Chapter 6 – Requirement R6
ERO Enterprise-Endorsed Implementation Guidance for conducting the thermal impact assessment of a power
transformer is presented in the Transformer Thermal Impact Assessment White Paper, October 2016 [4].
Transformers are exempt from the benchmark thermal impact assessment requirement if the effective GIC value
for the transformer is less than 75 A per phase, as determined by a GIC analysis of the System. A documented
design specification exceeding this value is also a justifiable threshold criterion that exempts a transformer from
Requirement R6.
The benchmark threshold criteria and its associated transformer thermal impact must be evaluated on the basis
of effective GIC. Refer to the above referenced white paper and the Screening Criterion for Transformer Thermal
Impact Assessment White Paper, October 2017 [5], for additional information.
Approaches for conducting the thermal impact assessment of transformers for the benchmark event are
presented in the Transformer Thermal Impact Assessment White Paper, October 2017 [6].
Thermal impact assessments for the benchmark event are provided to the planning entity, as determined in
Requirement R1, so that identified issues can be included in the GMD Vulnerability Assessment (R4) and the
Corrective Action Plan (CAP; R7) as necessary.
The provision of information in Requirement R6, Part 6.4, shall be subject to the legal and regulatory obligations
for the disclosure of confidential and/or sensitive information.
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Chapter 7 – Requirement R7
The proposed requirement addresses directives in FERC Order No. 830 for establishing CAP deadlines associated
with GMD Vulnerability Assessments. In FERC Order No. 830, FERC directed revisions to TPL-007 such that CAPs
are developed within one year from the completion of GMD Vulnerability Assessments (P 101). Furthermore, FERC
directed NERC to establish implementation deadlines after the completion of the CAP as follows (P 102):
•
Two years for non-hardware mitigation; and
•
Four years for hardware mitigation.
Part 7.4 requires entities to submit to the ERO with a request for extension when implementation of planned
mitigation is not achievable within the deadlines established in Part 7.3. Examples of situations beyond the control
of the responsible entity include, but are not limited to:
•
Delays resulting from regulatory/legal processes, such as permitting;
•
Delays resulting from stakeholder processes required by tariff;
•
Delays resulting from equipment lead times; or
•
Delays resulting from the inability to acquire necessary Right-of-Way.
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | July 2019
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Chapter 8 – Supplemental GMD Vulnerability Assessment
The exact spatial extent, local time of occurrence, latitude boundary, number of occurrences during a GMD event,
and geoelectric field characteristics (amplitude and orientation) inside/outside the local enhancement cannot yet
be scientifically determined.
TPL-007-4 provides flexibility for Transmission Planners to determine how to apply the supplemental GMD event
to the planning area. This guide provides acceptable approaches and boundaries to apply the supplemental event.
1. Spatial extent:
a. The local geoelectric field enhancement should not be smaller than 100 km (West-East) by 100 km
(North-South).
b. The transmission planner may perform a sensitivity analysis varying the spatial extent. Note that the
100 km North-South spatial extent is better understood than the West-East length, which could be
500 km or more.
c. The peak geoelectric field for the supplemental GMD event (12 V/km scaled to the planning area) can
be applied over the entire planning area. Note that this implies studying a GMD event rarer than 1-in100 years.
2. Geoelectric field inside the local enhancement:
a. Amplitude: 12 V/km (scaled to the planning area).
b. Orientation: at a minimum, a West-East 1 orientation should be considered when applying the
supplemental event.
c. The transmission planner may perform a sensitivity analysis varying the orientation of the geoelectric
field.
3. Geoelectric field outside 2 the local enhancement:
a. Amplitude: should not be smaller than 1.2 V/km (scaled to the planning area); i.e., an order of
magnitude smaller than the field inside the local enhancement.
b. Orientation: at a minimum, a West-East 3 orientation should be considered when applying the
supplemental event.
c. The transmission planner may perform a sensitivity analysis varying the orientation of the geoelectric
field.
4. Position of the local enhancement:
a. The transmission planner may use engineering judgement to position the local enhancement on
critical areas of their system. For example, the benchmark vulnerability assessment may identify areas
with depressed voltages, lack of dynamic reactive reserves, large GIC flows through transformers, etc.
The transmission planner may also consider the impact to critical infrastructure or other externalities.
b. The transmission planner may systematically move the position of the local enhancement throughout
the entire planning area.
1
West-East geomagnetic reference.
The characteristics of the geoelectric field outside the local enhancement, for example amplitude, orientation, spatial extent, are still
being reviewed by the scientific community.
3
West-East geomagnetic reference.
2
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | July 2019
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Chapter 8 – Supplemental GMD Vulnerability Assessment
c. Despite the fact that local enhancements appear to be limited to auroral regions, geomagnetic
latitude should not be used as a criterion to position the local enhancement.
The schematic in Figure 1 illustrates the boundaries to apply the supplemental GMD event. The local enhancement
should not be smaller than 100 km by 100 km, the geoelectric field inside the local enhancement is 12 V/km (scaled
to the planning area) with West-East orientation, and the geoelectric field outside the local enhancement could
be as low as 1.2 V/km (scaled to the planning area) with a West-East orientation.
100 km
1.2 V/km, West-East
(scaled to planning area)
100 km
Local Enhancement
12 V/km, West-East
(scaled to planning area)
Figure 1. Schematic showing the boundaries to apply the supplemental event.
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | July 2019
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Chapter 9 – Requirement R8
Distribution of supplemental GMD Vulnerability Assessment results provides a means for sharing relevant
information with other entities responsible for planning reliability. Results of GIC studies may affect neighboring
systems and should be considered by transmission planners.
The provision of information in Requirement R8, Part 8.3, shall be subject to the legal and regulatory obligations
for the disclosure of confidential and/or sensitive information.
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Chapter 10 – Requirement R9
The maximum effective GIC value provided in Part 9.1 is used for the supplemental thermal impact assessment.
Only those transformers that experience an effective GIC value of 85 A or greater per phase require evaluation in
Requirement R10.
A Transmission Owner or Generator Owner that desires GIC(t) may request it from the planning entity. The
planning entity shall provide GIC(t) upon request once GIC has been calculated, but no later than 90 calendar days
after receipt of a request from the owner and after completion of Requirement R9, Part 9.1.
The provision of information in Requirement R9 shall be subject to the legal and regulatory obligations for the
disclosure of confidential and/or sensitive information.
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Chapter 11 – Requirement R10
ERO Enterprise-Endorsed Implementation Guidance for conducting the thermal impact assessment of a power
transformer is presented in the Transformer Thermal Impact Assessment White Paper, October 2016 [4].
Transformers are exempt from the supplemental thermal impact assessment requirement if the effective GIC
value for the transformer is less than 85 A per phase, as determined by a GIC analysis of the System. A documented
design specification exceeding this value is also a justifiable threshold criterion that exempts a transformer from
Requirement R10.
The supplemental threshold criteria and its associated transformer thermal impact must be evaluated on the basis
of effective GIC. Refer to the above referenced white paper and the Screening Criterion for Transformer Thermal
Impact Assessment White Paper, October 2017 [5] for additional information.
Approaches for conducting the thermal impact assessment of transformers for the supplemental event are
presented in the Transformer Thermal Impact Assessment White Paper, October 2017 [6].
Thermal impact assessments for the supplemental event are provided to the planning entity, as determined in
Requirement R1, so that identified issues can be included in the GMD Vulnerability Assessment (R8) and the
Corrective Action Plan (R11) as necessary.
The provision of information in Requirement R10, Part 10.4, shall be subject to the legal and regulatory obligations
for the disclosure of confidential and/or sensitive information.
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Chapter 12 – Requirement R11
The requirement addresses directives in FERC Order No. 851 to develop and submit modifications to Reliability
Standard TPL-007-2 (and TPL-007-3) to require corrective action plans for assessed supplemental GMD event
vulnerabilities. This requirement is analogous to Requirement R7, such that CAPs are developed within one year
from the completion of supplemental GMD Vulnerability Assessments and establishment of implementation
deadlines after the completion of the CAP as follows:
•
Two years for non-hardware mitigation; and
•
Four years for hardware mitigation.
Part 11.4 requires entities to submit to the ERO with a request for extension when implementation of planned
mitigation is not achievable within the deadlines established in Part 11.3. Examples of situations beyond the
control of the responsible entity include, but are not limited to:
•
Delays resulting from regulatory/legal processes, such as permitting;
•
Delays resulting from stakeholder processes required by tariff;
•
Delays resulting from equipment lead times; or
•
Delays resulting from the inability to acquire necessary Right-of-Way.
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Chapter 13 – Requirement R12
Responsible entities consider the following in developing a process for obtaining GIC monitor data:
•
Monitor locations. An entity’s operating process may be constrained by location of existing GIC monitors.
However, when planning for additional GIC monitoring installations consider that data from monitors
located in areas found to have high GIC based on system studies may provide more useful information for
validation and situational awareness purposes. Conversely, data from GIC monitors that are located in the
vicinity of transportation systems using direct current (for example subways or light rail) may be
unreliable.
•
Monitor specifications. Capabilities of Hall effect transducers, existing and planned, should be considered
in the operating process. When planning new GIC monitor installations, consider monitor data range (for
example -500 A through + 500 A) and ambient temperature ratings consistent with temperatures in the
region in which the monitor will be installed.
•
Sampling Interval. An entity’s operating process may be constrained by capabilities of existing GIC
monitors. However, when possible specify data sampling during periods of interest at a rate of 10 seconds
or faster.
•
Collection Periods. The process should specify when the entity expects GIC data to be collected. For
example, collection could be required during periods where the Kp index is above a threshold, or when
GIC values are above a threshold. Determining when to discontinue collecting GIC data should also be
specified to maintain consistency in data collection.
•
Data format. Specify time and value formats. For example, Greenwich Mean Time (GMT) (MM/DD/YYYY
HH:MM:SS) and GIC Value (Ampere). Positive (+) and negative (-) signs indicate direction of GIC flow.
Positive reference is flow from ground into transformer neutral. Time fields should indicate the sampled
time rather than system or SCADA time if supported by the GIC monitor system.
•
Data retention. The entity’s process should specify data retention periods, for example one (1) year. Data
retention periods should be adequately long to support availability for the entity's model validation
process and external reporting requirements, if any.
•
Additional information. The entity’s process should specify collection of other information necessary for
making the data useful, for example monitor location and type of neutral connection (for example threephase or single-phase).
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | July 2019
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Chapter 14 – Requirement R13
Magnetometers measure changes in the earth’s magnetic field. Entities should obtain data from the nearest
accessible magnetometer. Sources of magnetometer data include:
•
Observatories such as those operated by U.S. Geological Survey (USGS) and Natural Resources Canada
(NRCan), see figure below for locations [7];
•
Research institutions and academic universities; and
•
Entities with installed magnetometers.
Entities that choose to install magnetometers should consider equipment specifications and data format protocols
contained in the INTERMAGNET Technical Reference Manual, Version 4.6, 2012 [8].
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | July 2019
15
References
1. FERC Order No. 779,
https://www.nerc.com/FilingsOrders/us/FERCOrdersRules/Order779_GMD_RM12-22_20130516.pdf
2. FERC Order No. 830,
https://www.nerc.com/filingsorders/us/FERCOrdersRules/E-4.pdf
3. FERC Order No. 851,
https://www.nerc.com/FilingsOrders/us/FERCOrdersRules/E-3_Order%20No%20851.pdf
4. Transformer Thermal Impact Assessment White Paper, ERO Enterprise-Endorsed Implementation
Guidance, NERC, Atlanta, GA, October 28,
2016, https://www.nerc.com/pa/comp/guidance/EROEndorsedImplementationGuidance/TPL-0071_Transformer_Thermal_Impact_Assessment_White_Paper.pdf
5. Screening Criterion for Transformer Thermal Impact Assessment White Paper, NERC, Atlanta, GA,
October
2017, https://www.nerc.com/pa/Stand/Project201303GeomagneticDisturbanceMitigation/Screening_Cr
iterion_Clean_2017_October_Clean.pdf
6. Transformer Thermal Impact Assessment White Paper, NERC, Atlanta, GA, October
2017, https://www.nerc.com/pa/Stand/Project201303GeomagneticDisturbanceMitigation/Thermal_Im
pact_Assessment_2017_October_Clean.pdf
7. International Real-Time Magnetic Observatory Network,
http://www.intermagnet.org/index-eng.php
8. INTERMAGNET Technical Reference Manual, Version 4.6,
2012, http://www.intermagnet.org/publications/intermag_4-6.pdf
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | July 2019
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Violation Risk Factor and Violation Severity Level Justification
Project 2019-01 Modifications to TPL-007-3
This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in TPL-007-4. Each requirement is assigned a VRF and a VSL. These elements support the determination of
an initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as defined in
the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the following NERC criteria and FERC Guidelines when
developing the VRFs and VSLs for the requirements.
NERC Criteria for Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that
is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.
FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report
FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•
Emergency operations
•
Vegetation management
•
Operator personnel training
•
Protection systems and their coordination
•
Operating tools and backup facilities
•
Reactive power and voltage control
•
System modeling and data exchange
•
Communication protocol and facilities
•
Requirements to determine equipment ratings
•
Synchronized data recorders
•
Clearer criteria for operationally critical facilities
•
Appropriate use of transmission loading relief.
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | July 2019
2
Guideline (2) – Consistency within a Reliability Standard
FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.
Guideline (3) – Consistency among Reliability Standards
FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.
Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.
Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.
VRF and VSL Justifications
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NERC Criteria for Violation Severity Levels
VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and
may have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL
Moderate VSL
The performance or product
measured almost meets the full
intent of the requirement.
The performance or product
measured meets the majority of
the intent of the requirement.
High VSL
The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.
Severe VSL
The performance or product
measured does not
substantively meet the intent of
the requirement.
FERC Order of Violation Severity Levels
The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance
Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.
Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
VRF and VSL Justifications
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Guideline (4) – Violation Severity Level Assignment Should Be Based on A Single Violation, Not on A Cumulative Number of
Violations
Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | July 2019
5
VRF Justification for TPL-007-4, Requirement R1
The VRF did not change from the previously FERC-approved TPL-007-3 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R1
The VSL did not change from the previously FERC-approved TPL-007-3 Reliability Standard.
VRF Justification for TPL-007-4, Requirement R2
The VRF did not change from the previously FERC-approved TPL-007-3 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R2
The VSL did not change from the previously FERC-approved TPL-007-3 Reliability Standard.
VRF Justification for TPL-007-4, Requirement R3
The VRF did not change from the previously FERC-approved TPL-007-3 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R3
The VSL did not change from the previously FERC-approved TPL-007-3 Reliability Standard.
VRF Justification for TPL-007-4, Requirement R4
The VRF did not change from the previously FERC-approved TPL-007-3 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R4
The VSL did not change from the previously FERC-approved TPL-007-3 Reliability Standard.
VRF Justification for TPL-007-4, Requirement R5
The VRF did not change from the previously FERC-approved TPL-007-3 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R5
The VSL did not change from the previously FERC-approved TPL-007-3 Reliability Standard.
VRF Justification for TPL-007-4, Requirement R6
The VRF did not change from the previously FERC-approved TPL-007-3 Reliability Standard.
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | July 2019
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VSL Justification for TPL-007-4, Requirement R6
The VSL did not change from the previously FERC-approved TPL-007-3 Reliability Standard.
VRF Justification for TPL-007-4, Requirement R7
The VRF did not change from the previously FERC-approved TPL-007-3 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R7
The VSL did not substantively change from the previously FERC-approved TPL-007-3 Reliability Standard. In the Severe VSL, the word “have”
was replaced with “develop” to more closely reflect the language of the Requirement.
VRF Justification for TPL-007-4, Requirement R8
The VRF did not change from the previously FERC-approved TPL-007-3 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R8
The justification is provided on the following pages.
VRF Justification for TPL-007-4, Requirement R9
The VRF did not change from the previously FERC-approved TPL-007-3 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R9
The VSL did not change from the previously FERC-approved TPL-007-3 Reliability Standard.
VRF Justification for TPL-007-4, Requirement R10
The VRF did not change from the previously FERC-approved TPL-007-3 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R10
The VSL did not change from the previously FERC-approved TPL-007-3 Reliability Standard.
VRF Justification for TPL-007-4, Requirement R11
The justification is provided on the following pages.
VSL Justification for TPL-007-4, Requirement R11
The justification is provided on the following pages.
VRF and VSL Justifications
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VRF Justification for TPL-007-4, Requirement R12
Requirement R12 was previously Requirement R11 in TPL-007-3. The VRF did not change from the previously FERC-approved TPL-007-3
Reliability Standard.
VSL Justification for TPL-007-4, Requirement R12
Requirement R12 was previously Requirement R11 in TPL-007-3. The VSL did not change from the previously FERC-approved TPL-007-3
Reliability Standard.
VRF Justification for TPL-007-4, Requirement R13
Requirement R13 was previously Requirement R12 in TPL-007-3. The VRF did not change from the previously FERC-approved TPL-007-3
Reliability Standard.
VSL Justification for TPL-007-4, Requirement R13
Requirement R13 was previously Requirement R12 in TPL-007-3. The VSL did not change from the previously FERC-approved TPL-007-3
Reliability Standard.
VRF and VSL Justifications
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VSLs for TPL-007-4, Requirement R8
Lower
Moderate
High
The responsible entity
completed a supplemental GMD
Vulnerability Assessment, but it
was more than 60 calendar
months and less than or equal
to 64 calendar months since the
last supplemental GMD
Vulnerability Assessment.
The responsible entity’s
completed supplemental GMD
Vulnerability Assessment failed
to satisfy one of elements listed
in Requirement R8, Parts 8.1
through 8.3;
OR
The responsible entity’s
completed supplemental GMD
Vulnerability Assessment failed
to satisfy two of the elements
listed in Requirement R8, Parts
8.1 through 8.3;
OR
The responsible entity
completed a supplemental GMD
Vulnerability Assessment, but it
was more than 64 calendar
months and less than or equal
to 68 calendar months since the
last supplemental GMD
Vulnerability Assessment.
The responsible entity
completed a supplemental GMD
Vulnerability Assessment, but it
was more than 68 calendar
months and less than or equal
to 72 calendar months since the
last supplemental GMD
Vulnerability Assessment.
Severe
The responsible entity’s
completed supplemental GMD
Vulnerability Assessment failed
to satisfy three of the elements
listed in Requirement R8, Parts
8.1 through 8.3;
OR
The responsible entity
completed a supplemental GMD
Vulnerability Assessment, but it
was more than 72 calendar
months since the last
supplemental GMD Vulnerability
Assessment;
OR
The responsible entity does not
have a completed supplemental
GMD Vulnerability Assessment.
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | July 2019
9
VSL Justifications for TPL-007-4, Requirement R8
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency
in the Determination of
Penalties
The proposed VSLs retain the VSLs from FERC-approved TPL-007-3 with the exception of removing one
part of the lower VSL to reflect the removal of subpart 8.3 in TPL-007-3. As a result, the proposed VSLs do
not lower the current level of compliance.
The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting
uniformity and consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | July 2019
10
FERC VSL G4
Each VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | July 2019
11
VSLs for TPL-007-4, Requirement R11
Lower
The responsible entity’s
Corrective Action Plan failed to
comply with one of the
elements in Requirement R11,
Parts 11.1 through 11.5.
Moderate
The responsible entity’s
Corrective Action Plan failed to
comply with two of the
elements in Requirement R11,
Parts 11.1 through 11.5.
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | July 2019
High
The responsible entity’s
Corrective Action Plan failed to
comply with three of the
elements in Requirement R11,
Parts 11.1 through 11.5.
Severe
The responsible entity’s
Corrective Action Plan failed to
comply with four or more of the
elements in Requirement R11,
Parts 11.1 through 11.5;
OR
The responsible entity did not
develop a Corrective Action Plan
as required by Requirement
R11.
12
VSL Justifications for TPL-007-4, Requirement R11
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency
in the Determination of
Penalties
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of
lowering the level of compliance. Further, the VSLs are consistent with those assigned for Requirement R7,
pertaining to Corrective Action Plans for benchmark GMD Vulnerability Assessments.
The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting
uniformity and consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | July 2019
13
VSL Justifications for TPL-007-4, Requirement R11
FERC VSL G4
Each VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
VRF Justifications for TPL-007-4, Requirement R11
Proposed VRF
Lower
NERC VRF Discussion
A VRF of High is being proposed for this requirement.
FERC VRF G1 Discussion
N/A
Guideline 1- Consistency
with Blackout Report
FERC VRF G2 Discussion
Guideline 2- Consistency
within a Reliability Standard
FERC VRF G3 Discussion
Guideline 3- Consistency
among Reliability Standards
FERC VRF G4 Discussion
Guideline 4- Consistency
with NERC Definitions of
VRFs
The proposed VRF is consistent among other FERC approved VRFs within the standard, specifically
Requirement R7 pertaining to Corrective Action Plans for benchmark GMD Vulnerability Assessments.
A VRF of High is consistent with Reliability Standard TPL‐001‐4 Requirement R2 which requires
Transmission Planners and Planning Coordinators to include a Corrective Action Plan that addresses
identified performance issues in the annual Planning Assessment.
The VRF of High is consistent with the NERC VRF Definition. Failure to develop a Corrective Action Plan
that addresses issues identified in a supplemental GMD Vulnerability Assessment could place the Bulk
Electric System at an unacceptable risk of instability, separation, or cascading failures.
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | July 2019
14
VRF Justifications for TPL-007-4, Requirement R11
Proposed VRF
Lower
FERC VRF G5 Discussion
This requirement does not co‐mingle a higher‐risk reliability objective with a lesser‐ risk reliability
objective.
Guideline 5- Treatment of
Requirements that Comingle More than One
Obligation
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | July 2019
15
Consideration of Issues and Directives
Project 2019-01 Modifications to TPL-007-3
Project 2019-01 Modifications to TPL-007-3
Issue or Directive
Source
Modify the provision in Reliability Standard TPL-007-2,
Requirement R7.4 that allows applicable entities to
exceed deadlines for completing corrective action plan
tasks when “situations beyond the control of the
responsible entity [arise]”, by requiring that NERC and
the Regional Entities, as appropriate, consider requests
for extension of time on a case-by-case basis. Under
this option, responsible entities seeking an extension
would submit the information required by
Requirement R7.4 to NERC and the Regional Entities for
their consideration of the request.
FERC Order
No. 851, P 5
and P 50
Consideration of Issue or Directive
The SDT proposed the modified language in Requirement R7.3
and R7.4 to require time extensions for completing CAPs be
submitted to the ERO for approval. The proposed modified
language reads as follows:
7.3. Include a timetable, subject to revision by the responsible
entity ERO approval for any extension sought under in Part 7.4,
for implementing the selected actions from Part 7.1. The
timetable shall:
7.3.1. Specify implementation of non-hardware
mitigation, if any, within two years of development
of the CAP; and
7.3.2. Specify implementation of hardware mitigation, if
any, within four years of development of the CAP.
7.4. Be submitted to the ERO with a request for extension
revised if situations beyond the control of the responsible entity
is unable to determined in Requirement R1 prevent
implementation of the CAP within the timetable for
implementation provided in Part 7.3. The submitted revised CAP
Project 2019-01 Modifications to TPL-007-3
Issue or Directive
Source
Consideration of Issue or Directive
shall document the following, and be updated at least once
every 12 calendar months until implemented:
7.4.1 Circumstances causing the delay for fully or
partially implementing the selected actions in Part
7.1 and how those circumstances are beyond the
control of each responsible entity;
7.4.2 Description of the original CAP, and any previous
changes to the CAP, with the associated
timetable(s) for implementing the selected actions
in Part 7.1; and
7.4.2 Revisions to the selected actions in Part 7.1, if any,
including utilization of Operating Procedures, if
applicable;, and
7.4.3 the uUpdated timetable for implementing the
selected actions in Part 7.1.
Submit modifications to Reliability Standard TPL-007-2
to require corrective action plans for assessed
supplemental GMD event vulnerabilities.
Consideration of Issues and Directives
Project 2019-01 Modifications to TPL-007 | July 2019
FERC Order
No. 851, P 4
and P 39
The SDT drafted TPL-007-4 Requirement R11 to address
require CAPs for supplemental GMD vulnerabilities and to
require extensions to these plans to be approved by NERC
and the Regional Entities, as appropriate, in situations beyond
the control of the responsible entity. This language is the
same as the modified Requirement R7 which addresses CAPs
for the benchmark GMD vulnerability assessment.
Requirement R8 was also modified to remove the original
R8.3 which stated “an evaluation of possible actions designed
2
Project 2019-01 Modifications to TPL-007-3
Issue or Directive
Source
Consideration of Issue or Directive
to reduce the likelihood or mitigate the consequences and
adverse impacts of the event(s) shall be conducted”
Consideration of Issues and Directives
Project 2019-01 Modifications to TPL-007 | July 2019
3
DRAFT TPL-007-4
CAP Extension
Request
Review Process
RELIABILITY | RESILIENCE | SECURITY
NERC | Report Title | Report Date
I
Table of Contents
Introduction ............................................................................................................................................................. iii
Background .......................................................................................................................................................... iii
Process Overview ......................................................................................................................................................1
Step 1 – Registered Entity Submittal ...................................................................................................................1
Step 2 – ERO Enterprise Review..........................................................................................................................1
Step 3 – Registered Entity Notification ...............................................................................................................1
Appendix A : Entity Submittal Template ................................................................................................................2
NERC | DRAFT TPL-007-4 CAP Extension Request Review Process | August 2019
ii
Introduction
Background
This Electric Reliability Organization (ERO) Enterprise1 TPL-007-4 Corrective Action Plan (CAP) Extension Review
Process document addresses how ERO Enterprise Compliance Monitoring and Enforcement staff (CMEP staff) will
jointly review requests for extensions to Corrective Action Plans (CAPs) developed under TPL-007-4 to ensure a
timely, structured and consistent approach to CAP extension request submittals and processing.
NERC Compliance Assurance will maintain this document under existing ERO Enterprise processes. This document
will be reviewed and updated by NERC Compliance Assurance, as needed.
1
The ERO Enterprise is comprised of NERC and the Regional Entities.
NERC | DRAFT TPL-007-4 CAP Extension Request Review Process | August 2019
iii
Process Overview
If a registered entity (entity) has determined that a Corrective Action Plan (CAP) developed in accordance with
TPL-007-4 R7 or R11 cannot be met in the timetable provided per Part 7.3 or 11.3 due to situations beyond the control
of the responsible entity, then the entity will submit a extension request to the ERO Enterprise for approval prior to
the original required CAP completion date.
The steps outlined here should be followed to ensure a timely, structured and consistent approach to extension
request submittals and processing.
Step 1 – Registered Entity Submittal
If a registered entity (entity) determines that it cannot meet the required timetable for completing a CAP, the entity
will contact their Compliance Enforcement Authority (CEA) to coordinate submittal of an extension request. The
entity should submit the request to their CEA using the template provided in Appendix A: Entity Submittal Template
or through an alternate method designated by the CEA that includes the same information.
Entities are encouraged to submit the extension request as soon as they are aware they will not meet the CAP
completion date to allow the ERO Enterprise time to approve the extension request before the original required
completion date.
All CAP extension requests must be approved by the ERO Enterprise prior to original required CAP completion date.
Step 2 – ERO Enterprise Review
The CEA will ensure that all information detailed in TPL-007-4 Part 7.4 or 11.4 and requested in the Entity Submittal
Template is provided in the entity’s extension request submittal. The CEA will work with the entity to provide any
missing information.
The CEA will notify NERC of the extension request submittal. The CEA and NERC will then perform a joint review of
(1) the situation(s) beyond the control of the entity preventing implementation of the CAP within the identified
timetable; and (2) the revisions to the CAP and updated timetable for implementing the selected actions. Any
additional information requested by the ERO Enterprise to support the extension request review will be coordinated
by the CEA.
The Standard language states that an entity will submit an extension request for a full or partial delay in the
implementation of the CAP within the timetable provided in TPL-007-4 Part 7.3 or 11.3. The CEA and NERC will
determine whether to approve the extension request based on the specific facts and circumstances provided as to
how the situations causing the delay in completing the CAP are beyond the control of the entity.
Step 3 – Registered Entity Notification
The CEA will communicate the ERO Enterprise approval or denial of the extension request to the entity along with
the rationale for the determination.
NERC | DRAFT TPL-007-4 CAP Extension Request Review Process | August 2019
1
Appendix A: Entity Submittal Template
[Will be formatted into a form for submission that includes the following information]
Entity name:
NCR#:
Primary entity contact name and information:
Coordinated Oversight Group # (if applicable):
Regional Entities impacted (for MRREs only):
Start date of CAP:
Original completion date of CAP:
Description of system deficiencies identified and selected actions to achieve required System performance per TPL007-4 Part 7.1:
Circumstances causing the delay for fully or partially implementing the selected actions:
Description of revisions to the selected actions, if applicable:
New proposed completion date of CAP:
NERC | DRAFT TPL-007-4 CAP Extension Request Review Process | August 2019
2
DRAFT Reliability Standard Audit Worksheet1
TPL-007-4 – Transmission System Planned Performance for Geomagnetic
Disturbance Events
This section to be completed by the Compliance Enforcement Authority.
Audit ID:
Registered Entity:
NCR Number:
Compliance Enforcement Authority:
Compliance Assessment Date(s) 2:
Compliance Monitoring Method:
Names of Auditors:
Applicability of Requirements
BA DP GO GOP PA/PC
X3
R1
X3
R2
X3
R3
X3
R4
X3
R5
X5
R6
X3
R7
X3
R8
Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
Registered name of entity being audited
NCRnnnnn
Region or NERC performing audit
Month DD, YYYY, to Month DD, YYYY
[On-site Audit | Off-site Audit | Spot Check]
Supplied by CEA
RC
RP
RSG
TO
TOP
TP
X
4
TSP
X4
X4
X4
X4
X6
X4
X4
1 NERC developed this Reliability Standard Audit Worksheet (RSAW) language in order to facilitate NERC’s and the Regional Entities’ assessment of a registered
entity’s compliance with this Reliability Standard. The NERC RSAW language is written to specific versions of each NERC Reliability Standard. Entities using this RSAW
should choose the version of the RSAW applicable to the Reliability Standard being assessed. While the information included in this RSAW provides some of the
methodology that NERC has elected to use to assess compliance with the requirements of the Reliability Standard, this document should not be treated as a
substitute for the Reliability Standard or viewed as additional Reliability Standard requirements. In all cases, the Regional Entity should rely on the language
contained in the Reliability Standard itself, and not on the language contained in this RSAW, to determine compliance with the Reliability Standard. NERC’s Reliability
Standards can be found on NERC’s website. Additionally, NERC Reliability Standards are updated frequently, and this RSAW may not necessarily be updated with the
same frequency. Therefore, it is imperative that entities treat this RSAW as a reference document only, and not as a substitute or replacement for the Reliability
Standard. It is the responsibility of the registered entity to verify its compliance with the latest approved version of the Reliability Standards, by the applicable
governmental authority, relevant to its registration status.
The NERC RSAW language contained within this document provides a non-exclusive list, for informational purposes only, of examples of the types of evidence a
registered entity may produce or may be asked to produce to demonstrate compliance with the Reliability Standard. A registered entity’s adherence to the examples
contained within this RSAW does not necessarily constitute compliance with the applicable Reliability Standard, and NERC and the Regional Entity using this RSAW
reserves the right to request additional evidence from the registered entity that is not included in this RSAW. Additionally, this RSAW includes excerpts from FERC
Orders and other regulatory references. The FERC Order cites are provided for ease of reference only, and this document does not necessarily include all applicable
Order provisions. In the event of a discrepancy between FERC Orders, and the language included in this document, FERC Orders shall prevail.
Compliance Assessment Date(s): The date(s) the actual compliance assessment (on-site audit, off-site spot check, etc.) occurs.
Planning Coordinator with a planning area that includes a Facility or Facilities specified in 4.2.
4 Transmission Planner with a planning area that includes a Facility or Facilities specified in 4.2.
5 Generator Owner who owns a Facility or Facilities specified in 4.2.
6 Transmission Owner who owns a Facility or Facilities specified in 4.2.
2
3
DRAFT NERC Reliability Standard Audit Worksheet
R9
R10
R11
R12
R13
BA
DP
GO
GOP PA/PC
X3
X5
RC
RP
RSG
TO
TOP
TP
X4
TSP
X6
X3
X4
X3
X4
3
X4
X
Legend:
Text with blue background:
Text entry area with Green background:
Text entry area with white background:
Fixed text – do not edit
Entity-supplied information
Auditor-supplied information
Facilities
Facilities that include power transformer(s) with a high side, wye-grounded winding with terminal voltage
greater than 200 kV.
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-007-4_2019_v1 Revision Date: NovemberOctoberAugust, 2019 RSAW Template: RSAW2014R1.2
2
DRAFT NERC Reliability Standard Audit Worksheet
Findings
(This section to be completed by the Compliance Enforcement Authority)
Req.
Finding
Summary and Documentation
R1
R2
R3
R4
R5
R6
R7
R8
R9
R10
R11
R12
R13
Req.
Areas of Concern
Req.
Recommendations
Req.
Positive Observations
Functions Monitored
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-007-4_2019_v1 Revision Date: NovemberOctoberAugust, 2019 RSAW Template: RSAW2014R1.2
3
DRAFT NERC Reliability Standard Audit Worksheet
Subject Matter Experts
Identify the Subject Matter Expert(s) responsible for this Reliability Standard.
Registered Entity Response (Required; Insert additional rows if needed):
SME Name
Title
Organization
Requirement(s)
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-007-4_2019_v1 Revision Date: NovemberOctoberAugust, 2019 RSAW Template: RSAW2014R1.2
4
DRAFT NERC Reliability Standard Audit Worksheet
R1 Supporting Evidence and Documentation
Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall identify the individual
and joint responsibilities of the Planning Coordinator and Transmission Planner(s) in the Planning
Coordinator’s planning area for maintaining models, performing the study or studies needed to complete
benchmark and supplemental GMD Vulnerability Assessments, and implementing process(es) to obtain
GMD measurement data as specified in this standard.
M1. Each Planning Coordinator, in conjunction with its Transmission Planners, shall provide documentation
on roles and responsibilities, such as meeting minutes, agreements, copies of procedures or protocols in
effect between entities or between departments of a vertically integrated system, or email
correspondence that identifies an agreement has been reached on individual and joint responsibilities for
maintaining models, performing the study or studies needed to complete benchmark and supplemental
GMD Vulnerability Assessments, and implementing process(es) to obtain GMD measurement data in
accordance with Requirement R1.
Registered Entity Response (Required):
Compliance Narrative:
Provide a brief explanation, in your own words, of how you comply with this Requirement. References to
supplied evidence, including links to the appropriate page, are recommended.
Evidence Requested i:
Provide the following evidence, or other evidence to demonstrate compliance.
Documentation that identifies the roles and responsibilities of entities in the planning area for maintaining
models and performing the studies needed to complete benchmark and supplemental GMD Vulnerability
Assessments, and implementing process(es) to obtain GMD measurement data.
Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document
Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-007-4_2019_v1 Revision Date: NovemberOctoberAugust, 2019 RSAW Template: RSAW2014R1.2
5
DRAFT NERC Reliability Standard Audit Worksheet
Compliance Assessment Approach Specific to TPL-007-4, R1
This section to be completed by the Compliance Enforcement Authority
Confirm existence of documentation identifying the individual and joint responsibilities for the responsible
entities, defined in Requirement R1, for maintaining models, performing studies needed to complete
benchmark and supplemental GMD Vulnerability Assessments, and implementing process(es) to obtain
GMD measurement data.
Note to Auditor:
Auditor Notes:
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-007-4_2019_v1 Revision Date: NovemberOctoberAugust, 2019 RSAW Template: RSAW2014R1.2
6
DRAFT NERC Reliability Standard Audit Worksheet
R2 Supporting Evidence and Documentation
Each responsible entity, as determined in Requirement R1, shall maintain System models and GIC System
models of the responsible entity’s planning area for performing the study or studies needed to complete
benchmark and supplemental GMD Vulnerability Assessments.
M2. Each responsible entity, as determined in Requirement R1, shall have evidence in either electronic or
hard copy format that it is maintaining System models and GIC System models of the responsible entity’s
planning area for performing the study or studies needed to complete benchmark and supplemental
GMD Vulnerability Assessments.
Registered Entity Response (Required):
Compliance Narrative:
Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.
Evidence Requestedi:
Provide the following evidence, or other evidence to demonstrate compliance.
Evidence to demonstrate maintenance of System models and GIC System models for the responsible entity’s
planning area.
Documentation that identifies the roles and responsibilities of entities in the planning area for maintaining
models and performing the studies needed to complete benchmark and supplemental GMD Vulnerability
Assessments.
Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document
Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):
Compliance Assessment Approach Specific to TPL-007-4, R2
This section to be completed by the Compliance Enforcement Authority
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-007-4_2019_v1 Revision Date: NovemberOctoberAugust, 2019 RSAW Template: RSAW2014R1.2
7
DRAFT NERC Reliability Standard Audit Worksheet
Verify the responsible entity maintained System models and GIC System models for performing studies for
benchmark and supplemental GMD Vulnerability Assessments.
Note to Auditor:
Benchmark and supplemental GMD Vulnerability Assessments require a GIC System model, which is a direct
current representation of the System, to calculate GIC flow. In benchmark and supplemental GMD
Vulnerability Assessments, GIC simulations are used to determine transformer Reactive Power absorption and
transformer thermal response. See the Application Guide for Computing Geomagnetically-Induced Current in
the Bulk Power System for details on developing the GIC System model.
Auditor Notes:
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-007-4_2019_v1 Revision Date: NovemberOctoberAugust, 2019 RSAW Template: RSAW2014R1.2
8
DRAFT NERC Reliability Standard Audit Worksheet
R3 Supporting Evidence and Documentation
Each responsible entity, as determined in Requirement R1, shall have criteria for acceptable System
steady state voltage performance for its System during the GMD events described in Attachment 1.
M3. Each responsible entity, as determined in Requirement R1, shall have evidence, such as electronic or hard
copies of the criteria for acceptable System steady state voltage performance for its System in
accordance with Requirement R3.
Registered Entity Response (Required):
Compliance Narrative:
Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.
Evidence Requestedi:
Provide the following evidence, or other evidence to demonstrate compliance.
Criteria for acceptable System steady state voltage performance for the entity’s System during the GMD events
described in Attachment 1.
Documentation that identifies the roles and responsibilities of entities in the planning area for maintaining
models and performing the studies needed to complete GMD Vulnerability Assessments.
Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document
Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):
Compliance Assessment Approach Specific to TPL-007-4, R3
This section to be completed by the Compliance Enforcement Authority
Verify the responsible entity has criteria for acceptable System steady state voltage performance for its
System during the GMD events described in TPL-007 Attachment 1.
Note to Auditor:
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-007-4_2019_v1 Revision Date: NovemberOctoberAugust, 2019 RSAW Template: RSAW2014R1.2
9
DRAFT NERC Reliability Standard Audit Worksheet
Auditor Notes:
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-007-4_2019_v1 Revision Date: NovemberOctoberAugust, 2019 RSAW Template: RSAW2014R1.2
10
DRAFT NERC Reliability Standard Audit Worksheet
R4 Supporting Evidence and Documentation
Each responsible entity, as determined in Requirement R1, shall complete a benchmark GMD
Vulnerability Assessment of the Near-Term Transmission Planning Horizon at least once every 60
calendar months. This benchmark GMD Vulnerability Assessment shall use a study or studies based on
models identified in Requirement R2, document assumptions, and document summarized results of the
steady state analysis.
4.1. The study or studies shall include the following conditions:
4.1.1. System On-Peak Load for at least one year within the Near-Term Transmission Planning
Horizon; and
4.1.2. System Off-Peak Load for at least one year within the Near-Term Transmission Planning
Horizon.
4.2. The study or studies shall be conducted based on the benchmark GMD event described in
Attachment 1 to determine whether the System meets the performance requirements for the
steady state planning benchmark GMD event contained in Table 1.
4.3. The benchmark GMD Vulnerability Assessment shall be provided: (i) to the responsible entity’s
Reliability Coordinator, adjacent Planning Coordinators, and adjacent Transmission Planners within
90 calendar days of completion, and (ii) to any functional entity that submits a written request and
has a reliability-related need within 90 calendar days of receipt of such request or within 90
calendar days of completion of the benchmark GMD Vulnerability Assessment, whichever is later.
4.3.1. If a recipient of the benchmark GMD Vulnerability Assessment provides documented
comments on the results, the responsible entity shall provide a documented response to
that recipient within 90 calendar days of receipt of those comments.
M4. Each responsible entity, as determined in Requirement R1, shall have dated evidence such as electronic
or hard copies of its benchmark GMD Vulnerability Assessment meeting all of the requirements in
Requirement R4. Each responsible entity, as determined in Requirement R1, shall also provide evidence,
such as email records, web postings with an electronic notice of posting, or postal receipts showing
recipient and date, that it has distributed its benchmark GMD Vulnerability Assessment: (i) to the
responsible entity’s Reliability Coordinator, adjacent Planning Coordinators, and adjacent Transmission
Planners within 90 calendar days of completion, and (ii) to any functional entity that submits a written
request and has a reliability-related need within 90 calendar days of receipt of such request or within 90
calendar days of completion of the benchmark GMD Vulnerability Assessment, whichever is later, as
specified in Requirement R4. Each responsible entity, as determined in Requirement R1, shall also
provide evidence, such as email notices or postal receipts showing recipient and date, that it has
provided a documented response to comments received on its benchmark GMD Vulnerability
Assessment within 90 calendar days of receipt of those comments in accordance with Requirement R4.
Registered Entity Response (Required):
Compliance Narrative:
Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-007-4_2019_v1 Revision Date: NovemberOctoberAugust, 2019 RSAW Template: RSAW2014R1.2
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DRAFT NERC Reliability Standard Audit Worksheet
evidence, including links to the appropriate page, are recommended.
Evidence Requestedi:
Provide the following evidence, or other evidence to demonstrate compliance.
Dated copies of the current and preceding benchmark GMD Vulnerability Assessments of Near-Term
Transmission Planning Horizon.
Evidence the study or studies include System On-Peak Load and System Off-Peak Load conditions for at least one
year within the Near-Term Transmission Planning Horizon.
Evidence the study or studies were conducted based on the benchmark GMD event described in Attachment 1
for the steady state planning benchmark GMD event to determine whether the System meets the performance
requirements for the steady state planning benchmark GMD event contained in Table 1.
Dated evidence that the responsible entity provided the benchmark GMD Vulnerability Assessment within 90
calendar days of completion to the responsible entity’s Reliability Coordinator, adjacent Planning Coordinators,
adjacent Transmission Planners.
Dated evidence that the responsible entity provided the benchmark GMD Vulnerability Assessment to any
functional entity that submits a written request and has a reliability-related need within 90 calendar days of
receipt of such request or within 90 calendar days of completion of the benchmark GMD Vulnerability
Assessment, whichever is later.
If a recipient of the benchmark GMD Vulnerability Assessment provided documented comments on the results,
dated evidence the responsible entity provided a documented response to that recipient within 90 calendar days
of receipt of those comments.
Documentation that identifies the roles and responsibilities of entities in the planning area for maintaining
models and performing the studies needed to complete GMD Vulnerability Assessments.
Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document
Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):
Compliance Assessment Approach Specific to TPL-007-4, R4
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-007-4_2019_v1 Revision Date: NovemberOctoberAugust, 2019 RSAW Template: RSAW2014R1.2
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This section to be completed by the Compliance Enforcement Authority
(R4) Verify the responsible entity completed the benchmark GMD Vulnerability Assessment of the NearTerm Transmission Planning Horizon at least once every 60-calendar months.
(R4) Verify the use of studies to complete the benchmark GMD Vulnerability Assessment based on
models evidenced in R2.
(R4) Verify the benchmark GMD Vulnerability Assessment documented assumptions and summarized
results of the steady state analysis.
(Part 4.1) Verify the study or studies include System On-Peak Load and System Off-Peak Load conditions
for at least one year within the Near-Term Transmission Planning Horizon.
(Part 4.2) Verify the study or studies were conducted based on the benchmark GMD event described in
Attachment 1 to determine whether the System meets the performance requirements for the steady
state planning benchmark GMD event contained in Table 1.
(Part 4.3) Verify the benchmark GMD Vulnerability Assessment was provided within 90 calendar days of
completion to the responsible entity’s Reliability Coordinator, adjacent Planning Coordinators, adjacent
Transmission Planners, and to any functional entity that submits a written request and has a reliabilityrelated need.
(Part 4.3) Verify the benchmark GMD Vulnerability Assessment was provided to any functional entity
that submits a written request and has a reliability-related need within 90 calendar days of receipt of
such request or within 90 calendar days of completion of the benchmark GMD Vulnerability Assessment,
whichever is later.
(Part 4.3.1) If a recipient of the benchmark GMD Vulnerability Assessment provided documented
comments on the results, verify the responsible entity provided a documented response to that
recipient within 90 calendar days of receipt of those comments.
Note to Auditor: Auditor should consider reviewing Requirement R4 in conjunction with Requirement R7,
since the development and review of Corrective Action Plans are corollaries to the benchmark GMD
Vulnerability Assessment.
Auditor Notes:
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-007-4_2019_v1 Revision Date: NovemberOctoberAugust, 2019 RSAW Template: RSAW2014R1.2
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DRAFT NERC Reliability Standard Audit Worksheet
R5 Supporting Evidence and Documentation
Each responsible entity, as determined in Requirement R1, shall provide GIC flow information to be used
for the benchmark thermal impact assessment of transformers specified in Requirement R6 to each
Transmission Owner and Generator Owner that owns an applicable Bulk Electric System (BES) power
transformer in the planning area. The GIC flow information shall include:
5.1. The maximum effective GIC value for the worst case geoelectric field orientation for the benchmark
GMD event described in Attachment 1. This value shall be provided to the Transmission Owner or
Generator Owner that owns each applicable BES power transformer in the planning area.
5.2. The effective GIC time series, GIC(t), calculated using the benchmark GMD event described in
Attachment 1 in response to a written request from the Transmission Owner or Generator Owner
that owns an applicable BES power transformer in the planning area. GIC(t) shall be provided within
90 calendar days of receipt of the written request and after determination of the maximum
effective GIC value in Part 5.1.
M5. Each responsible entity, as determined in Requirement R1, shall provide evidence, such as email records,
web postings with an electronic notice of posting, or postal receipts showing recipient and date, that it
has provided the maximum effective GIC values to the Transmission Owner and Generator Owner that
owns each applicable BES power transformer in the planning area as specified in Requirement R5, Part
5.1. Each responsible entity, as determined in Requirement R1, shall also provide evidence, such as email
records, web postings with an electronic notice of posting, or postal receipts showing recipient and date,
that it has provided GIC(t) in response to a written request from the Transmission Owner or Generator
Owner that owns an applicable BES power transformer in the planning area.
Registered Entity Response (Required):
Question: During the audit period, did the entity receive a written request for effective GIC time series, GIC(t),
from the Transmission Owner or Generator Owner that owns an applicable BES power transformer in the
planning area?
☐ Yes ☐ No
If Yes, provide a list of such requests.
[Note: A separate spreadsheet or other document may be used. If so, provide the document reference
below.]
Registered Entity Response (Required):
Compliance Narrative:
Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.
Evidence Requestedi:
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-007-4_2019_v1 Revision Date: NovemberOctoberAugust, 2019 RSAW Template: RSAW2014R1.2
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Provide the following evidence, or other evidence to demonstrate compliance.
A list of each Transmission Owner and Generator Owner in the planning area that owns an applicable BES power
transformer.
Evidence demonstrating the responsible entity provided the maximum effective GIC value for the worst case
geoelectric field orientation for the benchmark GMD event described in Attachment 1 to each Transmission
Owner and Generator Owner in the planning area that owns an applicable BES power transformer in the planning
area.
Evidence demonstrating the responsible entity, within 90 calendar days of receipt of the written request and
after determination of the maximum effective GIC value in Part 5.1, provided the effective GIC time series, GIC(t),
calculated using the benchmark GMD event described in Attachment 1 in response to a written request from
the Transmission Owner or Generator Owner that owns an applicable BES power transformer in the planning
area.
Documentation that identifies the roles and responsibilities of entities in the planning area for maintaining
models and performing the studies needed to complete GMD Vulnerability Assessments.
Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document
Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):
Compliance Assessment Approach Specific to TPL-007-4, R5
This section to be completed by the Compliance Enforcement Authority
(R5) Verify the responsible entity provided GIC flow information to each Transmission Owner and
Generator Owner that owns an applicable BES power transformer in the planning area.
(Part 5.1) Verify the GIC flow information provided by the responsible entity included the maximum
effective GIC value for the worst case geoelectric field orientation for the benchmark GMD event described
in Attachment 1.
(Part 5.2) For all, or a sample of, written requests from applicable Transmission Owner or Generation
Owners, verify the responsible entity provided the effective GIC time series, GIC(t), within 90 calendar days
of receipt of the written request and after determination of the maximum effective GIC value in Part 5.1.
Note to Auditor:
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-007-4_2019_v1 Revision Date: NovemberOctoberAugust, 2019 RSAW Template: RSAW2014R1.2
15
DRAFT NERC Reliability Standard Audit Worksheet
Auditor Notes:
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-007-4_2019_v1 Revision Date: NovemberOctoberAugust, 2019 RSAW Template: RSAW2014R1.2
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DRAFT NERC Reliability Standard Audit Worksheet
R6 Supporting Evidence and Documentation
Each Transmission Owner and Generator Owner shall conduct a benchmark thermal impact assessment
for its solely and jointly owned applicable BES power transformers where the maximum effective GIC
value provided in Requirement R5, Part 5.1, is 75 A per phase or greater. The benchmark thermal impact
assessment shall:
6.1. Be based on the effective GIC flow information provided in Requirement R5;
6.2. Document assumptions used in the analysis;
6.3. Describe suggested actions and supporting analysis to mitigate the impact of GICs, if any; and
6.4. Be performed and provided to the responsible entities, as determined in Requirement R1, within 24
calendar months of receiving GIC flow information specified in Requirement R5, Part 5.1.
M6. Each Transmission Owner and Generator Owner shall have evidence such as electronic or hard copies of
its benchmark thermal impact assessment for all of its solely and jointly owned applicable BES power
transformers where the maximum effective GIC value provided in Requirement R5, Part 5.1, is 75 A per
phase or greater, and shall have evidence such as email records, web postings with an electronic notice
of posting, or postal receipts showing recipient and date, that it has provided its thermal impact
assessment to the responsible entities as specified in Requirement R6.
Registered Entity Response (Required):
Compliance Narrative:
Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.
Evidence Requestedi:
Provide the following evidence, or other evidence to demonstrate compliance.
The GIC flow information provided by the Planning Coordinator or Transmission Planner in accordance with
Requirement R5.
Dated evidence demonstrating the completion of the benchmark thermal impact assessment for each of the
entity’s solely and jointly owned applicable BES power transformers where the maximum effective GIC value
provided in Requirement R5 Part 5.1 is 75 A per phase or greater.
Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-007-4_2019_v1 Revision Date: NovemberOctoberAugust, 2019 RSAW Template: RSAW2014R1.2
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DRAFT NERC Reliability Standard Audit Worksheet
Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):
Compliance Assessment Approach Specific to TPL-007-4, R6
This section to be completed by the Compliance Enforcement Authority
(R6) Verify the entity conducted a benchmark thermal impact assessment for each applicable BES
power transformer where the maximum effective GIC value provided in Requirement R5, Part 5.1, is 75
A per phase or greater.
Review thermal impact assessments for applicable BES power transformers and confirm the thermal
impact assessment meets the requirements identified in Requirement R6 Part 6.1 through Part 6.4.
(Part 6.1) Be based on the effective GIC flow information provided in Requirement R5.
(Part 6.2) Document assumptions used in the analysis.
(Part 6.3) Describe suggested actions and supporting analysis to mitigate the impact of GICs, if any.
(Part 6.4) Be performed and provided to the responsible entities as determined in Requirement R1
within 24 calendar months of receiving GIC flow information specified in Requirement R5, Part 5.1.
Note to Auditor:
Auditor Notes:
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-007-4_2019_v1 Revision Date: NovemberOctoberAugust, 2019 RSAW Template: RSAW2014R1.2
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R7 Supporting Evidence and Documentation
Each responsible entity, as determined in Requirement R1, that concludes through the benchmark GMD
Vulnerability Assessment conducted in Requirement R4 that their System does not meet the
performance requirements for the steady state planning benchmark GMD event contained in Table 1,
shall develop a Corrective Action Plan (CAP) addressing how the performance requirements will be met.
The CAP shall:
7.1. List System deficiencies and the associated actions needed to achieve required System
performance. Examples of such actions include:
•
Installation, modification, retirement, or removal of Transmission and generation Facilities and
any associated equipment.
•
Installation, modification, or removal of Protection Systems or Remedial Action Schemes.
•
Use of Operating Procedures, specifying how long they will be needed as part of the CAP.
•
Use of Demand-Side Management, new technologies, or other initiatives.
7.2. Be developed within one year of completion of the benchmark GMD Vulnerability Assessment.
7.3. Include a timetable, subject to ERO approval for any extension sought under Part 7.4, for
implementing the selected actions from Part 7.1. The timetable shall:
7.3.1. Specify implementation of non-hardware mitigation, if any, within two years of
development of the CAP; and
7.3.2. Specify implementation of hardware mitigation, if any, within four years of development of
the CAP.
7.4. Be submitted to the Compliance Enforcement Authority (CEA)ERO with a request for extension of
time if the responsible entity is unable to implement the CAP within the timetable provided in Part
7.3. The submitted CAP shall document the following:
7.4.1. Circumstances causing the delay for fully or partially implementing the selected actions in
Part 7.1 and how those circumstances are beyond the control of the responsible entity;
7.4.2. Revisions to the selected actions in Part 7.1, if any, including utilization of Operating
Procedures, if applicable; and
7.4.3. Updated timetable for implementing the selected actions in Part 7.1.
7.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent Planning Coordinator(s),
adjacent Transmission Planner(s), and functional entities referenced in the CAP within 90 calendar
days of development or revision, and (ii) to any functional entity that submits a written request and
has a reliability-related need within 90 calendar days of receipt of such request or within 90
calendar days of development or revision, whichever is later.
7.5.1. If a recipient of the CAP provides documented comments on the CAP, the responsible entity
shall provide a documented response to that recipient within 90 calendar days of receipt of
those comments.
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-007-4_2019_v1 Revision Date: NovemberOctoberAugust, 2019 RSAW Template: RSAW2014R1.2
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M7. Each responsible entity, as determined in Requirement R1, that concludes, through the benchmark GMD
Vulnerability Assessment conducted in Requirement R4, that the responsible entity’s System does not
meet the performance requirements for the steady state planning benchmark GMD event contained in
Table 1 shall have evidence such as dated electronic or hard copies of its CAP including timetable for
implementing selected actions, as specified in Requirement R7. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records or postal receipts showing recipient
and date, that it submitted a request for extension to the ERO if the responsible entity is unable to
implement the CAP within the timetable provided in Part 7.3. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records, web postings with an electronic
notice of posting, or postal receipts showing recipient and date, that it has distributed its CAP or relevant
information, if any, (i) to the responsible entity’s Reliability Coordinator, adjacent Planning
Coordinator(s), adjacent Transmission Planner(s), and functional entities referenced in the CAP within 90
calendar days of development or revision, and (ii) to any functional entity that submits a written request
and has a reliability-related need within 90 calendar days of receipt of such request or within 90 calendar
days of development or revision, whichever is later as specified in Requirement R7. Each responsible
entity, as determined in Requirement R1, shall also provide evidence, such as email notices or postal
receipts showing recipient and date, that it has provided a documented response to comments received
on its CAP within 90 calendar days of receipt of those comments, in accordance with Requirement R7.
Registered Entity Response (Required):
Question: Did the responsible entity conclude through the GMD Vulnerability Assessment conducted in
Requirement R4 that their System does not meet the performance requirements of Table 1? ☐ Yes ☐ No
If Yes, provide a dated list of CAPs developed to address how the performance requirements will be met.
[Note: A separate spreadsheet or other document may be used. If so, provide the document reference below.]
Registered Entity Response (Required):
Compliance Narrative:
Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.
Evidence Requestedi:
Provide the following evidence, or other evidence to demonstrate compliance.
Documentation that identifies the roles and responsibilities of entities in the planning area for maintaining
models and performing the studies needed to complete GMD Vulnerability Assessments.
Copy of the benchmark GMD Vulnerability Assessment conducted in Requirement R4
A list of System deficiencies identified through the GMD Vulnerability Assessment.
All dated CAPs associated with the System deficiencies, which identify the associated actions needed to achieve
required System performance.
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-007-4_2019_v1 Revision Date: NovemberOctoberAugust, 2019 RSAW Template: RSAW2014R1.2
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Evidence the CAP was submitted to the CEAERO with a request for extension of time if the responsible entity is
unable to implement the CAP within the timetable provided in Part 7.3.
Dated evidence that the CAP was provided, within 90 calendar days of development or revision, to the
responsible entity’s Reliability Coordinator, adjacent Planning Coordinator(s), adjacent Transmission Planner(s),
functional entities referenced in the CAP.
Dated evidence that the CAP was provided to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or within 90 calendar days of
development or revision, whichever is later.
If a recipient of the CAP provided documented comments on the CAP, evidence the responsible entity shall
provide a documented response to that recipient within 90 calendar days of receipt of those comments.
Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document
Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):
Compliance Assessment Approach Specific to TPL-007-4, R7
This section to be completed by the Compliance Enforcement Authority
(R7) Verify the entity developed a CAP addressing how the performance requirements will be met for the
steady state planning benchmark GMD event, if the entity concluded through the benchmark GMD
Vulnerability Assessment conducted in Requirement R4, that their System does not meet the performance
requirements of Table 1. Verify the CAP:
(Part 7.1) List system deficiencies and associated actions needed to achieve required System performance.
(Part 7.2) The CAP was developed within one year of completion of the benchmark GMD Vulnerability
Assessment.
(Part 7.3) The CAP includes a timetable.
(Part 7.3.1) A timetable specifying implementation of non-hardware mitigation, if any, within two years of
development of the CAP.
(Part 7.3.2) A timetable specifying implementation of hardware mitigation, if any, within four years of the
development of the CAP.
(Part 7.4) Verify the CAP was submitted to the CEAERO with a request for extension of time if the
responsible entity is unable to implement the CAP within the timetable provided in Part 7.3.
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
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(Part 7.4.1) Verify the submitted CAP documents circumstances causing the delay for fully or partially
implementing the selected actions in Part 7.1 and how those circumstances are beyond the control of each
responsible entity.
(Part 7.4.2) Verify the submitted CAP documents revisions to the selected actions in Part 7.1, if any,
including utilization of Operating Procedures if applicable.
(Part 7.4.3) Verify the submitted CAP documents an updated timetable for implementing the selected
actions in Part 7.1.
(Part 7.5) Verify the responsible entity provided the CAP, within 90 calendar days of development or
revision, to the responsible entity’s Reliability Coordinator, adjacent Planning Coordinator(s), adjacent
Transmission Planner(s), functional entities referenced in the CAP.
(Part 7.5) Verify the responsible entity provided the CAP to any functional entity that submits a written
request and has a reliability-related need within 90 calendar days of receipt of such request or within 90
calendar days of development or revision, whichever is later.
(Part 7.5.1) If a recipient of the CAP provided documented comments on the CAP, verify the responsible
entity provided a documented response to that recipient within 90 calendar days of receipt of those
comments.
Note to Auditor:
Auditor Notes:
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-007-4_2019_v1 Revision Date: NovemberOctoberAugust, 2019 RSAW Template: RSAW2014R1.2
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DRAFT NERC Reliability Standard Audit Worksheet
R8 Supporting Evidence and Documentation
Each responsible entity, as determined in Requirement R1, shall complete a supplemental GMD
Vulnerability Assessment of the Near-Term Transmission Planning Horizon at least once every 60
calendar months. This supplemental GMD Vulnerability Assessment shall use a study or studies based on
models identified in Requirement R2, document assumptions, and document summarized results of the
steady state analysis:
8.1. The study or studies shall include the following conditions:
8.1.1. System On-Peak Load for at least one year within the Near-Term Transmission Planning
Horizon; and
8.1.2. System Off-Peak Load for at least one year within the Near-Term Transmission Planning
Horizon.
8.2. The study or studies shall be conducted based on the supplemental GMD event described in
Attachment 1 to determine whether the System meets the performance requirements for the
steady state planning supplemental GMD event contained in Table 1.
8.3. The supplemental GMD Vulnerability Assessment shall be provided: (i) to the responsible entity’s
Reliability Coordinator, adjacent Planning Coordinators, adjacent Transmission Planners within 90
calendar days of completion, and (ii) to any functional entity that submits a written request and has
a reliability-related need within 90 calendar days of receipt of such request or within 90 calendar
days of completion of the supplemental GMD Vulnerability Assessment, whichever is later.
8.3.1. If a recipient of the supplemental GMD Vulnerability Assessment provides documented
comments on the results, the responsible entity shall provide a documented response to
that recipient within 90 calendar days of receipt of those comments.
M8. Each responsible entity, as determined in Requirement R1, shall have dated evidence such as electronic
or hard copies of its supplemental GMD Vulnerability Assessment meeting all of the requirements in
Requirement R8. Each responsible entity, as determined in Requirement R1, shall also provide evidence,
such as email records, web postings with an electronic notice of posting, or postal receipts showing
recipient and date, that it has distributed its supplemental GMD Vulnerability Assessment: (i) to the
responsible entity’s Reliability Coordinator, adjacent Planning Coordinators, adjacent Transmission
Planners within 90 calendar days of completion, and (ii) to any functional entity that submits a written
request and has a reliability-related need within 90 calendar days of receipt of such request or within 90
calendar days of completion of the supplemental GMD Vulnerability Assessment, whichever is later, as
specified in Requirement R8. Each responsible entity, as determined in Requirement R1, shall also
provide evidence, such as email notices or postal receipts showing recipient and date, that it has
provided a documented response to comments received on its supplemental GMD Vulnerability
Assessment within 90 calendar days of receipt of those comments in accordance with Requirement R8.
Registered Entity Response (Required):
Compliance Narrative:
Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-007-4_2019_v1 Revision Date: NovemberOctoberAugust, 2019 RSAW Template: RSAW2014R1.2
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Evidence Requestedi:
Provide the following evidence, or other evidence to demonstrate compliance.
Dated copies of the current and preceding supplemental GMD Vulnerability Assessments of Near-Term
Transmission Planning Horizon.
Evidence the study or studies include System On-Peak Load and System Off-Peak Load conditions for at least
one year within the Near-Term Transmission Planning Horizon.
Evidence the study or studies were conducted based on the supplemental GMD event described in Attachment
1 to determine whether the System meets the performance requirements for the steady state planning
supplemental GMD event in Table 1.
Dated evidence that the responsible entity provided the supplemental GMD Vulnerability Assessment within
90 calendar days of completion to the responsible entity’s Reliability Coordinator, adjacent Planning
Coordinators, adjacent Transmission Planners.
Dated evidence that the responsible entity provided the supplement GMD Vulnerability Assessment to any
functional entity that submits a written request and has a reliability-related need within 90 calendar days of
receipt of such request or within 90 calendar days of completion of the supplemental GMD Vulnerability
Assessment, whichever is later.
If a recipient of the supplemental GMD Vulnerability Assessment provided documented comments on the
results, dated evidence the responsible entity provided a documented response to that recipient within 90
calendar days of receipt of those comments.
Documentation that identifies the roles and responsibilities of entities in the planning area for maintaining
models and performing the studies needed to complete GMD Vulnerability Assessments.
Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document
Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):
Compliance Assessment Approach Specific to TPL-007-4, R8
This section to be completed by the Compliance Enforcement Authority
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Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
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(R8) Verify the responsible entity completed the supplemental GMD Vulnerability Assessment of the
Near-Term Transmission Planning Horizon at least once every 60-calendar months.
(R8) Verify the use of studies to complete the supplemental GMD Vulnerability Assessment based on
models evidenced in R2.
(R8) Verify the supplemental GMD Vulnerability Assessment documented assumptions and summarized
results of the steady state analysis.
(Part 8.1) Verify the study or studies include System On-Peak Load and System Off-Peak Load conditions
for at least one year within the Near-Term Transmission Planning Horizon.
(Part 8.2) Verify the study or studies were conducted based on the supplemental GMD event described
in Attachment 1 to determine whether the System meets the performance requirements in Table 1.
(Part 8.3) Verify the supplemental GMD Vulnerability Assessment was provided within 90 calendar days
of completion to the responsible entity’s Reliability Coordinator, adjacent Planning Coordinators,
adjacent Transmission Planners.
(Part 8.3) Verify the supplemental GMD Vulnerability Assessment was provided to any functional entity
that submits a written request and has a reliability-related need within 90 calendar days of receipt of
such request or within 90 calendar days of completion of the supplemental GMD Vulnerability
Assessment, whichever is later.
(Part 8.3.1) If a recipient of the supplemental GMD Vulnerability Assessment provided documented
comments on the results, verify the responsible entity provided a documented response to that
recipient within 90 calendar days of receipt of those comments.
Note to Auditor:
Auditor Notes:
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R9 Supporting Evidence and Documentation
Each responsible entity, as determined in Requirement R1, shall provide GIC flow information to be used
for the supplemental thermal impact assessment of transformers specified in Requirement R10 to each
Transmission Owner and Generator Owner that owns an applicable Bulk Electric System (BES) power
transformer in the planning area. The GIC flow information shall include:
9.1. The maximum effective GIC value for the worst case geoelectric field orientation for the
supplemental GMD event described in Attachment 1. This value shall be provided to the
Transmission Owner or Generator Owner that owns each applicable BES power transformer in the
planning area.
9.2. The effective GIC time series, GIC(t), calculated using the supplemental GMD event described in
Attachment 1 in response to a written request from the Transmission Owner or Generator Owner
that owns an applicable BES power transformer in the planning area. GIC(t) shall be provided within
90 calendar days of receipt of the written request and after determination of the maximum
effective GIC value in Part 9.1.
M9. Each responsible entity, as determined in Requirement R1, shall provide evidence, such as email records,
web postings with an electronic notice of posting, or postal receipts showing recipient and date, that it
has provided the maximum effective GIC values to the Transmission Owner and Generator Owner that
owns each applicable BES power transformer in the planning area as specified in Requirement R9, Part
9.1. Each responsible entity, as determined in Requirement R1, shall also provide evidence, such as email
records, web postings with an electronic notice of posting, or postal receipts showing recipient and date,
that it has provided GIC(t) in response to a written request from the Transmission Owner or Generator
Owner that owns an applicable BES power transformer in the planning area.
Registered Entity Response (Required):
Compliance Narrative:
Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.
Evidence Requestedi:
Provide the following evidence, or other evidence to demonstrate compliance.
A list of each Transmission Owner and Generator Owner in the planning area that owns an applicable BES power
transformer.
Dated evidence demonstrating the responsible entity provided the maximum effective GIC value for the worst
case geoelectric field orientation for the benchmark GMD event described in Attachment 1 to each
Transmission Owner and Generator Owner in the planning area that owns an applicable BES power transformer
in the planning area.
Dated evidence demonstrating the responsible entity, within 90 calendar days of receipt of the written request
and after determination of the maximum effective GIC value in Part 9.1, provided the effective GIC time series,
GIC(t), calculated using the benchmark GMD event described in Attachment 1 in response to a written request
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from the Transmission Owner or Generator Owner that owns an applicable BES power transformer in the
planning area.
Documentation that identifies the roles and responsibilities of entities in the planning area for maintaining
models and performing the studies needed to complete GMD Vulnerability Assessments.
Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document
Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):
Compliance Assessment Approach Specific to TPL-007-4, R9
This section to be completed by the Compliance Enforcement Authority
(R9) Verify the responsible entity provided GIC flow information to each Transmission Owner and
Generator Owner that owns an applicable BES power transformer in the planning area.
(Part 9.1) Verify the GIC flow information provided by the responsible entity included the maximum
effective GIC value for the worst case geoelectric field orientation for the supplemental GMD event
described in Attachment 1.
(Part 9.2) For all, or a sample of, written requests from applicable Transmission Owner or Generation
Owners, verify the responsible entity provided the effective GIC time series, GIC(t), within 90 calendar
days of receipt of the written request and after determination of the maximum effective GIC value in
Part 9.1.
Note to Auditor:
Auditor Notes:
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R10 Supporting Evidence and Documentation
Each Transmission Owner and Generator Owner shall conduct a supplemental thermal impact
assessment for its solely and jointly owned applicable BES power transformers where the maximum
effective GIC value provided in Requirement R9, Part 9.1, is 85 A per phase or greater. The supplemental
thermal impact assessment shall:
10.1. Be based on the effective GIC flow information provided in Requirement R9;
10.2. Document assumptions used in the analysis;
10.3. Describe suggested actions and supporting analysis to mitigate the impact of GICs, if any; and
10.4. Be performed and provided to the responsible entities, as determined in Requirement R1, within 24
calendar months of receiving GIC flow information specified in Requirement R9, Part 9.1
M10.Each Transmission Owner and Generator Owner shall have evidence such as electronic or hard copies of
its supplemental thermal impact assessment for all of its solely and jointly owned applicable BES power
transformers where the maximum effective GIC value provided in Requirement R9, Part 9.1, is 85 A per
phase or greater, and shall have evidence such as email records, web postings with an electronic notice
of posting, or postal receipts showing recipient and date, that it has provided its supplemental thermal
impact assessment to the responsible entities as specified in Requirement R10.
Registered Entity Response (Required):
Compliance Narrative:
Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.
Evidence Requestedi:
Provide the following evidence, or other evidence to demonstrate compliance.
The GIC flow information provided by the Planning Coordinator or Transmission Planner in accordance with
Requirement R9.
Dated evidence demonstrating the completion of the supplemental thermal impact assessment for each of the
entity’s solely and jointly owned applicable BES power transformers where the maximum effective GIC value
provided in Requirement R9 Part 9.1 is 85 A per phase or greater.
Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document
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Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):
Compliance Assessment Approach Specific to TPL-007-4, R10
This section to be completed by the Compliance Enforcement Authority
(R10) Verify the entity conducted a supplemental thermal impact assessment for each applicable BES
power transformer where the maximum effective GIC value provided in Requirement R9, Part 9.1, is 85
A per phase or greater.
(R10) Review supplemental thermal impact assessments for applicable BES power transformers and
confirm the thermal impact assessment meets the requirements identified in Requirement R10 Part
10.1 through Part 10.4.
(Part 10.1) Be based on the effective GIC flow information provided in Requirement R9.
(Part 10.2) Document assumptions used in the analysis.
(Part 10.3) Describe suggested actions and supporting analysis to mitigate the impact of GICs, if any.
(Part 10.4) Be performed and provided to the responsible entities as determined in Requirement R1
within 24 calendar months of receiving GIC flow information specified in Requirement R9, Part 9.1.
Note to Auditor:
Auditor Notes:
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R11 Supporting Evidence and Documentation
Each responsible entity, as determined in Requirement R1, that concludes through the supplemental
GMD Vulnerability Assessment conducted in Requirement R8 that their System does not meet the
performance requirements for the steady state planning supplemental GMD event contained in Table 1,
shall develop a Corrective Action Plan (CAP) addressing how the performance requirements will be met.
The CAP shall:
11.1. List System deficiencies and the associated actions needed to achieve required System
performance. Examples of such actions include:
• Installation, modification, retirement, or removal of Transmission and generation Facilities and any
associated equipment.
• Installation, modification, or removal of Protection Systems or Remedial Action Schemes.
• Use of Operating Procedures, specifying how long they will be needed as part of the CAP.
• Use of Demand-Side Management, new technologies, or other initiatives.
11.2. Be developed within one year of completion of the supplemental GMD Vulnerability Assessment.
11.3. Include a timetable, subject to ERO approval for any extension sought under Part 11.4, for
implementing the selected actions from Part 11.1. The timetable shall:
11.3.1. Specify implementation of non-hardware mitigation, if any, within two years of
development of the CAP; and
11.3.2. Specify implementation of hardware mitigation, if any, within four years of development of
the CAP.
11.4. Be submitted to the CEAERO with a request for extension of time if the responsible entity is unable
to implement the CAP within the timetable provided in Part 11.3. This submission shall include the
following:
11.4.1. Circumstances causing the delay for fully or partially implementing the selected actions in
Part 11.1 and how those circumstances are beyond the control of the responsible entity;
11.4.2. Revisions to the selected actions in Part 11.1, if any, including utilization of Operating
Procedures if applicable; and,
11.4.3. Updated timetable for implementing the selected actions in Part 11.1.
11.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent Planning Coordinator(s),
adjacent Transmission Planner(s), and functional entities referenced in the CAP within 90 calendar
days of development or revision, and (ii) to any functional entity that submits a written request and
has a reliability-related need within 90 calendar days of receipt of such request or within 90
calendar days of development or revision, whichever is later.
11.5.1. If a recipient of the CAP provides documented comments on the CAP, the responsible entity
shall provide a documented response to that recipient within 90 calendar days of receipt of
those comments.
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M11.Each responsible entity, as determined in Requirement R1, that concludes, through the supplemental
GMD Vulnerability Assessment conducted in Requirement R8, that the responsible entity's System does
not meet the performance requirements for the steady state planning supplemental GMD event
contained in Table 1 shall have evidence such as dated electronic or hard copies of its CAP including
timetable for implementing selected actions, as specified in Requirement R11. Each responsible entity, as
determined in Requirement R1, shall also provide evidence, such as email records or postal receipts
showing recipient and date, that it submitted a request for extension to the ERO if the responsible entity
is unable to implement the CAP within the timetable provided in Part 11.3. Each responsible entity, as
determined in Requirement R1, shall also provide evidence, such as email records, web postings with an
electronic notice of posting, or postal receipts showing recipient and date, that it has distributed its CAP
or relevant information, if any, (i) to the responsible entity's Reliability Coordinator, adjacent Planning
Coordinator(s), adjacent Transmission Planner(s), and functional entities referenced in the CAP within 90
calendar days of development or revision, and (ii) to any functional entity that submits a written request
and has a reliability-related need within 90 calendar days of receipt of such request or within 90 calendar
days of development or revision, whichever is later as specified in Requirement R11. Each responsible
entity, as determined in Requirement R1, shall also provide evidence, such as email notices or postal
receipts showing recipient and date, that it has provided a documented response to comments received
on its CAP within 90 calendar days of receipt of those comments, in accordance with Requirement R11.
Registered Entity Response (Required):
Compliance Narrative:
Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.
Evidence Requestedi:
Provide the following evidence, or other evidence to demonstrate compliance.
Documentation that identifies the roles and responsibilities of entities in the planning area for maintaining
models and performing the studies needed to complete GMD Vulnerability Assessments.
Copy of the supplemental GMD Vulnerability Assessment conducted in Requirement R8
A list of System deficiencies identified through the supplemental GMD Vulnerability Assessment.
All dated CAPs associated with the System deficiencies, which identify the associated actions needed to achieve
required System performance.
Evidence the CAP was submitted to the CEAERO with a request for extension of time if the responsible entity is
unable to implement the CAP within the timetable provided in Part 11.3.
Dated evidence that the CAP was provided, within 90 calendar days of development or revision, to the
responsible entity’s Reliability Coordinator, adjacent Planning Coordinator(s), adjacent Transmission Planner(s),
functional entities referenced in the CAP.
Dated evidence that the CAP was provided to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or within 90 calendar days of
development or revision, whichever is later.
If a recipient of the CAP provided documented comments on the CAP, evidence the responsible entity shall
provide a documented response to that recipient within 90 calendar days of receipt of those comments.
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Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document
Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):
Compliance Assessment Approach Specific to TPL-007-4, R11
This section to be completed by the Compliance Enforcement Authority
(R11) Verify the entity developed a CAP addressing how the performance requirements will be met
for the steady state planning supplemental GMD event, if the entity concluded through the
supplemental GMD Vulnerability Assessment conducted in Requirement R8, that their System does
not meet the performance requirements of Table 1. Verify the CAP:
(Part 11.1) List system deficiencies and associated actions needed to achieve required System
performance.
(Part 11.2) The CAP was developed within one year of completion of the supplemental GMD
Vulnerability Assessment.
(Part 11.3) The CAP includes a timetable.
(Part 11.3.1) A timetable specifying implementation of non-hardware mitigation, if any, within two
years of development of the CAP.
(Part 11.3.2) A timetable specifying implementation of hardware mitigation, if any, within four years
of the development of the CAP.
(Part 11.4) Verify the CAP was submitted to the CEAERO with a request for extension of time if the
responsible entity is unable to implement the CAP within the timetable provided in Part 11.3.
(Part 11.4.1) Verify the submitted CAP documents circumstances causing the delay for fully or
partially implementing the selected actions in Part 11.1 and how those circumstances are beyond the
control of each responsible entity.
(Part 11.4.2) Verify the submitted CAP documents revisions to the selected actions in Part 11.1, if
any, including utilization of Operating Procedures if applicable.
(Part 11.4.3) Verify the submitted CAP documents an updated timetable for implementing the
selected actions in Part 11.1.
(Part 11.5) Verify the responsible entity provided the CAP, within 90 calendar days of development
or revision, to the responsible entity’s Reliability Coordinator, adjacent Planning Coordinator(s),
adjacent Transmission Planner(s), functional entities referenced in the CAP.
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(Part 11.5) Verify the responsible entity provided the CAP to any functional entity that submits a
written request and has a reliability-related need within 90 calendar days of receipt of such request
or within 90 calendar days of development or revision, whichever is later.
(Part 11.5.1) If a recipient of the CAP provided documented comments on the CAP, verify the
responsible entity provided a documented response to that recipient within 90 calendar days of
receipt of those comments.
Note to Auditor:
Auditor Notes:
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R12 Supporting Evidence and Documentation
Each responsible entity, as determined in Requirement R1, shall implement a process to obtain GIC
monitor data from at least one GIC monitor located in the Planning Coordinator’s planning area or other
part of the system included in the Planning Coordinator’s GIC System model.
M12.Each responsible entity, as determined in Requirement R1, shall have evidence such as electronic or hard
copies of its GIC monitor location(s) and documentation of its process to obtain GIC monitor data in
accordance with Requirement R12.
Registered Entity Response (Required):
Compliance Narrative:
Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.
Evidence Requestedi:
Provide the following evidence, or other evidence to demonstrate compliance.
Documentation that identifies the implementation of a process to obtain GIC monitor data from at least one
GIC monitor located in the Planning Coordinator's planning area or other part of the system included in the
Planning Coordinator's GIC System model.
Documentation that identifies the roles and responsibilities of entities in the planning area for implementing
process(es) to obtain GMD measurement data.
Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document
Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):
Compliance Assessment Approach Specific to TPL-007-4, R12
This section to be completed by the Compliance Enforcement Authority
Verify that the responsible entity, as determined in Requirement R1, implemented its process to obtain
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GIC monitor data.
Verify that GIC monitor data came from at least one GIC monitor located in the Planning Coordinator's
planning area or other part of the system included in the Planning Coordinator's GIC System model.
Note to Auditor:
Auditor Notes:
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R12 Supporting Evidence and Documentation
Each responsible entity, as determined in Requirement R1, shall implement a process to obtain
geomagnetic field data for its Planning Coordinator’s planning area.
M13.Each responsible entity, as determined in Requirement R1, shall have evidence such as electronic or hard
copies of its process to obtain geomagnetic field data for its Planning Coordinator’s planning area in
accordance with Requirement R13.
Registered Entity Response (Required):
Compliance Narrative:
Provide a brief explanation, in your own words, of how you comply with this Requirement. References to supplied
evidence, including links to the appropriate page, are recommended.
Evidence Requestedi:
Provide the following evidence, or other evidence to demonstrate compliance.
Documentation that identifies the implementation of a process to obtain geomagnetic field data for its Planning
Coordinator’s planning area.
Documentation that identifies the roles and responsibilities of entities in the planning area for implementing
process(es) to obtain GMD measurement data.
Registered Entity Evidence (Required):
The following information is requested for each document submitted as evidence. Also, evidence submitted
should be highlighted and bookmarked, as appropriate, to identify the exact location where evidence of
compliance may be found.
Relevant
Revision
Page(s)
or
Document
or
Description of Applicability
File Name
Document Title
Version
Date
Section(s)
of Document
Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):
Compliance Assessment Approach Specific to TPL-007-4, R13
This section to be completed by the Compliance Enforcement Authority
Verify that the responsible entity, as determined in Requirement R1, implemented its process to obtain
geomagnetic field data.
Verify that geomagnetic field data is for the Planning Coordinator’s planning area.
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Note to Auditor:
Auditor Notes:
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Additional Information:
Reliability Standard
The full text of TPL-007-4 may be found on the NERC Web Site (www.nerc.com) under “Program Areas &
Departments”, “Reliability Standards.”
In addition to the Reliability Standard, there is an applicable Implementation Plan available on the NERC Web
Site.
In addition to the Reliability Standard, there is background information available on the NERC Web Site.
Capitalized terms in the Reliability Standard refer to terms in the NERC Glossary, which may be found on the
NERC Web Site.
Regulatory Language
In Order No. 830, issued in 2016, the Federal Energy Regulatory Commission approved Reliability Standard
TPL-007-1 and directed further revisions. Specifically, FERC directed NERC to: (1) revise the benchmark GMD
event definition so that the reference peak geoelectric field amplitude component is not based solely on
spatially-averaged data (P 44); (2) make corresponding revisions to Requirement R6, relating to transformer
thermal impact assessments (P 65) ; (3) require entities to collect GIC monitoring and magnetometer data (P
88); and (4) include deadlines for the development and completion of Corrective Action Plans to address
identified system vulnerabilities (PP 101-102). Order No. 830, Reliability Standard for Transmission System
Planned Performance for Geomagnetic Disturbance Events, 156 FERC ¶ 61,215 (2016).
In response to FERC’s Order No. 830 directives, NERC developed Reliability Standard TPL-007-2. Reliability
Standard TPL-007-2 added new Requirements for entities to assess their vulnerabilities to a second defined
event, the supplemental GMD event. The standard added new Requirements for the collection of GIC and
magnetometer data. The standard also revised Requirement R7 to include deadlines for the development and
completion of any necessary Corrective Action Plans.
The Commission approved Reliability Standard TPL-007-2 in Order No. 851, issued in 2018. In this Order, FERC
also directed further revisions as follows:
1. Require Corrective Action Plans for Supplemental GMD Vulnerability Assessment Vulnerabilities
29. As proposed in the NOPR, pursuant to section 215(d)(5) of the FPA, we also determine that it
is appropriate to direct NERC to develop and submit modifications to Reliability Standard TPL007-2 to require the development and completion of corrective action plans to mitigate assessed
supplemental GMD event vulnerabilities. Given that NERC has acknowledged the potential for
“severe, localized impacts” associated with supplemental GMD event vulnerabilities, we see no
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basis for requiring corrective action plans for benchmark GMD events but not for supplemental
GMD events.[ ] Based on the record in this proceeding, there appear to be no technical barriers to
developing or complying with such a requirement. Moreover, as discussed below, the record
supports issuance of a directive at this time, notwithstanding NOPR comments advocating
postponement of any directive until after the completion of additional GMD research, because
relevant GMD research is scheduled to be completed before the due date for submitting a
modified Reliability Standard. The Commission therefore adopts the NOPR proposal and directs
NERC to submit the modified Reliability Standard for approval within 12 months from the
effective date of Reliability Standard TPL-007-2.
2. Implement Case-by-Case Exception Process for Considering Corrective Action Plan Completion
Deadline Extensions
30. We also determine, pursuant to section 215(d)(5) of the FPA, that it is appropriate to direct
that NERC develop further modifications to Reliability Standard TPL-007-2, Requirement R7.4.
Under NERC’s proposal, applicable entities are allowed, without prior approval, to exceed
deadlines for completing corrective action plan tasks when “situations beyond the control of the
responsible entity [arise].”[ ] Instead, as discussed below, we direct NERC to develop a timely and
efficient process, consistent with the Commission’s guidance in Order No. 830, to consider time
extension requests on a case-by-case basis. Our directive balances the availability of time
extensions when applicable entities are presented with the types of uncontrollable delays
identified in NERC’s petition and NOPR comments with the need to ensure that the mitigation of
known GMD vulnerabilities is not being improperly delayed through such requests. Further, as
proposed in the NOPR, we direct NERC to prepare and submit a report addressing how often and
why applicable entities are exceeding corrective action plan deadlines as well as the disposition
of time extension requests. The report is due within 12 months from the date on which applicable
entities must comply with the last requirement of Reliability Standard TPL-007-2. Following
receipt of the report, the Commission will determine whether further action is necessary.
56. In reaching our determination on this issue, we considered NERC’s NOPR comments, which
attempted to address the concerns with Requirement R7.4 expressed in the NOPR, stating that
NERC and Regional Entity compliance and enforcement staff will review the reasonableness of
any delay in implementing corrective action plans, including reviewing the asserted “situations
beyond the control of the responsible entity” cited by the applicable entity, and by citing specific
examples of the types of delays that might justify the invocation of Requirement R7.4. NERC’s
comments also characterized Requirement R7.4 as being “not so flexible … as to allow entities to
extend Corrective Action Plan deadlines indefinitely or for any reason whatsoever.”[] We
generally agree with the standard of review that NERC indicates it will use to determine whether
an extension of time to implement a corrective action plan is appropriate. However, the
assessment of whether an extension of time is warranted is more appropriately made before an
applicable entity is permitted to delay mitigation of a known GMD vulnerability. While NERC
indicates that under proposed Requirement R7.4 there are compliance consequences for
improperly delaying mitigation, mitigation of a known GMD vulnerability will nonetheless have
been delayed, and we conclude it is important that any proposed delay be reviewed ahead of
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-007-4_2019_v1 Revision Date: NovemberOctoberAugust, 2019 RSAW Template: RSAW2014R1.2
39
DRAFT NERC Reliability Standard Audit Worksheet
time. Therefore, we direct NERC to modify Reliability Standard TPL-007-2, Requirement R7.4 to
develop a timely and efficient process, consistent with the Commission’s guidance in Order No.
830, to consider time extension requests on a case-by-case basis.
Order No. 851, Geomagnetic Disturbance Reliability Standard; Reliability Standard for Transmission System
Planned Performance for Geomagnetic Disturbance Events, 165 FERC ¶ 61,124 (2018).
In February 2019, the NERC Board of Trustees adopted a regional Variance for Canadian jurisdictions in
Reliability Standard TPL-007-3. None of the continent-wide Requirements were changed. This standard version
has been submitted to the Canadian provincial authorities for approval and to FERC for informational purposes
only.
Revision History for RSAW
Version
Date
1
08/02/2019
2
11/13/2019
Reviewers
NERC Compliance,
Standards, RSAWTF
NERC Compliance,
Standards, RSAWTF
Revision Description
New Document
Updated to most recent draft of the Standard
i
Items in the Evidence Requested section are suggested evidence that may, but will not necessarily, demonstrate compliance. These items are not
mandatory and other forms and types of evidence may be submitted at the entity’s discretion.
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_TPL-007-4_2019_v1 Revision Date: NovemberOctoberAugust, 2019 RSAW Template: RSAW2014R1.2
40
Standards Announcement
Project 2019-01 Modifications to TPL-007-3
Ballot Pools Forming through August 26, 2019
Formal Comment Period Open through September 9, 2019
Now Available
A 45-day formal comment period for TPL-007-4 – Transmission System Planned Performance for
Geomagnetic Disturbance Events is open through 8 p.m. Eastern, Monday, September 9, 2019.
Commenting
Use the Standards Balloting and Commenting System (SBS) to submit comments. If you experience issues
using the SBS, contact Linda Jenkins. An unofficial Word version of the comment form is posted on the
project page.
Ballot Pools
Ballot pools are being formed through 8 p.m. Eastern, Monday, August 26, 2019. Registered Ballot Body
members can join the ballot pools here.
•
If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential
error messages, or system lock-out, contact NERC IT support directly at https://support.nerc.net/
(Monday – Friday, 8 a.m. - 5 p.m. Eastern).
•
Passwords expire every 6 months and must be reset.
•
The SBS is not supported for use on mobile devices.
•
Please be mindful of ballot and comment period closing dates. We ask to allow at least 48 hours for
NERC support staff to assist with inquiries. Therefore, it is recommended that users try logging into
their SBS accounts prior to the last day of a comment/ballot period.
Next Steps
An Initial ballot for the standard, along with non-binding polls for the associated Violation Risk Factors
and Violation Severity Levels, will be conducted August 30 – September 9, 2019.
For more information on the Standards Development Process, refer to the Standard Processes Manual.
Subscribe to this project's observer mailing list by selecting "NERC Email Distribution Lists" from the
"Applications" drop-down menu and specify “Project 2019-01 Modifications to TPL-007-3 Observer List” in
the Description Box. For more information or assistance, contact Senior Standards Developer, Alison
Oswald (via email) or at 404-446-9668.
RELIABILITY | RESILIENCE | SECURITY
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement | Project 2019-01 Modifications to TPL-007-3
TPL-007-4 | July-August, 2019
2
Comment Report
Project Name:
2019-01 Modifications to TPL-007-3
Comment Period Start Date:
7/26/2019
Comment Period End Date:
9/9/2019
Associated Ballots:
2019-01 Modifications to TPL-007-3 TPL-007-4 IN 1 ST
There were 66 sets of responses, including comments from approximately 133 different people from approximately 98 companies
representing 10 of the Industry Segments as shown in the table on the following pages.
Questions
1. The SDT approach was to modify Requirement R7.4 to meet the directive in Order 851 to require prior approval of extension requests for
completing corrective action plan tasks. Do you agree that R7 meets the directive? If you disagree please explain and provide alternative
language and rationale for how it meets the directive of the order.
2. The SDT approach was to add Requirement R11 to meet the directive in Order No. 851 to “require corrective action plans for assessed
supplemental GMD event vulnerabilities.” R7 and R11 are the same language applied to the benchmark and supplemental events
respectively. Do you agree that R11 meets the directive? If you disagree please explain and provide alternative language and rationale for
how it meets the directive of the order.
3. Do you agree that the Canadian variance is written in a way that accommodates the regulatory processes in Canada? If you disagree
please explain and provide alternative language and rationale for how it meets the directive of the order while accommodating Canadian
regulatory processes.
4. Do you agree that the standard language changes in Requirement R7, R8, and R11 proposed by the SDT adequately address the directives
in FERC Order No. 851? If you disagree please explain and provide alternative language and rationale for how it meets the directive of the
order.
5. Do you have any comments on the modified VRF/VSL for Requirements R7, R8, and R11?
6. Do you agree with the proposed Implementation Plan? If you think an alternate, shorter or longer implementation time period is needed,
please propose an alternate implementation plan and time period, and provide a detailed explanation of actions planned to meet the
implementation deadline.
7. The SDT proposes that the modifications in TPL-007-4 meet the FERC directives in a cost effective manner. Do you agree? If you do not
agree, or if you agree but have suggestions for improvement to enable more cost effective approaches, please provide your recommendation
and, if appropriate, technical or procedural justification.
8. Provide any additional comments for the standard drafting team to consider, if desired.
Organization
Name
Name
FirstEnergy - Aubrey
FirstEnergy
Short
Corporation
Electric
Reliability
Council of
Texas, Inc.
Douglas
Webb
Brandon
Gleason
Segment(s)
4
ISO/RTO
Council
Standards
Review
Committee
2019-01
Modifications
to TPL-007
MRO,SPP RE
1,3,4,5,6
Group Name
FE VOTER
2
Douglas
Webb
ACES Power Jodirah
Marketing
Green
Region
Group
Member
Name
Group Member
Organization
Group
Member
Segment(s)
Group
Member
Region
Ann Carey
FirstEnergy
6
RF
Robert Loy
FirstEnergy FirstEnergy
Solutions
5
RF
Aaron
Ghodooshim
FirstEnergy FirstEnergy
Corporation
3
RF
Julie Severino FirstEnergy FirstEnergy
Corporation
1
RF
Aubrey Short
FirstEnergy
4
RF
Brandon
Gleason
Electric
Reliability
Council of
Texas, Inc.
2
Texas RE
Bobbi Welch
Midcontinent
Independent
System
Operator
2
MRO
Mark Holman
PJM
2
Interconnection,
L.L.C.
RF
Charles Yeung Southwest
Power Pool,
Inc. (RTO)
2
MRO
Gregory
Campoli
New York
Independent
System
Operator
2
NPCC
Westar-KCPL Doug Webb
Westar
1,3,5,6
MRO
Doug Webb
KCP&L
1,3,5,6
MRO
MRO,NA - Not
ACES
Bob Solomon
Applicable,RF,SERC,Texas Standard
RE,WECC
Collaborations
Hoosier Energy 1
Rural Electric
Cooperative,
Inc.
SERC
Kevin Lyons
Central Iowa
Power
Cooperative
MRO
John Shaver
Arizona Electric 1
Power
Cooperative
1
WECC
Public Utility Joyce
District No. 1 Gundry
of Chelan
County
Entergy
Julie Hall
DTE Energy - Karie
Detroit Edison Barczak
Company
Duke Energy Kim
Thomas
Southern
Pamela
Company Hunter
Southern
Company
Services, Inc.
3
CHPD
6
Entergy
3,4,5
1,3,5,6
1,3,5,6
Bill Hutchison
Southern Illinois 1
Power
Cooperative
SERC
Tara Lightner
Sunflower
Electric Power
Corporation
MRO
Meaghan
Connell
Public Utility
5
District No. 1 of
Chelan County
WECC
Davis Jelusich Public Utility
6
District No. 1 of
Chelan County
WECC
Jeff Kimbell
Public Utility
1
District No. 1 of
Chelan County
WECC
Oliver Burke
Entergy Entergy
Services, Inc.
1
SERC
Jamie Prater
Entergy
5
SERC
DTE Energy DTE Electric
5
RF
Daniel Herring DTE Energy DTE Electric
4
RF
Karie Barczak DTE Energy DTE Electric
3
RF
Laura Lee
Duke Energy
1
SERC
Dale
Goodwine
Duke Energy
5
SERC
Greg Cecil
Duke Energy
6
RF
Adrianne
Collins
Southern
Company Southern
Company
Services, Inc.
1
SERC
Joel
Dembowski
Southern
3
Company Alabama Power
Company
SERC
William D.
Shultz
Southern
Company
Generation
5
SERC
Ron Carlsen
Southern
Company Southern
6
SERC
DTE Energy - Jeffrey
DTE Electric Depriest
FRCC,RF,SERC
SERC
Duke Energy
Southern
Company
1
Company
Generation
Northeast
Power
Coordinating
Council
Ruida Shu 1,2,3,4,5,6,7,8,9,10 NPCC
RSC no NGrid Guy V. Zito
and NYISO
Northeast
Power
Coordinating
Council
10
NPCC
Randy
MacDonald
New Brunswick 2
Power
NPCC
Glen Smith
Entergy
Services
4
NPCC
Brian
Robinson
Utility Services 5
NPCC
Alan Adamson New York State 7
Reliability
Council
NPCC
David Burke
Orange &
Rockland
Utilities
3
NPCC
Michele
Tondalo
UI
1
NPCC
Helen Lainis
IESO
2
NPCC
Sean Cavote
PSEG
4
NPCC
Kathleen
Goodman
ISO-NE
2
NPCC
David Kiguel
Independent
NA - Not
Applicable
NPCC
Silvia Mitchell
NextEra Energy 6
- Florida Power
and Light Co.
NPCC
Paul
Malozewski
Hydro One
Networks, Inc.
3
NPCC
Nick
Kowalczyk
Orange and
Rockland
1
NPCC
Joel
Charlebois
AESI - Acumen 5
Engineered
Solutions
International
Inc.
NPCC
Quintin Lee
Eversource
Energy
1
NPCC
Mike Cooke
Ontario Power 4
Generation, Inc.
NPCC
Salvatore
Spagnolo
New York
1
Power Authority
NPCC
Shivaz Chopra New York
5
Power Authority
NPCC
Mike Forte
Con Ed Consolidated
Edison
4
NPCC
Dermot Smyth Con Ed Consolidated
Edison Co. of
New York
1
NPCC
Peter Yost
Con Ed Consolidated
Edison Co. of
New York
3
NPCC
Ashmeet Kaur Con Ed Consolidated
Edison
5
NPCC
Caroline
Dupuis
Hydro Quebec
1
NPCC
Chantal Mazza Hydro Quebec
2
NPCC
Dominion 6
Dominion
Resources, Inc.
NPCC
Sean Bodkin
PSEG
Southwest
Power Pool,
Inc. (RTO)
Sean
Cavote
Shannon
Mickens
1,3,5,6
2
FRCC,NPCC,RF
MRO,SPP RE
PSEG REs
Laura McLeod NB Power
Corporation
5
NPCC
Randy
MacDonald
NB Power
Corporation
2
NPCC
Tim Kucey
PSEG - PSEG
Fossil LLC
5
NPCC
Karla Barton
PSEG - PSEG 6
Energy
Resources and
Trade LLC
RF
Jeffrey Mueller PSEG - Public 3
Service Electric
and Gas Co.
RF
Joseph Smith
PSEG - Public 1
Service Electric
and Gas Co.
RF
Southwest
2
Power Pool Inc.
MRO
Southwest
2
Power Pool Inc
MRO
Nebraska
Public Power
District
MRO
SPP
Shannon
Standards
Mickens
Review Group Scott Jordan
Jamison
Cawley
1
1. The SDT approach was to modify Requirement R7.4 to meet the directive in Order 851 to require prior approval of extension requests for
completing corrective action plan tasks. Do you agree that R7 meets the directive? If you disagree please explain and provide alternative
language and rationale for how it meets the directive of the order.
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer
No
Document Name
Comment
CHPD does not agree with replacing the corrective action plan time-extension provision in Requirement R7.4 with a process through which extensions
of time are considered on a case-by-case basis. Since R7.4 is for “situations beyond the control of the entity,” it does not matter if the extensions are
considered on a case-by-case basis as the entity will not be able to comply with the CAP timeline as the situation was beyond their control. Adding the
case-by-case basis would increase the administrative burden to entities while adding very little benefit to the reliability of the BPS.
Likes
6
Dislikes
Orlando Utilities Commission, 1, Staley Aaron; Snohomish County PUD No. 1, 3, Chaney Holly; Public
Utility District No. 1 of Snohomish County, 4, Martinsen John; Snohomish County PUD No. 1, 6, Liang
John; Public Utility District No. 1 of Snohomish County, 1, Duong Long; Public Utility District No. 1 of
Snohomish County, 5, Nietfeld Sam
0
Response
Kenya Streeter - Edison International - Southern California Edison Company - 6
Answer
No
Document Name
Comment
See EEI's comments.
Likes
0
Dislikes
0
Response
Russell Noble - Cowlitz County PUD - 3
Answer
Document Name
Comment
No
The addition of the ERO for approving any timeline extension may prove to be excessive and burdensome for NERC, and possibly the responsible
entity as well. The District recommends an additional statement where the ERO has 60 days to provide notice to the responsible entity when a CAP
submittal with an extension request will require ERO approval following full review. Otherwise, if NERC acknowledges receipt with no further notice to
the responsible entity, the CAP and extension request is automatically approved. This would reduce the work load on NERC regarding CAPs with
extension requests that are minimal or otherwise considered low risk to the BES.
Additionally, there is no consideration of cost. It is possible that a CAP could be expensive and difficult to develop a four-year plan without hindering
other more important Transmission Planning objectives in compliance to TPL-001.
Likes
0
Dislikes
0
Response
Richard Jackson - U.S. Bureau of Reclamation - 1
Answer
No
Document Name
Comment
Reclamation recommends Requirement R7 be phrased in terms of a responsible entity’s required action, not an action required by a CAP.
Reclamation also recommends restructuring TPL-007 so that one requirement in TPL-007 addresses corrective action plans for both benchmark and
supplemental GMD Vulnerability Assessments. Reclamation offers the following language for this requirement (see the response to Question 2
regarding the numbering):
R10. Each responsible entity, as determined in Requirement R1, that concludes through the benchmark GMD Vulnerability Assessment conducted in
Requirement R4 or the Supplemental GMD Vulnerability Assessment conducted in Requirement R8 that their System does not meet the performance
requirements for the steady state planning benchmark GMD event contained in Table 1, shall develop a Corrective Action Plan (CAP) addressing how
the performance requirements will be met.
10.1. The responsible entity shall develop the CAP within one year of completion of the benchmark GMD Vulnerability Assessment or Supplemental
GMD Vulnerability Assessment.
10.2. The CAP shall contain the following:
10.2.1. A list of System deficiencies and the associated actions needed to achieve required System performance.
10.2.2. A timetable, subject to the following provisions, for implementing each action identified in 7.2.1:
10.2.2.1. Any implementation of non-hardware mitigation must be complete within two years of development of the CAP; and
10.2.2.2. Any implementation of hardware mitigation must be complete within 4 years of development of the CAP.
10.3 The responsible entity shall provide the CAP to the following entities within 90 days of development, revision, or receipt of a written request
10.3.1. Reliability Coordinator;
10.3.2. Adjacent Planning Coordinator(s);
10.3.3. Adjacent Transmission Planner(s);
10.3.4. Functional entities referenced in the CAP; or
10.3.5. Any functional entity that submits a written request and has a reliability-related need for the CAP.
10.4. If a recipient of a CAP provides documented comments about the CAP, the responsible entity shall provide a documented response to that
recipient within 90 calendar days of receipt of those comments.
10.5. If a responsible entity determines it will be unable to implement a CAP within the timetable provided in part 7.2.2, the responsible entity shall:
10.5.1. Document the circumstances causing the inability to implement the CAP within the existing timetable;
10.5.2. Document the reason those circumstances prevent the timely implementation of the CAP (including circumstances beyond the entity’s control);
10.5.3. Document revisions to the actions identified in part 7.2.1 and the timetable in part 7.2.2; and
10.5.4. Submit a request for extension of the revised CAP to the ERO.
Regarding R10.2.2, Reclamation recommends against mandating industry-wide timelines due to the differences in each entity’s capabilities to meet
deadlines. For example, the differences in procurement processes and timelines among entities.
Regarding R10.5, Reclamation recommends the standard describe an extension policy. Regional entities may not be capable of fully researching the
entire interconnection in order to provide adequate approvals. Reclamation recommends the regional entities or the ERO automate the CAP tracking
process.
Likes
0
Dislikes
0
Response
Eric Shaw - Eric Shaw On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; - Eric Shaw
Answer
No
Document Name
Comment
Please see comments submitted by EEI.
Likes
0
Dislikes
0
Response
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
No
Comment
EEI supports the language in Requirements R7.3 and R7.4 believing the proposed changes meet the intent of Order 851. However, the companion
process document (i.e., Draft TPL-007-4 CAP Extension Request Review Process) needs additional details to ensure efficient processing of entity CAP
Extension Requests, including:
1.
A process flow diagram documenting the CAP Extension Process and roles and responsibilities of participants, including the ERO and its authority
in this process.
2.
NERC contact information where companies can quickly and efficiently check the status of their CAP Extension Requests.
3.
Defined deadlines for the completion of CAP Extension Request reviews by NERC and responding to entity inquiries.
4.
A process for extending a CAP review deadline for situations where NERC may need additional time.
5.
Criteria for a CAP Extension Request
6.
An appeals process for denied CAP Extension Requests.
7.
A formal process to notify entities on the final ruling for all CAP Extension Requests.
8.
Identification of who has oversight of the process within the ERO.
While EEI recognizes that the SDT is still early in the development phase of the TPL-007-4 Reliability Standard, we believe it is important to emphasize
that having a strong CAP Extension Request process is crucial to ensuring that the directed CAPs are effectively and efficiently processed, similar to the
BES Exceptions Process (see Rules of Procedure, Appendix 5C; Procedure for Requesting and Receiving an Exception from the Application of the
NERC Definition of Bulk Electric System).
Likes
0
Dislikes
0
Response
Chris Scanlon - Exelon - 1
Answer
No
Document Name
Comment
Exelon agrees with EEI’s comments. Exelon believes that the SDT has proposed changes to Requirements R7.3 and R7.4 that meet the intent of the
FERC directive in Order 851 but feel it requires further modifications. The Draft TPL-007-4 CAP Extension Request Review Process does not provide
the requesting entity with a clear understanding of how the request will be considered, when a decision can be expected, and how an entity could
request reconsideration if an extension is denied. With the FERC directive requiring ERO involvement in this case, this justifies placing an obligation on
the ERO. The development of a well-defined process similar to the Technical Feasbility Exception Process or the BES Exceptions Process should be
concurrently developed and submitted along with the proposed standard to facilitate NERC’s engagement. This will provide a mechanism to address
the key items noted in EEI’s comments.
On Behalf of Exelon: Segments 1, 3, 5, 6
Likes
0
Dislikes
0
Response
Douglas Webb - Douglas Webb On Behalf of: Allen Klassen, Westar Energy, 6, 3, 1, 5; Bryan Taggart, Westar Energy, 6, 3, 1, 5; Derek Brown,
Westar Energy, 6, 3, 1, 5; Grant Wilkerson, Westar Energy, 6, 3, 1, 5; James McBee, Great Plains Energy - Kansas City Power and Light Co., 1,
3, 6, 5; Jennifer Flandermeyer, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; John Carlson, Great Plains Energy - Kansas
City Power and Light Co., 1, 3, 6, 5; Marcus Moor, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; - Douglas Webb, Group
Name Westar-KCPL
Answer
No
Document Name
Comment
Westar Energy and Kansas City Power & Light Company incorporate by reference and support comments submitted in response to Question 1 by the
Edison Electric Institute.
Likes
0
Dislikes
0
Response
David Jendras - Ameren - Ameren Services - 3
Answer
No
Document Name
Comment
Ameren agrees with and supports EEI comments.
Likes
0
Dislikes
0
Response
Rahn Petersen - PNM Resources - Public Service Company of New Mexico - 1 - WECC,Texas RE
Answer
Document Name
Comment
No
This requirement gives responsibility to an entity which is not an applicable entity under the Standard. The requirement as written also has no impact
on reliability, it is purely an administrative requirement and does not directly provide the entitiy with an approved extension. There should be a
requirement added which requires the entity that receives the request for CAP extension approve the request within a specified timeframe.
Likes
0
Dislikes
0
Response
Matthew Nutsch - Seattle City Light - 1,3,4,5,6 - WECC
Answer
Yes
Document Name
Comment
SCL agrees the modifications to R7.4 meet the directive in FERC Order. No. 851 by replacing the corrective action plan time-extension provisions in
R7.4 with a process that extensions of time are considered on a case-by case basis.
Likes
0
Dislikes
0
Response
Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer
Yes
Document Name
Comment
None.
Likes
1
Dislikes
Grand River Dam Authority, 3, Wells Jeff
0
Response
Neil Swearingen - Salt River Project - 1,3,5,6 - WECC
Answer
Document Name
Comment
Yes
SRP has no comments for the standard drafting team.
Likes
0
Dislikes
0
Response
sean erickson - Western Area Power Administration - 1
Answer
Yes
Document Name
Comment
Yes, the proposed TPL-007-4 Requirement R7, Part 7.4 meets the directive of FERC Order No. 851, Paragraph 54. The FERC directive is extremely
narrow and the Project 2019-01 SDT has met the intent to require a process to consider time extensions on a case-by-case basis.
However, the FERC directive did not demand that the ERO be the adjudicating entity for time extensions and we suggest the following revision to each
ERO reference in the proposed TPL-007-4: “ERO, or its delegated designee.” We believe that this modification will allow Regional Entities or other
designees to better adjudicate CAP time extensions given their closer proximity, System expertise, and existing Compliance Program obligations.
Likes
1
Dislikes
Orlando Utilities Commission, 1, Staley Aaron
0
Response
Ayman Samaan - Edison International - Southern California Edison Company - 1
Answer
Yes
Document Name
Comment
Do you agree that R7 meets the directive? my possible answer is NO.
Please see EEI's comments
Likes
0
Dislikes
0
Response
Bruce Reimer - Manitoba Hydro - 1
Answer
Yes
Document Name
Comment
The proposed language meets the FERC directive.
Likes
0
Dislikes
0
Response
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
BPA understands that the SDT had to respond with proposed changes to meet the directive for R7. BPA does not agree that entities should have to
request approval from the ERO for an extension to the Corrective Action Plan for circumstances that occur beyond the entities control.
BPA would like to utilize the new ERO Portal tool to allow NERC and the Commission immediate access in real time to the corrective action plan
extensions and the justification for the extension.
Retaining the requirement as written gives entities the flexibility to respond to unanticipated circumstances without the administrative burden of seeking
an extension from NERC. NERC and the Commission would be able to determine if entities are abusing this flexibility and if abuse occurs, should seek
to remedy at that time.
Likes
5
Dislikes
Snohomish County PUD No. 1, 3, Chaney Holly; Public Utility District No. 1 of Snohomish County, 4,
Martinsen John; Snohomish County PUD No. 1, 6, Liang John; Public Utility District No. 1 of Snohomish
County, 1, Duong Long; Public Utility District No. 1 of Snohomish County, 5, Nietfeld Sam
0
Response
Aaron Staley - Orlando Utilities Commission - 1
Answer
Yes
Document Name
Comment
I agree that the language meets the directive, but would it make more sense for the standard to assign this to the regional entities instead of the ERO?
Likes
Dislikes
0
0
Response
Sean Cavote - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer
Yes
Document Name
Comment
PSEG supports EEI's comments.
Likes
0
Dislikes
0
Response
Brandon McCormick - Brandon McCormick On Behalf of: Carol Chinn, Florida Municipal Power Agency, 6, 4, 3, 5; Chris Gowder, Florida
Municipal Power Agency, 6, 4, 3, 5; Joe McKinney, Florida Municipal Power Agency, 6, 4, 3, 5; Richard Montgomery, Florida Municipal Power
Agency, 6, 4, 3, 5; - Brandon McCormick, Group Name FMPA
Answer
Yes
Document Name
Comment
Agree that R7 meets the directive. Do not agree that Part 7.4 should require the request for extension be submitted to the ERO for approval. It makes
more sense the request be submitted to the Regional Entity.
Likes
0
Dislikes
0
Response
Quintin Lee - Eversource Energy - 1
Answer
Yes
Document Name
Comment
Eversource agrees with the modification of Requirement R7.4 to meet the directive of Order No. 851. However, Eversource does note that the
proposed R7 "approval for any extension" does not provide a mechanism to appeal a denied extension. Additionally, Eversource notes that the
proposed "approval for any extension" would come from the ERO while approval from a PC or RC would seem to be more appropriate as they are
aware of local limitations which may be the basis for the needed extension.
Likes
0
Dislikes
0
Response
Bobbi Welch - Midcontinent ISO, Inc. - 2 - MRO,SERC,RF
Answer
Yes
Document Name
Comment
MISO supports the comments submitted by the IRC SRC.
Likes
0
Dislikes
0
Response
Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee 2019-01
Modifications to TPL-007
Answer
Yes
Document Name
Project 2019-01 Comment Form Attachment.docx
Comment
ISO/RTO Council Standards Review Committee members ERCOT, MISO, NYISO, PJM, and SPP (the “SRC”) submit the following comments regarding
Project 2019-01 Modifications to TPL-007-3.
The SRC agrees that the revisions to Requirement R7 proposed by the SDT satisfy FERC’s directive in Order 851 regarding extensions of time to
implement corrective action plans on a case-by-case basis. In order to further streamline Requirement R7 and more closely align Requirement R7 to
the specific language in FERC’s directive, the SRC offers the proposed revisions described below and identified in the attached for consideration by the
SDT.
In connection with Part 7.3, mentioning the ERO approval processes is not necessary given that Part 7.4 addresses the process. Deleting the reference
(“ERO approval for any extension sought under”) would result in a more streamlined requirement, and would more closely align with FERC’s directive
that Part 7.4 be modified to incorporate the development of a timely and effective extension of time review process. This proposed revision to the
current draft of Part 7.3 proposed by the SDT is identified in the attached redline.
In connection with Part 7.4, the SRC suggests the SDT consider:
1. Including express language that an extension of time is “subject to the approval of NERC and the reliability entity’s Regional Entity(s) on a caseby-case basis” in order to more closely align Part 7.4 with FERC’s specific directive that Part 7.4 be modified and that requests for extension of
time are to be reviewed on a “case-by-case basis.”
2. Utilizing “NERC and the reliability entity’s Regional Entity(s)” instead of “ERO” in order to more closely align with the specific language utilized in
Order 851.
3. Including “of time” in order to more clearly articulate what type of extension is available under Part 7.4
These proposed revisions to the current draft of Part 7.4 proposed by the SDT are identified in the attached redline.
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0
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0
Response
Marty Hostler - Northern California Power Agency - 5
Answer
Yes
Document Name
Comment
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0
Dislikes
0
Response
Dennis Sismaet - Northern California Power Agency - 6
Answer
Yes
Document Name
Comment
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0
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0
Response
Aubrey Short - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE VOTER
Answer
Yes
Document Name
Comment
Likes
0
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0
Response
Nick Batty - Keys Energy Services - NA - Not Applicable - SERC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1
Answer
Yes
Document Name
Comment
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0
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0
Response
Christopher Overberg - Con Ed - Consolidated Edison Co. of New York - 6
Answer
Yes
Document Name
Comment
Likes
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0
0
Response
Frank Pace - Central Hudson Gas & Electric Corp. - 1,3
Answer
Yes
Document Name
Comment
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0
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0
Response
Travis Chrest - South Texas Electric Cooperative - 1
Answer
Yes
Document Name
Comment
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0
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0
Response
Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer
Yes
Document Name
Comment
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0
Dislikes
0
Response
Nick Batty - Keys Energy Services - 4
Answer
Document Name
Yes
Comment
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0
Dislikes
0
Response
Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1,3,5,6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
John Tolo - Unisource - Tucson Electric Power Co. - 1
Answer
Yes
Document Name
Comment
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0
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0
Response
Chantal Mazza - Hydro-Qu?bec TransEnergie - 1 - NPCC
Answer
Yes
Document Name
Comment
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0
Dislikes
Response
0
Steve Arnold - City of Independence, Power and Light Department - 1,3,5
Answer
Yes
Document Name
Comment
Likes
0
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0
Response
James Mearns - Pacific Gas and Electric Company - 1,3,5
Answer
Yes
Document Name
Comment
Likes
0
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0
Response
Lana Smith - San Miguel Electric Cooperative, Inc. - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - MRO,WECC
Answer
Document Name
Comment
Yes
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0
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0
Response
Greg Davis - Georgia Transmission Corporation - 1
Answer
Yes
Document Name
Comment
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0
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0
Response
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC
Answer
Yes
Document Name
Comment
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0
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0
Response
Eleanor Ewry - Puget Sound Energy, Inc. - 1,3,5
Answer
Yes
Document Name
Comment
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0
Dislikes
Response
0
Keith Jonassen - Keith Jonassen On Behalf of: Michael Puscas, ISO New England, Inc., 2; - Keith Jonassen
Answer
Yes
Document Name
Comment
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0
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0
Response
Scott McGough - Georgia System Operations Corporation - 3,4
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Standard Collaborations
Answer
Yes
Document Name
Comment
Likes
0
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0
Response
Andrea Barclay - Georgia System Operations Corporation - 3,4
Answer
Document Name
Comment
Yes
Likes
0
Dislikes
0
Response
Anthony Jablonski - ReliabilityFirst - 10
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO, Group Name SPP Standards Review Group
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Anton Vu - Los Angeles Department of Water and Power - 6
Answer
Yes
Document Name
Comment
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0
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0
Response
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no NGrid and NYISO
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Bette White - AES - Indianapolis Power and Light Co. - 3
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Document Name
Comment
“See EEI’s comments” on Modifications to TPL-007-3 – TPL-007-4 Transmission System Planned Performance for Geomagnetic Disturbance Events.
Likes
0
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0
Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE appreciates the standard drafting team’s (SDT) efforts to meet the FERC directives. Texas RE has a few concerns as to how the SDT
approached the directives.
First, Texas RE is concerned with the following language in Part 7.4:
Additionally, Texas RE is concerned with the ERO’s role involving the process for granting CAP extensions. Texas RE asserts that it may be more
appropriate to keep operational aspects of the BPS within the hands of the owners/operators and simply make the ERO aware of the CAP. For
example, Texas RE suggests that the RC is the appropriate entity to accept/approve the extensions for CAPs. In addition, there could also be a
requirement for the registered entity to inform its CEA of a CAP extension. This way, the ERO can verify compliance as far as the RC reviewing
extensions of the CAPs and the ERO would not become part of the compliance evaluation and processes of the standard by not having to verify that
they themselves reviewed the CAP extension. Moreover, this is consistent with Reliability Standard PRC-012-2 Requirement R6, which requires the
RAS-entity submit the CAP to its reviewing RC as the RC has the relevant expertise to review the CAP.
•
Part 7.4.1 requires entities to document how circumstances causing delay are beyond the control of the responsible entity, but Part 7.4 does not
include language to specify that an extensions are only allowed when “situations beyond the control of the responsible entity [arise].” (FERC
Order No. 851). Texas RE recommends updating Part 7.4 to include requirements for extension so implementation issues do not get
categorized as documentation issues under Part 7.4.1.
•
Part 7.4 only specifies that CAP extensions shall be submitted but does not include language requiring that CAP extensions be
approved. While the Draft TPL-007-4 CAP Extension Request Review Process, which is outside of the requirement language, sates “All CAP
extension requests must be approved the ERO Enterprise prior to the original CAP completion date”, it may be helpful to specify the timetables
for extension requests in relation to the timetables for implementation in the original CAP to avoid scenarios in which the responsible entity
submits an extension request immediately prior to the planned implementation date.
•
Neither the requirement nor the Draft TPL-007-4 CAP Extension Request Review Process indicate what shall occur if a CAP extension request
is not approved.
•
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0
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0
2. The SDT approach was to add Requirement R11 to meet the directive in Order No. 851 to “require corrective action plans for assessed
supplemental GMD event vulnerabilities.” R7 and R11 are the same language applied to the benchmark and supplemental events
respectively. Do you agree that R11 meets the directive? If you disagree please explain and provide alternative language and rationale for
how it meets the directive of the order.
Rahn Petersen - PNM Resources - Public Service Company of New Mexico - 1 - WECC,Texas RE
Answer
No
Document Name
Comment
Comment is the same as question #1.
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0
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0
Response
David Jendras - Ameren - Ameren Services - 3
Answer
No
Document Name
Comment
Ameren agrees with and supports EEI comments.
Likes
0
Dislikes
0
Response
Douglas Webb - Douglas Webb On Behalf of: Allen Klassen, Westar Energy, 6, 3, 1, 5; Bryan Taggart, Westar Energy, 6, 3, 1, 5; Derek Brown,
Westar Energy, 6, 3, 1, 5; Grant Wilkerson, Westar Energy, 6, 3, 1, 5; James McBee, Great Plains Energy - Kansas City Power and Light Co., 1,
3, 6, 5; Jennifer Flandermeyer, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; John Carlson, Great Plains Energy - Kansas
City Power and Light Co., 1, 3, 6, 5; Marcus Moor, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; - Douglas Webb, Group
Name Westar-KCPL
Answer
Document Name
Comment
No
Westar Energy and Kansas City Power & Light Company incorporate by reference and support comments submitted in response to Question 2 by the
Edison Electric Institute.
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0
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0
Response
Chris Scanlon - Exelon - 1
Answer
No
Document Name
Comment
Exelon agrees with EEI’s comments and believes that the same concerns expressed in the response to Question 1 are applicable to R11 as well.
On Behalf of Exelon: Segments 1, 3, 5, 6
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0
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0
Response
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
No
Document Name
Comment
TVA supports comments submitted by AEP for Question #2.
Likes
0
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0
Response
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
No
EEI supports the language in Requirements R11 believing the proposed changes meet the intent of Order 851. However as stated in more detail in our
response to Question 1, the companion process document (i.e., Draft TPL-007-4 CAP Extension Request Review Process) needs to include additional
details to ensure effective and transparent processing of entity CAP Extension Requests.
Likes
0
Dislikes
0
Response
Eric Shaw - Eric Shaw On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; - Eric Shaw
Answer
No
Document Name
Comment
Please see comments submitted by EEI.
Likes
0
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0
Response
Sean Cavote - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer
No
Document Name
Comment
PSEG supports EEI's comments.
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0
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0
Response
Richard Jackson - U.S. Bureau of Reclamation - 1
Answer
Document Name
Comment
No
Reclamation recommends combining the TPL-007 CAP requirements in R7 and R11 as provided above in response to Question 1. If Reclamation’s
proposal is accepted, Reclamation recommends restructuring and renumbering the requirements in TPL-007 as follows:
R1 through R6 – no change
R7 – remove and combine CAP language with existing R11
R8 – renumber existing R8 to R7
R9 – renumber existing R9 to R8
R10 – renumber existing R10 to R9
R11 – combine CAP language from existing R7; renumber the new single CAP requirement to R10
R12 – renumber existing R12 to R11
R13 – renumber existing R13 to R12
This will improve the logical flow of the activities required by the revised standard. Reclamation also recommends the SDT add a heading between the
new M9 and R10 for “Corrective Action Plans” for consistency with the existing headings “Benchmark GMD Vulnerability Assessments” between M3
and R4, “Supplemental GMD Vulnerability Assessments” between M7 and R8, and “GMD Measurement Data Processes” between M11 and R12.
Likes
0
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0
Response
Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Standard Collaborations
Answer
No
Document Name
Comment
ACES believes that the directive could have been dealt with in a less onerous way that addresses concerns other entities have expressed, in their
comments, about the potential for duplication of effort between the baseline corrective action plans and supplement corrective action plans. To alleviate
some of that potential, the standard could expressly state that corrective action plans are only required for supplemental GMD Vulnerability
Assessments, if the corrective actions plans identified for the baseline GMD Assessments do not already address any additional vulnerabilities identified
by the supplemental GMD Assessments.
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0
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0
Response
Joe O'Brien - NiSource - Northern Indiana Public Service Co. - 6
Answer
No
Document Name
Comment
Comments: NIPSCO does not agree with the Requirement R11 that requires development and implementation of Corrective Action Plan (CAP) for
Supplemental GMD events. Judging by the reference geoelectric field values to be utilized for the Supplemental event, the effort appears to be
duplicative of the benchmark GMD event (8V/km) with a higher magnitude of 12V/km. As such, we believe the supplemental event represents an
“extreme” version of a case that will be assessed under the defined benchmark event.
As corrective action plans are to be developed and implemented for the benchmark GMD event(Requirement R7), requiring CAP for Supplemental
event will unnecessarily burden companies for cases that represents an extreme system condition and is not the best cost effective approach to meet
the FERC directive
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0
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0
Response
Russell Noble - Cowlitz County PUD - 3
Answer
No
Document Name
Comment
See question one.
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0
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0
Response
Kenya Streeter - Edison International - Southern California Edison Company - 6
Answer
No
Document Name
Comment
See EEI's comments.
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0
Dislikes
Response
0
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer
No
Document Name
Comment
CHPD does not agree with requiring the development and implementation of corrective action plans to mitigate assessed supplemental GMD event
vulnerabilities. Entities have only just begun the process of evaluating the benchmark GMD event and developing mitigation measures. The industry is
in the preliminary stages of assessing and developing mitigation measures for GMD events and has not had much time to develop engineeringjudgement, experience, or expertise in this field. Revising the standard to include CAPs for the supplementary GMD event is not appropriate at this time
as the industry is still building a foundation for this type of system event analysis and exploring mitigation measures. Without a sound foundation
developed, requiring CAPs for the supplemental GMD event could lead to unnecessary mitigation measures and an immense amount of industry
resources spent on a still developing science. CHPD suggests that the benchmark GMD event be fully vetted before moving onto additional scenarios
such as the supplemental event.
Likes
5
Dislikes
Snohomish County PUD No. 1, 3, Chaney Holly; Public Utility District No. 1 of Snohomish County, 4,
Martinsen John; Snohomish County PUD No. 1, 6, Liang John; Public Utility District No. 1 of Snohomish
County, 1, Duong Long; Public Utility District No. 1 of Snohomish County, 5, Nietfeld Sam
0
Response
Thomas Foltz - AEP - 5
Answer
No
Document Name
Comment
While some aspects of R11 may indeed meet the directives as literally stated in Order No. 851, we do not believe it is a prudent way to meet the spirit
of those directives. We believe R11 is unnecessarily duplicative of the obligations already required for the benchmark event, and disagree with its
inclusion. In addition, the obligation to “specify implementation” of mitigation may not be consistently interpreted among entities, and as a result,
may not meet the directives for reasons we will provide in this response.
It is our view that the original purpose of the supplemental event was to investigate the impact of local enhancement of the generated electric field
from a GMD event on the transmission grid. This requires industry to take an approach in which the GICs are calculated with the higher, enhanced
electric field magnitude of 12 V/km (adjusted for location and ground properties) applied to some smaller defined area while outside of this area the
benchmark electric field magnitude of 8 V/km (also adjusted for location and ground properties) is applied. This smaller area is then systematically
moved across the system and the calculations are repeated. This is necessary as the phenomenon could occur anywhere on the system. Using this
Version 2 methodology, every part of the system is ultimately evaluated with the higher electric field magnitude.
In our view, the supplemental event represents a more extreme scenario. Referring to Attachment 1 of the proposed standard, the section titled
‘Applying the Localized Peak Geoelectric Field in the Supplemental GMD Event’ provides examples of applying the localized peak geoelectric field
over the planning area. The first example presented is applying the peak geoelectric field (12 V/km scaled to planning area) over the entire planning
area. This example is a more severe condition than the benchmark event, and should alleviate the need to study the benchmark event if used. In
addition, modeling tools for conducting GMD vulnerability studies for the supplemental event using the moving box method have not yet been
developed. As such, adding a corrective action plan requirement to the supplemental event obviates the need for studying the benchmark event.
Rather than pursuing a Corrective Action Plan for the existing Supplemental GMD Vulnerability Assessment, we believe the SDT should instead pursue
only one single GMD Vulnerability Assessment using a reference peak geoelectric field amplitude not determined solely by non-spatially averaged
data. This would be preferable to requiring two GMD Vulnerability Assessments, both having Corrective Action Plans and each having their own
unique reference peak geoelectric field amplitude. When the Supplemental GMD Vulnerability Assessment was originally developed and proposed,
there was no CAP envisioned for it. Because of this, one could argue the merits of having two unique assessments, as each were different not only in
reference peak amplitude, but in obligations as well. What has now been proposed in this revision however, is essentially having two GMD
Vulnerability Assessments requiring Corrective Action Plans but with different reference peak geoelectric field amplitudes (one presumably higher
than the other). It would be unnecessarily burdensome, as well as illogical, to have essentially the same obligations for both a baseline and
supplemental vulnerability assessment. In addition to its duplicative nature, it is possible that the results from a benchmark study may even differ or
conflict with the results from a given supplemental study.
While the NOPR directs the standard to be revised to incorporate the “development and completion of corrective action plans to mitigate assessed
supplemental GMD event vulnerabilities”, we find rather that R11 requires the entity “specify implementation” of mitigation. This could be
interpreted by some as simply specifying what actions are to be taken but without explicit bounds or expectations on when the final execution of that
implementation (i.e. “completion”) would take place.
Once again, we believe a more prudent path for meeting the directive would be for the SDT to work with industry and determine an
agreeable reference peak geoelectric field amplitude for a single GMD Vulnerability Assessment (benchmark), one not determined solely
by non-spatially averaged data, and that potentially requires a Corrective Action Plan. This would serve to both achieve the spirit of the
directive, as well as avoid unnecessary duplication of efforts that provide no added benefit to the reliability of the BES.
Likes
1
Dislikes
Grand River Dam Authority, 3, Wells Jeff
0
Response
Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee 2019-01
Modifications to TPL-007
Answer
Yes
Document Name
Comment
The SRC agrees that adding Requirement R11, which is based on the existing language of Requirement R7, satisfies FERC’s directive in Order 851
regarding the development and implementation of corrective action plans to mitigate assessed supplemental GMD event vulnerabilities. To the extent
the SDT incorporates in Requirement R7 the SRC’s suggested revisions identified in response to Question No. 1 above, the SRC proposes the SDT
make the same revisions to Requirement R11.
Likes
0
Dislikes
Response
0
Bobbi Welch - Midcontinent ISO, Inc. - 2 - MRO,SERC,RF
Answer
Yes
Document Name
Comment
MISO supports the comments submitted by the IRC SRC.
Likes
0
Dislikes
0
Response
Quintin Lee - Eversource Energy - 1
Answer
Yes
Document Name
Comment
Eversource agrees with the addition of Requirement R11 to meet the directive of Order No. 851. However, Eversource does note that the proposed
R11 "approval for any extension" does not provide a mechanism to appeal a denied extension. Additionally, Eversource notes that the proposed
"approval for any extension" would come from the ERO while approval from a PC or RC would seem to be more appropriate as they are aware of local
limitations which may be the basis for the needed extension.
Likes
0
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0
Response
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
The SDT has met the directive in Order 851.
BPA understands that the SDT had to respond with proposed changes to meet the directive for R11. BPA would like to reiterate the industry’s and
NERC’s opposition to developing corrective action plans for an extreme event (Supplemental GMD event) and the similarity to TPL-001-4. A GMD
event is considered to be a one in one hundred year event. BPA believes that assessing the event and performing an evaluation of possible actions to
reduce the likelihood of the impact is more appropriate than requiring a Supplemental GMD event corrective action plan.
BPA supports the comments made by NERC, referenced in FERC’s Final Rule, issued on 11/15/18, Docket Nos. RM18-8-000 and RM15-11-003, Order
No. 851; paragraph 35, lines
1-12, which were unfortunately rejected by FERC. Excerpted below:
NERC’s comments reiterate the rationale in its petition that requiring mitigation
“would result in the de facto replacement of the benchmark GMD event with the
proposed supplemental GMD event.” 39 NERC maintains that “while the supplemental
GMD event is strongly supported by data and analysis in ways that mirror the benchmark
GMD event, there are aspects of it that are less definitive than the benchmark GMD event
and less appropriate as the basis of requiring Corrective Action Plans.”40 NERC also
claims that the uncertainty of geographic size of the supplemental GMD event could not
be addressed adequately by sensitivity analysis or through other methods because there
are “inherent sources of modeling uncertainty (e.g., earth conductivity model, substation
grounding grid resistance values, transformer thermal and magnetic response models) …
[and] introducing additional variables for sensitivity analysis, such as the size of the
localized enhancement, may not improve the accuracy of GMD Vulnerability Assessments.”41
39 Id. at 11-12; see also id. at 14 (“many entities would likely employ the most
conservative approach for conducting supplemental GMD Vulnerability Assessments,
which would be to apply extreme peak values uniformly over an entire planning area”).
40 Id. at 13.
41 Id. at 15.
Likes
5
Dislikes
Snohomish County PUD No. 1, 3, Chaney Holly; Public Utility District No. 1 of Snohomish County, 4,
Martinsen John; Snohomish County PUD No. 1, 6, Liang John; Public Utility District No. 1 of Snohomish
County, 1, Duong Long; Public Utility District No. 1 of Snohomish County, 5, Nietfeld Sam
0
Response
Bruce Reimer - Manitoba Hydro - 1
Answer
Yes
Document Name
Comment
The proposed language meets the FERC directive.
Likes
0
Dislikes
0
Response
Ayman Samaan - Edison International - Southern California Edison Company - 1
Answer
Yes
Document Name
Comment
Do you agree that R11 meets the directive? my possible answer is NO.
Please see EEI's comments
Likes
0
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0
Response
sean erickson - Western Area Power Administration - 1
Answer
Yes
Document Name
Comment
Yes, the proposed TPL-007-4 Requirement R11 meets the directive of FERC Order No. 851, Paragraph 39. Again, the FERC directive leaves little
room for flexibility, requiring CAPs for the supplemental GMD event. While we are disappointed that FERC was not persuaded by the technical
challenges of simulating locally-enhanced peak geoelectric field suitable for supplemental GMD event analysis, the Project 2019-01 SDT has met the
intent.
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0
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0
Response
Neil Swearingen - Salt River Project - 1,3,5,6 - WECC
Answer
Document Name
Comment
Yes
SRP has no comments for the standard drafting team.
Likes
0
Dislikes
0
Response
Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer
Yes
Document Name
Comment
None.
Likes
0
Dislikes
0
Response
Matthew Nutsch - Seattle City Light - 1,3,4,5,6 - WECC
Answer
Yes
Document Name
Comment
SCL agrees modifications to R11 meets the requirements in FERC Order 851. The modifications to R11 properly address Order 851’s requirement to
develop CAP to mitigate assessed supplemental GMD event vulnerabilities with provisions for extension of time on a case-by-case analysis.
Likes
0
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0
Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Bette White - AES - Indianapolis Power and Light Co. - 3
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no NGrid and NYISO
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Aaron Staley - Orlando Utilities Commission - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Anton Vu - Los Angeles Department of Water and Power - 6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO, Group Name SPP Standards Review Group
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Anthony Jablonski - ReliabilityFirst - 10
Answer
Yes
Document Name
Comment
Likes
Dislikes
0
0
Response
Andrea Barclay - Georgia System Operations Corporation - 3,4
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Scott McGough - Georgia System Operations Corporation - 3,4
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Keith Jonassen - Keith Jonassen On Behalf of: Michael Puscas, ISO New England, Inc., 2; - Keith Jonassen
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC
Answer
Document Name
Yes
Comment
Likes
0
Dislikes
0
Response
Greg Davis - Georgia Transmission Corporation - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - MRO,WECC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Lana Smith - San Miguel Electric Cooperative, Inc. - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
Response
0
James Mearns - Pacific Gas and Electric Company - 1,3,5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Steve Arnold - City of Independence, Power and Light Department - 1,3,5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Chantal Mazza - Hydro-Qu?bec TransEnergie - 1 - NPCC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
John Tolo - Unisource - Tucson Electric Power Co. - 1
Answer
Document Name
Comment
Yes
Likes
0
Dislikes
0
Response
Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1,3,5,6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Nick Batty - Keys Energy Services - 4
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
Response
0
Travis Chrest - South Texas Electric Cooperative - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Frank Pace - Central Hudson Gas & Electric Corp. - 1,3
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Christopher Overberg - Con Ed - Consolidated Edison Co. of New York - 6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1
Answer
Document Name
Comment
Yes
Likes
0
Dislikes
0
Response
Nick Batty - Keys Energy Services - NA - Not Applicable - SERC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Aubrey Short - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE VOTER
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Dennis Sismaet - Northern California Power Agency - 6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Marty Hostler - Northern California Power Agency - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Please see Texas RE’s comments regarding Part 7.4 in question #1 as they also apply to Part 11.4.
Likes
0
Dislikes
0
Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Document Name
Comment
“See EEI’s comments” on Modifications to TPL-007-3 – TPL-007-4 Transmission System Planned Performance for Geomagnetic Disturbance Events.
Likes
0
Dislikes
0
Response
Eleanor Ewry - Puget Sound Energy, Inc. - 1,3,5
Answer
Document Name
Comment
PSE will abstain from answering this question
Likes
0
Dislikes
Response
0
3. Do you agree that the Canadian variance is written in a way that accommodates the regulatory processes in Canada? If you disagree
please explain and provide alternative language and rationale for how it meets the directive of the order while accommodating Canadian
regulatory processes.
sean erickson - Western Area Power Administration - 1
Answer
No
Document Name
Comment
N/A
Likes
1
Dislikes
Western Area Power Administration, 6, Jones Rosemary
0
Response
Bruce Reimer - Manitoba Hydro - 1
Answer
No
Document Name
Comment
The Canadian variance does not completely reflect the unique regulatory process in each region in Canada. The Manitoba Hydro Act prevents adoption
of reliability standards that have the effect of requiring construction or enhancement of facilities in Manitoba. Manitoba Hydro modified the language of
TPL-007-2 that works in Manitoba.
Likes
0
Dislikes
0
Response
Kenya Streeter - Edison International - Southern California Edison Company - 6
Answer
No
Document Name
Comment
See EEI's comments.
Likes
Dislikes
0
0
Response
Matthew Nutsch - Seattle City Light - 1,3,4,5,6 - WECC
Answer
Yes
Document Name
Comment
SCL agrees the Canadian variance portion of the standard is helpful for the utilities in the United States. However, SCL cannot comment on the
language of the standard in the Canadian Variance portion where it relates to regulatory process in Canada.
Likes
0
Dislikes
0
Response
Neil Swearingen - Salt River Project - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
SRP is not impacted by the Canadian variance..
Likes
0
Dislikes
0
Response
Ayman Samaan - Edison International - Southern California Edison Company - 1
Answer
Yes
Document Name
Comment
Please see EEI's comments
Likes
0
Dislikes
Response
0
Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1,3,5,6
Answer
Yes
Document Name
Comment
Not applicable
Likes
0
Dislikes
0
Response
Richard Jackson - U.S. Bureau of Reclamation - 1
Answer
Yes
Document Name
Comment
For the parts of the proposed changes to R7 (new R10) stated in the response to Question 1 that are accepted, Reclamation recommends conforming
changes be made to the pertinent language in the Canadian variance.
Likes
0
Dislikes
0
Response
Quintin Lee - Eversource Energy - 1
Answer
Yes
Document Name
Comment
Eversource has no opinion on the Canadian variance.
Likes
0
Dislikes
0
Response
Bobbi Welch - Midcontinent ISO, Inc. - 2 - MRO,SERC,RF
Answer
Yes
Document Name
Comment
MISO supports the comments submitted by the IRC SRC.
Likes
0
Dislikes
0
Response
Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee 2019-01
Modifications to TPL-007
Answer
Yes
Document Name
Comment
The Canadian member of the SRC agrees that the Canadian variance is written in a way that accommodates the regulatory process in Canada.
Likes
0
Dislikes
0
Response
Marty Hostler - Northern California Power Agency - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Dennis Sismaet - Northern California Power Agency - 6
Answer
Document Name
Comment
Yes
Likes
0
Dislikes
0
Response
Nick Batty - Keys Energy Services - NA - Not Applicable - SERC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Christopher Overberg - Con Ed - Consolidated Edison Co. of New York - 6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Frank Pace - Central Hudson Gas & Electric Corp. - 1,3
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Travis Chrest - South Texas Electric Cooperative - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Nick Batty - Keys Energy Services - 4
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
John Tolo - Unisource - Tucson Electric Power Co. - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Chantal Mazza - Hydro-Qu?bec TransEnergie - 1 - NPCC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Steve Arnold - City of Independence, Power and Light Department - 1,3,5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
James Mearns - Pacific Gas and Electric Company - 1,3,5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Lana Smith - San Miguel Electric Cooperative, Inc. - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - MRO,WECC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC
Answer
Yes
Document Name
Comment
Likes
Dislikes
0
0
Response
Leonard Kula - Independent Electricity System Operator - 2
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Standard Collaborations
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Anthony Jablonski - ReliabilityFirst - 10
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Anton Vu - Los Angeles Department of Water and Power - 6
Answer
Document Name
Yes
Comment
Likes
0
Dislikes
0
Response
Aaron Staley - Orlando Utilities Commission - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no NGrid and NYISO
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
Response
0
Aubrey Short - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE VOTER
Answer
Document Name
Comment
Not applicable to FirstEnergy.
Likes
0
Dislikes
0
Response
Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer
Document Name
Comment
N/A
Likes
0
Dislikes
0
Response
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer
Document Name
Comment
CHPD defers the response to this question to the Canadian provinces to determine if the Canadian variance is written to accommodate the regulatory
processes in Canada.
Likes
0
Dislikes
0
Response
Greg Davis - Georgia Transmission Corporation - 1
Answer
Document Name
Comment
GTC’s opinion is that this question should only be answered by Canadian entities.
Likes
0
Dislikes
0
Response
Eleanor Ewry - Puget Sound Energy, Inc. - 1,3,5
Answer
Document Name
Comment
PSE will abstain from answering this question
Likes
0
Dislikes
0
Response
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment
No comment
Likes
1
Dislikes
Snohomish County PUD No. 1, 3, Chaney Holly
0
Response
Andrea Barclay - Georgia System Operations Corporation - 3,4
Answer
Document Name
Comment
GSOC's opinion is that this question should only be answered by Canadian entities.
Likes
0
Dislikes
0
Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Document Name
Comment
“See EEI’s comments” on Modifications to TPL-007-3 – TPL-007-4 Transmission System Planned Performance for Geomagnetic Disturbance Events.
Likes
0
Dislikes
0
Response
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
Document Name
Comment
N/A
Likes
0
Dislikes
0
Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE does not have comments on this question.
Likes
0
Dislikes
0
Response
David Jendras - Ameren - Ameren Services - 3
Answer
Document Name
Comment
Ameren agrees with and supports EEI comments.
Likes
0
Dislikes
0
Response
Bette White - AES - Indianapolis Power and Light Co. - 3
Answer
Document Name
Comment
IPl is not in the Canadian district
Likes
0
Dislikes
0
Response
Rahn Petersen - PNM Resources - Public Service Company of New Mexico - 1 - WECC,Texas RE
Answer
Document Name
Comment
N/A
Likes
0
Dislikes
Response
0
4. Do you agree that the standard language changes in Requirement R7, R8, and R11 proposed by the SDT adequately address the directives
in FERC Order No. 851? If you disagree please explain and provide alternative language and rationale for how it meets the directive of the
order.
David Jendras - Ameren - Ameren Services - 3
Answer
No
Document Name
Comment
Ameren agrees with and supports EEI comments.
Likes
0
Dislikes
0
Response
Douglas Webb - Douglas Webb On Behalf of: Allen Klassen, Westar Energy, 6, 3, 1, 5; Bryan Taggart, Westar Energy, 6, 3, 1, 5; Derek Brown,
Westar Energy, 6, 3, 1, 5; Grant Wilkerson, Westar Energy, 6, 3, 1, 5; James McBee, Great Plains Energy - Kansas City Power and Light Co., 1,
3, 6, 5; Jennifer Flandermeyer, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; John Carlson, Great Plains Energy - Kansas
City Power and Light Co., 1, 3, 6, 5; Marcus Moor, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; - Douglas Webb, Group
Name Westar-KCPL
Answer
No
Document Name
Comment
Westar Energy and Kansas City Power & Light Company incorporate by reference and support comments submitted in response to Question 4 by the
Edison Electric Institute.
Likes
0
Dislikes
0
Response
Chris Scanlon - Exelon - 1
Answer
No
Document Name
Comment
As discussed in the response to Question 1, Exelon agrees that changes in Requirements R7, R8 and R11 meet the intent of the FERC directives, but
without a clear CAP Extension Process the changes cannot be supported at this time.
On Behalf of Exelon: Segments 1, 3, 5, 6
Likes
0
Dislikes
0
Response
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
No
Document Name
Comment
See response to Q2 above.
Likes
0
Dislikes
0
Response
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
No
Document Name
Comment
EEI supports the language in Requirements R7, R8 and R11 as proposed by the SDT believing that the changes conform to the directives contained in
Order 851. Nevertheless, we cannot support these changes as sufficient or complete at this time until a CAP Extension Request Review Process is
develop that ensure that key elements, as articulated in our response to Question 1, are addressed.
Likes
0
Dislikes
0
Response
Eric Shaw - Eric Shaw On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; - Eric Shaw
Answer
Document Name
Comment
Please see comments submitted by EEI.
No
Likes
0
Dislikes
0
Response
Sean Cavote - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer
No
Document Name
Comment
PSEG supports EEI's comments.
Likes
0
Dislikes
0
Response
Richard Jackson - U.S. Bureau of Reclamation - 1
Answer
No
Document Name
Comment
Reclamation recommends the language in Requirements R7 and R11 be combined into a single requirement addressing corrective action plans. Please
refer to the proposed language provided in the responses to Questions 1 and 2.
Likes
0
Dislikes
0
Response
Kenya Streeter - Edison International - Southern California Edison Company - 6
Answer
No
Document Name
Comment
See EEI's comments.
Likes
Dislikes
0
0
Response
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer
No
Document Name
Comment
CHPD does not agree with the directives in FERC Order No. 851 for “Corrective Action Plan Deadline Extensions” or “Corrective Action Plan for
Supplemental GMD Event Vulnerabilities” (see responses to questions 1 and 2). Therefore, CHPD does not agree the standard language changes in
Requirement R7, R8, and R11 proposed by the SDT.
Likes
5
Dislikes
Snohomish County PUD No. 1, 3, Chaney Holly; Public Utility District No. 1 of Snohomish County, 4,
Martinsen John; Snohomish County PUD No. 1, 6, Liang John; Public Utility District No. 1 of Snohomish
County, 1, Duong Long; Public Utility District No. 1 of Snohomish County, 5, Nietfeld Sam
0
Response
Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee 2019-01
Modifications to TPL-007
Answer
Yes
Document Name
Comment
The SRC agrees that the revisions to Requirements R7, R8, and R11 substantially satisfy FERC’s directives articulated in Order No. 851, and refers the
SDT to the comments provided in response to Question Nos. 1 and 2.
Likes
0
Dislikes
0
Response
Bobbi Welch - Midcontinent ISO, Inc. - 2 - MRO,SERC,RF
Answer
Yes
Document Name
Comment
MISO supports the comments submitted by the IRC SRC.
Likes
0
Dislikes
0
Response
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
The SDT has met the directive in Order 851.
BPA understands that the SDT had to respond with proposed changes to meet the directive. BPA believes requiring a corrective action plan for a
Supplemental GMD Event is unreasonable and imposes an unnecessary burden on transmission owners and operators.
BPA believes that mitigation strategies for GMD events and the ensuing geomagnetically induced currents would likely be considered novel and in the
Research and Development or prototype stages. As such, most devices or control/relay schemes that might be part of a corrective action plan could
increase operational complexity and a potential loss of system security. While attempting to mitigate the risk from a low frequency benchmark GMD
event, additional risk may be introduced which results in a net reduction in system security. Hence, there is caution from utilities and the industry in
general about mandating corrective action plans for schemes and devices that are not well developed and commonly deployed.
BPA supports the comments made by NERC, referenced in FERC’s Final Rule, issued on 11/15/18, Docket Nos. RM18-8-000 and RM15-11-003, Order
No. 851; paragraph 35, lines
1-12, which were unfortunately rejected by FERC. Excerpted below:
NERC’s comments reiterate the rationale in its petition that requiring mitigation
“would result in the de facto replacement of the benchmark GMD event with the
proposed supplemental GMD event.” 39 NERC maintains that “while the supplemental
GMD event is strongly supported by data and analysis in ways that mirror the benchmark
GMD event, there are aspects of it that are less definitive than the benchmark GMD event
and less appropriate as the basis of requiring Corrective Action Plans.”40 NERC also
claims that the uncertainty of geographic size of the supplemental GMD event could not
be addressed adequately by sensitivity analysis or through other methods because there
are “inherent sources of modeling uncertainty (e.g., earth conductivity model, substation
grounding grid resistance values, transformer thermal and magnetic response models) …
[and] introducing additional variables for sensitivity analysis, such as the size of the
localized enhancement, may not improve the accuracy of GMD Vulnerability Assessments.”41
39 Id. at 11-12; see also id. at 14 (“many entities would likely employ the most
conservative approach for conducting supplemental GMD Vulnerability Assessments,
which would be to apply extreme peak values uniformly over an entire planning area”).
40 Id. at 13.
41 Id. at 15.
Likes
5
Dislikes
Snohomish County PUD No. 1, 3, Chaney Holly; Public Utility District No. 1 of Snohomish County, 4,
Martinsen John; Snohomish County PUD No. 1, 6, Liang John; Public Utility District No. 1 of Snohomish
County, 1, Duong Long; Public Utility District No. 1 of Snohomish County, 5, Nietfeld Sam
0
Response
Bruce Reimer - Manitoba Hydro - 1
Answer
Yes
Document Name
Comment
The proposed language meets the FERC directive.
Likes
0
Dislikes
0
Response
Ayman Samaan - Edison International - Southern California Edison Company - 1
Answer
Yes
Document Name
Comment
my possible answer is NO.
Please see EEI's comments
Likes
0
Dislikes
0
Response
sean erickson - Western Area Power Administration - 1
Answer
Yes
Document Name
Comment
Yes, the proposed TPL-007-4 Requirements R7, R8, and R11 meets the directives of FERC Order No. 851.
However, FERC has not mandated the specific timetable proposed in Requirement R11, Part 11.3. Considering the 150% geoelectric field
enhancement reflected by the supplemental GMD event over the benchmark GMD event, we suggest that the Project 2019-01 SDT modify
Requirement R11, Parts 11.3.1 and 11.3.2 to three and six years, respectively.
Likes
0
Dislikes
0
Response
Neil Swearingen - Salt River Project - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
SRP has no comments for the standard drafting team.
Likes
0
Dislikes
0
Response
Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer
Yes
Document Name
Comment
None.
Likes
0
Dislikes
0
Response
Matthew Nutsch - Seattle City Light - 1,3,4,5,6 - WECC
Answer
Yes
Document Name
Comment
SCL agrees modifications to R7, R8, and R11 properly address the requirements in FERC Order 851 as noted under 1 and 2 above.
Likes
0
Dislikes
0
Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Rahn Petersen - PNM Resources - Public Service Company of New Mexico - 1 - WECC,Texas RE
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Bette White - AES - Indianapolis Power and Light Co. - 3
Answer
Document Name
Comment
Yes
Likes
0
Dislikes
0
Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no NGrid and NYISO
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Quintin Lee - Eversource Energy - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Aaron Staley - Orlando Utilities Commission - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Anton Vu - Los Angeles Department of Water and Power - 6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO, Group Name SPP Standards Review Group
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Anthony Jablonski - ReliabilityFirst - 10
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Andrea Barclay - Georgia System Operations Corporation - 3,4
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Standard Collaborations
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Scott McGough - Georgia System Operations Corporation - 3,4
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Keith Jonassen - Keith Jonassen On Behalf of: Michael Puscas, ISO New England, Inc., 2; - Keith Jonassen
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Eleanor Ewry - Puget Sound Energy, Inc. - 1,3,5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Greg Davis - Georgia Transmission Corporation - 1
Answer
Yes
Document Name
Comment
Likes
Dislikes
0
0
Response
Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - MRO,WECC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Lana Smith - San Miguel Electric Cooperative, Inc. - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
James Mearns - Pacific Gas and Electric Company - 1,3,5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Steve Arnold - City of Independence, Power and Light Department - 1,3,5
Answer
Document Name
Yes
Comment
Likes
0
Dislikes
0
Response
Chantal Mazza - Hydro-Qu?bec TransEnergie - 1 - NPCC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
John Tolo - Unisource - Tucson Electric Power Co. - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1,3,5,6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
Response
0
Nick Batty - Keys Energy Services - 4
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Travis Chrest - South Texas Electric Cooperative - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Frank Pace - Central Hudson Gas & Electric Corp. - 1,3
Answer
Document Name
Comment
Yes
Likes
0
Dislikes
0
Response
Christopher Overberg - Con Ed - Consolidated Edison Co. of New York - 6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Nick Batty - Keys Energy Services - NA - Not Applicable - SERC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
Response
0
Aubrey Short - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE VOTER
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Dennis Sismaet - Northern California Power Agency - 6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Marty Hostler - Northern California Power Agency - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Please see Texas RE’s answer to #1.
Likes
0
Dislikes
0
Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Document Name
Comment
“See EEI’s comments” on Modifications to TPL-007-3 – TPL-007-4 Transmission System Planned Performance for Geomagnetic Disturbance Events.
Likes
0
Dislikes
Response
0
5. Do you have any comments on the modified VRF/VSL for Requirements R7, R8, and R11?
Aubrey Short - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE VOTER
Answer
No
Document Name
Comment
No comments on the modified VRF/VSL for Requirements R7, R8 and R11
Likes
0
Dislikes
0
Response
Neil Swearingen - Salt River Project - 1,3,5,6 - WECC
Answer
No
Document Name
Comment
SRP has no comments for the standard drafting team.
Likes
0
Dislikes
0
Response
Ayman Samaan - Edison International - Southern California Edison Company - 1
Answer
No
Document Name
Comment
Please see EEI's comments
Likes
0
Dislikes
Response
0
Kenya Streeter - Edison International - Southern California Edison Company - 6
Answer
No
Document Name
Comment
See EEI's comments.
Likes
0
Dislikes
0
Response
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
No
Document Name
Comment
No comment
Likes
5
Dislikes
Snohomish County PUD No. 1, 3, Chaney Holly; Public Utility District No. 1 of Snohomish County, 4,
Martinsen John; Snohomish County PUD No. 1, 6, Liang John; Public Utility District No. 1 of Snohomish
County, 1, Duong Long; Public Utility District No. 1 of Snohomish County, 5, Nietfeld Sam
0
Response
David Jendras - Ameren - Ameren Services - 3
Answer
No
Document Name
Comment
Ameren agrees with and supports EEI comments.
Likes
0
Dislikes
0
Response
Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee 2019-01
Modifications to TPL-007
Answer
No
Document Name
Comment
None.
Likes
0
Dislikes
0
Response
Marty Hostler - Northern California Power Agency - 5
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Dennis Sismaet - Northern California Power Agency - 6
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Nick Batty - Keys Energy Services - NA - Not Applicable - SERC
Answer
Document Name
Comment
No
Likes
0
Dislikes
0
Response
Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
sean erickson - Western Area Power Administration - 1
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Christopher Overberg - Con Ed - Consolidated Edison Co. of New York - 6
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer
No
Document Name
Comment
Likes
5
Dislikes
Snohomish County PUD No. 1, 3, Chaney Holly; Public Utility District No. 1 of Snohomish County, 4,
Martinsen John; Snohomish County PUD No. 1, 6, Liang John; Public Utility District No. 1 of Snohomish
County, 1, Duong Long; Public Utility District No. 1 of Snohomish County, 5, Nietfeld Sam
0
Response
Frank Pace - Central Hudson Gas & Electric Corp. - 1,3
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Travis Chrest - South Texas Electric Cooperative - 1
Answer
Document Name
Comment
No
Likes
0
Dislikes
0
Response
Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Nick Batty - Keys Energy Services - 4
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1,3,5,6
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
John Tolo - Unisource - Tucson Electric Power Co. - 1
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Bruce Reimer - Manitoba Hydro - 1
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Chantal Mazza - Hydro-Qu?bec TransEnergie - 1 - NPCC
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
James Mearns - Pacific Gas and Electric Company - 1,3,5
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - MRO,WECC
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Greg Davis - Georgia Transmission Corporation - 1
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Eleanor Ewry - Puget Sound Energy, Inc. - 1,3,5
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Deanna Carlson - Cowlitz County PUD - 5
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Keith Jonassen - Keith Jonassen On Behalf of: Michael Puscas, ISO New England, Inc., 2; - Keith Jonassen
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Scott McGough - Georgia System Operations Corporation - 3,4
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Standard Collaborations
Answer
No
Document Name
Comment
Likes
Dislikes
0
0
Response
Andrea Barclay - Georgia System Operations Corporation - 3,4
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO, Group Name SPP Standards Review Group
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Anton Vu - Los Angeles Department of Water and Power - 6
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6
Answer
Document Name
No
Comment
Likes
0
Dislikes
0
Response
Aaron Staley - Orlando Utilities Commission - 1
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Sean Cavote - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Eric Shaw - Eric Shaw On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; - Eric Shaw
Answer
No
Document Name
Comment
Likes
0
Dislikes
Response
0
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
No
Likes
0
Dislikes
0
Response
Quintin Lee - Eversource Energy - 1
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no NGrid and NYISO
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Bobbi Welch - Midcontinent ISO, Inc. - 2 - MRO,SERC,RF
Answer
No
Document Name
Comment
Likes
0
Dislikes
Response
0
Bette White - AES - Indianapolis Power and Light Co. - 3
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Rahn Petersen - PNM Resources - Public Service Company of New Mexico - 1 - WECC,Texas RE
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Matthew Nutsch - Seattle City Light - 1,3,4,5,6 - WECC
Answer
Document Name
Comment
Yes
SCL agrees with the descriptions of VRF/VSL in the standard for requirements R7, R8, and R11.
Likes
0
Dislikes
0
Response
Richard Jackson - U.S. Bureau of Reclamation - 1
Answer
Yes
Document Name
Comment
Reclamation recommends combining R7 and R11. For consistency, Reclamation also recommends the VRF/VSL for these requirements be combined.
Likes
0
Dislikes
0
Response
Steve Arnold - City of Independence, Power and Light Department - 1,3,5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Lana Smith - San Miguel Electric Cooperative, Inc. - 5
Answer
Yes
Document Name
Comment
Likes
Dislikes
0
0
Response
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Anthony Jablonski - ReliabilityFirst - 10
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Document Name
Comment
“See EEI’s comments” on Modifications to TPL-007-3 – TPL-007-4 Transmission System Planned Performance for Geomagnetic Disturbance Events.
Likes
0
Dislikes
Response
0
6. Do you agree with the proposed Implementation Plan? If you think an alternate, shorter or longer implementation time period is needed,
please propose an alternate implementation plan and time period, and provide a detailed explanation of actions planned to meet the
implementation deadline.
Richard Jackson - U.S. Bureau of Reclamation - 1
Answer
No
Document Name
Comment
Continuing with a previous standard’s implementation plan causes confusion, misunderstandings, and the increased potential for missed deadlines.
Reclamation recommends retiring the implementation plans for previous versions of TPL-007 and creating a new implementation plan for TPL-007-4 so
there is only one implementation plan to work toward.
Likes
0
Dislikes
0
Response
Kenya Streeter - Edison International - Southern California Edison Company - 6
Answer
No
Document Name
Comment
See EEI's comments.
Likes
0
Dislikes
0
Response
Bruce Reimer - Manitoba Hydro - 1
Answer
No
Document Name
Comment
The implementation plan is likely long enough but does it make sense to have a standard in place that won’t be effective for several years? Based on
Canadian Law, when a standard is adopted it becomes immediately effective.
Likes
0
Dislikes
0
Response
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer
No
Document Name
Comment
CHPD does not agree with requiring a CAP for supplemental GMD event (TPL-007-4 R11). Therefore, CHPD does not agree with the implementation
plan which requires compliance with R11.
Likes
5
Dislikes
Snohomish County PUD No. 1, 3, Chaney Holly; Public Utility District No. 1 of Snohomish County, 4,
Martinsen John; Snohomish County PUD No. 1, 6, Liang John; Public Utility District No. 1 of Snohomish
County, 1, Duong Long; Public Utility District No. 1 of Snohomish County, 5, Nietfeld Sam
0
Response
Deanna Carlson - Cowlitz County PUD - 5
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee 2019-01
Modifications to TPL-007
Answer
Yes
Document Name
Comment
None.
Likes
Dislikes
0
0
Response
David Jendras - Ameren - Ameren Services - 3
Answer
Yes
Document Name
Comment
Ameren agrees with and supports EEI comments.
Likes
0
Dislikes
0
Response
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
No comment
Likes
5
Dislikes
Snohomish County PUD No. 1, 3, Chaney Holly; Public Utility District No. 1 of Snohomish County, 4,
Martinsen John; Snohomish County PUD No. 1, 6, Liang John; Public Utility District No. 1 of Snohomish
County, 1, Duong Long; Public Utility District No. 1 of Snohomish County, 5, Nietfeld Sam
0
Response
Ayman Samaan - Edison International - Southern California Edison Company - 1
Answer
Yes
Document Name
Comment
Please see EEI's comments
Likes
0
Dislikes
Response
0
sean erickson - Western Area Power Administration - 1
Answer
Yes
Document Name
Comment
Yes, the proposed TPL-007-4 Implementation Plan is consistent; essentially no TPL-007-3 Compliance Dates are changed, except for the modified
Requirements R7 and R11 (Requirement R8 proposed changes are trivial). Given the expectation of a rapid FERC approval process, the 01 January
2024 Compliance Dates to develop corrective actions for the supplemental GMD event are reasonable.
Likes
0
Dislikes
0
Response
Neil Swearingen - Salt River Project - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
SRP has no comments for the standard drafting team.
Likes
0
Dislikes
0
Response
Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer
Yes
Document Name
Comment
None.
Likes
0
Dislikes
Response
0
Matthew Nutsch - Seattle City Light - 1,3,4,5,6 - WECC
Answer
Yes
Document Name
Comment
SCL agrees with the impmentation plan for R7, R8, and R11. However, SCL would like to see a later effective date for R12 and R13 or clear guidelines
on how to monitor and collect GIC from at least one GIC monitor located in the Planning Coordinator’s area.
Likes
0
Dislikes
0
Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Rahn Petersen - PNM Resources - Public Service Company of New Mexico - 1 - WECC,Texas RE
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Bette White - AES - Indianapolis Power and Light Co. - 3
Answer
Document Name
Yes
Comment
Likes
0
Dislikes
0
Response
Bobbi Welch - Midcontinent ISO, Inc. - 2 - MRO,SERC,RF
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no NGrid and NYISO
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Quintin Lee - Eversource Energy - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
Response
0
Douglas Webb - Douglas Webb On Behalf of: Allen Klassen, Westar Energy, 6, 3, 1, 5; Bryan Taggart, Westar Energy, 6, 3, 1, 5; Derek Brown,
Westar Energy, 6, 3, 1, 5; Grant Wilkerson, Westar Energy, 6, 3, 1, 5; James McBee, Great Plains Energy - Kansas City Power and Light Co., 1,
3, 6, 5; Jennifer Flandermeyer, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; John Carlson, Great Plains Energy - Kansas
City Power and Light Co., 1, 3, 6, 5; Marcus Moor, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; - Douglas Webb, Group
Name Westar-KCPL
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Eric Shaw - Eric Shaw On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; - Eric Shaw
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Sean Cavote - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Aaron Staley - Orlando Utilities Commission - 1
Answer
Yes
Document Name
Comment
Likes
Dislikes
0
0
Response
Anton Vu - Los Angeles Department of Water and Power - 6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO, Group Name SPP Standards Review Group
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Anthony Jablonski - ReliabilityFirst - 10
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Andrea Barclay - Georgia System Operations Corporation - 3,4
Answer
Document Name
Yes
Comment
Likes
0
Dislikes
0
Response
Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Standard Collaborations
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Scott McGough - Georgia System Operations Corporation - 3,4
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Keith Jonassen - Keith Jonassen On Behalf of: Michael Puscas, ISO New England, Inc., 2; - Keith Jonassen
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
Response
0
Eleanor Ewry - Puget Sound Energy, Inc. - 1,3,5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Greg Davis - Georgia Transmission Corporation - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - MRO,WECC
Answer
Document Name
Comment
Yes
Likes
0
Dislikes
0
Response
Lana Smith - San Miguel Electric Cooperative, Inc. - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
James Mearns - Pacific Gas and Electric Company - 1,3,5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Steve Arnold - City of Independence, Power and Light Department - 1,3,5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
Response
0
Chantal Mazza - Hydro-Qu?bec TransEnergie - 1 - NPCC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
John Tolo - Unisource - Tucson Electric Power Co. - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1,3,5,6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Nick Batty - Keys Energy Services - 4
Answer
Document Name
Comment
Yes
Likes
0
Dislikes
0
Response
Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Travis Chrest - South Texas Electric Cooperative - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Frank Pace - Central Hudson Gas & Electric Corp. - 1,3
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Christopher Overberg - Con Ed - Consolidated Edison Co. of New York - 6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Nick Batty - Keys Energy Services - NA - Not Applicable - SERC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Aubrey Short - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE VOTER
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Dennis Sismaet - Northern California Power Agency - 6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Marty Hostler - Northern California Power Agency - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE noticed that TPL-007-3 is incorrectly referenced on page 1 of the Implementation Plan.
Likes
0
Dislikes
0
Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Document Name
Comment
“See EEI’s comments” on Modifications to TPL-007-3 – TPL-007-4 Transmission System Planned Performance for Geomagnetic Disturbance Events.
Likes
0
Dislikes
Response
0
7. The SDT proposes that the modifications in TPL-007-4 meet the FERC directives in a cost effective manner. Do you agree? If you do not
agree, or if you agree but have suggestions for improvement to enable more cost effective approaches, please provide your recommendation
and, if appropriate, technical or procedural justification.
Thomas Foltz - AEP - 5
Answer
No
Document Name
Comment
TPL-007-4, in contrast to the majority of standards established by NERC, GMD Vulnerability Assessments are not representative of an existing utility
practice. This is highlighted by the fact that there is a deficit of modeling tools available that would enable an entity to comply with the requirements
specified herein. The burden of expenses relative to CAPs has yet to be established because there are very few examples of vulnerability assessments
that have been completed for either the benchmark or the supplemental GMD events. In essence, the science to prudently study and assess system
vulnerabilities related to a High Impact, Low Frequency (HILF) event on the system is not conclusive and still subjective. In short, the obligations have
come before the development of proven modeling tools and mitigation techniques. Once again, AEP believes that R11 is unnecessarily duplicative of
the obligations already required for the benchmark event, and as such, we do not believe it to be cost effective. Those resources would be better
served for efforts having a discernable, positive impact on the reliability of the BES. Rather than pursuing this course, we believe a more prudent path,
as well as a more cost effective path, would be as we propose in our response to Q1.
Likes
0
Dislikes
0
Response
sean erickson - Western Area Power Administration - 1
Answer
No
Document Name
Comment
No, we do not agree that the modifications in TPL-007-4 meet the FERC directives in a cost effective manner; the imposition of Requirement R11, Parts
11.3.1 and 11.3.2 deadlines for corrective action implementation are too short thereby escalating costs. We echo industry comments made during
previous modifications to TPL-007-1: FERC opened the door for NERC to propose alternatives to the two- and four-year implementation of corrective
actions (FERC Order No. 830, Paragraph 97); FERC was clearly persuaded by device manufacturers over the concerns of utility commenters that
mitigation deadlines were impractical (FERC Order No. 830, Paragraph 102). This was particularly problematic because the hardware solutions that
existed then, as well as today, remain widely unproven (only one implementation in the continental United States) and are simply not suitable for highly
networked Systems (blocking GICs pushes the problem onto neighbors). Given that FERC has directed corrective actions and implementation
deadlines, as well as facilitated time extensions, the cost-effectiveness of the proposed TPL-007-4 would be enhanced by including a section in the
Technical Rationale that discusses how and when time extensions are reasonable. Examples could include a treatment of how to navigate the
challenges of formulating appropriate joint-mitigations with neighbors to address widespread GMD impacts and how, during the process of mitigation
implementation, unexpected System impacts may arise that delay completion.
Likes
0
Dislikes
0
Response
Christopher Overberg - Con Ed - Consolidated Edison Co. of New York - 6
Answer
No
Document Name
Comment
Requirements 7.3, 7.4, 11.3, and 11.4 should be revised to require extension request submittals be made to the entity’s Reliability Coordinator (RC), not
the ERO. The RC has the wide-area view, analysis tools, models and data necessary to ensure that extension requests are effectively evaluated. It is
unlikely that the ERO will have the necessary information to assess the extension request, and the ERO and will seek RC concurrence in order to
adequately respond to an extension request. This adds multiple steps and inefficiencies into the extension request process. The Requirements 7.3, 7.4,
11.3, and 11.4 should stipulate that extension requests are submitted to the RC for approval. This is a more appropriate and cost-effective approach to
addressing the requests.
Likes
0
Dislikes
0
Response
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer
No
Document Name
Comment
The industry is in the preliminary stages of assessing and developing mitigation measures for GMD events and has not had much time to develop
engineering-judgement, experience, or expertise in this field. Revising the standard to include CAPs for the supplementary GMD event is not
appropriate at this time as the industry is still building a foundation for this type of system event analysis and exploring mitigation measures. Without a
sound foundation developed, requiring CAPs for the supplemental GMD event could lead to unnecessary mitigation measures and an immense amount
of industry resources spent on a still developing science. CHPD suggests that the benchmark GMD event be fully vetted before moving onto additional
scenarios such as the supplemental event.
Likes
5
Dislikes
Snohomish County PUD No. 1, 3, Chaney Holly; Public Utility District No. 1 of Snohomish County, 4,
Martinsen John; Snohomish County PUD No. 1, 6, Liang John; Public Utility District No. 1 of Snohomish
County, 1, Duong Long; Public Utility District No. 1 of Snohomish County, 5, Nietfeld Sam
0
Response
Bruce Reimer - Manitoba Hydro - 1
Answer
No
Document Name
Comment
The proposed changes mandates implementation of a Corrective Action Plan for the supplemental GMD event (12 V/km). The research into this type of
disturbance is still evolving. The available tools do not support studying this disturbance at this time. The tools available would allow for a uniform field
over the entire planning Coordinator area. If this field is increased from 8 V/km to 12 V/km that corresponds to a disturbance well in excess of the 1/100
year level suggested by the benchmark. This is not just and reasonable. Let TPL-007-2 run through its first cycle of studies and review the assessment
results. Perhaps the next cycle of studies could evolve to the proposed wording in TPL-007-4 once the research and tools have matured and an
assessment of the potential costs have been tabulated to address the supplemental event.
Likes
0
Dislikes
0
Response
Kenya Streeter - Edison International - Southern California Edison Company - 6
Answer
No
Document Name
Comment
See EEI's comments.
Likes
0
Dislikes
0
Response
Eleanor Ewry - Puget Sound Energy, Inc. - 1,3,5
Answer
No
Document Name
Comment
It is difficult to assess the exact financial impacts of the requirements in this standard.
may not be cost effective.
Likes
0
Dislikes
Response
0
The addition of CAP for Supplementary GMD event may or
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
No
Document Name
Comment
BPA agrees that the SDT satisfied its obligation to modify TPL-007 to meet the directives in FERC Order No. 851.
BPA can not determine if the directives are cost effective. The modifications are requiring a corrective action plan for an extreme event (Supplemental
GMD event). The Transmission Planners and Transmission Owners have not done the analysis to determine the impact and the cost of the corrective
action plans that would be required. BPA believes without this analysis, the cost effectiveness can not be determined.
BPA believes that assessing the event and performing an evaluation of possible actions to reduce the likelihood of the impact is more appropriate than
requiring a Supplemental GMD event corrective action plan.
Likes
5
Dislikes
Snohomish County PUD No. 1, 3, Chaney Holly; Public Utility District No. 1 of Snohomish County, 4,
Martinsen John; Snohomish County PUD No. 1, 6, Liang John; Public Utility District No. 1 of Snohomish
County, 1, Duong Long; Public Utility District No. 1 of Snohomish County, 5, Nietfeld Sam
0
Response
Russell Noble - Cowlitz County PUD - 3
Answer
No
Document Name
Comment
We are concerned the cost and effort to address this standard could hinder other more important Transmission improvements.
Likes
0
Dislikes
0
Response
Joe O'Brien - NiSource - Northern Indiana Public Service Co. - 6
Answer
No
Document Name
Comment
Comments: See comments on Question 2
Likes
0
Dislikes
0
Response
Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Standard Collaborations
Answer
No
Document Name
Comment
If unintended duplication of efforts between baseline and supplemental corrective action plans occurs, as referenced in the response to question 2, that
would lead to unnecessary increases in costs to registered entities. Please reference the suggestion in our response to question 2.
Likes
0
Dislikes
0
Response
Richard Jackson - U.S. Bureau of Reclamation - 1
Answer
No
Document Name
Comment
For the implementation of numerous, overlapping versions of the same standard (such as the implementation of TPL-007-2, TPL-007-3, and TPL-007-4)
with lengthy phased-in implementation timelines, Reclamation supports the incorporation of insignificant subsequent modifications (such as the changes
from TPL-007-2 to TPL-007-3 to TPL-007-4) in accordance with existing phased-in implementation milestones, but recommends that all previous
implementation plans be retired so that there is only one implementation plan in effect at a time.
Likes
0
Dislikes
0
Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO, Group Name SPP Standards Review Group
Answer
No
Document Name
Comment
The SPP Standards Review Group (SSRG) has no concerns to cost effective issues from a Planning Coordinator (PC) perspective, however, from the
SPP membership perspective, the imposition of Requirement R11, Parts 11.3.1 and 11.3.2 deadlines for corrective action implementation are
short, thereby escalating costs over two and four years. This timeframe could create issues for hardware solutions.
Given that FERC has directed corrective actions and implementation deadlines, as well as facilitated time extensions, the cost-effectiveness of the
proposed TPL-007-4 would be enhanced by including a section in the Technical Rationale that discusses how and when time extensions are
reasonable. Examples could include a treatment of how to navigate the challenges of formulating appropriate joint-mitigations with neighbors to
address widespread GMD impacts and how, during the process of mitigation implementation, unexpected System impacts may arise that delay
completion.
Likes
0
Dislikes
0
Response
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
No
Document Name
Comment
TVA supports comments submitted by AEP for Question #7
Likes
0
Dislikes
0
Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no NGrid and NYISO
Answer
No
Document Name
Comment
Requirements 7.3, 7.4, 11.3, and 11.4 should be revised to require extension request submittals be made to the entity’s Planning Coordinator (PC), not
the ERO. The PC has the wide-area view, analysis tools, models and data necessary to ensure that extension requests are effectively evaluated. It is
unlikely that the ERO will have the necessary information to assess the extension request, and the ERO and will seek PC concurrence in order to
adequately respond to an extension request. This adds multiple steps and inefficiencies into the extension request process. The Requirements 7.3, 7.4,
11.3, and 11.4 should stipulate that extension requests are submitted to the PC for approval. This is a more appropriate and cost-effective approach to
addressing the requests.
Likes
0
Dislikes
0
Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
No
Document Name
Comment
OPG concurs with the RSC comment
Likes
0
Dislikes
0
Response
Deanna Carlson - Cowlitz County PUD - 5
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Matthew Nutsch - Seattle City Light - 1,3,4,5,6 - WECC
Answer
Yes
Document Name
Comment
SCL agrees; however, it is difficult to assess the true financial impacts of the requirements in this standard to SCL at this early stage. The modifications
in the standard may or may not be cost-effective to SCL.
Likes
0
Dislikes
0
Response
Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer
Document Name
Yes
Comment
None.
Likes
0
Dislikes
0
Response
Neil Swearingen - Salt River Project - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
SRP has no comments for the standard drafting team.
Likes
0
Dislikes
0
Response
Ayman Samaan - Edison International - Southern California Edison Company - 1
Answer
Yes
Document Name
Comment
Please see EEI's comments
Likes
0
Dislikes
0
Response
Bette White - AES - Indianapolis Power and Light Co. - 3
Answer
Document Name
Comment
Yes
NERC should evaluate the relative event probabilities with respect to the cost/benefit analysis of GMD event mitigations. Planning for increasingly rare
system events is inherently at odds with economic planning and rate payer responsibilities.
Likes
0
Dislikes
0
Response
Marty Hostler - Northern California Power Agency - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Dennis Sismaet - Northern California Power Agency - 6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Aubrey Short - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE VOTER
Answer
Yes
Document Name
Comment
Likes
Dislikes
0
0
Response
Nick Batty - Keys Energy Services - NA - Not Applicable - SERC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Frank Pace - Central Hudson Gas & Electric Corp. - 1,3
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Travis Chrest - South Texas Electric Cooperative - 1
Answer
Document Name
Yes
Comment
Likes
0
Dislikes
0
Response
Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Nick Batty - Keys Energy Services - 4
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1,3,5,6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
Response
0
John Tolo - Unisource - Tucson Electric Power Co. - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Chantal Mazza - Hydro-Qu?bec TransEnergie - 1 - NPCC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Steve Arnold - City of Independence, Power and Light Department - 1,3,5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
James Mearns - Pacific Gas and Electric Company - 1,3,5
Answer
Document Name
Comment
Yes
Likes
0
Dislikes
0
Response
Lana Smith - San Miguel Electric Cooperative, Inc. - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - MRO,WECC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Greg Davis - Georgia Transmission Corporation - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
Response
0
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Scott McGough - Georgia System Operations Corporation - 3,4
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Andrea Barclay - Georgia System Operations Corporation - 3,4
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Anthony Jablonski - ReliabilityFirst - 10
Answer
Document Name
Comment
Yes
Likes
0
Dislikes
0
Response
Anton Vu - Los Angeles Department of Water and Power - 6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Aaron Staley - Orlando Utilities Commission - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Rahn Petersen - PNM Resources - Public Service Company of New Mexico - 1 - WECC,Texas RE
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Keith Jonassen - Keith Jonassen On Behalf of: Michael Puscas, ISO New England, Inc., 2; - Keith Jonassen
Answer
Document Name
Comment
More experience with implementing the standard is required in order to better understand the implications on its cost-effectiveness.
Likes
0
Dislikes
0
Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Document Name
Comment
“See EEI’s comments” on Modifications to TPL-007-3 – TPL-007-4 Transmission System Planned Performance for Geomagnetic Disturbance Events.
Likes
0
Dislikes
0
Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE does not have comments on this question.
Likes
0
Dislikes
0
Response
David Jendras - Ameren - Ameren Services - 3
Answer
Document Name
Comment
Ameren agrees with and supports EEI comments.
Likes
0
Dislikes
0
Response
Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee 2019-01
Modifications to TPL-007
Answer
Document Name
Comment
No response.
Likes
0
Dislikes
Response
0
8. Provide any additional comments for the standard drafting team to consider, if desired.
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Document Name
Comment
OPG concurs with the RSC comment
Likes
0
Dislikes
0
Response
Rahn Petersen - PNM Resources - Public Service Company of New Mexico - 1 - WECC,Texas RE
Answer
Document Name
Comment
Nothing further
Likes
0
Dislikes
0
Response
Bette White - AES - Indianapolis Power and Light Co. - 3
Answer
Document Name
Comment
Thank you for the opportunity to comment.
Likes
0
Dislikes
Response
0
Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee 2019-01
Modifications to TPL-007
Answer
Document Name
Comment
In Requirements R7 and R11, the SRC suggests replacing “their” with “its” just prior to the first mention of “System” for grammatical reasons.
Likes
0
Dislikes
0
Response
Bobbi Welch - Midcontinent ISO, Inc. - 2 - MRO,SERC,RF
Answer
Document Name
Comment
MISO supports the comments submitted by the IRC SRC. In addition, MISO would like to propose a clarification to requirement R6, part 6.4.
As written, the Transmission Owner and Generator Owner functions referenced under TPL-007-4, requirement R6, Part 6.4 are not functions that are
included in the identification of the individual and joint responsibilities under TPL-007-4, requirement R1. As a result, when the Planning Coordinator, in
conjunction with its Transmission Planner(s) identifies the individual and joint responsibilities, the Transmission Owner and Generator Owner are not
party to this information and so would not know who to provide the results to.
In addition, there is no provision under R1 that requires the Planning Coordinator to determine or communicate who applicable Transmission Owners
(section 4.1.3) and Generator Owners (section 4.1.4) within its area should send the results of their benchmark thermal impact assessment to.
MISO became aware of this gap following an inquiry from a transformer owner when they did not know where to send the results.
Possible remedies:
1)
Modify Requirement R6, Part 6.4 to reference Requirement 5, i.e. “Be performed and provided to the responsible entity(ies) that provided the
GIC flow information in accordance with Requirement 5, within 24…
2)
Clarify the scope of requirement Require R1 to specify that the Planning Coordinator in conjunction with its Transmission Planner(s) determine
which responsible entity(ies) applicable Transmission Owner(s) and Generator Owner(s) in their area should send the results of their benchmark
thermal impact assessment(s) to.
Likes
0
Dislikes
0
Response
David Jendras - Ameren - Ameren Services - 3
Answer
Document Name
Comment
Ameren agrees with and supports EEI comments.
Likes
0
Dislikes
0
Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no NGrid and NYISO
Answer
Document Name
Comment
The Implementation Guidance document, as written, is not acceptable. Boundaries cannot be established with a CMEP Implementation Guidance
document. CMEP Implementation Guidance is a means to identify one approach to being compliant while not precluding the use of other
approaches. Auditors audit to requirements and don’t use CMEP Implementation Guidance to establish requirements which go beyond the standard’s
requirements. Problematic statements appearing in Chapter 8 of the document include, but may not be limited to, the following:
•
“The local geoelectric field enhancement should not be smaller than 100 km..”- this threshold value of 100 km does not appear in the
standard requirement
•
“…at a minimum, a West-East orientation should be considered when applying the supplemental event”- the standard requirement does not
contain any wording of a minimum consideration
•
“Geoelectric field outside the local enhancement:
a. Amplitude: should not be smaller than 1.2 V/km…” This also does not appear in the standard.
•
“The schematic in Figure 1 illustrates the boundaries to apply the supplemental GMD event”. This statement creates boundaries outside of
requirements, which guidance cannot do
The use of “shall” or “must” should not be used unless they are being used in the requriements in the standard. This is particularly true for the
requirement associated with sensitive/confidential information. It is not in the standard and was added in the IG as an additional “requirement”.
Likes
0
Dislikes
Response
0
Douglas Webb - Douglas Webb On Behalf of: Allen Klassen, Westar Energy, 6, 3, 1, 5; Bryan Taggart, Westar Energy, 6, 3, 1, 5; Derek Brown,
Westar Energy, 6, 3, 1, 5; Grant Wilkerson, Westar Energy, 6, 3, 1, 5; James McBee, Great Plains Energy - Kansas City Power and Light Co., 1,
3, 6, 5; Jennifer Flandermeyer, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; John Carlson, Great Plains Energy - Kansas
City Power and Light Co., 1, 3, 6, 5; Marcus Moor, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; - Douglas Webb, Group
Name Westar-KCPL
Answer
Document Name
Comment
Westar Energy and Kansas City Power & Light Company incorporate by reference and support comments submitted in response to Question 8 by the
Edison Electric Institute.
Likes
0
Dislikes
0
Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE recommends that TPL-007-4 be consistent with other standards that require data to be submitted from the applicable entities to the Regional
Entity. Reliability Standards FAC-003-4, EOP-008-2 Requirement R8, and PRC-002-2 Requirement R12 explicitly state the data shall be submitted to
the Regional Entity in the requirement language or in Part C. Compliance section of the standard. There is no need for an extraneous process
document describing where to submit the information.
Texas RE is concerned with introducing a separate process document for submitting CAP extension requests for the following reasons: the document
would not be FERC approved, how would entities and regions know that it exists, where would it be housed, etc. Registered entities should not have to
look beyond the standard in order to understand how to comply with a requirement.
Likes
0
Dislikes
0
Response
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Document Name
Comment
•
•
R7.1 (page 6 of TPL-007-4 clean draft):
o
The portion of this sub-requirement starting from “Examples include:” should be moved to the Implementation Guidance, as the bullet
point list’s purpose is more in line with the stated purpose of the Guidance. Consider updating R11.1 as well.
o
To this end, Page iii of Implementation Guidance Document needs to be updated to reflect new SERC region.
Consider deleting the four references to Attachment 1 in the Draft Technical Rationale document (Draft Tech Rationale_TPL-007-4.pdf).
Likes
0
Dislikes
0
Response
Julie Hall - Entergy - 6, Group Name Entergy
Answer
Document Name
Comment
Entergy supports comments submitted by EEI.
Likes
0
Dislikes
0
Response
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
EEI acknowledges and supports the good work by the SDT in support of this Reliability Standard believing that it conforms to the directives issued in
FERC Order 851. We also recognize that the supporting/companion ERO process document simply represents an initial draft of the Extension Request
Process. Nevertheless, the process of CAP extention reviews and approvals are inextricably tied to the modification of this standard. For this reason
and as stated in more detail in our response to Question 1, this companion process document needs to include additional details to ensure effective and
transparent processing of entity CAP Extension Requests. The process should also be formally codified in parallel with the required revisions to this
Reliability Standard.
Likes
Dislikes
0
0
Response
Eric Shaw - Eric Shaw On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; - Eric Shaw
Answer
Document Name
Comment
Please see comments submitted by EEI.
Likes
0
Dislikes
0
Response
Sean Cavote - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer
Document Name
Comment
PSEG supports EEI's comments.
Likes
0
Dislikes
0
Response
Aaron Staley - Orlando Utilities Commission - 1
Answer
Document Name
Comment
With the change that the Benchmark and Supplimental analysis both require a CAP, shouldn't they be consolidated into a single study effort to reduce
the overall number of requirements? The Supplimental seems to only be a Benchmark with additional areas of increased field strength, unless I am
missing some nuiance in how they are performed?
Likes
0
Dislikes
0
Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Document Name
Comment
“See EEI’s comments” on Modifications to TPL-007-3 – TPL-007-4 Transmission System Planned Performance for Geomagnetic Disturbance Events.
Likes
0
Dislikes
0
Response
Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6
Answer
Document Name
Comment
No comments.
Likes
0
Dislikes
0
Response
Anton Vu - Los Angeles Department of Water and Power - 6
Answer
Document Name
Comment
What was the rationale behind removing the Supplemental Material? It provided some background information and sources that could be
useful for understanding the practicality of the requirement.
Likes
0
Dislikes
0
Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO, Group Name SPP Standards Review Group
Answer
Document Name
Comment
Comments:
1. The language in Requirement 7.4 doesn’t properly align with the FERC Directive on who should be approving the extensions. The FERC
directive doesn’t clearly state that the ERO should be the entity approving the extension. We recommend the drafting team consider revising
their proposed language to include “ERO, or its delegated designee.” This modification will allow regional entities or other designees to better
adjudicate CAP time extensions given their close proximity, System expertise, and existing compliance program obligations.
2. The proposed language in Requirement R11 Part 11.3 doesn’t align with the FERC directive in reference to the duration of the Implementation
of the CAP. The FERC directive doesn’t clarify a specific time frame pertaining to the Implementation of the CAPs. Recommend the drafting
team consider revising their proposed language for Requirement R11.3 Parts 11.3.1 and 11.3.2 to include an implementation timeframe of
three (3) and six (6) years respectively.
3. The SSRG recommends that the drafting team considers including more technical language in the Technical Rationale document, explaining
how/why the drafting team came to their conclusions to revising these particular requirements. The document doesn’t provide technical
reasoning the drafting team developed or revised this requirement. Chapters 7, 8, and 11 are general, and have no technical information
explaining the drafting team’s actions.
4. The SSRG recommends the drafting team consider implementing all the redlines changes to the RSAW that have been identified in the other
documents to promote consistency throughout their documentation process.
Likes
0
Dislikes
0
Response
Anthony Jablonski - ReliabilityFirst - 10
Answer
Document Name
Comment
ReliabilityFirst has identified a change in Requirement R1 that was not captured in the redline. When Requirement R1 was copied over to TPL-007-4,
the SDT dropped the word “area” from the requirement. As is, the Requirement does not seem to make sence. Please note (in bold text) the updated
requirement below:
Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall identify the individual and joint responsibilities of the Planning
Coordinator and Transmission Planner(s) in the Planning Coordinator’s planning area for maintaining models, performing the study or studies needed to
complete benchmark and supplemental GMD Vulnerability Assessments, and implementing process(es) to obtain GMD measurement data as specified
in this standard.
Likes
0
Dislikes
0
Response
Andrea Barclay - Georgia System Operations Corporation - 3,4
Answer
Document Name
Comment
The only difference between R.4 through R.7 and R.8 through R.11 is the threshold for the maximum effective GIC value (75 A for the Benchmark GMD
Event, and 85 A for the Supplemental GMD event). Based on this fact, the number of requirements in the standard could be reduced, if R.4 through R.7
and R.8 through R.11 were combined.
Likes
0
Dislikes
0
Response
Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Standard Collaborations
Answer
Document Name
Comment
Thank you for the opportunity to comment. ACES appreciates the efforts of drafting team members and NERC staff in continuing to enhance the
standards for the benefit of reliability of the BES.
Likes
0
Dislikes
0
Response
Scott McGough - Georgia System Operations Corporation - 3,4
Answer
Document Name
Comment
The only difference between R.4 through R.7 and R.8 through R.11 is the threshold for the maximum effective GIC value (75 A for the Benchmark GMD
Event, and 85 A for the Supplemental GMD event). Based on this fact, the number of requirements in the standard could be reduced, if R.4 through R.7
and R.8 through R.11 were combined.
Likes
0
Dislikes
0
Response
Keith Jonassen - Keith Jonassen On Behalf of: Michael Puscas, ISO New England, Inc., 2; - Keith Jonassen
Answer
Document Name
Comment
ISO-NE believes that the additional guidance provided in chapter 8 of the draft Transmission System Planned Performance for Geomagnetic
Disturbance Events Implementation guidance document for simulating the supplemental GMD event is very helpful. ISO recommends reviewing the
language in that chapter to ensure consistency with the purpose of the implementation guidance document as explained in the first paragraph of its
Introduction section (i.e. make clear that the information provided describes an example of how the standard’s requirements could be met), and not infer
the introduction of additional requirements which would not otherwise be contained in the TPL-007 standard.
Likes
0
Dislikes
0
Response
Deanna Carlson - Cowlitz County PUD - 5
Answer
Document Name
Comment
The addition of the ERO for approving any timeline extension may prove to be excessive and burdensome for NERC, and possibly the responsible
entity as well. The District recommends an additional statement where the ERO has 60 days to provide notice to the responsible entity when a CAP
submittal with an extension request will require ERO approval following full review. Otherwise, if NERC acknowledges receipt with no further notice to
the responsible entity, the CAP and extension request is automatically approved. This would reduce the work load on NERC to regarding CAPs with
extension requests that are minimal or otherwise considered low risk to the BES.
Additionally, there is no consideration of cost. It is possible that a CAP could be expensive and difficult to develop a four-year plan without hindering
other more important Transmission Planning objectives in compliance to TPL-001.
Likes
0
Dislikes
0
Response
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment
No comment
Likes
0
Dislikes
0
Response
Steven Dowell - Alcoa - Alcoa, Inc. - 7
Answer
Document Name
Comment
Alcoa would like to abstain. Alcoa would urge the SDT to examine cost/benefit analysis for implementation of GMDs at non-critical facilities.
Likes
0
Dislikes
0
Response
Greg Davis - Georgia Transmission Corporation - 1
Answer
Document Name
Comment
The only difference between R.4 through R.7 and R.8 through R.11 is the threshold for the maximum effective GIC value (75 A for the Benchmark GMD
Event, and 85 A for the Supplemental GMD event). Based on this fact, the number of requirements in the standard could be reduced, if R.4 through R.7
and R.8 through R.11 were combined.
Likes
0
Dislikes
0
Response
Kenya Streeter - Edison International - Southern California Edison Company - 6
Answer
Document Name
Comment
See EEI's comments.
Likes
0
Dislikes
0
Response
James Mearns - Pacific Gas and Electric Company - 1,3,5
Answer
Document Name
Comment
As inverter based sources of generation increase on the grid, the requirements of IEEE-Std-519 related to THD percentages (to the 40th harmonic) may
need to be revisited. Energy at higher order harmonic frequencies has been observed at bulk (>20 MW) solar sites, which may increase potential for
thermal saturation in banks that would otherwise not be susceptable to GIC. Although separate from the specific guidance in this TPL, this may
represent a sensitivity factor that could be weighted as part of the overall security assessment of the banks being reviewed.
Likes
0
Dislikes
0
Response
Chantal Mazza - Hydro-Qu?bec TransEnergie - 1 - NPCC
Answer
Document Name
Comment
The Implementation Guidance document, as written, is not acceptable. Boundaries cannot be established with a CMEP Implementation Guidance
document. CMEP Implementation Guidance is a means to identify one approach to being compliant while not precluding the use of other
approaches. Auditors audit to requirements and don’t use CMEP Implementation Guidance to establish requirements which go beyond the standard’s
requirements. Problematic statements appearing in Chapter 8 of the document include, but may not be limited to, the following:
•
“The local geoelectric field enhancement should not be smaller than 100 km..”- this threshold value of 100 km does not appear in the
standard requirement
•
“…at a minimum, a West-East orientation should be considered when applying the supplemental event”- the standard requirement does not
contain any wording of a minimum consideration
•
“Geoelectric field outside the local enhancement:
a. Amplitude: should not be smaller than 1.2 V/km…” This also does not appear in the standard.
•
“The schematic in Figure 1 illustrates the boundaries to apply the supplemental GMD event”. This statement creates boundaries outside of
requirements, which guidance cannot do.
The use of “shall” or “must” should not be used unless they are being used in the requriements in the standard. This is particularly true for the
requirement associated with sensitive/confidential information. It is not in the standard and was added in the IG as an additional “requirement”.
Likes
0
Dislikes
0
Response
Louis Guidry - Louis Guidry On Behalf of: John Lindsey, Cleco Corporation, 6, 5, 1, 3; Robert Hirchak, Cleco Corporation, 6, 5, 1, 3; - Louis
Guidry
Answer
Document Name
Comment
Cleco does agree with the concept, the language, particularly with regard to the extent of the Corrective Action Plan (R11) and various timetable
requirements are overreaching and place undue burden on potentially affected entities.
Likes
0
Dislikes
0
Response
Ayman Samaan - Edison International - Southern California Edison Company - 1
Answer
Document Name
Comment
Please see EEI's comments
Likes
0
Dislikes
0
Response
sean erickson - Western Area Power Administration - 1
Answer
Document Name
Comment
We don’t need to remind the Project 2019-01 SDT that this will be the fourth version of the TPL-007 Reliability Standard in three years. The team has
done a fine job of meeting the directives of FERC Order No. 851, but we encourage the SDT to push back harder on the corrective action
implementation timeframes for the supplemental GMD event. From a holistic view, this effort to address vulnerability to GMD events appears to be
getting too far ahead of good, robust science and engineering. The industry simply does not have mature hardware solutions available to potentially
mitigate GIC issues, anticipated from mathematical model simulation software packages that are updating at least as frequently as the TPL-007
standard itself has changed, while constantly chasing the emerging GMD science. The reliability of the BES is, and will be, best served by the improved
awareness of GMD impacts embodied by the TPL-007, as well as operator responsiveness required by EOP-010-1. The existing required identification
of corrective actions is key; just give industry the time and flexibility to adopt solutions that suit them best.
Likes
0
Dislikes
0
Response
Neil Swearingen - Salt River Project - 1,3,5,6 - WECC
Answer
Document Name
Comment
SRP thanks the standards drafting team for their efforts on this project.
Likes
0
Dislikes
Response
0
Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer
Document Name
Comment
None.
Likes
0
Dislikes
0
Response
Jonathan Robbins - Seminole Electric Cooperative, Inc. - 1,3,4,5,6 - SERC
Answer
Document Name
Comment
The Standard Draft Team (SDT) has added language to submit requests for extensions of timeframes to the ERO, i.e., NERC, for approval. Seminole
reasons that individual entities should communicate such requests to the RRO, e.g., SERC, WECC, etc., and that the individual RRO should
approve/deny such requests instead of NERC. Seminole is requesting the language be revised to capture this.
Likes
0
Dislikes
0
Response
Matthew Nutsch - Seattle City Light - 1,3,4,5,6 - WECC
Answer
Document Name
Comment
None
Likes
0
Dislikes
0
Response
Nick Batty - Keys Energy Services - NA - Not Applicable - SERC
Answer
Document Name
Comment
N/A
Likes
0
Dislikes
0
Response
Thomas Foltz - AEP - 5
Answer
Document Name
Comment
As previously stated, many of the obligations within TPL-007, both existing and proposed, precede industries’ full understanding of GMD and its true,
discernable impacts. This proves challenging when attempting to develop standards to adequately address the perceived risks.
We support, and are appreciative of, the efforts of the standards drafting team and their desire to address the directives issued in Order No. 851,
however we believe the spirit of those directives can be met without pursuing a path that duplicates obligations already required for the benchmark
event. We believe a more prudent path for meeting the directive would be for the SDT to work with industry and determine an agreeable reference
peak geoelectric field amplitude (one not determined solely by non-spatially averaged data) for a single GMD Vulnerability Assessment (benchmark)
that potentially requires a Corrective Action Plan. This would serve to both achieve the spirit of the directive, as well as avoid unnecessary duplication
of efforts that provide no added benefit to the reliability of the BES. Due to the concerns we have expressed above, AEP has chosen to vote negative
on the proposed revisions.
Likes
0
Dislikes
0
Response
Marty Hostler - Northern California Power Agency - 5
Answer
Document Name
Comment
None
Likes
0
Dislikes
Response
0
Consideration of Comments
Project Name:
Project 2019-01 Modifications to TPL-007-3
Comment Period Start Date:
7/26/2019
Comment Period End Date:
9/9/2019
Associated Ballots:
Project 2019-01 Modifications to TPL-007-3 TPL-007-4 IN 1 ST
There were 66 sets of responses, including comments from approximately 133 different people from approximately 98 companies
representing 10 of the Industry Segments as shown in the table on the following pages.
All comments submitted can be reviewed in their original format on the project page.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give every comment serious consideration
in this process. If you feel there has been an error or omission, you can contact the Vice President of Engineering and Standards, Howard Gugel
(via email) or at (404) 446‐9693.
RELIABILITY | RESILIENCE | SECURITY
Questions
1. The SDT approach was to modify Requirement R7.4 to meet the directive in Order 851 to require prior approval of extension requests
for completing corrective action plan tasks. Do you agree that R7 meets the directive? If you disagree please explain and provide
alternative language and rationale for how it meets the directive of the order.
2. The SDT approach was to add Requirement R11 to meet the directive in Order No. 851 to “require corrective action plans for assessed
supplemental GMD event vulnerabilities.” R7 and R11 are the same language applied to the benchmark and supplemental events
respectively. Do you agree that R11 meets the directive? If you disagree please explain and provide alternative language and rationale
for how it meets the directive of the order.
3. Do you agree that the Canadian variance is written in a way that accommodates the regulatory processes in Canada? If you disagree
please explain and provide alternative language and rationale for how it meets the directive of the order while accommodating Canadian
regulatory processes.
4. Do you agree that the standard language changes in Requirement R7, R8, and R11 proposed by the SDT adequately address the
directives in FERC Order No. 851? If you disagree please explain and provide alternative language and rationale for how it meets the
directive of the order.
5. Do you have any comments on the modified VRF/VSL for Requirements R7, R8, and R11?
6. Do you agree with the proposed Implementation Plan? If you think an alternate, shorter or longer implementation time period is
needed, please propose an alternate implementation plan and time period, and provide a detailed explanation of actions planned to
meet the implementation deadline.
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
2
7. The SDT proposes that the modifications in TPL-007-4 meet the FERC directives in a cost effective manner. Do you agree? If you do not
agree, or if you agree but have suggestions for improvement to enable more cost effective approaches, please provide your
recommendation and, if appropriate, technical or procedural justification.
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load‐serving Entities
4 — Transmission‐dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
3
Organization Name
Name
Segment(s)
FirstEnergy - Aubrey 4
FirstEnergy Short
Corporation
Electric
Reliability
Council of
Texas, Inc.
Brandon 2
Gleason
Region
Group Name
FE VOTER
Group
Member
Name
Group Member
Organization
Group
Group
Member Member
Segment(s) Region
Ann Carey
FirstEnergy
6
RF
Robert Loy
FirstEnergy FirstEnergy
Solutions
5
RF
Aaron
FirstEnergy Ghodooshim FirstEnergy
Corporation
3
RF
Julie
Severino
FirstEnergy FirstEnergy
Corporation
1
RF
Aubrey
Short
FirstEnergy
4
RF
Electric
Reliability
Council of
Texas, Inc.
2
Texas RE
Midcontinent
Independent
System
Operator
2
MRO
ISO/RTO
Brandon
Council
Gleason
Standards
Review
Committee
Bobbi Welch
2019-01
Modifications
to TPL-007
Mark
Holman
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
PJM
2
Interconnection,
L.L.C.
RF
4
Douglas
Webb
Douglas
Webb
ACES Power Jodirah 1,3,4,5,6
Marketing Green
MRO,SPP RE
Charles
Yeung
Southwest
2
Power Pool, Inc.
(RTO)
MRO
Gregory
Campoli
New York
Independent
System
Operator
2
NPCC
Westar-KCPL Doug Webb Westar
1,3,5,6
MRO
Doug Webb KCP&L
1,3,5,6
MRO
MRO,NA - Not
ACES
Bob
Applicable,RF,SERC,Texas Standard
Solomon
RE,WECC
Collaborations
Hoosier Energy 1
Rural Electric
Cooperative,
Inc.
Kevin Lyons Central Iowa
Power
Cooperative
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
1
SERC
MRO
John Shaver Arizona Electric 1
Power
Cooperative
WECC
Bill
Hutchison
Southern Illinois 1
Power
Cooperative
SERC
Tara
Lightner
Sunflower
Electric Power
Corporation
MRO
1
5
Public Utility Joyce
3
District No. 1 Gundry
of Chelan
County
Entergy
Julie
Hall
CHPD
6
Entergy
DTE Energy - Karie
3,4,5
Detroit
Barczak
Edison
Company
Duke Energy Kim
1,3,5,6
Thomas
Southern
Company Southern
Pamela 1,3,5,6
Hunter
DTE Energy DTE Electric
FRCC,RF,SERC
SERC
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
Duke Energy
Southern
Company
Meaghan
Connell
Public Utility
5
District No. 1 of
Chelan County
WECC
Davis
Jelusich
Public Utility
6
District No. 1 of
Chelan County
WECC
Jeff Kimbell Public Utility
1
District No. 1 of
Chelan County
WECC
Oliver Burke Entergy Entergy
Services, Inc.
1
SERC
Jamie Prater Entergy
5
SERC
Jeffrey
Depriest
DTE Energy DTE Electric
5
RF
Daniel
Herring
DTE Energy DTE Electric
4
RF
Karie
Barczak
DTE Energy DTE Electric
3
RF
Laura Lee
Duke Energy
1
SERC
Dale
Goodwine
Duke Energy
5
SERC
Greg Cecil
Duke Energy
6
RF
Adrianne
Collins
Southern
Company Southern
1
SERC
6
Company
Services, Inc.
Northeast
Ruida
Power
Shu
Coordinating
Council
Company
Services, Inc.
1,2,3,4,5,6,7,8,9,10 NPCC
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
Joel
Southern
3
Dembowski Company Alabama Power
Company
SERC
William D.
Shultz
Southern
Company
Generation
5
SERC
Ron Carlsen Southern
Company Southern
Company
Generation
6
SERC
10
NPCC
RSC no NGrid Guy V. Zito
and NYISO
Northeast
Power
Coordinating
Council
Randy
New Brunswick 2
MacDonald Power
NPCC
Glen Smith
Entergy Services 4
NPCC
Brian
Robinson
Utility Services
5
NPCC
Alan
Adamson
New York State 7
Reliability
Council
NPCC
7
David Burke Orange &
Rockland
Utilities
3
NPCC
Michele
Tondalo
1
NPCC
Helen Lainis IESO
2
NPCC
Sean Cavote PSEG
4
NPCC
Kathleen
Goodman
2
NPCC
UI
ISO-NE
David Kiguel Independent
Silvia
Mitchell
NextEra Energy 6
- Florida Power
and Light Co.
NPCC
Paul
Hydro One
Malozewski Networks, Inc.
3
NPCC
Nick
Kowalczyk
Orange and
Rockland
1
NPCC
Joel
Charlebois
AESI - Acumen
Engineered
Solutions
International
Inc.
5
NPCC
1
NPCC
Mike Cooke Ontario Power 4
Generation, Inc.
NPCC
Quintin Lee Eversource
Energy
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
NA - Not
NPCC
Applicable
8
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
Salvatore
Spagnolo
New York Power 1
Authority
NPCC
Shivaz
Chopra
New York Power 5
Authority
NPCC
Mike Forte
Con Ed Consolidated
Edison
4
NPCC
Dermot
Smyth
Con Ed Consolidated
Edison Co. of
New York
1
NPCC
Peter Yost
Con Ed Consolidated
Edison Co. of
New York
3
NPCC
Ashmeet
Kaur
Con Ed Consolidated
Edison
5
NPCC
Caroline
Dupuis
Hydro Quebec
1
NPCC
Chantal
Mazza
Hydro Quebec
2
NPCC
Sean Bodkin Dominion 6
Dominion
Resources, Inc.
NPCC
Laura
McLeod
NPCC
NB Power
Corporation
5
9
PSEG
Sean
Cavote
1,3,5,6
FRCC,NPCC,RF
PSEG REs
Randy
NB Power
MacDonald Corporation
2
NPCC
Tim Kucey
5
NPCC
6
RF
Jeffrey
Mueller
PSEG - Public
3
Service Electric
and Gas Co.
RF
Joseph
Smith
PSEG - Public
1
Service Electric
and Gas Co.
RF
Southwest
2
Power Pool Inc.
MRO
PSEG - PSEG
Fossil LLC
Karla Barton PSEG - PSEG
Energy
Resources and
Trade LLC
Southwest Shannon 2
Power Pool, Mickens
Inc. (RTO)
MRO,SPP RE
SPP Standards Shannon
Review Group Mickens
Scott Jordan Southwest
Power Pool Inc
Jamison
Cawley
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
2
MRO
Nebraska Public 1
Power District
MRO
10
1. The SDT approach was to modify Requirement R7.4 to meet the directive in Order 851 to require prior approval of extension
requests for completing corrective action plan tasks. Do you agree that R7 meets the directive? If you disagree please explain and
provide alternative language and rationale for how it meets the directive of the order.
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer
No
Document Name
Comment
CHPD does not agree with replacing the corrective action plan time-extension provision in Requirement R7.4 with a process through
which extensions of time are considered on a case-by-case basis. Since R7.4 is for “situations beyond the control of the entity,” it does not
matter if the extensions are considered on a case-by-case basis as the entity will not be able to comply with the CAP timeline as the
situation was beyond their control. Adding the case-by-case basis would increase the administrative burden to entities while adding very
little benefit to the reliability of the BPS.
Likes
6
Dislikes
Orlando Utilities Commission, 1, Staley Aaron; Snohomish County PUD No. 1, 3, Chaney Holly;
Public Utility District No. 1 of Snohomish County, 4, Martinsen John; Snohomish County PUD No.
1, 6, Liang John; Public Utility District No. 1 of Snohomish County, 1, Duong Long; Public Utility
District No. 1 of Snohomish County, 5, Nietfeld Sam
0
Response
Thank you for your comment. FERC Order No. 851 (P. 54) states that R7.4 (in TPL-007-3) differs from Order No. 830 by allowing applicable
entities, under certain conditions, to extend corrective action plan implementation deadlines without prior approval. FERC Order No. 851
(P. 56) directs NERC to modify R7.4 by developing a timely and efficient process, consistent with the Commission’s guidance in Order No.
830, to consider time extension requests on a case-by-case basis. The 'exception' for situations beyond the control of the responsible
entity in TPL-007-3 R7.4 is hence replaced by submitting an extension request to the ERO Enterprise on a case-by-case basis as described
in the DRAFT TPL-007-4 CAP Extension Request Review Process document.
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
11
Kenya Streeter - Edison International - Southern California Edison Company – 6
Answer
No
Document Name
Comment
See EEI's comments.
Likes
0
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Russell Noble - Cowlitz County PUD – 3
Answer
No
Document Name
Comment
The addition of the ERO for approving any timeline extension may prove to be excessive and burdensome for NERC, and possibly the
responsible entity as well. The District recommends an additional statement where the ERO has 60 days to provide notice to the
responsible entity when a CAP submittal with an extension request will require ERO approval following full review. Otherwise, if NERC
acknowledges receipt with no further notice to the responsible entity, the CAP and extension request is automatically approved. This
would reduce the work load on NERC regarding CAPs with extension requests that are minimal or otherwise considered low risk to the
BES.
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
12
Additionally, there is no consideration of cost. It is possible that a CAP could be expensive and difficult to develop a four-year plan
without hindering other more important Transmission Planning objectives in compliance to TPL-001.
Likes
0
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
review process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL007-4, and therefore, it is not part of the ballot. TPL-007-4 is a performance based standard and it does not address the administrative
steps of the extension review process. The Electric Reliability Organization (ERO) Enterprise will determine the extension review process
(deadlines, appeal process, flow process, status check, etc).
Richard Jackson - U.S. Bureau of Reclamation – 1
Answer
No
Document Name
Comment
Reclamation recommends Requirement R7 be phrased in terms of a responsible entity’s required action, not an action required by a CAP.
Reclamation also recommends restructuring TPL-007 so that one requirement in TPL-007 addresses corrective action plans for both
benchmark and supplemental GMD Vulnerability Assessments. Reclamation offers the following language for this requirement (see the
response to Question 2 regarding the numbering):
R10. Each responsible entity, as determined in Requirement R1, that concludes through the benchmark GMD Vulnerability Assessment
conducted in Requirement R4 or the Supplemental GMD Vulnerability Assessment conducted in Requirement R8 that their System does
not meet the performance requirements for the steady state planning benchmark GMD event contained in Table 1, shall develop a
Corrective Action Plan (CAP) addressing how the performance requirements will be met.
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
13
10.1. The responsible entity shall develop the CAP within one year of completion of the benchmark GMD Vulnerability Assessment or
Supplemental GMD Vulnerability Assessment.
10.2. The CAP shall contain the following:
10.2.1. A list of System deficiencies and the associated actions needed to achieve required System performance.
10.2.2. A timetable, subject to the following provisions, for implementing each action identified in 7.2.1:
10.2.2.1. Any implementation of non-hardware mitigation must be complete within two years of development of the CAP; and
10.2.2.2. Any implementation of hardware mitigation must be complete within 4 years of development of the CAP.
10.3 The responsible entity shall provide the CAP to the following entities within 90 days of development, revision, or receipt of a written
request
10.3.1. Reliability Coordinator;
10.3.2. Adjacent Planning Coordinator(s);
10.3.3. Adjacent Transmission Planner(s);
10.3.4. Functional entities referenced in the CAP; or
10.3.5. Any functional entity that submits a written request and has a reliability-related need for the CAP.
10.4. If a recipient of a CAP provides documented comments about the CAP, the responsible entity shall provide a documented response
to that recipient within 90 calendar days of receipt of those comments.
10.5. If a responsible entity determines it will be unable to implement a CAP within the timetable provided in part 7.2.2, the responsible
entity shall:
10.5.1. Document the circumstances causing the inability to implement the CAP within the existing timetable;
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
14
10.5.2. Document the reason those circumstances prevent the timely implementation of the CAP (including circumstances beyond the
entity’s control);
10.5.3. Document revisions to the actions identified in part 7.2.1 and the timetable in part 7.2.2; and
10.5.4. Submit a request for extension of the revised CAP to the ERO.
Regarding R10.2.2, Reclamation recommends against mandating industry-wide timelines due to the differences in each entity’s
capabilities to meet deadlines. For example, the differences in procurement processes and timelines among entities.
Regarding R10.5, Reclamation recommends the standard describe an extension policy. Regional entities may not be capable of fully
researching the entire interconnection in order to provide adequate approvals. Reclamation recommends the regional entities or the ERO
automate the CAP tracking process.
Likes
0
Dislikes
0
Response
Thank you for your comment. The SDT contends that the language in R7 and R11 clearly indicates what the entity must do and what shall
be in the CAP.
Eric Shaw - Eric Shaw On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; - Eric Shaw
Answer
No
Document Name
Comment
Please see comments submitted by EEI.
Likes
Dislikes
0
0
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
15
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
No
Document Name
Comment
EEI supports the language in Requirements R7.3 and R7.4 believing the proposed changes meet the intent of Order 851. However, the
companion process document (i.e., Draft TPL-007-4 CAP Extension Request Review Process) needs additional details to ensure efficient
processing of entity CAP Extension Requests, including:
1. A process flow diagram documenting the CAP Extension Process and roles and responsibilities of participants, including the ERO and
its authority in this process.
2.
NERC contact information where companies can quickly and efficiently check the status of their CAP Extension Requests.
3.
Defined deadlines for the completion of CAP Extension Request reviews by NERC and responding to entity inquiries.
4.
A process for extending a CAP review deadline for situations where NERC may need additional time.
5.
Criteria for a CAP Extension Request
6.
An appeals process for denied CAP Extension Requests.
7.
A formal process to notify entities on the final ruling for all CAP Extension Requests.
8.
Identification of who has oversight of the process within the ERO.
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
16
While EEI recognizes that the SDT is still early in the development phase of the TPL-007-4 Reliability Standard, we believe it is important
to emphasize that having a strong CAP Extension Request process is crucial to ensuring that the directed CAPs are effectively and
efficiently processed, similar to the BES Exceptions Process (see Rules of Procedure, Appendix 5C; Procedure for Requesting and Receiving
an Exception from the Application of the NERC Definition of Bulk Electric System).
Likes
0
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Chris Scanlon - Exelon – 1
Answer
No
Document Name
Comment
Exelon agrees with EEI’s comments. Exelon believes that the SDT has proposed changes to Requirements R7.3 and R7.4 that meet the
intent of the FERC directive in Order 851 but feel it requires further modifications. The Draft TPL-007-4 CAP Extension Request Review
Process does not provide the requesting entity with a clear understanding of how the request will be considered, when a decision can be
expected, and how an entity could request reconsideration if an extension is denied. With the FERC directive requiring ERO involvement
in this case, this justifies placing an obligation on the ERO. The development of a well-defined process similar to the Technical Feasbility
Exception Process or the BES Exceptions Process should be concurrently developed and submitted along with the proposed standard to
facilitate NERC’s engagement. This will provide a mechanism to address the key items noted in EEI’s comments.
On Behalf of Exelon: Segments 1, 3, 5, 6
Likes
0
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
17
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Douglas Webb - Douglas Webb On Behalf of: Allen Klassen, Westar Energy, 6, 3, 1, 5; Bryan Taggart, Westar Energy, 6, 3, 1, 5; Derek
Brown, Westar Energy, 6, 3, 1, 5; Grant Wilkerson, Westar Energy, 6, 3, 1, 5; James McBee, Great Plains Energy - Kansas City Power and
Light Co., 1, 3, 6, 5; Jennifer Flandermeyer, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; John Carlson, Great Plains
Energy - Kansas City Power and Light Co., 1, 3, 6, 5; Marcus Moor, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; Douglas Webb, Group Name Westar-KCPL
Answer
No
Document Name
Comment
Westar Energy and Kansas City Power & Light Company incorporate by reference and support comments submitted in response to
Question 1 by the Edison Electric Institute.
Likes
0
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
David Jendras - Ameren - Ameren Services - 3
Answer
No
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
18
Document Name
Comment
Ameren agrees with and supports EEI comments.
Likes
0
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Rahn Petersen - PNM Resources - Public Service Company of New Mexico - 1 - WECC,Texas RE
Answer
No
Document Name
Comment
This requirement gives responsibility to an entity which is not an applicable entity under the Standard. The requirement as written also
has no impact on reliability, it is purely an administrative requirement and does not directly provide the entitiy with an approved
extension. There should be a requirement added which requires the entity that receives the request for CAP extension approve the
request within a specified timeframe.
Likes
0
Dislikes
0
Response
Thank you for your comment. FFERC Order No. 830 (P. 97 and P.102) and FERC Order No. 851 (P. 54) state that NERC should consider
extensions of time on a case-by-case basis. FERC Order 851 (P. 5 and P. 55) expands upon this by referring to submission "to NERC or a
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
19
Regional Entity, as appropriate". The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Matthew Nutsch - Seattle City Light - 1,3,4,5,6 - WECC
Answer
Yes
Document Name
Comment
SCL agrees the modifications to R7.4 meet the directive in FERC Order. No. 851 by replacing the corrective action plan time-extension
provisions in R7.4 with a process that extensions of time are considered on a case-by case basis.
Likes
0
Dislikes
0
Response
Thank you for your comment.
Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer
Yes
Document Name
Comment
None.
Likes
1
Dislikes
Grand River Dam Authority, 3, Wells Jeff
0
Response
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
20
Neil Swearingen - Salt River Project - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
SRP has no comments for the standard drafting team.
Likes
0
Dislikes
0
Response
Thank you for your response.
sean erickson - Western Area Power Administration - 1
Answer
Yes
Document Name
Comment
Yes, the proposed TPL-007-4 Requirement R7, Part 7.4 meets the directive of FERC Order No. 851, Paragraph 54. The FERC directive is
extremely narrow and the Project 2019-01 SDT has met the intent to require a process to consider time extensions on a case-by-case
basis.
However, the FERC directive did not demand that the ERO be the adjudicating entity for time extensions and we suggest the following
revision to each ERO reference in the proposed TPL-007-4: “ERO, or its delegated designee.” We believe that this modification will allow
Regional Entities or other designees to better adjudicate CAP time extensions given their closer proximity, System expertise, and existing
Compliance Program obligations.
Likes
1
Orlando Utilities Commission, 1, Staley Aaron
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
21
Dislikes
0
Response
Thank you for your comment. The language in R7.4 and R11.4 has been modified to clarify intent.
Ayman Samaan - Edison International - Southern California Edison Company - 1
Answer
Yes
Document Name
Comment
Do you agree that R7 meets the directive? my possible answer is NO.
Please see EEI's comments
Likes
0
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Bruce Reimer - Manitoba Hydro - 1
Answer
Yes
Document Name
Comment
The proposed language meets the FERC directive.
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
22
Likes
0
Dislikes
0
Response
Thank you for your comment.
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
BPA understands that the SDT had to respond with proposed changes to meet the directive for R7. BPA does not agree that entities
should have to request approval from the ERO for an extension to the Corrective Action Plan for circumstances that occur beyond the
entities control.
BPA would like to utilize the new ERO Portal tool to allow NERC and the Commission immediate access in real time to the corrective
action plan extensions and the justification for the extension.
Retaining the requirement as written gives entities the flexibility to respond to unanticipated circumstances without the administrative
burden of seeking an extension from NERC. NERC and the Commission would be able to determine if entities are abusing this flexibility
and if abuse occurs, should seek to remedy at that time.
Likes
5
Dislikes
Snohomish County PUD No. 1, 3, Chaney Holly; Public Utility District No. 1 of Snohomish County,
4, Martinsen John; Snohomish County PUD No. 1, 6, Liang John; Public Utility District No. 1 of
Snohomish County, 1, Duong Long; Public Utility District No. 1 of Snohomish County, 5, Nietfeld
Sam
0
Response
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
23
Thank you for your comment. FERC Order No. 851 (P. 54) states that R7.4 (in TPL-007-3) differs from Order No. 830 by allowing applicable
entities, under certain conditions, to extend corrective action plan implementation deadlines without prior approval. FERC Order No. 851
(P. 56) directs NERC to modify R7.4 by developing a timely and efficient process, consistent with the Commission’s guidance in Order No.
830, to consider time extension requests on a case-by-case basis. The 'exception' for situations beyond the control of the responsible
entity in TPL-007-3 R7.4 is hence replaced by submitting an extension request to the ERO Enterprise on a case-by-case basis as described
in the DRAFT TPL-007-4 CAP Extension Request Review Process document. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff.
Aaron Staley - Orlando Utilities Commission - 1
Answer
Yes
Document Name
Comment
I agree that the language meets the directive, but would it make more sense for the standard to assign this to the regional entities instead
of the ERO?
Likes
0
Dislikes
0
Response
Thank you for your comment. The language in R7.4 and R11.4 has been modified to clarify intent.
Sean Cavote - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer
Yes
Document Name
Comment
PSEG supports EEI's comments.
Likes
0
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
24
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Brandon McCormick - Brandon McCormick On Behalf of: Carol Chinn, Florida Municipal Power Agency, 6, 4, 3, 5; Chris Gowder, Florida
Municipal Power Agency, 6, 4, 3, 5; Joe McKinney, Florida Municipal Power Agency, 6, 4, 3, 5; Richard Montgomery, Florida Municipal
Power Agency, 6, 4, 3, 5; - Brandon McCormick, Group Name FMPA
Answer
Yes
Document Name
Comment
Agree that R7 meets the directive. Do not agree that Part 7.4 should require the request for extension be submitted to the ERO for
approval. It makes more sense the request be submitted to the Regional Entity.
Likes
0
Dislikes
0
Response
Thank you for your comment. The language in R7.4 and R11.4 has been modified to clarify intent.
Quintin Lee - Eversource Energy - 1
Answer
Yes
Document Name
Comment
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
25
Eversource agrees with the modification of Requirement R7.4 to meet the directive of Order No. 851. However, Eversource does note
that the proposed R7 "approval for any extension" does not provide a mechanism to appeal a denied extension. Additionally, Eversource
notes that the proposed "approval for any extension" would come from the ERO while approval from a PC or RC would seem to be more
appropriate as they are aware of local limitations which may be the basis for the needed extension.
Likes
0
Dislikes
0
Response
Thank you for your comment. FFERC Order No. 830 (P. 97 and P.102) and FERC Order No. 851 (P. 54) state that NERC should consider
extensions of time on a case-by-case basis. FERC Order 851 (P. 5 and P. 55) expands upon this by referring to submission "to NERC or a
Regional Entity, as appropriate". Your comment on recommended changes to the extension process will be forwarded to NERC
Compliance Assurance staff.
Bobbi Welch - Midcontinent ISO, Inc. - 2 - MRO,SERC,RF
Answer
Yes
Document Name
Comment
MISO supports the comments submitted by the IRC SRC.
Likes
0
Dislikes
0
Response
Thank you for your comment. The language in R7.3, R7.4, R11.3, and R11.4 has been modified to clarify intent.
Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee 2019-01
Modifications to TPL-007
Answer
Yes
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
26
Document Name
Project 2019-01 Comment Form Attachment.docx
Comment
ISO/RTO Council Standards Review Committee members ERCOT, MISO, NYISO, PJM, and SPP (the “SRC”) submit the following comments
regarding Project 2019-01 Modifications to TPL-007-3.
The SRC agrees that the revisions to Requirement R7 proposed by the SDT satisfy FERC’s directive in Order 851 regarding extensions of
time to implement corrective action plans on a case-by-case basis. In order to further streamline Requirement R7 and more closely align
Requirement R7 to the specific language in FERC’s directive, the SRC offers the proposed revisions described below and identified in the
attached for consideration by the SDT.
In connection with Part 7.3, mentioning the ERO approval processes is not necessary given that Part 7.4 addresses the process. Deleting
the reference (“ERO approval for any extension sought under”) would result in a more streamlined requirement, and would more closely
align with FERC’s directive that Part 7.4 be modified to incorporate the development of a timely and effective extension of time review
process. This proposed revision to the current draft of Part 7.3 proposed by the SDT is identified in the attached redline.
In connection with Part 7.4, the SRC suggests the SDT consider:
1.
Including express language that an extension of time is “subject to the approval of NERC and the reliability entity’s Regional
Entity(s) on a case-by-case basis” in order to more closely align Part 7.4 with FERC’s specific directive that Part 7.4 be modified and
that requests for extension of time are to be reviewed on a “case-by-case basis.”
2.
Utilizing “NERC and the reliability entity’s Regional Entity(s)” instead of “ERO” in order to more closely align with the specific
language utilized in Order 851.
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
27
3.
Including “of time” in order to more clearly articulate what type of extension is available under Part 7.4
These proposed revisions to the current draft of Part 7.4 proposed by the SDT are identified in the attached redline.
Likes
0
Dislikes
0
Response
Thank you for your comment. The language in R7.3, R7.4, R11.3, and R11.4 has been modified to clarify intent.
Marty Hostler - Northern California Power Agency - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Dennis Sismaet - Northern California Power Agency - 6
Answer
Yes
Document Name
Comment
Likes
0
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
28
Dislikes
0
Response
Aubrey Short - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE VOTER
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Nick Batty - Keys Energy Services - NA - Not Applicable - SERC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1
Answer
Yes
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
29
Document Name
Comment
Likes
0
Dislikes
0
Response
Christopher Overberg - Con Ed - Consolidated Edison Co. of New York - 6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Frank Pace - Central Hudson Gas & Electric Corp. - 1,3
Answer
Yes
Document Name
Comment
Likes
Dislikes
0
0
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
30
Response
Travis Chrest - South Texas Electric Cooperative - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Nick Batty - Keys Energy Services - 4
Answer
Yes
Document Name
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
31
Comment
Likes
0
Dislikes
0
Response
Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1,3,5,6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
John Tolo - Unisource - Tucson Electric Power Co. - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
32
Chantal Mazza - Hydro-Qu?bec TransEnergie - 1 - NPCC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Steve Arnold - City of Independence, Power and Light Department - 1,3,5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
James Mearns - Pacific Gas and Electric Company - 1,3,5
Answer
Yes
Document Name
Comment
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
33
Likes
0
Dislikes
0
Response
Lana Smith - San Miguel Electric Cooperative, Inc. - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - MRO,WECC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
34
Greg Davis - Georgia Transmission Corporation - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Eleanor Ewry - Puget Sound Energy, Inc. - 1,3,5
Answer
Yes
Document Name
Comment
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
35
Likes
0
Dislikes
0
Response
Keith Jonassen - Keith Jonassen On Behalf of: Michael Puscas, ISO New England, Inc., 2; - Keith Jonassen
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Scott McGough - Georgia System Operations Corporation - 3,4
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Standard Collaborations
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
36
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Andrea Barclay - Georgia System Operations Corporation - 3,4
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Anthony Jablonski - ReliabilityFirst - 10
Answer
Yes
Document Name
Comment
Likes
0
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
37
Dislikes
0
Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO, Group Name SPP Standards Review Group
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Anton Vu - Los Angeles Department of Water and Power - 6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
Yes
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
38
Document Name
Comment
Likes
0
Dislikes
0
Response
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no NGrid and NYISO
Answer
Yes
Document Name
Comment
Likes
Dislikes
0
0
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
39
Response
Bette White - AES - Indianapolis Power and Light Co. - 3
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Document Name
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
40
Comment
“See EEI’s comments” on Modifications to TPL-007-3 – TPL-007-4 Transmission System Planned Performance for Geomagnetic
Disturbance Events.
Likes
0
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE appreciates the standard drafting team’s (SDT) efforts to meet the FERC directives. Texas RE has a few concerns as to how the
SDT approached the directives.
First, Texas RE is concerned with the following language in Part 7.4:
Additionally, Texas RE is concerned with the ERO’s role involving the process for granting CAP extensions. Texas RE asserts that it may be
more appropriate to keep operational aspects of the BPS within the hands of the owners/operators and simply make the ERO aware of
the CAP. For example, Texas RE suggests that the RC is the appropriate entity to accept/approve the extensions for CAPs. In addition,
there could also be a requirement for the registered entity to inform its CEA of a CAP extension. This way, the ERO can verify compliance
as far as the RC reviewing extensions of the CAPs and the ERO would not become part of the compliance evaluation and processes of the
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
41
standard by not having to verify that they themselves reviewed the CAP extension. Moreover, this is consistent with Reliability Standard
PRC-012-2 Requirement R6, which requires the RAS-entity submit the CAP to its reviewing RC as the RC has the relevant expertise to
review the CAP.
•
Part 7.4.1 requires entities to document how circumstances causing delay are beyond the control of the responsible entity, but
Part 7.4 does not include language to specify that an extensions are only allowed when “situations beyond the control of the
responsible entity [arise].” (FERC Order No. 851). Texas RE recommends updating Part 7.4 to include requirements for extension
so implementation issues do not get categorized as documentation issues under Part 7.4.1.
•
Part 7.4 only specifies that CAP extensions shall be submitted but does not include language requiring that CAP extensions be
approved. While the Draft TPL-007-4 CAP Extension Request Review Process, which is outside of the requirement language, sates
“All CAP extension requests must be approved the ERO Enterprise prior to the original CAP completion date”, it may be helpful to
specify the timetables for extension requests in relation to the timetables for implementation in the original CAP to avoid
scenarios in which the responsible entity submits an extension request immediately prior to the planned implementation date.
•
Neither the requirement nor the Draft TPL-007-4 CAP Extension Request Review Process indicate what shall occur if a CAP
extension request is not approved.
•
Likes
0
Dislikes
0
Response
Thank you for your comment. FERC Order No. 830 (P. 97 and P.102) and FERC Order No. 851 (P. 54) state that NERC should consider
extensions of time on a case-by-case basis. FERC Order 851 (P. 5 and P. 55) expands upon this by referring to submission "to NERC or a
Regional Entity, as appropriate". The DRAFT TPL-007-4 CAP Extension Request Review Process document expresses how ERO Enterprise
Compliance Monitoring and Enforcement staff (CMEP staff) will jointly review requests for extensions to Corrective Action Plans (CAPs)
developed under TPL-007-4. The DRAFT TPL-007-4 CAP Extension Request Review Process document was developed by NERC Compliance
Assurance, not Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension process will be
forwarded to NERC Compliance Assurance staff. The language in R7.3, R7.4, R11.3, and R11.4 has been modified to clarify intent.
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
42
2. The SDT approach was to add Requirement R11 to meet the directive in Order No. 851 to “require corrective action plans for
assessed supplemental GMD event vulnerabilities.” R7 and R11 are the same language applied to the benchmark and supplemental
events respectively. Do you agree that R11 meets the directive? If you disagree please explain and provide alternative language and
rationale for how it meets the directive of the order.
Rahn Petersen - PNM Resources - Public Service Company of New Mexico - 1 - WECC,Texas RE
Answer
No
Document Name
Comment
Comment is the same as question #1.
Likes
0
Dislikes
0
Response
Thank you for your comment. FFERC Order No. 830 (P. 97 and P.102) and FERC Order No. 851 (P. 54) state that NERC should consider
extensions of time on a case-by-case basis. FERC Order 851 (P. 5 and P. 55) expands upon this by referring to submission "to NERC or a
Regional Entity, as appropriate". The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
David Jendras - Ameren - Ameren Services - 3
Answer
No
Document Name
Comment
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
43
Ameren agrees with and supports EEI comments.
Likes
0
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Douglas Webb - Douglas Webb On Behalf of: Allen Klassen, Westar Energy, 6, 3, 1, 5; Bryan Taggart, Westar Energy, 6, 3, 1, 5; Derek
Brown, Westar Energy, 6, 3, 1, 5; Grant Wilkerson, Westar Energy, 6, 3, 1, 5; James McBee, Great Plains Energy - Kansas City Power and
Light Co., 1, 3, 6, 5; Jennifer Flandermeyer, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; John Carlson, Great Plains
Energy - Kansas City Power and Light Co., 1, 3, 6, 5; Marcus Moor, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; Douglas Webb, Group Name Westar-KCPL
Answer
No
Document Name
Comment
Westar Energy and Kansas City Power & Light Company incorporate by reference and support comments submitted in response to
Question 2 by the Edison Electric Institute.
Likes
0
Dislikes
0
Response
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
44
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Chris Scanlon - Exelon - 1
Answer
No
Document Name
Comment
Exelon agrees with EEI’s comments and believes that the same concerns expressed in the response to Question 1 are applicable to R11 as
well.
On Behalf of Exelon: Segments 1, 3, 5, 6
Likes
0
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
No
Document Name
Comment
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
45
TVA supports comments submitted by AEP for Question #2.
Likes
0
Dislikes
0
Response
Thank you for your comment. The SDT believes that analyzing both benchmark and supplement events is the scientifically justified
approach to the study of GMD events that is not based solely on spatially averaged data. See Benchmark and Supplemental GMD Event
White Papers.
FERC order 851 requires the SDT to develop a CAP for supplemental event:
“The Commission also directs NERC to develop and submit modifications to Reliability Standard TPL-007-2: (1) to require the development
and implementation of corrective action plans to mitigate assessed supplemental GMD event vulnerabilities;……”
The SDT has elaborated on the supplement event to the Implementation Guidance document.
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
No
Document Name
Comment
EEI supports the language in Requirements R11 believing the proposed changes meet the intent of Order 851. However as stated in more
detail in our response to Question 1, the companion process document (i.e., Draft TPL-007-4 CAP Extension Request Review Process)
needs to include additional details to ensure effective and transparent processing of entity CAP Extension Requests.
Likes
0
Dislikes
0
Response
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
46
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Eric Shaw - Eric Shaw On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; - Eric Shaw
Answer
No
Document Name
Comment
Please see comments submitted by EEI.
Likes
0
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Sean Cavote - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer
No
Document Name
Comment
PSEG supports EEI's comments.
Likes
0
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
47
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Richard Jackson - U.S. Bureau of Reclamation - 1
Answer
No
Document Name
Comment
Reclamation recommends combining the TPL-007 CAP requirements in R7 and R11 as provided above in response to Question 1. If
Reclamation’s proposal is accepted, Reclamation recommends restructuring and renumbering the requirements in TPL-007 as follows:
R1 through R6 – no change
R7 – remove and combine CAP language with existing R11
R8 – renumber existing R8 to R7
R9 – renumber existing R9 to R8
R10 – renumber existing R10 to R9
R11 – combine CAP language from existing R7; renumber the new single CAP requirement to R10
R12 – renumber existing R12 to R11
R13 – renumber existing R13 to R12
Consideration of Comments
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48
This will improve the logical flow of the activities required by the revised standard. Reclamation also recommends the SDT add a heading
between the new M9 and R10 for “Corrective Action Plans” for consistency with the existing headings “Benchmark GMD Vulnerability
Assessments” between M3 and R4, “Supplemental GMD Vulnerability Assessments” between M7 and R8, and “GMD Measurement Data
Processes” between M11 and R12.
Likes
0
Dislikes
0
Response
Thank you for your comment. The standard is drafted in the manner that the vulnerability assessment and CAP development for the
benchmark and supplemental events are defined in separate sequential requirements in order to keep the standard language clear and
avoid misinterpretation. Since TPL-007-3 is an active standard and responsible entities are currently performing the pertinent studies, the
SDT decided to preserve the numbering structure in TPL-007-3 to minimize the disruption existing processes and documentation.
Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Standard Collaborations
Answer
No
Document Name
Comment
ACES believes that the directive could have been dealt with in a less onerous way that addresses concerns other entities have expressed,
in their comments, about the potential for duplication of effort between the baseline corrective action plans and supplement corrective
action plans. To alleviate some of that potential, the standard could expressly state that corrective action plans are only required for
supplemental GMD Vulnerability Assessments, if the corrective actions plans identified for the baseline GMD Assessments do not already
address any additional vulnerabilities identified by the supplemental GMD Assessments.
Likes
0
Dislikes
0
Response
Consideration of Comments
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49
Thank you for your comment. The SDT does not believe there is a duplication of efforts. A single corrective action plan could address both
the benchmark and supplemental vulnerability assessment, or the entity could develop separate corrective action plans for the
benchmark event or the supplemental event.
Joe O'Brien - NiSource - Northern Indiana Public Service Co. - 6
Answer
No
Document Name
Comment
Comments: NIPSCO does not agree with the Requirement R11 that requires development and implementation of Corrective Action Plan
(CAP) for Supplemental GMD events. Judging by the reference geoelectric field values to be utilized for the Supplemental event, the effort
appears to be duplicative of the benchmark GMD event (8V/km) with a higher magnitude of 12V/km. As such, we believe the
supplemental event represents an “extreme” version of a case that will be assessed under the defined benchmark event.
As corrective action plans are to be developed and implemented for the benchmark GMD event(Requirement R7), requiring CAP for
Supplemental event will unnecessarily burden companies for cases that represents an extreme system condition and is not the best cost
effective approach to meet the FERC directive
Likes
0
Dislikes
0
Response
Thank you for your comment. However, FERC order 851 requires the SDT to develop a CAP for supplemental event:
“The Commission also directs NERC to develop and submit modifications to Reliability Standard TPL-007-2: (1) to require the development
and implementation of corrective action plans to mitigate assessed supplemental GMD event vulnerabilities;……”
Russell Noble - Cowlitz County PUD - 3
Answer
No
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
50
Document Name
Comment
See question one.
Likes
0
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
review process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL007-4, and therefore, it is not part of the ballot. TPL-007-4 is a performance based standard and it does not address the administrative
steps of the extension review process. The Electric Reliability Organization (ERO) Enterprise will determine the extension review process
(deadlines, appeal process, flow process, status check, etc).
Kenya Streeter - Edison International - Southern California Edison Company - 6
Answer
No
Document Name
Comment
See EEI's comments.
Likes
0
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
51
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer
No
Document Name
Comment
CHPD does not agree with requiring the development and implementation of corrective action plans to mitigate assessed supplemental
GMD event vulnerabilities. Entities have only just begun the process of evaluating the benchmark GMD event and developing mitigation
measures. The industry is in the preliminary stages of assessing and developing mitigation measures for GMD events and has not had
much time to develop engineering-judgement, experience, or expertise in this field. Revising the standard to include CAPs for the
supplementary GMD event is not appropriate at this time as the industry is still building a foundation for this type of system event analysis
and exploring mitigation measures. Without a sound foundation developed, requiring CAPs for the supplemental GMD event could lead to
unnecessary mitigation measures and an immense amount of industry resources spent on a still developing science. CHPD suggests that
the benchmark GMD event be fully vetted before moving onto additional scenarios such as the supplemental event.
Likes
5
Dislikes
Snohomish County PUD No. 1, 3, Chaney Holly; Public Utility District No. 1 of Snohomish County, 4,
Martinsen John; Snohomish County PUD No. 1, 6, Liang John; Public Utility District No. 1 of
Snohomish County, 1, Duong Long; Public Utility District No. 1 of Snohomish County, 5, Nietfeld Sam
0
Response
Thank you for your comment. However, FERC order 851 requires the SDT to develop a CAP for supplemental event:
“The Commission also directs NERC to develop and submit modifications to Reliability Standard TPL-007-2: (1) to require the development
and implementation of corrective action plans to mitigate assessed supplemental GMD event vulnerabilities;……”
Thomas Foltz - AEP - 5
Answer
No
Consideration of Comments
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52
Document Name
Comment
While some aspects of R11 may indeed meet the directives as literally stated in Order No. 851, we do not believe it is a prudent way to
meet the spirit of those directives. We believe R11 is unnecessarily duplicative of the obligations already required for the benchmark
event, and disagree with its inclusion. In addition, the obligation to “specify implementation” of mitigation may not be consistently
interpreted among entities, and as a result, may not meet the directives for reasons we will provide in this response.
It is our view that the original purpose of the supplemental event was to investigate the impact of local enhancement of the generated
electric field from a GMD event on the transmission grid. This requires industry to take an approach in which the GICs are calculated with
the higher, enhanced electric field magnitude of 12 V/km (adjusted for location and ground properties) applied to some smaller defined
area while outside of this area the benchmark electric field magnitude of 8 V/km (also adjusted for location and ground properties) is
applied. This smaller area is then systematically moved across the system and the calculations are repeated. This is necessary as the
phenomenon could occur anywhere on the system. Using this Version 2 methodology, every part of the system is ultimately evaluated
with the higher electric field magnitude.
In our view, the supplemental event represents a more extreme scenario. Referring to Attachment 1 of the proposed standard, the
section titled ‘Applying the Localized Peak Geoelectric Field in the Supplemental GMD Event’ provides examples of applying the localized
peak geoelectric field over the planning area. The first example presented is applying the peak geoelectric field (12 V/km scaled to
planning area) over the entire planning area. This example is a more severe condition than the benchmark event, and should alleviate the
need to study the benchmark event if used. In addition, modeling tools for conducting GMD vulnerability studies for the supplemental
event using the moving box method have not yet been developed. As such, adding a corrective action plan requirement to the
supplemental event obviates the need for studying the benchmark event. Rather than pursuing a Corrective Action Plan for the existing
Supplemental GMD Vulnerability Assessment, we believe the SDT should instead pursue only one single GMD Vulnerability Assessment
using a reference peak geoelectric field amplitude not determined solely by non-spatially averaged data. This would be preferable to
requiring two GMD Vulnerability Assessments, both having Corrective Action Plans and each having their own unique reference peak
geoelectric field amplitude. When the Supplemental GMD Vulnerability Assessment was originally developed and proposed, there was no
CAP envisioned for it. Because of this, one could argue the merits of having two unique assessments, as each were different not only in
reference peak amplitude, but in obligations as well. What has now been proposed in this revision however, is essentially having two GMD
Vulnerability Assessments requiring Corrective Action Plans but with different reference peak geoelectric field amplitudes (one
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
53
presumably higher than the other). It would be unnecessarily burdensome, as well as illogical, to have essentially the same obligations for
both a baseline and supplemental vulnerability assessment. In addition to its duplicative nature, it is possible that the results from a
benchmark study may even differ or conflict with the results from a given supplemental study.
While the NOPR directs the standard to be revised to incorporate the “development and completion of corrective action plans to mitigate
assessed supplemental GMD event vulnerabilities”, we find rather that R11 requires the entity “specify implementation” of mitigation.
This could be interpreted by some as simply specifying what actions are to be taken but without explicit bounds or expectations on when
the final execution of that implementation (i.e. “completion”) would take place.
Once again, we believe a more prudent path for meeting the directive would be for the SDT to work with industry and determine an
agreeable reference peak geoelectric field amplitude for a single GMD Vulnerability Assessment (benchmark), one not determined solely
by non-spatially averaged data, and that potentially requires a Corrective Action Plan. This would serve to both achieve the spirit of the
directive, as well as avoid unnecessary duplication of efforts that provide no added benefit to the reliability of the BES.
Likes
1
Dislikes
Grand River Dam Authority, 3, Wells Jeff
0
Response
Thank you for your comment. The SDT believes that analyzing both benchmark and supplement events is the scientifically justified
approach to the study of GMD events that is not based solely on spatially averaged data. See Benchmark and Supplemental GMD Event
White Papers.
FERC order 851 requires the SDT to develop a CAP for supplemental event:
“The Commission also directs NERC to develop and submit modifications to Reliability Standard TPL-007-2: (1) to require the development
and implementation of corrective action plans to mitigate assessed supplemental GMD event vulnerabilities;……”
The SDT has elaborated on the supplement event to the Implementation Guidance document.
Consideration of Comments
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54
Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee 2019-01
Modifications to TPL-007
Answer
Yes
Document Name
Comment
The SRC agrees that adding Requirement R11, which is based on the existing language of Requirement R7, satisfies FERC’s directive in
Order 851 regarding the development and implementation of corrective action plans to mitigate assessed supplemental GMD event
vulnerabilities. To the extent the SDT incorporates in Requirement R7 the SRC’s suggested revisions identified in response to Question
No. 1 above, the SRC proposes the SDT make the same revisions to Requirement R11.
Likes
0
Dislikes
0
Response
Thank you for your comment. The language in R7.3, R7.4, R11.3, and R11.4 has been modified to clarify intent.
Bobbi Welch - Midcontinent ISO, Inc. - 2 - MRO,SERC,RF
Answer
Yes
Document Name
Comment
MISO supports the comments submitted by the IRC SRC.
Likes
0
Dislikes
0
Response
Thank you for your comment. The language in R7.3, R7.4, R11.3, and R11.4 has been modified to clarify intent.
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
55
Quintin Lee - Eversource Energy - 1
Answer
Yes
Document Name
Comment
Eversource agrees with the addition of Requirement R11 to meet the directive of Order No. 851. However, Eversource does note that the
proposed R11 "approval for any extension" does not provide a mechanism to appeal a denied extension. Additionally, Eversource notes
that the proposed "approval for any extension" would come from the ERO while approval from a PC or RC would seem to be more
appropriate as they are aware of local limitations which may be the basis for the needed extension.
Likes
0
Dislikes
0
Response
Thank you for your comment. FERC Order No. 830 (P. 97 and P.102) and FERC Order No. 851 (P. 54) state that NERC should consider
extensions of time on a case-by-case basis. FERC Order 851 (P. 5 and P. 55) expands upon this by referring to submission "to NERC or a
Regional Entity, as appropriate". Your comment on recommended changes to the extension process will be forwarded to NERC
Compliance Assurance staff.
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
The SDT has met the directive in Order 851.
BPA understands that the SDT had to respond with proposed changes to meet the directive for R11. BPA would like to reiterate the
industry’s and NERC’s opposition to developing corrective action plans for an extreme event (Supplemental GMD event) and the similarity
to TPL-001-4. A GMD event is considered to be a one in one hundred year event. BPA believes that assessing the event and performing
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
56
an evaluation of possible actions to reduce the likelihood of the impact is more appropriate than requiring a Supplemental GMD event
corrective action plan.
BPA supports the comments made by NERC, referenced in FERC’s Final Rule, issued on 11/15/18, Docket Nos. RM18-8-000 and RM15-11003, Order No. 851; paragraph 35, lines
1-12, which were unfortunately rejected by FERC. Excerpted below:
NERC’s comments reiterate the rationale in its petition that requiring mitigation
“would result in the de facto replacement of the benchmark GMD event with the
proposed supplemental GMD event.” 39 NERC maintains that “while the supplemental
GMD event is strongly supported by data and analysis in ways that mirror the benchmark
GMD event, there are aspects of it that are less definitive than the benchmark GMD event
and less appropriate as the basis of requiring Corrective Action Plans.”40 NERC also
claims that the uncertainty of geographic size of the supplemental GMD event could not
be addressed adequately by sensitivity analysis or through other methods because there
are “inherent sources of modeling uncertainty (e.g., earth conductivity model, substation
grounding grid resistance values, transformer thermal and magnetic response models) …
[and] introducing additional variables for sensitivity analysis, such as the size of the
localized enhancement, may not improve the accuracy of GMD Vulnerability Assessments.”41
39 Id. at 11-12; see also id. at 14 (“many entities would likely employ the most
conservative approach for conducting supplemental GMD Vulnerability Assessments,
Consideration of Comments
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57
which would be to apply extreme peak values uniformly over an entire planning area”).
40 Id. at 13.
41 Id. at 15.
Likes
5
Dislikes
Snohomish County PUD No. 1, 3, Chaney Holly; Public Utility District No. 1 of Snohomish County, 4,
Martinsen John; Snohomish County PUD No. 1, 6, Liang John; Public Utility District No. 1 of
Snohomish County, 1, Duong Long; Public Utility District No. 1 of Snohomish County, 5, Nietfeld Sam
0
Response
Thank you for your comment. FERC order 851 requires the SDT to develop a CAP for supplemental event:
“The Commission also directs NERC to develop and submit modifications to Reliability Standard TPL-007-2: (1) to require the development
and implementation of corrective action plans to mitigate assessed supplemental GMD event vulnerabilities;……”
Bruce Reimer - Manitoba Hydro - 1
Answer
Yes
Document Name
Comment
The proposed language meets the FERC directive.
Likes
0
Dislikes
0
Response
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
58
Thank you for your comment.
Ayman Samaan - Edison International - Southern California Edison Company - 1
Answer
Yes
Document Name
Comment
Do you agree that R11 meets the directive? my possible answer is NO.
Please see EEI's comments
Likes
0
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
sean erickson - Western Area Power Administration - 1
Answer
Yes
Document Name
Comment
Yes, the proposed TPL-007-4 Requirement R11 meets the directive of FERC Order No. 851, Paragraph 39. Again, the FERC directive leaves
little room for flexibility, requiring CAPs for the supplemental GMD event. While we are disappointed that FERC was not persuaded by the
technical challenges of simulating locally-enhanced peak geoelectric field suitable for supplemental GMD event analysis, the Project 201901 SDT has met the intent.
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
59
Likes
0
Dislikes
0
Response
Thank you for your comment.
Neil Swearingen - Salt River Project - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
SRP has no comments for the standard drafting team.
Likes
0
Dislikes
0
Response
Thank you for your response.
Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer
Yes
Document Name
Comment
None.
Likes
0
Dislikes
0
Response
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
60
Thank you for your response.
Matthew Nutsch - Seattle City Light - 1,3,4,5,6 - WECC
Answer
Yes
Document Name
Comment
SCL agrees modifications to R11 meets the requirements in FERC Order 851. The modifications to R11 properly address Order 851’s
requirement to develop CAP to mitigate assessed supplemental GMD event vulnerabilities with provisions for extension of time on a
case-by-case analysis.
Likes
0
Dislikes
0
Response
Thank you for your comment.
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Bette White - AES - Indianapolis Power and Light Co. - 3
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
61
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no NGrid and NYISO
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Yes
Document Name
Comment
Likes
0
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
62
Dislikes
0
Response
Aaron Staley - Orlando Utilities Commission - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Anton Vu - Los Angeles Department of Water and Power - 6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO, Group Name SPP Standards Review Group
Answer
Yes
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
63
Document Name
Comment
Likes
0
Dislikes
0
Response
Anthony Jablonski - ReliabilityFirst - 10
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Andrea Barclay - Georgia System Operations Corporation - 3,4
Answer
Yes
Document Name
Comment
Likes
Dislikes
0
0
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
64
Response
Scott McGough - Georgia System Operations Corporation - 3,4
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Keith Jonassen - Keith Jonassen On Behalf of: Michael Puscas, ISO New England, Inc., 2; - Keith Jonassen
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC
Answer
Yes
Document Name
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
65
Comment
Likes
0
Dislikes
0
Response
Greg Davis - Georgia Transmission Corporation - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - MRO,WECC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
66
Lana Smith - San Miguel Electric Cooperative, Inc. - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
James Mearns - Pacific Gas and Electric Company - 1,3,5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Steve Arnold - City of Independence, Power and Light Department - 1,3,5
Answer
Yes
Document Name
Comment
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
67
Likes
0
Dislikes
0
Response
Chantal Mazza - Hydro-Qu?bec TransEnergie - 1 - NPCC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
John Tolo - Unisource - Tucson Electric Power Co. - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
68
Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1,3,5,6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Nick Batty - Keys Energy Services - 4
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer
Yes
Document Name
Comment
Consideration of Comments
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Likes
0
Dislikes
0
Response
Travis Chrest - South Texas Electric Cooperative - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Frank Pace - Central Hudson Gas & Electric Corp. - 1,3
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Christopher Overberg - Con Ed - Consolidated Edison Co. of New York - 6
Consideration of Comments
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Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Nick Batty - Keys Energy Services - NA - Not Applicable - SERC
Answer
Yes
Document Name
Comment
Likes
0
Consideration of Comments
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Dislikes
0
Response
Aubrey Short - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE VOTER
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Dennis Sismaet - Northern California Power Agency - 6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Marty Hostler - Northern California Power Agency - 5
Answer
Yes
Consideration of Comments
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Document Name
Comment
Likes
0
Dislikes
0
Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Please see Texas RE’s comments regarding Part 7.4 in question #1 as they also apply to Part 11.4.
Likes
0
Dislikes
0
Response
Thank you for your comment. FERC Order No. 830 (P. 97 and P.102) and FERC Order No. 851 (P. 54) state that NERC should consider
extensions of time on a case-by-case basis. FERC Order 851 (P. 5 and P. 55) expands upon this by referring to submission "to NERC or a
Regional Entity, as appropriate". The DRAFT TPL-007-4 CAP Extension Request Review Process document expresses how ERO Enterprise
Compliance Monitoring and Enforcement staff (CMEP staff) will jointly review requests for extensions to Corrective Action Plans (CAPs)
developed under TPL-007-4. The DRAFT TPL-007-4 CAP Extension Request Review Process document was developed by NERC Compliance
Assurance, not Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension process will be
forwarded to NERC Compliance Assurance staff. The language in R7.3, R7.3, R11.3, and R11.4 has been modified to clarify intent.
Selene Willis - Edison International - Southern California Edison Company - 5
Consideration of Comments
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Answer
Document Name
Comment
“See EEI’s comments” on Modifications to TPL-007-3 – TPL-007-4 Transmission System Planned Performance for Geomagnetic
Disturbance Events.
Likes
0
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Eleanor Ewry - Puget Sound Energy, Inc. - 1,3,5
Answer
Document Name
Comment
PSE will abstain from answering this question
Likes
0
Dislikes
0
Response
Thank you for your comment.
Consideration of Comments
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74
3. Do you agree that the Canadian variance is written in a way that accommodates the regulatory processes in Canada? If you disagree
please explain and provide alternative language and rationale for how it meets the directive of the order while accommodating Canadian
regulatory processes.
sean erickson - Western Area Power Administration - 1
Answer
No
Document Name
Comment
N/A
Likes
1
Dislikes
Western Area Power Administration, 6, Jones Rosemary
0
Response
Bruce Reimer - Manitoba Hydro - 1
Answer
No
Document Name
Comment
The Canadian variance does not completely reflect the unique regulatory process in each region in Canada. The Manitoba Hydro Act
prevents adoption of reliability standards that have the effect of requiring construction or enhancement of facilities in Manitoba. Manitoba
Hydro modified the language of TPL-007-2 that works in Manitoba.
Likes
Dislikes
0
0
Consideration of Comments
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75
Response
Thank you for your comments. The SDT acknowledges the jurisdictional issues mentioned. It is noted that jurisdictional regulations may
have limits on standard adoption, and entities may have standard making authority.
Kenya Streeter - Edison International - Southern California Edison Company - 6
Answer
No
Document Name
Comment
See EEI's comments.
Likes
0
Dislikes
0
Response
No comments were submitted by EEI for Question 3.
Matthew Nutsch - Seattle City Light - 1,3,4,5,6 - WECC
Answer
Yes
Document Name
Comment
SCL agrees the Canadian variance portion of the standard is helpful for the utilities in the United States. However, SCL cannot comment on
the language of the standard in the Canadian Variance portion where it relates to regulatory process in Canada.
Likes
0
Dislikes
0
Response
Consideration of Comments
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76
Thank you for your response.
Neil Swearingen - Salt River Project - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
SRP is not impacted by the Canadian variance..
Likes
0
Dislikes
0
Response
Thank you for your response.
Ayman Samaan - Edison International - Southern California Edison Company - 1
Answer
Yes
Document Name
Comment
Please see EEI's comments
Likes
0
Dislikes
0
Response
No comments were submitted by EEI for Question 3.
Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1,3,5,6
Answer
Yes
Consideration of Comments
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77
Document Name
Comment
Not applicable
Likes
0
Dislikes
0
Response
Richard Jackson - U.S. Bureau of Reclamation - 1
Answer
Yes
Document Name
Comment
For the parts of the proposed changes to R7 (new R10) stated in the response to Question 1 that are accepted, Reclamation recommends
conforming changes be made to the pertinent language in the Canadian variance.
Likes
0
Dislikes
0
Response
Thank you for your comments. There are no equivalent changes to the Canadian Variance based on the comments and changes made to the
standard from Reclamations Question 1 response.
Quintin Lee - Eversource Energy - 1
Answer
Yes
Document Name
Consideration of Comments
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78
Comment
Eversource has no opinion on the Canadian variance.
Likes
0
Dislikes
0
Response
Thank you for your response.
Bobbi Welch - Midcontinent ISO, Inc. - 2 - MRO,SERC,RF
Answer
Yes
Document Name
Comment
MISO supports the comments submitted by the IRC SRC.
Likes
0
Dislikes
0
Response
The IRC SRC did not provide any comments for Question 3.
Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee 2019-01
Modifications to TPL-007
Answer
Yes
Document Name
Comment
Consideration of Comments
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79
The Canadian member of the SRC agrees that the Canadian variance is written in a way that accommodates the regulatory process in
Canada.
Likes
0
Dislikes
0
Response
Thank you for your comment.
Marty Hostler - Northern California Power Agency - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Dennis Sismaet - Northern California Power Agency - 6
Answer
Yes
Document Name
Comment
Likes
Dislikes
0
0
Consideration of Comments
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80
Response
Nick Batty - Keys Energy Services - NA - Not Applicable - SERC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Christopher Overberg - Con Ed - Consolidated Edison Co. of New York - 6
Answer
Yes
Document Name
Consideration of Comments
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81
Comment
Likes
0
Dislikes
0
Response
Frank Pace - Central Hudson Gas & Electric Corp. - 1,3
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Travis Chrest - South Texas Electric Cooperative - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Consideration of Comments
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82
Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Nick Batty - Keys Energy Services - 4
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
John Tolo - Unisource - Tucson Electric Power Co. - 1
Answer
Yes
Document Name
Comment
Consideration of Comments
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83
Likes
0
Dislikes
0
Response
Chantal Mazza - Hydro-Qu?bec TransEnergie - 1 - NPCC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Steve Arnold - City of Independence, Power and Light Department - 1,3,5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Consideration of Comments
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84
James Mearns - Pacific Gas and Electric Company - 1,3,5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Lana Smith - San Miguel Electric Cooperative, Inc. - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - MRO,WECC
Answer
Yes
Document Name
Comment
Consideration of Comments
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85
Likes
0
Dislikes
0
Response
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Leonard Kula - Independent Electricity System Operator - 2
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Standard Collaborations
Consideration of Comments
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86
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Anthony Jablonski - ReliabilityFirst - 10
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Anton Vu - Los Angeles Department of Water and Power - 6
Answer
Yes
Document Name
Comment
Likes
0
Consideration of Comments
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87
Dislikes
0
Response
Aaron Staley - Orlando Utilities Commission - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no NGrid and NYISO
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Yes
Consideration of Comments
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88
Document Name
Comment
Likes
0
Dislikes
0
Response
Aubrey Short - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE VOTER
Answer
Document Name
Comment
Not applicable to FirstEnergy.
Likes
0
Dislikes
0
Response
Thank you for your response.
Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer
Document Name
Comment
N/A
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
89
Likes
0
Dislikes
0
Response
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer
Document Name
Comment
CHPD defers the response to this question to the Canadian provinces to determine if the Canadian variance is written to accommodate the
regulatory processes in Canada.
Likes
0
Dislikes
0
Response
Thank you for your response.
Greg Davis - Georgia Transmission Corporation - 1
Answer
Document Name
Comment
GTC’s opinion is that this question should only be answered by Canadian entities.
Likes
Dislikes
0
0
Consideration of Comments
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Response
Thank you for your response.
Eleanor Ewry - Puget Sound Energy, Inc. - 1,3,5
Answer
Document Name
Comment
PSE will abstain from answering this question
Likes
0
Dislikes
0
Response
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment
No comment
Likes
1
Dislikes
Snohomish County PUD No. 1, 3, Chaney Holly
0
Response
Andrea Barclay - Georgia System Operations Corporation - 3,4
Consideration of Comments
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91
Answer
Document Name
Comment
GSOC's opinion is that this question should only be answered by Canadian entities.
Likes
0
Dislikes
0
Response
Thank you for your response.
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Document Name
Comment
“See EEI’s comments” on Modifications to TPL-007-3 – TPL-007-4 Transmission System Planned Performance for Geomagnetic Disturbance
Events.
Likes
0
Dislikes
0
Response
EEI did not provide a response to Question 3.
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
Document Name
Consideration of Comments
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Comment
N/A
Likes
0
Dislikes
0
Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE does not have comments on this question.
Likes
0
Dislikes
0
Response
Thank you for your response.
David Jendras - Ameren - Ameren Services - 3
Answer
Document Name
Comment
Ameren agrees with and supports EEI comments.
Consideration of Comments
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93
Likes
0
Dislikes
0
Response
EEI did not provide a response to Question 3.
Bette White - AES - Indianapolis Power and Light Co. - 3
Answer
Document Name
Comment
IPl is not in the Canadian district
Likes
0
Dislikes
0
Response
Thank you for your response.
Rahn Petersen - PNM Resources - Public Service Company of New Mexico - 1 - WECC,Texas RE
Answer
Document Name
Comment
N/A
Likes
0
Dislikes
0
Response
Consideration of Comments
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4. Do you agree that the standard language changes in Requirement R7, R8, and R11 proposed by the SDT adequately address the
directives in FERC Order No. 851? If you disagree please explain and provide alternative language and rationale for how it meets the
directive of the order.
David Jendras - Ameren - Ameren Services - 3
Answer
No
Document Name
Comment
Ameren agrees with and supports EEI comments.
Likes
0
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Douglas Webb - Douglas Webb On Behalf of: Allen Klassen, Westar Energy, 6, 3, 1, 5; Bryan Taggart, Westar Energy, 6, 3, 1, 5; Derek
Brown, Westar Energy, 6, 3, 1, 5; Grant Wilkerson, Westar Energy, 6, 3, 1, 5; James McBee, Great Plains Energy - Kansas City Power and
Light Co., 1, 3, 6, 5; Jennifer Flandermeyer, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; John Carlson, Great Plains
Energy - Kansas City Power and Light Co., 1, 3, 6, 5; Marcus Moor, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; Douglas Webb, Group Name Westar-KCPL
Answer
No
Document Name
Comment
Consideration of Comments
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96
Westar Energy and Kansas City Power & Light Company incorporate by reference and support comments submitted in response to Question
4 by the Edison Electric Institute.
Likes
0
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Chris Scanlon - Exelon - 1
Answer
No
Document Name
Comment
As discussed in the response to Question 1, Exelon agrees that changes in Requirements R7, R8 and R11 meet the intent of the FERC
directives, but without a clear CAP Extension Process the changes cannot be supported at this time.
On Behalf of Exelon: Segments 1, 3, 5, 6
Likes
0
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
97
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
No
Document Name
Comment
See response to Q2 above.
Likes
0
Dislikes
0
Response
Thank you for your comment. The SDT believes that analyzing both benchmark and supplement events is the scientifically justified approach
to the study of GMD events that is not based solely on spatially averaged data. See Benchmark and Supplemental GMD Event White Papers.
FERC order 851 requires the SDT to develop a CAP for supplemental event:
“The Commission also directs NERC to develop and submit modifications to Reliability Standard TPL-007-2: (1) to require the development
and implementation of corrective action plans to mitigate assessed supplemental GMD event vulnerabilities;……”
The SDT has elaborated on the supplement event to the Implementation Guidance document.
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
No
Document Name
Comment
Consideration of Comments
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98
EEI supports the language in Requirements R7, R8 and R11 as proposed by the SDT believing that the changes conform to the directives
contained in Order 851. Nevertheless, we cannot support these changes as sufficient or complete at this time until a CAP Extension Request
Review Process is develop that ensure that key elements, as articulated in our response to Question 1, are addressed.
Likes
0
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Eric Shaw - Eric Shaw On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; - Eric Shaw
Answer
No
Document Name
Comment
Please see comments submitted by EEI.
Likes
0
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Sean Cavote - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Consideration of Comments
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99
Answer
No
Document Name
Comment
PSEG supports EEI's comments.
Likes
0
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Richard Jackson - U.S. Bureau of Reclamation - 1
Answer
No
Document Name
Comment
Reclamation recommends the language in Requirements R7 and R11 be combined into a single requirement addressing corrective action
plans. Please refer to the proposed language provided in the responses to Questions 1 and 2.
Likes
0
Dislikes
0
Response
Thank you for your comment. The standard is drafted in the manner that the vulnerability assessment and CAP development for the
benchmark and supplemental events are defined in separate sequential requirements in order to keep the standard language clear and
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
100
avoid misinterpretation. Since TPL-007-3 is an active standard and responsible entities are currently performing the pertinent studies, the
SDT decided to preserve the numbering structure in TPL-007-3 to minimize the disruption existing processes and documentation.
Kenya Streeter - Edison International - Southern California Edison Company - 6
Answer
No
Document Name
Comment
See EEI's comments.
Likes
0
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer
No
Document Name
Comment
CHPD does not agree with the directives in FERC Order No. 851 for “Corrective Action Plan Deadline Extensions” or “Corrective Action Plan
for Supplemental GMD Event Vulnerabilities” (see responses to questions 1 and 2). Therefore, CHPD does not agree the standard language
changes in Requirement R7, R8, and R11 proposed by the SDT.
Consideration of Comments
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101
Likes
5
Dislikes
Snohomish County PUD No. 1, 3, Chaney Holly; Public Utility District No. 1 of Snohomish County, 4,
Martinsen John; Snohomish County PUD No. 1, 6, Liang John; Public Utility District No. 1 of Snohomish
County, 1, Duong Long; Public Utility District No. 1 of Snohomish County, 5, Nietfeld Sam
0
Response
Thank you for your comment. The SDT believes we have met the directives of the FERC order.
Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee 2019-01
Modifications to TPL-007
Answer
Yes
Document Name
Comment
The SRC agrees that the revisions to Requirements R7, R8, and R11 substantially satisfy FERC’s directives articulated in Order No. 851, and
refers the SDT to the comments provided in response to Question Nos. 1 and 2.
Likes
0
Dislikes
0
Response
Thank you for your comment. The language in R7.3, R7.4, R11.3, and R11.4 has been modified to clarify intent.
Bobbi Welch - Midcontinent ISO, Inc. - 2 - MRO,SERC,RF
Answer
Yes
Document Name
Comment
MISO supports the comments submitted by the IRC SRC.
Consideration of Comments
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102
Likes
0
Dislikes
0
Response
Thank you for your comment. The language in R7.3, R7.4, R11.3, and R11.4 has been modified to clarify intent.
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
The SDT has met the directive in Order 851.
BPA understands that the SDT had to respond with proposed changes to meet the directive. BPA believes requiring a corrective action plan
for a Supplemental GMD Event is unreasonable and imposes an unnecessary burden on transmission owners and operators.
BPA believes that mitigation strategies for GMD events and the ensuing geomagnetically induced currents would likely be considered novel
and in the Research and Development or prototype stages. As such, most devices or control/relay schemes that might be part of a
corrective action plan could increase operational complexity and a potential loss of system security. While attempting to mitigate the risk
from a low frequency benchmark GMD event, additional risk may be introduced which results in a net reduction in system security. Hence,
there is caution from utilities and the industry in general about mandating corrective action plans for schemes and devices that are not well
developed and commonly deployed.
BPA supports the comments made by NERC, referenced in FERC’s Final Rule, issued on 11/15/18, Docket Nos. RM18-8-000 and RM15-11003, Order No. 851; paragraph 35, lines
1-12, which were unfortunately rejected by FERC. Excerpted below:
NERC’s comments reiterate the rationale in its petition that requiring mitigation
“would result in the de facto replacement of the benchmark GMD event with the
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103
proposed supplemental GMD event.” 39 NERC maintains that “while the supplemental
GMD event is strongly supported by data and analysis in ways that mirror the benchmark
GMD event, there are aspects of it that are less definitive than the benchmark GMD event
and less appropriate as the basis of requiring Corrective Action Plans.”40 NERC also
claims that the uncertainty of geographic size of the supplemental GMD event could not
be addressed adequately by sensitivity analysis or through other methods because there
are “inherent sources of modeling uncertainty (e.g., earth conductivity model, substation
grounding grid resistance values, transformer thermal and magnetic response models) …
[and] introducing additional variables for sensitivity analysis, such as the size of the
localized enhancement, may not improve the accuracy of GMD Vulnerability Assessments.”41
39 Id. at 11-12; see also id. at 14 (“many entities would likely employ the most
conservative approach for conducting supplemental GMD Vulnerability Assessments,
which would be to apply extreme peak values uniformly over an entire planning area”).
40 Id. at 13.
41 Id. at 15.
Likes
Dislikes
5
Snohomish County PUD No. 1, 3, Chaney Holly; Public Utility District No. 1 of Snohomish County, 4,
Martinsen John; Snohomish County PUD No. 1, 6, Liang John; Public Utility District No. 1 of Snohomish
County, 1, Duong Long; Public Utility District No. 1 of Snohomish County, 5, Nietfeld Sam
0
Consideration of Comments
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104
Response
Thank you for your comment. FERC order 851 requires the SDT to develop a CAP for supplemental event:
“The Commission also directs NERC to develop and submit modifications to Reliability Standard TPL-007-2: (1) to require the development
and implementation of corrective action plans to mitigate assessed supplemental GMD event vulnerabilities;……”
Bruce Reimer - Manitoba Hydro - 1
Answer
Yes
Document Name
Comment
The proposed language meets the FERC directive.
Likes
0
Dislikes
0
Response
Thank you for your comment.
Ayman Samaan - Edison International - Southern California Edison Company - 1
Answer
Yes
Document Name
Comment
my possible answer is NO.
Please see EEI's comments
Likes
0
Consideration of Comments
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105
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
sean erickson - Western Area Power Administration - 1
Answer
Yes
Document Name
Comment
Yes, the proposed TPL-007-4 Requirements R7, R8, and R11 meets the directives of FERC Order No. 851.
However, FERC has not mandated the specific timetable proposed in Requirement R11, Part 11.3. Considering the 150% geoelectric field
enhancement reflected by the supplemental GMD event over the benchmark GMD event, we suggest that the Project 2019-01 SDT modify
Requirement R11, Parts 11.3.1 and 11.3.2 to three and six years, respectively.
Likes
0
Dislikes
0
Response
Thank you for your comment. The SDT believes consistent timelines is the best practice for implementing TPL-007-4, non-hardware
mitigations shall be completed within two years and hardware mitigations shall be completed within four years. In addition, the extension
process will allow entities that encounter situations beyond their control to request extensions of time.
Neil Swearingen - Salt River Project - 1,3,5,6 - WECC
Answer
Yes
Document Name
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
106
Comment
SRP has no comments for the standard drafting team.
Likes
0
Dislikes
0
Response
Thank you for your response.
Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer
Yes
Document Name
Comment
None.
Likes
0
Dislikes
0
Response
Matthew Nutsch - Seattle City Light - 1,3,4,5,6 - WECC
Answer
Yes
Document Name
Comment
SCL agrees modifications to R7, R8, and R11 properly address the requirements in FERC Order 851 as noted under 1 and 2 above.
Consideration of Comments
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107
Likes
0
Dislikes
0
Response
Thank you for your comment.
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Rahn Petersen - PNM Resources - Public Service Company of New Mexico - 1 - WECC,Texas RE
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Bette White - AES - Indianapolis Power and Light Co. - 3
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
108
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no NGrid and NYISO
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Quintin Lee - Eversource Energy - 1
Answer
Yes
Document Name
Comment
Likes
0
Consideration of Comments
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109
Dislikes
0
Response
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Aaron Staley - Orlando Utilities Commission - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Anton Vu - Los Angeles Department of Water and Power - 6
Answer
Yes
Consideration of Comments
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110
Document Name
Comment
Likes
0
Dislikes
0
Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO, Group Name SPP Standards Review Group
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Anthony Jablonski - ReliabilityFirst - 10
Answer
Yes
Document Name
Comment
Likes
Dislikes
0
0
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
111
Response
Andrea Barclay - Georgia System Operations Corporation - 3,4
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Standard Collaborations
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Scott McGough - Georgia System Operations Corporation - 3,4
Answer
Yes
Document Name
Consideration of Comments
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112
Comment
Likes
0
Dislikes
0
Response
Keith Jonassen - Keith Jonassen On Behalf of: Michael Puscas, ISO New England, Inc., 2; - Keith Jonassen
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Eleanor Ewry - Puget Sound Energy, Inc. - 1,3,5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Consideration of Comments
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113
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Greg Davis - Georgia Transmission Corporation - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - MRO,WECC
Answer
Yes
Document Name
Comment
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
114
Likes
0
Dislikes
0
Response
Lana Smith - San Miguel Electric Cooperative, Inc. - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
James Mearns - Pacific Gas and Electric Company - 1,3,5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
115
Steve Arnold - City of Independence, Power and Light Department - 1,3,5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Chantal Mazza - Hydro-Qu?bec TransEnergie - 1 - NPCC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
John Tolo - Unisource - Tucson Electric Power Co. - 1
Answer
Yes
Document Name
Comment
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
116
Likes
0
Dislikes
0
Response
Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1,3,5,6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Nick Batty - Keys Energy Services - 4
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
117
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Travis Chrest - South Texas Electric Cooperative - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Frank Pace - Central Hudson Gas & Electric Corp. - 1,3
Answer
Yes
Document Name
Comment
Likes
0
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
118
Dislikes
0
Response
Christopher Overberg - Con Ed - Consolidated Edison Co. of New York - 6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Nick Batty - Keys Energy Services - NA - Not Applicable - SERC
Answer
Yes
Consideration of Comments
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119
Document Name
Comment
Likes
0
Dislikes
0
Response
Aubrey Short - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE VOTER
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Dennis Sismaet - Northern California Power Agency - 6
Answer
Yes
Document Name
Comment
Likes
Dislikes
0
0
Consideration of Comments
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120
Response
Marty Hostler - Northern California Power Agency - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Please see Texas RE’s answer to #1.
Likes
0
Dislikes
0
Response
Thank you for your comment. FERC Order No. 830 (P. 97 and P.102) and FERC Order No. 851 (P. 54) state that NERC should consider
extensions of time on a case-by-case basis. FERC Order 851 (P. 5 and P. 55) expands upon this by referring to submission "to NERC or a
Regional Entity, as appropriate". The DRAFT TPL-007-4 CAP Extension Request Review Process document expresses how ERO Enterprise
Compliance Monitoring and Enforcement staff (CMEP staff) will jointly review requests for extensions to Corrective Action Plans (CAPs)
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
121
developed under TPL-007-4. The DRAFT TPL-007-4 CAP Extension Request Review Process document was developed by NERC Compliance
Assurance, not Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension process will be
forwarded to NERC Compliance Assurance staff. The language in R7.3, R7.4, R11.3, and R11.4 has been modified to clarify intent.
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Document Name
Comment
“See EEI’s comments” on Modifications to TPL-007-3 – TPL-007-4 Transmission System Planned Performance for Geomagnetic Disturbance
Events.
Likes
0
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Consideration of Comments
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122
5. Do you have any comments on the modified VRF/VSL for Requirements R7, R8, and R11?
Aubrey Short - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE VOTER
Answer
No
Document Name
Comment
No comments on the modified VRF/VSL for Requirements R7, R8 and R11
Likes
0
Dislikes
0
Response
Thank you for your response.
Neil Swearingen - Salt River Project - 1,3,5,6 - WECC
Answer
No
Document Name
Comment
SRP has no comments for the standard drafting team.
Likes
0
Dislikes
0
Response
Thank you for your response.
Ayman Samaan - Edison International - Southern California Edison Company - 1
Consideration of Comments
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123
Answer
No
Document Name
Comment
Please see EEI's comments
Likes
0
Dislikes
0
Response
Thank you for your comment. EEI did not provide comments on Question 5.
Kenya Streeter - Edison International - Southern California Edison Company - 6
Answer
No
Document Name
Comment
See EEI's comments.
Likes
0
Dislikes
0
Response
Thank you for your comment. EEI did not provide comments on Question 5.
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
No
Document Name
Comment
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
124
No comment
Likes
5
Dislikes
Snohomish County PUD No. 1, 3, Chaney Holly; Public Utility District No. 1 of Snohomish County, 4,
Martinsen John; Snohomish County PUD No. 1, 6, Liang John; Public Utility District No. 1 of Snohomish
County, 1, Duong Long; Public Utility District No. 1 of Snohomish County, 5, Nietfeld Sam
0
Response
David Jendras - Ameren - Ameren Services - 3
Answer
No
Document Name
Comment
Ameren agrees with and supports EEI comments.
Likes
0
Dislikes
0
Response
Thank you for your comment. EEI did not provide comments on Question 5.
Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee 2019-01
Modifications to TPL-007
Answer
No
Document Name
Comment
Consideration of Comments
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125
None.
Likes
0
Dislikes
0
Response
Marty Hostler - Northern California Power Agency - 5
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Dennis Sismaet - Northern California Power Agency - 6
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Consideration of Comments
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126
Nick Batty - Keys Energy Services - NA - Not Applicable - SERC
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1
Answer
No
Document Name
Comment
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
127
Likes
0
Dislikes
0
Response
sean erickson - Western Area Power Administration - 1
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Christopher Overberg - Con Ed - Consolidated Edison Co. of New York - 6
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Consideration of Comments
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128
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer
No
Document Name
Comment
Likes
5
Dislikes
Snohomish County PUD No. 1, 3, Chaney Holly; Public Utility District No. 1 of Snohomish County, 4,
Martinsen John; Snohomish County PUD No. 1, 6, Liang John; Public Utility District No. 1 of Snohomish
County, 1, Duong Long; Public Utility District No. 1 of Snohomish County, 5, Nietfeld Sam
0
Response
Frank Pace - Central Hudson Gas & Electric Corp. - 1,3
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Travis Chrest - South Texas Electric Cooperative - 1
Answer
No
Document Name
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
129
Comment
Likes
0
Dislikes
0
Response
Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Nick Batty - Keys Energy Services - 4
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
130
Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1,3,5,6
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
John Tolo - Unisource - Tucson Electric Power Co. - 1
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Bruce Reimer - Manitoba Hydro - 1
Answer
No
Document Name
Comment
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
131
Likes
0
Dislikes
0
Response
Chantal Mazza - Hydro-Qu?bec TransEnergie - 1 - NPCC
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
James Mearns - Pacific Gas and Electric Company - 1,3,5
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
132
Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - MRO,WECC
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Greg Davis - Georgia Transmission Corporation - 1
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Eleanor Ewry - Puget Sound Energy, Inc. - 1,3,5
Answer
No
Document Name
Comment
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
133
Likes
0
Dislikes
0
Response
Deanna Carlson - Cowlitz County PUD - 5
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Keith Jonassen - Keith Jonassen On Behalf of: Michael Puscas, ISO New England, Inc., 2; - Keith Jonassen
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Scott McGough - Georgia System Operations Corporation - 3,4
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
134
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Standard Collaborations
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Andrea Barclay - Georgia System Operations Corporation - 3,4
Answer
No
Document Name
Comment
Likes
0
Consideration of Comments
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135
Dislikes
0
Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO, Group Name SPP Standards Review Group
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Anton Vu - Los Angeles Department of Water and Power - 6
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6
Answer
No
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
136
Document Name
Comment
Likes
0
Dislikes
0
Response
Aaron Staley - Orlando Utilities Commission - 1
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Sean Cavote - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer
No
Document Name
Comment
Likes
Dislikes
0
0
Consideration of Comments
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137
Response
Eric Shaw - Eric Shaw On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; - Eric Shaw
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
No
Document Name
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
138
Comment
Likes
0
Dislikes
0
Response
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
139
Quintin Lee - Eversource Energy - 1
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no NGrid and NYISO
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Bobbi Welch - Midcontinent ISO, Inc. - 2 - MRO,SERC,RF
Answer
No
Document Name
Comment
Consideration of Comments
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140
Likes
0
Dislikes
0
Response
Bette White - AES - Indianapolis Power and Light Co. - 3
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Rahn Petersen - PNM Resources - Public Service Company of New Mexico - 1 - WECC,Texas RE
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Consideration of Comments
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141
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Matthew Nutsch - Seattle City Light - 1,3,4,5,6 - WECC
Answer
Yes
Document Name
Comment
SCL agrees with the descriptions of VRF/VSL in the standard for requirements R7, R8, and R11.
Likes
0
Dislikes
0
Response
The SDT thanks you for your comment.
Richard Jackson - U.S. Bureau of Reclamation - 1
Answer
Yes
Document Name
Comment
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
142
Reclamation recommends combining R7 and R11. For consistency, Reclamation also recommends the VRF/VSL for these requirements be
combined.
Likes
0
Dislikes
0
Response
Thank you for your comment. The standard is drafted in the manner that the vulnerability assessment and CAP development for the
benchmark and supplemental events are defined in separate sequential requirements in order to keep the standard language clear and
avoid misinterpretation. Since TPL-007-3 is an active standard and responsible entities are currently performing the pertinent studies, the
SDT decided to preserve the numbering structure in TPL-007-3 to minimize the disruption existing processes and documentation.
Steve Arnold - City of Independence, Power and Light Department - 1,3,5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Lana Smith - San Miguel Electric Cooperative, Inc. - 5
Answer
Yes
Document Name
Comment
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
143
Likes
0
Dislikes
0
Response
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Anthony Jablonski - ReliabilityFirst - 10
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Selene Willis - Edison International - Southern California Edison Company - 5
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
144
Answer
Document Name
Comment
“See EEI’s comments” on Modifications to TPL-007-3 – TPL-007-4 Transmission System Planned Performance for Geomagnetic Disturbance
Events.
Likes
0
Dislikes
0
Response
Thank you for your comment. EEI did not provide comments on Question 5.
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
145
6. Do you agree with the proposed Implementation Plan? If you think an alternate, shorter or longer implementation time period is
needed, please propose an alternate implementation plan and time period, and provide a detailed explanation of actions planned to
meet the implementation deadline.
Richard Jackson - U.S. Bureau of Reclamation - 1
Answer
No
Document Name
Comment
Continuing with a previous standard’s implementation plan causes confusion, misunderstandings, and the increased potential for missed
deadlines. Reclamation recommends retiring the implementation plans for previous versions of TPL-007 and creating a new implementation
plan for TPL-007-4 so there is only one implementation plan to work toward.
Likes
0
Dislikes
0
Response
Thank you for your comment. Although there are some additions to the requirements, the implementation plan for TPL-007-4 (the revised
standard) is the same as the existing, approved TPL-007-3 standard with the exception of R11, which is a new requirement in TPL-007-4.
Despite the additions, the SDT believes this implementation plan allows sufficient time for applicable entities to meet the added
requirements in the revised standard.
Kenya Streeter - Edison International - Southern California Edison Company - 6
Answer
No
Document Name
Comment
Consideration of Comments
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146
See EEI's comments.
Likes
0
Dislikes
0
Response
Thank you for your comment. EEI did not provide comments on Question 6.
Bruce Reimer - Manitoba Hydro - 1
Answer
No
Document Name
Comment
The implementation plan is likely long enough but does it make sense to have a standard in place that won’t be effective for several years?
Based on Canadian Law, when a standard is adopted it becomes immediately effective.
Likes
0
Dislikes
0
Response
Thank you for your comment. The implementation plan establishes future compliance dates which allows the applicable entities, as
established in R1, sufficient time to prepare to meet the requirements. The implementation plan also provides that a governmental
authority may provide different dates.
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer
No
Document Name
Comment
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CHPD does not agree with requiring a CAP for supplemental GMD event (TPL-007-4 R11). Therefore, CHPD does not agree with the
implementation plan which requires compliance with R11.
Likes
5
Dislikes
Snohomish County PUD No. 1, 3, Chaney Holly; Public Utility District No. 1 of Snohomish County, 4,
Martinsen John; Snohomish County PUD No. 1, 6, Liang John; Public Utility District No. 1 of Snohomish
County, 1, Duong Long; Public Utility District No. 1 of Snohomish County, 5, Nietfeld Sam
0
Response
Thank you for your comment. Requirement R11 was added by the SDT to address the FERC directive in Order No. 851 (Paragraphs 4 and 39
of the Order) which requires CAPs for the vulnerabilities identified in the supplemental GMD analysis.
Deanna Carlson - Cowlitz County PUD - 5
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee 2019-01
Modifications to TPL-007
Answer
Yes
Document Name
Comment
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None.
Likes
0
Dislikes
0
Response
David Jendras - Ameren - Ameren Services - 3
Answer
Yes
Document Name
Comment
Ameren agrees with and supports EEI comments.
Likes
0
Dislikes
0
Response
Thank you for your comment. EEI did not provide comments for Question 6.
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
No comment
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Likes
5
Dislikes
Snohomish County PUD No. 1, 3, Chaney Holly; Public Utility District No. 1 of Snohomish County, 4,
Martinsen John; Snohomish County PUD No. 1, 6, Liang John; Public Utility District No. 1 of Snohomish
County, 1, Duong Long; Public Utility District No. 1 of Snohomish County, 5, Nietfeld Sam
0
Response
Ayman Samaan - Edison International - Southern California Edison Company - 1
Answer
Yes
Document Name
Comment
Please see EEI's comments
Likes
0
Dislikes
0
Response
Thank you for your comment. EEI did not provide comments for Question 6.
sean erickson - Western Area Power Administration - 1
Answer
Yes
Document Name
Comment
Yes, the proposed TPL-007-4 Implementation Plan is consistent; essentially no TPL-007-3 Compliance Dates are changed, except for the
modified Requirements R7 and R11 (Requirement R8 proposed changes are trivial). Given the expectation of a rapid FERC approval process,
the 01 January 2024 Compliance Dates to develop corrective actions for the supplemental GMD event are reasonable.
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Likes
0
Dislikes
0
Response
Thank you for your comment.
Neil Swearingen - Salt River Project - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
SRP has no comments for the standard drafting team.
Likes
0
Dislikes
0
Response
Thank you for your response.
Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer
Yes
Document Name
Comment
None.
Likes
0
Dislikes
0
Response
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151
Matthew Nutsch - Seattle City Light - 1,3,4,5,6 - WECC
Answer
Yes
Document Name
Comment
SCL agrees with the impmentation plan for R7, R8, and R11. However, SCL would like to see a later effective date for R12 and R13 or clear
guidelines on how to monitor and collect GIC from at least one GIC monitor located in the Planning Coordinator’s area.
Likes
0
Dislikes
0
Response
Thank you for your comment. The SDT did not change the effective dates for R12 and R13 (R11 and R12 in TPL-007-3) from those in the
previous version of the standard. The applicable entity for this requirement is determined in R1. The R12 requirement states “in the
Planning Coordinators area or in the Planning Coordinator’s GIC System model.” The SDT drafted a Technical Rationale document where
more information can be found.
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
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Rahn Petersen - PNM Resources - Public Service Company of New Mexico - 1 - WECC,Texas RE
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Bette White - AES - Indianapolis Power and Light Co. - 3
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Bobbi Welch - Midcontinent ISO, Inc. - 2 - MRO,SERC,RF
Answer
Yes
Document Name
Comment
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Likes
0
Dislikes
0
Response
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no NGrid and NYISO
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Quintin Lee - Eversource Energy - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
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154
Douglas Webb - Douglas Webb On Behalf of: Allen Klassen, Westar Energy, 6, 3, 1, 5; Bryan Taggart, Westar Energy, 6, 3, 1, 5; Derek
Brown, Westar Energy, 6, 3, 1, 5; Grant Wilkerson, Westar Energy, 6, 3, 1, 5; James McBee, Great Plains Energy - Kansas City Power and
Light Co., 1, 3, 6, 5; Jennifer Flandermeyer, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; John Carlson, Great Plains
Energy - Kansas City Power and Light Co., 1, 3, 6, 5; Marcus Moor, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; Douglas Webb, Group Name Westar-KCPL
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
Yes
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Document Name
Comment
Likes
0
Dislikes
0
Response
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Eric Shaw - Eric Shaw On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; - Eric Shaw
Answer
Yes
Document Name
Comment
Likes
Dislikes
0
0
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Response
Sean Cavote - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Aaron Staley - Orlando Utilities Commission - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Anton Vu - Los Angeles Department of Water and Power - 6
Answer
Yes
Document Name
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Comment
Likes
0
Dislikes
0
Response
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO, Group Name SPP Standards Review Group
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Anthony Jablonski - ReliabilityFirst - 10
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
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Andrea Barclay - Georgia System Operations Corporation - 3,4
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Standard Collaborations
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Scott McGough - Georgia System Operations Corporation - 3,4
Answer
Yes
Document Name
Comment
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Likes
0
Dislikes
0
Response
Keith Jonassen - Keith Jonassen On Behalf of: Michael Puscas, ISO New England, Inc., 2; - Keith Jonassen
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Eleanor Ewry - Puget Sound Energy, Inc. - 1,3,5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
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Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Greg Davis - Georgia Transmission Corporation - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - MRO,WECC
Answer
Yes
Document Name
Comment
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161
Likes
0
Dislikes
0
Response
Lana Smith - San Miguel Electric Cooperative, Inc. - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
James Mearns - Pacific Gas and Electric Company - 1,3,5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Steve Arnold - City of Independence, Power and Light Department - 1,3,5
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Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Chantal Mazza - Hydro-Qu?bec TransEnergie - 1 - NPCC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
John Tolo - Unisource - Tucson Electric Power Co. - 1
Answer
Yes
Document Name
Comment
Likes
0
Consideration of Comments
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163
Dislikes
0
Response
Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1,3,5,6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Nick Batty - Keys Energy Services - 4
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer
Yes
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Document Name
Comment
Likes
0
Dislikes
0
Response
Travis Chrest - South Texas Electric Cooperative - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Frank Pace - Central Hudson Gas & Electric Corp. - 1,3
Answer
Yes
Document Name
Comment
Likes
Dislikes
0
0
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165
Response
Christopher Overberg - Con Ed - Consolidated Edison Co. of New York - 6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Nick Batty - Keys Energy Services - NA - Not Applicable - SERC
Answer
Yes
Document Name
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Comment
Likes
0
Dislikes
0
Response
Aubrey Short - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE VOTER
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Dennis Sismaet - Northern California Power Agency - 6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
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Marty Hostler - Northern California Power Agency - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE noticed that TPL-007-3 is incorrectly referenced on page 1 of the Implementation Plan.
Likes
0
Dislikes
0
Response
Thank you for your comment. The SDT believes that TPL-007-3 is correctly referenced in the Implementation Plan.
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Document Name
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Comment
“See EEI’s comments” on Modifications to TPL-007-3 – TPL-007-4 Transmission System Planned Performance for Geomagnetic Disturbance
Events.
Likes
0
Dislikes
0
Response
Thank you for your comment. EEI did not provide comments on Question 6.
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7. The SDT proposes that the modifications in TPL-007-4 meet the FERC directives in a cost effective manner. Do you agree? If you do not
agree, or if you agree but have suggestions for improvement to enable more cost effective approaches, please provide your
recommendation and, if appropriate, technical or procedural justification.
Thomas Foltz - AEP - 5
Answer
No
Document Name
Comment
TPL-007-4, in contrast to the majority of standards established by NERC, GMD Vulnerability Assessments are not representative of an
existing utility practice. This is highlighted by the fact that there is a deficit of modeling tools available that would enable an entity to
comply with the requirements specified herein. The burden of expenses relative to CAPs has yet to be established because there are very
few examples of vulnerability assessments that have been completed for either the benchmark or the supplemental GMD events. In
essence, the science to prudently study and assess system vulnerabilities related to a High Impact, Low Frequency (HILF) event on the
system is not conclusive and still subjective. In short, the obligations have come before the development of proven modeling tools and
mitigation techniques. Once again, AEP believes that R11 is unnecessarily duplicative of the obligations already required for the benchmark
event, and as such, we do not believe it to be cost effective. Those resources would be better served for efforts having a discernable,
positive impact on the reliability of the BES. Rather than pursuing this course, we believe a more prudent path, as well as a more cost
effective path, would be as we propose in our response to Q1.
Likes
0
Dislikes
0
Response
Thank you for your comment. The SDT believes that analyzing both benchmark and supplement events is the scientifically justified approach
to the study of GMD events that is not based solely on spatially averaged data. See Benchmark and Supplemental GMD Event White Papers.
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FERC order 851 requires the SDT to develop a CAP for supplemental event:
“The Commission also directs NERC to develop and submit modifications to Reliability Standard TPL-007-2: (1) to require the development
and implementation of corrective action plans to mitigate assessed supplemental GMD event vulnerabilities;……”
sean erickson - Western Area Power Administration - 1
Answer
No
Document Name
Comment
No, we do not agree that the modifications in TPL-007-4 meet the FERC directives in a cost effective manner; the imposition of Requirement
R11, Parts 11.3.1 and 11.3.2 deadlines for corrective action implementation are too short thereby escalating costs. We echo industry
comments made during previous modifications to TPL-007-1: FERC opened the door for NERC to propose alternatives to the two- and fouryear implementation of corrective actions (FERC Order No. 830, Paragraph 97); FERC was clearly persuaded by device manufacturers over
the concerns of utility commenters that mitigation deadlines were impractical (FERC Order No. 830, Paragraph 102). This was particularly
problematic because the hardware solutions that existed then, as well as today, remain widely unproven (only one implementation in the
continental United States) and are simply not suitable for highly networked Systems (blocking GICs pushes the problem onto
neighbors). Given that FERC has directed corrective actions and implementation deadlines, as well as facilitated time extensions, the costeffectiveness of the proposed TPL-007-4 would be enhanced by including a section in the Technical Rationale that discusses how and when
time extensions are reasonable. Examples could include a treatment of how to navigate the challenges of formulating appropriate jointmitigations with neighbors to address widespread GMD impacts and how, during the process of mitigation implementation, unexpected
System impacts may arise that delay completion.
Likes
0
Dislikes
0
Response
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171
Thank you for your comment. The SDT believes having the same CAP timelines for both the benchmark and supplemental GMD
vulnerability assessments is consistent with FERC Orders 830 and 851. In addition, the extension process will allow entities that encounter
situations beyond their control to request extensions of time.
Examples of situations beyond the control of the entity for which extensions of time may be approved are contained in the Implementation
Guidance document. The SDT provided comments to CMEP staff and believes that the revised draft process prepared by CMEP staff may
address many of your concerns.
Christopher Overberg - Con Ed - Consolidated Edison Co. of New York - 6
Answer
No
Document Name
Comment
Requirements 7.3, 7.4, 11.3, and 11.4 should be revised to require extension request submittals be made to the entity’s Reliability
Coordinator (RC), not the ERO. The RC has the wide-area view, analysis tools, models and data necessary to ensure that extension requests
are effectively evaluated. It is unlikely that the ERO will have the necessary information to assess the extension request, and the ERO and
will seek RC concurrence in order to adequately respond to an extension request. This adds multiple steps and inefficiencies into the
extension request process. The Requirements 7.3, 7.4, 11.3, and 11.4 should stipulate that extension requests are submitted to the RC for
approval. This is a more appropriate and cost-effective approach to addressing the requests.
Likes
0
Dislikes
0
Response
Thank you for your comment. FFERC Order No. 830 (P. 97 and P.102) and FERC Order No. 851 (P. 54) state that NERC should consider
extensions of time on a case-by-case basis. FERC Order 851 (P. 5 and P. 55) expands upon this by referring to submission "to NERC or a
Regional Entity, as appropriate".
Joyce Gundry - Public Utility District No. 1 of Chelan County - 3, Group Name CHPD
Answer
No
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172
Document Name
Comment
The industry is in the preliminary stages of assessing and developing mitigation measures for GMD events and has not had much time to
develop engineering-judgement, experience, or expertise in this field. Revising the standard to include CAPs for the supplementary GMD
event is not appropriate at this time as the industry is still building a foundation for this type of system event analysis and exploring
mitigation measures. Without a sound foundation developed, requiring CAPs for the supplemental GMD event could lead to unnecessary
mitigation measures and an immense amount of industry resources spent on a still developing science. CHPD suggests that the benchmark
GMD event be fully vetted before moving onto additional scenarios such as the supplemental event.
Likes
5
Dislikes
Snohomish County PUD No. 1, 3, Chaney Holly; Public Utility District No. 1 of Snohomish County, 4,
Martinsen John; Snohomish County PUD No. 1, 6, Liang John; Public Utility District No. 1 of Snohomish
County, 1, Duong Long; Public Utility District No. 1 of Snohomish County, 5, Nietfeld Sam
0
Response
FERC order 851 requires the SDT to develop a CAP for supplemental event:
“The Commission also directs NERC to develop and submit modifications to Reliability Standard TPL-007-2: (1) to require the development
and implementation of corrective action plans to mitigate assessed supplemental GMD event vulnerabilities;……”
Bruce Reimer - Manitoba Hydro - 1
Answer
No
Document Name
Comment
The proposed changes mandates implementation of a Corrective Action Plan for the supplemental GMD event (12 V/km). The research into
this type of disturbance is still evolving. The available tools do not support studying this disturbance at this time. The tools available would
allow for a uniform field over the entire planning Coordinator area. If this field is increased from 8 V/km to 12 V/km that corresponds to a
Consideration of Comments
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173
disturbance well in excess of the 1/100 year level suggested by the benchmark. This is not just and reasonable. Let TPL-007-2 run through
its first cycle of studies and review the assessment results. Perhaps the next cycle of studies could evolve to the proposed wording in TPL007-4 once the research and tools have matured and an assessment of the potential costs have been tabulated to address the supplemental
event.
Likes
0
Dislikes
0
Response
FERC order 851 requires the SDT to develop a CAP for supplemental event:
“The Commission also directs NERC to develop and submit modifications to Reliability Standard TPL-007-2: (1) to require the development
and implementation of corrective action plans to mitigate assessed supplemental GMD event vulnerabilities;……”
Kenya Streeter - Edison International - Southern California Edison Company - 6
Answer
No
Document Name
Comment
See EEI's comments.
Likes
0
Dislikes
0
Response
Thank you for your comment. EEI did not provide comments for Question 7.
Eleanor Ewry - Puget Sound Energy, Inc. - 1,3,5
Answer
No
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174
Document Name
Comment
It is difficult to assess the exact financial impacts of the requirements in this standard.
may or may not be cost effective.
Likes
The addition of CAP for Supplementary GMD event
0
Dislikes
0
Response
Thank you for your comment.
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
No
Document Name
Comment
BPA agrees that the SDT satisfied its obligation to modify TPL-007 to meet the directives in FERC Order No. 851.
BPA can not determine if the directives are cost effective. The modifications are requiring a corrective action plan for an extreme event
(Supplemental GMD event). The Transmission Planners and Transmission Owners have not done the analysis to determine the impact and
the cost of the corrective action plans that would be required. BPA believes without this analysis, the cost effectiveness can not be
determined.
BPA believes that assessing the event and performing an evaluation of possible actions to reduce the likelihood of the impact is more
appropriate than requiring a Supplemental GMD event corrective action plan.
Likes
5
Snohomish County PUD No. 1, 3, Chaney Holly; Public Utility District No. 1 of Snohomish County, 4,
Martinsen John; Snohomish County PUD No. 1, 6, Liang John; Public Utility District No. 1 of Snohomish
County, 1, Duong Long; Public Utility District No. 1 of Snohomish County, 5, Nietfeld Sam
Consideration of Comments
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175
Dislikes
0
Response
Thank you for your comment.
Russell Noble - Cowlitz County PUD - 3
Answer
No
Document Name
Comment
We are concerned the cost and effort to address this standard could hinder other more important Transmission improvements.
Likes
0
Dislikes
0
Response
Thank you for your comment.
Joe O'Brien - NiSource - Northern Indiana Public Service Co. - 6
Answer
No
Document Name
Comment
Comments: See comments on Question 2
Likes
0
Dislikes
0
Response
Thank you for your response, please see answer on Question 2.
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Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Standard Collaborations
Answer
No
Document Name
Comment
If unintended duplication of efforts between baseline and supplemental corrective action plans occurs, as referenced in the response to
question 2, that would lead to unnecessary increases in costs to registered entities. Please reference the suggestion in our response to
question 2.
Likes
0
Dislikes
0
Response
Thank you for your comment. The SDT does not believe there is a duplication of efforts. A single corrective action plan could address both
the benchmark and supplemental vulnerability assessment, or the entity could develop separate corrective action plans for the benchmark
event or the supplemental event.
Richard Jackson - U.S. Bureau of Reclamation - 1
Answer
No
Document Name
Comment
For the implementation of numerous, overlapping versions of the same standard (such as the implementation of TPL-007-2, TPL-007-3, and
TPL-007-4) with lengthy phased-in implementation timelines, Reclamation supports the incorporation of insignificant subsequent
modifications (such as the changes from TPL-007-2 to TPL-007-3 to TPL-007-4) in accordance with existing phased-in implementation
milestones, but recommends that all previous implementation plans be retired so that there is only one implementation plan in effect at a
time.
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177
Likes
0
Dislikes
0
Response
Thank you for your comment. Although there are some additions to the requirements, the implementation plan for TPL-007-4 (the revised
standard) is the same as the existing, approved TPL-007-3 standard with the exception of R11, which is a new requirement in TPL-007-4.
Despite the additions, the SDT believes this implementation plan allows sufficient time for applicable entities to meet the added
requirements in the revised standard.
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO, Group Name SPP Standards Review Group
Answer
No
Document Name
Comment
The SPP Standards Review Group (SSRG) has no concerns to cost effective issues from a Planning Coordinator (PC) perspective, however,
from the SPP membership perspective, the imposition of Requirement R11, Parts 11.3.1 and 11.3.2 deadlines for corrective action
implementation are short, thereby escalating costs over two and four years. This timeframe could create issues for hardware solutions.
Given that FERC has directed corrective actions and implementation deadlines, as well as facilitated time extensions, the cost-effectiveness
of the proposed TPL-007-4 would be enhanced by including a section in the Technical Rationale that discusses how and when time
extensions are reasonable. Examples could include a treatment of how to navigate the challenges of formulating appropriate jointmitigations with neighbors to address widespread GMD impacts and how, during the process of mitigation implementation, unexpected
System impacts may arise that delay completion.
Likes
0
Dislikes
0
Response
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178
Thank you for your comment. Examples of situations beyond the control of the entity for which extensions of time may be approved are
contained in the Implementation Guidance document. The SDT provided comments to CMEP staff and believes that the revised draft
process prepared by CMEP staff may address many of your concerns.
Dennis Chastain - Tennessee Valley Authority - 1,3,5,6 - SERC
Answer
No
Document Name
Comment
TVA supports comments submitted by AEP for Question #7
Likes
0
Dislikes
0
Response
Thank you for your comment. The SDT believes that analyzing both benchmark and supplement events is the scientifically justified approach
to the study of GMD events that is not based solely on spatially averaged data. See Benchmark and Supplemental GMD Event White Papers.
FERC order 851 requires the SDT to develop a CAP for supplemental event:
“The Commission also directs NERC to develop and submit modifications to Reliability Standard TPL-007-2: (1) to require the development
and implementation of corrective action plans to mitigate assessed supplemental GMD event vulnerabilities;……”
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no NGrid and NYISO
Answer
No
Document Name
Comment
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Requirements 7.3, 7.4, 11.3, and 11.4 should be revised to require extension request submittals be made to the entity’s Planning
Coordinator (PC), not the ERO. The PC has the wide-area view, analysis tools, models and data necessary to ensure that extension requests
are effectively evaluated. It is unlikely that the ERO will have the necessary information to assess the extension request, and the ERO and
will seek PC concurrence in order to adequately respond to an extension request. This adds multiple steps and inefficiencies into the
extension request process. The Requirements 7.3, 7.4, 11.3, and 11.4 should stipulate that extension requests are submitted to the PC for
approval. This is a more appropriate and cost-effective approach to addressing the requests.
Likes
0
Dislikes
0
Response
Thank you for your comment. FFERC Order No. 830 (P. 97 and P.102) and FERC Order No. 851 (P. 54) state that NERC should consider
extensions of time on a case-by-case basis. FERC Order 851 (P. 5 and P. 55) expands upon this by referring to submission "to NERC or a
Regional Entity, as appropriate". The language in R7.4 and R11.4 has been modified to clarify intent.
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
No
Document Name
Comment
OPG concurs with the RSC comment
Likes
0
Dislikes
0
Response
Thank you for your comment. FFERC Order No. 830 (P. 97 and P.102) and FERC Order No. 851 (P. 54) state that NERC should consider
extensions of time on a case-by-case basis. FERC Order 851 (P. 5 and P. 55) expands upon this by referring to submission "to NERC or a
Regional Entity, as appropriate". The language in R7.4 and R11.4 has been modified to clarify intent.
Consideration of Comments
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Deanna Carlson - Cowlitz County PUD - 5
Answer
No
Document Name
Comment
Likes
0
Dislikes
0
Response
Matthew Nutsch - Seattle City Light - 1,3,4,5,6 - WECC
Answer
Yes
Document Name
Comment
SCL agrees; however, it is difficult to assess the true financial impacts of the requirements in this standard to SCL at this early stage. The
modifications in the standard may or may not be cost-effective to SCL.
Likes
0
Dislikes
0
Response
Thank you for your comment.
Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Answer
Yes
Document Name
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Comment
None.
Likes
0
Dislikes
0
Response
Neil Swearingen - Salt River Project - 1,3,5,6 - WECC
Answer
Yes
Document Name
Comment
SRP has no comments for the standard drafting team.
Likes
0
Dislikes
0
Response
Thank you for your response.
Ayman Samaan - Edison International - Southern California Edison Company - 1
Answer
Yes
Document Name
Comment
Please see EEI's comments
Consideration of Comments
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Likes
0
Dislikes
0
Response
Thank you for your comment. EEI did not provide comments on Question 7.
Bette White - AES - Indianapolis Power and Light Co. - 3
Answer
Yes
Document Name
Comment
NERC should evaluate the relative event probabilities with respect to the cost/benefit analysis of GMD event mitigations. Planning for
increasingly rare system events is inherently at odds with economic planning and rate payer responsibilities.
Likes
0
Dislikes
0
Response
Thank you for your comment.
Marty Hostler - Northern California Power Agency - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
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Dennis Sismaet - Northern California Power Agency - 6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Aubrey Short - FirstEnergy - FirstEnergy Corporation - 4, Group Name FE VOTER
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Nick Batty - Keys Energy Services - NA - Not Applicable - SERC
Answer
Yes
Document Name
Comment
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Likes
0
Dislikes
0
Response
John Merrell - Tacoma Public Utilities (Tacoma, WA) - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Frank Pace - Central Hudson Gas & Electric Corp. - 1,3
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
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Travis Chrest - South Texas Electric Cooperative - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Karie Barczak - DTE Energy - Detroit Edison Company - 3,4,5, Group Name DTE Energy - DTE Electric
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Nick Batty - Keys Energy Services - 4
Answer
Yes
Document Name
Comment
Consideration of Comments
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Likes
0
Dislikes
0
Response
Kevin Conway - Public Utility District No. 1 of Pend Oreille County - 1,3,5,6
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
John Tolo - Unisource - Tucson Electric Power Co. - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Chantal Mazza - Hydro-Qu?bec TransEnergie - 1 - NPCC
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Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Steve Arnold - City of Independence, Power and Light Department - 1,3,5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
James Mearns - Pacific Gas and Electric Company - 1,3,5
Answer
Yes
Document Name
Comment
Likes
0
Consideration of Comments
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Dislikes
0
Response
Lana Smith - San Miguel Electric Cooperative, Inc. - 5
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Maryanne Darling-Reich - Black Hills Corporation - 1,3,5,6 - MRO,WECC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Greg Davis - Georgia Transmission Corporation - 1
Answer
Yes
Consideration of Comments
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Document Name
Comment
Likes
0
Dislikes
0
Response
Amy Casuscelli - Xcel Energy, Inc. - 1,3,5,6 - MRO,WECC
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Scott McGough - Georgia System Operations Corporation - 3,4
Answer
Yes
Document Name
Comment
Likes
Dislikes
0
0
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190
Response
Andrea Barclay - Georgia System Operations Corporation - 3,4
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Anthony Jablonski - ReliabilityFirst - 10
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Anton Vu - Los Angeles Department of Water and Power - 6
Answer
Yes
Document Name
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Comment
Likes
0
Dislikes
0
Response
Aaron Staley - Orlando Utilities Commission - 1
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
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Rahn Petersen - PNM Resources - Public Service Company of New Mexico - 1 - WECC,Texas RE
Answer
Yes
Document Name
Comment
Likes
0
Dislikes
0
Response
Keith Jonassen - Keith Jonassen On Behalf of: Michael Puscas, ISO New England, Inc., 2; - Keith Jonassen
Answer
Document Name
Comment
More experience with implementing the standard is required in order to better understand the implications on its cost-effectiveness.
Likes
0
Dislikes
0
Response
Thank you for your comment.
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Document Name
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Comment
“See EEI’s comments” on Modifications to TPL-007-3 – TPL-007-4 Transmission System Planned Performance for Geomagnetic Disturbance
Events.
Likes
0
Dislikes
0
Response
Thank you for your comment. EEI did not provide comments on Question 7.
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE does not have comments on this question.
Likes
0
Dislikes
0
Response
Thank you for your response.
David Jendras - Ameren - Ameren Services - 3
Answer
Document Name
Comment
Consideration of Comments
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194
Ameren agrees with and supports EEI comments.
Likes
0
Dislikes
0
Response
Thank you for your comment. EEI did not provide comments on Question 7.
Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee 2019-01
Modifications to TPL-007
Answer
Document Name
Comment
No response.
Likes
0
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0
Response
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195
8. Provide any additional comments for the standard drafting team to consider, if desired.
Constantin Chitescu - Ontario Power Generation Inc. - 5
Answer
Document Name
Comment
OPG concurs with the RSC comment
Likes
0
Dislikes
0
Response
Thank you for your response.
Rahn Petersen - PNM Resources - Public Service Company of New Mexico - 1 - WECC,Texas RE
Answer
Document Name
Comment
Nothing further
Likes
0
Dislikes
0
Response
Thank you for your comment.
Bette White - AES - Indianapolis Power and Light Co. - 3
Consideration of Comments
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196
Answer
Document Name
Comment
Thank you for the opportunity to comment.
Likes
0
Dislikes
0
Response
Brandon Gleason - Electric Reliability Council of Texas, Inc. - 2, Group Name ISO/RTO Council Standards Review Committee 2019-01
Modifications to TPL-007
Answer
Document Name
Comment
In Requirements R7 and R11, the SRC suggests replacing “their” with “its” just prior to the first mention of “System” for grammatical
reasons.
Likes
0
Dislikes
0
Response
Thank you for your comment. The SDT implemented the suggested editorial change to R7 and R11.
Bobbi Welch - Midcontinent ISO, Inc. - 2 - MRO,SERC,RF
Answer
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197
Document Name
Comment
MISO supports the comments submitted by the IRC SRC. In addition, MISO would like to propose a clarification to requirement R6, part 6.4.
As written, the Transmission Owner and Generator Owner functions referenced under TPL-007-4, requirement R6, Part 6.4 are not
functions that are included in the identification of the individual and joint responsibilities under TPL-007-4, requirement R1. As a result,
when the Planning Coordinator, in conjunction with its Transmission Planner(s) identifies the individual and joint responsibilities, the
Transmission Owner and Generator Owner are not party to this information and so would not know who to provide the results to.
In addition, there is no provision under R1 that requires the Planning Coordinator to determine or communicate who applicable
Transmission Owners (section 4.1.3) and Generator Owners (section 4.1.4) within its area should send the results of their benchmark
thermal impact assessment to.
MISO became aware of this gap following an inquiry from a transformer owner when they did not know where to send the results.
Possible remedies:
1) Modify Requirement R6, Part 6.4 to reference Requirement 5, i.e. “Be performed and provided to the responsible entity(ies) that
provided the GIC flow information in accordance with Requirement 5, within 24…
2) Clarify the scope of requirement Require R1 to specify that the Planning Coordinator in conjunction with its Transmission Planner(s)
determine which responsible entity(ies) applicable Transmission Owner(s) and Generator Owner(s) in their area should send the results of
their benchmark thermal impact assessment(s) to.
Likes
0
Dislikes
0
Response
Thank you for your comment. The SDT believes that this modification is outside the scope of the SAR.
David Jendras - Ameren - Ameren Services - 3
Consideration of Comments
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198
Answer
Document Name
Comment
Ameren agrees with and supports EEI comments.
Likes
0
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Ruida Shu - Northeast Power Coordinating Council - 1,2,3,4,5,6,7,8,9,10 - NPCC, Group Name RSC no NGrid and NYISO
Answer
Document Name
Comment
The Implementation Guidance document, as written, is not acceptable. Boundaries cannot be established with a CMEP Implementation
Guidance document. CMEP Implementation Guidance is a means to identify one approach to being compliant while not precluding the use
of other approaches. Auditors audit to requirements and don’t use CMEP Implementation Guidance to establish requirements which go
beyond the standard’s requirements. Problematic statements appearing in Chapter 8 of the document include, but may not be limited to,
the following:
•
“The local geoelectric field enhancement should not be smaller than 100 km..”- this threshold value of 100 km does not appear
in the standard requirement
Consideration of Comments
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199
•
“…at a minimum, a West-East orientation should be considered when applying the supplemental event”- the standard
requirement does not contain any wording of a minimum consideration
•
“Geoelectric field outside the local enhancement:
a. Amplitude: should not be smaller than 1.2 V/km…” This also does not appear in the standard.
•
“The schematic in Figure 1 illustrates the boundaries to apply the supplemental GMD event”. This statement creates boundaries
outside of requirements, which guidance cannot do
The use of “shall” or “must” should not be used unless they are being used in the requriements in the standard. This is particularly true for
the requirement associated with sensitive/confidential information. It is not in the standard and was added in the IG as an additional
“requirement”.
Likes
0
Dislikes
0
Response
Thank you for your comment. The SDT updated the Implementation Guidance document to incorporate this feedback.
Douglas Webb - Douglas Webb On Behalf of: Allen Klassen, Westar Energy, 6, 3, 1, 5; Bryan Taggart, Westar Energy, 6, 3, 1, 5; Derek
Brown, Westar Energy, 6, 3, 1, 5; Grant Wilkerson, Westar Energy, 6, 3, 1, 5; James McBee, Great Plains Energy - Kansas City Power and
Light Co., 1, 3, 6, 5; Jennifer Flandermeyer, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; John Carlson, Great Plains
Energy - Kansas City Power and Light Co., 1, 3, 6, 5; Marcus Moor, Great Plains Energy - Kansas City Power and Light Co., 1, 3, 6, 5; Douglas Webb, Group Name Westar-KCPL
Answer
Document Name
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200
Comment
Westar Energy and Kansas City Power & Light Company incorporate by reference and support comments submitted in response to Question
8 by the Edison Electric Institute.
Likes
0
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Rachel Coyne - Texas Reliability Entity, Inc. - 10
Answer
Document Name
Comment
Texas RE recommends that TPL-007-4 be consistent with other standards that require data to be submitted from the applicable entities to
the Regional Entity. Reliability Standards FAC-003-4, EOP-008-2 Requirement R8, and PRC-002-2 Requirement R12 explicitly state the data
shall be submitted to the Regional Entity in the requirement language or in Part C. Compliance section of the standard. There is no need for
an extraneous process document describing where to submit the information.
Texas RE is concerned with introducing a separate process document for submitting CAP extension requests for the following reasons: the
document would not be FERC approved, how would entities and regions know that it exists, where would it be housed, etc. Registered
entities should not have to look beyond the standard in order to understand how to comply with a requirement.
Consideration of Comments
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Likes
0
Dislikes
0
Response
Thank you for your comment. FERC Order No. 830 (P. 97 and P.102) and FERC Order No. 851 (P. 54) state that NERC should consider
extensions of time on a case-by-case basis. FERC Order 851 (P. 5 and P. 55) expands upon this by referring to submission "to NERC or a
Regional Entity, as appropriate". The DRAFT TPL-007-4 CAP Extension Request Review Process document expresses how ERO Enterprise
Compliance Monitoring and Enforcement staff (CMEP staff) will jointly review requests for extensions to Corrective Action Plans (CAPs)
developed under TPL-007-4. The DRAFT TPL-007-4 CAP Extension Request Review Process document was developed by NERC Compliance
Assurance, not Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension process will be
forwarded to NERC Compliance Assurance staff. The language in R7.3, R7.4, R11.3, and R11.4 has been modified to clarify intent.
Pamela Hunter - Southern Company - Southern Company Services, Inc. - 1,3,5,6 - SERC, Group Name Southern Company
Answer
Document Name
Comment
•
R7.1 (page 6 of TPL-007-4 clean draft):
o
o
•
The portion of this sub-requirement starting from “Examples include:” should be moved to the Implementation Guidance, as
the bullet point list’s purpose is more in line with the stated purpose of the Guidance. Consider updating R11.1 as well.
To this end, Page iii of Implementation Guidance Document needs to be updated to reflect new SERC region.
Consider deleting the four references to Attachment 1 in the Draft Technical Rationale document (Draft Tech Rationale_TPL-0074.pdf).
Likes
0
Dislikes
0
Response
Consideration of Comments
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202
Thank you for your comment. The SDT believes that maintaining the examples in Requirements R7.1 and R11.1 is reasonable and minimizes
confusion. The Electric Reliability Organization (ERO) Enterprise map and corresponding table have been updated in the Implementation
Guidance Document. References to Attachment 1 in the Technical Rationale document have been updated for clarity.
Julie Hall - Entergy - 6, Group Name Entergy
Answer
Document Name
Comment
Entergy supports comments submitted by EEI.
Likes
0
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Mark Gray - Edison Electric Institute - NA - Not Applicable - NA - Not Applicable
Answer
Document Name
Comment
EEI acknowledges and supports the good work by the SDT in support of this Reliability Standard believing that it conforms to the directives
issued in FERC Order 851. We also recognize that the supporting/companion ERO process document simply represents an initial draft of the
Extension Request Process. Nevertheless, the process of CAP extention reviews and approvals are inextricably tied to the modification of
this standard. For this reason and as stated in more detail in our response to Question 1, this companion process document needs to
Consideration of Comments
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203
include additional details to ensure effective and transparent processing of entity CAP Extension Requests. The process should also be
formally codified in parallel with the required revisions to this Reliability Standard.
Likes
0
Dislikes
0
Response
Thank you for your comment. The SDT provided comments to CMEP staff and believes that the revised draft process prepared by CMEP
staff may address many of your concerns.
Eric Shaw - Eric Shaw On Behalf of: Lee Maurer, Oncor Electric Delivery, 1; - Eric Shaw
Answer
Document Name
Comment
Please see comments submitted by EEI.
Likes
0
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Sean Cavote - PSEG - 1,3,5,6 - NPCC,RF, Group Name PSEG REs
Answer
Document Name
Comment
Consideration of Comments
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204
PSEG supports EEI's comments.
Likes
0
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Aaron Staley - Orlando Utilities Commission - 1
Answer
Document Name
Comment
With the change that the Benchmark and Supplimental analysis both require a CAP, shouldn't they be consolidated into a single study effort
to reduce the overall number of requirements? The Supplimental seems to only be a Benchmark with additional areas of increased field
strength, unless I am missing some nuiance in how they are performed?
Likes
0
Dislikes
0
Response
Thank you for your comment. The SDT believes that analyzing both benchmark and supplement events is the scientifically justified approach
to the study of GMD events that is not based solely on spatially averaged data. See Benchmark and Supplemental GMD Event White Papers.
FERC order 851 requires the SDT to develop a CAP for supplemental event:
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205
“The Commission also directs NERC to develop and submit modifications to Reliability Standard TPL-007-2: (1) to require the development
and implementation of corrective action plans to mitigate assessed supplemental GMD event vulnerabilities;……”
The SDT has elaborated on the supplement event to the Implementation Guidance document.
Selene Willis - Edison International - Southern California Edison Company - 5
Answer
Document Name
Comment
“See EEI’s comments” on Modifications to TPL-007-3 – TPL-007-4 Transmission System Planned Performance for Geomagnetic Disturbance
Events.
Likes
0
Dislikes
0
Response
Thank you for your comment. The DRAFT TPL-007-4 CAP Extension Request Review Process document is being developed by NERC
Compliance Assurance, not by the Project 2019-01 Standard Drafting Team. Your comment on recommended changes to the extension
process will be forwarded to NERC Compliance Assurance staff. Note that the extension review process itself is not part of TPL-007-4, and
therefore, it is not part of the ballot.
Sandra Shaffer - Berkshire Hathaway - PacifiCorp - 6
Answer
Document Name
Comment
No comments.
Likes
0
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Dislikes
0
Response
Anton Vu - Los Angeles Department of Water and Power - 6
Answer
Document Name
Comment
What was the rationale behind removing the Supplemental Material? It provided some background information and sources that could be
useful for understanding the practicality of the requirement.
Likes
0
Dislikes
0
Response
Thank you for your comment. All supporting background information is available at the project page. Additional background material is
provided in the Technical Rationale and Implementation Guidance documents (see references to white papers).
Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - MRO, Group Name SPP Standards Review Group
Answer
Document Name
Comment
Comments:
1.
The language in Requirement 7.4 doesn’t properly align with the FERC Directive on who should be approving the extensions. The
FERC directive doesn’t clearly state that the ERO should be the entity approving the extension. We recommend the drafting team
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207
consider revising their proposed language to include “ERO, or its delegated designee.” This modification will allow regional entities
or other designees to better adjudicate CAP time extensions given their close proximity, System expertise, and existing compliance
program obligations.
2.
The proposed language in Requirement R11 Part 11.3 doesn’t align with the FERC directive in reference to the duration of the
Implementation of the CAP. The FERC directive doesn’t clarify a specific time frame pertaining to the Implementation of the
CAPs. Recommend the drafting team consider revising their proposed language for Requirement R11.3 Parts 11.3.1 and 11.3.2
to include an implementation timeframe of three (3) and six (6) years respectively.
3.
The SSRG recommends that the drafting team considers including more technical language in the Technical Rationale document,
explaining how/why the drafting team came to their conclusions to revising these particular requirements. The document doesn’t
provide technical reasoning the drafting team developed or revised this requirement. Chapters 7, 8, and 11 are general, and have no
technical information explaining the drafting team’s actions.
4.
The SSRG recommends the drafting team consider implementing all the redlines changes to the RSAW that have been identified in
the other documents to promote consistency throughout their documentation process.
Likes
0
Dislikes
0
Response
Thank you for your comment. FFERC Order No. 830 (P. 97 and P.102) and FERC Order No. 851 (P. 54) state that NERC should consider
extensions of time on a case-by-case basis. FERC Order 851 (P. 5 and P. 55) expands upon this by referring to submission "to NERC or a
Regional Entity, as appropriate".
The SDT believes consistent timelines is the best practice for implementing TPL-007-4, non-hardware mitigations shall be completed within
two years and hardware mitigations shall be completed within four years. In addition, the extension process will allow entities that
encounter situations beyond their control to request extensions of time.
Consideration of Comments
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208
These requirements were revised as a result of FERC Order No. 851 (P. 56), which directs NERC to modify R7.4 by developing a timely and
efficient process, consistent with the Commission’s guidance in Order No. 830, to consider time extension requests on a case-by-case basis.
Regarding the comment about including additional technical language, the SDT believes that the Technical Rationale document provides a
reasonable level of technical detail. Note that supporting technical documents are provided in the Reference section of the Technical
Rationale document. For additional technical explanation on the Supplemental GMD Event please see the Supplemental GMD Event
Description white paper.
The SDT is not responsible for the RSAW. The process accounts for incorporating the changes to the RSAW as draft standards are modified.
Anthony Jablonski - ReliabilityFirst – 10
Answer
Document Name
Comment
ReliabilityFirst has identified a change in Requirement R1 that was not captured in the redline. When Requirement R1 was copied over to
TPL-007-4, the SDT dropped the word “area” from the requirement. As is, the Requirement does not seem to make sence. Please note (in
bold text) the updated requirement below:
Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall identify the individual and joint responsibilities of the
Planning Coordinator and Transmission Planner(s) in the Planning Coordinator’s planning area for maintaining models, performing the study
or studies needed to complete benchmark and supplemental GMD Vulnerability Assessments, and implementing process(es) to obtain GMD
measurement data as specified in this standard.
Likes
0
Dislikes
0
Response
Thank you for your comment. The SDT would like to express our thanks for pointing out the typo in Requirement R1, it has been corrected.
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
209
Andrea Barclay - Georgia System Operations Corporation - 3,4
Answer
Document Name
Comment
The only difference between R.4 through R.7 and R.8 through R.11 is the threshold for the maximum effective GIC value (75 A for the
Benchmark GMD Event, and 85 A for the Supplemental GMD event). Based on this fact, the number of requirements in the standard could
be reduced, if R.4 through R.7 and R.8 through R.11 were combined.
Likes
0
Dislikes
0
Response
Thank you for your comment. The standard is drafted in the manner that the vulnerability assessment and CAP development for the
benchmark and supplemental events are defined in separate sequential requirements in order to keep the standard language clear and
avoid misinterpretation. Since TPL-007-3 is an active standard and responsible entities are currently performing the pertinent studies, the
SDT decided to preserve the numbering structure in TPL-007-3 to minimize the disruption existing processes and documentation.
Jodirah Green - ACES Power Marketing - 1,3,4,5,6 - MRO,WECC,Texas RE,SERC,RF, Group Name ACES Standard Collaborations
Answer
Document Name
Comment
Thank you for the opportunity to comment. ACES appreciates the efforts of drafting team members and NERC staff in continuing to
enhance the standards for the benefit of reliability of the BES.
Likes
Dislikes
0
0
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
210
Response
Thank you for your comment.
Scott McGough - Georgia System Operations Corporation - 3,4
Answer
Document Name
Comment
The only difference between R.4 through R.7 and R.8 through R.11 is the threshold for the maximum effective GIC value (75 A for the
Benchmark GMD Event, and 85 A for the Supplemental GMD event). Based on this fact, the number of requirements in the standard could
be reduced, if R.4 through R.7 and R.8 through R.11 were combined.
Likes
0
Dislikes
0
Response
Thank you for your comment. The standard is drafted in the manner that the vulnerability assessment and CAP development for the
benchmark and supplemental events are defined in separate sequential requirements in order to keep the standard language clear and
avoid misinterpretation. Since TPL-007-3 is an active standard and responsible entities are currently performing the pertinent studies, the
SDT decided to preserve the numbering structure in TPL-007-3 to minimize the disruption existing processes and documentation.
Keith Jonassen - Keith Jonassen On Behalf of: Michael Puscas, ISO New England, Inc., 2; - Keith Jonassen
Answer
Document Name
Comment
ISO-NE believes that the additional guidance provided in chapter 8 of the draft Transmission System Planned Performance for Geomagnetic
Disturbance Events Implementation guidance document for simulating the supplemental GMD event is very helpful. ISO recommends
reviewing the language in that chapter to ensure consistency with the purpose of the implementation guidance document as explained in
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
211
the first paragraph of its Introduction section (i.e. make clear that the information provided describes an example of how the standard’s
requirements could be met), and not infer the introduction of additional requirements which would not otherwise be contained in the TPL007 standard.
Likes
0
Dislikes
0
Response
Thank you for your comment. Chapter 8 of the Implementation Guidance document has been updated to reflect ISO-NE’s comment.
Deanna Carlson - Cowlitz County PUD - 5
Answer
Document Name
Comment
The addition of the ERO for approving any timeline extension may prove to be excessive and burdensome for NERC, and possibly the
responsible entity as well. The District recommends an additional statement where the ERO has 60 days to provide notice to the
responsible entity when a CAP submittal with an extension request will require ERO approval following full review. Otherwise, if NERC
acknowledges receipt with no further notice to the responsible entity, the CAP and extension request is automatically approved. This would
reduce the work load on NERC to regarding CAPs with extension requests that are minimal or otherwise considered low risk to the BES.
Additionally, there is no consideration of cost. It is possible that a CAP could be expensive and difficult to develop a four-year plan without
hindering other more important Transmission Planning objectives in compliance to TPL-001.
Likes
0
Dislikes
0
Response
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
212
Thank you for your comment. The SDT provided comments to CMEP staff and believes that the revised draft process prepared by CMEP
staff may address many of your concerns.
Aaron Cavanaugh - Bonneville Power Administration - 1,3,5,6 - WECC
Answer
Document Name
Comment
No comment
Likes
0
Dislikes
0
Response
Steven Dowell - Alcoa - Alcoa, Inc. - 7
Answer
Document Name
Comment
Alcoa would like to abstain. Alcoa would urge the SDT to examine cost/benefit analysis for implementation of GMDs at non-critical
facilities.
Likes
0
Dislikes
0
Response
Thank you for your comment. The SDT believes the commenter’s suggestion is outside the scope of this SDT.
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
213
Greg Davis - Georgia Transmission Corporation - 1
Answer
Document Name
Comment
The only difference between R.4 through R.7 and R.8 through R.11 is the threshold for the maximum effective GIC value (75 A for the
Benchmark GMD Event, and 85 A for the Supplemental GMD event). Based on this fact, the number of requirements in the standard could
be reduced, if R.4 through R.7 and R.8 through R.11 were combined.
Likes
0
Dislikes
0
Response
Thank you for your comment. The standard is drafted in the manner that the vulnerability assessment and CAP development for the
benchmark and supplemental events are defined in separate sequential requirements in order to keep the standard language clear and
avoid misinterpretation. Since TPL-007-3 is an active standard and responsible entities are currently performing the pertinent studies, the
SDT decided to preserve the numbering structure in TPL-007-3 to minimize the disruption existing processes and documentation.
Kenya Streeter - Edison International - Southern California Edison Company - 6
Answer
Document Name
Comment
See EEI's comments.
Likes
0
Dislikes
0
Response
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
214
Thank you for your comment. The SDT provided comments to CMEP staff and believes that the revised draft process prepared by CMEP
staff may address many of your concerns.
James Mearns - Pacific Gas and Electric Company - 1,3,5
Answer
Document Name
Comment
As inverter based sources of generation increase on the grid, the requirements of IEEE-Std-519 related to THD percentages (to the 40th
harmonic) may need to be revisited. Energy at higher order harmonic frequencies has been observed at bulk (>20 MW) solar sites, which
may increase potential for thermal saturation in banks that would otherwise not be susceptable to GIC. Although separate from the specific
guidance in this TPL, this may represent a sensitivity factor that could be weighted as part of the overall security assessment of the banks
being reviewed.
Likes
0
Dislikes
0
Response
Thank you for your comment. TPL-007 is a performance standard which asks entities to take into account the impact of harmonics.
Chantal Mazza - Hydro-Qu?bec TransEnergie - 1 - NPCC
Answer
Document Name
Comment
The Implementation Guidance document, as written, is not acceptable. Boundaries cannot be established with a CMEP Implementation
Guidance document. CMEP Implementation Guidance is a means to identify one approach to being compliant while not precluding the use
of other approaches. Auditors audit to requirements and don’t use CMEP Implementation Guidance to establish requirements which go
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
215
beyond the standard’s requirements. Problematic statements appearing in Chapter 8 of the document include, but may not be limited to,
the following:
•
“The local geoelectric field enhancement should not be smaller than 100 km..”- this threshold value of 100 km does not appear
in the standard requirement
•
“…at a minimum, a West-East orientation should be considered when applying the supplemental event”- the standard
requirement does not contain any wording of a minimum consideration
•
“Geoelectric field outside the local enhancement:
a. Amplitude: should not be smaller than 1.2 V/km…” This also does not appear in the standard.
•
“The schematic in Figure 1 illustrates the boundaries to apply the supplemental GMD event”. This statement creates boundaries
outside of requirements, which guidance cannot do.
The use of “shall” or “must” should not be used unless they are being used in the requriements in the standard. This is particularly true for
the requirement associated with sensitive/confidential information. It is not in the standard and was added in the IG as an additional
“requirement”.
Likes
0
Dislikes
0
Response
Thank you for your comment. The SDT updated the Implementation Guidance document to incorporate this feedback.
Louis Guidry - Louis Guidry On Behalf of: John Lindsey, Cleco Corporation, 6, 5, 1, 3; Robert Hirchak, Cleco Corporation, 6, 5, 1, 3; - Louis
Guidry
Answer
Document Name
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
216
Comment
Cleco does agree with the concept, the language, particularly with regard to the extent of the Corrective Action Plan (R11) and various
timetable requirements are overreaching and place undue burden on potentially affected entities.
Likes
0
Dislikes
0
Response
Thank you for your comment. Requirement R11 was added by the SDT to address the FERC directive in Order No. 851 (Paragraphs 4 and 39
of the Order) which requires CAPs for the vulnerabilities identified in the supplemental GMD analysis.
Ayman Samaan - Edison International - Southern California Edison Company - 1
Answer
Document Name
Comment
Please see EEI's comments
Likes
0
Dislikes
0
Response
Thank you for your comment. The SDT provided comments to CMEP staff and believes that the revised draft process prepared by CMEP
staff may address many of your concerns.
sean erickson - Western Area Power Administration - 1
Answer
Document Name
Comment
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
217
We don’t need to remind the Project 2019-01 SDT that this will be the fourth version of the TPL-007 Reliability Standard in three years. The
team has done a fine job of meeting the directives of FERC Order No. 851, but we encourage the SDT to push back harder on the corrective
action implementation timeframes for the supplemental GMD event. From a holistic view, this effort to address vulnerability to GMD
events appears to be getting too far ahead of good, robust science and engineering. The industry simply does not have mature hardware
solutions available to potentially mitigate GIC issues, anticipated from mathematical model simulation software packages that are updating
at least as frequently as the TPL-007 standard itself has changed, while constantly chasing the emerging GMD science. The reliability of the
BES is, and will be, best served by the improved awareness of GMD impacts embodied by the TPL-007, as well as operator responsiveness
required by EOP-010-1. The existing required identification of corrective actions is key; just give industry the time and flexibility to adopt
solutions that suit them best.
Likes
0
Dislikes
0
Response
Thank you for your comment.
Neil Swearingen - Salt River Project - 1,3,5,6 - WECC
Answer
Document Name
Comment
SRP thanks the standards drafting team for their efforts on this project.
Likes
0
Dislikes
0
Response
Thank you for your comment.
Kim Thomas - Duke Energy - 1,3,5,6 - SERC,RF, Group Name Duke Energy
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
218
Answer
Document Name
Comment
None.
Likes
0
Dislikes
0
Response
Jonathan Robbins - Seminole Electric Cooperative, Inc. - 1,3,4,5,6 - SERC
Answer
Document Name
Comment
The Standard Draft Team (SDT) has added language to submit requests for extensions of timeframes to the ERO, i.e., NERC, for
approval. Seminole reasons that individual entities should communicate such requests to the RRO, e.g., SERC, WECC, etc., and that the
individual RRO should approve/deny such requests instead of NERC. Seminole is requesting the language be revised to capture this.
Likes
0
Dislikes
0
Response
Thank you for your comment. The language in R7.4 and R11.4 has been modified to clarify intent.
Matthew Nutsch - Seattle City Light - 1,3,4,5,6 - WECC
Answer
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
219
Document Name
Comment
None
Likes
0
Dislikes
0
Response
Nick Batty - Keys Energy Services - NA - Not Applicable - SERC
Answer
Document Name
Comment
N/A
Likes
0
Dislikes
0
Response
Thomas Foltz - AEP - 5
Answer
Document Name
Comment
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
220
As previously stated, many of the obligations within TPL-007, both existing and proposed, precede industries’ full understanding of GMD
and its true, discernable impacts. This proves challenging when attempting to develop standards to adequately address the perceived risks.
We support, and are appreciative of, the efforts of the standards drafting team and their desire to address the directives issued in Order No.
851, however we believe the spirit of those directives can be met without pursuing a path that duplicates obligations already required for
the benchmark event. We believe a more prudent path for meeting the directive would be for the SDT to work with industry and determine
an agreeable reference peak geoelectric field amplitude (one not determined solely by non-spatially averaged data) for a single GMD
Vulnerability Assessment (benchmark) that potentially requires a Corrective Action Plan. This would serve to both achieve the spirit of the
directive, as well as avoid unnecessary duplication of efforts that provide no added benefit to the reliability of the BES. Due to the concerns
we have expressed above, AEP has chosen to vote negative on the proposed revisions.
Likes
0
Dislikes
0
Response
Thank you for your comment. The SDT believes that analyzing both benchmark and supplement events is the scientifically justified approach
to the study of GMD events that is not based solely on spatially averaged data. See Benchmark and Supplemental GMD Event White Papers.
FERC order 851 requires the SDT to develop a CAP for supplemental event:
“The Commission also directs NERC to develop and submit modifications to Reliability Standard TPL-007-2: (1) to require the development
and implementation of corrective action plans to mitigate assessed supplemental GMD event vulnerabilities;……”
The SDT has elaborated on the supplement event to the Implementation Guidance document.
Marty Hostler - Northern California Power Agency - 5
Answer
Document Name
Comment
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
221
None
Likes
0
Dislikes
0
Response
Consideration of Comments
Project 2019-01 Modifications to TPL-007-3 | November 2019
222
Standards Announcement
Project 2019-01 Modifications to TPL-007-3
Ballot Pools Forming through August 26, 2019
Formal Comment Period Open through September 9, 2019
Now Available
A 45-day formal comment period for TPL-007-4 – Transmission System Planned Performance for
Geomagnetic Disturbance Events is open through 8 p.m. Eastern, Monday, September 9, 2019.
Commenting
Use the Standards Balloting and Commenting System (SBS) to submit comments. If you experience issues
using the SBS, contact Linda Jenkins. An unofficial Word version of the comment form is posted on the
project page.
Ballot Pools
Ballot pools are being formed through 8 p.m. Eastern, Monday, August 26, 2019. Registered Ballot Body
members can join the ballot pools here.
•
If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential
error messages, or system lock-out, contact NERC IT support directly at https://support.nerc.net/
(Monday – Friday, 8 a.m. - 5 p.m. Eastern).
•
Passwords expire every 6 months and must be reset.
•
The SBS is not supported for use on mobile devices.
•
Please be mindful of ballot and comment period closing dates. We ask to allow at least 48 hours for
NERC support staff to assist with inquiries. Therefore, it is recommended that users try logging into
their SBS accounts prior to the last day of a comment/ballot period.
Next Steps
An Initial ballot for the standard, along with non-binding polls for the associated Violation Risk Factors
and Violation Severity Levels, will be conducted August 30 – September 9, 2019.
For more information on the Standards Development Process, refer to the Standard Processes Manual.
Subscribe to this project's observer mailing list by selecting "NERC Email Distribution Lists" from the
"Applications" drop-down menu and specify “Project 2019-01 Modifications to TPL-007-3 Observer List” in
the Description Box. For more information or assistance, contact Senior Standards Developer, Alison
Oswald (via email) or at 404-446-9668.
RELIABILITY | RESILIENCE | SECURITY
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement | Project 2019-01 Modifications to TPL-007-3
TPL-007-4 | July-August, 2019
2
NERC Balloting Tool (/)
Dashboard (/)
Ballots
Users
Comment Forms
Login (/Users/Login) / Register (/Users/Register)
BALLOT RESULTS
Comment: View Comment Results (/CommentResults/Index/176)
Ballot Name: 2019-01 Modifications to TPL-007-3 TPL-007-4 IN 1 ST
Voting Start Date: 8/30/2019 12:01:00 AM
Voting End Date: 9/9/2019 8:00:00 PM
Ballot Type: ST
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 267
Total Ballot Pool: 292
Quorum: 91.44
Quorum Established Date: 9/9/2019 12:57:54 PM
Weighted Segment Value: 70.84
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Negative
Fraction w/
Comment
Negative
Votes w/o
Comment
Abstain
No
Vote
Segment:
1
82
1
43
0.694
19
0.306
0
10
10
Segment:
2
6
0.4
3
0.3
1
0.1
0
1
1
Segment:
3
67
1
35
0.673
17
0.327
0
11
4
Segment:
4
13
1
8
0.727
3
0.273
0
1
1
Segment:
5
65
1
32
0.64
18
0.36
0
8
7
Segment:
6
49
1
24
0.558
19
0.442
0
4
2
Segment:
7
0
0
0
0
0
0
0
0
0
Segment:
8
2
0.1
1
0.1
0
0
0
1
0
Segment:
9
1
0.1
1
0.1
0
0
0
0
0
Segment:
10
7
0.6
6
0.6
0
0
0
1
0
77
1.808
0
37
25
Segment
Totals:
292
6.2
153
4.392
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
BALLOT POOL MEMBERS
Show All
Segment
entries
Organization
Search:
Voter
Designated
Proxy
Search
Ballot
NERC
Memo
1
AEP - AEP Service
Corporation
Dennis Sauriol
Negative
Comments
Submitted
1
Ameren - Ameren Services
Eric Scott
Negative
Comments
Submitted
1
APS - Arizona Public Service
Co.
Michelle Amarantos
Abstain
N/A
1
Arizona Electric Power
Cooperative, Inc.
John Shaver
Affirmative
N/A
1
Austin Energy
Thomas Standifur
Affirmative
N/A
1
Balancing Authority of
Northern California
Kevin Smith
Affirmative
N/A
1
BC Hydro and Power Authority
Adrian Andreoiu
Abstain
N/A
1
Berkshire Hathaway Energy MidAmerican Energy Co.
Terry Harbour
Affirmative
N/A
1
Black Hills Corporation
Wes Wingen
Affirmative
N/A
1
Bonneville Power
Administration
Kammy RogersHolliday
Negative
Comments
Submitted
1
Central Electric Power
Cooperative (Missouri)
Michael Bax
None
N/A
1
City Utilities of Springfield,
Missouri
Michael Buyce
Affirmative
N/A
1
Cleco Corporation
John Lindsey
Negative
Comments
Submitted
1
CMS Energy - Consumers
Energy Company
Donald Lynd
Abstain
N/A
1
Colorado Springs Utilities
Mike Braunstein
Affirmative
N/A
Negative
Comments
Submitted
1
Con Ed - Consolidated Edison
Dermot Smyth
Co. ofMachine
New York
© 2020 - NERC Ver 4.3.0.0
Name: ERODVSBSWB01
Joe Tarantino
Louis Guidry
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Dairyland Power Cooperative
Renee Leidel
Abstain
N/A
1
Dominion - Dominion Virginia
Power
Candace Marshall
Affirmative
N/A
1
Duke Energy
Laura Lee
Affirmative
N/A
1
Edison International Southern California Edison
Company
Ayman Samaan
Negative
Comments
Submitted
1
Entergy - Entergy Services,
Inc.
Oliver Burke
Affirmative
N/A
1
Eversource Energy
Quintin Lee
Affirmative
N/A
1
Exelon
Daniel Gacek
Negative
Comments
Submitted
1
FirstEnergy - FirstEnergy
Corporation
Julie Severino
Affirmative
N/A
1
Georgia Transmission
Corporation
Greg Davis
Affirmative
N/A
1
Glencoe Light and Power
Commission
Terry Volkmann
Abstain
N/A
1
Great Plains Energy - Kansas
City Power and Light Co.
James McBee
Negative
Comments
Submitted
1
Great River Energy
Gordon Pietsch
Affirmative
N/A
1
Hydro One Networks, Inc.
Payam
Farahbakhsh
Affirmative
N/A
1
Hydro-Qu?bec TransEnergie
Nicolas Turcotte
Affirmative
N/A
1
IDACORP - Idaho Power
Company
Laura Nelson
None
N/A
1
Imperial Irrigation District
Jesus Sammy
Alcaraz
Abstain
N/A
1
JEA
Joe McClung
None
N/A
1
KAMO Electric Cooperative
Micah Breedlove
Affirmative
N/A
1
Lakeland Electric
Larry Watt
Negative
Third-Party
Comments
1
Lincoln Electric System
Danny Pudenz
Affirmative
N/A
1
Long Island Power Authority
Robert Ganley
Affirmative
N/A
None
N/A
1
Los Angeles Department of
faranak sarbaz
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Water and Power
Stephen Stafford
Douglas Webb
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Lower Colorado River
Authority
Trey Melcher
None
N/A
1
M and A Electric Power
Cooperative
William Price
Affirmative
N/A
1
Manitoba Hydro
Bruce Reimer
Negative
Comments
Submitted
1
MEAG Power
David Weekley
Abstain
N/A
1
Minnkota Power Cooperative
Inc.
Theresa Allard
Abstain
N/A
1
Muscatine Power and Water
Andy Kurriger
Affirmative
N/A
1
N.W. Electric Power
Cooperative, Inc.
Mark Ramsey
Affirmative
N/A
1
National Grid USA
Michael Jones
Affirmative
N/A
1
NB Power Corporation
Nurul Abser
Abstain
N/A
1
Nebraska Public Power
District
Jamison Cawley
Negative
Third-Party
Comments
1
New York Power Authority
Salvatore Spagnolo
Affirmative
N/A
1
NextEra Energy - Florida
Power and Light Co.
Mike ONeil
Affirmative
N/A
1
NiSource - Northern Indiana
Public Service Co.
Steve Toosevich
None
N/A
1
Northeast Missouri Electric
Power Cooperative
Kevin White
Affirmative
N/A
1
OGE Energy - Oklahoma Gas
and Electric Co.
Terri Pyle
Affirmative
N/A
1
Ohio Valley Electric
Corporation
Scott Cunningham
Negative
Third-Party
Comments
1
Omaha Public Power District
Doug Peterchuck
Affirmative
N/A
1
Oncor Electric Delivery
Lee Maurer
None
N/A
1
Orlando Utilities Commission
Aaron Staley
Affirmative
N/A
1
OTP - Otter Tail Power
Company
Charles Wicklund
Affirmative
N/A
1
Platte River Power Authority
Matt Thompson
Affirmative
N/A
None
N/A
1
PNM Resources - Public
Laurie Williams
Service Company of New
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Mexico
Scott Miller
Eric Shaw
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Portland General Electric Co.
Nathaniel Clague
Affirmative
N/A
1
PPL Electric Utilities
Corporation
Brenda Truhe
Affirmative
N/A
1
PSEG - Public Service Electric
and Gas Co.
Joseph Smith
Affirmative
N/A
1
Public Utility District No. 1 of
Chelan County
Jeff Kimbell
Negative
Comments
Submitted
1
Public Utility District No. 1 of
Snohomish County
Long Duong
Negative
Third-Party
Comments
1
Sacramento Municipal Utility
District
Arthur Starkovich
Affirmative
N/A
1
Salt River Project
Steven Cobb
Affirmative
N/A
1
Santee Cooper
Chris Wagner
Abstain
N/A
1
SaskPower
Wayne Guttormson
Affirmative
N/A
1
Seattle City Light
Pawel Krupa
None
N/A
1
Seminole Electric
Cooperative, Inc.
Bret Galbraith
Negative
Comments
Submitted
1
Sempra - San Diego Gas and
Electric
Mo Derbas
Affirmative
N/A
1
Sho-Me Power Electric
Cooperative
Peter Dawson
Affirmative
N/A
1
Southern Company - Southern
Company Services, Inc.
Adrianne Collins
Affirmative
N/A
1
Sunflower Electric Power
Corporation
Paul Mehlhaff
Affirmative
N/A
1
Tacoma Public Utilities
(Tacoma, WA)
John Merrell
Affirmative
N/A
1
Tallahassee Electric (City of
Tallahassee, FL)
Scott Langston
None
N/A
1
Tennessee Valley Authority
Gabe Kurtz
Negative
Third-Party
Comments
1
U.S. Bureau of Reclamation
Richard Jackson
Negative
Comments
Submitted
1
Westar Energy
Allen Klassen
Negative
Comments
Submitted
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Joe Tarantino
Douglas Webb
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Western Area Power
Administration
sean erickson
Negative
Comments
Submitted
1
Xcel Energy, Inc.
Dean Schiro
Affirmative
N/A
2
California ISO
Jamie Johnson
Abstain
N/A
2
Electric Reliability Council of
Texas, Inc.
Brandon Gleason
Negative
Comments
Submitted
2
Independent Electricity
System Operator
Leonard Kula
Affirmative
N/A
2
ISO New England, Inc.
Michael Puscas
Affirmative
N/A
2
Midcontinent ISO, Inc.
Bobbi Welch
None
N/A
2
PJM Interconnection, L.L.C.
Mark Holman
Affirmative
N/A
3
AEP
Leanna Lamatrice
Negative
Comments
Submitted
3
AES - Indianapolis Power and
Light Co.
Bette White
Affirmative
N/A
3
Ameren - Ameren Services
David Jendras
Negative
Comments
Submitted
3
APS - Arizona Public Service
Co.
Vivian Moser
Abstain
N/A
3
Associated Electric
Cooperative, Inc.
Todd Bennett
Abstain
N/A
3
Austin Energy
W. Dwayne
Preston
Abstain
N/A
3
Avista - Avista Corporation
Scott Kinney
None
N/A
3
BC Hydro and Power Authority
Hootan Jarollahi
Abstain
N/A
3
Berkshire Hathaway Energy MidAmerican Energy Co.
Darnez Gresham
Affirmative
N/A
3
Black Hills Corporation
Eric Egge
Affirmative
N/A
3
Bonneville Power
Administration
Rebecca Berdahl
Negative
Comments
Submitted
3
Central Electric Power
Cooperative (Missouri)
Adam Weber
Affirmative
N/A
3
City Utilities of Springfield,
Missouri
Scott Williams
Affirmative
N/A
Abstain
N/A
3
CMS Energy - Consumers
Karl Blaszkowski
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Energy Company
Keith Jonassen
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Colorado Springs Utilities
Hillary Dobson
Affirmative
N/A
3
Cowlitz County PUD
Russell Noble
Negative
Comments
Submitted
3
Dominion - Dominion
Resources, Inc.
Connie Lowe
Affirmative
N/A
3
Duke Energy
Lee Schuster
Affirmative
N/A
3
Edison International Southern California Edison
Company
Romel Aquino
Negative
Comments
Submitted
3
Eversource Energy
Sharon Flannery
Affirmative
N/A
3
Exelon
Kinte Whitehead
Negative
Comments
Submitted
3
FirstEnergy - FirstEnergy
Corporation
Aaron Ghodooshim
Affirmative
N/A
3
Florida Municipal Power
Agency
Joe McKinney
Brandon
McCormick
Negative
Comments
Submitted
3
Great Plains Energy - Kansas
City Power and Light Co.
John Carlson
Douglas Webb
Negative
Comments
Submitted
3
Great River Energy
Brian Glover
Affirmative
N/A
3
Hydro One Networks, Inc.
Paul Malozewski
Affirmative
N/A
3
Imperial Irrigation District
Denise Sanchez
Abstain
N/A
3
JEA
Garry Baker
None
N/A
3
KAMO Electric Cooperative
Tony Gott
Affirmative
N/A
3
Lakeland Electric
Patricia Boody
Abstain
N/A
3
Lincoln Electric System
Jason Fortik
Affirmative
N/A
3
Los Angeles Department of
Water and Power
Tony Skourtas
Affirmative
N/A
3
M and A Electric Power
Cooperative
Stephen Pogue
Affirmative
N/A
3
Manitoba Hydro
Karim Abdel-Hadi
Negative
Comments
Submitted
3
MEAG Power
Roger Brand
Abstain
N/A
3
Muscatine Power and Water
Seth Shoemaker
Affirmative
N/A
3
National Grid USA
Brian Shanahan
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Affirmative
N/A
Scott Miller
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Nebraska Public Power
District
Tony Eddleman
Negative
Third-Party
Comments
3
New York Power Authority
David Rivera
Affirmative
N/A
3
NiSource - Northern Indiana
Public Service Co.
Dmitriy Bazylyuk
Negative
Comments
Submitted
3
Northeast Missouri Electric
Power Cooperative
Skyler Wiegmann
Affirmative
N/A
3
NW Electric Power
Cooperative, Inc.
John Stickley
Affirmative
N/A
3
OGE Energy - Oklahoma Gas
and Electric Co.
Donald Hargrove
Affirmative
N/A
3
Omaha Public Power District
Aaron Smith
Affirmative
N/A
3
OTP - Otter Tail Power
Company
Wendi Olson
Affirmative
N/A
3
Owensboro Municipal Utilities
Thomas Lyons
Abstain
N/A
3
Platte River Power Authority
Jeff Landis
Affirmative
N/A
3
PNM Resources - Public
Service Company of New
Mexico
Trevor Tidwell
None
N/A
3
Portland General Electric Co.
Dan Zollner
Affirmative
N/A
3
PPL - Louisville Gas and
Electric Co.
Joseph Bencomo
Affirmative
N/A
3
PSEG - Public Service Electric
and Gas Co.
James Meyer
Affirmative
N/A
3
Public Utility District No. 1 of
Chelan County
Joyce Gundry
Negative
Comments
Submitted
3
Sacramento Municipal Utility
District
Nicole Looney
Affirmative
N/A
3
Salt River Project
Zack Heim
Affirmative
N/A
3
Santee Cooper
James Poston
Abstain
N/A
3
Seminole Electric
Cooperative, Inc.
Kristine Ward
Negative
Comments
Submitted
3
Sempra - San Diego Gas and
Electric
Bridget Silvia
Affirmative
N/A
Affirmative
N/A
3
Sho-Me Power Electric
Jeff Neas
Cooperative
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Joe Tarantino
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Snohomish County PUD No. 1
Holly Chaney
Negative
Third-Party
Comments
3
Southern Company - Alabama
Power Company
Joel Dembowski
Affirmative
N/A
3
Tacoma Public Utilities
(Tacoma, WA)
Marc Donaldson
Affirmative
N/A
3
TECO - Tampa Electric Co.
Ronald Donahey
None
N/A
3
Tennessee Valley Authority
Ian Grant
Negative
Third-Party
Comments
3
Tri-State G and T Association,
Inc.
Janelle Marriott Gill
Abstain
N/A
3
WEC Energy Group, Inc.
Thomas Breene
Negative
Third-Party
Comments
3
Westar Energy
Bryan Taggart
Negative
Comments
Submitted
3
Xcel Energy, Inc.
Michael Ibold
Affirmative
N/A
4
Austin Energy
Jun Hua
None
N/A
4
City Utilities of Springfield,
Missouri
John Allen
Affirmative
N/A
4
CMS Energy - Consumers
Energy Company
Nicholas Tenney
Abstain
N/A
4
FirstEnergy - FirstEnergy
Corporation
Aubrey Short
Affirmative
N/A
4
Florida Municipal Power
Agency
Carol Chinn
Negative
Comments
Submitted
4
MGE Energy - Madison Gas
and Electric Co.
Joseph DePoorter
Affirmative
N/A
4
Public Utility District No. 1 of
Snohomish County
John Martinsen
Negative
Third-Party
Comments
4
Public Utility District No. 2 of
Grant County, Washington
Karla Weaver
Affirmative
N/A
4
Sacramento Municipal Utility
District
Beth Tincher
Affirmative
N/A
4
Seattle City Light
Hao Li
Affirmative
N/A
4
Tacoma Public Utilities
(Tacoma, WA)
Hien Ho
Affirmative
N/A
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Douglas Webb
Brandon
McCormick
Joe Tarantino
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
4
Utility Services, Inc.
Brian EvansMongeon
Affirmative
N/A
4
WEC Energy Group, Inc.
Matthew Beilfuss
Negative
Third-Party
Comments
5
AEP
Thomas Foltz
Negative
Comments
Submitted
5
Ameren - Ameren Missouri
Sam Dwyer
None
N/A
5
APS - Arizona Public Service
Co.
Kelsi Rigby
Abstain
N/A
5
Austin Energy
Shirley Mathew
Affirmative
N/A
5
Avista - Avista Corporation
Glen Farmer
Affirmative
N/A
5
Berkshire Hathaway - NV
Energy
Kevin Salsbury
Affirmative
N/A
5
Black Hills Corporation
George Tatar
Affirmative
N/A
5
Boise-Kuna Irrigation District Lucky Peak Power Plant
Project
Mike Kukla
Affirmative
N/A
5
Bonneville Power
Administration
Scott Winner
Negative
Comments
Submitted
5
Brazos Electric Power
Cooperative, Inc.
Shari Heino
Affirmative
N/A
5
Choctaw Generation Limited
Partnership, LLLP
Rob Watson
None
N/A
5
City of Independence, Power
and Light Department
Jim Nail
Affirmative
N/A
5
CMS Energy - Consumers
Energy Company
David Greyerbiehl
Abstain
N/A
5
Colorado Springs Utilities
Jeff Icke
Affirmative
N/A
5
Con Ed - Consolidated Edison
Co. of New York
William Winters
Negative
Comments
Submitted
5
Cowlitz County PUD
Deanna Carlson
Negative
Comments
Submitted
5
Dairyland Power Cooperative
Tommy Drea
Abstain
N/A
5
Duke Energy
Dale Goodwine
Affirmative
N/A
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Daniel Valle
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Edison International Southern California Edison
Company
Selene Willis
Negative
Comments
Submitted
5
Entergy
Jamie Prater
Negative
Comments
Submitted
5
Exelon
Cynthia Lee
Negative
Comments
Submitted
5
FirstEnergy - FirstEnergy
Solutions
Robert Loy
Affirmative
N/A
5
Florida Municipal Power
Agency
Chris Gowder
Brandon
McCormick
Negative
Comments
Submitted
5
Great Plains Energy - Kansas
City Power and Light Co.
Marcus Moor
Douglas Webb
Negative
Comments
Submitted
5
Great River Energy
Preston Walsh
Affirmative
N/A
5
Herb Schrayshuen
Herb Schrayshuen
Affirmative
N/A
5
Imperial Irrigation District
Tino Zaragoza
Abstain
N/A
5
JEA
John Babik
None
N/A
5
Lakeland Electric
Jim Howard
Negative
Third-Party
Comments
5
Lincoln Electric System
Kayleigh Wilkerson
Affirmative
N/A
5
Los Angeles Department of
Water and Power
Glenn Barry
None
N/A
5
Lower Colorado River
Authority
Teresa Cantwell
None
N/A
5
Manitoba Hydro
Yuguang Xiao
Negative
Comments
Submitted
5
Massachusetts Municipal
Wholesale Electric Company
David Gordon
Abstain
N/A
5
Muscatine Power and Water
Neal Nelson
Affirmative
N/A
5
NaturEner USA, LLC
Eric Smith
None
N/A
5
NB Power Corporation
Laura McLeod
Abstain
N/A
5
Nebraska Public Power
District
Don Schmit
Negative
Third-Party
Comments
5
New York Power Authority
Shivaz Chopra
Affirmative
N/A
Negative
Comments
Submitted
5
NiSource - Northern Indiana
Kathryn Tackett
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Public Service Co.
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Northern California Power
Agency
Marty Hostler
Affirmative
N/A
5
NRG - NRG Energy, Inc.
Patricia Lynch
None
N/A
5
OGE Energy - Oklahoma Gas
and Electric Co.
Patrick Wells
Affirmative
N/A
5
Oglethorpe Power Corporation
Donna Johnson
Affirmative
N/A
5
Omaha Public Power District
Mahmood Safi
Affirmative
N/A
5
Ontario Power Generation Inc.
Constantin
Chitescu
Affirmative
N/A
5
OTP - Otter Tail Power
Company
Brett Jacobs
Affirmative
N/A
5
Platte River Power Authority
Tyson Archie
Affirmative
N/A
5
Portland General Electric Co.
Ryan Olson
Affirmative
N/A
5
PPL - Louisville Gas and
Electric Co.
JULIE
HOSTRANDER
Affirmative
N/A
5
PSEG - PSEG Fossil LLC
Tim Kucey
Affirmative
N/A
5
Public Utility District No. 1 of
Chelan County
Meaghan Connell
Negative
Comments
Submitted
5
Public Utility District No. 1 of
Snohomish County
Sam Nietfeld
Negative
Third-Party
Comments
5
Public Utility District No. 2 of
Grant County, Washington
Alex Ybarra
Affirmative
N/A
5
Sacramento Municipal Utility
District
Susan Oto
Affirmative
N/A
5
Salt River Project
Kevin Nielsen
Affirmative
N/A
5
Santee Cooper
Tommy Curtis
Abstain
N/A
5
Seattle City Light
Faz Kasraie
Affirmative
N/A
5
Sempra - San Diego Gas and
Electric
Jennifer Wright
Affirmative
N/A
5
SunPower
Bradley Collard
Abstain
N/A
5
Tacoma Public Utilities
(Tacoma, WA)
Ozan Ferrin
Affirmative
N/A
5
Tennessee Valley Authority
M Lee Thomas
Negative
Third-Party
Comments
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Joe Tarantino
Segment
Organization
Voter
5
WEC Energy Group, Inc.
Linda Horn
5
Westar Energy
Derek Brown
5
Xcel Energy, Inc.
6
Designated
Proxy
Ballot
NERC
Memo
Negative
Third-Party
Comments
Negative
Comments
Submitted
Gerry Huitt
Affirmative
N/A
AEP - AEP Marketing
Yee Chou
Negative
Comments
Submitted
6
Ameren - Ameren Services
Robert Quinlivan
None
N/A
6
APS - Arizona Public Service
Co.
Chinedu
Ochonogor
Abstain
N/A
6
Associated Electric
Cooperative, Inc.
Brian Ackermann
Affirmative
N/A
6
Austin Energy
Andrew Gallo
Affirmative
N/A
6
Berkshire Hathaway PacifiCorp
Sandra Shaffer
Abstain
N/A
6
Black Hills Corporation
Eric Scherr
Affirmative
N/A
6
Bonneville Power
Administration
Andrew Meyers
Negative
Comments
Submitted
6
Cleco Corporation
Robert Hirchak
Negative
Comments
Submitted
6
Con Ed - Consolidated Edison
Co. of New York
Christopher
Overberg
Negative
Comments
Submitted
6
Dominion - Dominion
Resources, Inc.
Sean Bodkin
Affirmative
N/A
6
Duke Energy
Greg Cecil
Affirmative
N/A
6
Edison International Southern California Edison
Company
Kenya Streeter
Negative
Comments
Submitted
6
Entergy
Julie Hall
Negative
Comments
Submitted
6
Exelon
Becky Webb
Negative
Comments
Submitted
6
FirstEnergy - FirstEnergy
Solutions
Ann Carey
Affirmative
N/A
6
Florida Municipal Power
Agency
Richard
Montgomery
Negative
Comments
Submitted
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Douglas Webb
Louis Guidry
Brandon
McCormick
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
Great Plains Energy - Kansas
City Power and Light Co.
Jennifer
Flandermeyer
Douglas Webb
Negative
Comments
Submitted
6
Great River Energy
Donna Stephenson
Michael Brytowski
Affirmative
N/A
6
Imperial Irrigation District
Diana Torres
Abstain
N/A
6
Lakeland Electric
Paul Shipps
Negative
Third-Party
Comments
6
Lincoln Electric System
Eric Ruskamp
Affirmative
N/A
6
Los Angeles Department of
Water and Power
Anton Vu
Affirmative
N/A
6
Manitoba Hydro
Blair Mukanik
Negative
Comments
Submitted
6
Muscatine Power and Water
Ryan Streck
Affirmative
N/A
6
New York Power Authority
Thomas Savin
Affirmative
N/A
6
NextEra Energy - Florida
Power and Light Co.
Silvia Mitchell
Affirmative
N/A
6
NiSource - Northern Indiana
Public Service Co.
Joe O'Brien
Negative
Comments
Submitted
6
Northern California Power
Agency
Dennis Sismaet
Affirmative
N/A
6
OGE Energy - Oklahoma Gas
and Electric Co.
Sing Tay
Affirmative
N/A
6
Omaha Public Power District
Joel Robles
Affirmative
N/A
6
Platte River Power Authority
Sabrina Martz
Affirmative
N/A
6
Portland General Electric Co.
Daniel Mason
Affirmative
N/A
6
PPL - Louisville Gas and
Electric Co.
Linn Oelker
Affirmative
N/A
6
PSEG - PSEG Energy
Resources and Trade LLC
Luiggi Beretta
Affirmative
N/A
6
Public Utility District No. 1 of
Chelan County
Davis Jelusich
Negative
Comments
Submitted
6
Public Utility District No. 2 of
Grant County, Washington
LeRoy Patterson
None
N/A
6
Sacramento Municipal Utility
District
Jamie Cutlip
Affirmative
N/A
Affirmative
N/A
6
Salt River Project
Bobby Olsen
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Joe Tarantino
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
Santee Cooper
Michael Brown
Abstain
N/A
6
Seattle City Light
Charles Freeman
Affirmative
N/A
6
Seminole Electric
Cooperative, Inc.
Trudy Novak
Negative
Comments
Submitted
6
Snohomish County PUD No. 1
John Liang
Negative
Third-Party
Comments
6
Southern Company - Southern
Company Generation
Ron Carlsen
Affirmative
N/A
6
Tennessee Valley Authority
Marjorie Parsons
Negative
Third-Party
Comments
6
WEC Energy Group, Inc.
David Hathaway
Negative
Third-Party
Comments
6
Westar Energy
Grant Wilkerson
Negative
Comments
Submitted
6
Western Area Power
Administration
Rosemary Jones
Negative
Third-Party
Comments
6
Xcel Energy, Inc.
Carrie Dixon
Affirmative
N/A
8
David Kiguel
David Kiguel
Affirmative
N/A
8
Florida Reliability Coordinating
Council – Member Services
Division
Vince Ordax
Abstain
N/A
9
Commonwealth of
Massachusetts Department of
Public Utilities
Donald Nelson
Affirmative
N/A
10
Midwest Reliability
Organization
Russel Mountjoy
Affirmative
N/A
10
New York State Reliability
Council
ALAN ADAMSON
Affirmative
N/A
10
Northeast Power Coordinating
Council
Guy V. Zito
Affirmative
N/A
10
ReliabilityFirst
Anthony Jablonski
Affirmative
N/A
10
SERC Reliability Corporation
Dave Krueger
Affirmative
N/A
10
Texas Reliability Entity, Inc.
Rachel Coyne
Abstain
N/A
10
Western Electricity
Coordinating Council
Steven Rueckert
Affirmative
N/A
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Douglas Webb
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BALLOT RESULTS
Ballot Name: 2019-01 Modifications to TPL-007-3 TPL-007-4 Non-binding Poll IN 1 NB
Voting Start Date: 8/30/2019 12:01:00 AM
Voting End Date: 9/9/2019 8:00:00 PM
Ballot Type: NB
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 246
Total Ballot Pool: 277
Quorum: 88.81
Quorum Established Date: 9/9/2019 1:14:18 PM
Weighted Segment Value: 71.04
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes
Negative
Fraction
Abstain
No
Vote
Segment:
1
74
1
36
0.75
12
0.25
17
9
Segment:
2
5
0.4
4
0.4
0
0
0
1
Segment:
3
66
1
31
0.738
11
0.262
18
6
Segment:
4
12
0.9
6
0.6
3
0.3
2
1
Segment:
5
62
1
28
0.7
12
0.3
12
10
Segment:
6
48
1
18
0.545
15
0.455
11
4
Segment:
7
0
0
0
0
0
0
0
0
Segment:
8
2
0.1
1
0.1
0
0
1
0
Segment:
9
1
0.1
1
0.1
0
0
0
0
Segment:
10
7
0.5
5
0.5
0
0
2
0
Totals:
277
6
130
4.434
53
1.566
63
31
Segment
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
BALLOT POOL MEMBERS
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entries
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Designated
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Ballot
NERC
Memo
1
AEP - AEP Service
Corporation
Dennis Sauriol
Negative
Comments
Submitted
1
Ameren - Ameren Services
Eric Scott
Negative
Comments
Submitted
1
APS - Arizona Public Service
Co.
Michelle Amarantos
Abstain
N/A
1
Arizona Electric Power
Cooperative, Inc.
John Shaver
Affirmative
N/A
1
Austin Energy
Thomas Standifur
Affirmative
N/A
1
Balancing Authority of
Northern California
Kevin Smith
Affirmative
N/A
1
BC Hydro and Power Authority
Adrian Andreoiu
Abstain
N/A
1
Berkshire Hathaway Energy MidAmerican Energy Co.
Terry Harbour
Affirmative
N/A
1
Bonneville Power
Administration
Kammy RogersHolliday
Affirmative
N/A
1
Central Electric Power
Cooperative (Missouri)
Michael Bax
None
N/A
1
City Utilities of Springfield,
Missouri
Michael Buyce
Affirmative
N/A
1
Cleco Corporation
John Lindsey
Negative
Comments
Submitted
1
CMS Energy - Consumers
Energy Company
Donald Lynd
Abstain
N/A
1
Colorado Springs Utilities
Mike Braunstein
Affirmative
N/A
1
Con Ed - Consolidated Edison
Co. of New York
Dermot Smyth
Negative
Comments
Submitted
1
Dairyland Power Cooperative
Renee Leidel
Abstain
N/A
1
Dominion - Dominion Virginia
Power
Candace Marshall
Affirmative
N/A
Affirmative
N/A
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Joe Tarantino
Louis Guidry
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Edison International Southern California Edison
Company
Ayman Samaan
Negative
Comments
Submitted
1
Entergy - Entergy Services,
Inc.
Oliver Burke
Affirmative
N/A
1
Eversource Energy
Quintin Lee
Abstain
N/A
1
Exelon
Daniel Gacek
None
N/A
1
FirstEnergy - FirstEnergy
Corporation
Julie Severino
Affirmative
N/A
1
Georgia Transmission
Corporation
Greg Davis
Affirmative
N/A
1
Glencoe Light and Power
Commission
Terry Volkmann
Abstain
N/A
1
Great Plains Energy - Kansas
City Power and Light Co.
James McBee
Negative
Comments
Submitted
1
Great River Energy
Gordon Pietsch
Affirmative
N/A
1
Hydro One Networks, Inc.
Payam
Farahbakhsh
Affirmative
N/A
1
Hydro-Qu?bec TransEnergie
Nicolas Turcotte
Affirmative
N/A
1
IDACORP - Idaho Power
Company
Laura Nelson
None
N/A
1
Imperial Irrigation District
Jesus Sammy
Alcaraz
Abstain
N/A
1
KAMO Electric Cooperative
Micah Breedlove
Affirmative
N/A
1
Lakeland Electric
Larry Watt
Negative
Comments
Submitted
1
Lincoln Electric System
Danny Pudenz
Abstain
N/A
1
Long Island Power Authority
Robert Ganley
Abstain
N/A
1
Los Angeles Department of
Water and Power
faranak sarbaz
None
N/A
1
Lower Colorado River
Authority
Trey Melcher
None
N/A
1
M and A Electric Power
Cooperative
William Price
Affirmative
N/A
1
MEAG Power
David Weekley
Abstain
N/A
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Stephen Stafford
Douglas Webb
Scott Miller
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Minnkota Power Cooperative
Inc.
Theresa Allard
Abstain
N/A
1
Muscatine Power and Water
Andy Kurriger
Affirmative
N/A
1
N.W. Electric Power
Cooperative, Inc.
Mark Ramsey
Affirmative
N/A
1
National Grid USA
Michael Jones
Affirmative
N/A
1
NB Power Corporation
Nurul Abser
Abstain
N/A
1
Nebraska Public Power
District
Jamison Cawley
Abstain
N/A
1
New York Power Authority
Salvatore Spagnolo
Affirmative
N/A
1
NextEra Energy - Florida
Power and Light Co.
Mike ONeil
Affirmative
N/A
1
NiSource - Northern Indiana
Public Service Co.
Steve Toosevich
None
N/A
1
Northeast Missouri Electric
Power Cooperative
Kevin White
Affirmative
N/A
1
OGE Energy - Oklahoma Gas
and Electric Co.
Terri Pyle
Affirmative
N/A
1
Ohio Valley Electric
Corporation
Scott Cunningham
Negative
Comments
Submitted
1
Omaha Public Power District
Doug Peterchuck
Affirmative
N/A
1
Orlando Utilities Commission
Aaron Staley
Affirmative
N/A
1
PNM Resources - Public
Service Company of New
Mexico
Laurie Williams
None
N/A
1
Portland General Electric Co.
Nathaniel Clague
Affirmative
N/A
1
PSEG - Public Service Electric
and Gas Co.
Joseph Smith
Abstain
N/A
1
Public Utility District No. 1 of
Chelan County
Jeff Kimbell
Negative
Comments
Submitted
1
Public Utility District No. 1 of
Snohomish County
Long Duong
Negative
Comments
Submitted
1
Sacramento Municipal Utility
District
Arthur Starkovich
Affirmative
N/A
1
Salt River Project
Steven Cobb
Affirmative
N/A
Abstain
N/A
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
1
Santee Cooper
Chris Wagner
Joe Tarantino
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
SaskPower
Wayne Guttormson
Affirmative
N/A
1
Seattle City Light
Pawel Krupa
None
N/A
1
Seminole Electric Cooperative,
Inc.
Bret Galbraith
Abstain
N/A
1
Sempra - San Diego Gas and
Electric
Mo Derbas
Affirmative
N/A
1
Sho-Me Power Electric
Cooperative
Peter Dawson
Affirmative
N/A
1
Southern Company - Southern
Company Services, Inc.
Adrianne Collins
Affirmative
N/A
1
Sunflower Electric Power
Corporation
Paul Mehlhaff
Affirmative
N/A
1
Tacoma Public Utilities
(Tacoma, WA)
John Merrell
Affirmative
N/A
1
Tallahassee Electric (City of
Tallahassee, FL)
Scott Langston
None
N/A
1
Tennessee Valley Authority
Gabe Kurtz
Abstain
N/A
1
U.S. Bureau of Reclamation
Richard Jackson
Negative
Comments
Submitted
1
Westar Energy
Allen Klassen
Negative
Comments
Submitted
1
Western Area Power
Administration
sean erickson
Affirmative
N/A
2
Electric Reliability Council of
Texas, Inc.
Brandon Gleason
Affirmative
N/A
2
Independent Electricity
System Operator
Leonard Kula
Affirmative
N/A
2
ISO New England, Inc.
Michael Puscas
Affirmative
N/A
2
Midcontinent ISO, Inc.
Bobbi Welch
None
N/A
2
PJM Interconnection, L.L.C.
Mark Holman
Affirmative
N/A
3
AEP
Leanna Lamatrice
Negative
Comments
Submitted
3
AES - Indianapolis Power and
Light Co.
Bette White
Affirmative
N/A
3
Ameren - Ameren Services
David Jendras
Abstain
N/A
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Douglas Webb
Keith Jonassen
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
APS - Arizona Public Service
Co.
Vivian Moser
Abstain
N/A
3
Associated Electric
Cooperative, Inc.
Todd Bennett
Abstain
N/A
3
Austin Energy
W. Dwayne
Preston
Abstain
N/A
3
Avista - Avista Corporation
Scott Kinney
None
N/A
3
BC Hydro and Power Authority
Hootan Jarollahi
Abstain
N/A
3
Berkshire Hathaway Energy MidAmerican Energy Co.
Darnez Gresham
Affirmative
N/A
3
Black Hills Corporation
Eric Egge
Affirmative
N/A
3
Bonneville Power
Administration
Rebecca Berdahl
Affirmative
N/A
3
Central Electric Power
Cooperative (Missouri)
Adam Weber
Affirmative
N/A
3
City Utilities of Springfield,
Missouri
Scott Williams
Affirmative
N/A
3
CMS Energy - Consumers
Energy Company
Karl Blaszkowski
Abstain
N/A
3
Colorado Springs Utilities
Hillary Dobson
Affirmative
N/A
3
Cowlitz County PUD
Russell Noble
Negative
Comments
Submitted
3
Dominion - Dominion
Resources, Inc.
Connie Lowe
Abstain
N/A
3
Duke Energy
Lee Schuster
Affirmative
N/A
3
Edison International Southern California Edison
Company
Romel Aquino
Negative
Comments
Submitted
3
Eversource Energy
Sharon Flannery
Affirmative
N/A
3
Exelon
Kinte Whitehead
None
N/A
3
FirstEnergy - FirstEnergy
Corporation
Aaron Ghodooshim
Affirmative
N/A
3
Florida Municipal Power
Agency
Joe McKinney
Brandon
McCormick
Negative
Comments
Submitted
Douglas Webb
Negative
Comments
Submitted
3
Great Plains Energy - Kansas
John Carlson
City
Power
and
Light
Co.
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Great River Energy
Brian Glover
Affirmative
N/A
3
Hydro One Networks, Inc.
Paul Malozewski
Affirmative
N/A
3
Imperial Irrigation District
Denise Sanchez
Abstain
N/A
3
KAMO Electric Cooperative
Tony Gott
Affirmative
N/A
3
Lakeland Electric
Patricia Boody
Abstain
N/A
3
Lincoln Electric System
Jason Fortik
Abstain
N/A
3
Los Angeles Department of
Water and Power
Tony Skourtas
Affirmative
N/A
3
M and A Electric Power
Cooperative
Stephen Pogue
Affirmative
N/A
3
Manitoba Hydro
Karim Abdel-Hadi
Negative
Comments
Submitted
3
MEAG Power
Roger Brand
Abstain
N/A
3
Muscatine Power and Water
Seth Shoemaker
Affirmative
N/A
3
National Grid USA
Brian Shanahan
Affirmative
N/A
3
Nebraska Public Power
District
Tony Eddleman
Abstain
N/A
3
New York Power Authority
David Rivera
Affirmative
N/A
3
NiSource - Northern Indiana
Public Service Co.
Dmitriy Bazylyuk
Negative
Comments
Submitted
3
Northeast Missouri Electric
Power Cooperative
Skyler Wiegmann
Affirmative
N/A
3
NW Electric Power
Cooperative, Inc.
John Stickley
Affirmative
N/A
3
OGE Energy - Oklahoma Gas
and Electric Co.
Donald Hargrove
Affirmative
N/A
3
Omaha Public Power District
Aaron Smith
Affirmative
N/A
3
OTP - Otter Tail Power
Company
Wendi Olson
Affirmative
N/A
3
Owensboro Municipal Utilities
Thomas Lyons
Abstain
N/A
3
Platte River Power Authority
Jeff Landis
Affirmative
N/A
None
N/A
3
PNM Resources - Public
Trevor Tidwell
Service Company of New
Mexico
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Scott Miller
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Portland General Electric Co.
Dan Zollner
None
N/A
3
PPL - Louisville Gas and
Electric Co.
James Frank
None
N/A
3
PSEG - Public Service Electric
and Gas Co.
James Meyer
Affirmative
N/A
3
Public Utility District No. 1 of
Chelan County
Joyce Gundry
Negative
Comments
Submitted
3
Sacramento Municipal Utility
District
Nicole Looney
Affirmative
N/A
3
Salt River Project
Zack Heim
Affirmative
N/A
3
Santee Cooper
James Poston
Abstain
N/A
3
Seminole Electric Cooperative,
Inc.
Kristine Ward
Abstain
N/A
3
Sempra - San Diego Gas and
Electric
Bridget Silvia
Affirmative
N/A
3
Sho-Me Power Electric
Cooperative
Jeff Neas
Affirmative
N/A
3
Snohomish County PUD No. 1
Holly Chaney
Negative
Comments
Submitted
3
Southern Company - Alabama
Power Company
Joel Dembowski
Affirmative
N/A
3
Tacoma Public Utilities
(Tacoma, WA)
Marc Donaldson
Affirmative
N/A
3
TECO - Tampa Electric Co.
Ronald Donahey
None
N/A
3
Tennessee Valley Authority
Ian Grant
Abstain
N/A
3
Tri-State G and T Association,
Inc.
Janelle Marriott Gill
Abstain
N/A
3
WEC Energy Group, Inc.
Thomas Breene
Negative
Comments
Submitted
3
Westar Energy
Bryan Taggart
Negative
Comments
Submitted
3
Xcel Energy, Inc.
Michael Ibold
Abstain
N/A
4
Austin Energy
Jun Hua
None
N/A
4
City Utilities of Springfield,
Missouri
John Allen
Affirmative
N/A
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Joe Tarantino
Douglas Webb
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
4
CMS Energy - Consumers
Energy Company
Nicholas Tenney
Abstain
N/A
4
FirstEnergy - FirstEnergy
Corporation
Aubrey Short
Affirmative
N/A
4
Florida Municipal Power
Agency
Carol Chinn
Negative
Comments
Submitted
4
Public Utility District No. 1 of
Snohomish County
John Martinsen
Negative
Comments
Submitted
4
Public Utility District No. 2 of
Grant County, Washington
Karla Weaver
Affirmative
N/A
4
Sacramento Municipal Utility
District
Beth Tincher
Affirmative
N/A
4
Seattle City Light
Hao Li
Affirmative
N/A
4
Tacoma Public Utilities
(Tacoma, WA)
Hien Ho
Affirmative
N/A
4
Utility Services, Inc.
Brian EvansMongeon
Abstain
N/A
4
WEC Energy Group, Inc.
Matthew Beilfuss
Negative
Comments
Submitted
5
AEP
Thomas Foltz
Negative
Comments
Submitted
5
Ameren - Ameren Missouri
Sam Dwyer
None
N/A
5
APS - Arizona Public Service
Co.
Kelsi Rigby
Abstain
N/A
5
Austin Energy
Shirley Mathew
Affirmative
N/A
5
Avista - Avista Corporation
Glen Farmer
Affirmative
N/A
5
Berkshire Hathaway - NV
Energy
Kevin Salsbury
Affirmative
N/A
5
Black Hills Corporation
George Tatar
Affirmative
N/A
5
Boise-Kuna Irrigation District Lucky Peak Power Plant
Project
Mike Kukla
Affirmative
N/A
5
Bonneville Power
Administration
Scott Winner
Affirmative
N/A
5
Brazos Electric Power
Cooperative, Inc.
Shari Heino
Affirmative
N/A
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Brandon
McCormick
Joe Tarantino
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Choctaw Generation Limited
Partnership, LLLP
Rob Watson
None
N/A
5
City of Independence, Power
and Light Department
Jim Nail
Affirmative
N/A
5
CMS Energy - Consumers
Energy Company
David Greyerbiehl
Abstain
N/A
5
Colorado Springs Utilities
Jeff Icke
Affirmative
N/A
5
Con Ed - Consolidated Edison
Co. of New York
William Winters
Negative
Comments
Submitted
5
Cowlitz County PUD
Deanna Carlson
Negative
Comments
Submitted
5
Dairyland Power Cooperative
Tommy Drea
Abstain
N/A
5
Duke Energy
Dale Goodwine
Affirmative
N/A
5
Edison International Southern California Edison
Company
Selene Willis
Negative
Comments
Submitted
5
Entergy
Jamie Prater
None
N/A
5
Exelon
Cynthia Lee
None
N/A
5
FirstEnergy - FirstEnergy
Solutions
Robert Loy
Affirmative
N/A
5
Florida Municipal Power
Agency
Chris Gowder
Brandon
McCormick
Negative
Comments
Submitted
5
Great Plains Energy - Kansas
City Power and Light Co.
Marcus Moor
Douglas Webb
Negative
Comments
Submitted
5
Great River Energy
Preston Walsh
Affirmative
N/A
5
Herb Schrayshuen
Herb Schrayshuen
Affirmative
N/A
5
Imperial Irrigation District
Tino Zaragoza
Abstain
N/A
5
JEA
John Babik
None
N/A
5
Lakeland Electric
Jim Howard
Negative
Comments
Submitted
5
Lincoln Electric System
Kayleigh Wilkerson
Abstain
N/A
5
Los Angeles Department of
Water and Power
Glenn Barry
None
N/A
None
N/A
5
Lower Colorado River
Teresa Cantwell
Authority
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Daniel Valle
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Manitoba Hydro
Yuguang Xiao
Negative
Comments
Submitted
5
Massachusetts Municipal
Wholesale Electric Company
David Gordon
Abstain
N/A
5
Muscatine Power and Water
Neal Nelson
Affirmative
N/A
5
NaturEner USA, LLC
Eric Smith
None
N/A
5
NB Power Corporation
Laura McLeod
Abstain
N/A
5
New York Power Authority
Shivaz Chopra
Affirmative
N/A
5
NiSource - Northern Indiana
Public Service Co.
Kathryn Tackett
Negative
Comments
Submitted
5
Northern California Power
Agency
Marty Hostler
Affirmative
N/A
5
NRG - NRG Energy, Inc.
Patricia Lynch
None
N/A
5
OGE Energy - Oklahoma Gas
and Electric Co.
Patrick Wells
Affirmative
N/A
5
Oglethorpe Power Corporation
Donna Johnson
Affirmative
N/A
5
Omaha Public Power District
Mahmood Safi
Affirmative
N/A
5
Ontario Power Generation Inc.
Constantin
Chitescu
Affirmative
N/A
5
OTP - Otter Tail Power
Company
Brett Jacobs
Affirmative
N/A
5
Platte River Power Authority
Tyson Archie
Abstain
N/A
5
Portland General Electric Co.
Ryan Olson
Affirmative
N/A
5
PPL - Louisville Gas and
Electric Co.
JULIE
HOSTRANDER
None
N/A
5
PSEG - PSEG Fossil LLC
Tim Kucey
Abstain
N/A
5
Public Utility District No. 1 of
Chelan County
Meaghan Connell
Negative
Comments
Submitted
5
Public Utility District No. 1 of
Snohomish County
Sam Nietfeld
Negative
Comments
Submitted
5
Public Utility District No. 2 of
Grant County, Washington
Alex Ybarra
Affirmative
N/A
5
Sacramento Municipal Utility
District
Susan Oto
Affirmative
N/A
Affirmative
N/A
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
5
Salt River Project
Kevin Nielsen
Joe Tarantino
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Santee Cooper
Tommy Curtis
Abstain
N/A
5
Seattle City Light
Faz Kasraie
Affirmative
N/A
5
Sempra - San Diego Gas and
Electric
Jennifer Wright
Affirmative
N/A
5
SunPower
Bradley Collard
Abstain
N/A
5
Tacoma Public Utilities
(Tacoma, WA)
Ozan Ferrin
Affirmative
N/A
5
Tennessee Valley Authority
M Lee Thomas
Abstain
N/A
5
Westar Energy
Derek Brown
Negative
Comments
Submitted
6
AEP - AEP Marketing
Yee Chou
Negative
Comments
Submitted
6
Ameren - Ameren Services
Robert Quinlivan
None
N/A
6
APS - Arizona Public Service
Co.
Chinedu
Ochonogor
Abstain
N/A
6
Associated Electric
Cooperative, Inc.
Brian Ackermann
Affirmative
N/A
6
Austin Energy
Andrew Gallo
Affirmative
N/A
6
Berkshire Hathaway PacifiCorp
Sandra Shaffer
Abstain
N/A
6
Black Hills Corporation
Eric Scherr
Affirmative
N/A
6
Bonneville Power
Administration
Andrew Meyers
Affirmative
N/A
6
Cleco Corporation
Robert Hirchak
Negative
Comments
Submitted
6
Con Ed - Consolidated Edison
Co. of New York
Christopher
Overberg
Negative
Comments
Submitted
6
Dominion - Dominion
Resources, Inc.
Sean Bodkin
Affirmative
N/A
6
Duke Energy
Greg Cecil
Affirmative
N/A
6
Edison International Southern California Edison
Company
Kenya Streeter
Negative
Comments
Submitted
6
Entergy
Julie Hall
Negative
Comments
Submitted
None
N/A
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
6
Exelon
Becky Webb
Douglas Webb
Louis Guidry
Segment
Organization
Voter
6
FirstEnergy - FirstEnergy
Solutions
Ann Carey
6
Florida Municipal Power
Agency
Richard
Montgomery
6
Great Plains Energy - Kansas
City Power and Light Co.
6
Designated
Proxy
Ballot
NERC
Memo
Affirmative
N/A
Brandon
McCormick
Negative
Comments
Submitted
Jennifer
Flandermeyer
Douglas Webb
Negative
Comments
Submitted
Great River Energy
Donna Stephenson
Michael Brytowski
Affirmative
N/A
6
Imperial Irrigation District
Diana Torres
Abstain
N/A
6
Lakeland Electric
Paul Shipps
Negative
Comments
Submitted
6
Lincoln Electric System
Eric Ruskamp
Abstain
N/A
6
Los Angeles Department of
Water and Power
Anton Vu
Affirmative
N/A
6
Manitoba Hydro
Blair Mukanik
Negative
Comments
Submitted
6
Muscatine Power and Water
Ryan Streck
Affirmative
N/A
6
New York Power Authority
Thomas Savin
Affirmative
N/A
6
NextEra Energy - Florida
Power and Light Co.
Silvia Mitchell
Abstain
N/A
6
NiSource - Northern Indiana
Public Service Co.
Joe O'Brien
Negative
Comments
Submitted
6
Northern California Power
Agency
Dennis Sismaet
Affirmative
N/A
6
OGE Energy - Oklahoma Gas
and Electric Co.
Sing Tay
Affirmative
N/A
6
Omaha Public Power District
Joel Robles
Affirmative
N/A
6
Platte River Power Authority
Sabrina Martz
Abstain
N/A
6
Portland General Electric Co.
Daniel Mason
Abstain
N/A
6
PPL - Louisville Gas and
Electric Co.
Linn Oelker
None
N/A
6
PSEG - PSEG Energy
Resources and Trade LLC
Luiggi Beretta
Abstain
N/A
6
Public Utility District No. 1 of
Chelan County
Davis Jelusich
Negative
Comments
Submitted
None
N/A
6
Public Utility District No. 2 of
LeRoy Patterson
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Grant County, Washington
Segment
Organization
Voter
6
Sacramento Municipal Utility
District
Jamie Cutlip
6
Salt River Project
6
Designated
Proxy
NERC
Memo
Affirmative
N/A
Bobby Olsen
Affirmative
N/A
Santee Cooper
Michael Brown
Abstain
N/A
6
Seattle City Light
Charles Freeman
Affirmative
N/A
6
Seminole Electric Cooperative,
Inc.
Trudy Novak
Abstain
N/A
6
Snohomish County PUD No. 1
John Liang
Negative
Comments
Submitted
6
Southern Company - Southern
Company Generation
Ron Carlsen
Affirmative
N/A
6
Tennessee Valley Authority
Marjorie Parsons
Abstain
N/A
6
WEC Energy Group, Inc.
David Hathaway
Negative
Comments
Submitted
6
Westar Energy
Grant Wilkerson
Negative
Comments
Submitted
6
Western Area Power
Administration
Rosemary Jones
Negative
Comments
Submitted
8
David Kiguel
David Kiguel
Affirmative
N/A
8
Florida Reliability Coordinating
Council – Member Services
Division
Vince Ordax
Abstain
N/A
9
Commonwealth of
Massachusetts Department of
Public Utilities
Donald Nelson
Affirmative
N/A
10
Midwest Reliability
Organization
Russel Mountjoy
Affirmative
N/A
10
New York State Reliability
Council
ALAN ADAMSON
Affirmative
N/A
10
Northeast Power Coordinating
Council
Guy V. Zito
Affirmative
N/A
10
ReliabilityFirst
Anthony Jablonski
Affirmative
N/A
10
SERC Reliability Corporation
Dave Krueger
Affirmative
N/A
10
Texas Reliability Entity, Inc.
Rachel Coyne
Abstain
N/A
Abstain
N/A
10
Western Electricity
Steven Rueckert
Coordinating
Council
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Joe Tarantino
Ballot
Douglas Webb
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).
Description of Current Draft
This is the final draft of proposed standard for formal 10-day final ballot period.
Completed Actions
Date
Standards Committee approved Standard Authorization Request
(SAR) for posting
February 20, 2019
SAR posted for comment
February 25 –
March 27, 2019
45-day formal comment period with ballot
August 30 –
September, 9 2019
Anticipated Actions
Date
10-day final ballot
November 2019
Board adoption
February 2020
Final Draft of TPL-007-4
November 2019
Page 1 of 39
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
A. Introduction
1.
Title:
Events
Transmission System Planned Performance for Geomagnetic Disturbance
2.
Number:
TPL-007-4
3.
Purpose:
Establish requirements for Transmission system planned performance
during geomagnetic disturbance (GMD) events.
4.
Applicability:
4.1. Functional Entities:
4.1.1. Planning Coordinator with a planning area that includes a Facility or
Facilities specified in 4.2;
4.1.2. Transmission Planner with a planning area that includes a Facility or
Facilities specified in 4.2;
4.1.3. Transmission Owner who owns a Facility or Facilities specified in 4.2; and
4.1.4. Generator Owner who owns a Facility or Facilities specified in 4.2.
4.2. Facilities:
4.2.1. Facilities that include power transformer(s) with a high side, wyegrounded winding with terminal voltage greater than 200 kV.
5.
Effective Date: See Implementation Plan for TPL-007-4.
6.
Background: During a GMD event, geomagnetically-induced currents (GIC) may cause
transformer hot-spot heating or damage, loss of Reactive Power sources, increased
Reactive Power demand, and Misoperation(s), the combination of which may result in
voltage collapse and blackout.
B. Requirements and Measures
R1.
Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall
identify the individual and joint responsibilities of the Planning Coordinator and
Transmission Planner(s) in the Planning Coordinator’s planning area for maintaining
models, performing the study or studies needed to complete benchmark and
supplemental GMD Vulnerability Assessments, and implementing process(es) to
obtain GMD measurement data as specified in this standard. [Violation Risk Factor:
Lower] [Time Horizon: Long-term Planning]
Final Draft of TPL-007-4
November 2019
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
M1. Each Planning Coordinator, in conjunction with its Transmission Planners, shall provide
documentation on roles and responsibilities, such as meeting minutes, agreements,
copies of procedures or protocols in effect between entities or between departments
of a vertically integrated system, or email correspondence that identifies an
agreement has been reached on individual and joint responsibilities for maintaining
models, performing the study or studies needed to complete benchmark and
supplemental GMD Vulnerability Assessments, and implementing process(es) to
obtain GMD measurement data in accordance with Requirement R1.
R2. Each responsible entity, as determined in Requirement R1, shall maintain System
models and GIC System models of the responsible entity’s planning area for
performing the study or studies needed to complete benchmark and supplemental
GMD Vulnerability Assessments. [Violation Risk Factor: High] [Time Horizon: Longterm Planning]
M2. Each responsible entity, as determined in Requirement R1, shall have evidence in
either electronic or hard copy format that it is maintaining System models and GIC
System models of the responsible entity’s planning area for performing the study or
studies needed to complete benchmark and supplemental GMD Vulnerability
Assessments.
R3. Each responsible entity, as determined in Requirement R1, shall have criteria for
acceptable System steady state voltage performance for its System during the GMD
events described in Attachment 1. [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]
M3. Each responsible entity, as determined in Requirement R1, shall have evidence, such
as electronic or hard copies of the criteria for acceptable System steady state voltage
performance for its System in accordance with Requirement R3.
Benchmark GMD Vulnerability Assessment(s)
R4. Each responsible entity, as determined in Requirement R1, shall complete a
benchmark GMD Vulnerability Assessment of the Near-Term Transmission Planning
Horizon at least once every 60 calendar months. This benchmark GMD Vulnerability
Assessment shall use a study or studies based on models identified in Requirement R2,
document assumptions, and document summarized results of the steady state
analysis. [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
4.1. The study or studies shall include the following conditions:
4.1.1. System On-Peak Load for at least one year within the Near-Term
Transmission Planning Horizon; and
4.1.2. System Off-Peak Load for at least one year within the Near-Term
Transmission Planning Horizon.
Final Draft of TPL-007-4
November 2019
Page 3 of 39
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
4.2. The study or studies shall be conducted based on the benchmark GMD event
described in Attachment 1 to determine whether the System meets the
performance requirements for the steady state planning benchmark GMD event
contained in Table 1.
4.3. The benchmark GMD Vulnerability Assessment shall be provided: (i) to the
responsible entity’s Reliability Coordinator, adjacent Planning Coordinators, and
adjacent Transmission Planners within 90 calendar days of completion, and (ii) to
any functional entity that submits a written request and has a reliability-related
need within 90 calendar days of receipt of such request or within 90 calendar
days of completion of the benchmark GMD Vulnerability Assessment, whichever
is later.
4.3.1. If a recipient of the benchmark GMD Vulnerability Assessment provides
documented comments on the results, the responsible entity shall
provide a documented response to that recipient within 90 calendar days
of receipt of those comments.
M4. Each responsible entity, as determined in Requirement R1, shall have dated evidence
such as electronic or hard copies of its benchmark GMD Vulnerability Assessment
meeting all of the requirements in Requirement R4. Each responsible entity, as
determined in Requirement R1, shall also provide evidence, such as email records,
web postings with an electronic notice of posting, or postal receipts showing recipient
and date, that it has distributed its benchmark GMD Vulnerability Assessment: (i) to
the responsible entity’s Reliability Coordinator, adjacent Planning Coordinators, and
adjacent Transmission Planners within 90 calendar days of completion, and (ii) to any
functional entity that submits a written request and has a reliability-related need
within 90 calendar days of receipt of such request or within 90 calendar days of
completion of the benchmark GMD Vulnerability Assessment, whichever is later, as
specified in Requirement R4. Each responsible entity, as determined in Requirement
R1, shall also provide evidence, such as email notices or postal receipts showing
recipient and date, that it has provided a documented response to comments received
on its benchmark GMD Vulnerability Assessment within 90 calendar days of receipt of
those comments in accordance with Requirement R4.
R5. Each responsible entity, as determined in Requirement R1, shall provide GIC flow
information to be used for the benchmark thermal impact assessment of transformers
specified in Requirement R6 to each Transmission Owner and Generator Owner that
owns an applicable Bulk Electric System (BES) power transformer in the planning area.
The GIC flow information shall include: [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]
5.1. The maximum effective GIC value for the worst case geoelectric field orientation
for the benchmark GMD event described in Attachment 1. This value shall be
provided to the Transmission Owner or Generator Owner that owns each
applicable BES power transformer in the planning area.
Final Draft of TPL-007-4
November 2019
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
5.2. The effective GIC time series, GIC(t), calculated using the benchmark GMD event
described in Attachment 1 in response to a written request from the
Transmission Owner or Generator Owner that owns an applicable BES power
transformer in the planning area. GIC(t) shall be provided within 90 calendar
days of receipt of the written request and after determination of the maximum
effective GIC value in Part 5.1.
M5. Each responsible entity, as determined in Requirement R1, shall provide evidence,
such as email records, web postings with an electronic notice of posting, or postal
receipts showing recipient and date, that it has provided the maximum effective GIC
values to the Transmission Owner and Generator Owner that owns each applicable
BES power transformer in the planning area as specified in Requirement R5, Part 5.1.
Each responsible entity, as determined in Requirement R1, shall also provide evidence,
such as email records, web postings with an electronic notice of posting, or postal
receipts showing recipient and date, that it has provided GIC(t) in response to a
written request from the Transmission Owner or Generator Owner that owns an
applicable BES power transformer in the planning area.
R6. Each Transmission Owner and Generator Owner shall conduct a benchmark thermal
impact assessment for its solely and jointly owned applicable BES power transformers
where the maximum effective GIC value provided in Requirement R5, Part 5.1, is 75 A
per phase or greater. The benchmark thermal impact assessment shall: [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]
6.1. Be based on the effective GIC flow information provided in Requirement R5;
6.2. Document assumptions used in the analysis;
6.3. Describe suggested actions and supporting analysis to mitigate the impact of
GICs, if any; and
6.4. Be performed and provided to the responsible entities, as determined in
Requirement R1, within 24 calendar months of receiving GIC flow information
specified in Requirement R5, Part 5.1.
M6. Each Transmission Owner and Generator Owner shall have evidence such as electronic
or hard copies of its benchmark thermal impact assessment for all of its solely and
jointly owned applicable BES power transformers where the maximum effective GIC
value provided in Requirement R5, Part 5.1, is 75 A per phase or greater, and shall
have evidence such as email records, web postings with an electronic notice of
posting, or postal receipts showing recipient and date, that it has provided its thermal
impact assessment to the responsible entities as specified in Requirement R6.
R7.
Each responsible entity, as determined in Requirement R1, that concludes through
the benchmark GMD Vulnerability Assessment conducted in Requirement R4 that
their System does not meet the performance requirements for the steady state
planning benchmark GMD event contained in Table 1, shall develop a Corrective
Final Draft of TPL-007-4
November 2019
Page 5 of 39
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Action Plan (CAP) addressing how the performance requirements will be met. The CAP
shall: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
7.1. List System deficiencies and the associated actions needed to achieve required
System performance. Examples of such actions include:
•
Installation, modification, retirement, or removal of Transmission and
generation Facilities and any associated equipment.
•
Installation, modification, or removal of Protection Systems or Remedial
Action Schemes.
•
Use of Operating Procedures, specifying how long they will be needed as
part of the CAP.
•
Use of Demand-Side Management, new technologies, or other initiatives.
7.2. Be developed within one year of completion of the benchmark GMD
Vulnerability Assessment.
7.3. Include a timetable, subject to approval for any extension sought under Part 7.4,
for implementing the selected actions from Part 7.1. The timetable shall:
7.3.1. Specify implementation of non-hardware mitigation, if any, within two
years of development of the CAP; and
7.3.2. Specify implementation of hardware mitigation, if any, within four years
of development of the CAP.
7.4. Be submitted to the Compliance Enforcement Authority (CEA) with a request for
extension of time if the responsible entity is unable to implement the CAP within
the timetable provided in Part 7.3. The submitted CAP shall document the
following:
7.4.1. Circumstances causing the delay for fully or partially implementing the
selected actions in Part 7.1 and how those circumstances are beyond the
control of the responsible entity;
7.4.2. Revisions to the selected actions in Part 7.1, if any, including utilization of
Operating Procedures, if applicable; and
7.4.3. Updated timetable for implementing the selected actions in Part 7.1.
7.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent
Planning Coordinator(s), adjacent Transmission Planner(s), and functional
entities referenced in the CAP within 90 calendar days of development or
revision, and (ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later.
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November 2019
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
7.5.1. If a recipient of the CAP provides documented comments on the CAP, the
responsible entity shall provide a documented response to that recipient
within 90 calendar days of receipt of those comments.
M7. Each responsible entity, as determined in Requirement R1, that concludes, through
the benchmark GMD Vulnerability Assessment conducted in Requirement R4, that the
responsible entity’s System does not meet the performance requirements for the
steady state planning benchmark GMD event contained in Table 1 shall have evidence
such as dated electronic or hard copies of its CAP including timetable for
implementing selected actions, as specified in Requirement R7. Each responsible
entity, as determined in Requirement R1, shall also provide evidence, such as email
records or postal receipts showing recipient and date, that it submitted a request for
extension to the CEA if the responsible entity is unable to implement the CAP within
the timetable provided in Part 7.3. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records, web postings with
an electronic notice of posting, or postal receipts showing recipient and date, that it
has distributed its CAP or relevant information, if any, (i) to the responsible entity’s
Reliability Coordinator, adjacent Planning Coordinator(s), adjacent Transmission
Planner(s), and functional entities referenced in the CAP within 90 calendar days of
development or revision, and (ii) to any functional entity that submits a written
request and has a reliability-related need within 90 calendar days of receipt of such
request or within 90 calendar days of development or revision, whichever is later as
specified in Requirement R7. Each responsible entity, as determined in Requirement
R1, shall also provide evidence, such as email notices or postal receipts showing
recipient and date, that it has provided a documented response to comments received
on its CAP within 90 calendar days of receipt of those comments, in accordance with
Requirement R7.
Supplemental GMD Vulnerability Assessment(s)
R8.
Each responsible entity, as determined in Requirement R1, shall complete a
supplemental GMD Vulnerability Assessment of the Near-Term Transmission Planning
Horizon at least once every 60 calendar months. This supplemental GMD Vulnerability
Assessment shall use a study or studies based on models identified in Requirement
R2, document assumptions, and document summarized results of the steady state
analysis. [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
8.1. The study or studies shall include the following conditions:
8.1.1. System On-Peak Load for at least one year within the Near-Term
Transmission Planning Horizon; and
8.1.2. System Off-Peak Load for at least one year within the Near-Term
Transmission Planning Horizon.
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November 2019
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
8.2. The study or studies shall be conducted based on the supplemental GMD event
described in Attachment 1 to determine whether the System meets the
performance requirements for the steady state planning supplemental GMD
event contained in Table 1.
8.3. The supplemental GMD Vulnerability Assessment shall be provided: (i) to the
responsible entity’s Reliability Coordinator, adjacent Planning Coordinators,
adjacent Transmission Planners within 90 calendar days of completion, and (ii) to
any functional entity that submits a written request and has a reliability-related
need within 90 calendar days of receipt of such request or within 90 calendar
days of completion of the supplemental GMD Vulnerability Assessment,
whichever is later.
8.3.1. If a recipient of the supplemental GMD Vulnerability Assessment
provides documented comments on the results, the responsible entity
shall provide a documented response to that recipient within 90 calendar
days of receipt of those comments.
M8. Each responsible entity, as determined in Requirement R1, shall have dated evidence
such as electronic or hard copies of its supplemental GMD Vulnerability Assessment
meeting all of the requirements in Requirement R8. Each responsible entity, as
determined in Requirement R1, shall also provide evidence, such as email records,
web postings with an electronic notice of posting, or postal receipts showing recipient
and date, that it has distributed its supplemental GMD Vulnerability Assessment: (i) to
the responsible entity’s Reliability Coordinator, adjacent Planning Coordinators,
adjacent Transmission Planners within 90 calendar days of completion, and (ii) to any
functional entity that submits a written request and has a reliability-related need
within 90 calendar days of receipt of such request or within 90 calendar days of
completion of the supplemental GMD Vulnerability Assessment, whichever is later, as
specified in Requirement R8. Each responsible entity, as determined in Requirement
R1, shall also provide evidence, such as email notices or postal receipts showing
recipient and date, that it has provided a documented response to comments
received on its supplemental GMD Vulnerability Assessment within 90 calendar days
of receipt of those comments in accordance with Requirement R8.
R9.
Each responsible entity, as determined in Requirement R1, shall provide GIC flow
information to be used for the supplemental thermal impact assessment of
transformers specified in Requirement R10 to each Transmission Owner and
Generator Owner that owns an applicable Bulk Electric System (BES) power
transformer in the planning area. The GIC flow information shall include: [Violation
Risk Factor: Medium] [Time Horizon: Long-term Planning]
9.1. The maximum effective GIC value for the worst case geoelectric field orientation
for the supplemental GMD event described in Attachment 1. This value shall be
provided to the Transmission Owner or Generator Owner that owns each
applicable BES power transformer in the planning area.
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November 2019
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
9.2. The effective GIC time series, GIC(t), calculated using the supplemental GMD
event described in Attachment 1 in response to a written request from the
Transmission Owner or Generator Owner that owns an applicable BES power
transformer in the planning area. GIC(t) shall be provided within 90 calendar
days of receipt of the written request and after determination of the maximum
effective GIC value in Part 9.1.
M9. Each responsible entity, as determined in Requirement R1, shall provide evidence,
such as email records, web postings with an electronic notice of posting, or postal
receipts showing recipient and date, that it has provided the maximum effective GIC
values to the Transmission Owner and Generator Owner that owns each applicable
BES power transformer in the planning area as specified in Requirement R9, Part 9.1.
Each responsible entity, as determined in Requirement R1, shall also provide
evidence, such as email records, web postings with an electronic notice of posting, or
postal receipts showing recipient and date, that it has provided GIC(t) in response to a
written request from the Transmission Owner or Generator Owner that owns an
applicable BES power transformer in the planning area.
R10. Each Transmission Owner and Generator Owner shall conduct a supplemental
thermal impact assessment for its solely and jointly owned applicable BES power
transformers where the maximum effective GIC value provided in Requirement R9,
Part 9.1, is 85 A per phase or greater. The supplemental thermal impact assessment
shall: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
10.1. Be based on the effective GIC flow information provided in Requirement R9;
10.2. Document assumptions used in the analysis;
10.3. Describe suggested actions and supporting analysis to mitigate the impact of
GICs, if any; and
10.4. Be performed and provided to the responsible entities, as determined in
Requirement R1, within 24 calendar months of receiving GIC flow information
specified in Requirement R9, Part 9.1.
M10. Each Transmission Owner and Generator Owner shall have evidence such as
electronic or hard copies of its supplemental thermal impact assessment for all of its
solely and jointly owned applicable BES power transformers where the maximum
effective GIC value provided in Requirement R9, Part 9.1, is 85 A per phase or greater,
and shall have evidence such as email records, web postings with an electronic notice
of posting, or postal receipts showing recipient and date, that it has provided its
supplemental thermal impact assessment to the responsible entities as specified in
Requirement R10.
R11. Each responsible entity, as determined in Requirement R1, that concludes through
the supplemental GMD Vulnerability Assessment conducted in Requirement R8 that
their System does not meet the performance requirements for the steady state
planning supplemental GMD event contained in Table 1, shall develop a Corrective
Final Draft of TPL-007-4
November 2019
Page 9 of 39
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Action Plan (CAP) addressing how the performance requirements will be met. The CAP
shall: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
11.1. List System deficiencies and the associated actions needed to achieve required
System performance. Examples of such actions include:
•
Installation, modification, retirement, or removal of Transmission and
generation Facilities and any associated equipment.
•
Installation, modification, or removal of Protection Systems or Remedial
Action Schemes.
•
Use of Operating Procedures, specifying how long they will be needed as
part of the CAP.
•
Use of Demand-Side Management, new technologies, or other initiatives.
11.2. Be developed within one year of completion of the supplemental GMD
Vulnerability Assessment.
11.3. Include a timetable, subject to approval for any extension sought under Part
11.4, for implementing the selected actions from Part 11.1. The timetable shall:
11.3.1. Specify implementation of non-hardware mitigation, if any, within two
years of development of the CAP; and
11.3.2. Specify implementation of hardware mitigation, if any, within four years
of development of the CAP.
11.4. Be submitted to the CEA with a request for extension of time if the responsible
entity is unable to implement the CAP within the timetable provided in Part 11.3.
The submitted CAP shall document the following:
11.4.1. Circumstances causing the delay for fully or partially implementing the
selected actions in Part 11.1 and how those circumstances are beyond
the control of the responsible entity;
11.4.2. Revisions to the selected actions in Part 11.1, if any, including utilization
of Operating Procedures, if applicable; and
11.4.3. Updated timetable for implementing the selected actions in Part 11.1.
11.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent
Planning Coordinator(s), adjacent Transmission Planner(s), and functional
entities referenced in the CAP within 90 calendar days of development or
revision, and (ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later.
11.5.1. If a recipient of the CAP provides documented comments on the CAP, the
responsible entity shall provide a documented response to that recipient
within 90 calendar days of receipt of those comments.
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November 2019
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
M11. Each responsible entity, as determined in Requirement R1, that concludes, through
the supplemental GMD Vulnerability Assessment conducted in Requirement R8, that
the responsible entity’s System does not meet the performance requirements for the
steady state planning supplemental GMD event contained in Table 1 shall have
evidence such as dated electronic or hard copies of its CAP including timetable for
implementing selected actions, as specified in Requirement R11. Each responsible
entity, as determined in Requirement R1, shall also provide evidence, such as email
records or postal receipts showing recipient and date, that it submitted a request for
extension to the CEA if the responsible entity is unable to implement the CAP within
the timetable provided in Part 11.3. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records, web postings with
an electronic notice of posting, or postal receipts showing recipient and date, that it
has distributed its CAP or relevant information, if any, (i) to the responsible entity’s
Reliability Coordinator, adjacent Planning Coordinator(s), adjacent Transmission
Planner(s), and functional entities referenced in the CAP within 90 calendar days of
development or revision, and (ii) to any functional entity that submits a written
request and has a reliability-related need within 90 calendar days of receipt of such
request or within 90 calendar days of development or revision, whichever is later as
specified in Requirement R11. Each responsible entity, as determined in Requirement
R1, shall also provide evidence, such as email notices or postal receipts showing
recipient and date, that it has provided a documented response to comments received
on its CAP within 90 calendar days of receipt of those comments, in accordance with
Requirement R11.
GMD Measurement Data Processes
R12. Each responsible entity, as determined in Requirement R1, shall implement a process
to obtain GIC monitor data from at least one GIC monitor located in the Planning
Coordinator’s planning area or other part of the system included in the Planning
Coordinator’s GIC System model. [Violation Risk Factor: Lower] [Time Horizon: Longterm Planning]
M12. Each responsible entity, as determined in Requirement R1, shall have evidence such
as electronic or hard copies of its GIC monitor location(s) and documentation of its
process to obtain GIC monitor data in accordance with Requirement R12.
R13. Each responsible entity, as determined in Requirement R1, shall implement a process
to obtain geomagnetic field data for its Planning Coordinator’s planning area.
[Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
M13. Each responsible entity, as determined in Requirement R1, shall have evidence such
as electronic or hard copies of its process to obtain geomagnetic field data for its
Planning Coordinator’s planning area in accordance with Requirement R13.
C. Compliance
1.
Compliance Monitoring Process
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
Authority may ask an entity to provide other evidence to show that it was
compliant for the full-time period since the last audit.
The applicable entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
•
For Requirements R1, R2, R3, R5, R6, R9, and R10, each responsible entity
shall retain documentation as evidence for five years.
•
For Requirements R4 and R8, each responsible entity shall retain
documentation of the current GMD Vulnerability Assessment and the
preceding GMD Vulnerability Assessment.
•
For Requirement R7 and R11, each responsible entity shall retain
documentation as evidence for five years or until all actions in the
Corrective Action Plan are completed, whichever is later.
•
For Requirements R12 and R13, each responsible entity shall retain
documentation as evidence for three years.
1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Table 1: Steady State Planning GMD Event
Steady State:
a. Voltage collapse, Cascading and uncontrolled islanding shall not occur.
b. Generation loss is acceptable as a consequence of the steady state planning GMD events.
c. Planned System adjustments such as Transmission configuration changes and re-dispatch of generation are allowed if such
adjustments are executable within the time duration applicable to the Facility Ratings.
Category
Initial Condition
Event
Interruption of
Firm
Transmission
Service Allowed
Load Loss
Allowed
Benchmark GMD
Event – GMD
Event with
Outages
1. System as may be
postured in response
to space weather
information1, and then
2. GMD event2
Reactive Power compensation devices
and other Transmission Facilities
removed as a result of Protection
System operation or Misoperation due
to harmonics during the GMD event
Yes3
Yes3
Supplemental
GMD Event – GMD
Event with
Outages
1. System as may be
postured in response
to space weather
information1, and then
2. GMD event2
Reactive Power compensation devices
and other Transmission Facilities
removed as a result of Protection
System operation or Misoperation due
to harmonics during the GMD event
Yes
Yes
Table 1: Steady State Performance Footnotes
1. The System condition for GMD planning may include adjustments to posture the System that are executable in response to
space weather information.
2. The GMD conditions for the benchmark and supplemental planning events are described in Attachment 1.
3. Load loss as a result of manual or automatic Load shedding (e.g., UVLS) and/or curtailment of Firm Transmission Service may
be used to meet BES performance requirements during studied GMD conditions. The likelihood and magnitude of Load loss or
curtailment of Firm Transmission Service should be minimized.
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
Lower VSL
R1.
R2.
Final Draft of TPL-007-4
November 2019
N/A
N/A
Violation Severity Levels
Moderate VSL
N/A
N/A
High VSL
Severe VSL
N/A
The Planning Coordinator, in
conjunction with its
Transmission Planner(s),
failed to determine and
identify individual or joint
responsibilities of the
Planning Coordinator and
Transmission Planner(s) in
the Planning Coordinator’s
planning area for
maintaining models,
performing the study or
studies needed to complete
benchmark and
supplemental GMD
Vulnerability Assessments,
and implementing
process(es) to obtain GMD
measurement data as
specified in this standard.
The responsible entity did
not maintain either System
models or GIC System
models of the responsible
entity’s planning area for
performing the studies
The responsible entity did
not maintain both System
models and GIC System
models of the responsible
entity’s planning area for
performing the studies
Page 14 of 39
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
needed to complete
benchmark and
supplemental GMD
Vulnerability Assessments.
R3.
R4.
N/A
N/A
N/A
The responsible entity
completed a benchmark
GMD Vulnerability
Assessment, but it was more
than 60 calendar months
and less than or equal to 64
calendar months since the
last benchmark GMD
Vulnerability Assessment.
The responsible entity’s
completed benchmark GMD
Vulnerability Assessment
failed to satisfy one of the
elements listed in
Requirement R4, Parts 4.1
through 4.3;
OR
The responsible entity
completed a benchmark
GMD Vulnerability
Assessment, but it was more
than 64 calendar months
and less than or equal to 68
calendar months since the
The responsible entity’s
completed benchmark GMD
Vulnerability Assessment
failed to satisfy two of the
elements listed in
Requirement R4, Parts 4.1
through 4.3;
OR
The responsible entity
completed a benchmark
GMD Vulnerability
Assessment, but it was more
than 68 calendar months
and less than or equal to 72
calendar months since the
Final Draft of TPL-007-4
November 2019
Severe VSL
needed to complete
benchmark and
supplemental GMD
Vulnerability Assessments.
The responsible entity did
not have criteria for
acceptable System steady
state voltage performance
for its System during the
GMD events described in
Attachment 1 as required.
The responsible entity’s
completed benchmark GMD
Vulnerability Assessment
failed to satisfy three of the
elements listed in
Requirement R4, Parts 4.1
through 4.3;
OR
The responsible entity
completed a benchmark
GMD Vulnerability
Assessment, but it was more
than 72 calendar months
since the last benchmark
Page 15 of 39
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
R5.
R6.
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
last benchmark GMD
Vulnerability Assessment.
last benchmark GMD
Vulnerability Assessment.
GMD Vulnerability
Assessment;
OR
The responsible entity does
not have a completed
benchmark GMD
Vulnerability Assessment.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 90
calendar days and less than
or equal to 100 calendar
days after receipt of a
written request.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 100
calendar days and less than
or equal to 110 calendar
days after receipt of a
written request.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 110
calendar days after receipt
of a written request.
The responsible entity did
not provide the maximum
effective GIC value to the
Transmission Owner and
Generator Owner that owns
each applicable BES power
transformer in the planning
area;
OR
The responsible entity did
not provide the effective GIC
time series, GIC(t), upon
written request.
The responsible entity failed
to conduct a benchmark
thermal impact assessment
for 5% or less or one of its
solely owned and jointly
owned applicable BES power
The responsible entity failed
to conduct a benchmark
thermal impact assessment
for more than 5% up to (and
including) 10% or two of its
solely owned and jointly
The responsible entity failed
to conduct a benchmark
thermal impact assessment
for more than 10% up to
(and including) 15% or three
of its solely owned and
The responsible entity failed
to conduct a benchmark
thermal impact assessment
for more than 15% or more
than three of its solely
owned and jointly owned
Final Draft of TPL-007-4
November 2019
Page 16 of 39
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase;
OR
The responsible entity
conducted a benchmark
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase
but did so more than 24
calendar months and less
than or equal to 26 calendar
months of receiving GIC flow
information specified in
Requirement R5, Part 5.1.
owned applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase;
OR
The responsible entity
conducted a benchmark
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase
but did so more than 26
calendar months and less
than or equal to 28 calendar
months of receiving GIC flow
information specified in
Requirement R5, Part 5.1;
OR
The responsible entity failed
to include one of the
jointly owned applicable BES
power transformers
(whichever is greater) where
the maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase;
OR
The responsible entity
conducted a benchmark
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase
but did so more than 28
calendar months and less
than or equal to 30 calendar
months of receiving GIC flow
information specified in
Requirement R5, Part 5.1;
OR
The responsible entity failed
to include two of the
applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase;
OR
The responsible entity
conducted a benchmark
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase
but did so more than 30
calendar months of receiving
GIC flow information
specified in Requirement R5,
Part 5.1;
OR
The responsible entity failed
to include three of the
required elements as listed
Final Draft of TPL-007-4
November 2019
Page 17 of 39
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
required elements as listed
in Requirement R6, Parts 6.1
through 6.3.
required elements as listed
in Requirement R6, Parts 6.1
through 6.3.
in Requirement R6, Parts 6.1
through 6.3.
The responsible entity’s
Corrective Action Plan failed
to comply with one of the
elements in Requirement
R7, Parts 7.1 through 7.5.
The responsible entity’s
Corrective Action Plan failed
to comply with two of the
elements in Requirement R7,
Parts 7.1 through 7.5.
The responsible entity’s
Corrective Action Plan failed
to comply with three of the
elements in Requirement
R7, Parts 7.1 through 7.5.
The responsible entity’s
Corrective Action Plan failed
to comply with four or more
of the elements in
Requirement R7, Parts 7.1
through 7.5;
OR
The responsible entity did
not develop a Corrective
Action Plan as required by
Requirement R7.
The responsible entity
completed a supplemental
GMD Vulnerability
Assessment, but it was more
than 60 calendar months
and less than or equal to 64
calendar months since the
last supplemental GMD
Vulnerability Assessment.
The responsible entity’s
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
one of the elements listed in
Requirement R8, Parts 8.1
through 8.3;
OR
The responsible entity
completed a supplemental
GMD Vulnerability
Assessment, but it was more
The responsible entity’s
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
two of the elements listed in
Requirement R8, Parts 8.1
through 8.3;
OR
The responsible entity
completed a supplemental
GMD Vulnerability
Assessment, but it was more
The responsible entity’s
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
three of the elements listed
in Requirement R8, Parts 8.1
through 8.3;
OR
The responsible entity
completed a supplemental
GMD Vulnerability
Assessment, but it was more
R7.
R8.
Final Draft of TPL-007-4
November 2019
Page 18 of 39
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
R9.
R10.
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
than 64 calendar months
and less than or equal to 68
calendar months since the
last supplemental GMD
Vulnerability Assessment.
than 68 calendar months
and less than or equal to 72
calendar months since the
last supplemental GMD
Vulnerability Assessment.
than 72 calendar months
since the last supplemental
GMD Vulnerability
Assessment;
OR
The responsible entity does
not have a completed
supplemental GMD
Vulnerability Assessment.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 90
calendar days and less than
or equal to 100 calendar
days after receipt of a
written request.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 100
calendar days and less than
or equal to 110 calendar
days after receipt of a
written request.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 110
calendar days after receipt
of a written request.
The responsible entity did
not provide the maximum
effective GIC value to the
Transmission Owner and
Generator Owner that owns
each applicable BES power
transformer in the planning
area;
OR
The responsible entity did
not provide the effective GIC
time series, GIC(t), upon
written request.
The responsible entity failed
to conduct a supplemental
thermal impact assessment
for 5% or less or one of its
The responsible entity failed
to conduct a supplemental
thermal impact assessment
for more than 5% up to (and
The responsible entity failed
to conduct a supplemental
thermal impact assessment
for more than 10% up to
The responsible entity failed
to conduct a supplemental
thermal impact assessment
for more than 15% or more
Final Draft of TPL-007-4
November 2019
Page 19 of 39
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
solely owned and jointly
owned applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase;
OR
The responsible entity
conducted a supplemental
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase
but did so more than 24
calendar months and less
than or equal to 26 calendar
months of receiving GIC flow
information specified in
Requirement R9, Part 9.1.
including) 10% or two of its
solely owned and jointly
owned applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase;
OR
The responsible entity
conducted a supplemental
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase
but did so more than 26
calendar months and less
than or equal to 28 calendar
months of receiving GIC flow
information specified in
Requirement R9, Part 9.1
OR
(and including) 15% or three
of its solely owned and
jointly owned applicable BES
power transformers
(whichever is greater) where
the maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase;
OR
The responsible entity
conducted a supplemental
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase
but did so more than 28
calendar months and less
than or equal to 30 calendar
months of receiving GIC flow
information specified in
Requirement R9, Part 9.1;
OR
than three of its solely
owned and jointly owned
applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase;
OR
The responsible entity
conducted a supplemental
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase
but did so more than 30
calendar months of receiving
GIC flow information
specified in Requirement R9,
Part 9.1;
OR
Final Draft of TPL-007-4
November 2019
Page 20 of 39
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
R11.
Violation Severity Levels
Lower VSL
The responsible entity’s
Corrective Action Plan failed
to comply with one of the
elements in Requirement
R11, Parts 11.1 through
11.5.
Final Draft of TPL-007-4
November 2019
Moderate VSL
High VSL
Severe VSL
The responsible entity failed
to include one of the
required elements as listed
in Requirement R10, Parts
10.1 through 10.3.
The responsible entity failed
to include two of the
required elements as listed
in Requirement R10, Parts
10.1 through 10.3.
The responsible entity failed
to include three of the
required elements as listed
in Requirement R10, Parts
10.1 through 10.3.
The responsible entity’s
Corrective Action Plan failed
to comply with three of the
elements in Requirement
R11, Parts 11.1 through
11.5.
The responsible entity’s
Corrective Action Plan failed
to comply with four or more
of the elements in
Requirement R11, Parts 11.1
through 11.5;
OR
The responsible entity did
not develop a Corrective
Action Plan as required by
Requirement R11.
The responsible entity’s
Corrective Action Plan failed
to comply with two of the
elements in Requirement
R11, Parts 11.1 through
11.5.
Page 21 of 39
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
Violation Severity Levels
Lower VSL
R12.
R13.
Final Draft of TPL-007-4
November 2019
N/A
N/A
Moderate VSL
N/A
N/A
High VSL
N/A
N/A
Severe VSL
The responsible entity did
not implement a process to
obtain GIC monitor data
from at least one GIC
monitor located in the
Planning Coordinator’s
planning area or other part
of the system included in the
Planning Coordinator’s GIC
System Model.
The responsible entity did
not implement a process to
obtain geomagnetic field
data for its Planning
Coordinator’s planning area.
Page 22 of 39
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
D. Regional Variances
D.A. Regional Variance for Canadian Jurisdictions
This Variance shall be applicable in those Canadian jurisdictions where the Variance
has been approved for use by the applicable governmental authority or has otherwise
become effective in the jurisdiction.
This variance replaces all references to “Attachment 1” in the standard with
“Attachment 1 or Attachment 1-CAN.”
In addition, this Variance replaces Requirement R7, Part 7.3 through Part 7.5 and
Requirement R11, Part 11.3 through Part 11.5 with the following:
D.A.7.3. Include a timetable, subject to revision by the responsible entity in Part
D.A.7.4, for implementing the selected actions from Part 7.1. The timetable
shall:
D.A.7.3.1. Specify implementation of non-hardware mitigation, if any, within
two years of the later of the development of the CAP or receipt of
regulatory approvals, if required; and
D.A.7.3.2. Specify implementation of hardware mitigation, if any, within four
years of the later of the development of the CAP or receipt of
regulatory approvals, if required.
D.A.7.4. Be revised if the responsible entity is unable to implement the CAP within
the timetable for implementation provided in Part D.A.7.3. The revised CAP
shall document the following:
D.A.7.4.1 Circumstances causing the delay for fully or partially implementing the
selected actions in Part 7.1 and how those circumstances are beyond
the control of the responsible entity;
D.A.7.4.2 Revisions to the selected actions in Part 7.1, if any, including utilization
of Operating Procedures if applicable; and
D.A.7.4.3 Updated timetable for implementing the selected actions in Part 7.1.
D.A.7.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent
Planning Coordinator(s), adjacent Transmission Planner(s), and functional
entities referenced in the CAP within 90 calendar days of development or
revision, (ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later, and
(iii) to the Compliance Enforcement Authority or Applicable Governmental
Authority when revised under D.A.7.4 within 90 calendar days of revision.
D.A.7.5.1 If a recipient of the CAP provides documented comments on the CAP,
the responsible entity shall provide a documented response to that
recipient within 90 calendar days of receipt of those comments.
Final Draft of TPL-007-4
November 2019
Page 23 of 39
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
D.A.M.7. Each responsible entity, as determined in Requirement R1, that concludes,
through the benchmark GMD Vulnerability Assessment conducted in
Requirement R4, that the responsible entity’s System does not meet the
performance requirements for the steady state planning benchmark GMD
event contained in Table 1 shall have evidence such as dated electronic or
hard copies of its CAP including timetable for implementing selected actions,
as specified in Requirement R7. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records or postal
receipts showing recipient and date, that it has revised its CAP if situations
beyond the responsible entity's control prevent implementation of the CAP
within the timetable specified. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records, web
postings with an electronic notice of posting, or postal receipts showing
recipient and date, that it has distributed its CAP or relevant information, if
any, (i) to the responsible entity’s Reliability Coordinator, adjacent Planning
Coordinator(s), adjacent Transmission Planner(s), and functional entities
referenced in the CAP within 90 calendar days of development or revision,
(ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later as
specified in Requirement R7, and (iii) to the Compliance Enforcement
Authority or Applicable Governmental Authority when revised under D.A.7.4
within 90 calendar days of revision. Each responsible entity, as determined
in Requirement R1, shall also provide evidence, such as email notices or
postal receipts showing recipient and date, that it has provided a
documented response to comments received on its CAP within 90 calendar
days of receipt of those comments, in accordance with Requirement R7.
D.A.11.3.Include a timetable, subject to revision by the responsible entity in Part
D.A.11.4, for implementing the selected actions from Part 11.1. The
timetable shall:
D.A.11.3.1. Specify implementation of non-hardware mitigation, if any, within
two years of the later of the development of the CAP or receipt of
regulatory approvals, if required; and
D.A.11.3.2. Specify implementation of hardware mitigation, if any, within four
years of the later of the development of the CAP or receipt of
regulatory approvals, if required.
D.A.11.4. Be revised if the responsible entity is unable to implement the CAP within
the timetable for implementation provided in Part D.A.11.3. The revised CAP
shall document the following:
D.A.11.4.1 Circumstances causing the delay for fully or partially implementing
the selected actions in Part 11.1 and how those circumstances are
beyond the control of the responsible entity;
Final Draft of TPL-007-4
November 2019
Page 24 of 39
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
D.A.11.4.2 Revisions to the selected actions in Part 11.1, if any, including
utilization of Operating Procedures if applicable; and
D.A.11.4.3 Updated timetable for implementing the selected actions in Part
11.1.
D.A.11.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent
Planning Coordinator(s), adjacent Transmission Planner(s), and functional
entities referenced in the CAP within 90 calendar days of development or
revision, (ii) to any functional entity that submits a written request and has
a reliability-related need within 90 calendar days of receipt of such request
or within 90 calendar days of development or revision, whichever is later,
and (iii) to the Compliance Enforcement Authority or Applicable
Governmental Authority when revised under D.A.11.4 within 90 calendar
days of revision.
D.A.11.5.1. If a recipient of the CAP provides documented comments on the
CAP, the responsible entity shall provide a documented response to
that recipient within 90 calendar days of receipt of those comments.
Final Draft of TPL-007-4
November 2019
Page 25 of 39
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
D.A.M.11. Each responsible entity, as determined in Requirement R1, that concludes,
through the supplemental GMD Vulnerability Assessment conducted in
Requirement R8, that the responsible entity’s System does not meet the
performance requirements for the steady state planning supplemental GMD
event contained in Table 1 shall have evidence such as dated electronic or
hard copies of its CAP including timetable for implementing selected actions,
as specified in Requirement R11. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records or postal
receipts showing recipient and date, that it has revised its CAP if situations
beyond the responsible entity's control prevent implementation of the CAP
within the timetable specified. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records, web
postings with an electronic notice of posting, or postal receipts showing
recipient and date, that it has distributed its CAP or relevant information, if
any, (i) to the responsible entity’s Reliability Coordinator, adjacent Planning
Coordinator(s), adjacent Transmission Planner(s), and functional entities
referenced in the CAP within 90 calendar days of development or revision,
(ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later as
specified in Requirement R11, and (iii) to the Compliance Enforcement
Authority or Applicable Governmental Authority when revised under
D.A.11.4 within 90 calendar days of revision. Each responsible entity, as
determined in Requirement R1, shall also provide evidence, such as email
notices or postal receipts showing recipient and date, that it has provided a
documented response to comments received on its CAP within 90 calendar
days of receipt of those comments, in accordance with Requirement R11.
Final Draft of TPL-007-4
November 2019
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
E. Associated Documents
Attachment 1
Attachment 1-CAN
Final Draft of TPL-007-4
November 2019
Page 27 of 39
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Version History
Version
1
Date
Action
December 17, 2014 Adopted by the NERC Board of Trustees
Change
Tracking
New
Revised to
respond to
directives in FERC
Order No. 830.
2
November 9, 2017
Adopted by the NERC Board of Trustees
2
November 25, 2018
FERC Order issued approving TPL-007-2.
Docket No. RM18-8-000
3
February 7, 2019
Adopted by the NERC Board of Trustees
Canadian
Variance
Adopted by the NERC Board of Trustees
Revised to
respond to
directives in FERC
Order. 851
4
Final Draft of TPL-007-4
November 2019
TBD
Page 28 of 39
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Attachment 1
Calculating Geoelectric Fields for the Benchmark and Supplemental GMD Events
The benchmark GMD event 1 defines the geoelectric field values used to compute GIC flows that
are needed to conduct a benchmark GMD Vulnerability Assessment. It is composed of the
following elements: (1) a reference peak geoelectric field amplitude of 8 V/km derived from
statistical analysis of historical magnetometer data; (2) scaling factors to account for local
geomagnetic latitude; (3) scaling factors to account for local earth conductivity; and (4) a
reference geomagnetic field time series or waveform to facilitate time-domain analysis of GMD
impact on equipment.
The supplemental GMD event is composed of similar elements as described above, except (1) the
reference peak geoelectric field amplitude is 12 V/km over a localized area; and (2) the
geomagnetic field time series or waveform includes a local enhancement in the waveform.2
The regional geoelectric field peak amplitude used in GMD Vulnerability Assessment, E peak , can
be obtained from the reference geoelectric field value of 8 V/km for the benchmark GMD event
(1) or 12 V/km for the supplemental GMD event (2) using the following relationships:
𝐸𝐸𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝 = 8 × 𝛼𝛼 × 𝛽𝛽 𝑏𝑏 (𝑉𝑉 ⁄𝑘𝑘𝑘𝑘)
𝐸𝐸𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝 = 12 × 𝛼𝛼 × 𝛽𝛽 𝑠𝑠 (𝑉𝑉 ⁄𝑘𝑘𝑘𝑘)
(1)
(2)
where, α is the scaling factor to account for local geomagnetic latitude, and β is a scaling factor
to account for the local earth conductivity structure. Subscripts b and s for the β scaling factor
denote association with the benchmark or supplemental GMD events, respectively.
Scaling the Geomagnetic Field
The benchmark and supplemental GMD events are defined for geomagnetic latitude of 60° and
must be scaled to account for regional differences based on geomagnetic latitude. Table 2
provides a scaling factor correlating peak geoelectric field to geomagnetic latitude. Alternatively,
the scaling factor α is computed with the empirical expression:
𝛼𝛼 = 0.001 × 𝑒𝑒 (0.115×𝐿𝐿)
(3)
where, L is the geomagnetic latitude in degrees and 0.1 ≤ α ≤ 1.
The Benchmark Geomagnetic Disturbance Event Description, May 2016 is available on the Related Information webpage for
TPL-007-1: http://www.nerc.com/pa/Stand/TPL0071RD/Benchmark_clean_May12_complete.pdf.
2 The extent of local enhancements is on the order of 100 km in North-South (latitude) direction but longer in East-West
(longitude) direction. The local enhancement in the geomagnetic field occurs over the time period of 2-5 minutes. Additional
information is available in the Supplemental Geomagnetic Disturbance Event Description, October 2017 white paper on the
Project 2013-03 Geomagnetic Disturbance Mitigation project webpage: http://www.nerc.com/pa/Stand/Pages/Project-201303-Geomagnetic-Disturbance-Mitigation.aspx.
1
Final Draft of TPL-007-4
November 2019
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
For large planning areas that cover more than one scaling factor from Table 2, the GMD
Vulnerability Assessment should be based on a peak geoelectric field that is:
•
calculated by using the most conservative (largest) value for α; or
•
calculated assuming a non-uniform or piecewise uniform geomagnetic field.
Table 2: Geomagnetic Field Scaling Factors for the
Benchmark and Supplemental GMD
Events
Geomagnetic Latitude
(Degrees)
Scaling Factor1
(α)
≤ 40
0.10
45
0.2
50
0.3
54
0.5
56
0.6
57
0.7
58
0.8
59
0.9
≥ 60
1.0
Scaling the Geoelectric Field
The benchmark GMD event is defined for the reference Quebec earth model described in Table
4. The peak geoelectric field, E peak , used in a GMD Vulnerability Assessment may be obtained by
either:
•
Calculating the geoelectric field for the ground conductivity in the planning area and the
reference geomagnetic field time series scaled according to geomagnetic latitude, using
a procedure such as the plane wave method described in the NERC GMD Task Force GIC
Application Guide; 3 or
•
Using the earth conductivity scaling factor β from Table 3 that correlates to the ground
conductivity map in Figure 1 or Figure 2. Along with the scaling factor α from equation
(3) or Table 2, β is applied to the reference geoelectric field using equation (1 or 2, as
applicable) to obtain the regional geoelectric field peak amplitude E peak to be used in
GMD Vulnerability Assessments. When a ground conductivity model is not available, the
responsible entity should use the largest β factor of adjacent physiographic regions or a
technically justified value.
Available at the NERC GMD Task Force project webpage: http://www.nerc.com/comm/PC/Pages/Geomagnetic-DisturbanceTask-Force-(GMDTF)-2013.aspx.
3
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
The earth models used to calculate Table 3 for the United States were obtained from publicly
available information published on the U. S. Geological Survey website. 4 The models used to
calculate Table 3 for Canada were obtained from Natural Resources Canada (NRCan) and reflect
the average structure for large regions. A planner can also use specific earth model(s) with
documented justification and the reference geomagnetic field time series to calculate the β
factor(s) as follows:
𝛽𝛽𝑏𝑏 = 𝐸𝐸 ⁄8 for the benchmark GMD event
(4)
𝛽𝛽𝑠𝑠 = 𝐸𝐸 ⁄12 for the supplemental GMD
(5)
where, E is the absolute value of peak geoelectric in V/km obtained from the technically justified
earth model and the reference geomagnetic field time series.
For large planning areas that span more than one β scaling factor, the most conservative (largest)
value for β may be used in determining the peak geoelectric field to obtain conservative results.
Alternatively, a planner could perform analysis using a non-uniform or piecewise uniform
geoelectric field.
Applying the Localized Peak Geoelectric Field in the Supplemental GMD Event
The peak geoelectric field of the supplemental GMD event occurs in a localized area.5 Planners
have flexibility to determine how to apply the localized peak geoelectric field over the planning
area in performing GIC calculations. Examples of approaches are:
•
Apply the peak geoelectric field (12 V/km scaled to the planning area) over the entire
planning area;
•
Apply a spatially limited (12 V/km scaled to the planning area) peak geoelectric field (e.g.,
100 km in North-South latitude direction and 500 km in East-West longitude direction)
over a portion(s) of the system, and apply the benchmark GMD event over the rest of the
system; or
•
Other methods to adjust the benchmark GMD event analysis to account for the localized
geoelectric field enhancement of the supplemental GMD event.
Available at http://geomag.usgs.gov/conductivity/.
See the Supplemental Geomagnetic Disturbance Description white paper located on the Project 2013-03 Geomagnetic
Disturbance Mitigation project webpage: http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspx.
4
5
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
FL-1
Figure 1: Physiographic Regions of the Continental United States 6
Figure 2: Physiographic Regions of Canada
6
Additional map detail is available at the U.S. Geological Survey: http://geomag.usgs.gov/.
Final Draft of TPL-007-4
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Table 3: Geoelectric Field Scaling Factors
Final Draft of TPL-007-4
November 2019
Earth model
Scaling Factor
Benchmark Event
(β b )
Scaling Factor
Supplemental
Event
(β s )
AK1A
0.56
0.51
AK1B
0.56
0.51
AP1
0.33
0.30
AP2
0.82
0.78
BR1
0.22
0.22
CL1
0.76
0.73
CO1
0.27
0.25
CP1
0.81
0.77
CP2
0.95
0.86
FL1
0.76
0.73
CS1
0.41
0.37
IP1
0.94
0.90
IP2
0.28
0.25
IP3
0.93
0.90
IP4
0.41
0.35
NE1
0.81
0.77
PB1
0.62
0.55
PB2
0.46
0.39
PT1
1.17
1.19
SL1
0.53
0.49
SU1
0.93
0.90
BOU
0.28
0.24
FBK
0.56
0.56
PRU
0.21
0.22
BC
0.67
0.62
PRAIRIES
0.96
0.88
SHIELD
1.0
1.0
ATLANTIC
0.79
0.76
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Scaling factors in Table 3 are dependent upon the frequency content of the reference storm.
Consequently, the benchmark GMD event and the supplemental GMD event may produce
different scaling factors for a given earth model.
Table 4: Reference Earth Model (Quebec)
Layer Thickness (km)
Resistivity (Ω-m)
15
20,000
10
200
125
1,000
200
100
∞
3
Reference Geomagnetic Field Time Series or Waveform for the Benchmark GMD
Event7
The geomagnetic field measurement record of the March 13-14 1989 GMD event, measured at
the NRCan Ottawa geomagnetic observatory, is the basis for the reference geomagnetic field
waveform to be used to calculate the GIC time series, GIC(t), required for transformer thermal
impact assessment.
The geomagnetic latitude of the Ottawa geomagnetic observatory is 55°; therefore, the
amplitudes of the geomagnetic field measurement data were scaled up to the 60° reference
geomagnetic latitude (see Figure 3) such that the resulting peak geoelectric field amplitude
computed using the reference earth model was 8 V/km (see Figures 4 and 5). The sampling rate
for the geomagnetic field waveform is 10 seconds.8 To use this geoelectric field time series when
a different earth model is applicable, it should be scaled with the appropriate benchmark
conductivity scaling factor β b .
Refer to the Benchmark Geomagnetic Disturbance Event Description white paper for details on the determination of the
reference geomagnetic field waveform: http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx.
8 The data file of the benchmark geomagnetic field waveform is available on the Related Information webpage for TPL-007-1:
http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx.
7
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Figure 3: Benchmark Geomagnetic Field Waveform
Red B n (Northward), Blue B e (Eastward)
Figure 4: Benchmark Geoelectric Field Waveform
E E (Eastward)
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Figure 5: Benchmark Geoelectric Field Waveform
E N (Northward)
Reference Geomagnetic Field Time Series or Waveform for the Supplemental GMD
Event9
The geomagnetic field measurement record of the March 13-14, 1989 GMD event, measured at
the NRCan Ottawa geomagnetic observatory, is the basis for the reference geomagnetic field
waveform to be used to calculate the GIC time series, GIC(t), required for transformer thermal
impact assessment for the supplemental GMD event. The supplemental GMD event waveform
differs from the benchmark GMD event waveform in that the supplemental GMD event
waveform has a local enhancement.
The geomagnetic latitude of the Ottawa geomagnetic observatory is 55°; therefore, the
amplitudes of the geomagnetic field measurement data were scaled up to the 60° reference
geomagnetic latitude (see Figure 6) such that the resulting peak geoelectric field amplitude
computed using the reference earth model was 12 V/km (see Figure7). The sampling rate for the
geomagnetic field waveform is 10 seconds. 10 To use this geoelectric field time series when a
different earth model is applicable, it should be scaled with the appropriate supplemental
conductivity scaling factor β s .
Refer to the Supplemental Geomagnetic Disturbance Event Description white paper for details on the determination of the
reference geomagnetic field waveform: http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspx.
10 The data file of the benchmark geomagnetic field waveform is available on the NERC GMD Task Force project webpage:
http://www.nerc.com/comm/PC/Pages/Geomagnetic-Disturbance-Task-Force-(GMDTF)-2013.aspx.
9
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4000
2000
Time (min)
200
400
600
800
1000
1200
1400
1600
1800
2000
Bx, By (nT)
0
-2000
-4000
-6000
-8000
-10000
Figure 6: Supplemental Geomagnetic Field Waveform
Red B N (Northward), Blue B E (Eastward)
12 V/km
Figure 7: Supplemental Geoelectric Field Waveform
Blue E N (Northward), Red E E (Eastward)
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TPL-007-4 – Supplemental Material
Attachment 1-CAN
Attachment 1-CAN provides an alternative that a Canadian entity may use in lieu of the
benchmark or supplemental GMD event(s) defined in Attachment 1 for performing GMD
Vulnerability Assessment(s).
A Canadian entity may use the provisions of Attachment 1-CAN if it has regionally specific
information that provides a technically justified means to re-define a 1-in-100 year GMD
planning event(s) within its planning area.
Information for the Alternative Methodology
GMD Vulnerability Assessment(s) require the use of geophysical and engineering models.
Canadian-specific data is available and growing. Ongoing research allows for more accurate
characterization of regional parameters used in these models. Such Canadian-specific data
includes geomagnetic field, earth conductivity, and geomagnetically induced current
measurements that can be used for modeling and simulation validation.
Information used to calculate geoelectric fields for the benchmark and supplemental GMD events
shall be clearly documented and technically justified. For example, the factors involved in the
calculation of geoelectric fields are geomagnetic field variations and an earth transfer
function(s). 1 Technically justified information used in modelling geomagnetic field variations may
include: technical documents produced by governmental entities such as Natural Resources
Canada; technical papers published in peer-reviewed journals; and data sets gathered using
sound scientific principles. An earth transfer function may rely on magnetotelluric measurements
or earth conductivity models.
Modeling assumptions shall also be clearly documented and technically justified. An entity may
use sensitivity analysis to identify how the assumptions affect the results.
A simplified model may be used to perform a GMD Vulnerability Assessment(s), as long as the
model is more conservative than a more detailed model.
When interpreting assessment results, the entity shall consider the maturity of the modeling,
toolset, and techniques applied.
Geomagnetic Disturbance Planning Events
The 1-in-100 year planning event shall be based on regionally specific data and technically
justifiable statistical analyses (e.g., extreme value theory) and applied to the benchmark and
supplemental GMD Vulnerability Assessment(s).
For the benchmark GMD Vulnerability Assessment(s), an entity shall consider the large-scale
spatial structure of the GMD event. For the supplemental GMD Vulnerability Assessment(s), an
The “earth transfer function” is the relationship between the electric fields and magnetic field variations at the surface of the
earth.
1
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TPL-007-4 – Supplemental Material
entity shall consider the small-scale spatial structure of the GMD event (e.g., using magnetometer
measurements or realistic electrojet calculations).
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).
Description of Current Draft
This is the firstfinal draft of proposed standard for formal 4510-day final ballotcomment period.
Completed Actions
Date
Standards Committee approved Standard Authorization Request
(SAR) for posting
February 20, 2019
SAR posted for comment
February 25 –
March 27, 2019
45-day formal comment period with ballot
August 30 –
September, 9 2019
Anticipated Actions
Date
45-day formal comment period with ballot
July – September
2019
45-day formal comment period with additional ballot
October –
December 2019
45-day formal comment period with second additional ballot
January – March
2020
10-day final ballot
April November
201920
Board adoption
MayFebruary 2020
Final Draft 1 of TPL-007-4
July November 2019
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Final Draft 1 of TPL-007-4
July November 2019
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
A. Introduction
1.
Title:
Events
Transmission System Planned Performance for Geomagnetic Disturbance
2.
Number:
TPL-007-4
3.
Purpose:
Establish requirements for Transmission system planned performance
during geomagnetic disturbance (GMD) events.
4.
Applicability:
4.1. Functional Entities:
4.1.1. Planning Coordinator with a planning area that includes a Facility or
Facilities specified in 4.2;
4.1.2. Transmission Planner with a planning area that includes a Facility or
Facilities specified in 4.2;
4.1.3. Transmission Owner who owns a Facility or Facilities specified in 4.2; and
4.1.4. Generator Owner who owns a Facility or Facilities specified in 4.2.
4.2. Facilities:
4.2.1. Facilities that include power transformer(s) with a high side, wyegrounded winding with terminal voltage greater than 200 kV.
5.
Effective Date: See Implementation Plan for TPL-007-4.
6.
Background: During a GMD event, geomagnetically-induced currents (GIC) may cause
transformer hot-spot heating or damage, loss of Reactive Power sources, increased
Reactive Power demand, and Misoperation(s), the combination of which may result in
voltage collapse and blackout.
B. Requirements and Measures
R1.
Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall
identify the individual and joint responsibilities of the Planning Coordinator and
Transmission Planner(s) in the Planning Coordinator’s planning area for maintaining
models, performing the study or studies needed to complete benchmark and
supplemental GMD Vulnerability Assessments, and implementing process(es) to
obtain GMD measurement data as specified in this standard. [Violation Risk Factor:
Lower] [Time Horizon: Long-term Planning]
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
M1. Each Planning Coordinator, in conjunction with its Transmission Planners, shall provide
documentation on roles and responsibilities, such as meeting minutes, agreements,
copies of procedures or protocols in effect between entities or between departments
of a vertically integrated system, or email correspondence that identifies an
agreement has been reached on individual and joint responsibilities for maintaining
models, performing the study or studies needed to complete benchmark and
supplemental GMD Vulnerability Assessments, and implementing process(es) to
obtain GMD measurement data in accordance with Requirement R1.
R2. Each responsible entity, as determined in Requirement R1, shall maintain System
models and GIC System models of the responsible entity’s planning area for
performing the study or studies needed to complete benchmark and supplemental
GMD Vulnerability Assessments. [Violation Risk Factor: High] [Time Horizon: Longterm Planning]
M2. Each responsible entity, as determined in Requirement R1, shall have evidence in
either electronic or hard copy format that it is maintaining System models and GIC
System models of the responsible entity’s planning area for performing the study or
studies needed to complete benchmark and supplemental GMD Vulnerability
Assessments.
R3. Each responsible entity, as determined in Requirement R1, shall have criteria for
acceptable System steady state voltage performance for its System during the GMD
events described in Attachment 1. [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]
M3. Each responsible entity, as determined in Requirement R1, shall have evidence, such
as electronic or hard copies of the criteria for acceptable System steady state voltage
performance for its System in accordance with Requirement R3.
Benchmark GMD Vulnerability Assessment(s)
R4. Each responsible entity, as determined in Requirement R1, shall complete a
benchmark GMD Vulnerability Assessment of the Near-Term Transmission Planning
Horizon at least once every 60 calendar months. This benchmark GMD Vulnerability
Assessment shall use a study or studies based on models identified in Requirement R2,
document assumptions, and document summarized results of the steady state
analysis. [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
4.1. The study or studies shall include the following conditions:
4.1.1. System On-Peak Load for at least one year within the Near-Term
Transmission Planning Horizon; and
4.1.2. System Off-Peak Load for at least one year within the Near-Term
Transmission Planning Horizon.
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
4.2. The study or studies shall be conducted based on the benchmark GMD event
described in Attachment 1 to determine whether the System meets the
performance requirements for the steady state planning benchmark GMD event
contained in Table 1.
4.3. The benchmark GMD Vulnerability Assessment shall be provided: (i) to the
responsible entity’s Reliability Coordinator, adjacent Planning Coordinators, and
adjacent Transmission Planners within 90 calendar days of completion, and (ii) to
any functional entity that submits a written request and has a reliability-related
need within 90 calendar days of receipt of such request or within 90 calendar
days of completion of the benchmark GMD Vulnerability Assessment, whichever
is later.
4.3.1. If a recipient of the benchmark GMD Vulnerability Assessment provides
documented comments on the results, the responsible entity shall
provide a documented response to that recipient within 90 calendar days
of receipt of those comments.
M4. Each responsible entity, as determined in Requirement R1, shall have dated evidence
such as electronic or hard copies of its benchmark GMD Vulnerability Assessment
meeting all of the requirements in Requirement R4. Each responsible entity, as
determined in Requirement R1, shall also provide evidence, such as email records,
web postings with an electronic notice of posting, or postal receipts showing recipient
and date, that it has distributed its benchmark GMD Vulnerability Assessment: (i) to
the responsible entity’s Reliability Coordinator, adjacent Planning Coordinators, and
adjacent Transmission Planners within 90 calendar days of completion, and (ii) to any
functional entity that submits a written request and has a reliability-related need
within 90 calendar days of receipt of such request or within 90 calendar days of
completion of the benchmark GMD Vulnerability Assessment, whichever is later, as
specified in Requirement R4. Each responsible entity, as determined in Requirement
R1, shall also provide evidence, such as email notices or postal receipts showing
recipient and date, that it has provided a documented response to comments received
on its benchmark GMD Vulnerability Assessment within 90 calendar days of receipt of
those comments in accordance with Requirement R4.
R5. Each responsible entity, as determined in Requirement R1, shall provide GIC flow
information to be used for the benchmark thermal impact assessment of transformers
specified in Requirement R6 to each Transmission Owner and Generator Owner that
owns an applicable Bulk Electric System (BES) power transformer in the planning area.
The GIC flow information shall include: [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]
5.1. The maximum effective GIC value for the worst case geoelectric field orientation
for the benchmark GMD event described in Attachment 1. This value shall be
provided to the Transmission Owner or Generator Owner that owns each
applicable BES power transformer in the planning area.
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July November 2019
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
5.2. The effective GIC time series, GIC(t), calculated using the benchmark GMD event
described in Attachment 1 in response to a written request from the
Transmission Owner or Generator Owner that owns an applicable BES power
transformer in the planning area. GIC(t) shall be provided within 90 calendar
days of receipt of the written request and after determination of the maximum
effective GIC value in Part 5.1.
M5. Each responsible entity, as determined in Requirement R1, shall provide evidence,
such as email records, web postings with an electronic notice of posting, or postal
receipts showing recipient and date, that it has provided the maximum effective GIC
values to the Transmission Owner and Generator Owner that owns each applicable
BES power transformer in the planning area as specified in Requirement R5, Part 5.1.
Each responsible entity, as determined in Requirement R1, shall also provide evidence,
such as email records, web postings with an electronic notice of posting, or postal
receipts showing recipient and date, that it has provided GIC(t) in response to a
written request from the Transmission Owner or Generator Owner that owns an
applicable BES power transformer in the planning area.
R6. Each Transmission Owner and Generator Owner shall conduct a benchmark thermal
impact assessment for its solely and jointly owned applicable BES power transformers
where the maximum effective GIC value provided in Requirement R5, Part 5.1, is 75 A
per phase or greater. The benchmark thermal impact assessment shall: [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]
6.1. Be based on the effective GIC flow information provided in Requirement R5;
6.2. Document assumptions used in the analysis;
6.3. Describe suggested actions and supporting analysis to mitigate the impact of
GICs, if any; and
6.4. Be performed and provided to the responsible entities, as determined in
Requirement R1, within 24 calendar months of receiving GIC flow information
specified in Requirement R5, Part 5.1.
M6. Each Transmission Owner and Generator Owner shall have evidence such as electronic
or hard copies of its benchmark thermal impact assessment for all of its solely and
jointly owned applicable BES power transformers where the maximum effective GIC
value provided in Requirement R5, Part 5.1, is 75 A per phase or greater, and shall
have evidence such as email records, web postings with an electronic notice of
posting, or postal receipts showing recipient and date, that it has provided its thermal
impact assessment to the responsible entities as specified in Requirement R6.
R7.
Each responsible entity, as determined in Requirement R1, that concludes through
the benchmark GMD Vulnerability Assessment conducted in Requirement R4 that
their System does not meet the performance requirements for the steady state
planning benchmark GMD event contained in Table 1, shall develop a Corrective
Final Draft 1 of TPL-007-4
July November 2019
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Action Plan (CAP) addressing how the performance requirements will be met. The CAP
shall: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
7.1. List System deficiencies and the associated actions needed to achieve required
System performance. Examples of such actions include:
•
Installation, modification, retirement, or removal of Transmission and
generation Facilities and any associated equipment.
•
Installation, modification, or removal of Protection Systems or Remedial
Action Schemes.
•
Use of Operating Procedures, specifying how long they will be needed as
part of the CAP.
•
Use of Demand-Side Management, new technologies, or other initiatives.
7.2. Be developed within one year of completion of the benchmark GMD
Vulnerability Assessment.
7.3. Include a timetable, subject to ERO approval for any extension sought under Part
7.4, for implementing the selected actions from Part 7.1. The timetable shall:
7.3.1. Specify implementation of non-hardware mitigation, if any, within two
years of development of the CAP; and
7.3.2. Specify implementation of hardware mitigation, if any, within four years
of development of the CAP.
7.4. Be submitted to the Compliance Enforcement Authority (CEA)ERO with a request
for extension of time if the responsible entity is unable to implement the CAP
within the timetable provided in Part 7.3. The submitted CAP shall document the
following:
7.4.1. Circumstances causing the delay for fully or partially implementing the
selected actions in Part 7.1 and how those circumstances are beyond the
control of the responsible entity;
7.4.2. Revisions to the selected actions in Part 7.1, if any, including utilization of
Operating Procedures, if applicable; and
7.4.3. Updated timetable for implementing the selected actions in Part 7.1.
7.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent
Planning Coordinator(s), adjacent Transmission Planner(s), and functional
entities referenced in the CAP within 90 calendar days of development or
revision, and (ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later.
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
7.5.1. If a recipient of the CAP provides documented comments on the CAP, the
responsible entity shall provide a documented response to that recipient
within 90 calendar days of receipt of those comments.
M7. Each responsible entity, as determined in Requirement R1, that concludes, through
the benchmark GMD Vulnerability Assessment conducted in Requirement R4, that the
responsible entity’s System does not meet the performance requirements for the
steady state planning benchmark GMD event contained in Table 1 shall have evidence
such as dated electronic or hard copies of its CAP including timetable for
implementing selected actions, as specified in Requirement R7. Each responsible
entity, as determined in Requirement R1, shall also provide evidence, such as email
records or postal receipts showing recipient and date, that it submitted a request for
extension to the CEAERO if the responsible entity is unable to implement the CAP
within the timetable provided in Part 7.3. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records, web postings with
an electronic notice of posting, or postal receipts showing recipient and date, that it
has distributed its CAP or relevant information, if any, (i) to the responsible entity’s
Reliability Coordinator, adjacent Planning Coordinator(s), adjacent Transmission
Planner(s), and functional entities referenced in the CAP within 90 calendar days of
development or revision, and (ii) to any functional entity that submits a written
request and has a reliability-related need within 90 calendar days of receipt of such
request or within 90 calendar days of development or revision, whichever is later as
specified in Requirement R7. Each responsible entity, as determined in Requirement
R1, shall also provide evidence, such as email notices or postal receipts showing
recipient and date, that it has provided a documented response to comments received
on its CAP within 90 calendar days of receipt of those comments, in accordance with
Requirement R7.
Supplemental GMD Vulnerability Assessment(s)
R8.
Each responsible entity, as determined in Requirement R1, shall complete a
supplemental GMD Vulnerability Assessment of the Near-Term Transmission Planning
Horizon at least once every 60 calendar months. This supplemental GMD Vulnerability
Assessment shall use a study or studies based on models identified in Requirement
R2, document assumptions, and document summarized results of the steady state
analysis. [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
8.1. The study or studies shall include the following conditions:
8.1.1. System On-Peak Load for at least one year within the Near-Term
Transmission Planning Horizon; and
8.1.2. System Off-Peak Load for at least one year within the Near-Term
Transmission Planning Horizon.
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
8.2. The study or studies shall be conducted based on the supplemental GMD event
described in Attachment 1 to determine whether the System meets the
performance requirements for the steady state planning supplemental GMD
event contained in Table 1.
8.3. The supplemental GMD Vulnerability Assessment shall be provided: (i) to the
responsible entity’s Reliability Coordinator, adjacent Planning Coordinators,
adjacent Transmission Planners within 90 calendar days of completion, and (ii) to
any functional entity that submits a written request and has a reliability-related
need within 90 calendar days of receipt of such request or within 90 calendar
days of completion of the supplemental GMD Vulnerability Assessment,
whichever is later.
8.3.1. If a recipient of the supplemental GMD Vulnerability Assessment
provides documented comments on the results, the responsible entity
shall provide a documented response to that recipient within 90 calendar
days of receipt of those comments.
M8. Each responsible entity, as determined in Requirement R1, shall have dated evidence
such as electronic or hard copies of its supplemental GMD Vulnerability Assessment
meeting all of the requirements in Requirement R8. Each responsible entity, as
determined in Requirement R1, shall also provide evidence, such as email records,
web postings with an electronic notice of posting, or postal receipts showing recipient
and date, that it has distributed its supplemental GMD Vulnerability Assessment: (i) to
the responsible entity’s Reliability Coordinator, adjacent Planning Coordinators,
adjacent Transmission Planners within 90 calendar days of completion, and (ii) to any
functional entity that submits a written request and has a reliability-related need
within 90 calendar days of receipt of such request or within 90 calendar days of
completion of the supplemental GMD Vulnerability Assessment, whichever is later, as
specified in Requirement R8. Each responsible entity, as determined in Requirement
R1, shall also provide evidence, such as email notices or postal receipts showing
recipient and date, that it has provided a documented response to comments
received on its supplemental GMD Vulnerability Assessment within 90 calendar days
of receipt of those comments in accordance with Requirement R8.
R9.
Each responsible entity, as determined in Requirement R1, shall provide GIC flow
information to be used for the supplemental thermal impact assessment of
transformers specified in Requirement R10 to each Transmission Owner and
Generator Owner that owns an applicable Bulk Electric System (BES) power
transformer in the planning area. The GIC flow information shall include: [Violation
Risk Factor: Medium] [Time Horizon: Long-term Planning]
9.1. The maximum effective GIC value for the worst case geoelectric field orientation
for the supplemental GMD event described in Attachment 1. This value shall be
provided to the Transmission Owner or Generator Owner that owns each
applicable BES power transformer in the planning area.
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July November 2019
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
9.2. The effective GIC time series, GIC(t), calculated using the supplemental GMD
event described in Attachment 1 in response to a written request from the
Transmission Owner or Generator Owner that owns an applicable BES power
transformer in the planning area. GIC(t) shall be provided within 90 calendar
days of receipt of the written request and after determination of the maximum
effective GIC value in Part 9.1.
M9. Each responsible entity, as determined in Requirement R1, shall provide evidence,
such as email records, web postings with an electronic notice of posting, or postal
receipts showing recipient and date, that it has provided the maximum effective GIC
values to the Transmission Owner and Generator Owner that owns each applicable
BES power transformer in the planning area as specified in Requirement R9, Part 9.1.
Each responsible entity, as determined in Requirement R1, shall also provide
evidence, such as email records, web postings with an electronic notice of posting, or
postal receipts showing recipient and date, that it has provided GIC(t) in response to a
written request from the Transmission Owner or Generator Owner that owns an
applicable BES power transformer in the planning area.
R10. Each Transmission Owner and Generator Owner shall conduct a supplemental
thermal impact assessment for its solely and jointly owned applicable BES power
transformers where the maximum effective GIC value provided in Requirement R9,
Part 9.1, is 85 A per phase or greater. The supplemental thermal impact assessment
shall: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
10.1. Be based on the effective GIC flow information provided in Requirement R9;
10.2. Document assumptions used in the analysis;
10.3. Describe suggested actions and supporting analysis to mitigate the impact of
GICs, if any; and
10.4. Be performed and provided to the responsible entities, as determined in
Requirement R1, within 24 calendar months of receiving GIC flow information
specified in Requirement R9, Part 9.1.
M10. Each Transmission Owner and Generator Owner shall have evidence such as
electronic or hard copies of its supplemental thermal impact assessment for all of its
solely and jointly owned applicable BES power transformers where the maximum
effective GIC value provided in Requirement R9, Part 9.1, is 85 A per phase or greater,
and shall have evidence such as email records, web postings with an electronic notice
of posting, or postal receipts showing recipient and date, that it has provided its
supplemental thermal impact assessment to the responsible entities as specified in
Requirement R10.
R11. Each responsible entity, as determined in Requirement R1, that concludes through
the supplemental GMD Vulnerability Assessment conducted in Requirement R8 that
their System does not meet the performance requirements for the steady state
planning supplemental GMD event contained in Table 1, shall develop a Corrective
Final Draft 1 of TPL-007-4
July November 2019
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Action Plan (CAP) addressing how the performance requirements will be met. The CAP
shall: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
11.1. List System deficiencies and the associated actions needed to achieve required
System performance. Examples of such actions include:
•
Installation, modification, retirement, or removal of Transmission and
generation Facilities and any associated equipment.
•
Installation, modification, or removal of Protection Systems or Remedial
Action Schemes.
•
Use of Operating Procedures, specifying how long they will be needed as
part of the CAP.
•
Use of Demand-Side Management, new technologies, or other initiatives.
11.2. Be developed within one year of completion of the supplemental GMD
Vulnerability Assessment.
11.3. Include a timetable, subject to ERO approval for any extension sought under Part
11.4, for implementing the selected actions from Part 11.1. The timetable shall:
11.3.1. Specify implementation of non-hardware mitigation, if any, within two
years of development of the CAP; and
11.3.2. Specify implementation of hardware mitigation, if any, within four years
of development of the CAP.
11.4. Be submitted to the CEAERO with a request for extension of time if the
responsible entity is unable to implement the CAP within the timetable provided
in Part 11.3. The submitted CAP shall document the following:
11.4.1. Circumstances causing the delay for fully or partially implementing the
selected actions in Part 11.1 and how those circumstances are beyond
the control of the responsible entity;
11.4.2. Revisions to the selected actions in Part 11.1, if any, including utilization
of Operating Procedures, if applicable; and
11.4.3. Updated timetable for implementing the selected actions in Part 11.1.
11.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent
Planning Coordinator(s), adjacent Transmission Planner(s), and functional
entities referenced in the CAP within 90 calendar days of development or
revision, and (ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later.
11.5.1. If a recipient of the CAP provides documented comments on the CAP, the
responsible entity shall provide a documented response to that recipient
within 90 calendar days of receipt of those comments.
Final Draft 1 of TPL-007-4
July November 2019
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
M11. Each responsible entity, as determined in Requirement R1, that concludes, through
the supplemental GMD Vulnerability Assessment conducted in Requirement R8, that
the responsible entity’s System does not meet the performance requirements for the
steady state planning supplemental GMD event contained in Table 1 shall have
evidence such as dated electronic or hard copies of its CAP including timetable for
implementing selected actions, as specified in Requirement R11. Each responsible
entity, as determined in Requirement R1, shall also provide evidence, such as email
records or postal receipts showing recipient and date, that it submitted a request for
extension to the CEAERO if the responsible entity is unable to implement the CAP
within the timetable provided in Part 11.3. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records, web postings with
an electronic notice of posting, or postal receipts showing recipient and date, that it
has distributed its CAP or relevant information, if any, (i) to the responsible entity’s
Reliability Coordinator, adjacent Planning Coordinator(s), adjacent Transmission
Planner(s), and functional entities referenced in the CAP within 90 calendar days of
development or revision, and (ii) to any functional entity that submits a written
request and has a reliability-related need within 90 calendar days of receipt of such
request or within 90 calendar days of development or revision, whichever is later as
specified in Requirement R11. Each responsible entity, as determined in Requirement
R1, shall also provide evidence, such as email notices or postal receipts showing
recipient and date, that it has provided a documented response to comments received
on its CAP within 90 calendar days of receipt of those comments, in accordance with
Requirement R11.
GMD Measurement Data Processes
R12. Each responsible entity, as determined in Requirement R1, shall implement a process
to obtain GIC monitor data from at least one GIC monitor located in the Planning
Coordinator’s planning area or other part of the system included in the Planning
Coordinator’s GIC System model. [Violation Risk Factor: Lower] [Time Horizon: Longterm Planning]
M12. Each responsible entity, as determined in Requirement R1, shall have evidence such
as electronic or hard copies of its GIC monitor location(s) and documentation of its
process to obtain GIC monitor data in accordance with Requirement R12.
R13. Each responsible entity, as determined in Requirement R1, shall implement a process
to obtain geomagnetic field data for its Planning Coordinator’s planning area.
[Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
M13. Each responsible entity, as determined in Requirement R1, shall have evidence such
as electronic or hard copies of its process to obtain geomagnetic field data for its
Planning Coordinator’s planning area in accordance with Requirement R13.
C. Compliance
1.
Compliance Monitoring Process
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July November 2019
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
Authority may ask an entity to provide other evidence to show that it was
compliant for the full-time period since the last audit.
The applicable entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
•
For Requirements R1, R2, R3, R5, R6, R9, and R10, each responsible entity
shall retain documentation as evidence for five years.
•
For Requirements R4 and R8, each responsible entity shall retain
documentation of the current GMD Vulnerability Assessment and the
preceding GMD Vulnerability Assessment.
•
For Requirement R7 and R11, each responsible entity shall retain
documentation as evidence for five years or until all actions in the
Corrective Action Plan are completed, whichever is later.
•
For Requirements R12 and R13, each responsible entity shall retain
documentation as evidence for three years.
1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.
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July November 2019
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Table 1: Steady State Planning GMD Event
Steady State:
a. Voltage collapse, Cascading and uncontrolled islanding shall not occur.
b. Generation loss is acceptable as a consequence of the steady state planning GMD events.
c. Planned System adjustments such as Transmission configuration changes and re-dispatch of generation are allowed if such
adjustments are executable within the time duration applicable to the Facility Ratings.
Category
Initial Condition
Event
Interruption of
Firm
Transmission
Service Allowed
Load Loss
Allowed
Benchmark GMD
Event – GMD
Event with
Outages
1. System as may be
postured in response
to space weather
information1, and then
2. GMD event2
Reactive Power compensation devices
and other Transmission Facilities
removed as a result of Protection
System operation or Misoperation due
to harmonics during the GMD event
Yes3
Yes3
Supplemental
GMD Event – GMD
Event with
Outages
1. System as may be
postured in response
to space weather
information1, and then
2. GMD event2
Reactive Power compensation devices
and other Transmission Facilities
removed as a result of Protection
System operation or Misoperation due
to harmonics during the GMD event
Yes
Yes
Table 1: Steady State Performance Footnotes
1. The System condition for GMD planning may include adjustments to posture the System that are executable in response to
space weather information.
2. The GMD conditions for the benchmark and supplemental planning events are described in Attachment 1.
3. Load loss as a result of manual or automatic Load shedding (e.g., UVLS) and/or curtailment of Firm Transmission Service may
be used to meet BES performance requirements during studied GMD conditions. The likelihood and magnitude of Load loss or
curtailment of Firm Transmission Service should be minimized.
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
Lower VSL
R1.
R2.
Final Draft 1 of TPL-007-4
July November 2019
N/A
N/A
Violation Severity Levels
Moderate VSL
N/A
N/A
High VSL
Severe VSL
N/A
The Planning Coordinator, in
conjunction with its
Transmission Planner(s),
failed to determine and
identify individual or joint
responsibilities of the
Planning Coordinator and
Transmission Planner(s) in
the Planning Coordinator’s
planning area for
maintaining models,
performing the study or
studies needed to complete
benchmark and
supplemental GMD
Vulnerability Assessments,
and implementing
process(es) to obtain GMD
measurement data as
specified in this standard.
The responsible entity did
not maintain either System
models or GIC System
models of the responsible
entity’s planning area for
performing the studies
The responsible entity did
not maintain both System
models and GIC System
models of the responsible
entity’s planning area for
performing the studies
Page 15 of 40
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
needed to complete
benchmark and
supplemental GMD
Vulnerability Assessments.
R3.
R4.
N/A
N/A
N/A
The responsible entity
completed a benchmark
GMD Vulnerability
Assessment, but it was more
than 60 calendar months
and less than or equal to 64
calendar months since the
last benchmark GMD
Vulnerability Assessment.
The responsible entity’s
completed benchmark GMD
Vulnerability Assessment
failed to satisfy one of the
elements listed in
Requirement R4, Parts 4.1
through 4.3;
OR
The responsible entity
completed a benchmark
GMD Vulnerability
Assessment, but it was more
than 64 calendar months
and less than or equal to 68
calendar months since the
The responsible entity’s
completed benchmark GMD
Vulnerability Assessment
failed to satisfy two of the
elements listed in
Requirement R4, Parts 4.1
through 4.3;
OR
The responsible entity
completed a benchmark
GMD Vulnerability
Assessment, but it was more
than 68 calendar months
and less than or equal to 72
calendar months since the
Final Draft 1 of TPL-007-4
July November 2019
Severe VSL
needed to complete
benchmark and
supplemental GMD
Vulnerability Assessments.
The responsible entity did
not have criteria for
acceptable System steady
state voltage performance
for its System during the
GMD events described in
Attachment 1 as required.
The responsible entity’s
completed benchmark GMD
Vulnerability Assessment
failed to satisfy three of the
elements listed in
Requirement R4, Parts 4.1
through 4.3;
OR
The responsible entity
completed a benchmark
GMD Vulnerability
Assessment, but it was more
than 72 calendar months
since the last benchmark
Page 16 of 40
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
R5.
R6.
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
last benchmark GMD
Vulnerability Assessment.
last benchmark GMD
Vulnerability Assessment.
GMD Vulnerability
Assessment;
OR
The responsible entity does
not have a completed
benchmark GMD
Vulnerability Assessment.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 90
calendar days and less than
or equal to 100 calendar
days after receipt of a
written request.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 100
calendar days and less than
or equal to 110 calendar
days after receipt of a
written request.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 110
calendar days after receipt
of a written request.
The responsible entity did
not provide the maximum
effective GIC value to the
Transmission Owner and
Generator Owner that owns
each applicable BES power
transformer in the planning
area;
OR
The responsible entity did
not provide the effective GIC
time series, GIC(t), upon
written request.
The responsible entity failed
to conduct a benchmark
thermal impact assessment
for 5% or less or one of its
solely owned and jointly
owned applicable BES power
The responsible entity failed
to conduct a benchmark
thermal impact assessment
for more than 5% up to (and
including) 10% or two of its
solely owned and jointly
The responsible entity failed
to conduct a benchmark
thermal impact assessment
for more than 10% up to
(and including) 15% or three
of its solely owned and
The responsible entity failed
to conduct a benchmark
thermal impact assessment
for more than 15% or more
than three of its solely
owned and jointly owned
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July November 2019
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase;
OR
The responsible entity
conducted a benchmark
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase
but did so more than 24
calendar months and less
than or equal to 26 calendar
months of receiving GIC flow
information specified in
Requirement R5, Part 5.1.
owned applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase;
OR
The responsible entity
conducted a benchmark
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase
but did so more than 26
calendar months and less
than or equal to 28 calendar
months of receiving GIC flow
information specified in
Requirement R5, Part 5.1;
OR
The responsible entity failed
to include one of the
jointly owned applicable BES
power transformers
(whichever is greater) where
the maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase;
OR
The responsible entity
conducted a benchmark
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase
but did so more than 28
calendar months and less
than or equal to 30 calendar
months of receiving GIC flow
information specified in
Requirement R5, Part 5.1;
OR
The responsible entity failed
to include two of the
applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase;
OR
The responsible entity
conducted a benchmark
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase
but did so more than 30
calendar months of receiving
GIC flow information
specified in Requirement R5,
Part 5.1;
OR
The responsible entity failed
to include three of the
required elements as listed
Final Draft 1 of TPL-007-4
July November 2019
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
required elements as listed
in Requirement R6, Parts 6.1
through 6.3.
required elements as listed
in Requirement R6, Parts 6.1
through 6.3.
in Requirement R6, Parts 6.1
through 6.3.
The responsible entity’s
Corrective Action Plan failed
to comply with one of the
elements in Requirement
R7, Parts 7.1 through 7.5.
The responsible entity’s
Corrective Action Plan failed
to comply with two of the
elements in Requirement R7,
Parts 7.1 through 7.5.
The responsible entity’s
Corrective Action Plan failed
to comply with three of the
elements in Requirement
R7, Parts 7.1 through 7.5.
The responsible entity’s
Corrective Action Plan failed
to comply with four or more
of the elements in
Requirement R7, Parts 7.1
through 7.5;
OR
The responsible entity did
not develop a Corrective
Action Plan as required by
Requirement R7.
The responsible entity
completed a supplemental
GMD Vulnerability
Assessment, but it was more
than 60 calendar months
and less than or equal to 64
calendar months since the
last supplemental GMD
Vulnerability Assessment.
The responsible entity’s
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
one of the elements listed in
Requirement R8, Parts 8.1
through 8.3;
OR
The responsible entity
completed a supplemental
GMD Vulnerability
Assessment, but it was more
The responsible entity’s
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
two of the elements listed in
Requirement R8, Parts 8.1
through 8.3;
OR
The responsible entity
completed a supplemental
GMD Vulnerability
Assessment, but it was more
The responsible entity’s
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
three of the elements listed
in Requirement R8, Parts 8.1
through 8.3;
OR
The responsible entity
completed a supplemental
GMD Vulnerability
Assessment, but it was more
R7.
R8.
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July November 2019
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
R9.
R10.
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
than 64 calendar months
and less than or equal to 68
calendar months since the
last supplemental GMD
Vulnerability Assessment.
than 68 calendar months
and less than or equal to 72
calendar months since the
last supplemental GMD
Vulnerability Assessment.
than 72 calendar months
since the last supplemental
GMD Vulnerability
Assessment;
OR
The responsible entity does
not have a completed
supplemental GMD
Vulnerability Assessment.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 90
calendar days and less than
or equal to 100 calendar
days after receipt of a
written request.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 100
calendar days and less than
or equal to 110 calendar
days after receipt of a
written request.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written request,
but did so more than 110
calendar days after receipt
of a written request.
The responsible entity did
not provide the maximum
effective GIC value to the
Transmission Owner and
Generator Owner that owns
each applicable BES power
transformer in the planning
area;
OR
The responsible entity did
not provide the effective GIC
time series, GIC(t), upon
written request.
The responsible entity failed
to conduct a supplemental
thermal impact assessment
for 5% or less or one of its
The responsible entity failed
to conduct a supplemental
thermal impact assessment
for more than 5% up to (and
The responsible entity failed
to conduct a supplemental
thermal impact assessment
for more than 10% up to
The responsible entity failed
to conduct a supplemental
thermal impact assessment
for more than 15% or more
Final Draft 1 of TPL-007-4
July November 2019
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
solely owned and jointly
owned applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase;
OR
The responsible entity
conducted a supplemental
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase
but did so more than 24
calendar months and less
than or equal to 26 calendar
months of receiving GIC flow
information specified in
Requirement R9, Part 9.1.
including) 10% or two of its
solely owned and jointly
owned applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase;
OR
The responsible entity
conducted a supplemental
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase
but did so more than 26
calendar months and less
than or equal to 28 calendar
months of receiving GIC flow
information specified in
Requirement R9, Part 9.1
OR
(and including) 15% or three
of its solely owned and
jointly owned applicable BES
power transformers
(whichever is greater) where
the maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase;
OR
The responsible entity
conducted a supplemental
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase
but did so more than 28
calendar months and less
than or equal to 30 calendar
months of receiving GIC flow
information specified in
Requirement R9, Part 9.1;
OR
than three of its solely
owned and jointly owned
applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase;
OR
The responsible entity
conducted a supplemental
thermal impact assessment
for its solely owned and
jointly owned applicable BES
power transformers where
the maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase
but did so more than 30
calendar months of receiving
GIC flow information
specified in Requirement R9,
Part 9.1;
OR
Final Draft 1 of TPL-007-4
July November 2019
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
R11.
Violation Severity Levels
Lower VSL
The responsible entity’s
Corrective Action Plan failed
to comply with one of the
elements in Requirement
R11, Parts 11.1 through
11.5.
Final Draft 1 of TPL-007-4
July November 2019
Moderate VSL
High VSL
Severe VSL
The responsible entity failed
to include one of the
required elements as listed
in Requirement R10, Parts
10.1 through 10.3.
The responsible entity failed
to include two of the
required elements as listed
in Requirement R10, Parts
10.1 through 10.3.
The responsible entity failed
to include three of the
required elements as listed
in Requirement R10, Parts
10.1 through 10.3.
The responsible entity’s
Corrective Action Plan failed
to comply with three of the
elements in Requirement
R11, Parts 11.1 through
11.5.
The responsible entity’s
Corrective Action Plan failed
to comply with four or more
of the elements in
Requirement R11, Parts 11.1
through 11.5;
OR
The responsible entity did
not develop a Corrective
Action Plan as required by
Requirement R11.
The responsible entity’s
Corrective Action Plan failed
to comply with two of the
elements in Requirement
R11, Parts 11.1 through
11.5.
Page 22 of 40
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
Violation Severity Levels
Lower VSL
R12.
R13.
Final Draft 1 of TPL-007-4
July November 2019
N/A
N/A
Moderate VSL
N/A
N/A
High VSL
N/A
N/A
Severe VSL
The responsible entity did
not implement a process to
obtain GIC monitor data
from at least one GIC
monitor located in the
Planning Coordinator’s
planning area or other part
of the system included in the
Planning Coordinator’s GIC
System Model.
The responsible entity did
not implement a process to
obtain geomagnetic field
data for its Planning
Coordinator’s planning area.
Page 23 of 40
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
D. Regional Variances
D.A. Regional Variance for Canadian Jurisdictions
This Variance shall be applicable in those Canadian jurisdictions where the Variance
has been approved for use by the applicable governmental authority or has otherwise
become effective in the jurisdiction.
This variance replaces all references to “Attachment 1” in the standard with
“Attachment 1 or Attachment 1-CAN.”
In addition, this Variance replaces Requirement R7, Part 7.3 through Part 7.5 and
Requirement R11, Part 11.3 through Part 11.5 with the following:
D.A.7.3. Include a timetable, subject to revision by the responsible entity in Part
D.A.7.4, for implementing the selected actions from Part 7.1. The timetable
shall:
D.A.7.3.1. Specify implementation of non-hardware mitigation, if any, within
two years of the later of the development of the CAP or receipt of
regulatory approvals, if required; and
D.A.7.3.2. Specify implementation of hardware mitigation, if any, within four
years of the later of the development of the CAP or receipt of
regulatory approvals, if required.
D.A.7.4. Be revised if the responsible entity is unable to implement the CAP within
the timetable for implementation provided in Part D.A.7.3. The revised CAP
shall document the following:
D.A.7.4.1 Circumstances causing the delay for fully or partially implementing the
selected actions in Part 7.1 and how those circumstances are beyond
the control of the responsible entity;
D.A.7.4.2 Revisions to the selected actions in Part 7.1, if any, including utilization
of Operating Procedures if applicable; and
D.A.7.4.3 Updated timetable for implementing the selected actions in Part 7.1.
D.A.7.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent
Planning Coordinator(s), adjacent Transmission Planner(s), and functional
entities referenced in the CAP within 90 calendar days of development or
revision, (ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later, and
(iii) to the Compliance Enforcement Authority or Applicable Governmental
Authority when revised under D.A.7.4 within 90 calendar days of revision.
D.A.7.5.1 If a recipient of the CAP provides documented comments on the CAP,
the responsible entity shall provide a documented response to that
recipient within 90 calendar days of receipt of those comments.
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
D.A.M.7. Each responsible entity, as determined in Requirement R1, that concludes,
through the benchmark GMD Vulnerability Assessment conducted in
Requirement R4, that the responsible entity’s System does not meet the
performance requirements for the steady state planning benchmark GMD
event contained in Table 1 shall have evidence such as dated electronic or
hard copies of its CAP including timetable for implementing selected actions,
as specified in Requirement R7. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records or postal
receipts showing recipient and date, that it has revised its CAP if situations
beyond the responsible entity's control prevent implementation of the CAP
within the timetable specified. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records, web
postings with an electronic notice of posting, or postal receipts showing
recipient and date, that it has distributed its CAP or relevant information, if
any, (i) to the responsible entity’s Reliability Coordinator, adjacent Planning
Coordinator(s), adjacent Transmission Planner(s), and functional entities
referenced in the CAP within 90 calendar days of development or revision,
(ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later as
specified in Requirement R7, and (iii) to the Compliance Enforcement
Authority or Applicable Governmental Authority when revised under D.A.7.4
within 90 calendar days of revision. Each responsible entity, as determined
in Requirement R1, shall also provide evidence, such as email notices or
postal receipts showing recipient and date, that it has provided a
documented response to comments received on its CAP within 90 calendar
days of receipt of those comments, in accordance with Requirement R7.
D.A.11.3.Include a timetable, subject to revision by the responsible entity in Part
D.A.11.4, for implementing the selected actions from Part 11.1. The
timetable shall:
D.A.11.3.1. Specify implementation of non-hardware mitigation, if any, within
two years of the later of the development of the CAP or receipt of
regulatory approvals, if required; and
D.A.11.3.2. Specify implementation of hardware mitigation, if any, within four
years of the later of the development of the CAP or receipt of
regulatory approvals, if required.
D.A.11.4. Be revised if the responsible entity is unable to implement the CAP within
the timetable for implementation provided in Part D.A.11.3. The revised CAP
shall document the following:
D.A.11.4.1 Circumstances causing the delay for fully or partially implementing
the selected actions in Part 11.1 and how those circumstances are
beyond the control of the responsible entity;
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
D.A.11.4.2 Revisions to the selected actions in Part 11.1, if any, including
utilization of Operating Procedures if applicable; and
D.A.11.4.3 Updated timetable for implementing the selected actions in Part
11.1.
D.A.11.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent
Planning Coordinator(s), adjacent Transmission Planner(s), and functional
entities referenced in the CAP within 90 calendar days of development or
revision, (ii) to any functional entity that submits a written request and has
a reliability-related need within 90 calendar days of receipt of such request
or within 90 calendar days of development or revision, whichever is later,
and (iii) to the Compliance Enforcement Authority or Applicable
Governmental Authority when revised under D.A.11.4 within 90 calendar
days of revision.
D.A.11.5.1. If a recipient of the CAP provides documented comments on the
CAP, the responsible entity shall provide a documented response to
that recipient within 90 calendar days of receipt of those comments.
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July November 2019
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
D.A.M.11. Each responsible entity, as determined in Requirement R1, that concludes,
through the supplemental GMD Vulnerability Assessment conducted in
Requirement R8, that the responsible entity’s System does not meet the
performance requirements for the steady state planning supplemental GMD
event contained in Table 1 shall have evidence such as dated electronic or
hard copies of its CAP including timetable for implementing selected actions,
as specified in Requirement R11. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records or postal
receipts showing recipient and date, that it has revised its CAP if situations
beyond the responsible entity's control prevent implementation of the CAP
within the timetable specified. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records, web
postings with an electronic notice of posting, or postal receipts showing
recipient and date, that it has distributed its CAP or relevant information, if
any, (i) to the responsible entity’s Reliability Coordinator, adjacent Planning
Coordinator(s), adjacent Transmission Planner(s), and functional entities
referenced in the CAP within 90 calendar days of development or revision,
(ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later as
specified in Requirement R11, and (iii) to the Compliance Enforcement
Authority or Applicable Governmental Authority when revised under
D.A.11.4 within 90 calendar days of revision. Each responsible entity, as
determined in Requirement R1, shall also provide evidence, such as email
notices or postal receipts showing recipient and date, that it has provided a
documented response to comments received on its CAP within 90 calendar
days of receipt of those comments, in accordance with Requirement R11.
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
E. Associated Documents
Attachment 1
Attachment 1-CAN
Final Draft 1 of TPL-007-4
July November 2019
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Version History
Version
1
Date
Action
December 17, 2014 Adopted by the NERC Board of Trustees
Change
Tracking
New
Revised to
respond to
directives in FERC
Order No. 830.
2
November 9, 2017
Adopted by the NERC Board of Trustees
2
November 25, 2018
FERC Order issued approving TPL-007-2.
Docket No. RM18-8-000
3
February 7, 2019
Adopted by the NERC Board of Trustees
Canadian
Variance
Adopted by the NERC Board of Trustees
Revised to
respond to
directives in FERC
Order. 851
4
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TBD
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Attachment 1
Calculating Geoelectric Fields for the Benchmark and Supplemental GMD Events
The benchmark GMD event 1 defines the geoelectric field values used to compute GIC flows that
are needed to conduct a benchmark GMD Vulnerability Assessment. It is composed of the
following elements: (1) a reference peak geoelectric field amplitude of 8 V/km derived from
statistical analysis of historical magnetometer data; (2) scaling factors to account for local
geomagnetic latitude; (3) scaling factors to account for local earth conductivity; and (4) a
reference geomagnetic field time series or waveform to facilitate time-domain analysis of GMD
impact on equipment.
The supplemental GMD event is composed of similar elements as described above, except (1) the
reference peak geoelectric field amplitude is 12 V/km over a localized area; and (2) the
geomagnetic field time series or waveform includes a local enhancement in the waveform.2
The regional geoelectric field peak amplitude used in GMD Vulnerability Assessment, E peak , can
be obtained from the reference geoelectric field value of 8 V/km for the benchmark GMD event
(1) or 12 V/km for the supplemental GMD event (2) using the following relationships:
𝐸𝐸𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝 = 8 × 𝛼𝛼 × 𝛽𝛽 𝑏𝑏 (𝑉𝑉 ⁄𝑘𝑘𝑘𝑘)
𝐸𝐸𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝 = 12 × 𝛼𝛼 × 𝛽𝛽 𝑠𝑠 (𝑉𝑉 ⁄𝑘𝑘𝑘𝑘)
(1)
(2)
where, α is the scaling factor to account for local geomagnetic latitude, and β is a scaling factor
to account for the local earth conductivity structure. Subscripts b and s for the β scaling factor
denote association with the benchmark or supplemental GMD events, respectively.
Scaling the Geomagnetic Field
The benchmark and supplemental GMD events are defined for geomagnetic latitude of 60° and
must be scaled to account for regional differences based on geomagnetic latitude. Table 2
provides a scaling factor correlating peak geoelectric field to geomagnetic latitude. Alternatively,
the scaling factor α is computed with the empirical expression:
𝛼𝛼 = 0.001 × 𝑒𝑒 (0.115×𝐿𝐿)
(3)
where, L is the geomagnetic latitude in degrees and 0.1 ≤ α ≤ 1.
The Benchmark Geomagnetic Disturbance Event Description, May 2016 is available on the Related Information webpage for
TPL-007-1: http://www.nerc.com/pa/Stand/TPL0071RD/Benchmark_clean_May12_complete.pdf.
2 The extent of local enhancements is on the order of 100 km in North-South (latitude) direction but longer in East-West
(longitude) direction. The local enhancement in the geomagnetic field occurs over the time period of 2-5 minutes. Additional
information is available in the Supplemental Geomagnetic Disturbance Event Description, October 2017 white paper on the
Project 2013-03 Geomagnetic Disturbance Mitigation project webpage: http://www.nerc.com/pa/Stand/Pages/Project-201303-Geomagnetic-Disturbance-Mitigation.aspx.
1
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
For large planning areas that cover more than one scaling factor from Table 2, the GMD
Vulnerability Assessment should be based on a peak geoelectric field that is:
•
calculated by using the most conservative (largest) value for α; or
•
calculated assuming a non-uniform or piecewise uniform geomagnetic field.
Table 2: Geomagnetic Field Scaling Factors for the
Benchmark and Supplemental GMD
Events
Geomagnetic Latitude
(Degrees)
Scaling Factor1
(α)
≤ 40
0.10
45
0.2
50
0.3
54
0.5
56
0.6
57
0.7
58
0.8
59
0.9
≥ 60
1.0
Scaling the Geoelectric Field
The benchmark GMD event is defined for the reference Quebec earth model described in Table
4. The peak geoelectric field, E peak , used in a GMD Vulnerability Assessment may be obtained by
either:
•
Calculating the geoelectric field for the ground conductivity in the planning area and the
reference geomagnetic field time series scaled according to geomagnetic latitude, using
a procedure such as the plane wave method described in the NERC GMD Task Force GIC
Application Guide; 3 or
•
Using the earth conductivity scaling factor β from Table 3 that correlates to the ground
conductivity map in Figure 1 or Figure 2. Along with the scaling factor α from equation
(3) or Table 2, β is applied to the reference geoelectric field using equation (1 or 2, as
applicable) to obtain the regional geoelectric field peak amplitude E peak to be used in
GMD Vulnerability Assessments. When a ground conductivity model is not available, the
planningresponsible entity should use the largest β factor of adjacent physiographic
regions or a technically justified value.
Available at the NERC GMD Task Force project webpage: http://www.nerc.com/comm/PC/Pages/Geomagnetic-DisturbanceTask-Force-(GMDTF)-2013.aspx.
3
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
The earth models used to calculate Table 3 for the United States were obtained from publicly
available information published on the U. S. Geological Survey website. 4 The models used to
calculate Table 3 for Canada were obtained from Natural Resources Canada (NRCan) and reflect
the average structure for large regions. A planner can also use specific earth model(s) with
documented justification and the reference geomagnetic field time series to calculate the β
factor(s) as follows:
𝛽𝛽𝑏𝑏 = 𝐸𝐸 ⁄8 for the benchmark GMD event
(4)
𝛽𝛽𝑠𝑠 = 𝐸𝐸 ⁄12 for the supplemental GMD
(5)
where, E is the absolute value of peak geoelectric in V/km obtained from the technically justified
earth model and the reference geomagnetic field time series.
For large planning areas that span more than one β scaling factor, the most conservative (largest)
value for β may be used in determining the peak geoelectric field to obtain conservative results.
Alternatively, a planner could perform analysis using a non-uniform or piecewise uniform
geoelectric field.
Applying the Localized Peak Geoelectric Field in the Supplemental GMD Event
The peak geoelectric field of the supplemental GMD event occurs in a localized area.5 Planners
have flexibility to determine how to apply the localized peak geoelectric field over the planning
area in performing GIC calculations. Examples of approaches are:
•
Apply the peak geoelectric field (12 V/km scaled to the planning area) over the entire
planning area;
•
Apply a spatially limited (12 V/km scaled to the planning area) peak geoelectric field (e.g.,
100 km in North-South latitude direction and 500 km in East-West longitude direction)
over a portion(s) of the system, and apply the benchmark GMD event over the rest of the
system; or
•
Other methods to adjust the benchmark GMD event analysis to account for the localized
geoelectric field enhancement of the supplemental GMD event.
Available at http://geomag.usgs.gov/conductivity/.
See the Supplemental Geomagnetic Disturbance Description white paper located on the Project 2013-03 Geomagnetic
Disturbance Mitigation project webpage: http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspx.
4
5
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
FL-1
Figure 1: Physiographic Regions of the Continental United States 6
Figure 2: Physiographic Regions of Canada
6
Additional map detail is available at the U.S. Geological Survey: http://geomag.usgs.gov/.
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Table 3: Geoelectric Field Scaling Factors
Earth model
Scaling Factor
Benchmark Event
(β b )
Scaling Factor
Supplemental
Event
(β s )
AK1A
0.56
0.51
AK1B
0.56
0.51
AP1
0.33
0.30
AP2
0.82
0.78
BR1
0.22
0.22
CL1
0.76
0.73
CO1
0.27
0.25
CP1
0.81
0.77
CP2
0.95
0.86
FL1
0.76
0.73
CS1
0.41
0.37
IP1
0.94
0.90
IP2
0.28
0.25
IP3
0.93
0.90
IP4
0.41
0.35
NE1
0.81
0.77
PB1
0.62
0.55
PB2
0.46
0.39
PT1
1.17
1.19
SL1
0.53
0.49
SU1
0.93
0.90
BOU
0.28
0.24
FBK
0.56
0.56
PRU
0.21
0.22
BC
0.67
0.62
PRAIRIES
0.96
0.88
SHIELD
1.0
1.0
ATLANTIC
0.79
0.76
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Scaling factors in Table 3 are dependent upon the frequency content of the reference storm.
Consequently, the benchmark GMD event and the supplemental GMD event may produce
different scaling factors for a given earth model.
Table 4: Reference Earth Model (Quebec)
Layer Thickness (km)
Resistivity (Ω-m)
15
20,000
10
200
125
1,000
200
100
∞
3
Reference Geomagnetic Field Time Series or Waveform for the Benchmark GMD
Event7
The geomagnetic field measurement record of the March 13-14 1989 GMD event, measured at
the NRCan Ottawa geomagnetic observatory, is the basis for the reference geomagnetic field
waveform to be used to calculate the GIC time series, GIC(t), required for transformer thermal
impact assessment.
The geomagnetic latitude of the Ottawa geomagnetic observatory is 55°; therefore, the
amplitudes of the geomagnetic field measurement data were scaled up to the 60° reference
geomagnetic latitude (see Figure 3) such that the resulting peak geoelectric field amplitude
computed using the reference earth model was 8 V/km (see Figures 4 and 5). The sampling rate
for the geomagnetic field waveform is 10 seconds.8 To use this geoelectric field time series when
a different earth model is applicable, it should be scaled with the appropriate benchmark
conductivity scaling factor β b .
Refer to the Benchmark Geomagnetic Disturbance Event Description white paper for details on the determination of the
reference geomagnetic field waveform: http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx.
8 The data file of the benchmark geomagnetic field waveform is available on the Related Information webpage for TPL-007-1:
http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx.
7
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Figure 3: Benchmark Geomagnetic Field Waveform
Red B n (Northward), Blue B e (Eastward)
Figure 4: Benchmark Geoelectric Field Waveform
E E (Eastward)
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Figure 5: Benchmark Geoelectric Field Waveform
E N (Northward)
Reference Geomagnetic Field Time Series or Waveform for the Supplemental GMD
Event9
The geomagnetic field measurement record of the March 13-14, 1989 GMD event, measured at
the NRCan Ottawa geomagnetic observatory, is the basis for the reference geomagnetic field
waveform to be used to calculate the GIC time series, GIC(t), required for transformer thermal
impact assessment for the supplemental GMD event. The supplemental GMD event waveform
differs from the benchmark GMD event waveform in that the supplemental GMD event
waveform has a local enhancement.
The geomagnetic latitude of the Ottawa geomagnetic observatory is 55°; therefore, the
amplitudes of the geomagnetic field measurement data were scaled up to the 60° reference
geomagnetic latitude (see Figure 6) such that the resulting peak geoelectric field amplitude
computed using the reference earth model was 12 V/km (see Figure7). The sampling rate for the
geomagnetic field waveform is 10 seconds. 10 To use this geoelectric field time series when a
different earth model is applicable, it should be scaled with the appropriate supplemental
conductivity scaling factor β s .
Refer to the Supplemental Geomagnetic Disturbance Event Description white paper for details on the determination of the
reference geomagnetic field waveform: http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspx.
10 The data file of the benchmark geomagnetic field waveform is available on the NERC GMD Task Force project webpage:
http://www.nerc.com/comm/PC/Pages/Geomagnetic-Disturbance-Task-Force-(GMDTF)-2013.aspx.
9
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TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
4000
2000
Time (min)
200
400
600
800
1000
1200
1400
1600
1800
2000
Bx, By (nT)
0
-2000
-4000
-6000
-8000
-10000
Figure 6: Supplemental Geomagnetic Field Waveform
Red B N (Northward), Blue B E (Eastward)
12 V/km
Figure 7: Supplemental Geoelectric Field Waveform
Blue E N (Northward), Red E E (Eastward)
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TPL-007-4 – Supplemental Material
Attachment 1-CAN
Attachment 1-CAN provides an alternative that a Canadian entity may use in lieu of the
benchmark or supplemental GMD event(s) defined in Attachment 1 for performing GMD
Vulnerability Assessment(s).
A Canadian entity may use the provisions of Attachment 1-CAN if it has regionally specific
information that provides a technically justified means to re-define a 1-in-100 year GMD
planning event(s) within its planning area.
Information for the Alternative Methodology
GMD Vulnerability Assessment(s) require the use of geophysical and engineering models.
Canadian-specific data is available and growing. Ongoing research allows for more accurate
characterization of regional parameters used in these models. Such Canadian-specific data
includes geomagnetic field, earth conductivity, and geomagnetically induced current
measurements that can be used for modeling and simulation validation.
Information used to calculate geoelectric fields for the benchmark and supplemental GMD events
shall be clearly documented and technically justified. For example, the factors involved in the
calculation of geoelectric fields are geomagnetic field variations and an earth transfer
function(s). 1 Technically justified information used in modelling geomagnetic field variations may
include: technical documents produced by governmental entities such as Natural Resources
Canada; technical papers published in peer-reviewed journals; and data sets gathered using
sound scientific principles. An earth transfer function may rely on magnetotelluric measurements
or earth conductivity models.
Modeling assumptions shall also be clearly documented and technically justified. An entity may
use sensitivity analysis to identify how the assumptions affect the results.
A simplified model may be used to perform a GMD Vulnerability Assessment(s), as long as the
model is more conservative than a more detailed model.
When interpreting assessment results, the entity shall consider the maturity of the modeling,
toolset, and techniques applied.
Geomagnetic Disturbance Planning Events
The 1-in-100 year planning event shall be based on regionally specific data and technically
justifiable statistical analyses (e.g., extreme value theory) and applied to the benchmark and
supplemental GMD Vulnerability Assessment(s).
For the benchmark GMD Vulnerability Assessment(s), an entity shall consider the large-scale
spatial structure of the GMD event. For the supplemental GMD Vulnerability Assessment(s), an
The “earth transfer function” is the relationship between the electric fields and magnetic field variations at the surface of the
earth.
1
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TPL-007-4 – Supplemental Material
entity shall consider the small-scale spatial structure of the GMD event (e.g., using magnetometer
measurements or realistic electrojet calculations).
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TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Standard Development Timeline
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard is adopted by the NERC Board of Trustees (Board).
Description of Current Draft
This is the final draft of proposed standard for formal 10-day final ballot period.
Completed Actions
Date
Standards Committee approved Standard Authorization Request
(SAR) for posting
February 20, 2019
SAR posted for comment
February 25 –
March 27, 2019
45-day formal comment period with ballot
August 30 –
September, 9 2019
Anticipated Actions
Date
10-day final ballot
November 2019
Board adoption
February 2020
Final Draft of TPL-007-4
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Page 1 of 51
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
A. Introduction
1.
Title:
Events
Transmission System Planned Performance for Geomagnetic Disturbance
2.
Number:
TPL-007-34
3.
Purpose:
Establish requirements for Transmission system planned performance
during geomagnetic disturbance (GMD) events.
4.
Applicability:
4.1. Functional Entities:
4.1.1. Planning Coordinator with a planning area that includes a Facility or
Facilities specified in 4.2;
4.1.2. Transmission Planner with a planning area that includes a Facility or
Facilities specified in 4.2;
4.1.3. Transmission Owner who owns a Facility or Facilities specified in 4.2; and
4.1.4. Generator Owner who owns a Facility or Facilities specified in 4.2.
4.2. Facilities:
4.2.1. Facilities that include power transformer(s) with a high side, wyegrounded winding with terminal voltage greater than 200 kV.
5.
Effective Date: See Implementation Plan for TPL-007-34.
6.
Background: During a GMD event, geomagnetically-induced currents (GIC) may cause
transformer hot-spot heating or damage, loss of Reactive Power sources, increased
Reactive Power demand, and Misoperation(s), the combination of which may result in
voltage collapse and blackout.
The only difference between TPL-007-3 and TPL-007-2 is that TPL-007-3 adds a
Canadian Variance to address regulatory practices/processes within Canadian
jurisdictions and to allow the use of Canadian-specific data and research to define and
implement alternative GMD event(s) that achieve at least an equivalent reliability
objective of that in TPL-007-2.
B. Requirements and Measures
R1.
Each Planning Coordinator, in conjunction with its Transmission Planner(s), shall
identify the individual and joint responsibilities of the Planning Coordinator and
Transmission Planner(s) in the Planning Coordinator’s planning area for maintaining
models, performing the study or studies needed to complete benchmark and
supplemental GMD Vulnerability Assessments, and implementing process(es) to
obtain GMD measurement data as specified in this standard. [Violation Risk Factor:
Lower] [Time Horizon: Long-term Planning]
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M1. Each Planning Coordinator, in conjunction with its Transmission Planners, shall provide
documentation on roles and responsibilities, such as meeting minutes, agreements,
copies of procedures or protocols in effect between entities or between departments
of a vertically integrated system, or email correspondence that identifies an
agreement has been reached on individual and joint responsibilities for maintaining
models, performing the study or studies needed to complete benchmark and
supplemental GMD Vulnerability Assessments, and implementing process(es) to
obtain GMD measurement data in accordance with Requirement R1.
R2. Each responsible entity, as determined in Requirement R1, shall maintain System
models and GIC System models of the responsible entity’s planning area for
performing the study or studies needed to complete benchmark and supplemental
GMD Vulnerability Assessments. [Violation Risk Factor: High] [Time Horizon: Longterm Planning]
M2. Each responsible entity, as determined in Requirement R1, shall have evidence in
either electronic or hard copy format that it is maintaining System models and GIC
System models of the responsible entity’s planning area for performing the study or
studies needed to complete benchmark and supplemental GMD Vulnerability
Assessments.
R3. Each responsible entity, as determined in Requirement R1, shall have criteria for
acceptable System steady state voltage performance for its System during the GMD
events described in Attachment 1. [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]
M3. Each responsible entity, as determined in Requirement R1, shall have evidence, such
as electronic or hard copies of the criteria for acceptable System steady state voltage
performance for its System in accordance with Requirement R3.
Benchmark GMD Vulnerability Assessment(s)
R4. Each responsible entity, as determined in Requirement R1, shall complete a
benchmark GMD Vulnerability Assessment of the Near-Term Transmission Planning
Horizon at least once every 60 calendar months. This benchmark GMD Vulnerability
Assessment shall use a study or studies based on models identified in Requirement R2,
document assumptions, and document summarized results of the steady state
analysis. [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
4.1. The study or studies shall include the following conditions:
4.1.1. System On-Peak Load for at least one year within the Near-Term
Transmission Planning Horizon; and
4.1.2. System Off-Peak Load for at least one year within the Near-Term
Transmission Planning Horizon.
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4.2. The study or studies shall be conducted based on the benchmark GMD event
described in Attachment 1 to determine whether the System meets the
performance requirements for the steady state planning benchmark GMD event
contained in Table 1.
4.3. The benchmark GMD Vulnerability Assessment shall be provided: (i) to the
responsible entity’s Reliability Coordinator, adjacent Planning Coordinators, and
adjacent Transmission Planners within 90 calendar days of completion, and (ii) to
any functional entity that submits a written request and has a reliability-related
need within 90 calendar days of receipt of such request or within 90 calendar
days of completion of the benchmark GMD Vulnerability Assessment, whichever
is later.
4.3.1. If a recipient of the benchmark GMD Vulnerability Assessment provides
documented comments on the results, the responsible entity shall
provide a documented response to that recipient within 90 calendar days
of receipt of those comments.
M4. Each responsible entity, as determined in Requirement R1, shall have dated evidence
such as electronic or hard copies of its benchmark GMD Vulnerability Assessment
meeting all of the requirements in Requirement R4. Each responsible entity, as
determined in Requirement R1, shall also provide evidence, such as email records,
web postings with an electronic notice of posting, or postal receipts showing recipient
and date, that it has distributed its benchmark GMD Vulnerability Assessment: (i) to
the responsible entity’s Reliability Coordinator, adjacent Planning Coordinators, and
adjacent Transmission Planners within 90 calendar days of completion, and (ii) to any
functional entity that submits a written request and has a reliability-related need
within 90 calendar days of receipt of such request or within 90 calendar days of
completion of the benchmark GMD Vulnerability Assessment, whichever is later, as
specified in Requirement R4. Each responsible entity, as determined in Requirement
R1, shall also provide evidence, such as email notices or postal receipts showing
recipient and date, that it has provided a documented response to comments received
on its benchmark GMD Vulnerability Assessment within 90 calendar days of receipt of
those comments in accordance with Requirement R4.
R5. Each responsible entity, as determined in Requirement R1, shall provide GIC flow
information to be used for the benchmark thermal impact assessment of transformers
specified in Requirement R6 to each Transmission Owner and Generator Owner that
owns an applicable Bulk Electric System (BES) power transformer in the planning area.
The GIC flow information shall include: [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]
5.1. The maximum effective GIC value for the worst case geoelectric field orientation
for the benchmark GMD event described in Attachment 1. This value shall be
provided to the Transmission Owner or Generator Owner that owns each
applicable BES power transformer in the planning area.
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5.2. The effective GIC time series, GIC(t), calculated using the benchmark GMD event
described in Attachment 1 in response to a written request from the
Transmission Owner or Generator Owner that owns an applicable BES power
transformer in the planning area. GIC(t) shall be provided within 90 calendar
days of receipt of the written request and after determination of the maximum
effective GIC value in Part 5.1.
M5. Each responsible entity, as determined in Requirement R1, shall provide evidence,
such as email records, web postings with an electronic notice of posting, or postal
receipts showing recipient and date, that it has provided the maximum effective GIC
values to the Transmission Owner and Generator Owner that owns each applicable
BES power transformer in the planning area as specified in Requirement R5, Part 5.1.
Each responsible entity, as determined in Requirement R1, shall also provide evidence,
such as email records, web postings with an electronic notice of posting, or postal
receipts showing recipient and date, that it has provided GIC(t) in response to a
written request from the Transmission Owner or Generator Owner that owns an
applicable BES power transformer in the planning area.
R6. Each Transmission Owner and Generator Owner shall conduct a benchmark thermal
impact assessment for its solely and jointly owned applicable BES power transformers
where the maximum effective GIC value provided in Requirement R5, Part 5.1, is 75 A
per phase or greater. The benchmark thermal impact assessment shall: [Violation Risk
Factor: Medium] [Time Horizon: Long-term Planning]
6.1. Be based on the effective GIC flow information provided in Requirement R5;
6.2. Document assumptions used in the analysis;
6.3. Describe suggested actions and supporting analysis to mitigate the impact of
GICs, if any; and
6.4. Be performed and provided to the responsible entities, as determined in
Requirement R1, within 24 calendar months of receiving GIC flow information
specified in Requirement R5, Part 5.1.
M6. Each Transmission Owner and Generator Owner shall have evidence such as electronic
or hard copies of its benchmark thermal impact assessment for all of its solely and
jointly owned applicable BES power transformers where the maximum effective GIC
value provided in Requirement R5, Part 5.1, is 75 A per phase or greater, and shall
have evidence such as email records, web postings with an electronic notice of
posting, or postal receipts showing recipient and date, that it has provided its thermal
impact assessment to the responsible entities as specified in Requirement R6.
R7.
Each responsible entity, as determined in Requirement R1, that concludes through
the benchmark GMD Vulnerability Assessment conducted in Requirement R4 that
their System does not meet the performance requirements for the steady state
planning benchmark GMD event contained in Table 1, shall develop a Corrective
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Action Plan (CAP) addressing how the performance requirements will be met. The CAP
shall: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
7.1. List System deficiencies and the associated actions needed to achieve required
System performance. Examples of such actions include:
•
Installation, modification, retirement, or removal of Transmission and
generation Facilities and any associated equipment.
•
Installation, modification, or removal of Protection Systems or Remedial
Action Schemes.
•
Use of Operating Procedures, specifying how long they will be needed as
part of the CAP.
•
Use of Demand-Side Management, new technologies, or other initiatives.
7.2. Be developed within one year of completion of the benchmark GMD
Vulnerability Assessment.
7.3. Include a timetable, subject to revision by the responsible entity inapproval for
any extension sought under Part 7.4, for implementing the selected actions from
Part 7.1. The timetable shall:
7.3.1. Specify implementation of non-hardware mitigation, if any, within two
years of development of the CAP; and
7.3.2. Specify implementation of hardware mitigation, if any, within four years
of development of the CAP.
7.4. Be revised if situations beyondsubmitted to the controlCompliance Enforcement
Authority (CEA) with a request for extension of time if the responsible entity
determined in Requirement R1 prevent implementation ofis unable to
implement the CAP within the timetable for implementation provided in Part
7.3. The revisedsubmitted CAP shall document the following, and be updated at
least once every 12 calendar months until implemented:
7.4.1. Circumstances causing the delay for fully or partially implementing the
selected actions in Part 7.1 and how those circumstances are beyond the
control of the responsible entity;
7.4.2. Description of the original CAP, and any previous changes to the CAP,
with the associated timetable(s) for implementing the selected actions in
Part 7.1; and
7.4.3.7.4.2. Revisions to the selected actions in Part 7.1, if any, including
utilization of Operating Procedures, if applicable,; and the updated
timetable for implementing the selected actions.
7.4.3. Updated timetable for implementing the selected actions in Part 7.1.
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7.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent
Planning Coordinator(s), adjacent Transmission Planner(s), and functional
entities referenced in the CAP within 90 calendar days of development or
revision, and (ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later.
7.5.1. If a recipient of the CAP provides documented comments on the
resultsCAP, the responsible entity shall provide a documented response
to that recipient within 90 calendar days of receipt of those comments.
M7. Each responsible entity, as determined in Requirement R1, that concludes, through
the benchmark GMD Vulnerability Assessment conducted in Requirement R4, that the
responsible entity’s System does not meet the performance requirements for the
steady state planning benchmark GMD event contained in Table 1 shall have evidence
such as dated electronic or hard copies of its CAP including timetable for
implementing selected actions, as specified in Requirement R7. Each responsible
entity, as determined in Requirement R1, shall also provide evidence, such as email
records or postal receipts showing recipient and date, that it has revised its
CAPsubmitted a request for extension to the CEA if situations beyond the responsible
entity's control prevent implementation ofentity is unable to implement the CAP
within the timetable specified.provided in Part 7.3. Each responsible entity, as
determined in Requirement R1, shall also provide evidence, such as email records,
web postings with an electronic notice of posting, or postal receipts showing recipient
and date, that it has distributed its CAP or relevant information, if any, (i) to the
responsible entity’s Reliability Coordinator, adjacent Planning Coordinator(s), adjacent
Transmission Planner(s), and functional entities referenced in the CAP within 90
calendar days of development or revision, and (ii) to any functional entity that submits
a written request and has a reliability-related need within 90 calendar days of receipt
of such request or within 90 calendar days of development or revision, whichever is
later as specified in Requirement R7. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email notices or postal receipts
showing recipient and date, that it has provided a documented response to comments
received on its CAP within 90 calendar days of receipt of those comments, in
accordance with Requirement R7.
Supplemental GMD Vulnerability Assessment(s)
R8.
Each responsible entity, as determined in Requirement R1, shall complete a
supplemental GMD Vulnerability Assessment of the Near-Term Transmission Planning
Horizon at least once every 60 calendar months. This supplemental GMD Vulnerability
Assessment shall use a study or studies based on models identified in Requirement
R2, document assumptions, and document summarized results of the steady state
analysis. [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
8.1. The study or studies shall include the following conditions:
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8.1.1. System On-Peak Load for at least one year within the Near-Term
Transmission Planning Horizon; and
8.1.2. System Off-Peak Load for at least one year within the Near-Term
Transmission Planning Horizon.
8.2. The study or studies shall be conducted based on the supplemental GMD event
described in Attachment 1 to determine whether the System meets the
performance requirements for the steady state planning supplemental GMD
event contained in Table 1.
8.3. If the analysis concludes there is Cascading caused by the supplemental GMD
event described in Attachment 1, an evaluation of possible actions designed to
reduce the likelihood or mitigate the consequences and adverse impacts of the
event(s) shall be conducted.
8.4.8.3.
The supplemental GMD Vulnerability Assessment shall be provided:
(i) to the responsible entity’s Reliability Coordinator, adjacent Planning
Coordinators, adjacent Transmission Planners within 90 calendar days of
completion, and (ii) to any functional entity that submits a written request and
has a reliability-related need within 90 calendar days of receipt of such request
or within 90 calendar days of completion of the supplemental GMD Vulnerability
Assessment, whichever is later.
8.4.1.8.3.1. If a recipient of the supplemental GMD Vulnerability Assessment
provides documented comments on the results, the responsible entity
shall provide a documented response to that recipient within 90 calendar
days of receipt of those comments.
M8. Each responsible entity, as determined in Requirement R1, shall have dated evidence
such as electronic or hard copies of its supplemental GMD Vulnerability Assessment
meeting all of the requirements in Requirement R8. Each responsible entity, as
determined in Requirement R1, shall also provide evidence, such as email records,
web postings with an electronic notice of posting, or postal receipts showing recipient
and date, that it has distributed its supplemental GMD Vulnerability Assessment: (i) to
the responsible entity’s Reliability Coordinator, adjacent Planning Coordinators,
adjacent Transmission Planners within 90 calendar days of completion, and (ii) to any
functional entity that submits a written request and has a reliability-related need
within 90 calendar days of receipt of such request or within 90 calendar days of
completion of the supplemental GMD Vulnerability Assessment, whichever is later, as
specified in Requirement R8. Each responsible entity, as determined in Requirement
R1, shall also provide evidence, such as email notices or postal receipts showing
recipient and date, that it has provided a documented response to comments
received on its supplemental GMD Vulnerability Assessment within 90 calendar days
of receipt of those comments in accordance with Requirement R8.
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R9.
Each responsible entity, as determined in Requirement R1, shall provide GIC flow
information to be used for the supplemental thermal impact assessment of
transformers specified in Requirement R10 to each Transmission Owner and
Generator Owner that owns an applicable Bulk Electric System (BES) power
transformer in the planning area. The GIC flow information shall include: [Violation
Risk Factor: Medium] [Time Horizon: Long-term Planning]
9.1. The maximum effective GIC value for the worst case geoelectric field orientation
for the supplemental GMD event described in Attachment 1. This value shall be
provided to the Transmission Owner or Generator Owner that owns each
applicable BES power transformer in the planning area.
9.2. The effective GIC time series, GIC(t), calculated using the supplemental GMD
event described in Attachment 1 in response to a written request from the
Transmission Owner or Generator Owner that owns an applicable BES power
transformer in the planning area. GIC(t) shall be provided within 90 calendar
days of receipt of the written request and after determination of the maximum
effective GIC value in Part 9.1.
M9. Each responsible entity, as determined in Requirement R1, shall provide evidence,
such as email records, web postings with an electronic notice of posting, or postal
receipts showing recipient and date, that it has provided the maximum effective GIC
values to the Transmission Owner and Generator Owner that owns each applicable
BES power transformer in the planning area as specified in Requirement R9, Part 9.1.
Each responsible entity, as determined in Requirement R1, shall also provide
evidence, such as email records, web postings with an electronic notice of posting, or
postal receipts showing recipient and date, that it has provided GIC(t) in response to a
written request from the Transmission Owner or Generator Owner that owns an
applicable BES power transformer in the planning area.
R10. Each Transmission Owner and Generator Owner shall conduct a supplemental
thermal impact assessment for its solely and jointly owned applicable BES power
transformers where the maximum effective GIC value provided in Requirement R9,
Part 9.1, is 85 A per phase or greater. The supplemental thermal impact assessment
shall: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
10.1. Be based on the effective GIC flow information provided in Requirement R9;
10.2. Document assumptions used in the analysis;
10.3. Describe suggested actions and supporting analysis to mitigate the impact of
GICs, if any; and
10.4. Be performed and provided to the responsible entities, as determined in
Requirement R1, within 24 calendar months of receiving GIC flow information
specified in Requirement R9, Part 9.1.
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M10. Each Transmission Owner and Generator Owner shall have evidence such as
electronic or hard copies of its supplemental thermal impact assessment for all of its
solely and jointly owned applicable BES power transformers where the maximum
effective GIC value provided in Requirement R9, Part 9.1, is 85 A per phase or greater,
and shall have evidence such as email records, web postings with an electronic notice
of posting, or postal receipts showing recipient and date, that it has provided its
supplemental thermal impact assessment to the responsible entities as specified in
Requirement R10.
R11. Each responsible entity, as determined in Requirement R1, that concludes through
the supplemental GMD Vulnerability Assessment conducted in Requirement R8 that
their System does not meet the performance requirements for the steady state
planning supplemental GMD event contained in Table 1, shall develop a Corrective
Action Plan (CAP) addressing how the performance requirements will be met. The CAP
shall: [Violation Risk Factor: High] [Time Horizon: Long-term Planning]
11.1. List System deficiencies and the associated actions needed to achieve required
System performance. Examples of such actions include:
•
Installation, modification, retirement, or removal of Transmission and
generation Facilities and any associated equipment.
•
Installation, modification, or removal of Protection Systems or Remedial
Action Schemes.
•
Use of Operating Procedures, specifying how long they will be needed as
part of the CAP.
•
Use of Demand-Side Management, new technologies, or other initiatives.
11.2. Be developed within one year of completion of the supplemental GMD
Vulnerability Assessment.
11.3. Include a timetable, subject to approval for any extension sought under Part
11.4, for implementing the selected actions from Part 11.1. The timetable shall:
11.3.1. Specify implementation of non-hardware mitigation, if any, within two
years of development of the CAP; and
11.3.2. Specify implementation of hardware mitigation, if any, within four years
of development of the CAP.
11.4. Be submitted to the CEA with a request for extension of time if the responsible
entity is unable to implement the CAP within the timetable provided in Part 11.3.
The submitted CAP shall document the following:
11.4.1. Circumstances causing the delay for fully or partially implementing the
selected actions in Part 11.1 and how those circumstances are beyond
the control of the responsible entity;
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11.4.2. Revisions to the selected actions in Part 11.1, if any, including utilization
of Operating Procedures, if applicable; and
11.4.3. Updated timetable for implementing the selected actions in Part 11.1.
11.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent
Planning Coordinator(s), adjacent Transmission Planner(s), and functional
entities referenced in the CAP within 90 calendar days of development or
revision, and (ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later.
11.5.1. If a recipient of the CAP provides documented comments on the CAP, the
responsible entity shall provide a documented response to that recipient
within 90 calendar days of receipt of those comments.
M11. Each responsible entity, as determined in Requirement R1, that concludes, through
the supplemental GMD Vulnerability Assessment conducted in Requirement R8, that
the responsible entity’s System does not meet the performance requirements for the
steady state planning supplemental GMD event contained in Table 1 shall have
evidence such as dated electronic or hard copies of its CAP including timetable for
implementing selected actions, as specified in Requirement R11. Each responsible
entity, as determined in Requirement R1, shall also provide evidence, such as email
records or postal receipts showing recipient and date, that it submitted a request for
extension to the CEA if the responsible entity is unable to implement the CAP within
the timetable provided in Part 11.3. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records, web postings with
an electronic notice of posting, or postal receipts showing recipient and date, that it
has distributed its CAP or relevant information, if any, (i) to the responsible entity’s
Reliability Coordinator, adjacent Planning Coordinator(s), adjacent Transmission
Planner(s), and functional entities referenced in the CAP within 90 calendar days of
development or revision, and (ii) to any functional entity that submits a written
request and has a reliability-related need within 90 calendar days of receipt of such
request or within 90 calendar days of development or revision, whichever is later as
specified in Requirement R11. Each responsible entity, as determined in Requirement
R1, shall also provide evidence, such as email notices or postal receipts showing
recipient and date, that it has provided a documented response to comments received
on its CAP within 90 calendar days of receipt of those comments, in accordance with
Requirement R11.
GMD Measurement Data Processes
R11.R12. Each responsible entity, as determined in Requirement R1, shall implement a
process to obtain GIC monitor data from at least one GIC monitor located in the
Planning Coordinator’s planning area or other part of the system included in the
Planning Coordinator’s GIC System model. [Violation Risk Factor: Lower] [Time
Horizon: Long-term Planning]
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M11.M12. Each responsible entity, as determined in Requirement R1, shall have evidence
such as electronic or hard copies of its GIC monitor location(s) and documentation of
its process to obtain GIC monitor data in accordance with Requirement R11R12.
R12.R13. Each responsible entity, as determined in Requirement R1, shall implement a
process to obtain geomagnetic field data for its Planning Coordinator’s planning area.
[Violation Risk Factor: Lower] [Time Horizon: Long-term Planning]
M12.M13. Each responsible entity, as determined in Requirement R1, shall have evidence
such as electronic or hard copies of its process to obtain geomagnetic field data for its
Planning Coordinator’s planning area in accordance with Requirement R12R13.
C. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority”
means NERC or the Regional Entity, or any entity as otherwise designated by an
Applicable Governmental Authority, in their respective roles of monitoring
and/or enforcing compliance with mandatory and enforceable Reliability
Standards in their respective jurisdictions.
1.2. Evidence Retention: The following evidence retention period(s) identify the
period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below
is shorter than the time since the last audit, the Compliance Enforcement
Authority may ask an entity to provide other evidence to show that it was
compliant for the full-time period since the last audit.
The applicable entity shall keep data or evidence to show compliance as
identified below unless directed by its Compliance Enforcement Authority to
retain specific evidence for a longer period of time as part of an investigation.
•
For Requirements R1, R2, R3, R5, R6, R9, and R10, each responsible entity
shall retain documentation as evidence for five years.
•
For Requirements R4 and R8, each responsible entity shall retain
documentation of the current GMD Vulnerability Assessment and the
preceding GMD Vulnerability Assessment.
•
For Requirement R7 and R11, each responsible entity shall retain
documentation as evidence for five years or until all actions in the
Corrective Action Plan are completed, whichever is later.
•
For Requirements R11R12 and R12R13, each responsible entity shall retain
documentation as evidence for three years.
1.3. Compliance Monitoring and Enforcement Program: As defined in the NERC
Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers
to the identification of the processes that will be used to evaluate data or
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information for the purpose of assessing performance or outcomes with the
associated Reliability Standard.
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Table 1: Steady State Planning GMD Event
Steady State:
a. Voltage collapse, Cascading and uncontrolled islanding shall not occur.
b. Generation loss is acceptable as a consequence of the steady state planning GMD events.
c. Planned System adjustments such as Transmission configuration changes and re-dispatch of generation are allowed if such
adjustments are executable within the time duration applicable to the Facility Ratings.
Category
Initial Condition
Event
Interruption of
Firm
Transmission
Service Allowed
Load Loss
Allowed
Benchmark GMD
Event -– GMD
Event with
Outages
1. System as may be
postured in response
to space weather
information1, and then
2. GMD event2
Reactive Power compensation devices
and other Transmission Facilities
removed as a result of Protection
System operation or Misoperation due
to harmonics during the GMD event
Yes3
Yes3
Supplemental
GMD Event -–
GMD Event with
Outages
1. System as may be
postured in response
to space weather
information1, and then
2. GMD event2
Reactive Power compensation devices
and other Transmission Facilities
removed as a result of Protection
System operation or Misoperation due
to harmonics during the GMD event
Yes
Yes
Table 1: Steady State Performance Footnotes
1. The System condition for GMD planning may include adjustments to posture the System that are executable in response to
space weather information.
2. The GMD conditions for the benchmark and supplemental planning events are described in Attachment 1.
3. Load loss as a result of manual or automatic Load shedding (e.g., UVLS) and/or curtailment of Firm Transmission Service may
be used to meet BES performance requirements during studied GMD conditions. The likelihood and magnitude of Load loss or
curtailment of Firm Transmission Service should be minimized.
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Violation Severity Levels
R#
R1.
R2.
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November 2019
Lower VSL
N/A
N/A
Violation Severity Levels
Moderate VSL
High VSL
Severe VSL
N/A
N/A
The Planning Coordinator,
in conjunction with its
Transmission Planner(s),
failed to determine and
identify individual or joint
responsibilities of the
Planning Coordinator and
Transmission Planner(s) in
the Planning Coordinator’s
planning area for
maintaining models,
performing the study or
studies needed to complete
benchmark and
supplemental GMD
Vulnerability Assessments,
and implementing
process(es) to obtain GMD
measurement data as
specified in this standard.
N/A
The responsible entity did
not maintain either System
models or GIC System
models of the responsible
entity’s planning area for
performing the studies
The responsible entity did
not maintain both System
models and GIC System
models of the responsible
entity’s planning area for
performing the studies
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Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
needed to complete
benchmark and
supplemental GMD
Vulnerability Assessments.
R3.
R4.
N/A
The responsible entity
completed a benchmark
GMD Vulnerability
Assessment, but it was
more than 60 calendar
months and less than or
equal to 64 calendar
months since the last
benchmark GMD
Vulnerability Assessment.
Final Draft of TPL-007-4
November 2019
N/A
N/A
The responsible entity’s
completed benchmark GMD
Vulnerability Assessment
failed to satisfy one of the
elements listed in
Requirement R4, Parts 4.1
through 4.3;
OR
The responsible entity
completed a benchmark
GMD Vulnerability
Assessment, but it was
more than 64 calendar
months and less than or
equal to 68 calendar
The responsible entity’s
completed benchmark GMD
Vulnerability Assessment
failed to satisfy two of the
elements listed in
Requirement R4, Parts 4.1
through 4.3;
OR
The responsible entity
completed a benchmark
GMD Vulnerability
Assessment, but it was
more than 68 calendar
months and less than or
equal to 72 calendar
Severe VSL
needed to complete
benchmark and
supplemental GMD
Vulnerability Assessments.
The responsible entity did
not have criteria for
acceptable System steady
state voltage performance
for its System during the
GMD events described in
Attachment 1 as required.
The responsible entity’s
completed benchmark GMD
Vulnerability Assessment
failed to satisfy three of the
elements listed in
Requirement R4, Parts 4.1
through 4.3;
OR
The responsible entity
completed a benchmark
GMD Vulnerability
Assessment, but it was
more than 72 calendar
months since the last
Page 16 of 51
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
R5.
R6.
Lower VSL
Moderate VSL
High VSL
Severe VSL
months since the last
benchmark GMD
Vulnerability Assessment.
months since the last
benchmark GMD
Vulnerability Assessment.
benchmark GMD
Vulnerability Assessment;
OR
The responsible entity does
not have a completed
benchmark GMD
Vulnerability Assessment.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written
request, but did so more
than 90 calendar days and
less than or equal to 100
calendar days after receipt
of a written request.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written
request, but did so more
than 100 calendar days and
less than or equal to 110
calendar days after receipt
of a written request.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written
request, but did so more
than 110 calendar days
after receipt of a written
request.
The responsible entity did
not provide the maximum
effective GIC value to the
Transmission Owner and
Generator Owner that owns
each applicable BES power
transformer in the planning
area;
OR
The responsible entity did
not provide the effective
GIC time series, GIC(t), upon
written request.
The responsible entity failed
to conduct a benchmark
thermal impact assessment
for 5% or less or one of its
solely owned and jointly
owned applicable BES
The responsible entity failed
to conduct a benchmark
thermal impact assessment
for more than 5% up to (and
including) 10% or two of its
solely owned and jointly
The responsible entity failed
to conduct a benchmark
thermal impact assessment
for more than 10% up to
(and including) 15% or three
of its solely owned and
The responsible entity failed
to conduct a benchmark
thermal impact assessment
for more than 15% or more
than three of its solely
owned and jointly owned
Final Draft of TPL-007-4
November 2019
Page 17 of 51
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
power transformers
(whichever is greater)
where the maximum
effective GIC value provided
in Requirement R5, Part 5.1,
is 75 A or greater per phase;
OR
The responsible entity
conducted a benchmark
thermal impact assessment
for its solely owned and
jointly owned applicable
BES power transformers
where the maximum
effective GIC value provided
in Requirement R5, Part 5.1,
is 75 A or greater per phase
but did so more than 24
calendar months and less
than or equal to 26 calendar
months of receiving GIC
flow information specified
in Requirement R5, Part 5.1.
owned applicable BES
power transformers
(whichever is greater)
where the maximum
effective GIC value provided
in Requirement R5, Part 5.1,
is 75 A or greater per phase;
OR
The responsible entity
conducted a benchmark
thermal impact assessment
for its solely owned and
jointly owned applicable
BES power transformers
where the maximum
effective GIC value provided
in Requirement R5, Part 5.1,
is 75 A or greater per phase
but did so more than 26
calendar months and less
than or equal to 28 calendar
months of receiving GIC
flow information specified
in Requirement R5, Part 5.1;
OR
The responsible entity failed
to include one of the
jointly owned applicable
BES power transformers
(whichever is greater)
where the maximum
effective GIC value provided
in Requirement R5, Part 5.1,
is 75 A or greater per phase;
OR
The responsible entity
conducted a benchmark
thermal impact assessment
for its solely owned and
jointly owned applicable
BES power transformers
where the maximum
effective GIC value provided
in Requirement R5, Part 5.1,
is 75 A or greater per phase
but did so more than 28
calendar months and less
than or equal to 30 calendar
months of receiving GIC
flow information specified
in Requirement R5, Part 5.1;
OR
The responsible entity failed
to include two of the
applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R5, Part 5.1, is
75 A or greater per phase;
OR
The responsible entity
conducted a benchmark
thermal impact assessment
for its solely owned and
jointly owned applicable
BES power transformers
where the maximum
effective GIC value provided
in Requirement R5, Part 5.1,
is 75 A or greater per phase
but did so more than 30
calendar months of
receiving GIC flow
information specified in
Requirement R5, Part 5.1;
OR
The responsible entity failed
to include three of the
required elements as listed
Final Draft of TPL-007-4
November 2019
Page 18 of 51
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
required elements as listed
in Requirement R6, Parts
6.1 through 6.3.
required elements as listed
in Requirement R6, Parts
6.1 through 6.3.
in Requirement R6, Parts
6.1 through 6.3.
The responsible entity’s
Corrective Action Plan failed
to comply with one of the
elements in Requirement
R7, Parts 7.1 through 7.5.
The responsible entity’s
Corrective Action Plan failed
to comply with two of the
elements in Requirement
R7, Parts 7.1 through 7.5.
The responsible entity’s
Corrective Action Plan failed
to comply with three of the
elements in Requirement
R7, Parts 7.1 through 7.5.
The responsible entity’s
Corrective Action Plan failed
to comply with four or more
of the elements in
Requirement R7, Parts 7.1
through 7.5;
OR
The responsible entity did
not havedevelop a
Corrective Action Plan as
required by Requirement
R7.
The responsible entity's
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
one of elements listed in
Requirement R8, Parts 8.1
through 8.4;
OR
The responsible entity
completed a supplemental
GMD Vulnerability
The responsible entity’s
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
twoone of the elements
listed in Requirement R8,
Parts 8.1 through 8.43;
OR
The responsible entity
completed a supplemental
GMD Vulnerability
The responsible entity’s
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
threetwo of the elements
listed in Requirement R8,
Parts 8.1 through 8.43;
OR
The responsible entity
completed a supplemental
GMD Vulnerability
The responsible entity’s
completed supplemental
GMD Vulnerability
Assessment failed to satisfy
fourthree of the elements
listed in Requirement R8,
Parts 8.1 through 8.43;
OR
The responsible entity
completed a supplemental
GMD Vulnerability
R7.
R8.
Final Draft of TPL-007-4
November 2019
Severe VSL
Page 19 of 51
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
R9.
R10.
Lower VSL
Moderate VSL
High VSL
Severe VSL
Assessment, but it was
more than 60 calendar
months and less than or
equal to 64 calendar
months since the last
supplemental GMD
Vulnerability Assessment.
Assessment, but it was
more than 64 calendar
months and less than or
equal to 68 calendar
months since the last
supplemental GMD
Vulnerability Assessment.
Assessment, but it was
more than 68 calendar
months and less than or
equal to 72 calendar
months since the last
supplemental GMD
Vulnerability Assessment.
Assessment, but it was
more than 72 calendar
months since the last
supplemental GMD
Vulnerability Assessment;
OR
The responsible entity does
not have a completed
supplemental GMD
Vulnerability Assessment.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written
request, but did so more
than 90 calendar days and
less than or equal to 100
calendar days after receipt
of a written request.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written
request, but did so more
than 100 calendar days and
less than or equal to 110
calendar days after receipt
of a written request.
The responsible entity
provided the effective GIC
time series, GIC(t), in
response to written
request, but did so more
than 110 calendar days
after receipt of a written
request.
The responsible entity did
not provide the maximum
effective GIC value to the
Transmission Owner and
Generator Owner that owns
each applicable BES power
transformer in the planning
area;
OR
The responsible entity did
not provide the effective
GIC time series, GIC(t), upon
written request.
The responsible entity failed The responsible entity failed The responsible entity failed The responsible entity failed
to conduct a supplemental
to conduct a supplemental
to conduct a supplemental
to conduct a supplemental
thermal impact assessment thermal impact assessment thermal impact assessment thermal impact assessment
Final Draft of TPL-007-4
November 2019
Page 20 of 51
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
for 5% or less or one of its
solely owned and jointly
owned applicable BES
power transformers
(whichever is greater)
where the maximum
effective GIC value provided
in Requirement R9, Part 9.1,
is 85 A or greater per phase;
OR
The responsible entity
conducted a supplemental
thermal impact assessment
for its solely owned and
jointly owned applicable
BES power transformers
where the maximum
effective GIC value provided
in Requirement R9, Part 9.1,
is 85 A or greater per phase
but did so more than 24
calendar months and less
than or equal to 26 calendar
months of receiving GIC
flow information specified
in Requirement R9, Part 9.1.
for more than 5% up to (and
including) 10% or two of its
solely owned and jointly
owned applicable BES
power transformers
(whichever is greater)
where the maximum
effective GIC value provided
in Requirement R9, Part 9.1,
is 85 A or greater per phase;
OR
The responsible entity
conducted a supplemental
thermal impact assessment
for its solely owned and
jointly owned applicable
BES power transformers
where the maximum
effective GIC value provided
in Requirement R9, Part 9.1,
is 85 A or greater per phase
but did so more than 26
calendar months and less
than or equal to 28 calendar
months of receiving GIC
flow information specified
in Requirement R9, Part 9.1
for more than 10% up to
(and including) 15% or three
of its solely owned and
jointly owned applicable
BES power transformers
(whichever is greater)
where the maximum
effective GIC value provided
in Requirement R9, Part 9.1,
is 85 A or greater per phase;
OR
The responsible entity
conducted a supplemental
thermal impact assessment
for its solely owned and
jointly owned applicable
BES power transformers
where the maximum
effective GIC value provided
in Requirement R9, Part 9.1,
is 85 A or greater per phase
but did so more than 28
calendar months and less
than or equal to 30 calendar
months of receiving GIC
flow information specified
in Requirement R9, Part 9.1;
for more than 15% or more
than three of its solely
owned and jointly owned
applicable BES power
transformers (whichever is
greater) where the
maximum effective GIC
value provided in
Requirement R9, Part 9.1, is
85 A or greater per phase;
OR
The responsible entity
conducted a supplemental
thermal impact assessment
for its solely owned and
jointly owned applicable
BES power transformers
where the maximum
effective GIC value provided
in Requirement R9, Part 9.1,
is 85 A or greater per phase
but did so more than 30
calendar months of
receiving GIC flow
information specified in
Requirement R9, Part 9.1;
OR
Final Draft of TPL-007-4
November 2019
Page 21 of 51
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Violation Severity Levels
R#
R11.
Lower VSL
The responsible entity’s
Corrective Action Plan failed
to comply with one of the
elements in Requirement
R11, Parts 11.1 through
11.5.
Final Draft of TPL-007-4
November 2019
Moderate VSL
High VSL
Severe VSL
OR
The responsible entity failed
to include one of the
required elements as listed
in Requirement R10, Parts
10.1 through 10.3.
OR
The responsible entity failed
to include two of the
required elements as listed
in Requirement R10, Parts
10.1 through 10.3.
The responsible entity failed
to include three of the
required elements as listed
in Requirement R10, Parts
10.1 through 10.3.
The responsible entity’s
Corrective Action Plan failed
to comply with two of the
elements in Requirement
R11, Parts 11.1 through
11.5.
The responsible entity’s
Corrective Action Plan failed
to comply with four or more
The responsible entity’s
of the elements in
Corrective Action Plan failed Requirement R11, Parts
to comply with three of the 11.1 through 11.5;
elements in Requirement
OR
R11, Parts 11.1 through
The responsible entity did
11.5.
not develop a Corrective
Action Plan as required by
Requirement R11.
Page 22 of 51
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
R#
R11R12.
R12R13.
Final Draft of TPL-007-4
November 2019
Violation Severity Levels
Lower VSL
N/A
N/A
Moderate VSL
N/A
N/A
High VSL
N/A
N/A
Severe VSL
The responsible entity did
not implement a process to
obtain GIC monitor data
from at least one GIC
monitor located in the
Planning Coordinator’s
planning area or other part
of the system included in
the Planning Coordinator’s
GIC System Model.
The responsible entity did
not implement a process to
obtain geomagnetic field
data for its Planning
Coordinator’s planning area.
Page 23 of 51
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
D. Regional Variances
D.A. Regional Variance for Canadian Jurisdictions
This Variance shall be applicable in those Canadian jurisdictions where the Variance
has been approved for use by the applicable governmental authority or has otherwise
become effective in the jurisdiction.
AllThis variance replaces all references to “Attachment 1” in the standard are replaced
with “Attachment 1 or Attachment 1-CAN.”
In addition, this Variance replaces Requirement R7, Part 7.3 through Part 7.5 and
Requirement R11, Part 11.3 through Part 11.5 with the following:
D.A.7.3. Include a timetable, subject to revision by the responsible entity in Part
D.A.7.4, for implementing the selected actions from Part 7.1. The timetable
shall:
D.A.7.3.1. Specify implementation of non-hardware mitigation, if any, within
two years of the later of the development of the CAP or receipt of
regulatory approvals, if required; and
D.A.7.3.2. Specify implementation of hardware mitigation, if any, within four
years of the later of the development of the CAP or receipt of
regulatory approvals, if required.
D.A.7.4. Be revised if the responsible entity is unable to implement the CAP
within the timetable for implementation provided in Part D.A.7.3. The
revised CAP shall document the following:
D.A.7.4.1 Circumstances causing the delay for fully or partially implementing the
selected actions in Part 7.1 and how those circumstances are beyond
the control of the responsible entity;
D.A.7.4.2 Revisions to the selected actions in Part 7.1, if any, including utilization
of Operating Procedures if applicable; and
D.A.7.4.3 Updated timetable for implementing the selected actions in Part 7.1.
D.A.7.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent
Planning Coordinator(s), adjacent Transmission Planner(s), and functional
entities referenced in the CAP within 90 calendar days of development or
revision, (ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later, and
(iii) to the Compliance Enforcement Authority or Applicable Governmental
Authority when revised under D.A.7.4 within 90 calendar days of revision.
D.A.7.5.1 If a recipient of the CAP provides documented comments on the CAP,
the responsible entity shall provide a documented response to that
recipient within 90 calendar days of receipt of those comments.
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November 2019
Page 24 of 51
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
D.A.M.7. Each responsible entity, as determined in Requirement R1, that concludes,
through the benchmark GMD Vulnerability Assessment conducted in
Requirement R4, that the responsible entity’s System does not meet the
performance requirements for the steady state planning benchmark GMD
event contained in Table 1 shall have evidence such as dated electronic or
hard copies of its CAP including timetable for implementing selected actions,
as specified in Requirement R7. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records or postal
receipts showing recipient and date, that it has revised its CAP if situations
beyond the responsible entity's control prevent implementation of the CAP
within the timetable specified. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records, web
postings with an electronic notice of posting, or postal receipts showing
recipient and date, that it has distributed its CAP or relevant information, if
any, (i) to the responsible entity’s Reliability Coordinator, adjacent Planning
Coordinator(s), adjacent Transmission Planner(s), and functional entities
referenced in the CAP within 90 calendar days of development or revision,
(ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later as
specified in Requirement R7, and (iii) to the Compliance Enforcement
Authority or Applicable Governmental Authority when revised under D.A.7.4
within 90 calendar days of revision. Each responsible entity, as determined
in Requirement R1, shall also provide evidence, such as email notices or
postal receipts showing recipient and date, that it has provided a
documented response to comments received on its CAP within 90 calendar
days of receipt of those comments, in accordance with Requirement R7.
D.A.11.3.Include a timetable, subject to revision by the responsible entity in Part
D.A.11.4, for implementing the selected actions from Part 11.1. The
timetable shall:
D.A.11.3.1. Specify implementation of non-hardware mitigation, if any, within
two years of the later of the development of the CAP or receipt of
regulatory approvals, if required; and
D.A.11.3.2. Specify implementation of hardware mitigation, if any, within four
years of the later of the development of the CAP or receipt of
regulatory approvals, if required.
D.A.11.4. Be revised if the responsible entity is unable to implement the CAP within
the timetable for implementation provided in Part D.A.11.3. The revised CAP
shall document the following:
D.A.11.4.1 Circumstances causing the delay for fully or partially implementing
the selected actions in Part 11.1 and how those circumstances are
beyond the control of the responsible entity;
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November 2019
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TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
D.A.11.4.2 Revisions to the selected actions in Part 11.1, if any, including
utilization of Operating Procedures if applicable; and
D.A.11.4.3 Updated timetable for implementing the selected actions in Part
11.1.
D.A.11.5. Be provided: (i) to the responsible entity’s Reliability Coordinator, adjacent
Planning Coordinator(s), adjacent Transmission Planner(s), and functional
entities referenced in the CAP within 90 calendar days of development or
revision, (ii) to any functional entity that submits a written request and has
a reliability-related need within 90 calendar days of receipt of such request
or within 90 calendar days of development or revision, whichever is later,
and (iii) to the Compliance Enforcement Authority or Applicable
Governmental Authority when revised under D.A.11.4 within 90 calendar
days of revision.
D.A.11.5.1. If a recipient of the CAP provides documented comments on the
CAP, the responsible entity shall provide a documented response to
that recipient within 90 calendar days of receipt of those comments.
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November 2019
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TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
D.A.M.11. Each responsible entity, as determined in Requirement R1, that concludes,
through the supplemental GMD Vulnerability Assessment conducted in
Requirement R8, that the responsible entity’s System does not meet the
performance requirements for the steady state planning supplemental GMD
event contained in Table 1 shall have evidence such as dated electronic or
hard copies of its CAP including timetable for implementing selected actions,
as specified in Requirement R11. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records or postal
receipts showing recipient and date, that it has revised its CAP if situations
beyond the responsible entity's control prevent implementation of the CAP
within the timetable specified. Each responsible entity, as determined in
Requirement R1, shall also provide evidence, such as email records, web
postings with an electronic notice of posting, or postal receipts showing
recipient and date, that it has distributed its CAP or relevant information, if
any, (i) to the responsible entity’s Reliability Coordinator, adjacent Planning
Coordinator(s), adjacent Transmission Planner(s), and functional entities
referenced in the CAP within 90 calendar days of development or revision,
(ii) to any functional entity that submits a written request and has a
reliability-related need within 90 calendar days of receipt of such request or
within 90 calendar days of development or revision, whichever is later as
specified in Requirement R11, and (iii) to the Compliance Enforcement
Authority or Applicable Governmental Authority when revised under
D.A.11.4 within 90 calendar days of revision. Each responsible entity, as
determined in Requirement R1, shall also provide evidence, such as email
notices or postal receipts showing recipient and date, that it has provided a
documented response to comments received on its CAP within 90 calendar
days of receipt of those comments, in accordance with Requirement R11.
Final Draft of TPL-007-4
November 2019
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TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
E. Associated Documents
Attachment 1
Attachment 1-CAN
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November 2019
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TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Version History
Version
1
Date
Action
December 17, 2014 Adopted by the NERC Board of Trustees
Change
Tracking
New
Revised to
respond to
directives in FERC
Order No. 830.
2
November 9, 2017
Adopted by the NERC Board of Trustees
2
November 25, 2018
FERC Order issued approving TPL-007-2.
Docket No. RM18-8-000
3
February 7, 2019
Adopted by the NERC Board of Trustees
Canadian
Variance
Adopted by the NERC Board of Trustees
Revised to
respond to
directives in FERC
Order. 851
4
Final Draft of TPL-007-4
November 2019
TBD
Page 29 of 51
TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Attachment 1
Calculating Geoelectric Fields for the Benchmark and Supplemental GMD Events
The benchmark GMD event 1 defines the geoelectric field values used to compute GIC flows that
are needed to conduct a benchmark GMD Vulnerability Assessment. It is composed of the
following elements: (1) a reference peak geoelectric field amplitude of 8 V/km derived from
statistical analysis of historical magnetometer data; (2) scaling factors to account for local
geomagnetic latitude; (3) scaling factors to account for local earth conductivity; and (4) a
reference geomagnetic field time series or waveform to facilitate time-domain analysis of GMD
impact on equipment.
The supplemental GMD event is composed of similar elements as described above, except (1) the
reference peak geoelectric field amplitude is 12 V/km over a localized area; and (2) the
geomagnetic field time series or waveform includes a local enhancement in the waveform.2
The regional geoelectric field peak amplitude used in GMD Vulnerability Assessment, E peak , can
be obtained from the reference geoelectric field value of 8 V/km for the benchmark GMD event
(1) or 12 V/km for the supplemental GMD event (2) using the following relationships:
𝐸𝐸𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝 = 8 × 𝛼𝛼 × 𝛽𝛽 𝑏𝑏 (𝑉𝑉 ⁄𝑘𝑘𝑘𝑘)
𝐸𝐸𝑝𝑝𝑝𝑝𝑝𝑝𝑝𝑝 = 12 × 𝛼𝛼 × 𝛽𝛽 𝑠𝑠 (𝑉𝑉 ⁄𝑘𝑘𝑘𝑘)
(1)
(2)
where, α is the scaling factor to account for local geomagnetic latitude, and β is a scaling factor
to account for the local earth conductivity structure. Subscripts b and s for the β scaling factor
denote association with the benchmark or supplemental GMD events, respectively.
Scaling the Geomagnetic Field
The benchmark and supplemental GMD events are defined for geomagnetic latitude of 60° and
must be scaled to account for regional differences based on geomagnetic latitude. Table 2
provides a scaling factor correlating peak geoelectric field to geomagnetic latitude. Alternatively,
the scaling factor α is computed with the empirical expression:
𝛼𝛼 = 0.001 × 𝑒𝑒 (0.115×𝐿𝐿)
(3)
where, L is the geomagnetic latitude in degrees and 0.1 ≤ α ≤ 1.
The Benchmark Geomagnetic Disturbance Event Description, May 2016 is available on the Related Information webpage for
TPL-007-1: http://www.nerc.com/pa/Stand/TPL0071RD/Benchmark_clean_May12_complete.pdf.
2 The extent of local enhancements is on the order of 100 km in North-South (latitude) direction but longer in East-West
(longitude) direction. The local enhancement in the geomagnetic field occurs over the time period of 2-5 minutes. Additional
information is available in the Supplemental Geomagnetic Disturbance Event Description, October 2017 white paper on the
Project 2013-03 Geomagnetic Disturbance Mitigation project webpage: http://www.nerc.com/pa/Stand/Pages/Project-201303-Geomagnetic-Disturbance-Mitigation.aspx.
1
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For large planning areas that cover more than one scaling factor from Table 2, the GMD
Vulnerability Assessment should be based on a peak geoelectric field that is:
•
calculated by using the most conservative (largest) value for α; or
•
calculated assuming a non-uniform or piecewise uniform geomagnetic field.
Table 2: Geomagnetic Field Scaling Factors for the
Benchmark and Supplemental GMD
Events
Geomagnetic Latitude
(Degrees)
Scaling Factor1
(α)
≤ 40
0.10
45
0.2
50
0.3
54
0.5
56
0.6
57
0.7
58
0.8
59
0.9
≥ 60
1.0
Scaling the Geoelectric Field
The benchmark GMD event is defined for the reference Quebec earth model described in Table
4. The peak geoelectric field, E peak , used in a GMD Vulnerability Assessment may be obtained by
either:
•
Calculating the geoelectric field for the ground conductivity in the planning area and the
reference geomagnetic field time series scaled according to geomagnetic latitude, using
a procedure such as the plane wave method described in the NERC GMD Task Force GIC
Application Guide; 3 or
•
Using the earth conductivity scaling factor β from Table 3 that correlates to the ground
conductivity map in Figure 1 or Figure 2. Along with the scaling factor α from equation
(3) or Table 2, β is applied to the reference geoelectric field using equation (1 or 2, as
applicable) to obtain the regional geoelectric field peak amplitude E peak to be used in
GMD Vulnerability Assessments. When a ground conductivity model is not available, the
planningresponsible entity should use the largest β factor of adjacent physiographic
regions or a technically justified value.
Available at the NERC GMD Task Force project webpage: http://www.nerc.com/comm/PC/Pages/Geomagnetic-DisturbanceTask-Force-(GMDTF)-2013.aspx.
3
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The earth models used to calculate Table 3 for the United States were obtained from publicly
available information published on the U. S. Geological Survey website. 4 The models used to
calculate Table 3 for Canada were obtained from Natural Resources Canada (NRCan) and reflect
the average structure for large regions. A planner can also use specific earth model(s) with
documented justification and the reference geomagnetic field time series to calculate the β
factor(s) as follows:
𝛽𝛽𝑏𝑏 = 𝐸𝐸 ⁄8 for the benchmark GMD event
(4)
𝛽𝛽𝑠𝑠 = 𝐸𝐸 ⁄12 for the supplemental GMD
(5)
where, E is the absolute value of peak geoelectric in V/km obtained from the technically justified
earth model and the reference geomagnetic field time series.
For large planning areas that span more than one β scaling factor, the most conservative (largest)
value for β may be used in determining the peak geoelectric field to obtain conservative results.
Alternatively, a planner could perform analysis using a non-uniform or piecewise uniform
geoelectric field.
Applying the Localized Peak Geoelectric Field in the Supplemental GMD Event
The peak geoelectric field of the supplemental GMD event occurs in a localized area.5 Planners
have flexibility to determine how to apply the localized peak geoelectric field over the planning
area in performing GIC calculations. Examples of approaches are:
•
Apply the peak geoelectric field (12 V/km scaled to the planning area) over the entire
planning area;
•
Apply a spatially limited (12 V/km scaled to the planning area) peak geoelectric field (e.g.,
100 km in North-South latitude direction and 500 km in East-West longitude direction)
over a portion(s) of the system, and apply the benchmark GMD event over the rest of the
system; or
•
Other methods to adjust the benchmark GMD event analysis to account for the localized
geoelectric field enhancement of the supplemental GMD event.
Available at http://geomag.usgs.gov/conductivity/.
See the Supplemental Geomagnetic Disturbance Description white paper located on the Project 2013-03 Geomagnetic
Disturbance Mitigation project webpage: http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspx.
4
5
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TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
FL-1
Figure 1: Physiographic Regions of the Continental United States 6
Figure 2: Physiographic Regions of Canada
6
Additional map detail is available at the U.S. Geological Survey: http://geomag.usgs.gov/.
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Table 3: Geoelectric Field Scaling Factors
Final Draft of TPL-007-4
November 2019
Earth model
Scaling Factor
Benchmark Event
(β b )
Scaling Factor
Supplemental
Event
(β s )
AK1A
0.56
0.51
AK1B
0.56
0.51
AP1
0.33
0.30
AP2
0.82
0.78
BR1
0.22
0.22
CL1
0.76
0.73
CO1
0.27
0.25
CP1
0.81
0.77
CP2
0.95
0.86
FL1
0.76
0.73
CS1
0.41
0.37
IP1
0.94
0.90
IP2
0.28
0.25
IP3
0.93
0.90
IP4
0.41
0.35
NE1
0.81
0.77
PB1
0.62
0.55
PB2
0.46
0.39
PT1
1.17
1.19
SL1
0.53
0.49
SU1
0.93
0.90
BOU
0.28
0.24
FBK
0.56
0.56
PRU
0.21
0.22
BC
0.67
0.62
PRAIRIES
0.96
0.88
SHIELD
1.0
1.0
ATLANTIC
0.79
0.76
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Scaling factors in Table 3 are dependent upon the frequency content of the reference storm.
Consequently, the benchmark GMD event and the supplemental GMD event may produce
different scaling factors for a given earth model.
Rationale: Scaling factors in Table 3 are dependent upon the frequency content of the reference
storm. Consequently, the benchmark GMD event and the supplemental GMD event may produce
different scaling factors for a given earth model.
The scaling factor associated with the benchmark GMD event for the Florida earth model (FL1)
has been updated based on the earth model published on the USGS public website.
Table 4: Reference Earth Model (Quebec)
Layer Thickness (km)
Resistivity (Ω-m)
15
20,000
10
200
125
1,000
200
100
∞
3
Reference Geomagnetic Field Time Series or Waveform for the Benchmark GMD
Event7
The geomagnetic field measurement record of the March 13-14 1989 GMD event, measured at
the NRCan Ottawa geomagnetic observatory, is the basis for the reference geomagnetic field
waveform to be used to calculate the GIC time series, GIC(t), required for transformer thermal
impact assessment.
The geomagnetic latitude of the Ottawa geomagnetic observatory is 55°; therefore, the
amplitudes of the geomagnetic field measurement data were scaled up to the 60° reference
geomagnetic latitude (see Figure 3) such that the resulting peak geoelectric field amplitude
computed using the reference earth model was 8 V/km (see Figures 4 and 5). The sampling rate
for the geomagnetic field waveform is 10 seconds.8 To use this geoelectric field time series when
a different earth model is applicable, it should be scaled with the appropriate benchmark
conductivity scaling factor β b .
Refer to the Benchmark Geomagnetic Disturbance Event Description white paper for details on the determination of the
reference geomagnetic field waveform: http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx.
8 The data file of the benchmark geomagnetic field waveform is available on the Related Information webpage for TPL-007-1:
http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx.
7
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Figure 3: Benchmark Geomagnetic Field Waveform
Red B n (Northward), Blue B e (Eastward)
Figure 4: Benchmark Geoelectric Field Waveform
E E (Eastward)
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Figure 5: Benchmark Geoelectric Field Waveform
E N (Northward)
Reference Geomagnetic Field Time Series or Waveform for the Supplemental GMD
Event9
The geomagnetic field measurement record of the March 13-14, 1989 GMD event, measured at
the NRCan Ottawa geomagnetic observatory, is the basis for the reference geomagnetic field
waveform to be used to calculate the GIC time series, GIC(t), required for transformer thermal
impact assessment for the supplemental GMD event. The supplemental GMD event waveform
differs from the benchmark GMD event waveform in that the supplemental GMD event
waveform has a local enhancement.
The geomagnetic latitude of the Ottawa geomagnetic observatory is 55°; therefore, the
amplitudes of the geomagnetic field measurement data were scaled up to the 60° reference
geomagnetic latitude (see Figure 6) such that the resulting peak geoelectric field amplitude
computed using the reference earth model was 12 V/km (see Figure7). The sampling rate for the
geomagnetic field waveform is 10 seconds. 10 To use this geoelectric field time series when a
different earth model is applicable, it should be scaled with the appropriate supplemental
conductivity scaling factor β s .
Refer to the Supplemental Geomagnetic Disturbance Event Description white paper for details on the determination of the
reference geomagnetic field waveform: http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-DisturbanceMitigation.aspx.
10 The data file of the benchmark geomagnetic field waveform is available on the NERC GMD Task Force project webpage:
http://www.nerc.com/comm/PC/Pages/Geomagnetic-Disturbance-Task-Force-(GMDTF)-2013.aspx.
9
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TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
4000
2000
Time (min)
200
400
600
800
1000
1200
1400
1600
1800
2000
Bx, By (nT)
0
-2000
-4000
-6000
-8000
-10000
Figure 6: Supplemental Geomagnetic Field Waveform
Red B N (Northward), Blue B E (Eastward)
12 V/km
Figure 7: Supplemental Geoelectric Field Waveform
Blue E N (Northward), Red E E (Eastward)
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TPL-007-34 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Attachment 1-CAN
Attachment 1-CAN provides an alternative that a Canadian entity may use in lieu of the
benchmark or supplemental GMD event(s) defined in Attachment 1 for performing GMD
Vulnerability Assessment(s).
A Canadian entity may use the provisions of Attachment 1-CAN if it has regionally specific
information that provides a technically justified means to re-define a 1-in-100 year GMD
planning event(s) within its planning area.
Information for the Alternative Methodology
GMD Vulnerability Assessment(s) require the use of geophysical and engineering models.
Canadian-specific data is available and growing. Ongoing research allows for more accurate
characterization of regional parameters used in these models. Such Canadian-specific data
includes geomagnetic field, earth conductivity, and geomagnetically induced current
measurements that can be used for modeling and simulation validation.
Information used to calculate geoelectric fields for the benchmark and supplemental GMD events
shall be clearly documented and technically justified. For example, the factors involved in the
calculation of geoelectric fields are geomagnetic field variations and an earth transfer
function(s). [1] 1 Technically justified information used in modelling geomagnetic field variations
may include: technical documents produced by governmental entities such as Natural Resources
Canada; technical papers published in peer-reviewed journals; and data sets gathered using
sound scientific principles. An earth transfer function may rely on magnetotelluric measurements
or earth conductivity models.
Modeling assumptions shall also be clearly documented and technically justified. An entity may
use sensitivity analysis to identify how the assumptions affect the results.
A simplified model may be used to perform a GMD Vulnerability Assessment(s), as long as the
model is more conservative than a more detailed model.
When interpreting assessment results, the entity shall consider the maturity of the modeling,
toolset, and techniques applied.
Geomagnetic Disturbance Planning Events
The 1-in-100 year planning event shall be based on regionally specific data and technically
justifiable statistical analyses (e.g., extreme value theory) and applied to the benchmark and
supplemental GMD Vulnerability Assessment(s).
The “earth transfer function” is the relationship between the electric fields and magnetic field variations at the surface of the
earth.
1 The “earth transfer function” is the relationship between the electric fields and magnetic field variations at the surface of the
earth.
[1]
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For the benchmark GMD Vulnerability Assessment(s), an entity shall consider the large-scale
spatial structure of the GMD event. For the supplemental GMD Vulnerability Assessment(s), an
entity shall consider the small-scale spatial structure of the GMD event (e.g., using magnetometer
measurements or realistic electrojet calculations).
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TPL-007-34 – Supplemental Material
Guidelines and Technical Basis
The diagram below provides an overall view of the GMD Vulnerability Assessment process:
Geomagnetic
Field
B(t)
Earth
Conductivity
Model
Potential
Mitigation
Measures
Geoelectric
Field
E(t)
dc
System
Model
GIC
Transformer vars
Model
(Electrical)
GIC(t)
Power Flow
Analysis
Transformer
Model
(Thermal)
Fail
Bus
Voltages
Line Loading &
var Reserves
Assessment
Criteria
Operating
Procedures
and
Pass
Mitigation
Measures
(if needed)
Temp(t)
Critical Temperatures
The requirements in this standard cover various aspects of the GMD Vulnerability Assessment
process.
Benchmark GMD Event (Attachment 1)
The benchmark GMD event defines the geoelectric field values used to compute GIC flows that
are needed to conduct a benchmark GMD Vulnerability Assessment. The Benchmark
Geomagnetic Disturbance Event Description, May 2016 11 white paper includes the event
description, analysis, and example calculations.
Supplemental GMD Event (Attachment 1)
The supplemental GMD event defines the geoelectric field values used to compute GIC flows that
are needed to conduct a supplemental GMD Vulnerability Assessment. The Supplemental
Geomagnetic Disturbance Event Description, October 2017 12 white paper includes the event
description and analysis.
Requirement R2
A GMD Vulnerability Assessment requires a GIC System model, which is a dc representation of
the System, to calculate GIC flow. In a GMD Vulnerability Assessment, GIC simulations are used
to determine transformer Reactive Power absorption and transformer thermal response. Details
for developing the GIC System model are provided in the NERC GMD Task Force guide:
Application Guide for Computing Geomagnetically-Induced Current in the Bulk Power System,
December 2013.13
Underground pipe-type cables present a special modeling situation in that the steel pipe that
encloses the power conductors significantly reduces the geoelectric field induced into the
http://www.nerc.com/pa/stand/Pages/TPL0071RI.aspx.
http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-Disturbance-Mitigation.aspx.
13 http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GIC%20Application
%20Guide%202013_approved.pdf.
11
12
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TPL-007-34 – Supplemental Material
conductors themselves, while they remain a path for GIC. Solid dielectric cables that are not
enclosed by a steel pipe will not experience a reduction in the induced geoelectric field. A
planning entity should account for special modeling situations in the GIC system model, if
applicable.
Requirement R4
The Geomagnetic Disturbance Planning Guide, 14 December 2013 developed by the NERC GMD
Task Force provides technical information on GMD-specific considerations for planning studies.
Requirement R5
The benchmark thermal impact assessment of transformers specified in Requirement R6 is based
on GIC information for the benchmark GMD Event. This GIC information is determined by the
planning entity through simulation of the GIC System model and must be provided to the entity
responsible for conducting the thermal impact assessment. GIC information should be provided
in accordance with Requirement R5 each time the GMD Vulnerability Assessment is performed
since, by definition, the GMD Vulnerability Assessment includes a documented evaluation of
susceptibility to localized equipment damage due to GMD.
The maximum effective GIC value provided in Part 5.1 is used for the benchmark thermal impact
assessment. Only those transformers that experience an effective GIC value of 75 A or greater
per phase require evaluation in Requirement R6.
GIC(t) provided in Part 5.2 is used to convert the steady state GIC flows to time-series GIC data
for the benchmark thermal impact assessment of transformers. This information may be needed
by one or more of the methods for performing a benchmark thermal impact assessment.
Additional information is in the following section and the Transformer Thermal Impact
Assessment White Paper, 15 October 2017.
The peak GIC value of 75 Amps per phase has been shown through thermal modeling to be a
conservative threshold below which the risk of exceeding known temperature limits established
by technical organizations is low.
Requirement R6
The benchmark thermal impact assessment of a power transformer may be based on
manufacturer-provided GIC capability curves, thermal response simulation, thermal impact
screening, or other technically justified means. Approaches for conducting the assessment are
presented in the Transformer Thermal Impact Assessment White Paper ERO Enterprise-Endorsed
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GMD%20Planning
%20Guide_approved.pdf.
15 http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-Disturbance-Mitigation.aspx.
14
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Implementation Guidance 16 for this requirement. This ERO-Endorsed document is posted on the
NERC Compliance Guidance 17 webpage.
Transformers are exempt from the benchmark thermal impact assessment requirement if the
effective GIC value for the transformer is less than 75 A per phase, as determined by a GIC analysis
of the System. Justification for this criterion is provided in the Screening Criterion for Transformer
Thermal Impact Assessment White Paper, 18 October 2017. A documented design specification
exceeding this value is also a justifiable threshold criterion that exempts a transformer from
Requirement R6.
The benchmark threshold criteria and its associated transformer thermal impact must be
evaluated on the basis of effective GIC. Refer to the white papers for additional information.
Requirement R7
Technical considerations for GMD mitigation planning, including operating and equipment
strategies, are available in Chapter 5 of the Geomagnetic Disturbance Planning Guide, 19
December 2013. Additional information is available in the 2012 Special Reliability Assessment
Interim Report: Effects of Geomagnetic Disturbances on the Bulk-Power System, 20 February 2012.
Requirement R8
The Geomagnetic Disturbance Planning Guide, 21 December 2013 developed by the NERC GMD
Task Force provides technical information on GMD-specific considerations for planning studies.
The supplemental GMD Vulnerability Assessment process is similar to the benchmark GMD
Vulnerability Assessment process described under Requirement R4.
Requirement R9
The supplemental thermal impact assessment specified of transformers in Requirement R10 is
based on GIC information for the supplemental GMD Event. This GIC information is determined
by the planning entity through simulation of the GIC System model and must be provided to the
entity responsible for conducting the thermal impact assessment. GIC information should be
provided in accordance with Requirement R9 each time the GMD Vulnerability Assessment is
performed since, by definition, the GMD Vulnerability Assessment includes a documented
evaluation of susceptibility to localized equipment damage due to GMD.
http://www.nerc.com/pa/comp/guidance/EROEndorsedImplementationGuidance/TPL-007-1_Transformer_Thermal_Impact_
Assessment_White_Paper.pdf.
17 http://www.nerc.com/pa/comp/guidance/Pages/default.aspx.
18 http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-Disturbance-Mitigation.aspx.
19 http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GMD%20Planning
%20Guide_approved.pdf.
20 http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2012GMD.pdf.
21 http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GMD%20Planning
%20Guide_approved.pdf.
16
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TPL-007-34 – Supplemental Material
The maximum effective GIC value provided in Part 9.1 is used for the supplemental thermal
impact assessment. Only those transformers that experience an effective GIC value of 85 A or
greater per phase require evaluation in Requirement R10.
GIC(t) provided in Part 9.2 is used to convert the steady state GIC flows to time-series GIC data
for the supplemental thermal impact assessment of transformers. This information may be
needed by one or more of the methods for performing a supplemental thermal impact
assessment. Additional information is in the following section.
The peak GIC value of 85 Amps per phase has been shown through thermal modeling to be a
conservative threshold below which the risk of exceeding known temperature limits established
by technical organizations is low.
Requirement R10
The supplemental thermal impact assessment of a power transformer may be based on
manufacturer-provided GIC capability curves, thermal response simulation, thermal impact
screening, or other technically justified means. Approaches for conducting the assessment are
presented in the Transformer Thermal Impact Assessment White Paper ERO Enterprise-Endorsed
Implementation Guidance 22 discussed in the Requirement R6 section above. A later version of the
Transformer Thermal Impact Assessment White Paper, 23 October 2017, has been developed to
include updated information pertinent to the supplemental GMD event and supplemental
thermal impact assessment.
Transformers are exempt from the supplemental thermal impact assessment requirement if the
effective GIC value for the transformer is less than 85 A per phase, as determined by a GIC analysis
of the System. Justification for this criterion is provided in the revised Screening Criterion for
Transformer Thermal Impact Assessment White Paper, 24 October 2017. A documented design
specification exceeding this value is also a justifiable threshold criterion that exempts a
transformer from Requirement R10.
The supplemental threshold criteria and its associated transformer thermal impact must be
evaluated on the basis of effective GIC. Refer to the white papers for additional information.
Requirement R11
Technical considerations for GIC monitoring are contained in Chapter 6 of the 2012 Special
Reliability Assessment Interim Report: Effects of Geomagnetic Disturbances on the Bulk-Power
System, 25 February 2012. GIC monitoring is generally performed by Hall effect transducers that
are attached to the neutral of the wye-grounded transformer. Data from GIC monitors is useful
for model validation and situational awareness.
http://www.nerc.com/pa/comp/guidance/EROEndorsedImplementationGuidance/TPL-007-1_Transformer_Thermal_Impact_
Assessment_White_Paper.pdf.
23 http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-Disturbance-Mitigation.aspx.
24 http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-Disturbance-Mitigation.aspx.
25 http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2012GMD.pdf.
22
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Responsible entities consider the following in developing a process for obtaining GIC monitor
data:
•
Monitor locations. An entity's operating process may be constrained by location of
existing GIC monitors. However, when planning for additional GIC monitoring installations
consider that data from monitors located in areas found to have high GIC based on system
studies may provide more useful information for validation and situational awareness
purposes. Conversely, data from GIC monitors that are located in the vicinity of
transportation systems using direct current (e.g., subways or light rail) may be unreliable.
•
Monitor specifications. Capabilities of Hall effect transducers, existing and planned,
should be considered in the operating process. When planning new GIC monitor
installations, consider monitor data range (e.g., -500 A through + 500 A) and ambient
temperature ratings consistent with temperatures in the region in which the monitor will
be installed.
•
Sampling Interval. An entity's operating process may be constrained by capabilities of
existing GIC monitors. However, when possible specify data sampling during periods of
interest at a rate of 10 seconds or faster.
•
Collection Periods. The process should specify when the entity expects GIC data to be
collected. For example, collection could be required during periods where the Kp index is
above a threshold, or when GIC values are above a threshold. Determining when to
discontinue collecting GIC data should also be specified to maintain consistency in data
collection.
•
Data format. Specify time and value formats. For example, Greenwich Mean Time (GMT)
(MM/DD/YYYY HH:MM:SS) and GIC Value (Ampere). Positive (+) and negative (-) signs
indicate direction of GIC flow. Positive reference is flow from ground into transformer
neutral. Time fields should indicate the sampled time rather than system or SCADA time
if supported by the GIC monitor system.
•
Data retention. The entity's process should specify data retention periods, for example 1
year. Data retention periods should be adequately long to support availability for the
entity's model validation process and external reporting requirements, if any.
•
Additional information. The entity's process should specify collection of other
information necessary for making the data useful, for example monitor location and type
of neutral connection (e.g., three-phase or single-phase).
Requirement R12
Magnetometers measure changes in the earth's magnetic field. Entities should obtain data from
the nearest accessible magnetometer. Sources of magnetometer data include:
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•
Observatories such as those operated by U.S. Geological Survey and Natural Resources
Canada, see figure below for locations: 26
•
•
Research institutions and academic universities;
Entities with installed magnetometers.
Entities that choose to install magnetometers should consider equipment specifications and data
format protocols contained in the latest version of the INTERMAGNET Technical Reference
Manual, Version 4.6, 2012. 27
26
27
http://www.intermagnet.org/index-eng.php.
http://www.intermagnet.org/publications/intermag_4-6.pdf.
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Rationale
During development of TPL-007-1, text boxes were embedded within the standard to explain the
rationale for various parts of the standard. The text from the rationale text boxes was moved to
this section upon approval of TPL-007-1 by the NERC Board of Trustees. In developing TPL-007-2,
the SDT has made changes to the sections below only when necessary for clarity. Changes are
marked with brackets [ ].
Rationale for Applicability:
Instrumentation transformers and station service transformers do not have significant impact on
geomagnetically-induced current (GIC) flows; therefore, these transformers are not included in
the applicability for this standard.
Terminal voltage describes line-to-line voltage.
Rationale for R1:
In some areas, planning entities may determine that the most effective approach to conduct a
GMD Vulnerability Assessment is through a regional planning organization. No requirement in
the standard is intended to prohibit a collaborative approach where roles and responsibilities are
determined by a planning organization made up of one or more Planning Coordinator(s).
Rationale for R2:
A GMD Vulnerability Assessment requires a GIC System model to calculate GIC flow which is used
to determine transformer Reactive Power absorption and transformer thermal response.
Guidance for developing the GIC System model is provided in the Application Guide Computing
Geomagnetically-Induced Current in the Bulk-Power System,28 December 2013, developed by the
NERC GMD Task Force.
The System model specified in Requirement R2 is used in conducting steady state power flow
analysis that accounts for the Reactive Power absorption of power transformer(s) due to GIC in
the System.
The GIC System model includes all power transformer(s) with a high side, wye-grounded winding
with terminal voltage greater than 200 kV. The model is used to calculate GIC flow in the network.
The projected System condition for GMD planning may include adjustments to the System that
are executable in response to space weather information. These adjustments could include, for
example, recalling or postponing maintenance outages.
The Violation Risk Factor (VRF) for Requirement R2 is changed from Medium to High. This change
is for consistency with the VRF for approved standard TPL-001-4 Requirement R1, which is
proposed for revision in the NERC filing dated August 29, 2014 (Docket No. RM12-1-000). NERC
guidelines require consistency among Reliability Standards.
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GIC%20Application
%20Guide%202013_approved.pdf.
28
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Rationale for R3:
Requirement R3 allows a responsible entity the flexibility to determine the System steady state
voltage criteria for System steady state performance in Table 1. Steady state voltage limits are
an example of System steady state performance criteria.
Rationale for R4:
The GMD Vulnerability Assessment includes steady state power flow analysis and the supporting
study or studies using the models specified in Requirement R2 that account for the effects of GIC.
Performance criteria are specified in Table 1.
At least one System On-Peak Load and at least one System Off-Peak Load must be examined in
the analysis.
Distribution of GMD Vulnerability Assessment results provides a means for sharing relevant
information with other entities responsible for planning reliability. Results of GIC studies may
affect neighboring systems and should be taken into account by planners.
The Geomagnetic Disturbance Planning Guide, 29 December 2013 developed by the NERC GMD
Task Force provides technical information on GMD-specific considerations for planning studies.
The provision of information in Requirement R4, Part 4.3, shall be subject to the legal and
regulatory obligations for the disclosure of confidential and/or sensitive information.
Rationale for R5:
This GIC information is necessary for determining the thermal impact of GIC on transformers in
the planning area and must be provided to entities responsible for performing the thermal impact
assessment so that they can accurately perform the assessment. GIC information should be
provided in accordance with Requirement R5 as part of the GMD Vulnerability Assessment
process since, by definition, the GMD Vulnerability Assessment includes documented evaluation
of susceptibility to localized equipment damage due to GMD.
The maximum effective GIC value provided in Part 5.1 is used for transformer thermal impact
assessment.
GIC(t) provided in Part 5.2 can alternatively be used to convert the steady state GIC flows to timeseries GIC data for transformer thermal impact assessment. This information may be needed by
one or more of the methods for performing a thermal impact assessment. Additional guidance is
available in the Transformer Thermal Impact Assessment White Paper, 30 October 2017.
A Transmission Owner or Generator Owner that desires GIC(t) may request it from the planning
entity. The planning entity shall provide GIC(t) upon request once GIC has been calculated, but
http://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GMD%20Planning
%20Guide_approved.pdf.
30 http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-Disturbance-Mitigation.aspx.
29
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TPL-007-34 – Supplemental Material
no later than 90 calendar days after receipt of a request from the owner and after completion of
Requirement R5, Part 5.1.
The provision of information in Requirement R5 shall be subject to the legal and regulatory
obligations for the disclosure of confidential and/or sensitive information.
Rationale for R6:
The transformer thermal impact screening criterion has been revised from 15 A per phase to 75
A per phase [for the benchmark GMD event]. Only those transformers that experience an
effective GIC value of 75 A per phase or greater require evaluation in Requirement R6. The
justification is provided in the Screening Criterion for Transformer Thermal Impact Assessment
White Paper, 31 October 2017.
The thermal impact assessment may be based on manufacturer-provided GIC capability curves,
thermal response simulation, thermal impact screening, or other technically justified means. The
transformer thermal assessment will be repeated or reviewed using previous assessment results
each time the planning entity performs a GMD Vulnerability Assessment and provides GIC
information as specified in Requirement R5. Approaches for conducting the assessment are
presented in the Transformer Thermal Impact Assessment White Paper, 32 October 2017.
Thermal impact assessments are provided to the planning entity, as determined in Requirement
R1, so that identified issues can be included in the GMD Vulnerability Assessment (R4), and the
Corrective Action Plan (R7) as necessary.
Thermal impact assessments of non-BES transformers are not required because those
transformers do not have a wide-area effect on the reliability of the interconnected Transmission
system.
The provision of information in Requirement R6, Part 6.4, shall be subject to the legal and
regulatory obligations for the disclosure of confidential and/or sensitive information.
Rationale for R7:
The proposed requirement addresses directives in Order No. 830 for establishing Corrective
Action Plan (CAP) deadlines associated with GMD Vulnerability Assessments. In Order No. 830,
FERC directed revisions to TPL-007 such that CAPs are developed within one year from the
completion of GMD Vulnerability Assessments (P 101). Furthermore, FERC directed
establishment of implementation deadlines after the completion of the CAP as follows (P 102):
•
Two years for non-hardware mitigation; and
•
Four years for hardware mitigation.
The objective of Part 7.4 is to provide awareness to potentially impacted entities when
implementation of planned mitigation is not achievable within the deadlines established in Part
31
32
http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-Disturbance-Mitigation.aspx.
http://www.nerc.com/pa/Stand/Pages/Project-2013-03-Geomagnetic-Disturbance-Mitigation.aspx.
Final Draft of TPL-007-4
November 2019
Page 49 of 51
TPL-007-34 – Supplemental Material
7.3. Examples of situations beyond the control of the of the responsible entity (see Section 7.4)
include, but are not limited to:
•
Delays resulting from regulatory/legal processes, such as permitting;
•
Delays resulting from stakeholder processes required by tariff;
•
Delays resulting from equipment lead times; or
Delays resulting from the inability to acquire necessary Right-of-Way.
Rationale for Table 3:
Table 3 has been revised to use the same ground model designation, FL1, as is being used by
USGS. The calculated scaling factor for FL1 is 0.74. [The scaling factor associated with the
benchmark GMD event for the Florida earth model (FL1) has been updated to 0.76 in TPL-007-2
based on the earth model published on the USGS public website.]
Rationale for R8 – R10:
The proposed requirements address directives in Order No. 830 for revising the benchmark GMD
event used in GMD Vulnerability Assessments (P 44, P 47-49). The requirements add a
supplemental GMD Vulnerability Assessment based on the supplemental GMD event that
accounts for localized peak geoelectric fields.
Rationale for R11 – R12:
The proposed requirements address directives in Order No. 830 for requiring responsible
entities to collect GIC monitoring and magnetometer data as necessary to enable model
validation and situational awareness (P 88; P. 90-92). GMD measurement data refers to GIC
monitor data and geomagnetic field data in Requirements R11 and R12, respectively. See the
Guidelines and Technical Basis section of this standard for technical information.
The objective of Requirement R11 is for entities to obtain GIC data for the Planning
Coordinator's planning area or other part of the system included in the Planning Coordinator's
GIC System model to inform GMD Vulnerability Assessments. Technical considerations for GIC
monitoring are contained in Chapter 9 of the 2012 Special Reliability Assessment Interim
Report: Effects of Geomagnetic Disturbances on the Bulk-Power System (NERC 2012 GMD
Report). GIC monitoring is generally performed by Hall effect transducers that are attached to
the neutral of the transformer and measure dc current flowing through the neutral.
The objective of Requirement R12 is for entities to obtain geomagnetic field data for the
Planning Coordinator's planning area to inform GMD Vulnerability Assessments.
Magnetometers provide geomagnetic field data by measuring changes in the earth's magnetic
field. Sources of geomagnetic field data include:
•
Observatories such as those operated by U.S. Geological Survey, Natural Resources
Canada, research organizations, or university research facilities;
•
Installed magnetometers; and
•
Commercial or third-party sources of geomagnetic field data.
Final Draft of TPL-007-4
November 2019
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TPL-007-34 – Supplemental Material
Geomagnetic field data for a Planning Coordinator’s planning area is obtained from one or
more of the above data sources located in the Planning Coordinator’s planning area, or by
obtaining a geomagnetic field data product for the Planning Coordinator’s planning area from a
government or research organization. The geomagnetic field data product does not need to be
derived from a magnetometer or observatory within the Planning Coordinator’s planning area.
Final Draft of TPL-007-4
November 2019
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Implementation Plan
Project 2019-01 Modifications to TPL-007-3
Applicable Standard
•
TPL-007-4 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Requested Retirement
•
TPL-007-3 – Transmission System Planned Performance for Geomagnetic Disturbance Events
Prerequisite Standard
None
Applicable Entities
•
Planning Coordinator with a planning area that includes a Facility or Facilities specified in Section 4.2 of
the standard;
•
Transmission Planner with a planning area that includes a Facility or Facilities specified in Section 4.2 of
the standard;
•
Transmission Owner who owns a Facility or Facilities specified in Section 4.2 of the standard; and
•
Generator Owner who owns a Facility or Facilities specified in Section 4.2 of the standard.
Section 4.2 states that the standard applies to facilities that include power transformer(s) with a high-side,
wye-grounded winding with terminal voltage greater than 200 kV.
Terms in the NERC Glossary of Terms
There are no new, modified, or retired terms.
Background
On November 15, 2018, the Federal Energy Regulatory Commission (FERC) issued Order No. 851 approving
Reliability Standard TPL-007-2 and its associated implementation plan. In the order, FERC also directed
NERC to develop certain modifications to the standard. FERC established a deadline of 12 months from the
effective date of Reliability Standard TPL-007-2 to submit a revised standard (July 1, 2020).
On February 7, 2019, the NERC Board of Trustees adopted Reliability Standard TPL-007-3, which added a
Variance option for applicable entities in Canadian jurisdictions. No continent-wide requirements were
changed. Under the terms of its implementation plan, Reliability Standard TPL-007-3 became effective in
the United States on July 1, 2019. All phased-in compliance dates from the TPL-007-2 implementation plan
were carried forward unchanged in the TPL-007-3 implementation plan.
RELIABILITY | RESILIENCE | SECURITY
General Considerations
This implementation plan is intended to integrate the new and revised requirements in TPL-007-4 in the
existing timeframe under the TPL-007-3 implementation plan.
Effective Date
The effective date for the proposed Reliability Standard is provided below. Where the standard drafting
team identified the need for a longer implementation period for compliance with a particular section of
the proposed Reliability Standard (e.g., an entire Requirement or a portion thereof), the additional time for
compliance with that section is specified below. These phased-in compliance dates represent the dates
that entities must begin to comply with that particular section of the Reliability Standard, even where the
Reliability Standard goes into effect at an earlier date.
Reliability Standard TPL-007-4
Where approval by an applicable governmental authority is required, the standard shall become effective
on the first day of the first calendar quarter that is six (6) months after the effective date of the applicable
governmental authority’s order approving the standard, or as otherwise provided for by the applicable
governmental authority.
Where approval by an applicable governmental authority is not required, the standard shall become
effective on the first day of the first calendar quarter that is six (6) months after the date the standard is
adopted by the NERC Board of Trustees, or as otherwise provided for in that jurisdiction.
Phased-In Compliance Dates
Compliance Date for TPL-007-4 Requirements R1, R2, R5, and R9
Entities shall be required to comply with Requirements R1, R2, R5, and R9 upon the effective date of
Reliability Standard TPL-007-4.
Compliance Date for TPL-007-4 Requirements R12 and R13
Entities shall not be required to comply with Requirements R12 and R13 until the later of: (i) July 1, 2021;
or (ii) the effective date of Reliability Standard TPL-007-4.
Compliance Date for TPL-007-4 Requirements R6 and R10
Entities shall not be required to comply with Requirements R6 and R10 until the later of: (i) January 1,
2022; or (ii) the effective date of Reliability Standard TPL-007-4.
Compliance Date for TPL-007-4 Requirements R3, R4, and R8
Entities shall not be required to comply with Requirements R3, R4, and R8 until the later of: (i) January 1,
2023; or (ii) the effective date of Reliability Standard TPL-007-4.
Compliance Date for TPL-007-4 Requirement R7
Entities shall not be required to comply with Requirement R7 until the later of: (i) January 1, 2024; or (ii)
the effective date of Reliability Standard TPL-007-4.
Implementation Plan
Project 2019-01 Modifications to TPL-007-3 | November 2019
2
Compliance Date for TPL-007-4 Requirement R11
Entities shall not be required to comply with Requirement R11 until the later of: (i) January 1, 2024; or (ii)
six (6) months after the effective date of Reliability Standard TPL-007-4.
Retirement Date
Standard TPL-007-3
Reliability Standard TPL-007-3 shall be retired immediately prior to the effective date of TPL-007-4 in the
particular jurisdiction in which the revised standard is becoming effective.
Initial Performance of Periodic Requirements
Transmission Owners and Generator Owners are not required to comply with Requirement R6 prior to the
compliance date for Requirement R6, regardless of when geomagnetically-induced current (GIC) flow
information specified in Requirement R5, Part 5.1 is received.
Transmission Owners and Generator Owners are not required to comply with Requirement R10 prior to
the compliance date for Requirement R10, regardless of when GIC flow information specified in
Requirement R9, Part 9.1 is received.
Implementation Plan
Project 2019-01 Modifications to TPL-007-3 | November 2019
3
Transmission System
Planned Performance for
Geomagnetic Disturbance
Events
Technical Rationale and Justification for
Reliability Standard TPL-007-4
November 2019
RELIABILITY | RESILIENCE | SECURITY
NERC | Report Title | Report Date
I
Table of Contents
Preface ....................................................................................................................................................................... iii
Introduction ............................................................................................................................................................... iv
Background ............................................................................................................................................................ iv
General Considerations ..............................................................................................................................................1
Rationale for Applicability.......................................................................................................................................1
Benchmark GMD Event (TPL-007-4 Attachment 1) .................................................................................................1
Supplemental GMD Event (TPL-007-4 Attachment 1) .............................................................................................1
Requirement R2..........................................................................................................................................................2
Requirement R4..........................................................................................................................................................3
Requirement R5..........................................................................................................................................................4
Requirement R6..........................................................................................................................................................5
Requirement R7..........................................................................................................................................................6
Supplemental GMD Vulnerability Assessment ...........................................................................................................7
Requirement R8..........................................................................................................................................................8
Requirement R9..........................................................................................................................................................9
Requirement R10..................................................................................................................................................... 10
Requirement R11..................................................................................................................................................... 11
Requirement R12..................................................................................................................................................... 12
Requirement R13..................................................................................................................................................... 13
References ............................................................................................................................................................... 14
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
ii
Preface
Electricity is a key component of the fabric of modern society and the Electric Reliability Organization (ERO)
Enterprise serves to strengthen that fabric. The vision for the ERO Enterprise, which is comprised of the North
American Electric Reliability Corporation (NERC) and the six Regional Entities (REs), is a highly reliable and secure
North American bulk power system (BPS). Our mission is to assure the effective and efficient reduction of risks to
the reliability and security of the grid.
Reliability | Resilience | Security
Because nearly 400 million citizens in North America are counting on us
The North American BPS is divided into six RE boundaries as shown in the map and corresponding table below.
The multicolored area denotes overlap as some load-serving entities participate in one Region while associated
Transmission Owners/Operators participate in another.
MRO
Midwest Reliability Organization
NPCC
Northeast Power Coordinating Council
RF
ReliabilityFirst
SERC
SERC Reliability Corporation
Texas RE
Texas Reliability Entity
WECC
Western Electricity Coordinating Council
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
iii
Introduction
Background
This document explains the technical rationale and justification for the proposed Reliability Standard TPL-007-4 –
Transmission System Planned Performance for Geomagnetic Disturbance Events. It provides stakeholders and the
ERO Enterprise with an understanding of the technical requirements in the Reliability Standard. It also contains
information on the standard drafting team’s intent in drafting the requirements. This document, the Technical
Rationale and Justification for TPL-007-4, is not a Reliability Standard and should not be considered mandatory
and enforceable.
The first version of the standard, TPL-007-1, approved by FERC in Order No. 779 [1], requires entities to assess the
impact to their systems from a defined event referred to as the “Benchmark GMD Event.” The second version of
the standard, TPL-007-2, adds new Requirements R8, R9, and R10 to require responsible entities to assess the
potential implications of a “Supplemental GMD Event” on their equipment and systems in accordance with FERC’s
directives in Order No. 830 [2]. Some GMD events have shown localized enhancements of the geomagnetic field.
The supplemental GMD event was developed to represent conditions associated with such localized enhancement
during a severe GMD event for use in a GMD Vulnerability Assessment. The third version of the standard, TPL007-3, adds a Canadian variance for Canadian Registered Entities to leverage operating experience, observed GMD
effects, and on-going research efforts for defining alternative Benchmark GMD Events and/or Supplemental GMD
Events that appropriately reflect Canadian-specific geographical and geological characteristics. No continent-wide
requirements were changed between the second and the third versions of the standard. The fourth version of the
standard, TPL-007-4, addresses the directives issued by FERC in Order No. 851 [3] to modify Reliability Standard
TPL-007-3. FERC directed NERC to submit modifications to: (1) require the development and implementation of
corrective action plans to mitigate assessed supplemental GMD event vulnerabilities (P 29); and (2) to replace the
corrective action plan time-extension provision in TPL-007-3 with a process through which extensions of time are
considered on a case-by-case basis (P 54).
The requirements in this standard cover various aspects of the GMD Vulnerability Assessment process. Figure 1
provides an overall view of the GMD Vulnerability Assessment process:
Figure 1. GMD Vulnerability Assessment Process.
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
iv
General Considerations
Rationale for Applicability
Reliability Standard TPL-007-4 is applicable to Facilities that include power transformer(s) with a high side, wyegrounded winding with terminal voltage greater than 200 kV.
Instrumentation transformers and station service transformers do not have significant impact on geomagneticallyinduced current (GIC) flows; therefore, these types of transformers are not included in the applicability for this
standard. Terminal voltage describes line-to-line voltage.
Benchmark GMD Event (TPL-007-4 Attachment 1)
The benchmark GMD event defines the geoelectric field values used to compute GIC flows that are needed to
conduct a benchmark GMD Vulnerability Assessment. The Benchmark Geomagnetic Disturbance Event
Description, May 2016 [4], includes the event description, analysis, and example calculations.
Supplemental GMD Event (TPL-007-4 Attachment 1)
The supplemental GMD event defines the geoelectric field values used to compute GIC flows that are needed to
conduct a supplemental GMD Vulnerability Assessment. The Supplemental Geomagnetic Disturbance Event
Description, October 2017 [5], includes the event description and analysis.
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
1
Requirement R2
A GMD Vulnerability Assessment requires a GIC System model, which is a dc representation of the System, to
calculate GIC flow. In a GMD Vulnerability Assessment, GIC simulations are used to determine transformer
Reactive Power absorption and transformer thermal response. Guidance for developing the GIC System model are
provided in the Application Guide – Computing Geomagnetically-Induced Current in the Bulk-Power System,
December 2013 [6].
System models specified in Requirement R2 are used in conducting steady state power flow analysis, that accounts
for the Reactive Power absorption of power transformer(s) due to GIC flow in the System, when performing GMD
Vulnerability Assessments. Additional System modeling considerations could include facilities less than 200 kV.
The GIC System model includes all power transformer(s) with a high side, wye-grounded winding with terminal
voltage greater than 200 kV. The model is used to calculate GIC flow in the network.
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
2
Requirement R4
The Geomagnetic Disturbance Planning Guide, December 2013 [7], provides technical information on GMDspecific considerations for planning studies.
The GMD Vulnerability Assessment includes steady state power flow analysis and the supporting study or studies
using the models specified in Requirement R2 that account for the effects of GIC. Performance criteria are
specified in Table 1: Steady State Planning GMD Event found in TPL-007-4. At least one System On-Peak Load and
at least one System Off-Peak Load shall be included in the in the study or studies (see Requirement R4).
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
3
Requirement R5
The benchmark thermal impact assessment of transformers, specified in Requirement R6, is based on GIC
information for the benchmark GMD Event. This GIC information is determined by the responsible entity through
simulation of the GIC System model and shall be provided to the entity responsible for conducting the thermal
impact assessment (see Requirement R5). GIC information for the benchmark thermal impact assessment should
be provided in accordance with Requirement R5 each time the benchmark GMD Vulnerability Assessment is
performed since, by definition, the GMD Vulnerability Assessment includes a documented evaluation of
susceptibility to localized equipment damage due to GMD.
The peak GIC value of 75 A per phase, in the benchmark GMD Vulnerability Assessment, has been shown through
thermal modeling to be a conservative threshold below which the risk of exceeding known temperature limits
established by technical organizations is low.
This GIC information is necessary for determining the benchmark thermal impact of GIC on transformers in the
planning area and shall be provided to entities responsible for performing the thermal impact assessment so that
they can accurately perform the assessment (see Requirement R5). GIC information should be provided in
accordance with Requirement R5 as part of the benchmark GMD Vulnerability Assessment process since, by
definition, the GMD Vulnerability Assessment includes documented evaluation of susceptibility to localized
equipment damage due to GMD.
GIC(t) provided in Part 5.2 can be used to convert the steady state GIC flows to time-series GIC data for the
benchmark transformer thermal impact assessment. This information may be needed by one or more of the
methods for performing a thermal impact assessment. Additional guidance is available in the Transformer Thermal
Impact Assessment White Paper, October 2017 [8].
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
4
Requirement R6
The transformer thermal assessment will be repeated or reviewed using previous assessment results each time
the responsible entity performs a GMD Vulnerability Assessment and provides GIC information as specified in
Requirement R5.
Thermal assessments for transformers with a high side, grounded-wye winding greater than 200 kV are required
because the damage of these types of transformers may have an effect on the wide-area reliability of the
interconnected Transmission System.
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
5
Requirement R7
This requirement addresses directives in FERC Order No. 851 to replace the time-extension provision in
Requirement R7.4 of TPL-007-2 (and TPL-007-3) with a process through which extensions of time are considered
on a case-by-case basis.
Technical considerations for GMD mitigation planning, including operating and equipment strategies, are available
in Chapter 5 of the Geomagnetic Disturbance Planning Guide, December 2013 [7]. Additional information is
available in the 2012 Special Reliability Assessment Interim Report: Effects of Geomagnetic Disturbances on the
Bulk Power System, February 2012 [9].
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
6
Supplemental GMD Vulnerability Assessment
The requirements, R8-R11, address directives in FERC Order No. 830 for revising the benchmark GMD event used
in GMD Vulnerability Assessments (PP 44, 47-49). The requirements add a supplemental GMD Vulnerability
Assessment based on the supplemental GMD event that accounts for localized peak geoelectric fields.
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
7
Requirement R8
The Geomagnetic Disturbance Planning Guide, December 2013 [7], provides technical information on GMDspecific considerations for planning studies.
The GMD Vulnerability Assessment includes steady state power flow analysis and the supporting study or studies
using the models specified in Requirement R2 that account for the effects of GIC. Performance criteria are
specified in Table 1: Steady State Planning GMD Event found in TPL-007-4. At least one System On-Peak Load and
at least one System Off-Peak Load shall be included in the study or studies (see Requirement R8).
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
8
Requirement R9
The supplemental thermal impact assessment of transformers, specified in Requirement R10, is based on GIC
information for the supplemental GMD Event. This GIC information is determined by the responsible entity
through simulation of the GIC System model and shall be provided to the entity responsible for conducting the
thermal impact assessment (see Requirement R9). GIC information for the supplemental thermal impact
assessment should be provided in accordance with Requirement R9 each time the supplemental GMD
Vulnerability Assessment is performed since, by definition, the GMD Vulnerability Assessment includes a
documented evaluation of susceptibility to localized equipment damage due to GMD.
The peak GIC value of 85 A per phase, in the supplemental GMD Vulnerability Assessment, has been shown
through thermal modeling to be a conservative threshold below which the risk of exceeding known temperature
limits established by technical organizations is low.
This GIC information is necessary for determining the supplemental thermal impact of GIC on transformers in the
planning area and shall be provided to entities responsible for performing the thermal impact assessment so that
they can accurately perform the assessment (see Requirement R9). GIC information should be provided in
accordance with Requirement R9 as part of the supplemental GMD Vulnerability Assessment process since, by
definition, the GMD Vulnerability Assessment includes documented evaluation of susceptibility to localized
equipment damage due to GMD.
GIC(t) provided in Part 9.2 can be used to convert the steady state GIC flows to time-series GIC data for the
supplemental transformer thermal impact assessment. This information may be needed by one or more of the
methods for performing a thermal impact assessment. Additional guidance is available in the Transformer Thermal
Impact Assessment White Paper, October 2017 [8].
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
9
Requirement R10
The supplemental thermal impact assessment of a power transformer may be based on manufacturer-provided
GIC capability curves, thermal response simulation, thermal impact screening, or other technically justified means.
Justification for this criterion is provided in the Screening Criterion for Transformer Thermal Impact Assessment
White Paper, October 2017 [10].
The transformer thermal assessment will be repeated or reviewed using previous assessment results each time
the responsible entity performs a GMD Vulnerability Assessment and provides GIC information as specified in
Requirement R9.
Thermal assessments for transformers with a high side, grounded-wye winding greater than 200 kV are required
because the damage of these types of transformers may have an effect on the wide-area reliability of the
interconnected Transmission System.
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
10
Requirement R11
The requirement addresses directives in FERC Order No. 851 to develop and submit modifications to Reliability
Standard TPL-007-2 (and TPL-007-3) to require corrective action plans for the assessed supplemental GMD event
vulnerabilities.
Technical considerations for GMD mitigation planning, including operating and equipment strategies, are available
in Chapter 5 of the Geomagnetic Disturbance Planning Guide, December 2013 [7]. Additional information is
available in the 2012 Special Reliability Assessment Interim Report: Effects of Geomagnetic Disturbances on the
Bulk Power System, February 2012 [9].
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
11
Requirement R12
GMD measurement data refers to GIC monitor data and geomagnetic field data in Requirements R12 and R13,
respectively. This requirement addresses directives in FERC Order No. 830 for requiring responsible entities to
collect GIC monitoring data as necessary to enable model validation and situational awareness (PP 88, 90-92).
Technical considerations for GIC monitoring are contained in Chapter 9 of the 2012 Special Reliability Assessment
Interim Report: Effects of Geomagnetic Disturbances on the Bulk Power System, February 2012 [9]. GIC monitoring
is generally performed by Hall effect transducers that are attached to the neutral of the wye-grounded
transformer and measure dc current flowing through the neutral. Data from GIC monitors is useful for model
validation and situational awareness.
The objective of Requirement R12 is for entities to obtain GIC data for the Planning Coordinator’s planning area
or other part of the system included in the Planning Coordinator’s GIC System model to inform GMD Vulnerability
Assessments. Technical considerations for GIC monitoring are contained in Chapter 9 of the 2012 Special Reliability
Assessment Interim Report: Effects of Geomagnetic Disturbances on the Bulk Power System, February 2012 [9].
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
12
Requirement R13
GMD measurement data refers to GIC monitor data and geomagnetic field data in Requirements R12 and R13,
respectively. This requirement addresses directives in FERC Order No. 830 for requiring responsible entities to
collect magnetometer data as necessary to enable model validation and situational awareness (PP 88, 90-92).
The objective of Requirement R13 is for entities to obtain geomagnetic field data for the Planning Coordinator’s
planning area to inform GMD Vulnerability Assessments.
Magnetometers provide geomagnetic field data by measuring changes in the earth’s magnetic field. Sources of
geomagnetic field data include:
•
Observatories such as those operated by U.S. Geological Survey, Natural Resources Canada, research
organizations, or university research facilities;
•
Installed magnetometers; and
•
Commercial or third-party sources of geomagnetic field data.
Geomagnetic field data for a Planning Coordinator’s planning area is obtained from one or more of the above data
sources located in the Planning Coordinator’s planning area, or by obtaining a geomagnetic field data product for
the Planning Coordinator’s planning area from a government or research organization. The geomagnetic field data
product does not need to be derived from a magnetometer or observatory within the Planning Coordinator’s
planning area.
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
13
References
1. FERC Order No. 779,
https://www.nerc.com/FilingsOrders/us/FERCOrdersRules/Order779_GMD_RM12-22_20130516.pdf
2. FERC Order No. 830,
https://www.nerc.com/filingsorders/us/FERCOrdersRules/E-4.pdf
3. FERC Order No. 851,
https://www.nerc.com/FilingsOrders/us/FERCOrdersRules/E-3_Order%20No%20851.pdf
4. Benchmark Geomagnetic Disturbance Event Description, NERC, Atlanta, GA, May 12,
2016, https://www.nerc.com/pa/Stand/TPL0071RD/Benchmark_clean_May12_complete.pdf
5. Supplemental Geomagnetic Disturbance Event Description, NERC, Atlanta, GA, October
2017, https://www.nerc.com/pa/Stand/Project201303GeomagneticDisturbanceMitigation/Supplement
al_GMD_Event_Description_2017_October_Clean.pdf
6. Application Guide – Computing Geomagnetically-Induced Current in the Bulk-Power System, NERC,
Atlanta, GA, December,
2013, https://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%2
02013/GIC%20Application%20Guide%202013_approved.pdf
7. Geomagnetic Disturbance Planning Guide, NERC, Atlanta, GA, December,
2013, https://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%2
02013/GMD%20Planning%20Guide_approved.pdf
8. Transformer Thermal Impact Assessment White Paper, NERC, Atlanta, GA, October
2017, https://www.nerc.com/pa/Stand/Project201303GeomagneticDisturbanceMitigation/Thermal_Im
pact_Assessment_2017_October_Clean.pdf
9. 2012 Special Reliability Assessment Interim Report: Effects of Geomagnetic Disturbances on the Bulk
Power System, NERC, Atlanta, GA, February,
2012, https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2012GMD.pdf
10. Screening Criterion for Transformer Thermal Impact Assessment White Paper, NERC, Atlanta, GA,
October
2017, https://www.nerc.com/pa/Stand/Project201303GeomagneticDisturbanceMitigation/Screening_Cr
iterion_Clean_2017_October_Clean.pdf
NERC | Technical Rationale and Justification for Reliability Standard TPL-007-4 | November 2019
14
November 2019 - DRAFT Implementation Guidance
Pending Submittal for ERO Enterprise Endorsement
Transmission System
Planned Performance for
Geomagnetic Disturbance
Events
Implementation Guidance for
Reliability Standard TPL-007-4
November 2019
RELIABILITY | RESILIENCE | SECURITY
NERC | Report Title | Report Date
I
Table of Contents
Preface ....................................................................................................................................................................... iii
Introduction ............................................................................................................................................................... iv
Background ............................................................................................................................................................ iv
Requirement R1..........................................................................................................................................................1
Requirement R2..........................................................................................................................................................2
Requirement R3..........................................................................................................................................................3
Requirement R4..........................................................................................................................................................4
Requirement R5..........................................................................................................................................................5
Requirement R6..........................................................................................................................................................6
Requirement R7..........................................................................................................................................................7
Supplemental GMD Vulnerability Assessment ...........................................................................................................8
Requirement R8....................................................................................................................................................... 10
Requirement R9....................................................................................................................................................... 11
Requirement R10..................................................................................................................................................... 12
Requirement R11..................................................................................................................................................... 13
Requirement R12..................................................................................................................................................... 14
Requirement R13..................................................................................................................................................... 15
References ............................................................................................................................................................... 16
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | November 2019
ii
Preface
Electricity is a key component of the fabric of modern society and the Electric Reliability Organization (ERO)
Enterprise serves to strengthen that fabric. The vision for the ERO Enterprise, which is comprised of the North
American Electric Reliability Corporation (NERC) and the six Regional Entities (REs), is a highly reliable and secure
North American bulk power system (BPS). Our mission is to assure the effective and efficient reduction of risks to
the reliability and security of the grid.
Reliability | Resilience | Security
Because nearly 400 million citizens in North America are counting on us
The North American BPS is divided into six RE boundaries as shown in the map and corresponding table below.
The multicolored area denotes overlap as some load-serving entities participate in one Region while associated
Transmission Owners/Operators participate in another.
MRO
Midwest Reliability Organization
NPCC
Northeast Power Coordinating Council
RF
ReliabilityFirst
SERC
SERC Reliability Corporation
Texas RE
Texas Reliability Entity
WECC
Western Electricity Coordinating Council
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | November 2019
iii
Introduction
Background
The Standards Project 2019-01 Modifications to TPL-007-3 standard drafting team prepared this Implementation
Guidance to provide example approaches for compliance with the modifications to TPL-007 – Transmission System
Planned Performance for Geomagnetic Disturbance Events. Implementation Guidance does not prescribe the only
approach, but highlights one or more approaches that would be effective in achieving compliance with the
standard. Because Implementation Guidance only provides examples, entities may choose alternative approaches
based on engineering judgement, individual equipment, and system conditions.
The first version of the standard, TPL-007-1 which was approved in FERC’s Order No. 779 [1], requires entities to
assess the impact to their systems from a defined event referred to as the “Benchmark GMD Event.” The second
version of the standard, TPL-007-2, adds new Requirements R8, R9, and R10 to require responsible entities to
assess the potential implications of a “Supplemental GMD Event” on their equipment and systems in accordance
with FERC’s directives in Order No. 830 [2]. Some GMD events have shown localized enhancements of the
geomagnetic field. The supplemental GMD event was developed to represent conditions associated with such
localized enhancement during a severe GMD event for use in a GMD Vulnerability Assessment. The third version
of the standard, TPL-007-3, adds a Canadian variance for Canadian Registered Entities to leverage operating
experience, observed GMD effects, and on-going research efforts for defining alternative Benchmark GMD Events
and/or Supplemental GMD Events that appropriately reflect their specific geographical and geological
characteristics. No continent-wide requirements were changed between the second and the third versions of the
standard. The fourth version, TPL-007-4, addresses the directives issued by FERC in Order No. 851 [3] to modify
Reliability Standard TPL-007-3. FERC directed NERC to submit modifications to: (1) require the development and
implementation of corrective action plans to mitigate assessed supplemental GMD event vulnerabilities (P 29);
and (2) to replace the corrective action plan time-extension provision in TPL-007-3 Requirement R7.4 with a
process through which extensions of time are considered on a case-by-case basis (P 54).
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | November 2019
iv
Requirement R1
In some areas, planning entities may determine that the most effective approach to conduct a GMD Vulnerability
Assessment is through a regional planning organization. No requirement in the standard is intended to prohibit a
collaborative approach where roles and responsibilities are determined by a planning organization made up of
one or more Planning Coordinator(s).
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | November 2019
1
Requirement R2
The projected System condition for GMD planning may include adjustments to the System that are executable in
response to space weather information. These system adjustments could for example include recalling or
postponing maintenance outages.
Underground pipe-type cables present a special modeling situation in that the steel pipe that encloses the power
conductors significantly reduces the geoelectric field induced into the conductors themselves, while they remain
a path for GIC. Solid dielectric cables that are not enclosed by a steel pipe will not experience a reduction in the
induced geoelectric field. If applicable, include the above special modeling situations in the GIC System model.
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | November 2019
2
Requirement R3
Requirement R3 allows a responsible entity the flexibility to determine the System steady state voltage criteria
for System steady state performance in Table 1: Steady State Planning GMD Event found in TPL-007-4. Steady
state voltage limits are an example of System steady state performance criteria.
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | November 2019
3
Requirement R4
Distribution of benchmark GMD Vulnerability Assessment results provides a means for sharing relevant
information with other entities responsible for planning reliability. Consider impact on neighboring systems when
evaluating GIC study results.
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | November 2019
4
Requirement R5
The maximum effective GIC value provided in Part 5.1 is used for the benchmark thermal impact assessment. Only
those transformers that experience an effective GIC value of 75 A or greater per phase require evaluation in
Requirement R6.
A Transmission Owner or Generator Owner that desires GIC(t) may request it from the responsible entity. The
responsible entity shall provide GIC(t) upon request once GIC has been calculated, but no later than 90 calendar
days after receipt of a request from the owner and after completion of Requirement R5, Part 5.1 (see Requirement
R5).
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | November 2019
5
Requirement R6
ERO Enterprise-Endorsed Implementation Guidance for conducting the thermal impact assessment of a power
transformer is presented in the Transformer Thermal Impact Assessment White Paper, October 2016 [4].
Transformers are exempt from the benchmark thermal impact assessment requirement if the effective GIC value
for the transformer is less than 75 A per phase, as determined by a GIC analysis of the System. A documented
design specification exceeding this value is also a justifiable threshold criterion that exempts a transformer from
Requirement R6.
The benchmark thermal impact assessment of a power transformer may be based on manufacturer-provided GIC
capability curves, thermal response simulation, thermal impact screening, or other technically justified means.
The benchmark thermal impact assessment shall be based on the effective GIC flow information (see Requirement
R6). For additional information, refer to the above referenced white paper and the Screening Criterion for
Transformer Thermal Impact Assessment White Paper, October 2017 [5].
Approaches for conducting the thermal impact assessment of transformers for the benchmark event are
presented in the Transformer Thermal Impact Assessment White Paper, October 2017 [6].
Thermal impact assessments for the benchmark event are provided to the responsible entity, as determined in
Requirement R1, so that identified issues can be included in the GMD Vulnerability Assessment (Requirement R4)
and the Corrective Action Plan (CAP) (Requirement R7) as necessary.
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | November 2019
6
Requirement R7
This requirement addresses directives in FERC Order No. 830 for establishing CAP deadlines associated with GMD
Vulnerability Assessments. In FERC Order No. 830, FERC directed revisions to TPL-007 such that CAPs are
developed within one year from the completion of GMD Vulnerability Assessments (P 101). Furthermore, FERC
directed NERC to establish implementation deadlines after the completion of the CAP as follows (P 102):
•
Two years for non-hardware mitigation; and
•
Four years for hardware mitigation.
Part 7.4 requires entities to submit to the CEA a request for extension when implementation of planned mitigation
is not achievable within the deadlines established in Part 7.3. Examples of situations beyond the control of the
responsible entity include, but are not limited to:
•
Delays resulting from regulatory/legal processes, such as permitting;
•
Delays resulting from stakeholder processes required by tariff;
•
Delays resulting from equipment lead times; or
•
Delays resulting from the inability to acquire necessary Right-of-Way.
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | November 2019
7
Supplemental GMD Vulnerability Assessment
The exact spatial extent, local time of occurrence, latitude boundary, number of occurrences during a GMD event,
and geoelectric field characteristics (amplitude and orientation) inside/outside the local enhancement cannot yet
be scientifically determined.
TPL-007-4 provides flexibility in applying the supplemental GMD event to the planning area. This guide provides
examples of approaches and boundaries to apply the supplemental event based on what is presently understood
on localized enhancements. As provided in the standard (Attachment 1) “Other methods to adjust the benchmark
GMD event analysis to account for the localized geoelectric field enhancement of the supplemental GMD event”
may be used.
1. Spatial extent considerations:
a. Apply a local geoelectric field enhancement consistent with available recordings of past events, e.g.,
greater than or equal to 100 km (West-East) by 100 km (North-South). Additional analysis may be
performed by varying the spatial extent. Note that the 100 km North-South spatial extent is better
understood than the West-East length, which could be 500 km or more; or
b. Apply the peak geoelectric field for the supplemental GMD event (12 V/km scaled to the planning
area) over the entire planning area. Note that this implies studying a GMD event rarer than 1-in-100
years.
2. Geoelectric field inside the local enhancement considerations:
a. Amplitude: 12 V/km (scaled to the planning area); and
b. Orientation: West-East (geomagnetic reference). Additional analysis may be performed varying the
orientation of the geoelectric field.
3. Geoelectric field outside 1 the local enhancement consideration:
a. Amplitude: Greater than or equal to 1.2 V/km (scaled to the planning area); i.e., an order of magnitude
smaller than the field inside the local enhancement; and
b. Orientation: West-East (geomagnetic reference). Additional analysis may be performed varying the
orientation of the geoelectric field.
4. Position of the local enhancement considerations:
a. Use engineering judgement to position the local enhancement on critical areas of the system. For
example, the benchmark vulnerability assessment may identify areas with depressed voltages, lack of
dynamic reactive reserves, large GIC flows through transformers, etc. Impacts to critical infrastructure
or other externalities may also be considered; or
b. Systematically move the position of the local enhancement throughout the entire planning area.
The schematic in Figure 1 illustrates an example of applying the supplemental GMD event. The local enhancement
is 100 km by 100 km, the geoelectric field inside the local enhancement is 12 V/km (scaled to the planning area)
with West-East orientation, and the geoelectric field outside the local enhancement is 1.2 V/km (scaled to the
planning area) with a West-East orientation.
The characteristics of the geoelectric field outside the local enhancement, for example amplitude, orientation, and spatial extent, are still
being reviewed by the scientific community.
1
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | November 2019
8
Supplemental GMD Vulnerability Assessment
100 km
1.2 V/km, West-East
(scaled to planning area)
100 km
Local Enhancement
12 V/km, West-East
(scaled to planning area)
Figure 1. An Example of Applying the Supplemental Event.
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | November 2019
9
Requirement R8
Distribution of supplemental GMD Vulnerability Assessment results provides a means for sharing relevant
information with other entities responsible for planning reliability. Consider impact on neighboring systems when
evaluating GIC study results.
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | November 2019
10
Requirement R9
The maximum effective GIC value provided in Part 9.1 is used for the supplemental thermal impact assessment.
Only those transformers that experience an effective GIC value of 85 A or greater per phase require evaluation in
Requirement R10.
A Transmission Owner or Generator Owner that desires GIC(t) may request it from the responsible entity. The
responsible entity shall provide GIC(t) upon request once GIC has been calculated, but no later than 90 calendar
days after receipt of a request from the owner and after completion of Requirement R9, Part 9.1 (see Requirement
R9).
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | November 2019
11
Requirement R10
ERO Enterprise-Endorsed Implementation Guidance for conducting the thermal impact assessment of a power
transformer is presented in the Transformer Thermal Impact Assessment White Paper, October 2016 [4].
Transformers are exempt from the supplemental thermal impact assessment requirement if the effective GIC
value for the transformer is less than 85 A per phase, as determined by a GIC analysis of the System. A documented
design specification exceeding this value is also a justifiable threshold criterion that exempts a transformer from
Requirement R10.
The supplemental thermal impact assessment of a power transformer may be based on manufacturer-provided
GIC capability curves, thermal response simulation, thermal impact screening, or other technically justified means.
The supplemental thermal impact assessment shall be based on the effective GIC flow information (see
Requirement R10). For additional information, refer to the above referenced white paper and the Screening
Criterion for Transformer Thermal Impact Assessment White Paper, October 2017 [5].
Approaches for conducting the thermal impact assessment of transformers for the supplemental event are
presented in the Transformer Thermal Impact Assessment White Paper, October 2017 [6].
Thermal impact assessments for the supplemental event are provided to the responsible entity, as determined in
Requirement R1, so that identified issues can be included in the GMD Vulnerability Assessment (R8) and the
Corrective Action Plan (R11) as necessary.
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | November 2019
12
Requirement R11
This requirement addresses directives in FERC Order No. 851 to develop and submit modifications to Reliability
Standard TPL-007-2 (and TPL-007-3) to require corrective action plans for assessed supplemental GMD event
vulnerabilities. This requirement is analogous to Requirement R7, such that CAPs are developed within one year
from the completion of supplemental GMD Vulnerability Assessments and establishes implementation deadlines
after the completion of the CAP as follows:
•
Two years for non-hardware mitigation; and
•
Four years for hardware mitigation.
Part 11.4 requires entities to submit to the CEA a request for extension when implementation of planned
mitigation is not achievable within the deadlines established in Part 11.3. Examples of situations beyond the
control of the responsible entity include, but are not limited to:
•
Delays resulting from regulatory/legal processes, such as permitting;
•
Delays resulting from stakeholder processes required by tariff;
•
Delays resulting from equipment lead times; or
•
Delays resulting from the inability to acquire necessary Right-of-Way.
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | November 2019
13
Requirement R12
Responsible entities can consider the guidance found in NERC Rules of Procedure Section 1600 Data Request for
the collection of GMD Data. 2
2
As of November 2019, a draft copy can be found at:
https://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GMD_Data_Reporting_
Instruction_draft.docx
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | November 2019
14
Requirement R13
Responsible entities can consider the guidance found in NERC Rules of Procedure Section 1600 Data Request for
the collection of GMD Data. 3
The following map shows locations of magnetometers operated by U.S. Geological Survey (USGS) and Natural
Resources Canada (NRCan). For a full listing refer to International Real-Time Magnetic Observatory Network [7].
Additional data could be found at research institutions and academic universities or other entities with installed
magnetometers.
The INTERMAGNET Technical Reference Manual, Version 4.6, 2012 [8] provides equipment specifications and data
format protocols.
3
As of November 2019, a draft copy can be found at:
https://www.nerc.com/comm/PC/Geomagnetic%20Disturbance%20Task%20Force%20GMDTF%202013/GMD_Data_Reporting_
Instruction_draft.docx
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | November 2019
15
References
1. FERC Order No. 779,
https://www.nerc.com/FilingsOrders/us/FERCOrdersRules/Order779_GMD_RM12-22_20130516.pdf
2. FERC Order No. 830,
https://www.nerc.com/filingsorders/us/FERCOrdersRules/E-4.pdf
3. FERC Order No. 851,
https://www.nerc.com/FilingsOrders/us/FERCOrdersRules/E-3_Order%20No%20851.pdf
4. Transformer Thermal Impact Assessment White Paper, ERO Enterprise-Endorsed Implementation
Guidance, NERC, Atlanta, GA, October 28,
2016, https://www.nerc.com/pa/comp/guidance/EROEndorsedImplementationGuidance/TPL-0071_Transformer_Thermal_Impact_Assessment_White_Paper.pdf
5. Screening Criterion for Transformer Thermal Impact Assessment White Paper, NERC, Atlanta, GA,
October
2017, https://www.nerc.com/pa/Stand/Project201303GeomagneticDisturbanceMitigation/Screening_Cr
iterion_Clean_2017_October_Clean.pdf
6. Transformer Thermal Impact Assessment White Paper, NERC, Atlanta, GA, October
2017, https://www.nerc.com/pa/Stand/Project201303GeomagneticDisturbanceMitigation/Thermal_Im
pact_Assessment_2017_October_Clean.pdf
7. International Real-Time Magnetic Observatory Network,
http://www.intermagnet.org/index-eng.php
8. INTERMAGNET Technical Reference Manual, Version 4.6,
2012, http://www.intermagnet.org/publications/intermag_4-6.pdf
NERC | Implementation Guidance for Reliability Standard TPL-007-4 | November 2019
16
Violation Risk Factor and Violation Severity Level Justification
Project 2019-01 Modifications to TPL-007-3
This document provides the standard drafting team’s (SDT’s) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in TPL-007-4. Each requirement is assigned a VRF and a VSL. These elements support the determination of
an initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as defined in
the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the following NERC criteria and FERC Guidelines when
developing the VRFs and VSLs for the requirements.
NERC Criteria for Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric System
at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to effectively
monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric System
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk requirement is
unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric System instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.
RELIABILITY | RESILIENCE | SECURITY
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical state
or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement that is
administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or restorative
conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric System, or the
ability to effectively monitor, control, or restore the Bulk Electric System.
FERC Guidelines for Violation Risk Factors
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report
FERC seeks to ensure that VRFs assigned to Requirements of Reliability Standards in these identified areas appropriately reflect their historical
critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System:
•
Emergency operations
•
Vegetation management
•
Operator personnel training
•
Protection systems and their coordination
•
Operating tools and backup facilities
•
Reactive power and voltage control
•
System modeling and data exchange
•
Communication protocol and facilities
•
Requirements to determine equipment ratings
•
Synchronized data recorders
•
Clearer criteria for operationally critical facilities
•
Appropriate use of transmission loading relief.
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | November 2019
2
Guideline (2) – Consistency within a Reliability Standard
FERC expects a rational connection between the sub-Requirement VRF assignments and the main Requirement VRF assignment.
Guideline (3) – Consistency among Reliability Standards
FERC expects the assignment of VRFs corresponding to Requirements that address similar reliability goals in different Reliability Standards would
be treated comparably.
Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular VRF level conforms to NERC’s definition of that risk level.
Guideline (5) – Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability Standard.
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | November 2019
3
NERC Criteria for Violation Severity Levels
VSLs define the degree to which compliance with a requirement was not achieved. Each requirement must have at least one VSL. While it is
preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of noncompliant performance and may
have only one, two, or three VSLs.
VSLs should be based on NERC’s overarching criteria shown in the table below:
Lower VSL
Moderate VSL
The performance or product
measured almost meets the full
intent of the requirement.
The performance or product
measured meets the majority of
the intent of the requirement.
High VSL
The performance or product
measured does not meet the
majority of the intent of the
requirement, but does meet
some of the intent.
Severe VSL
The performance or product
measured does not
substantively meet the intent of
the requirement.
FERC Order of Violation Severity Levels
The FERC VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard meet
the FERC Guidelines for assessing VSLs:
Guideline (1) – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance
Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than was
required when levels of non-compliance were used.
Guideline (2) – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline (3) – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | November 2019
4
Guideline (4) – Violation Severity Level Assignment Should Be Based on A Single Violation, Not on A Cumulative Number of
Violations
Unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | November 2019
5
VRF Justification for TPL-007-4, Requirement R1
The VRF did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R1
The VSL did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VRF Justification for TPL-007-4, Requirement R2
The VRF did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R2
The VSL did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VRF Justification for TPL-007-4, Requirement R3
The VRF did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R3
The VSL did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VRF Justification for TPL-007-4, Requirement R4
The VRF did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R4
The VSL did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VRF Justification for TPL-007-4, Requirement R5
The VRF did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R5
The VSL did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VRF Justification for TPL-007-4, Requirement R6
The VRF did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | November 2019
6
VSL Justification for TPL-007-4, Requirement R6
The VSL did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VRF Justification for TPL-007-4, Requirement R7
The VRF did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R7
The VSL did not substantively change from the TPL-007-3 Reliability Standard or FERC-approved TPL-007-2 Reliability Standard. In the Severe
VSL, the word “have” was replaced with “develop” to more closely reflect the language of the Requirement.
VRF Justification for TPL-007-4, Requirement R8
The VRF did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R8
The justification is provided on the following pages.
VRF Justification for TPL-007-4, Requirement R9
The VRF did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R9
The VSL did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VRF Justification for TPL-007-4, Requirement R10
The VRF did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R10
The VSL did not change from the TPL-007-3 Reliability Standard or the FERC-approved TPL-007-2 Reliability Standard.
VRF Justification for TPL-007-4, Requirement R11
The justification is provided on the following pages.
VSL Justification for TPL-007-4, Requirement R11
The justification is provided on the following pages.
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | November 2019
7
VRF Justification for TPL-007-4, Requirement R12
Requirement R12 was previously Requirement R11 in TPL-007-3. The VRF did not change from the TPL-007-3 Reliability Standard or the FERCapproved TPL-007-2 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R12
Requirement R12 was previously Requirement R11 in TPL-007-3. The VSL did not change from the TPL-007-3 Reliability Standard or the FERCapproved TPL-007-2 Reliability Standard.
VRF Justification for TPL-007-4, Requirement R13
Requirement R13 was previously Requirement R12 in TPL-007-3. The VRF did not change from the TPL-007-3 Reliability Standard or the FERCapproved TPL-007-2 Reliability Standard.
VSL Justification for TPL-007-4, Requirement R13
Requirement R13 was previously Requirement R12 in TPL-007-3. The VSL did not change from the TPL-007-3 Reliability Standard or the FERCapproved TPL-007-2 Reliability Standard.
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | November 2019
8
VSLs for TPL-007-4, Requirement R8
Lower
Moderate
High
The responsible entity
completed a supplemental GMD
Vulnerability Assessment, but it
was more than 60 calendar
months and less than or equal
to 64 calendar months since the
last supplemental GMD
Vulnerability Assessment.
The responsible entity’s
completed supplemental GMD
Vulnerability Assessment failed
to satisfy one of elements listed
in Requirement R8, Parts 8.1
through 8.3;
OR
The responsible entity’s
completed supplemental GMD
Vulnerability Assessment failed
to satisfy two of the elements
listed in Requirement R8, Parts
8.1 through 8.3;
OR
The responsible entity
completed a supplemental GMD
Vulnerability Assessment, but it
was more than 64 calendar
months and less than or equal
to 68 calendar months since the
last supplemental GMD
Vulnerability Assessment.
The responsible entity
completed a supplemental GMD
Vulnerability Assessment, but it
was more than 68 calendar
months and less than or equal
to 72 calendar months since the
last supplemental GMD
Vulnerability Assessment.
Severe
The responsible entity’s
completed supplemental GMD
Vulnerability Assessment failed
to satisfy three of the elements
listed in Requirement R8, Parts
8.1 through 8.3;
OR
The responsible entity
completed a supplemental GMD
Vulnerability Assessment, but it
was more than 72 calendar
months since the last
supplemental GMD Vulnerability
Assessment;
OR
The responsible entity does not
have a completed supplemental
GMD Vulnerability Assessment.
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | November 2019
9
VSL Justifications for TPL-007-4, Requirement R8
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency
in the Determination of
Penalties
The proposed VSLs retain the VSLs from the TPL-007-3 Reliability Standard, approved by FERC in TPL-0072, with the exception of removing one part of the lower VSL to reflect the removal of subpart 8.3 in
proposed TPL-007-4. As a result, the proposed VSLs do not lower the current level of compliance.
The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting
uniformity and consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | November 2019
10
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
Each VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | November 2019
11
VSLs for TPL-007-4, Requirement R11
Lower
The responsible entity’s
Corrective Action Plan failed to
comply with one of the
elements in Requirement R11,
Parts 11.1 through 11.5.
Moderate
The responsible entity’s
Corrective Action Plan failed to
comply with two of the
elements in Requirement R11,
Parts 11.1 through 11.5.
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | November 2019
High
The responsible entity’s
Corrective Action Plan failed to
comply with three of the
elements in Requirement R11,
Parts 11.1 through 11.5.
Severe
The responsible entity’s
Corrective Action Plan failed to
comply with four or more of the
elements in Requirement R11,
Parts 11.1 through 11.5;
OR
The responsible entity did not
develop a Corrective Action Plan
as required by Requirement
R11.
12
VSL Justifications for TPL-007-4, Requirement R11
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency
in the Determination of
Penalties
The requirement is new. Therefore, the proposed VSLs do not have the unintended consequence of
lowering the level of compliance. Further, the VSLs are consistent with those assigned for Requirement R7,
pertaining to Corrective Action Plans for benchmark GMD Vulnerability Assessments.
The proposed VSLs are not binary and do not use any ambiguous terminology, thereby supporting
uniformity and consistency in the determination of similar penalties for similar violations.
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is
Not Consistent
Guideline 2b: Violation
Severity Level Assignments
that Contain Ambiguous
Language
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | November 2019
13
VSL Justifications for TPL-007-4, Requirement R11
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
The proposed VSLs use the same terminology as used in the associated requirement and are, therefore,
consistent with the requirement.
Each VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
VRF Justifications for TPL-007-4, Requirement R11
Proposed VRF
Lower
NERC VRF Discussion
A VRF of High is being proposed for this requirement.
FERC VRF G1 Discussion
N/A
Guideline 1- Consistency
with Blackout Report
FERC VRF G2 Discussion
Guideline 2- Consistency
within a Reliability Standard
The proposed VRF is consistent among other FERC approved VRFs within the standard, specifically
Requirement R7 pertaining to Corrective Action Plans for benchmark GMD Vulnerability Assessments.
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | November 2019
14
VRF Justifications for TPL-007-4, Requirement R11
Proposed VRF
Lower
FERC VRF G3 Discussion
A VRF of High is consistent with Reliability Standard TPL‐001‐4 Requirement R2 which requires
Transmission Planners and Planning Coordinators to include a Corrective Action Plan that addresses
identified performance issues in the annual Planning Assessment.
Guideline 3- Consistency
among Reliability Standards
FERC VRF G4 Discussion
Guideline 4- Consistency
with NERC Definitions of
VRFs
FERC VRF G5 Discussion
Guideline 5- Treatment of
Requirements that Comingle More than One
Obligation
The VRF of High is consistent with the NERC VRF Definition. Failure to develop a Corrective Action Plan
that addresses issues identified in a supplemental GMD Vulnerability Assessment could place the Bulk
Electric System at an unacceptable risk of instability, separation, or cascading failures.
This requirement does not co‐mingle a higher‐risk reliability objective with a lesser‐ risk reliability
objective.
VRF and VSL Justifications
Project 2019-01 Modifications to TPL-007-3 | November 2019
15
Consideration of Issues and Directives
Project 2019-01 Modifications to TPL-007-3
Project 2019-01 Modifications to TPL-007-3
Issue or Directive
Source
Modify the provision in Reliability Standard TPL-007-2,
Requirement R7.4 that allows applicable entities to
exceed deadlines for completing corrective action plan
tasks when “situations beyond the control of the
responsible entity [arise]”, by requiring that NERC and
the Regional Entities, as appropriate, consider requests
for extension of time on a case-by-case basis. Under
this option, responsible entities seeking an extension
would submit the information required by
Requirement R7.4 to NERC and the Regional Entities for
their consideration of the request.
FERC Order
No. 851, P 5
and P 50
Consideration of Issue or Directive
The SDT proposed the modified language in Requirement R7.3
and R7.4 to require time extensions for completing CAPs be
submitted to the ERO for approval. The proposed modified
language reads as follows:
7.3. Include a timetable, subject to revision by the responsible
entity approval for any extension sought under in Part 7.4, for
implementing the selected actions from Part 7.1. The timetable
shall:
7.3.1. Specify implementation of non-hardware
mitigation, if any, within two years of development
of the CAP; and
7.3.2. Specify implementation of hardware mitigation, if
any, within four years of development of the CAP.
7.4. Be submitted to the Compliance Enforcement Authority
(CEA) with a request for extension of time revised if situations
beyond the control of the responsible entity is unable to
determined in Requirement R1 prevent implementation of the
CAP within the timetable for implementation provided in Part
RELIABILITY | RESILIENCE | SECURITY
Project 2019-01 Modifications to TPL-007-3
Issue or Directive
Source
Consideration of Issue or Directive
7.3. The submitted revised CAP shall document the following,
and be updated at least once every 12 calendar months until
implemented:
7.4.1 Circumstances causing the delay for fully or
partially implementing the selected actions in Part
7.1 and how those circumstances are beyond the
control of the responsible entity;
7.4.2 Description of the original CAP, and any previous
changes to the CAP, with the associated
timetables(s) for implementing the selected actions
in Part 7.1; and
7.4.37.4.2
Revisions to the selected actions in Part
7.1, if any, including utilization of Operating
Procedures, if applicable;, and the updated
timetable for implementing the selected actions.
7.4.47.4.3
Updated timetable for implementing the
selected actions in Part 7.1.
Submit modifications to Reliability Standard TPL-007-2
to require corrective action plans for assessed
supplemental GMD event vulnerabilities.
Consideration of Issues and Directives
Project 2019-01 Modifications to TPL-007-3 | November 2019
FERC Order
No. 851, P 4
and P 39
The SDT drafted TPL-007-4 Requirement R11 to address
require CAPs for supplemental GMD vulnerabilities and to
require extensions to these plans to be approved by NERC
and the Regional Entities, as appropriate, in where situations
beyond the control of the responsible entity prevent
implementation of the CAP in the two and four year timelines
provided in the standard for non-hardware and hardware
2
Project 2019-01 Modifications to TPL-007-3
Issue or Directive
Source
Consideration of Issue or Directive
mitigation, respectively. This language is the same as the
modified Requirement R7 which addresses CAPs for the
benchmark GMD vulnerability assessment. Requirement R8
was also modified to remove the original R8.3 which stated
“an evaluation of possible actions designed to reduce the
likelihood or mitigate the consequences and adverse impacts
of the event(s) shall be conducted.”
Consideration of Issues and Directives
Project 2019-01 Modifications to TPL-007-3 | November 2019
3
DRAFT TPL-007-4
CAP Extension
Request
Review Process
RELIABILITY | RESILIENCE | SECURITY
NERC | Report Title | Report Date
I
Table of Contents
Introduction ................................................................................................................................................................... iii
Background................................................................................................................................................................. iii
Process Overview ............................................................................................................................................................ 1
Step 1 – Registered Entity Submittal ....................................................................................................................... 1
Step 2 – ERO Enterprise Review .............................................................................................................................. 1
Step 3 – Registered Entity Notification.................................................................................................................... 2
Appendix A : Entity Submittal Template ..................................................................................................................... 3
NERC | DRAFT TPL-007-4 CAP Extension Request Review Process | Month, 2019
ii
Introduction
Background
This Electric Reliability Organization (ERO) Enterprise 1 TPL-007-4 Corrective Action Plan (CAP) Extension Review
Process document addresses how ERO Enterprise Compliance Monitoring and Enforcement staff (CMEP staff) will
jointly review requests for extensions to CAPs developed under TPL-007-4 to ensure a timely, structured and
consistent approach to CAP extension request submittals and processing.
NERC Compliance Assurance will maintain this document under existing ERO Enterprise processes. This document
will be reviewed and updated by NERC Compliance Assurance, as needed.
1
The ERO Enterprise is comprised of NERC and the Regional Entities.
NERC | DRAFT TPL-007-4 CAP Extension Request Review Process | Month, 2019
iii
Process Overview
If a registered entity (entity) has determined that a Corrective Action Plan (CAP) developed in accordance with
TPL-007-4 Requirements R7 or R11 cannot meet the timetable provided per R7 Part 7.3 or R11 Part 11.3 due to
situations beyond the control of the responsible entity, then the entity will submit an extension request to the ERO
Enterprise for approval prior to the original required CAP completion date.
The steps outlined here should be followed to ensure a timely, structured and consistent approach to extension
request submittals and processing.
The entity will work with the Regional Entity designated as its CEA as outlined in this process. The entity submitting
the extension request will be referred to as the ‘submitting entity’ and may represent only itself or multiple registered
entities who have developed a joint extension request. The submitting entity is responsible for ensuring all registered
entities who are jointly submitting the extension request are listed in the requested information below and for
distributing any communications from its CEA to the other entities that are part of the joint extension request. If a
joint extension request is submitted for multiple registered entities who have different Regional Entities designated
as the CEA, the submitting entity’s CEA will perform the steps outlined in this process and will be responsible for
coordinating with the Regional Entity(ies) that are the designated CEA for the additional entities party to the joint
extension request.
For entities in Coordinated Oversight, the CEA for this process is the Lead Regional Entity (LRE). The LRE will
coordinate with the Affected Regional Entity(ies) (ARE) and the AREs may participate in the joint review as well.
Step 1 – Registered Entity Submittal
If an entity determines that it cannot meet the required timetable for completing a CAP, the submitting entity will
contact their CEA to coordinate submittal of an extension request. The submitting entity will submit the request to
their CEA using the template provided in Appendix A: Entity Submittal Template.
Entities are encouraged to submit the extension request as soon as they are aware they will not meet the CAP
completion date but no later than 60 days before the original required completion date to allow the CEA and NERC
time to approve the extension request before the original required completion date.
If CAP extension requests are submitted less than 60 calendar days before the original required completion date, the
CEA and NERC may not have sufficient time to review the extension request before the required completion date.
This could cause the entity not to meet its obligations under TPL-007-4 R7 Part 7.3 and R11 Part 11.3. It is the
submitting entity’s responsibility to ensure that all information detailed in TPL-007-4 Part 7.4 or 11.4 and requested
in the Entity Submittal Template is provided in the entity’s extension request submittal to facilitate the CEA and NERC
review.
Step 2 – ERO Enterprise Review
The CEA will acknowledge receipt of the submission in writing within 15 calendar days and review that all information
detailed in TPL-007-4 R7 Part 7.4 or R11 Part 11.4 and requested in the Entity Submittal Template is provided in the
submitting entity’s extension request submittal. The CEA will work with the submitting entity to provide any missing
information and will notify NERC of the extension request submittal when acknowledging receipt of the submission.
CMEP staff from the CEA and NERC will then perform a joint review of (1) the situation(s) beyond the control of the
entity preventing implementation of the CAP within the identified timetable; and (2) the revisions to the CAP and
updated timetable for implementing the selected actions. Any additional information requested to support the
extension request review will be coordinated with the submitting entity by the CEA. The CEA and NERC will complete
NERC | DRAFT TPL-007-4 CAP Extension Request Review Process | Month, 2019
1
Process Overview
the review within 45 calendar days or provide notification to the submitting entity that it extending the time needed
for review.
The Standard language states that an entity will submit an extension request for a full or partial delay in the
implementation of the CAP within the timetable provided in TPL-007-4 R7 Part 7.3 or R11 Part 11.3. The
determination whether to approve the extension request will be based on the specific facts and circumstances
provided as to how the situations causing the delay in completing the CAP are beyond the control of the entity.
Examples of situations beyond the control of the responsible entity include, but are not limited to:
• Delays resulting from regulatory/legal processes, such as permitting;
• Delays resulting from stakeholder processes required by tariff;
• Delays resulting from equipment lead times; or
• Delays resulting from the inability to acquire necessary Right-of-Way.
Due diligence to order equipment, plan Right-of-Ways, obtain permits, etc., will be considered as part of the
determination of whether a particular set of facts and circumstances constitute situations beyond the control of the
entity. Additionally, cost may be a factor in whether a particular set of facts and circumstances constitute situations
that are beyond the control of the entity. However, the cost of mitigation alone is not likely to be determined to be
a situation that is beyond the control of the entity.
Step 3 – Registered Entity Notification
The CEA will communicate the approval or denial of the extension request or continuation of the time needed to
review the extension request in writing to the submitting entity including the rationale for the determination. For
any continuation of the review, the CEA will also provide the submitting entity a revised timeline for when the
determination will be provided.
NERC | DRAFT TPL-007-4 CAP Extension Request Review Process | Month, 2019
2
Appendix A: Entity Submittal Template
[Will be formatted into a form for submission that includes the following information]
Submitting entity name:
Submitting entity NCR#:
Submitting entity contact name and information:
Coordinated Oversight Group # (if applicable):
Regional Entities impacted (for MRREs only):
Is this extension request being submitted jointly with another entity? If yes, please provide:
1. NCR#’s for addition entity(ies)
2. Regional Entity that is the CEA for additional entity(ies)
Start date of CAP:
Original completion date of CAP:
Description of system deficiencies identified and selected actions to achieve required System performance per TPL007-4 Part 7.1:
Circumstances causing the delay for fully or partially implementing the selected actions:
Explanation for why circumstances causing the delay are beyond the entity’s control:
Description of revisions to the selected actions, if applicable:
New proposed completion date of CAP:
NERC | DRAFT TPL-007-4 CAP Extension Request Review Process | Month, 2019
3
DRAFT TPL-007-4
CAP Extension
Request
Review Process
RELIABILITY | RESILIENCE | SECURITY
NERC | Report Title | Report Date
I
Table of Contents
Introduction ................................................................................................................................................................... iii
Background................................................................................................................................................................. iii
Process Overview ............................................................................................................................................................ 1
Step 1 – Registered Entity Submittal ....................................................................................................................... 1
Step 2 – ERO Enterprise Review .............................................................................................................................. 1
Step 3 – Registered Entity Notification.................................................................................................................... 2
Appendix A : Entity Submittal Template ..................................................................................................................... 3
NERC | DRAFT TPL-007-4 CAP Extension Request Review Process | Month, 2019
ii
Introduction
Background
This Electric Reliability Organization (ERO) Enterprise 1 TPL-007-4 Corrective Action Plan (CAP) Extension Review
Process document addresses how ERO Enterprise Compliance Monitoring and Enforcement staff (CMEP staff) will
jointly review requests for extensions to Corrective Action Plans (CAPs) developed under TPL-007-4 to ensure a
timely, structured and consistent approach to CAP extension request submittals and processing.
NERC Compliance Assurance will maintain this document under existing ERO Enterprise processes. This document
will be reviewed and updated by NERC Compliance Assurance, as needed.
1
The ERO Enterprise is comprised of NERC and the Regional Entities.
NERC | DRAFT TPL-007-4 CAP Extension Request Review Process | Month, 2019
iii
Process Overview
If a registered entity (entity) has determined that a Corrective Action Plan (CAP) developed in accordance with
TPL-007-4 Requirements R7 or R11 cannot be metmeet in the timetable provided per R7 Part 7.3 or R11 Part 11.3
due to situations beyond the control of the responsible entity, then the entity will submit an extension request to the
ERO Enterprise ir Compliance Enforcement Authority (CEA) and NERC for approval prior to the original required CAP
completion date.
The steps outlined here should be followed to ensure a timely, structured and consistent approach to extension
request submittals and processing.
The entity will work with the Regional Entity designated as its CEA as outlined in this process. The entity submitting
the extension request will be referred to as the ‘submitting entity’ and may represent only itself or multiple registered
entities who have developed a joint extension request. The submitting entity is responsible for ensuring all registered
entities who are jointly submitting the extension request are listed in the requested information below and for
distributing any communications from its CEA to the other entities that are part of the joint extension request. If a
joint extension request is submitted for multiple registered entities who have different Regional Entities designated
as the CEA, the submitting entity’s CEA will perform the steps outlined in this process and will be responsible for
coordinating with the Regional Entity(ies) that are the designated CEA for the additional entities party to the joint
extension request.
For entities in Coordinated Oversight, the CEA for this process is the Lead Regional Entity (LRE). The LRE will
coordinate with the Affected Regional Entity(ies) (ARE) and the AREs may participate in the joint review as well.
Step 1 – Registered Entity Submittal
If a registered entity (entity) determines that it cannot meet the required timetable for completing a CAP, the
submitting entity will contact their Compliance Enforcement Authority (CEA) to coordinate submittal of an extension
request. The submitting entity should will submit the request to their CEA using the template provided in Appendix
A: Entity Submittal Template or through an alternate method designated by the CEA that includes the same
information.
Entities are encouraged to submit the extension request as soon as they are aware they will not meet the CAP
completion date but no later than 60 days before the original required completion date to allow the ERO
EnterpriseCEA and NERC time to approve the extension request before the original required completion date.
All CAP extension requests must be approved by the ERO Enterprise prior to original required CAP completion date.If
CAP extension requests are submitted less than 60 days before the original required completion date, the CEA and
NERC may not have sufficient time to review the extension request before the required completion date. This could
cause the entity not to meet its obligations under TPL-007-4 R7 Part 7.3 and R11 Part 11.3. It is the submitting entity’s
responsibility to ensure that all information detailed in TPL-007-4 Part 7.4 or 11.4 and requested in the Entity
Submittal Template is provided in the entity’s extension request submittal to facilitate the CEA and NERC review.
Step 2 – ERO Enterprise Review
The CEA will acknowledge receipt of the submission in writing within 15 days and reviewensure that all information
detailed in TPL-007-4 R7 Part 7.4 or R11 Part 11.4 and requested in the Entity Submittal Template is provided in the
submitting entity’s extension request submittal. The CEA will work with the submitting entity to provide any missing
information and will notify NERC of the extension request submittal when acknowledging receipt of the submission.
NERC | DRAFT TPL-007-4 CAP Extension Request Review Process | Month, 2019
1
Process Overview
The CEA will notify NERC of the extension request submittal. CMEP staff from The the CEA and NERC will then perform
a joint review of (1) the situation(s) beyond the control of the entity preventing implementation of the CAP within
the identified timetable; and (2) the revisions to the CAP and updated timetable for implementing the selected
actions. Any additional information requested by the ERO Enterprise to support the extension request review will be
coordinated with the submitting entity by the CEA. The CEA and NERC will complete the review within 45 days or
provide notification to the submitting entity that it extending the time needed for review.
The Standard language states that an entity will submit an extension request for a full or partial delay in the
implementation of the CAP within the timetable provided in TPL-007-4 R7 Part 7.3 or R11 Part 11.3. The CEA and
NERC willThe determinatione whether to approve the extension request will be based on the specific facts and
circumstances provided as to how the situations causing the delay in completing the CAP are beyond the control of
the entity.
Examples of situations beyond the control of the responsible entity include, but are not limited to:
• Delays resulting from regulatory/legal processes, such as permitting;
• Delays resulting from stakeholder processes required by tariff;
• Delays resulting from equipment lead times; or
• Delays resulting from the inability to acquire necessary Right-of-Way.
Due diligence to order equipment, plan Right-of-Ways, obtain permits, etc., will be considered as part of the
determination of whether a particular set of facts and circumstances constitute situations beyond the control of the
entity. Additionally, cost may be a factor in whether a particular set of facts and circumstances constitute situations
that are beyond the control of the entity. However, the cost of mitigation alone is not likely to be determined to be
a situation that is beyond the control of the entity.
Step 3 – Registered Entity Notification
The CEA will communicate the ERO Enterprise approval or denial of the extension request or continuation of the time
needed to review the extension request in writing to the submitting entity along withincluding the rationale for the
determination. For any continuation of the review, the CEA will also provide the submitting entity a revised timeline
for when the determination will be provided.
NERC | DRAFT TPL-007-4 CAP Extension Request Review Process | Month, 2019
2
Appendix A: Entity Submittal Template
[Will be formatted into a form for submission that includes the following information]
Submitting Entity entity name:
Submitting entity NCR#:
Primary Submitting entity contact name and information:
Coordinated Oversight Group # (if applicable):
Regional Entities impacted (for MRREs only):
Is this extension request being submitted jointly with another entity? If yes, please provide:
1. NCR#’s for addition entity(ies)
1.2. Regional Entity that is the CEA for additional entity(ies)
Start date of CAP:
Original completion date of CAP:
Description of system deficiencies identified and selected actions to achieve required System performance per TPL007-4 Part 7.1:
Circumstances causing the delay for fully or partially implementing the selected actions:
Explanation for why circumstances causing the delay are beyond the entity’s control:
Description of revisions to the selected actions, if applicable:
New proposed completion date of CAP:
NERC | DRAFT TPL-007-4 CAP Extension Request Review Process | Month, 2019
3
Standards Announcement
Project 2019-01 Modifications to TPL-007-3
Final Ballot Open through November 22, 2019
Now Available
A 10-day final ballot for TPL-007-4 - Transmission System Planned Performance for Geomagnetic
Disturbance Events is open through 8 p.m. Eastern, Friday, November 22, 2019.
Balloting
In the final ballot, votes are counted by exception. Votes from the previous ballot are automatically
carried over in the final ballot. Only members of the applicable ballot pools can cast a vote. Ballot pool
members who previously voted have the option to change their vote in the final ballot. Ballot pool
members who did not cast a vote during the previous ballot can vote in the final ballot.
Members of the ballot pool(s) associated with this project can log in and submit their votes by accessing
the Standards Balloting & Commenting System (SBS) here. If you experience issues navigating the SBS,
contact Linda Jenkins.
•
If you are having difficulty accessing the SBS due to a forgotten password, incorrect credential
error messages, or system lock-out, contact NERC IT support directly at
https://support.nerc.net/ (Monday – Friday, 8 a.m. - 5 p.m. Eastern).
•
Passwords expire every 6 months and must be reset.
•
The SBS is not supported for use on mobile devices.
•
Please be mindful of ballot and comment period closing dates. We ask to allow at least 48
hours for NERC support staff to assist with inquiries. Therefore, it is recommended that users try
logging into their SBS accounts prior to the last day of a comment/ballot period.
Next Steps
The voting results will be posted and announced after the ballot closes. If approved, the standard will be
submitted to the Board of Trustees for adoption and then filed with the appropriate regulatory
authorities.
Standards Development Process
For more information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact Senior Standards Developer, Alison Oswald (via email) or at
404-446-9668.
RELIABILITY | RESILIENCE | SECURITY
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement | Project 2019-01 Modifications to TPL-007-3
Final Ballot | November 2019
2
NERC Balloting Tool (/)
Dashboard (/)
Ballots
Users
Comment Forms
Login (/Users/Login) / Register (/Users/Register)
BALLOT RESULTS
Ballot Name: 2019-01 Modifications to TPL-007-3 TPL-007-4 FN 2 ST
Voting Start Date: 11/13/2019 8:17:24 AM
Voting End Date: 11/22/2019 8:00:00 PM
Ballot Type: ST
Ballot Activity: FN
Ballot Series: 2
Total # Votes: 276
Total Ballot Pool: 292
Quorum: 94.52
Quorum Established Date: 11/13/2019 10:08:13 AM
Weighted Segment Value: 78.95
Ballot
Pool
Segment
Weight
Affirmative
Votes
Affirmative
Fraction
Negative
Votes w/
Comment
Negative
Fraction w/
Comment
Negative
Votes w/o
Comment
Abstain
No
Vote
Segment:
1
82
1
50
0.758
16
0.242
0
9
7
Segment:
2
6
0.5
5
0.5
0
0
0
1
0
Segment:
3
67
1
42
0.764
13
0.236
0
9
3
Segment:
4
13
1
10
0.833
2
0.167
0
1
0
Segment:
5
65
1
36
0.706
15
0.294
0
9
5
Segment:
6
49
1
27
0.614
17
0.386
0
4
1
Segment:
7
0
0
0
0
0
0
0
0
0
Segment:
8
2
0.1
1
0.1
0
0
0
1
0
Segment:
9
1
0.1
1
0.1
0
0
0
0
0
Segment:
10
7
0.6
6
0.6
0
0
0
1
0
Totals:
292
6.3
178
4.974
63
1.326
0
35
16
Segment
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
BALLOT POOL MEMBERS
Show All
Segment
entries
Organization
Search:
Voter
Designated
Proxy
Search
Ballot
NERC
Memo
1
AEP - AEP Service Corporation
Dennis Sauriol
Negative
N/A
1
Ameren - Ameren Services
Eric Scott
Negative
N/A
1
APS - Arizona Public Service
Co.
Michelle Amarantos
Abstain
N/A
1
Arizona Electric Power
Cooperative, Inc.
Ben Engelby
Affirmative
N/A
1
Austin Energy
Thomas Standifur
Affirmative
N/A
1
Balancing Authority of Northern
California
Kevin Smith
Affirmative
N/A
1
BC Hydro and Power Authority
Adrian Andreoiu
Abstain
N/A
1
Berkshire Hathaway Energy MidAmerican Energy Co.
Terry Harbour
Affirmative
N/A
1
Black Hills Corporation
Wes Wingen
Affirmative
N/A
1
Bonneville Power
Administration
Kammy RogersHolliday
Negative
N/A
1
Central Electric Power
Cooperative (Missouri)
Michael Bax
None
N/A
1
City Utilities of Springfield,
Missouri
Michael Buyce
Affirmative
N/A
1
Cleco Corporation
John Lindsey
Negative
N/A
1
CMS Energy - Consumers
Energy Company
Donald Lynd
Abstain
N/A
1
Colorado Springs Utilities
Mike Braunstein
Affirmative
N/A
1
Con Ed - Consolidated Edison
Co. of New York
Dermot Smyth
Negative
N/A
1
Dairyland Power Cooperative
Renee Leidel
Abstain
N/A
Affirmative
N/A
1
Dominion - Dominion Virginia
Candace Marshall
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Power
Joe Tarantino
Louis Guidry
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Duke Energy
Laura Lee
Affirmative
N/A
1
Edison International - Southern
California Edison Company
Ayman Samaan
Affirmative
N/A
1
Entergy - Entergy Services, Inc.
Oliver Burke
Affirmative
N/A
1
Eversource Energy
Quintin Lee
Affirmative
N/A
1
Exelon
Daniel Gacek
Affirmative
N/A
1
FirstEnergy - FirstEnergy
Corporation
Julie Severino
Affirmative
N/A
1
Georgia Transmission
Corporation
Greg Davis
Affirmative
N/A
1
Glencoe Light and Power
Commission
Terry Volkmann
Abstain
N/A
1
Great Plains Energy - Kansas
City Power and Light Co.
James McBee
Negative
N/A
1
Great River Energy
Gordon Pietsch
Affirmative
N/A
1
Hydro One Networks, Inc.
Payam
Farahbakhsh
Affirmative
N/A
1
Hydro-Qu?bec TransEnergie
Nicolas Turcotte
Affirmative
N/A
1
IDACORP - Idaho Power
Company
Laura Nelson
None
N/A
1
Imperial Irrigation District
Jesus Sammy
Alcaraz
Abstain
N/A
1
JEA
Joe McClung
None
N/A
1
KAMO Electric Cooperative
Micah Breedlove
Affirmative
N/A
1
Lakeland Electric
Larry Watt
Negative
N/A
1
Lincoln Electric System
Danny Pudenz
Affirmative
N/A
1
Long Island Power Authority
Robert Ganley
Affirmative
N/A
1
Los Angeles Department of
Water and Power
faranak sarbaz
None
N/A
1
Lower Colorado River Authority
Trey Melcher
Affirmative
N/A
1
M and A Electric Power
Cooperative
William Price
Affirmative
N/A
1
Manitoba Hydro
Bruce Reimer
Negative
N/A
Affirmative
N/A
© 2020
1 - NERC Ver 4.3.0.0
MEAGMachine
Power Name: ERODVSBSWB01
David Weekley
Stephen Stafford
Douglas Webb
Scott Miller
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
1
Minnkota Power Cooperative
Inc.
Theresa Allard
Abstain
N/A
1
Muscatine Power and Water
Andy Kurriger
Affirmative
N/A
1
N.W. Electric Power
Cooperative, Inc.
Mark Ramsey
Affirmative
N/A
1
National Grid USA
Michael Jones
Affirmative
N/A
1
NB Power Corporation
Nurul Abser
Abstain
N/A
1
Nebraska Public Power District
Jamison Cawley
Negative
N/A
1
New York Power Authority
Salvatore Spagnolo
Affirmative
N/A
1
NextEra Energy - Florida Power
and Light Co.
Mike ONeil
Affirmative
N/A
1
NiSource - Northern Indiana
Public Service Co.
Steve Toosevich
None
N/A
1
Northeast Missouri Electric
Power Cooperative
Kevin White
Affirmative
N/A
1
OGE Energy - Oklahoma Gas
and Electric Co.
Terri Pyle
Affirmative
N/A
1
Ohio Valley Electric Corporation
Scott Cunningham
Negative
N/A
1
Omaha Public Power District
Doug Peterchuck
Affirmative
N/A
1
Oncor Electric Delivery
Lee Maurer
None
N/A
1
Orlando Utilities Commission
Aaron Staley
Affirmative
N/A
1
OTP - Otter Tail Power
Company
Charles Wicklund
Affirmative
N/A
1
Platte River Power Authority
Matt Thompson
Affirmative
N/A
1
PNM Resources - Public
Service Company of New
Mexico
Laurie Williams
None
N/A
1
Portland General Electric Co.
Angela Gaines
Affirmative
N/A
1
PPL Electric Utilities
Corporation
Brenda Truhe
Affirmative
N/A
1
PSEG - Public Service Electric
and Gas Co.
Sean Cavote
Affirmative
N/A
1
Public Utility District No. 1 of
Chelan County
Ginette Lacasse
Negative
N/A
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Eric Shaw
Segment
Organization
Voter
1
Public Utility District No. 1 of
Snohomish County
Long Duong
1
Sacramento Municipal Utility
District
Arthur Starkovich
1
Salt River Project
1
Designated
Proxy
Ballot
NERC
Memo
Negative
N/A
Affirmative
N/A
Chris Hofmann
Affirmative
N/A
Santee Cooper
Chris Wagner
Abstain
N/A
1
SaskPower
Wayne Guttormson
Affirmative
N/A
1
Seattle City Light
Pawel Krupa
Affirmative
N/A
1
Seminole Electric Cooperative,
Inc.
Bret Galbraith
Negative
N/A
1
Sempra - San Diego Gas and
Electric
Mo Derbas
Affirmative
N/A
1
Sho-Me Power Electric
Cooperative
Peter Dawson
Affirmative
N/A
1
Southern Company - Southern
Company Services, Inc.
Matt Carden
Affirmative
N/A
1
Sunflower Electric Power
Corporation
Paul Mehlhaff
Affirmative
N/A
1
Tacoma Public Utilities
(Tacoma, WA)
John Merrell
Affirmative
N/A
1
Tallahassee Electric (City of
Tallahassee, FL)
Scott Langston
Affirmative
N/A
1
Tennessee Valley Authority
Gabe Kurtz
Affirmative
N/A
1
U.S. Bureau of Reclamation
Richard Jackson
Negative
N/A
1
Westar Energy
Allen Klassen
Negative
N/A
1
Western Area Power
Administration
sean erickson
Negative
N/A
1
Xcel Energy, Inc.
Dean Schiro
Affirmative
N/A
2
California ISO
Jamie Johnson
Abstain
N/A
2
Electric Reliability Council of
Texas, Inc.
Brandon Gleason
Affirmative
N/A
2
Independent Electricity System
Operator
Leonard Kula
Affirmative
N/A
2
ISO New England, Inc.
Michael Puscas
Affirmative
N/A
Affirmative
N/A
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
2
Midcontinent ISO, Inc.
David Zwergel
Joe Tarantino
Douglas Webb
Keith Jonassen
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
2
PJM Interconnection, L.L.C.
Mark Holman
Affirmative
N/A
3
AEP
Kent Feliks
Negative
N/A
3
AES - Indianapolis Power and
Light Co.
Colleen Campbell
Affirmative
N/A
3
Ameren - Ameren Services
David Jendras
Negative
N/A
3
APS - Arizona Public Service
Co.
Vivian Moser
Abstain
N/A
3
Associated Electric
Cooperative, Inc.
Todd Bennett
Abstain
N/A
3
Austin Energy
W. Dwayne Preston
Affirmative
N/A
3
Avista - Avista Corporation
Scott Kinney
Affirmative
N/A
3
BC Hydro and Power Authority
Hootan Jarollahi
Abstain
N/A
3
Berkshire Hathaway Energy MidAmerican Energy Co.
Darnez Gresham
Affirmative
N/A
3
Black Hills Corporation
Eric Egge
Affirmative
N/A
3
Bonneville Power
Administration
Ken Lanehome
Negative
N/A
3
Central Electric Power
Cooperative (Missouri)
Adam Weber
Affirmative
N/A
3
City Utilities of Springfield,
Missouri
Scott Williams
Affirmative
N/A
3
CMS Energy - Consumers
Energy Company
Karl Blaszkowski
Abstain
N/A
3
Colorado Springs Utilities
Hillary Dobson
Affirmative
N/A
3
Cowlitz County PUD
Russell Noble
Negative
N/A
3
Dominion - Dominion
Resources, Inc.
Connie Lowe
Affirmative
N/A
3
Duke Energy
Lee Schuster
Affirmative
N/A
3
Edison International - Southern
California Edison Company
Romel Aquino
Affirmative
N/A
3
Eversource Energy
Sharon Flannery
Affirmative
N/A
3
Exelon
Kinte Whitehead
Affirmative
N/A
Affirmative
N/A
3
FirstEnergy - FirstEnergy
Aaron Ghodooshim
Corporation
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Florida Municipal Power Agency
Joe McKinney
Brandon
McCormick
Negative
N/A
3
Great Plains Energy - Kansas
City Power and Light Co.
John Carlson
Douglas Webb
Negative
N/A
3
Great River Energy
Brian Glover
Affirmative
N/A
3
Hydro One Networks, Inc.
Paul Malozewski
Affirmative
N/A
3
Imperial Irrigation District
Denise Sanchez
Abstain
N/A
3
JEA
Garry Baker
None
N/A
3
KAMO Electric Cooperative
Tony Gott
Affirmative
N/A
3
Lakeland Electric
Patricia Boody
Abstain
N/A
3
Lincoln Electric System
Jason Fortik
Affirmative
N/A
3
Los Angeles Department of
Water and Power
Tony Skourtas
Affirmative
N/A
3
M and A Electric Power
Cooperative
Stephen Pogue
Affirmative
N/A
3
Manitoba Hydro
Karim Abdel-Hadi
Negative
N/A
3
MEAG Power
Roger Brand
Affirmative
N/A
3
Muscatine Power and Water
Seth Shoemaker
Affirmative
N/A
3
National Grid USA
Brian Shanahan
Affirmative
N/A
3
Nebraska Public Power District
Tony Eddleman
Negative
N/A
3
New York Power Authority
David Rivera
Affirmative
N/A
3
NiSource - Northern Indiana
Public Service Co.
Dmitriy Bazylyuk
Negative
N/A
3
Northeast Missouri Electric
Power Cooperative
Skyler Wiegmann
Affirmative
N/A
3
NW Electric Power Cooperative,
Inc.
John Stickley
Affirmative
N/A
3
OGE Energy - Oklahoma Gas
and Electric Co.
Donald Hargrove
Affirmative
N/A
3
Omaha Public Power District
Aaron Smith
Affirmative
N/A
3
OTP - Otter Tail Power
Company
Wendi Olson
Affirmative
N/A
Abstain
N/A
3
Owensboro Municipal Utilities
Thomas Lyons
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Scott Miller
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
3
Platte River Power Authority
Wade Kiess
Affirmative
N/A
3
PNM Resources - Public
Service Company of New
Mexico
Trevor Tidwell
None
N/A
3
Portland General Electric Co.
Dan Zollner
Affirmative
N/A
3
PPL - Louisville Gas and
Electric Co.
James Frank
Affirmative
N/A
3
PSEG - Public Service Electric
and Gas Co.
James Meyer
Affirmative
N/A
3
Public Utility District No. 1 of
Chelan County
Joyce Gundry
Negative
N/A
3
Sacramento Municipal Utility
District
Nicole Looney
Affirmative
N/A
3
Salt River Project
Zack Heim
Affirmative
N/A
3
Santee Cooper
James Poston
Abstain
N/A
3
Seminole Electric Cooperative,
Inc.
Kristine Ward
Negative
N/A
3
Sempra - San Diego Gas and
Electric
Bridget Silvia
Affirmative
N/A
3
Sho-Me Power Electric
Cooperative
Jarrod Murdaugh
Affirmative
N/A
3
Snohomish County PUD No. 1
Holly Chaney
Negative
N/A
3
Southern Company - Alabama
Power Company
Joel Dembowski
Affirmative
N/A
3
Tacoma Public Utilities
(Tacoma, WA)
Marc Donaldson
Affirmative
N/A
3
TECO - Tampa Electric Co.
Ronald Donahey
None
N/A
3
Tennessee Valley Authority
Ian Grant
Affirmative
N/A
3
Tri-State G and T Association,
Inc.
Janelle Marriott Gill
Abstain
N/A
3
WEC Energy Group, Inc.
Thomas Breene
Affirmative
N/A
3
Westar Energy
Bryan Taggart
Negative
N/A
3
Xcel Energy, Inc.
Joel Limoges
Affirmative
N/A
4
Austin Energy
Jun Hua
Affirmative
N/A
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Joe Tarantino
Douglas Webb
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
4
City Utilities of Springfield,
Missouri
John Allen
Affirmative
N/A
4
CMS Energy - Consumers
Energy Company
Dwayne Parker
Abstain
N/A
4
FirstEnergy - FirstEnergy
Corporation
Mark Garza
Affirmative
N/A
4
Florida Municipal Power Agency
Carol Chinn
Negative
N/A
4
MGE Energy - Madison Gas
and Electric Co.
Joseph DePoorter
Affirmative
N/A
4
Public Utility District No. 1 of
Snohomish County
John Martinsen
Negative
N/A
4
Public Utility District No. 2 of
Grant County, Washington
Karla Weaver
Affirmative
N/A
4
Sacramento Municipal Utility
District
Beth Tincher
Affirmative
N/A
4
Seattle City Light
Hao Li
Affirmative
N/A
4
Tacoma Public Utilities
(Tacoma, WA)
Hien Ho
Affirmative
N/A
4
Utility Services, Inc.
Brian EvansMongeon
Affirmative
N/A
4
WEC Energy Group, Inc.
Matthew Beilfuss
Affirmative
N/A
5
AEP
Thomas Foltz
Negative
N/A
5
Ameren - Ameren Missouri
Sam Dwyer
None
N/A
5
APS - Arizona Public Service
Co.
Kelsi Rigby
Abstain
N/A
5
Austin Energy
Lisa Martin
Affirmative
N/A
5
Avista - Avista Corporation
Glen Farmer
Affirmative
N/A
5
Berkshire Hathaway - NV
Energy
Kevin Salsbury
Affirmative
N/A
5
Black Hills Corporation
George Tatar
Affirmative
N/A
5
Boise-Kuna Irrigation District Lucky Peak Power Plant Project
Mike Kukla
Affirmative
N/A
5
Bonneville Power
Administration
Scott Winner
Negative
N/A
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
Brandon
McCormick
Joe Tarantino
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Brazos Electric Power
Cooperative, Inc.
Shari Heino
Affirmative
N/A
5
Choctaw Generation Limited
Partnership, LLLP
Rob Watson
None
N/A
5
City of Independence, Power
and Light Department
Jim Nail
Affirmative
N/A
5
CMS Energy - Consumers
Energy Company
David Greyerbiehl
Abstain
N/A
5
Colorado Springs Utilities
Jeff Icke
Affirmative
N/A
5
Con Ed - Consolidated Edison
Co. of New York
William Winters
Negative
N/A
5
Cowlitz County PUD
Deanna Carlson
Abstain
N/A
5
Dairyland Power Cooperative
Tommy Drea
Abstain
N/A
5
Duke Energy
Dale Goodwine
Affirmative
N/A
5
Edison International - Southern
California Edison Company
Neil Shockey
Affirmative
N/A
5
Entergy
Jamie Prater
Negative
N/A
5
Exelon
Cynthia Lee
Affirmative
N/A
5
FirstEnergy - FirstEnergy
Solutions
Robert Loy
Affirmative
N/A
5
Florida Municipal Power Agency
Chris Gowder
Brandon
McCormick
Negative
N/A
5
Great Plains Energy - Kansas
City Power and Light Co.
Marcus Moor
Douglas Webb
Negative
N/A
5
Great River Energy
Preston Walsh
Affirmative
N/A
5
Herb Schrayshuen
Herb Schrayshuen
Affirmative
N/A
5
Imperial Irrigation District
Tino Zaragoza
Abstain
N/A
5
JEA
John Babik
None
N/A
5
Lakeland Electric
Jim Howard
Negative
N/A
5
Lincoln Electric System
Kayleigh Wilkerson
Affirmative
N/A
5
Los Angeles Department of
Water and Power
Glenn Barry
None
N/A
5
Lower Colorado River Authority
Teresa Cantwell
Affirmative
N/A
Negative
N/A
© 2020
Machine
Name: ERODVSBSWB01
5 - NERC Ver 4.3.0.0
Manitoba
Hydro
Yuguang Xiao
Daniel Valle
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Massachusetts Municipal
Wholesale Electric Company
Anthony Stevens
Abstain
N/A
5
Muscatine Power and Water
Neal Nelson
Affirmative
N/A
5
NaturEner USA, LLC
Eric Smith
Affirmative
N/A
5
NB Power Corporation
Laura McLeod
Abstain
N/A
5
Nebraska Public Power District
Ronald Bender
Negative
N/A
5
New York Power Authority
Shivaz Chopra
Affirmative
N/A
5
NiSource - Northern Indiana
Public Service Co.
Kathryn Tackett
Negative
N/A
5
Northern California Power
Agency
Marty Hostler
Affirmative
N/A
5
NRG - NRG Energy, Inc.
Patricia Lynch
None
N/A
5
OGE Energy - Oklahoma Gas
and Electric Co.
Patrick Wells
Affirmative
N/A
5
Oglethorpe Power Corporation
Donna Johnson
Affirmative
N/A
5
Omaha Public Power District
Mahmood Safi
Affirmative
N/A
5
Ontario Power Generation Inc.
Constantin Chitescu
Affirmative
N/A
5
OTP - Otter Tail Power
Company
Brett Jacobs
Affirmative
N/A
5
Platte River Power Authority
Tyson Archie
Affirmative
N/A
5
Portland General Electric Co.
Ryan Olson
Affirmative
N/A
5
PPL - Louisville Gas and
Electric Co.
JULIE
HOSTRANDER
Affirmative
N/A
5
PSEG - PSEG Fossil LLC
Tim Kucey
Affirmative
N/A
5
Public Utility District No. 1 of
Chelan County
Meaghan Connell
Negative
N/A
5
Public Utility District No. 1 of
Snohomish County
Sam Nietfeld
Negative
N/A
5
Public Utility District No. 2 of
Grant County, Washington
Alex Ybarra
Affirmative
N/A
5
Sacramento Municipal Utility
District
Susan Oto
Affirmative
N/A
5
Salt River Project
Kevin Nielsen
Affirmative
N/A
Abstain
N/A
© 2020
Machine
5 - NERC Ver 4.3.0.0
Santee
CooperName: ERODVSBSWB01
Tommy Curtis
Joe Tarantino
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
5
Seattle City Light
Faz Kasraie
Affirmative
N/A
5
Sempra - San Diego Gas and
Electric
Jennifer Wright
Affirmative
N/A
5
SunPower
Bradley Collard
Abstain
N/A
5
Tacoma Public Utilities
(Tacoma, WA)
Ozan Ferrin
Affirmative
N/A
5
Tennessee Valley Authority
M Lee Thomas
Negative
N/A
5
WEC Energy Group, Inc.
Janet OBrien
Negative
N/A
5
Westar Energy
Derek Brown
Negative
N/A
5
Xcel Energy, Inc.
Gerry Huitt
Affirmative
N/A
6
AEP - AEP Marketing
Yee Chou
Negative
N/A
6
Ameren - Ameren Services
Robert Quinlivan
None
N/A
6
APS - Arizona Public Service
Co.
Chinedu Ochonogor
Abstain
N/A
6
Associated Electric
Cooperative, Inc.
Brian Ackermann
Affirmative
N/A
6
Austin Energy
Andrew Gallo
Affirmative
N/A
6
Berkshire Hathaway PacifiCorp
Sandra Shaffer
Abstain
N/A
6
Black Hills Corporation
Eric Scherr
Affirmative
N/A
6
Bonneville Power
Administration
Andrew Meyers
Negative
N/A
6
Cleco Corporation
Robert Hirchak
Negative
N/A
6
Con Ed - Consolidated Edison
Co. of New York
Christopher
Overberg
Negative
N/A
6
Dominion - Dominion
Resources, Inc.
Sean Bodkin
Affirmative
N/A
6
Duke Energy
Greg Cecil
Affirmative
N/A
6
Edison International - Southern
California Edison Company
Kenya Streeter
Negative
N/A
6
Entergy
Julie Hall
Negative
N/A
6
Exelon
Becky Webb
Affirmative
N/A
Affirmative
N/A
6
FirstEnergy - FirstEnergy
Ann Carey
© 2020 - NERC Ver 4.3.0.0
Machine Name: ERODVSBSWB01
Solutions
Douglas Webb
Louis Guidry
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
Florida Municipal Power Agency
Richard
Montgomery
Brandon
McCormick
Negative
N/A
6
Great Plains Energy - Kansas
City Power and Light Co.
Jennifer
Flandermeyer
Douglas Webb
Negative
N/A
6
Great River Energy
Donna Stephenson
Michael Brytowski
Affirmative
N/A
6
Imperial Irrigation District
Diana Torres
Abstain
N/A
6
Lakeland Electric
Paul Shipps
Negative
N/A
6
Lincoln Electric System
Eric Ruskamp
Affirmative
N/A
6
Los Angeles Department of
Water and Power
Anton Vu
Affirmative
N/A
6
Manitoba Hydro
Blair Mukanik
Negative
N/A
6
Muscatine Power and Water
Nick Burns
Affirmative
N/A
6
New York Power Authority
Thomas Savin
Affirmative
N/A
6
NextEra Energy - Florida Power
and Light Co.
Justin Welty
Affirmative
N/A
6
NiSource - Northern Indiana
Public Service Co.
Joe O'Brien
Negative
N/A
6
Northern California Power
Agency
Dennis Sismaet
Affirmative
N/A
6
OGE Energy - Oklahoma Gas
and Electric Co.
Sing Tay
Affirmative
N/A
6
Omaha Public Power District
Joel Robles
Affirmative
N/A
6
Platte River Power Authority
Sabrina Martz
Affirmative
N/A
6
Portland General Electric Co.
Daniel Mason
Affirmative
N/A
6
PPL - Louisville Gas and
Electric Co.
Linn Oelker
Affirmative
N/A
6
PSEG - PSEG Energy
Resources and Trade LLC
Luiggi Beretta
Affirmative
N/A
6
Public Utility District No. 1 of
Chelan County
Davis Jelusich
Negative
N/A
6
Public Utility District No. 2 of
Grant County, Washington
LeRoy Patterson
Negative
N/A
6
Sacramento Municipal Utility
District
Jamie Cutlip
Affirmative
N/A
Affirmative
N/A
© 2020 - NERC Ver 4.3.0.0 Machine Name: ERODVSBSWB01
6
Salt River Project
Bobby Olsen
Joe Tarantino
Segment
Organization
Voter
Designated
Proxy
Ballot
NERC
Memo
6
Santee Cooper
Michael Brown
Abstain
N/A
6
Seattle City Light
Charles Freeman
Affirmative
N/A
6
Seminole Electric Cooperative,
Inc.
David Reinecke
Negative
N/A
6
Snohomish County PUD No. 1
John Liang
Negative
N/A
6
Southern Company - Southern
Company Generation
Ron Carlsen
Affirmative
N/A
6
Tennessee Valley Authority
Marjorie Parsons
Affirmative
N/A
6
WEC Energy Group, Inc.
David Hathaway
Affirmative
N/A
6
Westar Energy
Grant Wilkerson
Negative
N/A
6
Western Area Power
Administration
Rosemary Jones
Negative
N/A
6
Xcel Energy, Inc.
Carrie Dixon
Affirmative
N/A
8
David Kiguel
David Kiguel
Affirmative
N/A
8
Florida Reliability Coordinating
Council – Member Services
Division
Vince Ordax
Abstain
N/A
9
Commonwealth of
Massachusetts Department of
Public Utilities
Donald Nelson
Affirmative
N/A
10
Midwest Reliability Organization
Russel Mountjoy
Affirmative
N/A
10
New York State Reliability
Council
ALAN ADAMSON
Affirmative
N/A
10
Northeast Power Coordinating
Council
Guy V. Zito
Affirmative
N/A
10
ReliabilityFirst
Anthony Jablonski
Affirmative
N/A
10
SERC Reliability Corporation
Dave Krueger
Affirmative
N/A
10
Texas Reliability Entity, Inc.
Rachel Coyne
Abstain
N/A
10
Western Electricity Coordinating
Council
Steven Rueckert
Affirmative
N/A
Douglas Webb
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Exhibit G
Standard Drafting Team Roster for Project 2019-01
RELIABILITY | RESILIENCE | SECURITY
Standard Drafting Team Roster
Project 2019-01 Modifications to TPL-007-3
Name
Entity
Chair
Emanuel Bernabeu
PJM Interconnection
Vice Chair
Per-Anders Lof
National Grid
Members
Mike Steckelberg
Great River Energy
Rui Sun
Dominion Energy
Jow Ortiz
Florida Power & Light (NextEra Energy)
Cynthia Yiu
Hydro One Networks Inc.
Reynaldo Ramos
Southern Company Services
Aster Amahatsion
American Electric Power
Justin Michlig
MISO
Michael Brytowski
Great River Energy
Sean Cavote
PSEG Services Company
Alison Oswald – Senior Standards
Developer
North American Electric Reliability
Corporation
Lauren Perotti – Senior Counsel
North American Electric Reliability
Corporation
PMOS
Liaison(s)
NERC Staff
RELIABILITY | RESILIENCE | SECURITY
Exhibit H
Consideration of Directives
RELIABILITY | RESILIENCE | SECURITY
Consideration of Issues and Directives
Project 2019-01 Modifications to TPL-007-3
Project 2019-01 Modifications to TPL-007-3
Issue or Directive
Source
Modify the provision in Reliability Standard TPL-007-2,
Requirement R7.4 that allows applicable entities to
exceed deadlines for completing corrective action plan
tasks when “situations beyond the control of the
responsible entity [arise]”, by requiring that NERC and
the Regional Entities, as appropriate, consider requests
for extension of time on a case-by-case basis. Under
this option, responsible entities seeking an extension
would submit the information required by
Requirement R7.4 to NERC and the Regional Entities for
their consideration of the request.
FERC Order
No. 851, P 5
and P 50
Consideration of Issue or Directive
The SDT proposed the modified language in Requirement R7.3
and R7.4 to require time extensions for completing CAPs be
submitted to the ERO for approval. The proposed modified
language reads as follows:
7.3. Include a timetable, subject to revision by the responsible
entity approval for any extension sought under in Part 7.4, for
implementing the selected actions from Part 7.1. The timetable
shall:
7.3.1. Specify implementation of non-hardware
mitigation, if any, within two years of development
of the CAP; and
7.3.2. Specify implementation of hardware mitigation, if
any, within four years of development of the CAP.
7.4. Be submitted to the Compliance Enforcement Authority
(CEA) with a request for extension of time revised if situations
beyond the control of the responsible entity is unable to
determined in Requirement R1 prevent implementation of the
CAP within the timetable for implementation provided in Part
RELIABILITY | RESILIENCE | SECURITY
Project 2019-01 Modifications to TPL-007-3
Issue or Directive
Source
Consideration of Issue or Directive
7.3. The submitted revised CAP shall document the following,
and be updated at least once every 12 calendar months until
implemented:
7.4.1 Circumstances causing the delay for fully or
partially implementing the selected actions in Part
7.1 and how those circumstances are beyond the
control of the responsible entity;
7.4.2 Description of the original CAP, and any previous
changes to the CAP, with the associated
timetables(s) for implementing the selected actions
in Part 7.1; and
7.4.37.4.2
Revisions to the selected actions in Part
7.1, if any, including utilization of Operating
Procedures, if applicable;, and the updated
timetable for implementing the selected actions.
7.4.47.4.3
Updated timetable for implementing the
selected actions in Part 7.1.
Submit modifications to Reliability Standard TPL-007-2
to require corrective action plans for assessed
supplemental GMD event vulnerabilities.
Consideration of Issues and Directives
Project 2019-01 Modifications to TPL-007-3 | November 2019
FERC Order
No. 851, P 4
and P 39
The SDT drafted TPL-007-4 Requirement R11 to address
require CAPs for supplemental GMD vulnerabilities and to
require extensions to these plans to be approved by NERC
and the Regional Entities, as appropriate, in where situations
beyond the control of the responsible entity prevent
implementation of the CAP in the two and four year timelines
provided in the standard for non-hardware and hardware
2
Project 2019-01 Modifications to TPL-007-3
Issue or Directive
Source
Consideration of Issue or Directive
mitigation, respectively. This language is the same as the
modified Requirement R7 which addresses CAPs for the
benchmark GMD vulnerability assessment. Requirement R8
was also modified to remove the original R8.3 which stated
“an evaluation of possible actions designed to reduce the
likelihood or mitigate the consequences and adverse impacts
of the event(s) shall be conducted.”
Consideration of Issues and Directives
Project 2019-01 Modifications to TPL-007-3 | November 2019
3
| File Type | application/pdf |
| Author | Lauren Perotti |
| File Modified | 2020-04-29 |
| File Created | 2020-02-07 |